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.
HARVARD LAW SCHOOL 

ENVIRONMENTAL LAW & POLICY CLINIC

1563 Massachusetts Avenue 

Pound Hall · Room 501 

Cambridge · Massachusetts · 02138 

TEL 617.496.3368 · FAX 617.384.7633 · EMAIL wjacobs@law.harvard.edu

 

 November 21, 2008 

By Electronic Submission to www.regulations.gov 

Environmental Protection Agency 

Docket Center—Water Docket 

1200 Pennsylvania Avenue, NW. 

Washington, D.C. 20460 

 

RE: Docket ID No. EPA – HQ – OW – 2008 – 0390

To Whom It May Concern: 

 The Harvard Law School Environmental Law and Policy Clinic (“ELPC”)1 submits the 

following comments on its own behalf and on behalf of the Energy Technology Innovation 

Policy research group at the Harvard Kennedy School (“ETIP”)2 in response to EPA’s 

solicitation of public comments on the proposed federal requirements under the Safe Drinking 

Water Act (“SDWA”) for long-term sequestration of carbon dioxide in geologic formations 

(“geologic sequestration” or “GS”). Federal Requirements under the Underground Injection 

Control (“UIC”) Program for Carbon Dioxide (“CO2”) Geologic Sequestration (“GS”) Wells, 73 

Fed. Reg. 43,491 (proposed July 25, 2008) (to be codified at 40 C.F.R. pts. 144 and 146) 

[hereinafter the “proposed regulation”]. 

 

1

 The ELPC works on a variety of local, national, and international projects covering the spectrum of environmental 

law and policy issues. These comments are authored by Wendy Jacobs, a Clinical Professor at Harvard Law School 

and Director of the ELPC, together with Phillip Assmus, Alejandra Maupome Cagigal, Mina Makarious and Emily 

Wack, who are active members of the Clinic and students at Harvard Law School, and Nancy Wang, Esquire, 

special research assistant on this project. 

2

 The overarching objective of ETIP is to determine and then seek to promote adoption of effective strategies for 

developing and deploying cleaner and more efficient energy technologies. 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

The ELPC’s primary objection to the proposed regulation is that regulation of geologic 

sequestration under the SDWA is too narrow in focus to ensure that carbon capture and 

sequestration (“CCS”) fulfills its potential to be “a key mitigation technology for achieving 

domestic [greenhouse gas] emissions reductions.” 73 Fed. Reg. at 43,496. EPA is proposing to 

regulate GS by creating a new category of injection well (“Class VI”) for GS under its existing 

UIC program under the SDWA. As EPA acknowledges, however, its authority under the SDWA 

is limited. See 42 U.S.C. 300h(a)-(b)(1), (d); 73 Fed. Reg. at 43,495. Other rules and regulations 

are needed to address CCS issues falling outside the scope of the SDWA (e.g., establishing 

mechanisms for protecting private drinking water supplies, funding costs and damages associated 

with injury to persons and/or water supplies despite compliance with the UIC regulations, 

accidental releases of CO2 to the atmosphere, and compensation for and remediation of harm to 

public health or the environment other than the endangerment of underground sources of 

drinking water (“USDWs”)). See infra Part III(c)(1)(b); 73 Fed. Reg. at 43,495, 43,497, 43,520, 

43,522 (discussing EPA’s view of CCS issues that fall outside purview of SDWA). Other issues 

related to the capture and transport of CO2 also need to be considered and addressed. 

Many of these issues are of critical importance and will likely need to be addressed 

before large-scale industry investment in CCS will take place. See, e.g., infra Part 

III(C)(1)(b)(ii) (discussing industry’s need for a clear and comprehensive long-term liability 

scheme). Piecemeal regulation of CCS is likely to cause confusion, inefficiency, potentially 

conflicting requirements or policies, and other problems that could be avoided by a 

comprehensive approach to regulation of CCS. Although ELPC and ETIP believe 

comprehensive regulations addressing CCS would more likely ensure that CCS becomes a 

successful climate change mitigation technology, we recognize that Congress may need to enact 

legislation enabling EPA (or another federal agency) to take such a comprehensive approach. 

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 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

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ELPC and ETIP commend EPA for including precautionary measures for Class VI wells 

above and beyond what is required for other classes of wells. The proposed regulation allows 

the owner or operator the flexibility to choose particular cements or metal well components for 

Class VI wells while still requiring that such materials meet or exceed the standards developed 

by the American Petroleum Institute, ASTM International or comparable standards acceptable to 

the Director. 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 146.86(b)(1)). By doing so, the 

proposed regulation addresses the potential corrosion of cement and metal well components by 

the CO2 stream (plus water impurities) that can compromise the structure of the well and result in 

leaks of stored CO2. ELPC and ETIP laud other precautionary measures required in the 

proposed regulation, including down-hole shut off valves, continuous and frequent monitoring of 

the integrity of the internal and external portions of the well, tracking the plume and pressure 

front, and detailed electronic record keeping. Id. at 43,511, 43,538-40 (proposed 40 C.F.R. 

§§ 146.88-.91). The requirements in the proposed regulation reflect EPA’s understanding of and 

sensitivity to the challenges posed by CCS. Because CO2 GS entails new technology with a 

potentially large impact and lasting duration, ELPC and ETIP support these precautionary 

measures. 

With the reservation that comprehensive regulations would be preferable to partial 

regulation under the SDWA, ELPC and ETIP submit the following comments on the proposed 

regulation. 

I. Summary of Comments 

I. Summary of Comments 

II. Ensuring Long-Term Containment of CO2 at Sequestration Sites 

A. EPA Should Require Owners or Operators to Demonstrate that CO2 Will Be 

Contained for the Long-Term 

B. EPA Should Impose More Specific Well Plugging Standards 

C. EPA Should Clarify the Site Closure Standard 

D. EPA Should Expand the Emergency and Remedial Response Requirements 

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 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

III. Providing Certainty with Respect to Financial Assurance Requirements and Short- and 

Long-Term Liability 

A. Financial Assurance 

1. EPA Should Prescribe the Use of Specific Financial Assurance 

Instruments. 

2. EPA Should Incorporate OIG’s and GAO’s Recommendations. 

a. EPA Should Pay Special Attention to GAO’s and OIG’s 

Recommendations for Reforming Financial Test and Corporate 

Guarantee Mechanisms. 

b. EPA Should Implement the Recommendations Made by OIG and 

GAO Regarding Insurance Mechanisms Before Allowing Their 

Use by Owners or Operators. 

c. EPA Should Set a Firm Timeline for Issuing More Detailed 

Regulations on Financial Assurance Mechanisms. 

3. EPA Should Require Owners or Operators to Re-Demonstrate Financial 

Assurance Throughout the Life of the Project. 

4. The Regulation Fails to Require Financial Assurance for All 

Contingencies and Costs of Protecting Drinking Water Supplies. 

B. The Proposed Regulation Does Not Cover All Parties Involved in CCS Even 

Though Their Actions Create a Risk of Endangerment to USDWs. 

C. EPA’s Long-Term Liability Scheme for GS Does Not Adequately Protect the 

Public or Address the Concerns of Industry. 

1. The Problem of Long-Term Care of GS Facilities 

2. EPA’s Proposed Regulation 

a. The Public Is at Risk. 

b. Industry Lacks Certainty. 

3. EPA Should Extend Its Financial Assurance Requirements into the PostClosure Period and Transfer MMV Responsibilities to the Government. 

a. EPA’s Need for Additional Authority 

b. Long-Term Liability Should Be Addressed at a National Level, 

Not Left to the States. 

IV. EPA Should Update the Definition of USDW So That All Current and Viable Future 

Drinking Water Supplies are Protected from GS. 

V. EPA Should Not Allow, or Should At Least Severely Restrict, Grandfathering of Existing 

Wells. 

VI. The EPA Should Rank Sites with GS Capability Based On Their Specific Leakage Risk 

Profiles. 

A. CO2 Injection above the Lowermost USDW 

B. Exempting USDWs for the Purpose of GS 

VII.Conclusion 

Page 4 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

 

II. Ensuring the Long-Term Containment of CO2 at Sequestration Sites 

A. EPA Should Require Owners or Operators to Demonstrate that CO2 Will Be 

Contained for the Long-Term 

The purpose of GS is to store anthropogenic CO2 for the “long term.” See 73 Fed. Reg. 

at 43,535 (proposed 40 C.F.R. § 146.81) (defining “geologic sequestration” as the “long-term 

containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic 

formations”). If—but only if—the sequestered CO2 is contained (i.e., not allowed to escape into 

the atmosphere) for a sufficiently long period of time will CCS fulfill its potential to be “a key 

mitigation technology for achieving domestic emissions reductions” and “help to mitigate 

climate change.” 73 Fed. Reg. at 43,492, 43,496. As drafted, however, the proposed regulation 

fails to tackle the question of how long is “long term.” 

EPA should provide a sense of the time scales involved and require owners/operators to 

make a reasonable demonstration that the injected CO2 will not migrate in such a way that will 

frustrate the broader climate change related goals of GS, lead to human endangerment, or 

threaten USDWs. 

Despite the fact that long-term containment is critical to the success of a climate change 

mitigation program and to satisfy the public protection mandate of the SDWA, EPA’s proposed 

GS regulation fails to require permit applicants to demonstrate that long-term containment will 

be achieved and maintained. In this respect, the proposed rule is less stringent than the 

requirements for Class I hazardous waste injection wells, which require the permit applicant to 

show to a reasonable degree of certainty that no hazardous materials will migrate from the 

injection zone for 10,000 years.3

 40 C.F.R. § 148.20(a)(1)(i). The differences between 

3

 In the alternative, the owner or operator may demonstrate that, “[b]efore the injected fluids migrate out of the 

injection zone or to a point of discharge or interface with USDW, the fluid will no longer be hazardous because of 

attenuation, transformation, or immobilization of hazardous constituents within the injection zone by hydrolysis, 

chemical interactions or other means . . . .” 40 C.F.R. §148.20(a)(1)(ii). 

Page 5 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

 

hazardous waste and CO2 suggest that a 10,000 year demonstration may be too stringent for GS 

within Class VI wells, but the existence of a 10,000 year demonstration standard for Class I wells 

confirms that EPA can reasonably impose and administer a reasonable demonstration standard 

for Class VI wells. 

In its regulations for GS of CO2, Washington State requires GS permit applicants to 

demonstrate to a high degree of confidence that “substantially ninety-nine percent of the 

greenhouse gases will remain contained for at least one thousand years.” Wash. Admin. Code 

§§ 173-218-115(4)(a)(i)(A), 173-407-110 (2008). Though Washington’s one thousand year 

requirement seems consistent with the timescales imagined in EPA’s preamble, see 73 Fed. Reg. 

at 43,496 (total GS capacity is expressed as the ability to sequester CO2 emissions for “hundreds, 

if not thousands” of years), no comparable requirement is imposed on a permit applicant under 

EPA’s proposed regulation for Class VI wells (or on the owner or operator during the 

construction, injection, post-site injection care, site closure, and post-closure phases of a GS 

project). See id. at 43,536-37, 43,537-41 (proposed 40 C.F.R. §§ 146.82-.84, 146.86-.94).4 

Given the central importance of “long-term” containment to any GS project, EPA should 

add a long-term containment demonstration requirement to the proposed regulation. At a 

minimum, a permit applicant should be required to demonstrate long-term containment as a 

precondition to being issued an injection permit, similar to the requirement in the Class I UIC 

program and Washington State’s GS regulation.5 ELPC and ETIP recommend adopting a 

1,000 year containment standard. 

4

 Texas imposes a demonstration requirement similar to Washington State as a condition for tax exemptions to 

encourage GS. Tex. Tax Code Ann. § 202.0545(d)(1)(2007) (“The operator’s planned sequestration program will 

ensure that at least 99 percent of the carbon dioxide sequestered . . . will remain sequestered for at least 1,000 

years.”). 

5

 EPA also should consider requiring the owner or operator to demonstrate long-term containment again as a 

precondition to granting site closure, and/or periodically during various phases of the GS project. 

Page 6 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

B. EPA Should Impose More Specific Well Plugging Standards 

In the preamble, EPA states that the proposed regulation will ensure that injection wells 

are plugged at the end of an injection project so that the wells will not serve as conduits for CO2

movement into USDWs. See 73 Fed. Reg. at 43,499, 43,518. If an improperly plugged well 

allows CO2 to escape into the atmosphere, the climate change mitigation purpose underlying 

Class VI wells is undermined. See id. at 43,492 (discussing how improper well plugging of an 

abandoned oil exploration well allows a geyser of CO2 and water to erupt periodically from the 

well, releasing 12,000 gigatons per year of CO2 into the atmosphere). The proposed regulation, 

however, does not provide enough meaningful guidance for owners/operators regarding how to 

“plug wells in a manner that does not endanger USDWs.” Id. at 43,518. Owners/operators are 

directed simply to “prepare, maintain, and comply with a [well plugging] plan that is acceptable 

to the Director.” Id. at 43,540 (proposed 40 C.F.R. § 146.92(b)). EPA neglects to specify “the 

types of materials or tests that must be used during well plugging because there are a variety of 

methods that are appropriate and new materials and tests may become available in the future.” 

Id. at 43,518. Its general outline for the well plugging plan is intended “to give owners or 

operators flexibility in . . . choos[ing] from available materials and tests to carry out the proposed 

requirements.” Id. Allowing flexibility is certainly important. It does not, however, preclude 

EPA from providing specific performance requirements, preferred methods, or a non-exhaustive 

list of approved materials and techniques. 

EPA’s existing regulations for other UIC wells and surface impoundments and landfills 

under the Resource Conservation and Recovery Act, 42 U.S.C. § 6901, et. seq., (“RCRA”), 

provide good models in this regard. The existing regulations for Class I, II, and III wells require 

plugging in a manner to “prevent the movement of fluids” into a USDW. 40 C.F.R. 

Page 7 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

§ 146.10(a)(1). In addition, the existing regulation lists three accepted plugging techniques. 40 

C.F.R. § 146.10(a)(2)(i)-(iii)). It builds in flexibility by allowing the Director to approve 

plugging techniques outside of the enumerated categories if the technique will “reliably provide 

a comparable level of protection to USDWs.” 40 C.F.R. § 146.10(a)(2)(iv); see also 40 C.F.R. 

§§ 264.228(a)(2)(iii)(A)-(E), 264.310(a)(1)-(5) (plugging requirements for surface 

impoundments and landfills, respectively, which include specific targets to be met (permeability) 

as well as general performance goals (minimum maintenance and migration)). 

By specifying a baseline of plugging techniques that EPA already knows will work for 

GS, EPA would provide valuable GS-specific guidance to owners/operators (and Directors). 

This may be especially valuable in this early stage of development for GS technology as it will 

give all involved parties a brighter line by which to measure compliance. Additionally, existing 

regulations demonstrate that more specificity need not, as EPA suggests in the preamble to the 

proposed regulation (73 Fed. Reg. at 43,518), constrain the use of future technologies. The 

proposed regulations can preserve flexibility by vesting the Director with the authority to 

consider and approve new plugging techniques. Accordingly, EPA should revise the proposed 

Class VI UIC program regulation to include a list of specific materials and tests that it deems 

suitable for plugging GS wells, in addition to providing the Director with the discretion to 

approve new techniques as they become available, provided they will perform at least as well. 

C. EPA Should Clarify the Site Closure Standard 

EPA is proposing a “combination of fixed timeframe and performance standard” 

approach to site closure. 73 Fed. Reg. at 43,519. Under the proposal, the owner or operator 

would be required to undertake “post-injection site care” following the permanent cessation of 

injection activities at the site, which would include “submit[ting] periodic reports providing 

monitoring results and updated modeling results as appropriate until a demonstration of nonPage 8 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

endangerment to USDWs can be made.” Id. at 43,520. Specifically, the owner or operator 

would need to demonstrate “that the carbon dioxide plume and pressure front have stabilized and 

that no additional monitoring is needed to assure that the geologic sequestration project does not 

pose an endangerment to USDWs.” Id. at 43,541 (proposed 40 C.F.R. § 146.93(b)(3)). Once the 

owners or operators provide documentation to show that this standard has been met, they can 

request that the Director authorize site closure. Id. at 43,520. By default, the “post-injection site 

care” period would last for 50 years following cessation of injection activities; however, the 

Director would have discretion to shorten the 50-year timeframe if the owner or operator could 

demonstrate “stabilization/no endangerment” in less than 50 years, or conversely, to lengthen the 

timeframe if the owner or operator failed to make a demonstration within 50 years. Id. 

As a general matter, ELPC and ETIP agree that a combination of a fixed timeframe and a 

performance standard strikes a good balance and is preferable to relying upon only one of those 

elements. Adherence to an exacting performance standard alone, defined before commercial 

deployment of CCS technologies, could preclude owner or operators from taking advantage of 

best practices as they are developed. Adherence to a single fixed timeframe could allow owner 

or operators to abandon well sites even as monitoring data indicates a threat to a USDW. 

Requiring the owner or operator to meet a flexible performance standard throughout a baseline 

period of 50 years would ensure that post-injection site care, including monitoring and 

verification, would continue as long as necessary to prevent endangerment of USDWs and 

require post-injection monitoring and modeling even if the data appear to show “stabilization” 

within a short timeframe. This would be especially prudent in the short term, given lack of data 

and experience with large-scale, long-term GS projects. 

Page 9 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

 

EPA should, however, clarify the performance standard element by defining the key term 

“stabilized” in the context of GS.6 See 73 Fed. Reg. at 43,540-41 (proposed 40 C.F.R. 

§ 146.93(b)(2)). It is unclear whether “stabilized” refers to certain measurable physical 

properties of the “carbon dioxide plume and pressure front” (such as pressure), or broadly 

describes some macro-state (for example, no movement of the CO2 over a specified period of 

time) that EPA is using as a proxy for USDW safety, or something else. EPA has promulgated 

more specific closure and post-closure standards for Class I wells and should follow suit here to 

avoid confusion, uncertainty, and potential threats to drinking water supplies. 

The owner or operator of a Class I hazardous waste injection well must observe and 

record “pressure decay” observations and show conformance to predicted values before site 

closure will be authorized. 40 C.F.R. § 146.71(d). During post-closure care, the owner or 

operator of a Class I well is required to continue monitoring “until pressure in the injection zone 

decays to the point that the well’s cone of influence no longer intersects the base of the 

lowermost USDW.” 40 C.F.R. § 146.72(b)(2). These standards provide more guidance than 

does the proposed regulation. 

ELPC and ETIP are sensitive to the numerous outstanding technical issues surrounding 

wide-scale use of CCS technologies and the importance of demonstration projects to solve many 

of those questions. Accordingly, while we view the EPA’s undefined use of the term 

“stabilization” as problematic for a closure standard, we are not prepared to recommend 

numerical monitoring targets or reach the specificity of the Class I well regulations. Even so, 

there is ample room for the EPA to adopt a stronger and better-defined post-injection site care 

6

 The term “stabilize” is also used in existing regulations governing surface impoundments under RCRA. See 40 

C.F.R. § 264.228(a)(2)(ii) (“At closure, the owner or operator must . . . stabilize remaining wastes to a bearing 

capacity sufficient to support final cover . . . .”). Although the term is not defined in those regulations either, those 

regulations do impose other specific requirements on the owner or operator (e.g., cover the surface impoundment 

with a final cover) that are measured in terms of specific factors like migration, erosion, maintenance, and 

permeability. See 40 C.F.R. § 264.228(a)(2)(iii)(A)-(E). 

Page 10 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

standard that gives greater assurances that USDWs will not be threatened while still allowing 

flexibility for innovation. 

 The World Resources Institute (WRI) recommendations avoid explicit use of the term 

“stabilization” and instead focus on the endangerment issue. Completion of the WRI postinjection monitoring requirements occurs when the owner or operator demonstrates “with a high 

degree of confidence that the storage project does not endanger human health or the 

environment.” SARAH M. FORBES ET AL., WORLD RESOURCES INSTITUTE, CCS GUIDELINES:

GUIDELINES FOR CARBON DIOXIDE CAPTURE, TRANSPORT, AND STORAGE 103 (2008) [hereinafter 

WRI GUIDELINES]. WRI suggests that an owner or operator can make this demonstration by 

showing: 

1. the estimated magnitude and extent of the project footprint 

(CO2 plume and the area of elevated pressure), based on 

measurements and modeling; 

2. that CO2 movement and pressure changes match model 

predictions; 

3. the estimated location of the detectable CO2 plume based on 

measurement and modeling (measuring magnitude of 

saturation within the plume or mapping the edge of it); 

4. either (a) no evidence of significant leakage of injected or 

displaced fluids into formations outside the confining zone, or 

(b) the integrity of the confining zone; 

5. that, based on the most recent geologic understanding of the 

site, including monitoring data and modeling, the [CO2 plume 

and formation water] are not expected to migrate in the future 

in a manner that encounters a potential leakage pathway; and 

6. that wells at the site are not leaking and have maintained 

integrity. 

Id. Requirements four, five, and six all address stabilization, but in language more precise than 

the approach offered by EPA. Where EPA leaves open the definition of “stabilize,” WRI offers 

a more exacting standard built from terms like “leakage,” “integrity,” and “migrate.” The WRI 

approach provides a standard more certain to ensure that non-endangerment is achieved while 

Page 11 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

 

preserving flexibility for owner or operators to develop best practices as CCS continues to 

develop. In addition, WRI’s more specific closure standard is more consistent with the models 

employed in existing EPA regulations for Class I wells. See supra pp. 9-10. 

D. EPA Should Expand the Emergency and Remedial Response Requirements 

The proposed emergency and remedial response provisions are meant to address threats 

to USDWs that may arise during the lifetime of a Class VI well. 73 Fed. Reg. at 43,541 

(proposed 40 C.F.R. § 146.94(a)). As part of the permitting process, the owner or operator is 

required to submit a remedial response plan describing responses “address[ing] movement of the 

injection or formation fluids that may cause an endangerment to a USDW.” Id. The plan should 

cover the “construction, operation, closure and post-closure” phases of the GS project.7 Id. 

No additional guidance for the plan’s contents is provided by the proposed regulation. 

The emergency and remedial response provisions are too narrow in that they fail to 

address ways in which GS may endanger USDWs other than “movement of the injection or 

formation fluids.” For example, as a result of the CO2 mixing with fluid during or after injection, 

two problems may occur. First, the mixture can be highly corrosive, thereby potentially 

weakening the well and/or the containment boundaries and increasing the risk inherent to all 

Class VI wells that injected fluids will migrate outside the containment zone. Second, the 

corrosive liquid can cause metals and minerals present in a specific containment zone to leach, 

migrate, and threaten USDWs. Under the proposed regulation, these dangers would not be 

accounted for in the owner or operator’s emergency and remedial response plan. The emergency 

and remedial response provisions should be expanded to address these concerns. 

7

 It is unclear whether EPA intended the term “operation” to include the post-injection site care period (which 

precedes site closure). See 73 Fed. Reg. at 43,540-41 (proposed 40 C.F.R. § 146.93). EPA should clarify this 

language and require that the emergency and remedial response plan specifically cover the post-injection site care 

period. 

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 Submitted by Harvard Law School Environmental Law & Policy Clinic 

Further, the draft regulations require the owner or operator to report and implement its 

emergency and remedial response plan only if the “owner or operator obtains evidence that the 

injected carbon dioxide stream and associated pressure front may cause an endangerment to a 

USDW.” Id. at 43,541 (proposed 40 C.F.R. §146.94(b)). As an initial matter, the phrase 

“obtains evidence” is undefined and has no clear meaning within the regulation. ELPC and ETIP 

recommend that EPA clarify the term. Further, like proposed 40 C.F.R. section 146.94(a), 

proposed section 146.94(b) is too narrow, for two reasons. First, it is unclear why EPA should 

rely solely on evidence obtained from owners or operators. ELPC and ETIP recommend that 

EPA require that remedial (or at least investigatory) responses be triggered by information from 

third parties in addition to owners or operators, including but not limited to sub-surface, surface 

or adjacent property owners, as well as government entities. Second, the owner or operator’s 

duty to report and implement the remedial response plan would not be triggered in every instance 

in which a USDW may be endangered. ELPC and ETIP recommend expanding the trigger to 

include, for example, instances where leaching of metals or minerals is detected (by the owner or 

operator or third parties). 

III. Providing Certainty with Respect to Financial Assurance Requirements and Shortand Long-Term Liability 

A. Financial Assurance 

The role of financial assurance requirements, generally, is “to ensure that owners and 

operators maintain adequate financial resources to fulfill their current and future environmental 

obligations [and] to minimize the number of facilities that are orphaned and abandoned; thereby, 

reducing the potential that these costs will be borne by the public.” OFFICE OF WATER, U.S.

ENVTL. PROT. AGENCY, APPROACHES TO GEOLOGIC SEQUESTRATION SITE STEWARDSHIP AFTER 

SITE CLOSURE 3 n.2 (July 2008) [hereinafter, “EPA SITE STEWARDSHIP”]. To serve these 

purposes, “[f]inancial responsibility must span the entire life of a project (from capture through 

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 Submitted by Harvard Law School Environmental Law & Policy Clinic 

post-closure stewardship) and must include adequate assurance that there is sufficient funding to 

cover the net present value of estimated closure . . . and post-closure[.]” WRI GUIDELINES at 58. 

The adequacy of financial assurances is not tested, however, until the owner or operator is unable 

or unwilling to fulfill its obligations at a facility. “The ultimate test of whether financial 

assurances are adequate is an owner’s bankruptcy. If an owner declares bankruptcy and the 

financial assurances are found to be inadequate, drinking water sources may be at risk and the 

public may be required to bear the cost of closing a well. Consequently, any uncertainties about 

the adequacy of financial assurances need to be minimized.” U.S. GENERAL ACCOUNTING 

OFFICE, GAO-03-761, DEEP INJECTION WELLS: EPA NEEDS TO INVOLVE COMMUNITIES EARLIER 

AND ENSURE THAT FINANCIAL ASSURANCE REQUIREMENTS ARE ADEQUATE 22 (2003)

[hereinafter GAO REPORT], cited in 73 Fed. Reg. at 43,521 (discussing financial assurances for 

Class I wells). 

The proposed regulation for GS require owners and operators to make financial 

assurances, but the requirements are so vague that they likely will lead to uncertainty, confusion, 

inconsistent and/or fiscally imprudent practices by the states, and other problems. The proposed 

regulation also does not do enough to ensure that the amount of the financial assurances reflects 

the most current cost estimates and includes some margin of error or fund to cover unplanned 

costs. As a result of these failures, drinking water sources (and the broader environment) and the 

public are at risk of finding that financial assurances are inadequate to cover actual operational, 

closure or post-closure costs for a GS facility in the event the facility is unwilling or unable to 

cover such costs. EPA should revise the proposed regulation in the various ways described 

below to minimize that risk. 

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1. EPA Should Prescribe the Use of Specific Financial Assurance 

Instruments. 

 The proposed regulation establishes that the owner or operator must demonstrate and 

maintain financial assurance: 

The owner or operator must demonstrate and maintain financial 

responsibility and resources for corrective action (that meets the 

requirements of § 146.84), injection well plugging (that meets the 

requirements of § 146.92), post injection site care and site closure (that 

meets the requirements of § 146.93), and emergency and remedial 

response (that meets the requirements of § 146.94) in a manner described 

by the Director .... 

73 Fed. Reg. at 43,537 (proposed 40 CFR § 146.85(a)), but it does not adequately inform owners 

and operators (and state Directors) how to satisfy that duty. EPA admits as much, stating in the 

preamble that for now, it “is proposing that the rule only specify a general duty to obtain 

financial responsibility acceptable to the Director,” and that it will publish guidance “that 

describes recommended types of financial mechanisms that owners or operators can use to meet 

this requirement” at some unspecified future date. Id. at 43,520. 

As discussed below, EPA’s long experience with Class I wells, RCRA, and other 

regulatory frameworks demonstrates that vague financial assurance standards do not work. 

EPA should specify—now, not later, and in the regulation itself—the mechanisms by which a 

well owner or operator may demonstrate financial assurance.8

 In developing its list of 

8

 Merely providing EPA guidance on the subject, as EPA is proposing to do, is insufficient given the fact that 

guidance is not legally binding on EPA. EPA is free to follow the guidance or to act at variance with it, depending 

onthe facts of a particular case. See e.g., Memorandum from Victor J. Kimm, Office of Drinking Water, U.S. EPA, 

to Water Division Directors and Water Supply Branch Chiefs, Regions I-X, U.S. EPA, 1-2 (May 29, 1985) (“This 

manual is a guidance piece to be used on a case-by-case basis, taking into consideration all relevant factors.”) 

(emphasis in original); see also Cement Kiln Recycling Coalition v. EPA, 493 F.3d 207, 227 (D.C. Cir. 2007) 

(holding that a different EPA guidance was designed to “have the flexibility to make adjustments for the specific 

conditions” and was non-binding on EPA). EPA should follow the recommendation that the states and regions 

made (in the RCRA context), to address concerns about insufficient guidance with respect to financial assurance on 

a national level, by including detailed guidance in the regulations themselves. See OFFICE OF INSPECTOR GENERAL,

U.S. ENVTL. PROT. AGENCY, REPORT NO. 2005-P-00026, CONTINUED EPA LEADERSHIP WILL SUPPORT STATE 

NEEDS FOR INFORMATION AND GUIDANCE ON RCRA FINANCIAL ASSISTANCE 2 (2005) [hereinafter OIG REPORT],

cited in 73 Fed. Reg. at 43,521 (“The States and regions . . . expressed consistent concerns with aspects of financial 

assurance. They believed these concerns would be best addressed at the national level by EPA, including a 

rulemaking process that would revise the existing financial assurance regulations [under RCRA].”). 

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 not 

r trust funds). Id. at 43,521. 

acceptable financial assurance mechanisms for GS, EPA should incorporate the 

recommendations made by the General Accounting Office (“GAO”) and EPA Office of 

Inspector General (“OIG”) in the reports that EPA describes in the preamble (for example, by

allowing captive insurance, see p. 22, infra). 73 Fed. Reg. at 43,521-22. Also, EPA should 

make sure to provide detailed guidance, especially regarding the problem areas highlighted by 

GAO and OIG in their reports (for example, regarding cost estimation methodology or pay-in

period fo

To minimize uncertainty (and the attendant risk to drinking water supplies and the 

public), EPA must provide as much detailed guidance as possible. It should look to existing lists 

of acceptable financial mechanisms in other EPA programs as just a starting point. 

EPA’s RCRA regulations (40 C.F.R. § 264.143) include a list of acceptable financial 

mechanisms, yet OIG reports that states implementing the RCRA regulations have “expressed 

consistent concerns” regarding “insufficient guidance” in a number of important areas, 

prompting OIG to recommend that EPA issue additional guidance for its RCRA financial 

assurance mechanisms. OIG REPORT at 3, 9-12. OIG found that a lack of clear guidance led 

states to accept a broad range of financial assurance mechanisms, some of which were 

“not explicitly allowed by Federal regulations” and others that were not fiscally prudent. 

See OIG REPORT at 11. To avoid those same problems in the GS context, EPA should provide a 

list of acceptable financial mechanisms like that included in the existing RCRA regulations, but 

make sure to add more detailed guidance to the GS financial assurance provisions. 

Such guidance should be based on “best practices” for each of the acceptable financial 

mechanisms. OIG REPORT at 12. 

Further, time is of the essence. For maximum benefit, EPA should act as soon as 

possible to include detailed guidance on financial assurance in any regulation for GS, while 

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large-scale CCS projects are still in the early planning stages (or are not yet being planned). 

“Experience shows that it is often necessary to put [financial responsibility] mechanisms in place 

before [a] project can move forward.” WORLD RESOURCES INSTITUTE, WORKSHOP SUMMARY:

ADDRESSING LONG-TERM LIABILITY OF CARBON DIOXIDE CAPTURE AND GEOLOGICAL 

SEQUESTRATION 5 (2007) [hereinafter WRI WORKSHOP SUMMARY]. A clear description of 

required financial mechanisms allows “[p]roject developers, financiers, and insurers . . . to know 

the operational and regulatory requirements up front in order to manage costs and risks.” Id. at 

1. Without a clear description from EPA of which mechanisms will be allowed, project owners 

and operators will have to account for the additional risk that their chosen financial mechanism 

will not be acceptable to the Director. EPA should also provide this guidance as soon as possible 

so that states do not create conflicting financial assurance requirements. A lack of clear 

standards creates a potential “race-to-the-bottom” as states compete to set the lowest standards 

for financial assurances in an effort to attract GS projects. See ALEXANDRA B. KLASS AND 

ELIZABETH J. WILSON, CLIMATE CHANGE AND CARBON SEQUESTRATION: ASSESSING A LIABILITY 

REGIME FOR LONG-TERM STORAGE OF CARBON DIOXIDE 30 (2008), available at 

http://works.bepress/com/alexandra_klass/4,_(discussing the presence of the “race-to-thebottom” in connection with FutureGen). As financial assurance requirements are relaxed, the 

public loses its assurance “that adequate care and funding will be in place to manage storage 

facilities.” WRI WORKSHOP SUMMARY at 1. With states unsure, industry also would have 

uncertainty over the fact that assurances now accepted by a state Director later may be deemed 

inadequate under more detailed guidance. This uncertainty is especially problematic under 

market conditions, such as today’s, in which financing may be difficult to secure in the first 

place. See Peter S. Goodman, Credit Enters a Lockdown, N.Y. TIMES, Sep. 26, 2008, at A1. 

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EPA’s implementing regulations under the Class I deep injection well program provide at 

least a starting point for EPA to use in compiling the list of acceptable financial assurance 

mechanisms for GS.9 40 C.F.R. § 144.63 provides that “an owner or operator of each facility 

must establish financial assurance for the plugging and abandonment of each existing and new 

Class I hazardous waste injection well” in one of the following ways: (a) establishing a 

“plugging and abandonment trust fund”; (b) “surety bond guaranteeing payment into a plugging 

and abandonment trust fund”; (c) “surety bond guaranteeing performance of plugging and 

abandonment”; (d) “plugging and abandonment letter of credit”; (5) “plugging and abandonment 

insurance”; (6) corporate guarantee of plugging and abandonment (after passing a financial test); 

or (7) a combination of “trust funds, surety bonds guaranteeing payment into a trust fund, letters 

of credit, and insurance.” These mechanisms are similar to, but more detailed, than the Class II 

mechanisms which EPA suggests it intends to use as a model for the financial mechanisms for 

GS. See 73 Fed. Reg. at 43,521. They are also nearly identical to the financial assurance options 

available under the RCRA program. See 40 C.F.R. § 264.143. EPA should use the Class I 

regulations, as opposed to the Class II guidance, as a starting point, eliminate any that are not 

suitable for long-term CO2 containment, and include a list of acceptable financial assurance 

mechanisms in the proposed regulation for GS. 

2. EPA Should Implement OIG’s and GAO’s Recommendations. 

Regardless of whether EPA chooses the Class I, Class II or RCRA program (or a 

combination) as a model when developing the financial assurance requirements for GS, 

EPA should make sure to implement OIG’s and GAO’s recommendations as well. See 73 Fed. 

Reg. at 43,522-23 (discussing OIG’s and GAO’s recommendations for EPA’s financial 

assurance requirements). 

9

 We recommend, however, that EPA only adopt these standards with the GAO and OIG’s recommendations in 

mind. See section III(A)(2) below. 

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OIG’s and GAO’s criticisms and recommendations are well described in the preamble, 

but then are entirely ignored in the actual regulation. See 73 Fed. Reg. at 43,521. Those offices 

“have raised issues regarding the use of financial responsibility instruments applicable to site 

closure for several EPA programs.” 73 Fed. Reg. at 43,521. The Class I, Class II and RCRA 

guidance and regulations have not been updated to reflect OIG’s and GAO’s recommendations, 

so many of the financial assurance mechanisms criticized by the OIG and GAO are still accepted 

in those programs. Id. According to GAO, those “financial assurance requirements may not 

ensure that adequate resources are available to close a commercial deep injection well in the 

event of bankruptcy or ceased operations.” GAO REPORT at 1. 

In fact, GAO found that of the four Class I wells which “have gone into bankruptcy or 

ceased operating since the program began in 1980; two did not have adequate financial resources 

to plug and abandon wells.” Id. Financial assurance for the other two wells “was not tested 

because other companies purchased and continued operating the wells.” Id. GAO recognized 

that “it is increasingly difficult for owners to meet [existing] financial assurance requirements” 

for injection wells, but cautioned that “failure to do so risks contaminating underground drinking 

water sources.” Id. at 21. 

a. EPA Should Pay Special Attention to GAO’s and OIG’s 

Recommendations for Reforming Financial Test and Corporate 

Guarantee Mechanisms. 

 

EPA should reform the means for meeting the financial test and corporate guarantee in 

accordance with the recommendations of OIG and the Environmental Finance Advisory Board 

(“EFAB”). EFAB has recommended the use of “independent third-party assessment” of a 

company’s credit ratings. Letter from A. Stanley Meiburg, Executive Director, Environmental 

Finance Advisory Board to Stephen L. Johnson, Administrator, U.S. EPA 6 (Jan. 11, 2006). 

“Using an independent third party will relieve [the Director] of the administrative burden of 

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reviewing financial statements” as well as alleviate concerns about the Director’s “capacity to 

adequately undertake such review.” Id. EPA should also follow OIG’s recommendations by 

making sure that any financial tests are in conformance with the generally accepted accounting 

principles of today. OIG REPORT at 17. 

EPA should indicate that it will review financial test practices on a periodic basis to avoid 

acceptance of a “financial test on a less stringent opinion [from a certified public accountant] 

than those that certify conformance with generally accepted accounting principles.” Id. at 15. 

EPA states that it is also “considering whether adjustments should be made to the 

absolute net worth threshold of $10 million currently required under the UIC regulations.” 

73 Fed. Reg. at 43,522. EPA notes that other Federal Agencies and programs require different 

measures of net worth. Id. For instance, both Class I and RCRA regulations require a showing 

of “at least six times the sum” of covered costs as measured in the current cost estimate. 

40 C.F.R. §§ 144.63(f)(1)(i)(b); 265.143(e)(1)(i)(b). EPA also cites as an example the Minerals 

Management Service, which “requires a net worth threshold at least 10 times the amount of the 

obligations being assured.” 73 Fed. Reg. at 43,522. A study of cost estimates for GS suggests 

that estimates “can be made with confidence” given that storage “technologies and equipment” 

are already being used in the oil and gas industries. INTERGOVERNMENTAL PANEL ON CLIMATE 

CHANGE, IPCC SPECIAL REPORT ON CARBON DIOXIDE CAPTURE AND STORAGE 345 (2005). 

Although costs may vary significantly from project to project due to the “geological 

characteristics of the storage formation,” the “reservoir depth,” the monitoring mechanism, and 

other factors, once these factors are identified, costs estimates can be made with some reliance. 

Id. 

In determining whether either threshold—or another alternative—is appropriate, the 

EPA should consider other factors as well, including a company’s net worth/obligations ratio, 

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cash flow, commitments to other projects, and percentage of assets that may not be reachable 

under United States law. 

b. EPA Should Implement the Recommendations Made by OIG and 

GAO Regarding Insurance Mechanisms Before Allowing Their Use 

by Owners or Operators 

EPA also notes that it “is assessing whether to provide guidance on the use of insurance 

providers” and whether to allow insurance as a financial assurance mechanism for GS wells at 

all. 73 Fed. Reg. at 43,521. Given the lack of experience using private commercial insurance for 

injection wells, EPA should develop clear guidelines for its use in this context. The guidance 

should take into account the “numerous problems” with insurance reported by states in the 

RCRA context, “including the difficulty of getting claims paid and lack of State awareness of the 

true coverage provided by the policy.” OIG REPORT at 3. Furthermore, “the lack of 

standardized language for policies” creates problems for Directors in approving the plan. Id. 

At the very least, EPA should consult with insurers currently involved in sequestration and oil 

and gas injection projects in the United States and abroad. This will allow EPA to better 

understand the role of insurance in providing financial assurances and how to best manage the 

use of insurance for this purpose. EPA should include representatives from OIG, GAO and 

EFAB in those consultations. 

If insurance is allowed, EPA should make sure to exclude “captive insurance” from the 

definition of acceptable insurance. GAO defines captive insurance companies as “wholly owned 

subsidiaries of the corporation they are insuring.” GAO REPORT at 20. This kind of insurance 

provides the public with “little confidence that the captive insurance company will provide the 

funds to pay for closure” if “the parent company experiences financial difficulty.” Id. Captive 

insurance leaves “no independence of risk between the corporate parent and the company 

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insured.” OIG REPORT at 15-16. These policies “are also high risk if they cannot be assigned to 

different owners” if a GS site is sold. GAO REPORT at 20.

c. EPA Should Set a Firm Timeline for Issuing More Detailed 

Regulations on Financial Assurance Mechanisms. 

EPA’s bare promise that it will develop further guidance at some unspecified later date 

runs afoul of the recommendations made by OIG and referenced by the proposed regulation. 

73 Fed. Reg. at 43,520-21. In 2005, OIG urged the EPA to “[d]evelop and communicate EPA’s 

plan for addressing concerns with the existing financial assurance regulations . . . .” 

OIG REPORT at 17. “The plan should include milestones, decision points, and timelines for 

taking action, and indicate when and how EPA will determine if a rulemaking is necessary.” Id. 

Although OIG made that recommendation in reference to updating existing financial assurance 

regulations under RCRA, the reasoning underlying the recommendation applies equally in this 

situation. 

3. EPA Should Require Owners or Operators to Re-Demonstrate Financial 

Assurance Throughout the Life of the Project. 

The proposed regulation states that the “owner or operator must demonstrate and 

maintain financial responsibility and resources” until the post-injection site care period ends and 

the Director has approved the site closure plan. 73 Fed. Reg. at 43,538 (proposed 40 C.F.R. 

§ 146.85(a)) (emphasis added). At certain times during the life of the GS project, the owner or 

operator is required to provide to the Director adjustments to the cost estimates upon which the 

financial assurances are based. See 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 146.85). 

For example, proposed 40 C.F.R. § 146.85(b) requires the owner or operator to “provide to the 

Director, at a frequency determined by the Director, written updates of adjustments to the cost 

estimate,” but only when the owner or operator amends a plan (area of review and corrective 

action plan, injection well plugging plan, etc.). Meanwhile, proposed 40 C.F.R. § 146.85(d) 

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requires the operator to “provide an adjustment of the cost estimate to the Director if the Director 

has reason to believe that the original demonstration is no longer adequate to cover the cost of 

injection well plugging . . . and post-injection site care and site closure[.]” The regulation, 

however, does not automatically require an owner or operator to re-demonstrate financial 

assurances to reflect adjustments in cost estimates. See id. at 43,537 (proposed 40 C.F.R. § 

146.85). As a result, the financial assurances “maintained” by the owner or operator may 

become outdated over time. Instead, EPA should require that the owner or operator redemonstrate financial assurances on a regular basis (perhaps with each adjustment of cost 

estimates) so that an owner or operator “maintains” financial assurance that reflects the most upto-date cost estimate information. 

In the same vein, EPA should require periodic re-demonstration of financial assurance to 

account for inflation. See id. at 43,522 (stating that EPA is still “considering” whether to include 

provisions for annual inflationary adjustments).. 

4. The Regulation Fails to Require Financial Assurance for All 

Contingencies and Costs of Protecting Drinking Water Supplies. 

The amount of financial assurance required by the proposed regulation is based entirely 

on the costs estimated by the owner or operator (and accepted by the Director) in its plans for 

corrective action, well plugging, post-injection site care, site closure, and emergency and 

remedial response as defined by the regulations. 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. 

§ 146.85(a)). There are many reasons why the demonstrated amount could turn out to be 

inadequate to cover actual costs, yet EPA has not addressed financing to cover these 

contingencies.10 For example, the owner or operator may simply underestimate costs for the 

various covered operations, because of lack of experience with the new technology, or confusion 

10 ELPC and ETIP also are concerned that the financial assurance does not cover costs not contemplated by the plans 

or harms caused by the GS activity but affecting interests other than public drinking water supplies, such as, for 

example, harms to private drinking water supplies. 

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regarding cost estimation techniques, or other reasons. Or, any part of the GS operation may 

take longer than expected and in turn incur more costs. Or, the demonstrated amount was not 

updated to reflect adjusted cost estimates or was not adjusted for inflation. Then there is the 

problem of occurrences or accidents that are completely unanticipated and unplanned. In light of 

the many unknowns associated with large-scale GS at this time, it seems prudent to factor in a 

margin of error to the owner or operator’s cost estimates, which would allow for some unplanned 

costs to be covered by financial assurances. To address catastrophic, “break-the-bank” 

accidents, however, EPA should consider utilizing a funding mechanism based upon the PriceAnderson Nuclear Indemnities Act or other models. 

The proposed regulation requires the owner or operator to “provide the Director with an 

emergency and remedial response plan that describes actions to be taken to address movement of 

the injection or formation fluids that may cause an endangerment to a USDW.” Id. at 43,541 

(proposed 40 C.F.R. § 146.94(a)). Proposed 40 C.F.R. § 146.85 requires the owner or operator 

to maintain financial assurance to cover the emergency plan. However, neither that provision 

nor proposed section 146.94 indicates how the costs should be estimated. 73 Fed. Reg. at 

43,537, 43,541. Proposed 40 C.F.R. § 146.94 also does not explain how the owner, operator or 

Director will cover the costs of emergencies not anticipated by the plan. In fact, since the only 

emergencies covered are those already anticipated by the emergency planning provisions, truly 

unanticipated events are not covered. 

Given the many uncertainties surrounding GS, the prospect that a GS operation will 

proceed, or that a CO2 plume will behave, in a way that is “unplanned” is real. See WRI ISSUE 

BRIEF at 9 (“A need remains for ongoing research and analysis into the post-injection risk 

profile.”). Furthermore, EPA notes, “it may be difficult to estimate the appropriate amount of 

funds that may be required at either an individual site or collectively at all sites.” EPA SITE 

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STEWARDSHIP at 25. In light of this, tying the financial assurance requirement to the owner or 

operator’s plans, without providing any margin of error or guidance for acceptable models to 

measure these costs, is risky and inappropriate. 

EPA should provide the regulated community and the public with greater assurance that 

project owners/operators will have the financial wherewithal to cover “the financial 

consequences of potential cost overruns” and of “unanticipated events.” WRI GUIDELINES at 78. 

The proposed regulations refer to updates of the “cost estimates” to reflect changes in costs of 

well operation, but do not set any standards for these estimates. 73 Fed. Reg. at 43,537. 

The Agency should require owners/operators to use rigorous cost estimation techniques to make 

sure that the owner or operator’s estimation of “planned” costs is as accurate as possible. 

“Sound cost estimation requirements ensure that sufficient funds are set aside in the financial 

assurance instrument.” Id. at 43,521; see also WRI ISSUE BRIEF at 8 (“Understanding . . . the 

attendant costs associated with mitigating each stage of risk [is] essential to assess the utility of, 

and appropriately price, various financial instruments for purposes of financial responsibility.”). 

Cost estimates should “be updated annually” and account for “inflation.” OIG REPORT at 2. 

EPA should require independent verification of all cost estimates as well. See 73 Fed. Reg. at 

43,521. 

EPA should also proceed with “allowing separate financial demonstrations to be 

submitted for the plugging of the injection well and for the post-injection site care requirements” 

in order to tie the most up-to-date cost estimation to financial assurance for later parts of the GS 

process. Id. at 43,522. Although EPA notes in the preamble that it “may be appropriate to redemonstrate financial responsibility on a periodic basis,” to “take into account any amendments 

to the area of review and corrective action plan . . . and adjustments for inflation,” it has not 

addressed this sentiment in the proposed regulations. Id. at 43,520. EPA should make it explicit 

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that a re-demonstration of financial responsibility is necessary any time there is a change in cost 

estimates, amendment to the area of review, or change in the corrective action plan. EPA also 

should require periodic re-demonstration of financial assurance to account for inflation as it 

indicates it is considering. 

Here again, EPA can draw upon its experience with cost estimation in the RCRA 

program. Under RCRA regulations, the “closure cost estimate must be based on the costs to the 

owner or operator of hiring a third party to close the facility.” 40 C.F.R. § 265.142(a)(2). 

This consideration better approximates the true costs to government of continuing post-injection 

operations. RCRA’s model provides enough collateral to cover closure costs should the owner 

or operator become insolvent and the financial assurance mechanism fail to cover the true costs 

of closure. EPA could also adopt the RCRA requirement that the estimate equal costs “at the 

point in the facility’s active life when the extent and manner of its operation would make closure 

the most expensive, as indicated by its closure plan,” thereby providing a margin of error in 

financial assurances for cost estimates. 40 C.F.R. § 265.142(a)(1). 

Perhaps more importantly, however, unplanned costs that could “break the bank” of the 

owner or operator must be addressed (such as, for example, costs associated with a catastrophic 

accident). See WRI WORKSHOP SUMMARY at 6 (identifying “‘break the bank’ risks” as one of 

the key issues that must be addressed by a financial assurance scheme for GS). Several 

commentators have suggested addressing such risks through the use of a funding scheme for GS 

that resembles that developed under the Price-Anderson Nuclear Industries Indemnity Act of 

1957, 42 U.S.C. § 2210, or the National Flood Insurance Act of 1968, 42 U.S.C. 4001 et. seq. 

WORLD RESOURCES INSTITUTE, WORKSHOP SUMMARY: ADDRESSING LONG-TERM LIABILITY OF 

CARBON DIOXIDE CAPTURE AND GEOLOGICAL SEQUESTRATION 5 (2007), at 6-8; EPA SITE 

STEWARDSHIP at 13-24 (discussing Price-Anderson and National Flood Insurance models, among 

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others); ALEXANDRA B. KLASS & ELIZABETH J. WILSON, CLIMATE CHANGE AND CARBON 

SEQUESTRATION: ASSESSING A LIABILITY REGIME FOR LONG-TERM STORAGE OF CARBON 

DIOXIDE 30 (2008), at 38-39, available at http://works.bepress/com/alexandra_klass/4. Creation 

of such a fund would provide the means to pay for costs in excess of any covered by financial 

assurance posted under proposed 40 C.F.R. § 146.85. 

The Price-Anderson Act, for instance, makes available a large pool of funds to cover 

public compensation for claims of personal injury and property damage. Although each large 

nuclear plant must obtain “primary financial protection” through financial assurance mechanisms 

similar to those acceptable under the UIC and RCRA programs, each company also contributes 

to a collective fund in order to pay for accidents beyond the scope of the financial assurance. 42 

U.S.C. § 2210(a)(1). A similar funding mechanism could be useful in the GS context to provide 

an additional source of funding in the event that financial assurance is insufficient to meet actual 

costs, for example in the case of a catastrophic incident. 

B. The Proposed Regulation Does Not Cover All Parties Involved in CCS Even 

Though Their Actions Create a Risk of Endangerment to USDWs. 

The proposed regulation applies only to “owners or operators of injection wells that will 

be used to inject CO2 into the subsurface for the purposes of GS.” 73 Fed. Reg. at 43,492; see id. 

at 43,534 (proposed 40 C.F.R. §144.18). Other parties involved in a CCS project, including the 

CO2 generator, transporter and surface and sub-surface property owner(s), are not covered. 

As EPA notes, though, “[t]he SDWA provides EPA with the authority to develop regulations to 

protect USDWs.” Id. at 43,495; see also 42 U.S.C. §300h(a)-(b), (d). That authority extends 

over all actors involved in the CCS process (not just the injection well owner or operator), at 

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least to the extent their actions may contribute to the risk of harm to USDWs.11 

For instance, EPA has recognized that “co-contaminants in the CO2 stream could 

endanger a USDW if the injectate migrates into a USDW.” 73 Fed. Reg. at 43,497. 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.” Id. at 43,503. 

Yet the proposed regulation’s current standard for stream purity is loosely defined. 

The proposed regulation allows injection of a stream with “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.” Id. at 43,535 (proposed 40 CFR § 146.81(d) 

(definition of “carbon dioxide stream”)). By regulating CO2 generators and CO2 stream 

treatment (purification) facilities directly, EPA could reduce the likelihood that a contaminated 

CO2 stream would be injected into a GS well and thereby reduce the likelihood that such 

contaminants would endanger a USDW.12 EPA should therefore consider setting specific 

requirements for the maximum concentrations of “incidental substances” in injected CO2 streams 

to reduce the uncertainty about the proper level of treatment required. By imposing financial 

assurance requirements on those parties, EPA could also reduce the likelihood that costs and 

damages arising from such contamination would go unpaid, for example, if such costs exceeded 

the security posted by the owner or operator. Regulatory oversight would make these firms 

“more likely to undertake operating decisions that consider environmental (and remediation) 

costs.” WRI ISSUE BRIEF at 6. 

11 ELPC agrees, however, that EPA does not have authority under the SDWA to address all of the conduct of all of 

the parties involved in CCS or all of the risks posed by CCS, and therefore urges EPA to advocate on behalf of a 

broader mandate from Congress. See discussion at Part III(C)(1)(b). supra. 

12 Note that even such a consideration would fall short of protecting many private sources of well-water which could 

be harmed by CO2 migration. EPA should provide for mandatory consultation with owners of private wells before 

permitting any sequestration project in an area with private well use. 

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As a matter of equity, parties other than owners and operators should also be regulated to 

“ensure that risks are borne by those who share in the benefit of [GS] technologies.” Id. at 9. 

For example, geological sequestration may “allow some [generators of CO2] to extend the life of 

their existing capital investment in plant machinery or plant processes.” 73 Fed. Reg. at 43,531. 

Moreover, since “it is caps on greenhouse gas emissions that will explicitly establish a price for 

CO2 and will encourage utilities and others to invest in CCS in order to meet those caps,” it is the 

generators of the CO2 —along with their customers—who may receive credits for sequestration. 

KLASS AND WILSON at 13. All parties who benefit from GS of CO2 should help bear the risks 

attendant to that sequestration. 

C. EPA’s Long-Term Liability Scheme for GS Does Not Adequately Protect the 

Public or Address the Concerns of Industry 

The proposed regulation sets out the following long-term liability scheme for GS: 

(1) owners and operators remain liable for the GS operation and all damages arising from it, in 

perpetuity; however, (2) owner and operators are required to post financial security only until the 

end of the site-care period, and are freed from this responsibility at site closure. 

The combination of these two elements, perpetual liability plus limited financial 

assurance, means that: (1) the public is at risk of more orphaned sites and uncompensated postclosure costs and damages; and (2) the industry is left with liability that is unlimited in scope or 

time. EPA should minimize the risks to the public by requiring owners and operators to post 

financial security and/or contribute to a national fund to cover costs and damages arising from 

post-closure incidents that endanger USDWs and to provide for the costs of post-closure 

monitoring, measurement, and verification (“MMV”). 

To address the issue of long-term care of GS facilities in a way that would balance the 

public interest in having the private sector pay for CCS with the private sector’s interest in 

removing obstacles to deployment of CCS, a long-term liability scheme for GS that would 

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transfer post-closure site care and MMV to the government once closure conditions are met 

should be developed. EPA should seek from Congress the additional authority it would need to 

establish such a scheme. 

1. The Problem of Long-Term Care of GS Facilities 

 Long-term liability “comprises both anticipated costs associated with the long-term care 

of a storage facility and the potential for costs associated with unanticipated damages.” WRI

WORKSHOP SUMMARY at 1. EPA has discussed the issue of long-term liability for GS in various 

workshops leading up to the proposed regulation and seems to recognize that it is a key issue that 

must be addressed. See 73 Fed. Reg. at 43,500-01 (discussing EPA’s participation in, or hosting 

of, workshops to discuss “key questions and considerations” including long-term financial 

assurance and liability); see also UNITED NATIONS FRAMEWORK CONVENTION ON CLIMATE 

CHANGE (“UNFCCC”), FACT SHEET: INVESTMENT AND FINANCIAL FLOWS FOR A STRENGTHENED 

RESPONSE TO CLIMATE CHANGE 1 (2007) (discussing critical factors for large scale 

implementation of CCS: developing the technology, managing public perception, and deciding 

upon a long-term liability regime); MARK E. FESMIRE ET. AL., NEW MEXICO ENERGY, MINERALS,

NATURAL RESOURCES DEPARTMENT, CARBON DIOXIDE SEQUESTRATION: REPORT ON IDENTIFIED 

STATUTORY AND REGULATORY ISSUES 40 (2007). (“The various forms of liability 

(e.g., economic and environmental) inherent in proposed sequestration projects and how they 

will be addressed within a given regulatory framework are perceived as being significant factors 

in making sequestration projects feasible and for attaining public acceptance of the technologies, 

processes and regulations.”); WRI WORKSHOP SUMMARY at 1 (“Long-term liability is one of the 

several important challenges that CCS faces.”). 

Given the indefinite long-term lifespan of GS projects, stakeholders and policy makers 

have struggled with how to establish a framework that balances the interests of the private sector 

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(in avoiding perpetual, limitless liability) and the public (in being protected against adverse 

impacts and the risk of uncompensated costs and damages). One prominent view among 

policymakers is that a regulatory regime for GS should include a transfer of liability to the public 

at some point in time. ELPC and ETIP favor an approach that would require the GS 

owner/operator to calculate and pay into a fund or otherwise set aside the funds needed to cover 

the costs with (1) MMV or its Class VI wells and (2) remediation, corrective action, personal 

injury, natural resource damages, treatment of contaminated drinking water supplies, and the like 

that, while unlikely, are nonetheless possible, and, hence the public sector should not bear the 

entire cost (or risk). EPA’s proposal to regulate GS within a UIC framework applies a different 

long-term liability regime to GS, as discussed below.

2. EPA’s Proposed Regulation 

Under the proposed regulation, “the owner or operator of a GS site is released from postinjection site care responsibilities” (including all monitoring or reporting responsibilities) upon 

site closure. 73 Fed. Reg. at 43,535 (proposed 40 C.F.R. § 146.81(d)) (defining “site closure” as 

“the point/time, as determined by the Director following the requirements under § 146.93, at 

which the owner or operator of a GS site is released from post-injection site care 

responsibilities”)). The owner or operator also is released from responsibility for posting any 

financial assurance. 73 Fed. Reg. at 43,522 (“[O]bligation for financial responsibility ends for 

owners or operators after the post-injection site care period has ended and the Director has 

authorized site closure[.]”). Thus, once the site is closed, the owner or operator’s only remaining 

regulatory responsibility is to retain its records for a period of three years. See id. at 43,541 

(proposed 40 C.F.R. § 146.93(g)). 

As the EPA notes in the preamble to the proposed regulation, it is assuming that postclosure liability will remain with the owner or operator of the site. 73 Fed. Reg. at 43,522 

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(“[O]wners or operators may still be held responsible after the post-injection site care period has 

ended . . . . Trust responsibility for potential impacts to USDWs remains with the owner or 

operator indefinitely under current SDWA provisions.”). Presumably, this would apply to 

liability for both anticipated costs associated with the long-term care of a storage facility and the 

potential for costs associated with unanticipated damages. See 42 U.S.C. § 300j-8(e) (“Nothing 

in this section shall restrict any right which any person (or class of persons) may have under any 

statute or common law to seek enforcement of any requirement prescribed by or under this 

subchapter or to seek any other relief.”). 

There are a number of significant problems with this perpetual-liability-but-limitedfinancial-assurance approach. 

a. The Public Is at Risk 

The limited financial assurance element puts the public at risk. The proposed 

regulation’s failure to require the owner or operator to maintain any financial assurance during 

the post-closure period means that the public has (by definition) no assurance that the owner or 

operator will in fact be able to pay the cost of post-closure incidents. The owner or operator 

may no longer be in existence or otherwise unable to pay, leaving the public, the state, or the 

individual victims to bear the uncompensated damages of any migration, leakage, or damage that 

occurs after a site is closed. Given the uncertainties of CCS technology at this time and the 

anticipated indefinite lifetime for GS wells, the government must anticipate that some number of 

post-closure incidents will occur, and it must provide the public with assurance that any costs or 

damages arising from them will be paid. 

b. Industry Lacks Certainty 

 In addition to burdening the public with risks of future costs, the proposed regulation’s 

infinite liability leaves potential owners/operators with much uncertainty as to the management 

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of their responsibilities. This uncertainty could significantly hamper large-scale industry 

investment in CCS. EPA is aware of this problem, but the proposed regulation does not offer a 

solution: 

Responsibility for long-term care is often considered an important 

topic related to GS because of cost implications of indefinite 

responsibility for GS sites. Because of the focus of the SDWA on 

endangerment to USDWs and the absence of provisions to allow 

transfer of liability, stakeholders have expressed interest in 

alternative instruments for addressing financial responsibility after 

the post-injection care period has ended. As a result of the interest 

in alternative instruments, including indemnity programs, EPA has 

compiled information on a variety of alternative instruments not 

currently available under the SDWA. . . . EPA has not determined 

whether any of the models are appropriate for GS wells, however, 

EPA is aware that these models may contain important concepts 

that may become the model for future strategies for long-term care. 

73 Fed. Reg. at 43,522. 

 Until those “future strategies” are incorporated into the regulations for GS, however, 

industry is left with indefinite long-term liability (in the proposed regulation), which could 

impede implementation of large-scale GS. 

3. EPA Should Extend Its Financial Assurance Requirements Into The PostClosure Period and Transfer MMV Responsibilities to the Government. 

The risk to the public can be addressed by requiring owners/operators to post financial 

security and/or pay into a national fund to cover costs and damages arising after site closure. 

There is no reason why EPA cannot do this using its existing authority under the SDWA. 

As EPA itself states, “[a]lthough the SDWA does not have explicit provisions for financial 

responsibility, as included in RCRA, EPA believes that the general authorities provided under 

the SDWA authority to prevent endangerment of USDWs include the authority to set standards 

for financial responsibility to prevent endangerment of USDWs from improper . . . management 

of wells after site closure.” 73 Fed. Reg. at 43,520 (emphasis added). 

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Many commentators have suggested that government should put in place a long-term 

liability scheme which includes the transfer of liability to the public at a reasonable point in time 

and after satisfaction of performance standards. See generally WRI WORKSHOP SUMMARY at 6 

(“Some participants voiced the opinion that the private sector could adequately deal with the 

risks, but would need the public sector to take over the long-term responsibility for 

monitoring.”); MIT, THE FUTURE OF COAL: OPTIONS FOR A CARBON-CONSTRAINED WORLD 60 

(2008), available at http://web.mit.edu/coal/The_ Future_ of_Coal.pdf (“The government needs 

to assume liability for the sequestered CO2 once injection operations cease and the site is closed. 

The transfer of liability would be contingent on the site meeting a set of regulatory criteria . . . 

and the operators paying into an insurance pool to cover potential damages from any future CO2

leakage.”). The New Mexico Report summarizes neatly, 

Nearly all of the sequestration literature assumes that long-term 

liability must be transferred to the public sector to maintain 

economic viability and to encourage industry participation. 

Because the lifespan of sequestration projects after closure, 

which would include continuous [MMV] of the reservoir 

integrity, is contemplated to endure for possibly hundreds to 

thousands of years, the public sector (because of the longevity 

of public institutions and the ease of transferability of 

institutional knowledge) is seen as the most viable entity 

capable of maintaining these projects over the long term. 

FESMIRE ET AL., supra, at 39. 

ELPC and ETIP agree that transferring liability to the public during the post-closure 

period is sensible so long as there are effective cost-sharing arrangements and other limitations 

on the financial burden to be borne by the public. Notably, the transference of liability is not the 

only way to monitor and maintain these projects over the long term. For example, Australia’s 

proposed regulations for off-shore sequestration of CO2 intend that when a site is “closed” and 

the owner or operator vacates the site, post-closure long-term monitoring will be carried out by 

the Commonwealth, the cost of such monitoring nevertheless remains the responsibility of the 

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operator, who must post financial security for the estimated cost of long-term monitoring and is 

liable to the Commonwealth for actual costs incurred. See Offshore Petroleum Amendment 

(Greenhouse Gas Storage) Bill 2008 § 249CZGAA & Explanatory Memorandum Attachment A 

at 27. 

A regulatory regime for GS in the U.S. too, could incorporate financial assurances and/or 

funding to address the long-term costs of MMV post-closure.13 See Jeffrey W. Moore, The 

Potential Law of On-Shore Geological Sequestration of CO2 Captured From Coal-Fired Power 

Plants, 28 ENERGY L.J. 443, 468 (2007) (advocating a site-specific, risk-based approach to GS 

regulation). Additionally, the long-term liability scheme could provide for a national fund to 

address all other costs (e.g., remediation and corrective action), as well as damages relating to 

any incident at any closed GS facility. 

The ELPC and ETIP support the transfer of responsibility not only because it is a 

practical solution to the problems of ensuring long-term care and responsibility of GS sites while 

encouraging sufficient investment, but also from a moral standpoint—“philosophically, 

everyone—not just industry—is responsible in part for climate change and should bear some 

burden for its mitigation.” FESMIRE ET AL., supra, at 59. 

a. EPA’s Need for Additional Authority 

 In the preamble to the proposed regulation, EPA notes (probably correctly) that it lacks 

authority under the SDWA to establish a comprehensive long-term liability scheme for GS such 

as the one outlined above. “The SDWA authority . . . does not cover transfer of owner or 

13 The proposed UIC regulations address MMV post-site closure very minimally. The ELPC and ETIP believe that 

given the uncertainties of GS and the great discretion which the proposed regulation grants the Director in 

determining when a site no longer poses a risk to USDW, EPA should address long-term, post-closure MMV 

practices. We accept the scientific assessment that sequestered CO2 becomes more stable over time as secondary 

trapping mechanisms engage; however, given that the CO2 is meant to be contained indefinitely, post-closure 

monitoring and associated costs should be addressed. 

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operator financial responsibility to other entities [such as a government entity], or creation of a 

third party financial mechanism where EPA is the trustee.” 73 Fed. Reg. at 43,520. 

Nonetheless, a comprehensive long-term liability regime for GS, which includes an 

eventual transfer of responsibility to the government and the creation of a national fund, would 

facilitate large-scale implementation of CCS. EPA should advocate for the best approach that 

will not impede GS while giving maximum protection to USDWs and the public and, to the 

extent that EPA lacks authority under the SDWA to implement such an approach, it should seek 

additional authority from Congress. 

b. Long-Term Liability Should Be Addressed at a National Level, Not 

Left to the States 

EPA seems to suggest that because it lacks the authority to transfer liability from the 

owner or operator to the federal government, this piece of the liability puzzle could be left to the 

states to establish (or not). See U.S. EPA, PROPOSED UIC REGULATIONS FOR GEOLOGICAL 

SEQUESTRATION OF CARBON DIOXIDE FEBRUARY 26-27, 2008 MEETING SUMMARY 6 (2008) 

(noting that individual states, exercising primacy under SDWA, could choose to assume 

responsibility for GS sites after closure, but that the EPA could not require the transfer of 

liability). Leaving it to the states to create appropriate liability and financial mechanisms for GS 

is inadvisable for the reasons stated below. A uniform national framework is needed. 

First, individual states may not be able to achieve the economies of scale and pooling of 

resources that would make fund measures able to generate adequate coverage for CCS. 

Moreover, the “[t]ransfer of liability and ownership of the injected gas to the public sector may 

pose too great a financial burden, especially for a state with a populace of limited means and 

other significant resource-demanding needs (e.g. education, health care).” FESMIRE ET. AL.,

supra, at 59. 

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Second, much if not all of the energy industry is composed of companies that operate 

and/or supply energy in multiple states. We could see races to the bottom in which states 

compete with each other to attract CCS investment. Indeed, this has already been seen in 

reaction to the Department of Energy’s FutureGen project, where both Texas and Illinois 

extended indemnification and significant tax benefits to CCS projects in order to attract the 

investment. This competition increases the likelihood that state-implemented liability 

assumption and creation of trusts may not be adequate to cover the long-term costs of monitoring 

or future accidents. MOORE, supra, at 463 (“Disparities in state UIC programs could also lead to 

a concentration of [GS] activity in states with more lenient regulations . . . .”). 

Third, geological realities mean that some states (i.e., those with suitable storage 

formations) may bear a disproportionate share of the costs and risks of geological sequestration 

relative to those states’ consumption of the electricity or other products which generated the 

CO2. 

Fourth, given the fact that stored CO2 is expected to migrate, in cases where the CO2

crosses state boundaries, liability and remediation issues would impact more than the single state 

in which the GS facility (well) is situated. 

For these and other reasons, a national approach to GS regulation of long-term liabilities 

should be taken, which includes the creation of a national fund to address costs associated with 

unexpected damages or remediation measures. 

IV. EPA Should Update the Definition of USDW So that All Current and Viable Future 

Drinking Water Supplies are Protected from GS. 

EPA’s definition of what constitutes an “underground source of drinking water” 

(“USDW”) is critical, because non-USDWs are not protected against potential endangerment 

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from GS operations under the proposed regulation.14 EPA’s continued use of a 1980 definition 

for USDWs, however, means that many now-viable sources of drinking water fall outside the 

technical definition of “USDW,” leaving valuable water supplies unprotected by the proposed 

UIC regulation. See 73 Fed. Reg. at 43,492, 43,494. EPA should update the definition of 

USDW to reflect the current state and foreseeable further advancement of desalination 

technology. The definition of USDW should meet the statutory goal of ensuring that all aquifers 

that “can reasonably be expected to supply any public water system” are protected from potential 

contamination. See 42 U.S.C. §300h (a)-(b), (d)(2). 

Since 1980, when EPA first promulgated the UIC regulations, “USDW” has been defined 

narrowly to exclude any aquifer with waters containing more than 10,000 mg/L (also known as 

10,000 p.p.m.) total dissolved solids (TDS). See Consolidated Permit Regulations and Technical 

Criteria and Standards; State Underground Injection Programs, 45 Fed. Reg. 42,472, 42,502 

(June 24, 1980) (Final Rule for 40 C.F.R. § 146 and Amendments to § 122; 40 C.F.R. §146.03 

(1980)). This numerical limit is the creation of regulation, not statute: the SDWA directed EPA 

to protect USDWs by publishing regulations for underground injection control programs that 

include “minimum requirements for effective programs to prevent underground injection which 

endangers drinking water sources,” which the SDWA defined to mean injection which may 

contaminate any “underground water which supplies or can reasonably be expected to supply

any public water system.” See 42 U.S.C. §300h(a)-(b), (d)(2) (emphasis added). 

14 40 C.F.R. §144.3 provides: “[U]SDW means an aquifer or its portion: 

(a)(1) Which supplies any public water system; or 

(2) Which contains a sufficient quantity of ground water to supply a public water system; and 

(i) Currently supplies drinking water for human consumption; or 

(ii) Contains fewer than 10,000 mg/L total dissolved solids; and 

(b) Which is not an exempted aquifer.” 

Thus, the definition also excludes from “USDW” any aquifer that contains fewer than 10,000 mg/L TDS but does 

not contain “a sufficient quantity of groundwater to supply a public water system.” 

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The legislative history supports the position that Congress intended these terms to be 

construed broadly to effectuate Congress’s “overriding intent to maximize protection of the 

public health.” In a 1974 report accompanying the SDWA, the House Committee on Interstate 

and Foreign Commerce explained: 

[Section 1421 of the SDWA] . . . defines “underground injection 

which endangers drinking water sources.” It is the Committee’s 

intent that the definition be liberally construed so as to effectuate the 

preventive and public health protective purposes of the bill. 

The Committee seeks to protect not only currently-used sources of 

drinking water, but also potential drinking water sources for the 

future. This may include water sources which presently exceed 

minimum intake water quality requirements or maximum 

contaminant levels or which are not presently accessible for use as a 

community drinking water supply source. 

Thus, for example, the Committee expects the [EPA] 

Administrator’s regulations at least to require States to provide 

protection for subsurface waters having less than 10,000 p.p.m. 

dissolved solids, as is currently done in Illinois and Texas, even 

though water containing as much as 9,000 p.p.m. would probably 

require treatment prior to human consumption. 

Further contamination of such sources should not be permitted if 

there is any reasonable likelihood that these sources will be needed 

in the future to meet the public demand for drinking water and if 

these sources may be used for such purpose in the future. 

H. R. Rep. No. 93-1185, pt. C, at 32 (1974) (emphasis added). 

Thus, the House Committee offered the 10,000 mg/L standard, in 1974, as a reference 

point. Then in 1980, EPA stated that it considered alternative proposed concentrations to 

determine whether any offered “any superior justification in terms of current State practice, 

human health, or technological considerations,” but found that none did. 45 Fed. Reg. at 42,483. 

Accordingly, “[i]n the absence of any overriding argument to the contrary, the Agency will 

follow the standard in the House Committee Report accompanying the SDWA.” Id. 

However, improvements in desalination technology since 1974 and 1980 provide 

“superior justification” for increasing the 10,000 mg/L standard. Water with TDS concentrations 

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above 10,000 mg/L is desalinated using Reverse Osmosis (RO) or Distillation processes that 

include multistage flash evaporation (MSF), multiple effect distillation (MED), and vapor 

compression (VC). See YUAN ZHOU & RICHARD S.J. TOL, EVALUATING THE COSTS OF 

DESALINATION AND WATER TRANSPORT, WATER RESOURCES RESEARCH, VOL. 41, available at

http://www.unihamburg.de/Wiss /FB/15/Sustainability/wrrdesalt.pdf (discussing the variety of 

desalting technologies). The cost-efficiency of these technologies vary with specific site 

characteristics. Accordingly, the cost per unit depends on size and location of the desalination 

plant and is highly linked to the price of electricity. “Larger plant capacity reduces the unit cost 

of water due to economies of scale. Lower energy costs and longer plant period reduce unit 

product water cost.” Id.

The data on desalination costs indicate that per unit cost has decreased since the EPA first 

promulgated the UIC program in 1980. The average cost of desalinating high TDS 

concentrations through RO has fallen from $3.70 per m3

 in 1979 to about $1.33 per m3 in 2001. 

For the MSF process, the cost has gone down from $3.04 m3 in 1979 to $.66 m3 in 2001. As for 

the ME process, the cost has also decreased from $3.56 m3 in 1979 to $1.21 m3 in 2001. Lastly, 

the average unit cost of VC has gone down from $3.72 m3

 in 1979 to $1.50 m3 in 2001.15 

See RESEARCH UNIT SUSTAINABILITY AND GLOBAL CHANGE, HAMBURG UNIVERSITY AND 

CENTRE FOR MARINE AND ATMOSPHERIC SCIENCE, available at 

http://www.unihamburg.de/Wiss/FB/15/Sustainability/Models.htm cited in YUAN ZHOU & TOL. 

at 4.

For EPA to meet SDWA’s goal of ensuring that not only all current, but also all 

reasonably expected, sources of drinking water are protected from GS, EPA must update the 

15 Unit costs are given in terms of 1995 US dollars. See YUAN ZHOU & TOL, supra, at 4. 

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10,000 mg/L reference to reflect the “reasonable expectations” of today based on the current 

state and foreseeable further advancement of desalination technology.16

In addition, ELPC and ETIP note that the proposed regulation excludes from protection 

aquifers and wells that likely would not be sufficient to supply water to public water systems17

but that are used as a supply of water for smaller, private systems. At a minimum, EPA should 

require that owners of small wells be consulted and included in the planning and permitting 

process for GS wells and that provision be made to provide them with an alternative drinking 

water source if necessary. 

V. EPA Should Not Allow, or Should At Least Severely Restrict, Grandfathering of 

Existing Wells. 

Under proposed 40 C.F.R. § 146.81(c), “[i]f the Director determines that USDWs will not 

be endangered,” existing Class I and II wells and Class V experimental GS wells may be used for 

large-scale GS under the Class VI regulations but “are exempt, at the Director’s discretion, from 

the casing and cementing requirements at [proposed] §§ 146.86(b) and 146.87(a)(1) through 

(3).” See also 73 Fed. Reg. at 43,502 (discussing how the grandfathering proposal “requires that 

the owner or operator make a demonstration that the well will maintain integrity and stability in a 

CO2 rich environment for the life of the GS project”). All wells would need to meet all other 

requirements for Class VI wells, including the area of review and site characterization, operating, 

monitoring, mechanical integrity, well plugging, post-injection site care, and site closure 

requirements. Id. 

16Going forward, EPA should consider revising the definition of USDWs on a rolling basis to prevent the TDS 

standard from becoming outdated and the resulting endangerment of viable sources of drinking water by GS. In this 

way, EPA will comply with its Congressional mandate to prevent endangerment of USDWs. 

17 “The term ‘public water system’ means a system for the provision to the public of piped water for human 

consumption, if such system has at least fifteen service connections or regularly serves at least twenty-five 

individuals.” 42 U.S.C. § 300F(4). 

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As EPA points out, “GS projects are anticipated to have long lifespans in comparison to 

other types of deep injection wells. Not only must GS wells be able to function safely and 

properly over the lifespan of the GS project, but they must be constructed such that USDWs 

remain protected after well plugging.” Id. at 43,510. In terms of construction materials, it 

appears from EPA’s discussion that the selection of the cement and metal well materials is of 

central importance given the potential of the CO2 stream (including water and impurities) to 

corrode cement and metal well components. See id. at 43,509. Therefore, proposed 40 C.F.R. 

§ 146.86(b)(1) requires that “[a]ll well materials must be compatible with fluids with which the 

materials may be expected to come into contact and meet or exceed standards developed for such 

materials by the American Petroleum Institute, ASTM International, or comparable standards 

acceptable to the Director.... [T]he owner or operator must provide [the Director] the following 

information [including] Corrosiveness of the carbon dioxide stream, and formation fluids; [and] 

[t]ype or grade of cement ....” Id. at 43,537-38 (proposed 40 C.F.R. § 146.86(b)(1)). 

EPA concludes that “[t]he quality of the well materials, proper well construction, composition 

and placement of appropriate cement along the wellbore, and appropriate maintenance are 

crucial, because a leaking annulus would be a significant route of escape for CO2.” Id. at 

43,509(emphasis added). 

It is not clear why bypassing the “crucial” safeguards of proposed 40 C.F.R. § 146.86(b) 

and 146.87(a)(1) through (3) in favor of the Director’s general determination that use of the well 

would not endanger USDWs is a good idea. See 73 Fed. Reg. at 43,535 (Proposed 40 C.F.R. 

§ 146.81(c)). The need to “grandfather” implies that the existing wells would not necessarily 

meet EPA’s proposed construction standards for Class VI wells.18 To the extent that the specific 

18 The construction requirements for Class I hazardous waste injection wells include similar language to the Class VI 

standards. For example, “[a]ll well materials must be compatible with fluids with which the materials may be 

expected to come into contact. A well shall be deemed to have compatibility as long as the materials used in the 

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proposed casing and construction requirements for GS wells provide assurance beyond 

“no endangerment of USDWs,” that “extra” assurance seems appropriate in light of industry’s 

inexperience with large-scale, long-term GS of CO2 and should be preserved. EPA has not 

articulated any justification for why grandfathering is necessary. See 73 Fed. Reg. at 43,502. 

If grandfathering is permitted, EPA should limit its availability so as to not create an 

unintended loophole from Class VI construction requirements. EPA should require the Director 

to engage in a rigorous review of the design, purpose, and suitability of the original well before 

allowing grandfathering in any particular case. Also, grandfathering should only be allowed 

(if at all) for existing Class I, II or GS Class V wells that are in operation as of the final date of 

adoption of the GS regulations. If a well owner or operator anticipates using a well constructed 

after that date for GS at any point in the future, he or she should be required to plan accordingly 

and use the well materials required by the most protective applicable standard. 

VI. EPA Should Rank Sites With GS Capability Based On Their Specific Leakage Risk 

Profiles. 

In the preamble to the proposed regulation, EPA states that it is soliciting comment on: 

(1) Whether CO2 injection should be allowed into an injection 

zone above the lowermost USDW, when the Director 

determines that geologic conditions (e.g., thousands of feet of 

intervening formations between the injection zone and the 

overlying and/or underlying USDWs) exist that will prevent 

fluid movement into adjacent USDWs; and 

(2) Whether aquifer exemptions should be allowed for the purpose 

of Class VI injection, and under what conditions should such 

aquifer exemptions be approved. 

73 Fed. Reg. at 43,511-12 

construction of the well meet or exceed standards developed for such materials by the American Petroleum Institute, 

The American Society for Testing Materials, or comparable standards acceptable to the Director.” 40 C.F.R. 

§146.65(b). However, the Class I well would have been evaluated for “compatibility” with respect to the waste that 

was initially injected into the well, which may be less (or more) corrosive than CO2 to the particular well materials 

used to construct the well. Thus, the Class I requirements would not necessarily ensure compatibility with CO2. 

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 Submitted by Harvard Law School Environmental Law & Policy Clinic 

EPA suggests that its rationale for allowing the injection of CO2 above the lowermost 

aquifer is to increase the available storage capacity for CO2. See id. at 43,512. In other contexts 

(e.g., for Class I injection wells), however, EPA has refrained from compromising USDWs to 

increase the available storage capacity for fluids. The Agency has not presented a case for a 

departure from that general principle here. 

The WRI Guidelines avoid explicit use of the terms “exemption” or “injection above the 

lowermost aquifer” and instead propose guidelines for site selection and characterization of 

storage capacity. WRI GUIDELINES at 91. Building on the WRI’s guidelines and on further 

research, the EPA should rank sites with geological storage capacity depending on the specific 

risk profile of CO2 leakage to lower geological formations and other relevant factors. The WRI 

Guidelines suggest the following “General Guidelines for Site Characterization and Selection”: 

1. Potential storage reservoirs should be ranked using a set of 

criteria developed to minimize leakage risks. Future work is 

needed to clarify such ranking criteria. 

2. Low-risk sites should be prioritized for early projects. 

3. As required by regulation, storage reservoirs should not be 

freshwater aquifers or potential underground sources of 

drinking water. 

4. Confining zone(s) should be present that possess characteristics 

sufficient to prevent the injected or displaced fluids from 

migrating to drinking water sources or the surface. 

5. Site-specific data should be collected and used to develop a 

subsurface reservoir model to predict/simulate the injection 

over the lifetime of the storage project and the associated 

project footprint. These simulations should make predictions 

that can be verified by history-matching within a relatively 

short period of time after initial CO2 injection or upon 

completion of the first round of wells. The reservoir model and 

simulations should be updated periodically as warranted and 

agreed with regulators. 

6. Saline formations and mature oil and gas fields should be 

considered for initial projects. Other formations, such as coal 

seams, may prove viable for subsequent activity with 

additional research. 

Page 44 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

WRI GUIDELINES at 91. 

The According to the WRI Guidelines, EPA would first authorize GS at sites with low risk. 

However, as more GS projects are deployed and the availability of low risk sites decreases 

(eventually, perhaps, to zero), EPA would then determine whether to authorize GS at higher-risk 

sites. In that case, ELPC and ETIP suggest that EPA consider conditioning its approval on a 

demonstration by the owner or operator that it is technically feasible to treat groundwater that 

may become contaminated as a result of the GS activity if needed to supply public or smaller 

water systems at a future date. EPA could also require the owner or operator to provide financial 

assurance to cover the costs of such treatment. 

A. CO2 Injection Above The Lowermost USDW 

The proposed regulation prohibits GS above the lowermost USDW. 73 Fed. Reg. at 

43,535 (proposed 40 C.F.R. § 146.5(f)) (defining Class VI wells as “[w]ells used for geologic 

sequestration of carbon dioxide beneath the lowermost formation containing an underground 

source of drinking water (USDW)”). EPA explains in the preamble that this safeguard is “a very 

important protective component of the UIC program. Placing distance between the point of 

injection and USDWs allows for the necessary confining and buffer formations, and further 

provides for opportunity for additional monitoring to detect any excursions from the intended 

injection zone.” Id. at 43,511. 

The regulations for Class I hazardous and non-hazardous waste injection wells contain a 

similar prohibition against injection above a lowermost USDW. See id. at 43,511; U.S. EPA,

CLASS I UNDERGROUND INJECTION CONTROL PROGRAM: STUDY OF THE RISKS ASSOCIATED WITH 

CLASS I UNDERGROUND INJECTION WELLS 2 (March 2001) (“By definition, Class I wells inject 

industrial or municipal wastewater beneath the lowermost USDW.”). EPA explains that this 

restriction is one of “multiple barriers” to a release of injected fluid into a USDW. Id. at 40. It is 

Page 45 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

unclear, however, why lowermost USDWs should be afforded less protection from GS, 

especially in light of the anticipated long life spans of GS projects. 

Given the emerging state of technology associated with GS and the lack of data available 

regarding the likely behavior of injected CO2 over hundreds or thousands of years, EPA should 

at minimum ensure that multiple safeguards are in place before USDWs are put at risk. Indeed, 

EPA itself admits that it currently lacks data to demonstrate if injection above or between 

USDWs is appropriate and protective of USDWs. 73 Fed. Reg. at 43,512. Nonetheless, EPA is 

considering giving the Director discretion to allow CO2 injection above the lowermost USDW 

when he or she determines that geologic conditions such as thousands of feet of intervening 

formations between the injection zone and the overlying and/or underlying USDWs exist that 

will prevent fluid movement into adjacent USDWs. Id. 

EPA anticipates that such discretion would allow GS “in specific geologic settings where 

the depth of the USDWs may preclude GS, make GS technically challenging, or significantly 

limit CO2 storage capacity.” Id. (suggesting that “[a]n example where such injection may be 

appropriate presents itself in areas such as the Williston and Powder River Basins in Wyoming, 

North Dakota, and South Dakota, where receiving formations (formations with large CO2 storage 

capacity) for GS have been identified above the lowermost USDW and where there may be 

thousands of feet of rock strata between the injection zone and the overlying and underlying 

USDWs”). 

Before allowing such injections, EPA should first carry out further research and rank sites 

with geological storage capacity according to specific factors such as risk of leakage of impure 

streams of CO2 to lowermost geological formations, distance between the injection zone and the 

lowermost USDW, composition of the rock strata that will prevent contamination of 

Page 46 of 49 
 RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 

 Submitted by Harvard Law School Environmental Law & Policy Clinic 

underground reservoirs, and the specific characteristics of the aquifer such as the quantity of 

water and the depth of the aquifer. 

B. Exempting USDWs for the Purpose of GS

Under current UIC Program regulations, the Director has the discretion to exempt 

USDWs pursuant to 40 C.F.R. § 146.4 when the following conditions are met: 

a) [the USDW] does not currently serve as a source of drinking 

water; and 

b) It cannot now and will not in the future serve as a source of 

drinking water because: 

(1) It is mineral, hydrocarbon or geothermal energy producing, 

or can be demonstrated by a permit applicant as part of a 

permit application for a Class II or III operation to contain 

minerals or hydrocarbons that considering their quantity 

and location are expected to be commercially producible. 

(2) It is situated at a depth or location which makes recovery of 

water for drinking water purposes economically or 

technologically impractical; 

(3) It is so contaminated that it would be economically or 

technologically impractical to render that water fit for 

human consumption; or 

(4) It is located over a Class III well mining area subject to 

subsidence or catastrophic collapse; or 

(c) The total dissolved solids content of the ground water is more 

than 3,000 and less than 10,000 mg/l and it is not reasonably 

expected to supply a public water system. 

40 C.F.R. § 146.4. 

Once a USDW is exempted, it is no longer afforded protection as a USDW, now or in the 

future. See 73 Fed. Reg. at 43,512; 40 C.F.R. §144.7(b)(1). 

Allowing exemptions of USDWs for the purpose of GS is premature. By definition, a 

(non-exempted) USDW is a source that has less than 10,000 mg/L total dissolved solids, the 

level that EPA already has determined “can reasonably be expected to supply any public water 

system.” 42 U.S.C. §300 (h)(d)(2). Thus, given the expected increase in demand for water 

resources and the available technology, it does not make sense to allow current or potential 

Page 47 of 49 


HARVARD LAW SCHOOL 

ENVIRONMENTAL LAW & POLICY CLINIC

1563 Massachusetts Avenue 

Pound Hall · Room 501 

Cambridge · Massachusetts · 02138 

TEL 617.496.3368 · FAX 617.384.7633 · EMAIL wjacobs@law.harvard.edu

 

November 21, 2008 

The following documents are attached to the Comments submitted by the Clinic regarding 

Docket ID No. EPA–HA–OW–2008–0390: 

1) SARAH M. FORBES ET AL., WORLD RESOURCES INSTITUTE, CCS GUIDELINES:

GUIDELINES FOR CARBON DIOXIDE CAPTURE, TRANSPORT, AND STORAGE (2008); 

2) WORLD RESOURCES INSTITUTE, WORKSHOP SUMMARY: ADDRESSING LONG-TERM 

LIABILITY OF CARBON DIOXIDE CAPTURE AND GEOLOGICAL SEQUESTRATION (2007);

3) ALEXANDRA B. KLASS AND ELIZABETH J. WILSON, CLIMATE CHANGE AND CARBON 

SEQUESTRATION: ASSESSING A LIABILITY REGIME FOR LONG-TERM STORAGE OF 

CARBON DIOXIDE (2008); 

4) INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE, IPCC SPECIAL REPORT ON 

CARBON DIOXIDE CAPTURE AND STORAGE (2005). 

5) UNITED NATIONS FRAMEWORK CONVENTION ON CLIMATE CHANGE (“UNFCCC”),

FACT SHEET: INVESTMENT AND FINANCIAL FLOWS FOR A STRENGTHENED RESPONSE 

TO CLIMATE CHANGE (2007); 

6) MARK E. FESMIRE ET. AL., NEW MEXICO ENERGY, MINERALS, NATURAL RESOURCES 

DEPARTMENT, CARBON DIOXIDE SEQUESTRATION: REPORT ON IDENTIFIED STATUTORY 

AND REGULATORY ISSUES (2007); 

7) MIT, THE FUTURE OF COAL: OPTIONS FOR A CARBON-CONSTRAINED WORLD (2008); 

8) JEFFREY W. MOORE, THE POTENTIAL LAW OF ON-SHORE GEOLOGICAL 

SEQUESTRATION OF CO2 CAPTURED FROM COAL-FIRED POWER PLANTS, (2007); and, 

9) YUAN ZHOU & RICHARD S.J. TOL, EVALUATING THE COSTS OF DESALINATION AND 

WATER TRANSPORT, WATER RESOURCES RESEARCH, VOL. 41, available at

http://www.unihamburg.de/Wiss /FB/15/Sustainability/wrrdesalt.pdf. 

Page 1 of 1 
1 

Workshop Summary 

 

Addressing Long-term Liability 

of Carbon Dioxide Capture and Geological Sequestration 

5 June 2007 

Summary 

The World Resources Institute convened this workshop on Tuesday, June 5th to explore issues 

around long-term liability of Carbon Capture and Sequestration (CCS) projects. Long-term 

liability is one of several important challenges that CCS faces. A key finding from the June 5 

workshop is that long-term liability comprises both anticipated costs associated with the long 

term care of a storage facility and the potential for costs associated with unanticipated damages. 

Another key finding of the workshop is that there are important inter-relations among the 

different stages of a project (siting, operation, closure, and post-closure). These inter-relations 

are important both in terms of reducing the long-term risk of liability and in creating efficient 

and flexible financial mechanisms to mitigate long-term liability. 

This workshop fits into the larger project WRI is conducting with representative stakeholders to 

begin addressing key CCS challenges. In particular, the larger project is developing guidelines 

that will help ensure public confidence in the technology, provide investor certainty, and clarify 

operational issues for project developers.

This workshop brought together 38 experts from the insurance, finance, research, energy, 

governmental and NGO communities (see Appendix B). The goal was to assess the need and 

options for sharing the long-term liability associated with CCS between the public and private 

sectors. 

Long-term liability is an important issue from many perspectives. The public needs assurance 

that adequate care and funding will be in place to manage storage facilities long into the future, 

potentially long after the companies that operated storage facilities go out of business. Project 

developers, financiers, and insurers need to know the operational and regulatory requirements up 

front in order to manage costs and risks. There is a need for much greater clarity in this regard. 

We covered the following sessions during the day (see Appendix A for the full agenda): 

1. Scale and timing of CCS as a climate strategy 

2. Potential risk and mitigation strategies for CCS 

3. Barriers to long-term investment in CCS technology 

4. Financial responsibility models 

5. The role of the public sector 

6. Elements of a potential framework for managing long-term liability 
2

This discussion was a great success in that it brought together a diverse set of stakeholders, 

revealed a set of informational needs and identified a concrete set of steps towards making 

progress. That said, the discussion also illustrated that the group did not have a common 

language regarding risk and liability, nor did it have a common understanding of the potential 

risks associated with CCS. Rather than attempting to assess models for mitigating long-term 

liability, the group called for an interim step to develop a common vocabulary and more clearly 

articulate the potential risks from CCS. With this information in hand, the group plans to 

reconvene for a second workshop in the fall to review options for addressing long-term liability 

associated with the various potential risks from CCS. 

Review of Discussions

Slides were used throughout the day except for the general discussions which took place in 

sessions numbered 3 and 5. These slides are available on the WRI site 

(http://carboncapture.wri.org) and are referenced in the notes below. The summaries below were 

prepared by the project team and not by the presenters. They include a recap of the important 

points from the presentations as well as a summary of the important points from the discussions. 

1. Dimensions of CCS – This presentation set the stage for the discussion with the following key 

points: 

• Addressing climate change will require limiting greenhouse gas (GHG) emissions to the 

atmosphere to a finite level. 

• The longer we wait to reduce emissions, the more we will have to do to “make up” for 

having waited. 

• Large levels of reductions in GHG are expected to be necessary by the middle of this century 

and beyond. This will require fundamental changes to our energy system. 

• Integrated assessment modeling of the global energy system suggests that no single 

technology (e.g., renewable energy, energy efficiency, nuclear energy, coal CCS) will be 

sufficient to achieve the reductions necessary. In fact, it suggests that all will be needed. 

• CCS involves the capture and storage of the most common GHG, known as carbon dioxide 

or CO2. CCS has the theoretical potential capacity to “fill the gap” or enable the world to 

make the reductions it needs in addition to those it achieves through other technologies, to 

meet the GHG reduction levels associated with the most commonly cited stabilization levels 

(450-750 ppm). 

• The US is well endowed with potential storage capacity and an exercise to show the marginal 

cost of deploying CCS in the US for current large sources suggests that it could provide a 

cost-effective reduction option for large sources of CO2 emissions. 

• In order to achieve the lower stabilization concentration of 450 ppm, the integrated 

assessment modeling suggests that the efficient use of CCS in the US would represent several 

orders of magnitude increase in deployment over what we have today. This might include 

100’s of millions of tonnes being injected into the subsurface annually by 2050 whereas 

today the US injects only about 3 million tonnes annually. 

• The group asked about the implications if this level of deployment was not achieved by midcentury. Although the modeling results were not prepared for the group, the response 

indicated that other studies and additional work by Battelle suggested that in the absence of 

achieving large scale deployment of CCS, other technologies would need to be used and the 
3

predicted costs to reduce CO2 or other GHG would rise dramatically. It was estimated that 

costs would more than double or would be worth more than tens of billions of dollars to the 

US economy. 

 

2. CCS Risks and Mitigation – This presentation covered three main topics: (a) the 

fundamentals of storage security (including physical analogs), (b) the environmental risks of 

geological storage, and (c) risk management and mitigation (including the storage security 

pyramid). It seemed that several participants did not have prior exposure to the information in 

this presentation and it stimulated significant discussion. In particular, the presentation included 

a conceptual risk profile (shown below) illustrating that the risk of leakage from the targeted 

reservoir diminishes over time as secondary trapping mechanisms came into effect. There was 

discussion about the ability of an operator to impact the risk profile through operational changes. 

• CCS can take place in several types of geologic formations including depleted oil and gas 

fields, unmineable coal seams and saline (brine) formations. It’s possible that other 

formations can be used as well, but there is less known about such formations. 

• There are four ways that injected CO2 is contained in the injection zone. The primary 

trapping mechanism is the overlying caprock. Secondary trapping mechanisms include CO2

dissolving in brine, capillary trapping, and eventual “mineralization”. 

• IPCC experts agreed that for well-selected sites that are operated and monitored properly, 

there is a greater than 99% probability that CO2 will remain in the selected storage reservoir 

for 1,000 years or more. An important caveat was noted that this figure was based on natural 

and industrial analogues and not specific modeling results. However, there is considerable 

evidence for this found in the natural and industrial analogs. 

• The potential risks from CCS stem primarily from the unintended release of CO2 (and also 

include potential industrial accidents conventionally associated with construction and drilling 

projects). Potential release pathways include well leakage (injection and abandoned wells), 

undetected faults, and excessive pressure buildup that can damage seals. 

• An 8-tier “storage security pyramid” (shown below) was used to show the steps that could be 

taken to reduce the risk of CO2 release. 

Source: Sally Benson, Stanford. 
4

• Jumping to the top tier, financial responsibility (please see the slides for detailed information 

on each tier), the group was presented with a conceptual risk profile for CCS projects (shown 

below). The concept is that if storage projects do not demonstrate any problems during the 

operation stage, the risk of CO2 release is expected to decrease as injection stops and the 

secondary trapping mechanisms take effect. However, the concept also shows that the risk 

will remain greater than zero for a long time in the future, suggesting that financial 

responsibility mechanisms may be needed to address long-lived, but low-probability risks. It 

was noted that this profile can be influenced by operational changes. 

Source: Sally Benson, Stanford. 

3. Barriers to Investment: This was an open discussion and covered a wide range of 

perceptions about the risks to investment. It led to a discussion about the nature of the business 

of storage and a call for a more precise articulation of the perceived risks. Some of the issues 

touched on and included the differences between long-term responsibility for measures such as 

ongoing MMV and well maintenance versus long-term liability for damages to human health and 

property through accidental future release of injected CO2. 

• It does not seem likely that investors will invest in CCS as a means of complying with 

existing climate change obligations, such as the Kyoto Protocol, because the timelines for 

compliance are so much shorter than the timelines for completing CCS projects. This means 

that most investors will be considering investment in CCS as it may pertain to compliance 

with potential post-Kyoto (or future US) requirements. Since none of those requirements are 

defined at this point, it may be the case that investor interest in learning about CCS will not be 

matched by hard investment until there is a stronger signal of future obligations. 

• There is a disconnect between the typical investment horizon and the timelines associated 

with fully reducing the risk associated with CCS projects. If investors are going to be held 

responsible for the long-term risks of CCS, it will make those investments unattractive in 
5

comparison to many other investments with shorter term payouts or more certain exit 

strategies. 

• Likewise, investors will be interested in the transferability of the environmental benefit 

(carbon credit) associated with CCS. 

• There is no such thing as perfect indemnification, especially in a litigious U.S. A concern was 

voiced that, if they looked hard enough, many lawyers could find a regulation or standard that

the project developer did not meet completely. 

• Demonstration projects are needed to start identifying and understanding the unknowns. For 

example, how much does it cost to plug an abandoned well? What will this cost in terms of

business interruption? In terms of carbon lost? How far out into the future do project 

developers have to consider these? 

• Regulatory uncertainty was identified as one of the biggest barriers. 

• Differing opinions were offered about whether liability will be a major barrier. 

o One view: if the government is tasked with assuming long-term liability, they will be 

extremely cautious in allowing projects to move forward. 

o Another view: large firms can cover operational risks, but will want government to 

take over long-term monitoring and liability. 

4. Financial Responsibility (FR) Models: This presentation outlined the rationale and some 

models for designing FR mechanisms. The rationales include properly incentivizing sound siting 

and operations practices, ensuring adequate funding to cover LT responsibilities and liabilities, 

and giving confidence to the public. At the heart of this presentation was the point that the nature 

of the risk needs to be well understood to design FR mechanisms and this point was the focus of

discussion for the rest of the day. In addition, the insurance community pointed out the need for 

and the difficulty in adopting a flexible approach so that a FR mechanism can adapt to changes 

in scientific knowledge, technical capacity, and economic tools. Thus, the earlier conversation 

calling for a better definition of the risks was reiterated and it was refined to suggest 

distinguishing the interests of the public, investor groups and industry/carbon emitters. 

 

This section of the discussion also included a brief presentation on the Zero Emission 

Technology Platform (ZEP) program in the EU. There were several important differences 

between the general approach to environmental regulation, litigation and ownership of pore 

space/mineral rights in the EU and the US, but nonetheless useful comparisons emerged in 

thinking about managing the long-term care of storage facilities. 

• The discussion reiterated the need for and difficulty in allowing flexibility in FR mechanisms. 

Experience shows that it is often necessary to put FR mechanisms in place before projects can 

move forward, and that it is very difficult to make any changes in them once some project 

experience is gained and/or markets change. 

• There were different views about whether we need to figure out all the LT liability solutions 

now. An effective framework must evolve with the technology and experience. It was 

suggested that this framework could perhaps be modified annually as we learn more about the 

risks and project performance. 
6

• How FR is structured will impact larger companies very differently than smaller ones. For 

example, larger companies may be able to self insure whereas, smaller ones may not. Such a 

discrepancy could effectively preclude companies from engaging in CCS. 

• A hybrid approach was discussed. In this model, different instruments and providers (private 

v. public) would provide financial assurance based on the phase of the project. 

• Privately run risk pools have incentives to be operated efficiently and cost effectively. There 

are concerns that a publicly run program would not have these built-in incentives. In addition, 

publicly run pools are notoriously difficult to modify (e.g. RCRA). 

• Perhaps the greatest need is to address the “break the bank” risks. 

• It was again noted that it is imperative to determine who bears the financial risks, and when. 

• Some participants voiced the opinion that the private sector could adequately deal with the 

risks, but would need the public sector to take over the long-term responsibility for 

monitoring. 

5. The Appropriateness and Role for the Public in LT Liability Management Associated 

with Storage: This was a wide ranging discussion that highlighted several topics including (a) 

the appropriateness/precision of applying the term LT liability to the activities that might need to 

take place after closing or decommissioning a storage facility, (b) the nature of the concerns 

associated with the cost and/or uncertainty associated with those activities, (c) the need (both 

pros and cons) associated with any transfer of the responsibility for LT care to the public (either 

funded or unfunded, state or federal, and via creation of 3rd party institutions or other 

administrative options). This led to a reiterated call for an articulation of risk by stage, type and 

interested party. 

• A well structured FR framework will encourage proper siting, operation, and closure—

minimizing risks to all. 

• There is a serious problem with the message that is being sent right now: “CCS is very safe, 

but we cannot move forward unless the public takes on the long-term risks for anything that 

might happen.” This mixed message will undermine public acceptability. Public perception of 

CCS was identified as a potentially large challenge. 

• One participant noted that life-cycle monitoring may not be that expensive, at perhaps $0.05-

$0.10/ton. This cost is small compared to overall project costs. 

• Concerns were raised about bureaucracy and inefficiency if the government was tasked to 

managing these sites after closure. 

• One suggested criteria for transferring liability to the public was project performance. 

• Some of the concerns of the private sector derive from the fact that this is a new technology. 

Demonstration projects are urgently needed to address a lack of knowledge, information, and 

experience. 

• There was wide agreement on a strong need for defining and distinguishing risks, 

characterizing their timing and probability, identifying how to prioritize them, estimating their 

costs, and defining who should be responsible for what risks. Answers to these questions will 

determine the shape of the risk profile. 
7

6. Potential Frameworks for LT Liability Management: This presentation compared some of 

the existing approaches to LT liability management being considered in various efforts to 

develop model CCS rules, support FutureGen and otherwise guide the early development of 

CCS. It attempted to draw common themes or framework elements to spur a discussion of what 

would be appropriate to include in a proposed framework. In many regards, this was a top-down 

approach to looking at long-term liability: it examined programs to determine how they 

addressed certain issues. The group called for more of a bottom-up approach that first identified 

the full suite of issues (risks) and then looked at ways to prioritize the risks and efficiently 

mitigate them. In the absence of having this analysis done, the group offered some reflections on 

the top-down analysis: 

• Transferring LT responsibility to a public-private corporation was discussed. One reason that 

transfer to government or a public-private corporation is needed at some point is to ensure that 

the entity will be around to deal with any problems. 

• There were some concerns that the term “liability” was being used by participants to mean 

different things. There is a difference between financial responsibility—liability for 

monitoring and post-closure management of the site—and liability for risk of something 

happening, such as injury to person or property. These are separate topics, and need to be 

clearly distinguished in future discussions. 

• Concerns about lawsuits were voiced. Even lawsuits without merit could be very costly. 

• There was discussion about the pros and cons of a one-size-fits all federal approach to liability 

versus a state-by-state approach. In a worst case scenario, unequal approaches across the 

states could result in a race to the bottom, creating perverse incentives for siting, operation, 

and closure. 

• One suggested approach involved developing different models for liability based on risk 

profiles. 

Next Steps 

There are two next steps planned to complete this discussion: 

1. Develop a risk log to identify a common vocabulary and complete set of risks associated with 

the various stages of CCS. There are several papers and significant other work related to CCS 

risk assessment. The risk log proposed here will attempt to draw from those and also to 

contemplate a broad group of stakeholders including project developers, the public, and 

investors. Once complete, we will initiate an iterative process to solicit input from a working 

group of participants in the meeting and additional outside experts. Using conventional 

approaches to risk assessment, the goal is to develop a prioritized ranking of risks and an 

understanding of their interrelations and options for mitigation. 

2. Convene a second workshop in early fall to review the risk log and options for most efficiently 

managing the risks. The purpose of this review is to develop recommendations suitable for 

addressing planned pilot and research projects in the short term and also to offer suggestions for 

approaches to be used over the long term in addressing commercial deployment.
8

 

Appendix A 

Agenda for CCS Long-Term Liability Workshop

8:00 - 8:30 Overview: Frame the discussion, and give a charge to the group 

(Jeffrey Logan, WRI; Sarah Wade, AJW, Inc.) 

8:30 – 9:15 Scale and Timing of CCS if it is Deployed as a Climate Strategy? 

(Jim Dooley, Joint Global Change Research Institute) 

9:15 – 10:15 What is the Potential Liability from CCS and Options to Mitigate? 

(Sally Benson, Executive Director of GCEP, Stanford) 

10:15 – 11:00 Barriers to long term investment in CCS technology (Group Discussion) 

 Representatives from the oil/gas industry, electric industry, investment 

 community and financial community kick-off group discussion 

11:15 – 12:30 Options for Financial Mitigation of LT Risks from Storage (Chiara Trabucchi, 

Industrial Economics; Lindene Patton, Zurich; Keith Harsham, BP) 

12:30 – 1:30 Lunch and informal discussion

1:30 – 2:15 What is the appropriate role and timing for the public sector to share the 

long-term storage risk of CCS with the private sector? (Group Discussion) 

2:15 – 3:45 Elements of a Potential Framework for Managing LT Liability 

(Sarah Wade, AJW, Inc.) Presentation of matrix and group discussion 

3:45 – 4:00 Wrap up – next steps in the process 
9

Appendix B 

Participant List for CCS Long-Term Liability Workshop

Vicki Arroyo 

Pew Center on Global Climate Change 

Adrienne Atwell 

SwissRe 

Julia Bailey Dulan 

Southern Company 

Sally Benson 

Stanford University 

Robert Bradley 

World Resources Institute 

Kipp Coddington 

Alston and Bird 

Jack Cogen 

Natsource, LLC 

Jim Dooley 

Joint Global Change Research Institute 

Matt Elkington 

Marsh Europe S.A. 

Ivan Gaydarov 

Occidental Petroleum Corporation 

Tim Grant 

National Energy Technology Laboratory 

Dr. Keith Harsham 

Bp Alternative Energy International Ltd 

Elliott Heide 

Occidental Petroleum Corporation 

Anhar Karimjee 

Environmental Protection Agency (EPA) 

Asteghik Khajetoorians 

BP 

Sarah Ladislaw 

Center for Strategic and International Studies 

Melissa Lauderdale 

Edison Electric Institute 

Susan Macey 

Indiana Office of Utility Consumer Couselor 

Granville Martin 

JP Morgan Chase and Co 

Gary Meggs 

Southern Company 

Mike Mudd 

FutureGen Alliance 

Larry Myer 

California Energy Commission 

Kyung-Ah Park 

Goldman Sachs 

Lindene Patton 

Zurich (North American) Insurance Company 

George Peridas 

Natural Resource Defense Council 

Darlene Radcliffe 

Duke Energy 

David Reisinger 

AIG Global Marine and Energy 

Sierra Salmon 

AIG 

John Steelman 

Natural Resource Defense Council 

Frank Tierney 

AEGIS 

Chiara Trabucchi 

Industrial Economics, Incorporated 

Robert F. Van Voorhees 
10

Bryan Cave L.L.P. 

John Venezia 

World Resources Institute 

Preeti Verma 

World Resources Institute 

Sarah Wade 

AJW, Inc. 

Richard Wagner 

AIG Insurance Company 

Mark Webster 

Duke Energy 

Fred Wellington 

World Resources Institute 

Elizabeth Wilson 

University of Minnesota 
1

CLIMATE CHANGE AND CARBON SEQUESTRATION: ASSESSING A LIABILITY 

REGIME FOR LONG-TERM STORAGE OF CARBON DIOXIDE 

ALEXANDRA B. KLASS∗

ELIZABETH J. WILSON** 

ABSTRACT

 As the nation struggles with how to address climate change, one of the most significant 

questions is how to reduce increasing levels of carbon dioxide in the atmosphere. One 

promising technology is carbon capture and sequestration (“CCS”), which consists of 

capturing carbon dioxide emissions from power plants and industrial sources and 

sequestering them in deep geologic formations for long periods of time. Areas for potential 

CO2 sequestration include oil and gas fields, saline aquifers, and coal seams. As Congress 

and the private sector begin to spend billions of dollars to research and deploy this 

technology, there has been insufficient attention paid to how to structure liability for the 

short-term or long-term risks associated with the geologic sequestration of CO2 in connection 

with CCS. Until now, federal and state legislators, when they have acted at all, have 

appeared to be in a rush to limit corporate liability for potential harm in order to encourage 

the development of CCS. We take a different approach. In this Article, we survey the existing 

liability regimes that may cover potential harm from escaping or migrating CO2. We 

conclude that existing federal statutory environmental law and state common law can provide

important risk management tools and serve as safeguards to private parties and state and 

local governments in the event of harm. State and federal legislation specific to CCS should 

leave this basic liability framework in place. We also propose several different compensation 

mechanisms including bonding, insurance, and pooled federal funding, to provide financial 

security to investors without destroying existing liability protections for those who may suffer 

harm from CCS. 

INTRODUCTION 

 One of today’s most pressing environmental challenges is climate change1 and, 

particularly, the need to reduce increasing levels of carbon dioxide in the atmosphere. Achieving 

the deep emissions reductions necessary to stabilize atmospheric concentrations of greenhouse 

gases will require a fundamental shift in the way we generate, transport, and use energy.2

 

Controlling greenhouse gases is fundamentally different than managing traditional criteria air 

 

∗

Associate Professor of Law, University of Minnesota Law School. 

** Assistant Professor, Center for Science, Technology and Public Policy, Humphrey Institute of Public Affairs, 

University of Minnesota. This work was supported by the Doris Duke Charitable Foundation under a grant to 

develop a regulatory framework for Carbon Capture and Sequestration. 

1

 The term “climate change” (which is often used synonymously with the term “global warming”), refers to “any 

significant change in measures of climate (such as temperature, precipitation, or wind) lasting for an extended period 

(decades or longer).” EPA, Climate Change, Basic Information, available at

http://www.epa.gov/climatechange/basicinfo.html; EPA, Climate Change, Emissions, available at

http://www.epa.gov/climatechange/emissions/index.html. 

2

See INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE (“IPCC”) FOURTH ASSESSMENT REPORT, WORKING 

GROUP 1 REPORT, THE PHYSICAL SCIENCE BASIS 138, 512 (2007), available at http://www.ipcc.ch/pdf/assessmentreport/ar4/wg1/ar4-wg1-chapter2.pdf. 
2

pollutants. As the atmospheric lifetime of traditional criteria pollutants (e.g., sulfur dioxide or 

oxides of nitrogen) is only a few hours or days, pollution control and emission reduction at the 

source is sufficient for reducing atmospheric concentrations of these pollutants. Greenhouse 

gases, however, with their long atmospheric residence times, require a dramatically different 

management strategy.3 Stabilizing the concentrations of these gases in the atmosphere, the goal 

of the United Nations Framework Convention on Climate Change,4 will require reductions in 

emissions of roughly an order of magnitude. 

 Many studies have focused on available technologies that would enable deep emission 

reductions.5 Carbon capture and sequestration (“CCS”) is emerging as a technology that would 

enable the continued use of fossil fuels while dramatically reducing accompanying greenhouse 

gas emissions. This technology drastically reduces emissions from power plants and industrial 

sources by capturing CO2 emissions and storing or sequestering them in deep geologic 

formations for long periods of time. Areas for potential CO2 sequestration include oil and gas 

fields, saline aquifers, and coal seams. Natural geologic analogs, like geologic formations 

containing crude oil, natural gas, brine, and CO2, have proven storage capabilities for millions of 

years. CCS technologies would attempt to take advantage of these natural storage capacities to 

reduce CO2 emissions. 

From a legal perspective, CCS owners and operators must manage complex projects and 

technologies that involve injecting large volumes of buoyant CO2 and storing them underground 

over long timeframes. The volumes of CO2 sequestered from an individual site are likely to be 

large (millions of tons of CO2 per year) and the corresponding subsurface property area is vast 

(injected CO2 potentially taking up tens of miles for a single project, with pressure effects felt 

over great distances).6 The injected CO2 must remain in the subsurface for hundreds to 

thousands of years for significant climate benefit,7 effectively using the subsurface property in 

perpetuity. Because injected CO2 will be more buoyant than the formation waters associated 

with the injection sites, the possibility of leakage to the near surface or surface is a risk that must 

be managed through site selection, operation, monitoring, and remediation. 

 

3

 The term “greenhouse gases” include carbon dioxide, methane, nitrous oxide, and fluorinated gases. See EPA, 

Climate Change, Basic Information, available at http://www.epa.gov/climatechange/basicinfo.html; EPA, Climate 

Change, Emissions, supra note 1. 

4

See United Nations Framework Convention on Climate Change, 1992, Art. 2, at p. 5 (“The ultimate objective of 

this Convention and any related legal instruments that the Conference of the Parties may adopt is to achieve, in 

accordance with the relevant provisions of the Convention, stabilization of greenhouse gas concentrations in the 

atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. Such a 

level should be achieved within a time frame sufficient to allow ecosystems to adapt naturally to climate change, to 

ensure that food production is not threatened and to enable economic development to proceed in a sustainable 

manner.”), available at http://unfccc.int/resource/docs/convkp/conveng.pdf. 

5

See Stephen Pacala & Robert Socolow, Stabilization Wedges: Solving the Climate Problem for the Next 50 Years 

with Current Technologies, SCIENCE 305, 968-972 (2004); James A. Edmonds, et al, Modeling Greenhouse Gas 

Energy Technology Responses to Climate Change, 29 ENERGY 1529 (2004); ELECTRIC POWER RESEARCH INSTITUTE 

(EPRI), THE POWER TO REDUCE CO2 EMISSIONS: THE FULL PORTFOLIO (Discussion Paper Aug. 2007), available at

http://epri-reports/org/DiscussionPaper2007.pdf. 

6

 Kartsen Preuss, et al., Numerical Modeling of Aquifer Disposal of CO2, 8 SOCIETY OF PETROLEUM ENGINEERS J. 

49, 52-53 (2003). 

7

See, e.g., Mihn Ha-Duong & David W. Keith, Carbon Storage: The Economic Efficiency of Storing CO2 in Leaky 

Reservoirs, in 5 CLEAN TECH. & ENVTL. POLICY 181 (2003). 
3

 In this Article, we focus on the relationships among CCS technologies, risk management, 

and potential liability for accidental leakage of stored CO2. We do this with an eye toward how 

potential liability may help to balance the risks and benefits of CCS and influence patterns of 

technology deployment. Much of the writing on this topic to date has either implicitly or 

explicitly argued that policymakers should limit or virtually eliminate project operators’ liability 

associated with stored CO2 in order to encourage development of this potential technology.8 

We take a different approach. We believe that potential liability for harm in the form of 

state tort law or federal or state statutory vehicles for recovery can and should serve an important 

risk management role in ensuring protection of human health and the environment in the process 

of developing and commercializing this new technology. In our view, the goal should be to use 

modest risk shifting techniques such as insurance, bonding, and pooled federal funding to 

encourage CCS development while preserving federal and state liability frameworks to promote 

and encourage safe practices and allow recovery for those who may be subject to harm. We 

believe that the anticipated level of risk from long-term storage of CO2 can be managed through 

rigorous site selection, diligent project management, a well-developed monitoring and 

verification program, and, in the case of leakage, a site-specific remediation plan. This, as well 

as the potential monetary benefits to investors and operators associated with deploying a 

successful CCS technology, should encourage policymakers to reject attempts to immediately 

shift a significant portion of the risk of liability to states or the public at large. 

There are two caveats to this approach. First, given the inherent uncertainties of 

technology research, development, and demonstration, and the strong governmental role in 

getting initial CCS projects off the ground, the first dozen or so CCS projects could be 

encouraged under a shared public-private liability regime if the private sector is willing to share 

project data and information to aid in the development of a risk-management framework.9 

Second, commercial projects which are developed after these first “demonstration projects” will 

likely require some transfer of long-term liability—approximately 20-30 years after project 

injection has ceased—and a successful monitoring and verification program has demonstrated 

that the injected CO2 is stable and behaving as expected. This is due, in part, to the mismatch 

between the lifetime of firms (tens of years) and the long-term sequestration requirements of 

CCS (hundreds to thousands of years). 

 We recognize that potential liability for harm is only one of many legal and policy issues 

that will impact the technical, economic, and political feasibility of CCS technology. Other 

important issues include the nature of the statutory and regulatory framework that will be created 

to govern all aspects of CCS, including its role within a larger climate policy; government 

funding and partnerships; and the various property rights that currently exist or will be created in 

 

8

See, e.g., Jeffrey W. Moore, The Potential Law of On-Shore Geologic Sequestration of CO2 Captured from CoalFired Power Plants, 28 ENERGY L.J. 443, 444 (2007) (arguing that the federal government should limit long-term 

liability for stored CO2 under existing federal statutes and state common law); THE INTERSTATE OIL AND GAS 

COMPACT COMMISSION (“IOGCC”), TASK FORCE ON CARBON CAPTURE AND GEOLOGIC STORAGE, A LEGAL AND 

REGULATORY GUIDE FOR STATES AND PROVINCES 11 (2007) (proposing, among other things, that after a 10-year 

period the operator of the CO2 storage site would be released from any bonding requirements and liability for 

ensuring that the site remains a secure storage site would transfer to the state). 

9

 Elizabeth J. Wilson et al., Regulating Geologic Carbon Sequestration, in ENVIRONMENTAL SCIENCE AND 

TECHNOLOGY (forthcoming 2008). 
4

the stored CO2, the subsurface pore-space that will hold the CO2, and subsurface minerals in the 

area of the stored CO2.

10 This Article acknowledges these important issues but will leave them 

for future analyses. We have chosen to focus on the issue of liability for harm instead of these 

other key issues because it is often too easy to limit or eliminate potential liabilities before they 

come into existence in the name of economic progress. Thus, we hope to provide here a 

balanced response to what we see as recent trends to limit too severely the potential liability of 

project developers through legislation and to encourage policymakers to consider a different 

approach. 

 Part I of the Article provides a brief background of CO2 sources from the industrial and 

electric power sector and a description of the potential benefits and risks of CCS. In Part II we 

outline potential liability for stored CO2 under federal environmental laws and state common 

law. As CCS will be deployed into a complex web of pre-existing property rights, legal 

standards, and case law, a clearly defined framework for better understanding how some of these 

issues would be resolved is critical in creating the legal structures that will govern any widescale use of CCS. 

In Part III, we look at actions federal and state policymakers have taken to date in 

anticipation of CCS deployment. These actions show that lawmakers in states hoping to attract a 

CCS project appear to be engaging in a classic “race-to-the-bottom” in an effort to lure CCS 

development to their state. In this Part, we also consider the potential role of federal preemption 

of state tort law and regulatory standards. In Part IV, we survey available mechanisms to 

provide financial responsibility and manage liability risks such as bonding, insurance, selective 

damage caps, and pooled federal funding. Finally, in Part V, we attempt to provide guidance to 

policymakers at the state and federal levels to address potential liability issues associated with 

CCS that goes beyond arguing that such liability should be severely limited or eliminated. As 

we show in this Part, the continuing existence of liability for harm can help to balance divergent 

interests and provide important safeguards to complement whatever regulatory regime is created 

to guide the long-term storage of CO2. Consistent with these principles, we propose a threephase framework of liability and federal funding that tracks the life-cycle of a CCS project and 

accounts for variation among projects based on site-specific risks. 

Ultimately, any assessment of risks and benefits of CCS must be put in its proper context. 

Although there are clearly long-term risks associated with CCS, they must be balanced against 

the even more significant long-term risks of climate change. As a result, the goal of this Article 

is to present options for creating liability and funding frameworks that encourage the 

development of CCS and its corresponding benefits while ensuring that the potential risks of 

CCS do not fall too heavily on states or individuals that may be vulnerable to harm. 

I. ELECTRIC POWER GENERATION, INDUSTRIAL SOURCES, GREENHOUSE GAS EMISSIONS,

AND CCS 

 This Part describes CCS technology by first introducing the role of industrial sources and 

the electric power sector in the creation of greenhouse gas emissions and explaining how CCS 

 

10 For a detailed discussion of the potential property right and liability frameworks associated with stored CO2, see 

MARK ANTHONY DE FIGUEIREDO, THE LIABILITY OF CARBON DIOXIDE STORAGE (MIT Ph.D. Thesis Feb. 2007). 
5

technology is being developed as a means to control such emissions. It then proceeds to provide 

some detail on the CCS projects that exist today and those that are planned for the near future. 

Finally, this Part introduces some of the potential environmental and public health risks 

associated with CCS and the long-term storage of CO2. 

A. Electric Power and Greenhouse Gas Emissions 

 The electric power sector is responsible for 41% of greenhouse gas emissions from fossil 

fuel combustion, and 33% of total greenhouse gas emissions in the United States.11 Of these 2.4 

billion metric tons of greenhouse gas emissions a year from the electric power sector, 88% is 

emitted from coal-fired electric plants.12 These plants play a crucial role in our energy 

infrastructure, providing inexpensive base-load electricity generation.13 Coal is plentiful in the 

United States14 and worldwide,15 inexpensive relative to other fuel sources,16 and was the fastest 

growing fuel in 2006,17 making it a key source of energy in countries like China and Germany as 

well as in the United States. 

 Using coal for electricity generation, however, has also been linked to many 

environmental ills. Upstream impacts from coal combustion include the adverse effects of 

mountain-top removal, acid mine drainage, and land subsidence. Downstream impacts from coal 

combustion include air pollution, acid rain deposition, and, more recently, greenhouse gases 

implicated in global climate change. Regulations have been developed to manage these impacts 

with varying degrees of success. Federal law has attempted to address upstream mining impacts 

through the Surface Mining Control and Reclamation Act of 1977,18 and regulations 

promulgated by the Office of Surface Mining.19 With regard to downstream impacts, early state 

 

11 See U.S. ENVIRONMENTAL PROTECTION AGENCY, INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS 1990-2005 

Table ES-3 (2007), available at http://www.epa.gov/climatechange/emissions/downloads06/07CR.pdf,. 

12 Id. at Table 1-4. 

13 Electricity cannot be stored and must be generated to meet demand. Because electricity demand varies both 

throughout the day and across different seasons, plants typically are run as either base load or peaking plants. Base 

load generating plants are plants that run almost continuously. Typically, base load plants—traditionally nuclear or 

coal—are inexpensive to operate, but more expensive to build. See generally Stratford Douglas, Measuring Gains 

from Regional Dispatch: Coal-fired Power Plant Utilization and Market Reforms, 27 ENERGY J. 119-28 (2006).

14 See Energy Information Administration Coal Reserves Data, available at

http://www.eia.doe.gov/cneaf/coal/reserves/chapter1.html. 

15 Coal reserves are especially prominent in North America, Europe and Asia. See BP, BP STATISTICAL REVIEW OF 

WORLD ENERGY 2007, available at

http://www.bp.com/liveassets/bp_internet/globalbp/globalbp_uk_english/reports_and_publications/statistical_energ

y_review_2007/STAGING/local_assets/downloads/pdf/statistical_review_of_world_energy_full_report_2007.pdf. 

16 For a good summary of the above data sources see Energy Information Administration (“EIA”), Annual Energy 

Review 2005 and Monthly Energy Review, available at http://www.eia.doe.gov/overview_hd.html; EIA Petroleum 

Navigator, available at http://tonto.eia.doe.gov/dnav/pet/pet_pri_top.asp; EIA Coal News and Markets, available at

http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html; MIT Energy Club Units and Conversions Fact 

Sheet, available at

http://web.mit.edu/mit_energy/resources/factsheets/Units&ConvFactors.MIT%20EnergyClub%20Factsheet.v8.pdf. 

17 See BP, supra note 15, at 42. 

18 Surface Mining Control and Reclamation Act of 1977, 30 U.S.C. §§ 1300, et seq.

19 See 30 C.F.R. §§ 700, et seq., (specifying conditions and rules for mining coal and other minerals), available at

http://www.osmre.gov/regindex.htm. 
6

regulations20 and the Clean Air Act21 have led to the successful deployment of technologies to 

control particulate matter, sulfur dioxide emissions,22 and oxides of nitrogen. Reducing CO2

emissions from coal, however, is a fundamentally different—and difficult—challenge. 

 CCS has been examined in detail in a Special Report by the Intergovernmental Panel on 

Climate Change.23 The IPCC report outlines sources of CO2, capture technologies, transportation 

modes, geologic storage and risks, and covers economic potential and cost, along with a 

description of how CCS could fit within a greenhouse gas inventory and accounting scheme. It 

finds that CCS could play an important role in enabling deep and relatively inexpensive 

greenhouse-gas emissions reductions. At a sequestration cost estimated from twenty-five to 

ninety dollars per metric ton, depending upon the source for CO2 captured and sequestered, large 

energy-economic models predict CCS could help to reduce the overall societal cost of deep 

emission reductions.24 Table 1 outlines the quantities of CO2 from various industrial and electric 

power sources. Emerging technologies for non-conventional hydrocarbons, including oil from 

tar sands or coal-to-liquids projects are also potential large CO2 emission sources and candidates 

for CCS.25 

TABLE 126

PROCESS NUMBER OF 

SOURCES 

EMISSIONS 

(MILLION TONS OF 

CO2 PER YEAR) 

Fossil Fuels 

Power 4,924 10,539 

Cement production 1,175 932 

Refineries 638 798 

Iron and steel industry 269 646 

Petrochemical industry 470 379 

Oil and gas processing Not available 50 

Other sources 90 33 

Biomass 

Bioethanol and bioenergy 303 91 

TOTAL 7,887 13,466 

 

20 See JOEL A. TARR, THE SEARCH FOR THE ULTIMATE SINK: URBAN POLLUTION IN HISTORICAL PERSPECTIVE 219-62 

(Univ. of Akron Press 1996) (providing environmental history of pollution control in urban areas). 

21 Clean Air Act, 42 U.S.C. §§ 7401-7671q. 

22 See Margaret R. Taylor et al., Effect of Government Actions on Technological Innovation for SO2 Control, 37 

ENVTL. SCI. & TECH. 4527-4534 (2003).

23 WORKING GROUP III OF THE INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE, IPCC SPECIAL REPORT ON 

CARBON DIOXIDE CAPTURE AND STORAGE (Cambridge Univ. Press 2005), available at

http://www.ipcc.ch/ipccreports/special-reports.htm. 

24 Id. at 11. 

25 See Matthew L. Wald, Search for New Oil Sources Leads to Processed Coal, N.Y. TIMES (July 5, 2006). 

26 See IPCC SPECIAL REPORT ON CARBON CAPTURE AND STORAGE, SUMMARY FOR POLICYMAKERS SPM-3 

(worldwide large stationary CO2 sources with emissions greater than 0.1 million tons per year). 
7

B. How CCS Works 

CCS projects must capture CO2 from power plants or industrial sources27 and transport 

it28 to a geological sequestration site. The CO2 is then injected deep underground—at depths 

greater than roughly one kilometer—into geological formations, such as depleted oil and gas 

reservoirs, saline aquifers, and unminable coal seams.29 Injecting CO2 into an injection well is 

essentially the reverse of pumping oil or water from a confined aquifer. The injection pressure 

must exceed the formation pressure, and the CO2 fills the permeable pore space within the 

sedimentary rocks, essentially trapped by less permeable rock layers which impede upward fluid 

migration. CO2 will be sequestered either as a gas, a dense supercritical gas, or a liquid.30 

Depending on reservoir temperature and pressure injected, in almost all circumstances, except 

deep ocean subsurface sequestration, CO2 will be less dense than the brine present in the 

reservoir. This makes buoyancy flow an important force governing supercritical CO2 behavior in 

the subsurface.31 The life-cycle of a geological storage project progresses from site selection, 

characterization, and demonstration and regulatory review (1-10 years); active CO2 injection and 

well closure (20-30 years); post-closure monitoring (10-15 years); and long-term stewardship 

(hundreds of years).32 Regulatory reporting, monitoring, and necessary remediation activities 

take place throughout the life-cycle.33

Because injected CO2 will initially be more buoyant than the in situ waters, upwards and 

lateral migration within the subsurface is an important consideration for modeling and 

monitoring subsurface behavior. Due to geological heterogeneity, CO2 behavior in the 

subsurface will vary between sequestration sites. Importantly, storage integrity will become 

more secure over time as geochemical reactions dissolve CO2 in formation waters (centuries), 

and eventually convert it to minerals like calcium carbonate (millennia).34 Thus, an effective 

geologic sequestration site will keep large volumes of a buoyant fluid underground for centuries 

to millennia. 

 

27 In terms of costs of electricity generation, capture costs are the greatest component – 1.8 to 3.4 ¢/kWh for 

pulverized coal plants; 0.9 to 2.2 ¢/kWh for integrated gasification combined cycle coal plants; 1.2 – 2.4 ¢/kWh for 

natural gas combined cycle power plants. Transport and sequestration costs range from -1 to 1 ¢/kWh (the negative 

values are possible if captured CO2 is sold for use in enhanced oil recovery or enhanced coal-bed methane 

production. These transport costs would be considerably higher if sequestration sites are not located within a 

reasonable distance from the plant. See Howard Herzog et al., Costs and Economic Potential, IPCC SPECIAL 

REPORT ON CARBON DIOXIDE CAPTURE AND STORAGE 8-1 to 8-37 (2005). 

28 See IPCC, supra note 2, at 179-94. 

29 Id. at 31-36. See generally Sam Holloway, An Overview of the Underground Disposal of Carbon Dioxide, 

ENERGY CONVERSION AND MANAGEMENT 38 (Supplement): S193-S198 (1997); Sam Holloway, Storage of Fossil 

Fuel-Derived Carbon Dioxide Beneath the Surface of the Earth, 26 ANNUAL REVIEW OF ENERGY AND THE 

ENVIRONMENT 145-166 (2001). 

30 CO2 is considered a supercritical fluid at temperatures greater than 31.1°C and 7.38 MPa (critical point). See

CRC HANDBOOK OF CHEMISTRY AND PHYSICS Table II, F-89 (60th ed. 1979); Robert G. Bruant et al., Safe Storage 

of CO2 in Deep Saline Aquifers, 36 ENVTL. SCIENCE & TECH. 240A-245A (2002). 

31 Stefan Bachu, Sequestration of CO2 in Geological Media: Criteria and Approach for Site Selection in Response to 

Climate Change, 41 ENERGY CONVERSION MGMT. 953, 967 (2000). 

32 Elizabeth J. Wilson et al., supra note 9. 

33

 Id. 

34 Preuss et al., supra note 6, at 52-53. 
8

Although the idea of injecting CO2 into the subsurface for the purpose of controlling 

greenhouse gas emissions may be new, the practice of injecting CO2 into the subsurface for other 

purposes is not. For decades, oil producers have injected CO2 into the subsurface to increase oil 

production from depleted fields. This process, known as “enhanced oil recovery” or EOR, is in 

widespread use in West Texas, where 30 million tons of CO2 are injected into the ground 

annually, resulting in a total of 600 million tons injected—though not stored for sequestration—

in that area since 1985.35 While supporters of CCS hold up the success and safety of CO2

injection for enhanced oil recovery purposes, it is clear that CO2 storage for purposes of 

controlling greenhouse gas levels in the atmosphere will be several orders of magnitude larger.36 

The MIT “Future of Coal” study states, “ If 60% of the CO2 produced from U.S. coal-based 

power generation were to be captured and compressed to a liquid for geologic sequestration, its 

volume would about equal the total U.S. oil consumption of 20 million barrels per day,”37 

highlighting the massive volumes of CO2 involved in a large-scale carbon capture program. 

C. Potential Risks of Geologic Sequestration from CCS 

For CCS to enable continued use of fossil fuels and simultaneous deep emission 

reductions, it must be deployed on a scale far beyond what exists today. To do this the risks 

must be adequately managed and the technology must be integrated into a larger legal and 

regulatory scheme. Of key import are (1) the volume of the CO2 to be injected—a 1,000 

Megawatt power plant produces from 4-6 Million tons per year; (2) the fact that CO2 will be 

more buoyant than the subsurface saline formation water; and (3) the need for injected CO2 to 

remain in the subsurface for hundreds to thousands of years. Worldwide, there are four CCS 

projects, each injecting roughly 1 million tons of CO2 annually.38 If all of the 1.5 billion tons of 

CO2 produced from U.S. coal-fired power plants were captured, transported and injected for 

CCS, it would be equivalent to roughly one-third of the natural gas transported by pipelines in 

the U.S. each year.39

The IPCC report on CCS estimates that in excess of 99% of injected CO2 is very likely 

(probability between 90 to 99%) to remain in appropriately selected geological reservoirs for 

over 100 years.40 While the probability for leakage to the surface appears low for well-selected 

 

35 RICHARD C. MAXWELL ET AL., OIL AND GAS 13-14 (8th ed. 2007) (discussing enhanced recovery technology); 

Steven D. Cook, Researchers Optimistic on Prospects for Successful Carbon Capture, Storage, DAILY ENV. REP. 

No. 94 at A-1 (BNA May 16, 2007) (discussing the use of enhanced oil recovery in Texas as a current example of 

subsurface injection of CO2). 

36 See U.S. Environmental Protection Agency, Guidance Document, Using Class V Experimental Technology Well 

Classification for Pilot Geologic Sequestration Projects, UIC Program Guidance (UICPG #83) at 2 (March 1, 2007) 

(stating that “[w]hile injection of fluids, including CO2 into the subsurface, e.g., for enhanced oil recovery (EOR) 

and enhanced gas recovery (EGR), is a long-standing practice, injection of CO2 [for CCS] is an experimental 

application of this existing technology.”). 

37 MIT, THE FUTURE OF COAL xi (2007). 

38 These projects are Sleipner in the North Sea, run by StatoilHydro; In Salah in Algeria by BP, Sonatrach and 

StatoilHydro; Weyburn in Canada, operated by EnCana; and Snøhvit in the Barents Sea, operated by StatoilHydro. 

A comprehensive list of commercial and pilot CCS projects is maintained by the International Energy Agency 

(“IEA”), available at http://co2captureandstorage.info/co2db.php. 

39 See MIT, supra note 37, at ix. 

40 See id. at 14 (“Observations from engineered and natural analogues as well as models suggest that the fraction 

retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years 
9

sites, and potential leakage manageable, identifying potential risks for CCS and developing 

management strategies will help to ensure predictable technology deployment. With respect to 

global climate change, small surface leaks may be tolerated, but excessive (greater than 1% to 

.01% per year) CO2 leakage back to the atmosphere will negate the climate benefits from 

sequestration.41 Persistent leakage could result in diminishing benefits in carbon emissions 

reductions associated with a CCS program. 

CCS risks seem to be well within the bounds of other industrial activities like enhanced 

oil recovery, but they must be managed by an emerging regulatory and institutional framework.42 

These risks are associated both with the sheer volume of injected material, as well as the specific 

properties of CO2, and vary for given stages in the life-cycle of a CCS project.43 Risks also vary 

due to local and regional geology and site history, and will likely decrease with time as 

formation buoyancy pressures naturally decrease.44 Initially, buoyancy flow could drive CO2

upward through pathways in undetected faults or abandoned well bores. Large surface releases, 

albeit unlikely, could pose health risks to humans, both in the form of immediate death from 

asphyxiation or effects from prolonged exposure to high concentrations of CO2.

45 Slow CO2

seepage into the near subsurface could harm flora and fauna, and potentially cause local 

disruptions of ecology or agriculture.46 There are also a number of potential risks associated 

with injected CO2 even if it remains underground, including displacement of saline groundwater 

into potable aquifers, contamination of hydrocarbon resources, pressure changes causing ground 

 

and is likely to exceed 99% over 1,000 years. For well-selected, designed and managed geological storage sites, the 

vast majority of the CO2 will gradually be immobilized by various trapping mechanisms and, in that case, could be 

retained for up to millions of years. Because of these mechanisms, storage could become more secure over longer 

timeframes.”). 

41 See generally, Minh Ha-Duong & David W. Keith, Carbon Storage: The Economic Efficiency of Storing CO2 in 

Leaky Reservoirs, CLEAN TECHNOLOGIES AND ENVIRONMENTAL POLICY 181-89 (2003); Stephen W. Pacala, Global 

Constraints on Reservoir Leakage, SIXTH INTERNATIONAL CONFERENCE FOR GREENHOUSE GAS CONTROL 

TECHNOLOGIES, KYOTO, JAPAN (2002); Robert P. Hepple & Sally M. Benson, Implications of Surface Seepage on 

the Effectiveness of Geological Storage of Carbon Dioxide as a Climate Change Mitigation Strategy, SIXTH 

INTERNATIONAL CONFERENCE ON GREENHOUSE GAS CONTROL TECHNOLOGIES, Kyoto, Japan 30 (2002). 

42 Sally Benson et al., Underground Geological Storage, in IPCC SPECIAL REPORT ON CARBON DIOXIDE CAPTURE 

AND STORAGE, supra note 6, at 196-276. 

43 Elizabeth J. Wilson & David Gerard, Geologic Sequestration Under Current U.S. Regulations, in CARBON 

CAPTURE AND SEQUESTRATION: INTEGRATING TECHNOLOGY, MONITORING, REGULATION 169-93 (Elizabeth J. 

Wilson & David Gerard, eds. 2007). 

44 In several modeling simulation studies, complete dissolution of the CO2 in the formation water is predicted on the 

order of 5,000-100,000 years, depending on the formation. See Erik Lindeberg & Per Bergmo, The Long-term Fate 

of CO2 Injected Into an Aquifer, SIXTH INTERNATIONAL CONFERENCE ON GREENHOUSE GAS CONTROL 

TECHNOLOGIES, KYOTO, Vol. I, 489-94 (John Gale and Yoichi Kaya eds. 2003); J. Ennis-King, & L. Paterson, Rate 

of Dissolution Due to Convective Mixing in the Underground Storage of Carbon Dioxide, in SIXTH INTERNATIONAL 

CONFERENCE ON GREENHOUSE GAS CONTROL TECHNOLOGIES, KYOTO, Vol. I, 507-10 (John Gale & Yoichi Kaya 

eds. 2003). 

45 See Kay Damen et al., Health, Safety and Environmental Risks of Underground CO2 Storage – Overview of 

Mechanisms and Current Knowledge, 74 CLIMATIC CHANGE 297 (2006); SALLY M. BENSON ET AL., LESSONS 

LEARNED FROM NATURAL AND INDUSTRIAL ANALOGUES FOR STORAGE OF CARBON DIOXIDE IN DEEP GEOLOGICAL 

FORMATIONS, EARTH SCIENCES DIVISION, E.O. LAWRENCE BERKELEY NATIONAL LABORATORY, BERKELEY, 135 

(2002).

46 See Prasad Saripalli et al., Risk and Hazard Assessment for Projects Involving the Geological Sequestration of 

CO2, in SIXTH INTERNATIONAL CONFERENCE ON GREENHOUSE GAS CONTROL TECHNOLOGIES, supra note 44, at 

511-16. 
10

heave, and even triggering seismic events—though these risks likely will be small with properly 

managed sites.47 Experience with remediation of leaking well-bores is well developed, whereas 

approaches for remediation of undetected faults are potentially more costly.48 

Thus, there are a range of potential risks associated with long-term storage of CO2, 

including groundwater contamination, surface ecological damage, harm to human health, 

geologic hazards, and damage from hydrocarbons where CO2 injection is linked with enhanced 

oil recovery operations.49 While the probability of these risks is site specific and estimated to be 

low and manageable, ensuring CCS projects project human and environmental safety is an 

important component of the future program’s success. 

D. Storage Capacity and CCS Projects 

 Estimated worldwide storage capacity for CCS is large, as shown in Table 2 below. A 

Department of Energy report released March 27, 2007 indicates underground storage capacity of 

3,500 billion metric tons across the U.S. and Canada for storing CO2 and other greenhouse gases 

produced at power plants and other industrial sources.50 Estimates are that the Powder River 

Basin in Wyoming alone may have the capacity to sequester 13.6 billion metric tons of CO2.

51

 

Compared directly with the 1.5 billion tons of CO2 emitted from coal-fired power plants annually 

in the U.S., storage capacity is plentiful. Some electric power industry representatives believe 

that carbon capture and storage could reduce power plant emissions by one-quarter in 2030.52 

Federal energy personnel have testified in Congress that at the current rate of energy production 

and use, the United States and Canada have the capacity to store all of the CO2 emissions they 

produce over the next 175 to 500 years.53 Physical storage capacity, however, is just one factor 

that will influence CCS deployment; state laws, liability, and risk also will affect the viability of 

CCS project deployment. 

 

47 Benson et al., supra note 42, at 293-96. 

48 See generally Yingqi Zhang et al., Vadose Zone Remediation of Carbon Dioxide Leakage from Geologic Carbon 

Dioxide Sequestration Sites, 3 VADOSE ZONE JOURNAL 858-866 (2004).

49 Elizabeth J. Wilson et al., Liability and Financial Responsibility Frameworks for Carbon Capture and 

Sequestration, WORLD RESOURCES INSTITUTE ISSUE BRIEF 1, 3-4 (Dec. 2007). 

50 See U.S. DEPARTMENT OF ENERGY, CARBON SEQUESTRATION ATLAS OF THE U.S. AND CANADA (2006), available 

at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlas/index.html, Lawrence J. Speer, DOE Finds Large 

Capacity for Storing Carbon Dioxide Across U.S., Canada, DAILY ENVT. REP. No. 60 at A-5 (BNA March 29, 

2007). See also ERIC WILLIAMS, ET AL., CARBON CAPTURE, PIPELINE AND STORAGE: A VIABLE OPTION FOR NORTH 

CAROLINA UTILITIES?, WORKING PAPER, NICOLAS INSTITUTE FOR ENVIRONMENTAL POLICY SOLUTIONS AND THE 

CENTER ON GLOBAL CHANGE, DUKE UNIVERSITY (March 8, 2007), available at

www.nicholas.duke.edu/institute/carboncapture.pdf. 

51 See Dustin Bleizeffer, State has Vast Capacity for CO2 Sequestration, CASPER STAR TRIBUNE (April 5, 2007). 

52 Steven D. Cook, Power Industry Officials Disagree on Future, Feasibility of Carbon Capture, Storage, DAILY 

ENVT. REP. No. 186 at A-1 (BNA Sept. 26, 2007). 

53 Id.
11

TABLE 254

RESERVOIR TYPE LOWER ESTIMATE OF 

STORAGE CAPACITY 

(BILLIONS OF TONS OF 

CO2) 

UPPER ESTIMATE OF 

STORAGE CAPACITY 

(BILLIONS OF TONS OF 

CO2) 

Oil and gas fields 675 900

Unminable coal seams 3-15 200 

Deep saline formations 1000 Uncertain, possibly 10,000 

 Several CCS projects are underway or planned in Canada, the United States, and other 

countries.55 Four current projects each capture roughly one metric ton of CO2 per year from 

natural gas production projects, with Sleipner and Snohvit in the North Sea injecting CO2

captured from the produced natural gas deep below the seafloor, and In Salah in Algeria injecting 

the CO2 into a deep gas formation.56 The Weyburn enhanced oil recovery project in 

Saskatchewan injects roughly one metric ton of CO2 each year and monitors it for storage. The 

CO2 injected in this project is captured from a coal gasification plant in Beulah, North Dakota, 

and transported by pipeline over an international border.57 Other projects are planned in 

Australia, Europe, and the United States.58

 Over the past several years, federal and state governments and the private sector have 

focused significant amounts of money and attention on a large-scale CCS project known as 

“FutureGen.” Although recent political decisions place the project’s viability in significant 

doubt, the size and scope of the project demonstrate the federal government’s commitment to 

large-scale CCS in general. Specifically, in 2005, the U.S. Department of Energy (“DOE”) 

began an initiative to build the world’s first integrated sequestration and hydrogen production 

research power plant. This project was designed as a $1.5 billion public/private partnership 

made up of member power companies working with DOE to build the world’s first coal-based, 

zero-emission electricity and hydrogen production facility. The federal government committed 

to provide 74 percent of the project costs while private sector partners agreed to provide the 

remaining 26 percent.59 

 

54 See supra note 50. Estimated storage capacity for different geological storage sites, including non-economic sites. 

These numbers would increase 25% if currently “undiscovered” oil and gas fields were included. 

55 See Elizabeth J. Wilson & Mark A. de Figueiredo, Geologic Carbon Dioxide Sequestration: An Analysis of 

Subsurface Property Law, 36 ELR 10114 (Feb. 2006). Existing projects include ones at Sleipner (North Sea), 

Weyburn (Canada), and In Salah (Algeria). 

56 Id.

57 Id.

58 Id.

59 Steven D. Cook & Michael Bologna, Illinois Site Chosen for FutureGen Project Amid Warnings of Possible 

Restructuring, DAILY ENVT. REP. No. 243, at A-3 (Dec. 19, 2007). See also FutureGen Alliance, available at

www.futuregenalliance.org/about/siting.stm. 
12

 As part of the project, the FutureGen partnership evaluated four candidate sites in Illinois 

and Texas and, in December 2007, selected Mattoon, Illinois.60 According to the FutureGen 

partnership, the site was selected because the town could offer clean legal title to the site for both 

the plant and the site for CO2 injection, it has ready access to plentiful water, and the geology of 

the site is suitable for CO2 injection.61 In January 2008, however, DOE announced that it was 

withdrawing support for the FutureGen project in favor of supporting multiple commercial-scale 

power plants across the country.62 The reasons given for withdrawal were the rising costs 

associated with the project, and recent technological advances that would allow broader 

commercial-scale deployment than was envisioned with FutureGen.63 

Putting FutureGen aside, Congress and DOE have been attempting to authorize 

significant funding for CCS projects across the country. Competing House and Senate bills in 

2007 each provided nearly $1.5 billion in funding for research and development of CCS.64 In 

October 2007, DOE awarded $197 million in funding to three regional carbon sequestration 

partnerships in connection with pilot projects to store 1 million tons or more of CO2 in deep 

saline reservoirs to test the feasibility of long-term CO2 storage.65 The money will be spent on 

these projects over ten years in the Great Plains states,66 the Southeast,67 and the Southwest.68 

The projects will cost $318 million, with private partners providing the balance of the funds. In 

January 2008, DOE funded a fourth project in the Midwest to inject 1 million tons of CO2 one 

mile below the earth’s surface within the Illinois basin.69 

Many recognize, however, that such subsidies alone will not be sufficient to spur 

commercial deployment. Instead, commercial deployment will follow federal and/or state law 

that establishes regulatory limits on greenhouse gas emissions, coupled with a sufficiently high 

and stable price on CO2, which together will provide an incentive for new technology to meet 

those limits.70 For instance, the States of California and Washington have enacted legislation 

setting greenhouse gas emission performance standards for electric utilities beginning January 1, 

 

60 Cook & Bologna, supra note 59. 

61 Id. See also FUTUREGEN ALLIANCE, FINAL SITE SELECTION REPORT (Dec. 18, 2007) (discussing FutureGen 

project, the incentives provided by state and local governments to attract the project, and analysis of the site 

selection process), available at http://www.futuregenalliance.org/news/fg_final_site_selection_report.pdf. 

62 See Steven D. Cook, DOE Pulls Support for FutureGen Project, Will Fund Carbon Capture at Multiple Sites, 

DAILY ENVT. REP. No. 20, at A-1 (BNA Jan. 31, 2008); U.S. Department of Energy, Press Release, DOE Announces 

Restructured FutureGen Approach to Demonstrate CCS Technology at Multiple Clean Coal Plants (Jan. 30, 2008), 

available at http://www.energy.gov/news/5912.htm. 

63 Id. 

64 Dean Scott, Combined Incentives, Regulation Needed to Spur Carbon Sequestration, Markey Says, DAILY ENVT.

REP. No. 173 at A-4 (Sept. 7, 2007). 

65 DOE Funds Three Large-Scale Projects to Test Feasibility of Carbon Dioxide Storage, DAILY ENVT. REP. No. 

196 at A-7 (Oct. 11, 2007). 

66 This project is the Plains CO2 Reduction Partnership led by the Energy & Environmental Research Center at the 

University of North Dakota. Id.

67 This project is the Southeast Regional Carbon Sequestration Partnership. Id.

68 This project is the Southwest Regional Partnership for Carbon Sequestration coordinated by the New Mexico 

Institute of Mining and Technology. Id.

69 Michael Bologna, Energy Department, Midwest Partners Launch Carbon Sequestration Project in Illinois Basin, 

DAILY ENVT. REP. No. 3, at A-1 (Jan. 7, 2008). The project is a joint effort by the Midwest Geological 

Sequestration Consortium, the Illinois State Geological Survey, and Archer Daniels Midland Company. Id.

70 Scott, supra note 64 (citing Rep. Edward Markey (D-Mass.)). 
13

2007 in California and July 1, 2008 in Washington. In both states, the laws allow utilities to 

exempt from their emissions calculations those emissions that are injected permanently into 

geologic formations or otherwise permanently sequestered by other approved means.71 Thus, 

even more than federal or state financial incentives, it is caps on greenhouse gas emissions that 

will explicitly establish a price for CO2 and will encourage utilities and others to invest in CCS 

in order to meet those caps. 

II. CCS AND LIABILITY FOR HARM TO HUMAN HEALTH AND THE ENVIRONMENT

 The scope, scale, and duration of any full-fledged CCS project will create the potential 

for liability associated with CO2 leakage, and other adverse impacts on resources, human health 

and the environment. This Part focuses on liability for harm associated with the post-closure and 

long-term sequestration of CO2, as opposed to liability associated with the operation of the CCS 

project itself. This Part concludes that the potential liability associated with long-term storage of 

CO2 is an issue which must be addressed, and will be subject to significant debate by federal and 

state policymakers wishing to encourage CCS deployment. These debates will center on how 

best to establish in advance as precisely as possible where tort liability, financial responsibility, 

and ownership interests will rest as between corporate developers, state and federal governments, 

and other interested parties. 

Before any widespread, large-scale implementation of CCS technologies, there likely will 

be thousands of pages of statutes and regulations governing all aspects of the CCS process. This 

regulatory framework is critical to creating technology and safety standards to guide 

development, manage risk, and protect human health and the environment. The intense focus on 

this future regulatory structure, however, should not lead policy makers to eliminate or overlook 

the role of existing liability regimes, particularly state tort law and federal environmental law, in 

providing a backstop to guide behavior and compensate injured parties. 

A. Federal Statutory Relief for Harm to Human Health and the Environment 

 Since the 1970s, Congress and state legislatures have enacted far-reaching legislation to 

reduce or eliminate air and water pollution, govern the generation, storage, and disposal of solid 

and hazardous waste, and create a regulatory system to review, classify, and regulate a host of 

pollutants and hazardous chemicals. This Section does not attempt to provide a full discussion of 

the existing environmental laws that may govern the long-term storage of CO2.

72 Instead, it 

focuses solely on those federal environmental statutes that allow non-federal parties (i.e., states 

and private parties) the opportunity to obtain monetary recovery or injunctive relief in case of 

harm from the long-term storage of CO2. These laws may act as important gap-fillers in any 

federal regulatory system governing CCS. 

 

71 CA PUB. UTIL. CODE § 8341(d)(5); Wash. Rev. Code Ann. § 80.80.040. See also Rick Valliere, State Lawmakers 

Briefed on Development of Carbon Capture, Storage Initiatives, DAILY ENVT. REP. No. 151, at A-3 (Aug. 7, 2007) 

(discussing efforts by legislatures in Texas, Wyoming, California, and Maine to provide regulatory approval for 

CCS projects and to use CCS technology as an offset in setting caps on greenhouse gas emissions); Western 

Governors’ Association, Clean and Diversified Energy Initiative, available at

http://www.westgov.org/wga/initiatives/cdeac/progress-renewable.htm (discussing legislative efforts to create clean 

energy policies, including through CCS). 

72 Prior papers that have attempted to do so include de Figeueiredo, supra note 10, and Moore, supra note 8. 
14

The most important of these laws for present purposes are the Comprehensive 

Environmental Response, Compensation, and Liability Act (“CERCLA”),73 also known as 

“Superfund” and the Resource Conservation and Recovery Act (“RCRA”).74 These statutes are 

unique among environmental laws in that they allow private parties and state and local 

governments to seek injunctive relief or monetary recovery in case of harm without federal 

government involvement. In this way, these statutes provide potential incentives to promote 

project safety that go beyond the existence of a federal or state regulatory structure or the fear of 

federal or state enforcement for noncompliance with regulations. This ability for non-federal 

parties to take action separate and apart from a federal enforcement action has always been 

critical to ensuring enforcement of the environmental laws.75 It is even truer today at a time 

when agency budgets and staffs are limited and there is a perception that industry has too much 

control over the federal agencies’ regulatory and enforcement agenda.76 

 1. CERCLA 

CERCLA, also known as “Superfund”77 was enacted in 1980 to create a federal 

framework to address the problems associated with the existence of hazardous substances in the 

environment. Unlike other environmental laws that govern the generation, management, and 

disposal of hazardous materials and waste, CERCLA provides a cost-recovery vehicle for the 

federal government, state and local governments, and private parties to recover costs associated 

with contamination that occurred in the past, often decades ago, during a time when there were 

few requirements associated with the disposal of hazardous substances.

78 Specifically, CERCLA 

provides that any private or government entity may sue to recover for any “release”79 of a 

“hazardous substance,”80 from a “facility,”81 which results in “response costs,”82 so long as those 

costs are incurred in a manner consistent with the “National Contingency Plan.”83 Liability 

under CERCLA is retroactive, joint, and several and is imposed on current as well as past owners 

and operators of “facilities” where there has been a release of a hazardous substance, as well as 

 

73 42 U.S.C. §§ 9601-9675. 

74 42 U.S.C. § 6901-6992k. 

75 See Alexandra B. Klass, Punitive Damages and Valuing Harm, 92 MINN. L. REV. 83, 127-28 (2007) (discussing 

the important role Congress envisioned for citizen enforcement of environmental laws). 

76 Id. at 126-27 (discussing difficulties federal government faces in enforcing existing environmental laws and 

importance of suits by non-federal parties under statutes and common law to fill the enforcement gap).

77 The term “Superfund” is from the five-year, $1.6 billion Hazardous Substances Response Trust Fund created to 

finance cleanups at CERCLA’s inception. See 28 U.S.C. § 9507 (establishing fund). Superfund is funded by special 

taxes on oil and chemical companies and other businesses and supplemented by general revenues, as well as cleanup 

costs recovered from responsible parties. See SUSAN M. COOKE & CHRISTOPHER P. DAVIS, THE LAW OF 

HAZARDOUS WASTE: MANAGEMENT, CLEANUP, LIABILITY AND LITIGATION § 12.03[3] (2004) [hereinafter 

“COOKE”]. 

78 See generally Alexandra B. Klass, From Reservoirs to Remediation, The Impact of CERCLA on Common Law 

Strict Liability Environmental Claims, 39 WAKE FOREST L. REV. 903, 920-23 (2004) (discussing CERCLA’s 

liability provisions). 

79 42 U.S.C. § 9601(22) (defining “release”). 

80 42 U.S.C. § 9601(14) (defining “hazardous substance”). 

81 42 U.S.C. § 9601(9) (defining “facility”). 

82 42 U.S.C. § 9601(25) defining “response”). 

83 See 42 U.S.C. § 9607(a) (setting forth prima facie case for CERCLA recovery); Klass, supra note 78, at 920-23 

(discussing CERCLA’s liability provisions). 
15

on those who have generated or transported hazardous substances.84 The broad nature of the 

liability coupled with the ability of private parties to recover under CERCLA has made 

CERCLA a powerful vehicle to recover costs associated with contamination resulting from a 

wide-range of harmful substances. 

CERCLA, however, only allows recovery by private parties for money spent on the 

investigation and remediation of a release of hazardous substances; it does not allow private 

parties to recover damages associated with lost profits, diminution in value to property, personal 

injury, lost rents, punitive damages, or other damages associated with contamination of property 

or the environment.85 By contrast, some state superfund statutes, such as those in Alaska, 

Minnesota, and Washington, allow recovery for personal injury, lost profits, diminution in value 

to property, attorneys fees, expenses, or other losses stemming from the contamination of 

property or harm to human health and the environment.86 

In order for CERCLA to apply to any releases of CO2, however, the stored CO2 must be a 

“hazardous substance.” CERCLA defines a hazardous substance as including any substance 

designated as hazardous by EPA under CERCLA and/or various other environmental statutes 

such as the Clean Air Act, the Clean Water Act, and the Solid Waste Disposal Act.87 As CO2 is 

non-toxic at low concentrations and is not a listed waste, CERCLA likely does not apply to 

current CO2 injection activities unless recognized hazardous substances are present. 

Additionally, if CCS is associated with hydrocarbon production, CERCLA also contains a 

“petroleum exclusion” which states that petroleum and natural gas are not hazardous 

substances.88 Finally, CERCLA typically does not apply to hazardous substances contained in 

“useful products” (as opposed to waste) which would mean that CERCLA might not cover stored 

CO2 if it was classified as a “commodity” rather than a waste.89 Most important, CERCLA does 

not define CO2 as a hazardous substance and neither does any other federal environmental 

statute. 

While CERCLA (and most state analogs) do not appear to cover CO2, applying 

CERCLA’s liability framework to CCS risk management allows us to examine the implications 

of such an approach. The retroactive nature of CERCLA was critical to its success because 

much of the conduct and contamination it was attempting to cover was perfectly legal at the time 

it took place. Thus, the lack of standards in the past required a super-charged liability statute in 

order to cast as wide a net as possible, both with regard to the number of potential defendants 

 

84 See 42 U.S.C. § 9607(a). See also ROBERT V. PERCIVAL ET AL., ENVIRONMENTAL REGULATION: LAW, SCIENCE,

& POLICY 370-71 (5th ed. 2006) (discussing retroactivity of CERCLA’s liability provisions). 

85 Klass, supra note 78, at 923. 

86 See, e.g., ALASKA STAT. § 46.03.422(a), 46.03.824, and 46.03.822(m) (allowing cost recovery and broadly 

defined damages as well as costs of containment and cleanup in connection with the release of hazardous 

substances); MINN. STAT. §§ 115B.05, 115B.14 (allowing recovery for personal injury, lost profits, diminution in 

value to property and other damages associated with the release of hazardous substances as well as reasonable costs 

and attorneys fees); WASH. REV. CODE § 70.105D.080 (allowing recovery of expenses and reasonable attorneys fees 

in connection with cost recovery actions). 

87 See 42 U.S.C. § 9601(14) (defining “hazardous substance”). 

88 See id. See also Klass, supra note 78, at 937 & n.139 (discussing CERCLA’s petroleum exclusion). 

89 See M. STUART MADDEN & GERALD W. BOSTON, LAW OF ENVIRONMENTAL AND TOXIC TORTS 627-28 (3rd ed. 

2005) (discussing lack of CERCLA coverage for useful products); infra note 102 and accompanying text (discussing 

efforts to classify stored CO2 as a commodity to avoid application of CERCLA and other environmental laws). 
16

and the nature of the conduct that could form the basis for recovery. Congress was particularly 

concerned with “orphan sites” where the property was subject to significant contamination but 

those companies or individuals responsible for the contamination were long gone (through death, 

dissolution, or bankruptcy).90 Congress thus imposed liability on current owners of property 

even if they did not “cause” the harm and also created the “Superfund,” a federal trust account 

funded through taxes on the chemical industry, to provide funding for cleanups.91 Congress also 

provided that the statute of limitations for cost recovery actions under CERCLA does not even 

begin to run until a cleanup begins, thus eliminating that defense for most potential defendants.92

There are some obvious differences and similarities between the goals of CERCLA and 

the realities of a CCS regulatory regime. First, there will undoubtedly be many more safeguards 

in place in connection with the injection and storage of CO2 than there were with regard to the 

handling and disposal of hazardous substances in the decades prior to CERCLA. Thus, there 

may be no immediate concerns with regard to orphan sites. On the other hand, CCS operators 

envision storing CO2 for hundreds of years, which means that harm may not occur until long 

after the original operators are gone. Likewise, even if regulatory safeguards are created, 

unforeseen long-term problems associated with the storage CO2 in these amounts raises 

significant uncertainty with regard to the success of any regulatory structure. 

In sum, CERCLA is probably a crude tool to apply directly to CCS operators, particularly 

in light of the fact that CO2 is not inherently the type of “hazardous substance” Congress 

envisioned when it enacted CERCLA. Nevertheless, a federal liability statute tailored to CCS 

that includes some of the signature elements of CERCLA (creation of a national fund, a private 

cause of action, retroactive, strict, joint, and several liability, and perhaps a limitations period 

tied to cleanup) should not be dismissed out of hand. If the CERCLA liability model were 

applied to the long-term storage of CO2, public and private actors that suffer injury would be 

able to take advantage of strong liability and funding provisions to facilitate remediation and to 

provide compensation for public and private harm. 

 

2. RCRA 

The Resource Conservation and Recovery Act (“RCRA”)93 was enacted in 1976 to 

provide, among other things, a comprehensive “cradle-to-grave” regulatory system for 

identifying, listing, and tracking hazardous wastes; setting standards for the generation, handling, 

 

90 See PERCIVAL, supra note 84, at 429-30 (discussing “orphan” shares under CERCLA); Klass, supra note 78, at 

926-27 (discussing legislative history of CERCLA which justified “the need for federal legislation to address what 

was seen as a major crisis of abandoned hazardous waste facilities.”). 

91 See MADDEN & BOSTON, supra note 89, at 622 (discussing creation of Superfund). See also supra notes 77-78 

and accompanying text. 

92 See 42 U.S.C. § 9613(g)(2) (statute of limitations for CERCLA). By contrast, state common law claims for relief 

such as nuisance, negligence, trespass, or strict liability generally are subject to state statutes of limitation that begin 

to run with the defendant knew or should have known of the harm to the property, which is often long before a 

cleanup begins on the property. See infra notes 143-150 and accompanying text (discussing statutes of limitation for 

common law claims). 

93 42 U.S.C. §§ 42 U.S.C. §§ 6901-6992k. RCRA is sometimes also referred to as the Solid Waste Disposal Act, the 

name of the federal law governing solid waste issues prior to the RCRA amendments to that Act in 1976. RCRA 

was substantially revised in 1984 by the Hazardous and Solid Waste Amendments. See PERCIVAL ET AL., supra note 

84, at 317. 
17

storage, and disposal of hazardous wastes; and assisting states with the management of solid 

wastes from active facilities.94 Section 7002 of RCRA authorizes suits by any person to restrain 

anyone who has contributed or is contributing to the past or present handling of any solid or 

hazardous waste that may present an imminent and substantial endangerment to human health or 

the environment.95 Such suits are not authorized until the potential plaintiff provides 90 days 

notice of the suit to the defendant, the EPA, and the state in which the alleged violation occurs; 

and are not authorized if EPA is already “diligently prosecuting” an action involving the alleged 

endangerment or the defendant is already engaged in an EPA-approved cleanup.96 

Under RCRA, private parties can use Section 7002 to obtain injunctive relief to address 

contamination as well as attorneys’ fees and expert costs resulting from the disposal of solid or 

hazardous wastes.97 In such a suit, the plaintiff need not establish an emergency situation but 

only that there is a reasonable prospect of potentially serious harm.98 Relief can include an order 

that the defendant is responsible for site investigation, monitoring, testing costs, cleanup costs 

and an order barring further endangerment but does not include money damages, such as the 

plaintiff’s past cleanup costs.99 

RCRA’s provisions thus may provide liability for harm arising from the long-term 

storage of CO2 if stored CO2 is determined to be a solid or a hazardous waste and may also

impose stringent handling, storage, and disposal requirements on the CCS process. RCRA 

defines solid waste as including “any garbage, refuse, sludge from a waste treatment plant, water 

supply treatment plant, or air pollution control facility and other discarded material, including 

solid, liquid, semisolid or contained gaseous materials, resulting from industrial, commercial, 

mining, and agricultural operations, and from community activities.”100 This definition likely 

includes stored CO2 in connection with CCS operations because the CO2 is arguably “discarded 

material,” is in “gaseous” or “liquid” form, and results from industrial or commercial activities. 

It is possible that EPA will exclude CO2 from the definition of solid waste (as it has done for 

domestic sewage, certain mining wastes, and certain nuclear materials covered by other laws), or 

that the stored CO2 can qualify for a recycling exemption if it is seen as being stored for later use 

in enhanced oil recovery operations or for other purposes.101 Likewise, there has been some 

effort within the industry to encourage Congress, federal agencies, and states to classify CO2 as a 

“commodity,” thus avoiding a classification as a “waste” and bringing it outside the scope of 

RCRA.102 Without such actions by EPA, however, it is likely that stored CO2 meets the 

definition of a solid waste. 

 

94 See PERCIVAL ET AL., supra note 84, at 319-31 (discussing RCRA’s requirements). 

95 42 U.S.C. § 6972(a). 

96 See 42 U.S.C. § 6972(b)(2). 

97 See 42 U.S.C. § 6972(e) (authorizing award of attorneys fees and expert fees to prevailing party). 

98 See Maine People’s Alliance v. Mallinckrodt, Inc., 471 F.3d 277 (1st Cir. 2006) (noting the courts have liberally 

construed the term “imminent and substantial endangerment” to include a reasonable prospect of future harm). 

99 See Mehrig v. KFC Western, Inc., 516 U.S. 479 (1996) (CERCLA, not RCRA provides framework for past 

recovery of cleanup costs). 

100 See 42 U.S.C. § 6903(27). 

101 See PERCIVAL, supra note 84, at 329-31 (discussing RCRA solid wastes and exclusions from the definition of 

solid waste); Moore, supra note 8, at 471-72 (discussing same in context of stored CO2 and noting that EPA and the 

courts have determined that injected CO2 does not qualify for the natural gas exemption to RCRA). 

102 See, e.g., Kipp Coddington & Bob Reynolds, Carbon Dioxide Poised for a Comeback, AMERICAN COAL, Issue 2, 

at 58-59 (American Coal Council 2006) (discussing what “label” to place on CO2 stored or injected for hydrocarbon 
18

Hazardous waste is defined as a subset of solid waste that: (1) exhibits a hazardous 

characteristic (such characteristics includes ignitability, corrosivity, reactivity, and toxicity); (2) 

is a “listed” hazardous waste meaning EPA has placed it on a list of hazardous wastes; (3) is a 

waste mixed with a listed waste (“mixture rule”); or (4) is a waste “derived from” a listed waste 

(“derived from rule”).103 CO2 is not a listed hazardous waste and it seems unlikely that CO2

alone would be considered a hazardous waste, although co-injection with other waste stream 

constituents (e.g. hydrogen sulfide (H2S) could cause it to be defined so. It is also possible EPA 

would exclude stored CO2 from the definition of hazardous waste, as it has done with incinerator 

ash and, more applicably, for wastes produced during the exploration, development, and 

production of crude oil, natural gas, and geothermal energy.104 

Although there remains significant regulatory uncertainty with regard to the status of 

stored CO2 under RCRA, without specific action by Congress or EPA it is likely CO2 is at least a 

solid waste under RCRA, and if injected in a mixed stream with listed (and non-exempted) 

contaminants,105 potentially a hazardous waste. If that classification is accurate, then Section 

7002 of RCRA provides a right of action for injunctive relief to compel the remediation of any 

migration or release of stored CO2 that presents an imminent and substantial endangerment to 

human health and the environment.106 Notably, RCRA has been used successfully by plaintiffs 

where the disposal that caused the endangerment happened years or decades earlier; it is the 

present nature of the harm rather than the disposal that matters.107 As a result, RCRA is a 

potential vehicle for establishing liability associated with harm to human health and the 

environment resulting from the long-term storage of CO2. 

B. Recovery for Harm under State Law 

In many ways, in comparison to federal environmental statutes, state law, and particularly 

state common law, has the potential to provide non-federal actors more comprehensive relief 

from harm related to the long-term storage of CO2, but also is at most risk of preemption by any 

forthcoming federal regulatory framework on CCS.108 Unlike the federal environmental 

 

recovery for purposes of environmental liabilities). See also Kipp Coddington, A Model CCS Code: Establishing 

the Regulatory Framework & Incentives to Enable Technology Deployment, Conference Proceedings, at 7-8 

(proposing model federal legislation that would create a federal insurance program for CCS but requiring that states 

define CO2 as a “commodity” and not a “waste” or a “pollutant” in order to participate in the federal program); 

IOGCC, supra note 8, at 32 (proposing model regulation stating that “carbon dioxide is a valuable commodity to the

citizens of the state,” thus potentially undermining protection under federal environmental laws). 

103 See 42 U.S.C. § 6904(5); PERCIVAL ET AL., supra note 84, at 341-45 (discussing hazardous wastes). 

104 See PERCIVAL ET AL., supra note 84, at 330-31, 347 (discussing and listing EPA exclusion of certain wastes from 

definition of solid waste or hazardous waste); Regulatory Determination for Oil and Gas and Geothermal

Exploration, Development and Production Wastes, 53 Fed. Reg. 25,446, 25,447 (July 6, 1988). H2S is also 

exempted under this provision. 

105 Under current regulation, a CO2 and H2S stream from a hydrocarbon associated project—where the H2S is an 

exempted waste—would be treated differently than the same stream from an industrial project injecting into a saline 

formation. 

106 See 42 U.S.C. § 7003. 

107 See Main People’s Alliance v. Mallinckrodt, Inc., 471 F.3d 277 (1st Cir. 2006); City of Toledo v. Beazer 

Materials & Services, Inc., 833 F. Supp. 646 (N.D. Ohio 1993); Gache v. Town of Harrison, 813 F. Supp. 1037 

(S.D.N.Y. 1993). 

108 See infra Part III.B (discussing federal preemption of state law). 
19

statutes, which either do not give states or private parties the right to seek monetary recovery or, 

in the case of CERCLA, allow only for recovery of response costs, the state common law claims 

discussed below are available to private parties, local governments, and states to recover for a 

fuller range of harms associated with leakage from stored CO2. This means that the common law 

may play a significant role in creating liability for the long-term storage of CO2. At the same 

time, however, it is state common law that is most vulnerable to arguments by industry or federal 

regulators that Congress should preempt the availability of such claims through federal 

legislation.109 The potential claims of trespass, nuisance, and strict liability, along with potential 

damages and statutes of limitation, are discussed below, followed by a discussion in Part III of 

related federal preemption issues. 

While these claims do not constitute the universe of potential state law claims that could 

result in liability associated with the long-term storage of CO2, we focus on these claims because 

they provide potentially the broadest scope of relief and will significantly affect CCS project 

siting and technology deployment. Not only do these claims allow the possibility of monetary 

relief (damages for harm) and injunctive relief (an order to cease storage operations or remediate 

pollution) but they also need not be based on arguments that the defendant breached a duty of 

care (negligence) or violated a statute or permit (negligence per se). As a result, in the absence 

of preemption by federal or state statute, the common law claims discussed below provide a basis 

for liability that is independent of the safety and environmental protection standards that may be 

set by Congress, state regulators, or administrative agencies. In the initial years of CCS project 

deployment, such claims could affect decisions on project siting and risk management. 

 

 1. Property rights, fugitive resources, and trespass 

 As far back as the middle of the 19th century, there have disputes over who owns 

subsurface oil and gas, when interference with oil and gas constitutes a trespass, and who owns 

oil and gas that has been recovered and then re-injected into the subsurface for storage or 

enhanced oil recovery purposes.110 The body of common law that had developed around these 

issues forms a potential basis of liability for the long-term storage of CO2.

111 While state and 

federal statutes and regulations will almost certainly create a regulatory system governing these 

issues, this system will be against a backdrop of the common law, which will inevitably be put to 

use in interpreting the statutes and filling in the “spaces” within the statutes. 

 In the early days, courts found it difficult to apply traditional ideas of ownership to 

substances that could not be seen from the surface and moved underground on their own accord. 

As a result, early courts often drew analogies to legal doctrines governing ownership of water, 

wild animals, and other “fugitive resources.”112 This resulted in a body of case law which held 

 

109 Id.

110 A “trespass” is generally defined as a physical and unauthorized invasion of the property of another where the 

entry is either intended by the defendant, caused by the defendant’s recklessness or negligence, or the result of the 

defendant’s carrying on an ultrahazardous activity. See HENDERSON ET AL., THE TORTS PROCESS 380-81 (2003). 

111 For a more detailed discussion of the property rights associated with injected gas in the context geologic storage 

of CO2 see Mark A. de Figueiredo, Property Interests and Liability of Geologic Carbon Dioxide Storage, in

CARBON CAPTURE AND SEQUESTRATION, INTEGRATING TECHNOLOGY, MONITORING AND REGULATION 243 

(Elizabeth J. Wilson & David Gerard eds. 2007). 

112 See OWEN L. ANDERSON ET AL., HEMMINGWAY OIL AND GAS LAW AND TAXATION 29-30 (4th ed. 2004). 
20

that a landowner did not own oil and gas located beneath her land until it was reduced to 

“possession.” Such law also held that an owner lost title to oil or gas if it was re-injected (placed 

back “into the wild”) for storage purposes and that the owner was not liable for trespass of that 

oil or gas on neighboring property because of the lack of ownership.113 This denied the 

landowner any protectable property interest in oil or gas being drained to other tracts and also 

discouraged the use of underground storage reservoirs as a safe and economic means of holding 

oil and gas after production. As stakeholders and courts developed more sophisticated 

knowledge about the movement of oil and gas, most courts rejected the analogy to wild animals 

and held that once previously extracted oil or gas is stored in defined underground reservoirs, 

title to the oil or gas is not lost and remains with the person or company placing the oil or gas in 

storage.114

 Once that shift occurred, the question arose under what circumstances the owner of reinjected oil or gas would be liable for trespass or other tort liability if the oil or gas migrated and 

interfered with neighboring property or persons. Generally, if substances injected into a 

reservoir for storage or for enhanced oil recovery cause damage to neighboring property, the 

injector will be liable. In some cases, thought, courts have found that a trespass in the absence of 

damage is not actionable and that a trespass is not actionable where public policy favors the 

injection.115 

 The cases refusing to find a trespass based on public policy favoring injection of dry gas 

or salt water for enhanced oil recovery are particularly instructive. For instance, the Alabama 

Supreme Court in 1998 reversed a $27 million jury verdict in favor of the plaintiffs who had 

claimed that the defendant wrongfully injected dry gas into the ground that migrated onto the 

plaintiffs’ property and allegedly drained the natural gas from their property.116 The supreme 

court held that there was no actionable trespass because the defendants had injected the dry gas 

to obtain secondary recovery of oil and gas resources within an area the state oil and gas board 

had approved as “unitized” for oil and gas recovery.117 The court found that state public policy 

supported unitization of areas for oil and gas recovery and also supported secondary recovery to 

promote the efficient collection of oil and gas, prevent waste, and avoid the drilling of 

unnecessary wells.118 

 

113 Id. See also Hammonds v. Central Kentucky Natural Gas Co., 75 S.W.2d 204 (Ky. Ct. App. 1934) (no trespass 

claim because owner of gas lost title to gas once it was injected into the subsurface). 

114 See, e.g., Texas American Energy Corp. v. Citizens Fidelity Bank & Trust, 736 S.W.2d 25 (Tex. 1987) 

(overruling Hammonds, discussing limitation of analogy to wild animals, and citing cases in other jurisdictions that 

had rejected Hammonds); Elizabeth Wilson & Mark A. de Figueiredo, Geologic Carbon Dioxide Sequestration: An 

Analysis of Subsurface Property Law, 36 ELR 10114, 10121 (Feb. 2006) (noting that Hammonds is not currently 

followed in the United States, that gas companies retain ownership of injected gas, and that trespass can occur if gas 

migrates). 

115 See West Edmonds Salt Water Disposal Ass’n v. Rosencrans, 226 P.2d 965 (Okla. 1950) (injector not liable for 

damages or injunctive relief for injection of salt water into existing salt water formation that extended under 

neighboring property because neighbor could not establish damage); R.R. Comm’n v. Manziel, 361 S.W.2d 560 

(Tex. 1962) (no liability for authorized injection into adjoining subsurface property because of public policy 

favoring injection of salt water for secondary recovery of oil); Phillips Petroleum Co. v. Stryker, 723 So. 2d 585 

(Ala. 1998); ANDERSON ET AL., supra note 112, at 160. 

116 Phillips Petroleum Co., 723 So. 2d at 591. 

117 Id. at 589-91. 

118 Id. at 588. 
21

 

 The development of CCS will involve the injection of CO2 into the subsurface on a scale 

that dwarfs today’s current injection of CO2 or other substances for storage or enhanced oil 

recovery purposes. As a matter of common law though, courts will be forced to look to the 

precedent created in traditional oil and gas operations and attempt to apply them to a new 

technology on a new scale. Just as courts moved away from the analogies to wild animals as 

public policy began to favor re-injection and storage of oil, gas, and water, courts will be called 

upon to adopt new common law frameworks to address stored CO2. What this will look like 

remains to be seen, but it may be that public policy favoring reduction of greenhouse gas 

emissions might weigh in favor of applying liability sparingly as a common law matter, as has 

been done in the past with traditional oil and gas operations. Nevertheless, in a case of 

significant harm to human health and the environment the sheer volume of injected CO2

associated with CCS may also cause courts to pause before weighing the costs and benefits of 

stored CO2 in the same way as has been done for the injection of CO2 in connection with 

traditional oil and gas recovery. 

 2. Nuisance 

 While the trespass claims discussed above represent one classic, property-based tort, 

nuisance law provides another means for holders of property rights to recover for harm resulting 

from the long-term storage of CO2. Nuisance law is based on the principle that a defendant may 

not engage in activity that unreasonably interferes with public rights or a private party’s interest 

in land. Nuisance law underlies much of environmental law, and has been used by private and 

public parties to obtain injunctive and monetary relief from air, water, soil, and noise pollution 

resulting from industrial and commercial activities such as landfills, sewage treatment plants, oil 

refineries, quarries and the like.119 

There are two types of nuisance: private nuisance and public nuisance. A public 

nuisance is an “unreasonable interference with a right common to the general public” and may 

only be asserted by a public body (such as a state or local government) or by a private party who 

has suffered a unique or special injury that differentiates his or her harm from that suffered by 

the general public.120 A private nuisance is a “nontrespassory invasion of another’s interest in 

the private use and enjoyment of land” and may be brought by anyone with an ownership or 

possessory interest in land.121 Generally, for an activity to be a nuisance, the invasion of the 

private use and enjoyment of land must be (1) intentional and unreasonable or (2) unintentional 

but negligence, reckless, or subject to strict liability because it is an abnormally dangerous 

activity.122 An invasion is unreasonable if the gravity of harm outweighs the utility of the actor’s 

conduct or the harm caused by the conduct is serious and the financial burden of compensating 

 

119 See WILLIAM H. RODGERS, JR., ENVIRONMENTAL LAW § 2.1 at 112-113, 114-15 (2d ed. West 1994) (stating that 

to “a surprising degree, the legal history of the environment has been written by nuisance law” and detailing the 

various types of nuisance actions that have been brought in connection with harm arising from various industrial and 

commercial activities). 

120 See RESTATEMENT (SECOND) OF TORTS §§ 821B, 821C. 

121 See RESTATEMENT (SECOND) OF TORTS §§ 821D-828 (setting forth principles of private nuisance). 

122 See RESTATEMENT (SECOND) OF TORTS § 822. For a discussion of activities that are considered “abnormally 

dangerous,” see infra notes 130-137, and accompanying text. 
22

for this and similar harm would not be unreasonable.123 Once a nuisance is established, the court 

balances the benefits of the alleged nuisance activity, the harm to the plaintiff and others, and 

other equitable factors to determine whether the defendant should pay damages to the plaintiff or 

whether the plaintiff is entitled to completely enjoin the conduct causing the nuisance.124

Notably, even lawful operations that result in harm to public resources or private property 

can be enjoined or subject to damages based on nuisance. In 1998, a Washington state court 

found that a pulp mill operating lawfully pursuant to a wastewater discharge permit was liable 

under a private nuisance theory for $2.5 million in damages to nearby potato farmers using 

irrigation water from the aquifer contaminated by the defendant’s operations.125 Also in 1998, 

the Court of Appeals for the Ninth Circuit upheld a lower court injunction against a metal tube 

manufacturer under a public nuisance theory where the defendant’s dumping of hazardous 

chemicals resulted in contaminating a subterranean aquifer.126

In the context of the long-term storage of CO2, migrating or leaking CO2 that harms 

nearby soil, surface water, groundwater, mineral, or other resources, or interferes with human 

health could constitute either a public or private nuisance. This could result in an injunction 

requiring remediation of any harm caused by CO2 or preventing the continued storage of CO2. It 

could also result in an award of monetary damages for harm associated with the release. Such 

injunctive or monetary relief could be awarded under a nuisance theory even if the CCS project 

or storage area was in full compliance with all federal or state permits.127 In determining 

whether a nuisance exists and the appropriate remedy, a court may balance the harm to the 

plaintiff against the benefits of stored CO2. Under such a balancing, it may be that the public 

interest associated with storing CO2 would be significant if the technology is seen as playing a 

significant role in efforts to reverse climate change. On the other hand, a court could also find 

that it is more equitable for the CO2 owner or operator to bear the risks and at least pay damages 

for the harm, even if the stored CO2 is allowed to remain.128 

In sum, harm to human health, the environment, or private property from the migration or 

release of stored CO2 would seem to fit fairly easily within a public or private nuisance 

framework, barring any Congressional actions to preempt such claims as part of federal 

 

123 See RESTATEMENT (SECOND) OF TORTS §§ 826-27. 

124 See RESTATEMENT (SECOND) OF TORTS § 936 (setting forth balancing factors for injunctions); DAN B. DOBBS,

LAW OF REMEDIES § 5.7(2) (discussing judicial discretion in balancing benefits and harms in nuisance cases). 

125 Tiegs v. Watts, 954 P.2d 877, 883 (Wash. 1998) (stating that pollution caused by the defendant constituted a 

nuisance even if the state had approved the discharge). 

126 California v. Campbell, 138 F.3d 772 (9th Cir. 1998) (upholding lower court injunction finding that pollution of 

subterranean percolating waters caused by dumping of hazardous chemicals was a public nuisance). See also Denise 

E. Antolini & Clifford L. Rechtschaffen, Common Law Remedies: A Refresher, in CREATIVE COMMON LAW 

STRATEGIES FOR PROTECTING THE ENVIRONMENT 23-30 (Rechtschaffen & Antolini eds. 2007) (discussing theories 

of private and public nuisance and describing cases in which courts granted injunctions and awarded damages under 

nuisance theories for polluting activities). 

127 See Michal D. Axline, The Limits of Statutory Law and the Wisdom of Common Law, in CREATIVE COMMON 

LAW STRATEGIES FOR PROTECTING THE ENVIRONMENT, supra note 126, at 74-76 (discussing how compliance with

federal or state statutes or permits is not a defense to a common law claim for relief); Alexandra B. Klass, Common 

Law and Federalism in the Age of the Regulatory State, 92 IOWA L. REV. 545, 583 & n.215 (2007) (same). 

128 See Zhang et al., supra note 48. Remediation techniques can use passive techniques, vertical or horizontal 

extraction wells and pumping, though remediation depends largely on the site geology. 
23

legislation governing CCS and the storage of CO2.

129 Even if a nuisance claim for such harm is 

possible, however, most courts would balance carefully the benefits of CCS and CO2 storage 

against the nature of the harm before finding either that a nuisance exists or determining the 

appropriate remedy for the nuisance. 

 

 3. Strict liability for abnormally dangerous activities 

Unlike nuisance doctrine, which requires a balancing of benefits and harms to establish 

liability, the common law doctrine of strict liability allows for liability even where the defendant 

did not intend to interfere with a legally protected interest or did not act unreasonably or breach 

any duty of care in causing the harm.130 Instead, the justification for imposing liability is that 

where the defendant has engaged in an activity for profit that causes harm, the defendant is in the 

best position to bear the loss under principles of justice.131 

In most jurisdictions, a defendant is strictly liable for harm to public health or the 

environment under either the doctrine of Rylands v. Fletcher or for activities that are deemed 

“abnormally dangerous” under Sections 519 and 520 of the Restatement (Second) of Torts.132 

Under Rylands v. Fletcher, a defendant is liable if it engages in a “non-natural” or “abnormal” 

use of the land which results in harm.133 Under the Restatement, an activity is “abnormally 

dangerous” and thus subject to strict liability based on a judicial balancing of the following 

factors: (1) the existence of a high degree of risk of some harm to the person, chattel, or lands of 

others; (2) likelihood that the harm that will result from the activity will be great; (3) inability to 

eliminate the risk of harm by the exercise of reasonable care; (4) the extent to which the activity 

is not a matter of common usage; (5) the inappropriateness of the activity to the place where it is 

carried on; and (6) the extent to which the value of the activity to the community is outweighed 

by its dangerous attributes.134 

Courts have held defendants strictly liable for harm to public health and the environment 

under both Rylands and the Restatement for a broad range of activities that include the release of 

petroleum or oil that contaminated groundwater, seeping salt water from an oil and gas well that 

contaminated a water supply, the release of toxic and hazardous wastes from industrial 

operations and disposal facilities, the release of PCBs from a natural gas pipeline that 

contaminated neighboring property, the release of pollutants during the blowout of an oil well 

during drilling, and pollution of water wells by nearby oil wells that percolated on the 

 

129 See infra Part III.B. 

130 See W. PAGE KEETON ET AL., PROSSER & KEETON ON THE LAW OF TORTS § 75 at 534 (5th ed. 1984). 

131 See Klass, supra note 78, at 907 (citing PROSSER & KEETON, supra note 130, § 75, at 536; Mark Geistfeld, 

Should Enterprise Liability Replace the Rule of Strict Liability for Abnormally Dangerous Activities, 45 UCLA L.

REV. 611 (1998); William K. Jones, Strict Liability for Hazardous Enterprises, 92 COLUM. L. REV. 1705, 1712 

(1992); Virginia E. Nolan & Edmund Ursin, The Revitalization of Hazardous Activity Strict Liability, 65 N.C. L.

REV. 257, 297 (1987). 

132 See Rylands v. Fletcher, L.R. 3 H.L. 330 (1868); RESTATEMENT (SECOND) OF TORTS §§ 519-20; Klass, supra

note 78, at 904 (discussing strict liability under Rylands and the Restatement). 

133 Rylands, L.R. 3 H.L. 330 (1868); PROSSER & KEETON, supra note 130, at 545-46 (discussing Rylands case). 

134 RESTATEMENT (SECOND) OF TORTS § 520. See also RESTATEMENT (THIRD) OF TORTS § 20 (Proposed Final Draft 

No. 1 2005) (proposing to revise the Restatement of Torts on abnormally dangerous activities to provide that an 

activity is abnormally dangerous if it (1) creates a foreseeable and highly significant risk of physical harm even 

when reasonable care is exercised by all actors and (2) the activity is not a matter of common usage).
24

property.135 In all, putting aside those jurisdictions that do not recognize strict liability (or only 

in narrow circumstances), twenty-one out of twenty-seven jurisdictions that have squarely 

considered the issue have applied the doctrine of strict liability to activities resulting in 

environmental contamination.136

Whether courts will find the long-term storage of CO2 associated with CCS to be subject 

to strict liability remains to be seen and, given the significant geologic differences, will likely 

vary by region or state. Is the storage of large quantities of CO2 a “natural” use of the land, a 

“matter of common usage,” or “appropriate” for its location?137 It may not be now, but do the 

demands of addressing climate change alter that equation? Is the answer different in Texas, 

where injection of CO2 is more common in connection with enhanced oil recovery operations, 

than it is in eastern or Midwestern states? In terms of the value to the community, the value of 

stored CO2 may be significant if it has a measurable impact on reducing greenhouse gas 

emissions. 

As may be evident from these questions, different courts in different jurisdictions may 

reach widely varying results on whether harm from stored CO2 is subject to strict liability. This 

is true, however, for most industrial and commercial activities around the country, with different 

laws applying in different jurisdictions. While there is an argument that CCS and the large-scale 

storage of CO2 should be subject to a uniform standard of liability, there is perhaps a more 

compelling argument that operators should recognize the existence of potential strict liability in 

multiple jurisdictions, and conduct their operations accordingly but with an eye toward reducing 

the downside risk consistent with the proposals in Parts IV and V. 

 4. Damages 

 Under any of the trespass, nuisance and strict liability theories discussed above, parties 

responsible for the long-term storage of CO2 may be liable for remediation costs, diminution in 

value to private or public property (i.e., stigma damages), lost profits, personal injury, and other 

damages flowing from harm to human health and the environment. In recent years, there have 

been significant lawsuits against gasoline producers over contamination from the gasoline 

additive methyl tertiary butyl ether (“MTBE”) which has contaminated numerous municipal and 

state water supplies. The South Tahoe Public Utility District sued several major gasoline 

companies in 1998 after MTBE pollution forced it to close numerous of its drinking water wells 

in California and, after a jury trial, the defendant companies agreed to pay $69 million to 

remediate the contaminated wells.138 New Hampshire filed a similar suit in 2003 and numerous 

other public and private parties are also seeking recovery for harm under various common law 

theories including nuisance, negligence, and strict liability.139 These suits show the willingness 

of courts to find liability under state law and uphold significant damage awards associated with 

widespread environmental contamination. 

 

135 See Klass, supra note 78, at 942-61 (discussing cases). 

136 Id. at 957-61. 

137 See supra notes 132-134, and accompanying text. 

138 Tyler Cunningham, Oil Companies Settle Lawsuit over MTBE in Lake Tahoe—the Long Running Case Will Not 

Mark a Legal Precedent Because of the Deal, but Will Surely Have a Wide Impact, S.F. DAILY J. (Aug. 6, 2002). 

139 See Klass, supra note 127, at 596-97 (discussing MTBE lawsuits); Moore, supra note 8, at 482-83 (discussing 

MTBE suits and potential application to contamination from storage of CO2). 
25

Even beyond these high-profile suits, courts are more willing today to award “stigma” 

damages arising from property contamination in addition to cleanup costs. Environmental 

“stigma” is defined as an adverse impact on the value of a property based on the market’s 

perception that the property poses an environmental risk.140 Thus, stigma can attach not only to 

property that is currently contaminated, but also to property that has a risk of future 

contamination or property that has been remediated but is still perceived as posing a risk of 

harm.141 Although some jurisdictions require some minimal physical impact sufficient to 

interfere with the owner’s use of the land for stigma damages to be recoverable, other 

jurisdictions recognize that the value of property can decrease through “stigma” simply by being 

near contamination.142 Thus, in most jurisdictions, a subsurface invasion of CO2 or a release of 

CO2 to the surface that interferes with use of the property will support stigma damages while in 

others, any significant release of CO2 near the property may suffice so long as the release 

constitutes a trespass, nuisance, abnormally dangerous activity, or other actionable tort. 

5. Statutes of Limitation, Repose, and Revival 

For all common law claims, defendants can take advantage of state statutes of limitation 

which limit the time (often between two and six years) within which a plaintiff may bring a 

lawsuit for injuries. Because of the long time-frame associated with the storage of CO2, 

questions will inevitably arise as to when various causes of action will “accrue,” and cause the 

limitations period to start to run. In particular, an issue may arise over whether a trespass, 

nuisance, or strict liability claim associated with stored CO2 is “continuing,” thus allowing the 

plaintiff to maintain an action or successive actions until the contamination is remediated.143 

This issue of whether the wrongdoing is “continuing” arises frequently in cases of environmental 

contamination, where the illegal conduct ceased decades ago but contamination continues to 

move through the soil and groundwater, resulting in continuing harm. Thus, is the triggering 

event the defendant’s wrongful conduct or it the harm caused to the plaintiff that may continue 

decades after the wrongful conduct ceases? Many courts and commentators have argued that 

proof of continuing harm supports a claim of continuing trespass which prevents the statute of 

 

140 See UNIFORM STANDARDS OF PROFESSIONAL APPRAISAL PRACTICE, Advisory Op. 9, at 143-45 (Appraisal 

Standards Bd. 2003). 

141 See Klass, supra note 127, at 588-90. See also Dealers Mfg. Co. v. County of Anoka, 615 N.W.2d 76, 77 n.1 

(Minn. 2000) (environmental risk resulting in stigma damages may be due to fear of potential liability for cleanup 

costs, potential liability to third parties affected by existing or prior contamination, or concerns regarding the ability 

to obtain financing for the property) (citing Peter J. Patchin, Valuation of Contaminated Properties, 56 APPRAISAL J. 

7, 7-8 (1988)). 

142 Compare Chance v. BP Chemicals, 670 N.E.2d 985, 993 (Ohio 1996) (requiring some type of physical damage 

or interference with use to recover stigma damages and holding that a trespass to subterranean rock strata by 

deepwell injectate is not sufficient) with Dealers Mfg., 615 N.W.2d at 79-80 (finding that stigma may exist for a 

property that is merely in proximity to property that is contaminated because “of the heavy burden on the value of 

the property due to the perception of risk of liability, or government imposed restrictions on the use or transferability 

of the property, among other concerns.”). 

143 See RESTATEMENT (SECOND) OF TORTS § 899, cmt. d (stating that a continuing trespass “confers on the possessor 

of the land an option to maintain a succession of actions based on a theory of continuing trespass, or to treat the 

continuing of the thing on the land as an aggravation of the original trespass.”); MADDEN & BOSTON, supra note 89, 

at 29-31 (discussing the arguments surrounding the relationship between continuing trespass and statutes of 

limitation). 
26

limitations from expiring until the defendant has abated the harm.144 Other courts, however, 

have focused on the conduct as the triggering event, rather than the harm, meaning that the 

limitations period runs from when the plaintiff knew or should have known of the last wrongful 

act, regardless of whether the contamination continues far into the future.145 

In the context of CCS, if the wrongful conduct is the improper selection and operation of 

a storage area or the improper injection of CO2, it may take years or decades for sufficient CO2

to migrate and cause harm. Even though the statute of limitations does not begin to run in most 

jurisdictions until the plaintiff knew or should have known of the wrongful conduct and its 

impact, it is still possible that the plaintiff might know of the wrongful conduct before the impact 

on the plaintiff or its property is significant enough to justify bringing a suit. In such a case, 

whether the wrong is deemed to be continuing is critical to the scope of the defendant’s liability. 

If courts determine that the limitations period begins to run when the plaintiff knew or should 

have known that the CCS operator selected an improper storage site, the CCS operator’s liability 

will be quite limited in duration so long as the CCS does not cause immediate or significant 

harm. If, however, courts determine that the limitations period continues to run until all harm is 

remediated, CCS operator liability has the potential to continue long into the future. In all of 

these cases, of course, the plaintiff must establish causation, which can be extremely difficult in 

cases where CO2 or contaminants react with native rock and potentially affect groundwater in a 

manner that is difficult to observe and document. 

A defense related to a statute of limitations is a statute of repose. While a statute of 

limitations bars the plaintiff’s action at a specified time period after the cause of action accrues 

(usually from the plaintiff’s knowledge or constructive knowledge of her cause of action), a 

statute of repose bars the plaintiff from bringing an action after a specified number of years past 

a particular event, such as the date of the sale of a product or the date of improvements to real 

property.146 As a result, if a statute of repose applies, a cause of action may be extinguished 

before the plaintiff’s claim ever accrues, because the required number of years has run from the 

stated event, even if the plaintiff has not yet suffered harm or is not yet aware of the harm.147 

Many states have created statutes of repose in connection with improvements to real property, 

resulting in the extinguishment of claims against asbestos manufacturers or other manufacturers 

 

144 See Nieman v. NLO, Inc. 108 F.3d 1546 (6th Cir. 1997) (holding that under Ohio law, the statute of limitations 

does not expire because the time period has elapsed from the defendant’s last affirmative act of wrongdoing but 

instead continues based on proof of continuing damages); Jacques v. Pioneer Plastics, Inc. 676 A.2d 504 (Me. 1996) 

(focusing on the hazardous material that remained on the site rather than the dumping itself in deciding whether the 

limitations period had run); Hoery v. United States, 64 P.3d 214 (2003) (holding that under Colorado law, 

continuing migration of contaminants and ongoing presence of contaminates constitute a continuing trespass and 

continuing nuisance rendering the plaintiff’s claim timely); RESTATEMENT (SECOND) OF TORTS §§ 161(1) and 899 

(discussing continuing nature of trespass when defendant fails to remove a thing from land that was wrongfully 

placed there). 

145 See, e.g., Carpenter v. Texaco, 646 N.E.2d 398 (Mass. 1995) (finding plaintiffs’ claim for damage due to 

contamination from leaking petroleum tank was time-barred because they failed to sue within three years of the last 

instance of unlawful conduct and a continuing nuisance or trespass must be based on “recurring tortious or unlawful 

conduct, and is not established by the continuing of harmed caused by previous but terminated tortious or unlawful 

conduct.”). 

146 See MADDEN & BOSTON, supra note 89, at 939 (comparing statutes of limitation and statutes of repose). 

147 Id.
27

of toxic products used in construction.148 The flip side to a statute of repose is a revival statute, 

which resuscitates claims that have already been barred by the statute of limitations. For 

instance, the New York legislature in 1986 enacted a statute to revive expired claims related to 

exposure to certain toxic substances for one year.149

 

In the context of CCS, federal and state legislators can create limitations periods, repose 

periods, or revival periods specific to claims involving stored CO2 if they wish, as Congress has 

done with claims involving hazardous substances under CERCLA,150 and as states have done to 

both protect certain industries in some cases and protect citizens with particular injuries in other 

cases. In light of the unique concerns associated with CCS claims such as potentially long 

latency periods prior to knowledge of harm and the difficulties in observing the movement of 

CCS underground, existing common law principles associated with statutes of limitations may be 

crude tools to govern CCS claims. In the absence of federal or state legislative action on this 

front, however, courts will be left with the task of determining issues associated with the claim 

accrual date, whether the harm is “continuing” for limitations purposes, and whether a state 

statute of repose might apply in the CCS context. This is one area where there is ample common 

law precedent on which to draw but where a legislatively-tailored solution would appear to be 

superior. 

 

C. Conclusion 

 This Part illustrates that there is a significant body of federal and state law that may apply 

to claims for harm associated with the long-term storage of CO2. The challenges of balancing the 

benefits of CCS with the potential risks must be weighed both locally and within the larger 

context of climate change. This structure is not and cannot be a substitute for the adoption of 

carefully tailored state and federal regulation governing all aspects of the development of CCS. 

Such CCS-specific laws can consider the unique features of CCS, create regulatory safeguards to 

guide development, and create a permitting and compliance structure unique to CCS. This does 

not mean, however, that the existing liability framework is of no relevance. These sometimes 

broad and sometimes narrow statutory and common law safeguards are available to serve as an 

additional incentive for project developers to comply with whatever CCS regulations come into 

existence, as well as meet basic common law duties. State and federal legislation specific to 

CCS, discussed in Part III, should leave much of this basic liability framework in place. 

 

 

148 Id. at 940-41 (citing cases and discussing challenges to statutes of repose under state constitutions that contain 

provisions granting citizens a “right to a remedy” or right to access to the courts). 

149 Id. at 942 (citing Hymowitz v. Eli Lilly & Co., 539 N.E.2d 1069 (N.Y. 1969) (upholding constitutionality of 

revival statute)). 

150 See supra note 92 and accompanying text (discussing how CERCLA provides that the statute of limitations for 

recovery of response costs does not even begin to run until the plaintiff begins remediating the property). CERCLA 

creates not only a specific limitations period for cost recovery claims under CERCLA but also imposes a discovery 

rule (for those states that do not have one) on state common law claims for relief. See 42 U.S.C. § 9658 (imposing a 

“federally required commencement date” for state law causes of action defined as the date the plaintiff knew or 

reasonably should have known that the personal injury or property damages were caused or contributed by the 

hazardous substance, pollutant, or contaminant). 
28

III. STATUTORY DEVELOPMENTS, COMPETITION, AND THE SPECTER OF THE “RACE-TO-THE-

 BOTTOM” 

 No federal or state program currently regulates CCS and related storage of CO2, although 

CO2 storage projects may now be permitted pursuant to a March 2007 EPA Guidance 

Memorandum under EPA’s Underground Injection Control (“UIC”) Program created under the 

Safe Drinking Water Act of 1974.151 EPA has begun the process of developing regulations on 

the injection of CO2 under the UIC program.152 Federal and state legislators, however, are 

keenly aware of the importance of defining property rights and tort liability in advance of 

implementing CCS and the long-term storage of CO2. Although little has been enacted thus far, 

recent efforts to do so are instructive and show recognition of the importance of tort liability in 

the development of this new technology. As shown below, much of this legislation attempts to 

significantly limit project operators’ liability for long-term storage of CO2, raising the issue of 

whether a “race-to-the-bottom” mentality may influence the ability of existing laws to provide 

long-term protection for human health and the environment. 

A. Legislative Efforts to Reduce or Eliminate Liability for Harm 

 At both the federal and state levels, there have been efforts to encourage the development 

of CCS through the enactment of significant limitations on liability for harm associated with the 

long-term storage of CO2. For instance, in 2006, the U.S. House of Representatives considered a

bill to authorize and appropriate funds for the FutureGen project153 “to demonstrate the 

feasibility of the commercial application of advanced clean coal energy technology, including 

carbon capture and geological sequestration, for electricity generation.”154 One of the failed 

amendments to that bill was to allow the Secretary of the Department of Energy to “indemnify 

the consortium and its member companies for liability associated with the first-of-a-kind 

sequestration component of the project,” with indemnity extending to any legal liability arising 

out of “the storage or unintentional release, of sequestered emissions.”155 The proposed 

indemnification contained exceptions for gross negligence and intentional misconduct, and 

limited the U.S. Government’s aggregate liability to $500,000,000 for a single incident.156 

In 2006 and 2007, the two state finalists for the FutureGen project, Illinois and Texas, 

were in keen competition for the project which would bring cutting-edge coal research, hundreds 

of jobs, and a new market for local natural resources including but not limited to coal.157 As part 

of that competition, both states began a race to enact legislation to enhance their bids as the host 

 

151 42 U.S.C. § 300h(b)(1) (“SWDA”); 40 C.F.R. § 144.1; EPA Guidance Memorandum, supra note 36. 

152 Patricia Ware, EPA Begins Discussions on Rulemaking for Underground Storage of Carbon Dioxide, DAILY 

ENVT. REP. No. 232, at A-11 (BNA Dec. 4, 2007). 

153 See supra notes 59-63 and accompanying text (discussing FutureGen project and DOE decision in January 2008 

to withdraw support for the project in favor of other commercial CCS projects). 

154 See Energy Research, Development, Demonstration, and Commercial Application Act of 2006, H.R. 5656 

(2006). 

155 Amendment to H.R. 5656 offered by Rep. Costello of Illinois (June 27, 2006). 

156 Id. See also Department of Energy Carbon Capture and Storage Research, Development, and Demonstration Act 

of 2007, H.R. 1933 (April 18, 2007) (bill to amend the Energy Policy Act of 2005 to reauthorize and improve the 

carbon capture and storage research, development, and demonstration program of the Department of Energy). 

157 See supra note 60 and accompanying text. 
29

site, including offering freedom from tort liability through statutory indemnification and transfer 

of property rights in CO2. For instance, Texas enacted legislation in 2006 providing that the state 

would acquire title to carbon dioxide captured by a clean coal process, thus releasing the owner 

of the project from any liability after capture of the CO2.

158 In 2007, additional bills were 

introduced in the Texas legislature to strengthen those indemnification provisions and make clear 

that “once the State of Texas assumes ownership of CO2, the [FutureGen] Alliance will be 

protected from tort liability.”159 The purpose of the indemnity provisions were to move “Texas 

significantly ahead in the national competition for FutureGen because no other state has 

identified a suitable answer to this important question.”160 Illinois for its part attempted to 

provide similar assurances to the Alliance. In 2007, Illinois enacted legislation to offer liability 

protections similar to those enacted in Texas in order to “compete” with Texas and put Illinois 

“on an even playing field.”161 

Specifically, the Illinois legislation provided that if the FutureGen project was located in 

Illinois, Illinois would take title to injected CO2, would obtain at its own expense insurance from 

private carriers against loss from stored CO2 if such a policy was available, and would indemnify 

the FutureGen Operator to the extent liability was not covered by insurance.162 The only limits 

on the state’s indemnity for the Operator’s liability are in cases of intentional or willful 

misconduct by the Operator or if the loss stemmed from the Operator’s failure to comply with 

applicable state or federal laws, rules, or regulations for the carbon capture and storage of the 

sequestered gas.163 The Illinois incentives “package” also included a $17 million direct grant 

from the Illinois Coal Development Fund, an estimated $15 million sales tax exemption on 

materials and equipment purchased through local enterprise zones, and $50 million for belowmarket rate loans through state finance agencies.164

 Despite the fact that DOE has withdrawn its support for the FutureGen project, the state 

legislative activity prior to that withdrawal serves as an example of what is known as the “raceto-the-bottom” phenomenon. As has been discussed in numerous scholarly articles on 

environmental regulation, the initial push for statutes and regulation providing minimal federal 

environmental standards in the 1970s was believed to be necessary to prevent regulatory 

competition among states from undercutting environmental quality.165 This “race-to-the-bottom” 

scenario remains subject to significant debate. Some scholars argue that there is no empirical 

 

158 See TEX. NAT. RES. CODE Ch. 119 (enacted as Tex. H.B. 149 (2006)). 

159 See Press Release, Railroad Commission of Texas, House Energy Committee Unanimously Approves 2007 

FutureGen Legislation (April 11, 2007). 

160 See Press Release, Railroad Commission of Texas, Williams: Legislation Improves Texas Chance to Win

FutureGen (May 16, 2006). 

161 See 20 ILCS 1107 (Clean Coal FutureGen for Illinois Act); See also Kate Clemens, Illinois Senate Passes Bill to 

Help Land FutureGen Plant, THE NEWS-GAZETTE (March 22, 2007). 

162 See 20 ILCS 1107/25. 

163 See 20 ILCS 1107/25(g). 

164 Cook & Bologna, supra note 59 (discussing Illinois legislative incentives and noting that “all the candidate sites 

came with financial inducements from state and local governments.”). 

165 See PERCIVAL ET AL, supra note 84, at 104 (explaining the “race-to-the-bottom” rationale and citing scholarly 

debates on the subject); Kirsten H. Engel, State Environmental Standard-Setting: Is There a “Race and Is It “To The 

Bottom,” 48 HASTINGS L.J. 271, 283 (1997) (stating that the “race-to-the-bottom” in the debate over federal 

environmental standards refers to a lowering of state environmental standards that also results in a lowering in net 

social welfare). 
30

evidence that states will reduce environmental protections to attract business.166 They point to 

state innovation in the environmental protection field that was in place prior to the federalization 

of environmental law in the 1970s and continues more recently in response to the federal 

government’s lack of support for strong environmental protection laws.167 

 Putting aside the validity of this debate with regard to environmental standards in 

general, the “race-to-the-bottom” phenomenon appears to have been at work in the legislative 

efforts by Texas and Illinois to compete for the FutureGen project. In many ways, this is not 

surprising. While states generally set (or fail to set) environmental standards that will cover a 

wide range of industries (the power industry, the auto industry, manufacturing) or environmental 

resources (e.g., air, water, waste) the FutureGen legislation was focused on a specific project that 

would only be built in one of two candidate states. Such a situation cannot help but encourage 

competition to be seen as the most “friendly” forum with regard to a host of issues including 

taxes, land availability, and geography in addition to potential liability. Notably, prior to the 

potential sites being narrowed to those in Illinois and Texas, Kentucky had enacted legislation 

allowing project sponsors to “bypass much of the regulatory process” for siting the facility, so 

that the state would not have “an administrative process that’s seen as burdensome.”168

This type of legislation serves as a caution for the future. If CCS continues to develop, it 

will likely be on a plant-by-plant basis, with some states in intense competition to be selected as 

the site, as was the case with FutureGen. For instance, the current DOE proposal calls for a 

public-private partnership to implement CCS technologies at multiple commercial-scale power 

plants across the country.169 Thus, the state legislative actions to date should encourage federal 

lawmakers to ensure that any regulatory structure governing the long-term storage of CO2

contains standards that act as a floor, rather than a ceiling. As scholars have shown, while some 

states may compete based on the least regulations, others have a history of adopting more 

protective regulations. California currently serves as such as example, acting as leader in 

regulatory efforts to reverse climate change by reducing emissions from automobiles, power 

plants, and other sources of greenhouse gases. Such environmental protection efforts should be 

encouraged. Existing federal environmental statutes that govern the air, water, and hazardous 

waste can act as examples of the federal government setting a floor and allowing states to 

innovate using their regulatory authority and common law.170 Legislators should look to these 

statutes for guidance in enacting CCS legislation. 

 

166 See Richard L. Revesz, The Race to the Bottom and Federal Environmental Regulation: A Response to the 

Critics, 82 MINN. L. REV. 535, 540-42 (1997) (rejecting a “race-to-the-bottom” rationale as a justification for federal 

environmental standards). See also Klass, supra note 127, at 579-84 (discussing recent state efforts to enhance 

environmental protection efforts in the face of the federal government’s failures to do so). 

167 Id. See also Richard L. Revesz, Federalism and Environmental Regulation: A Public Choice Analysis, 115 

HARV. L. REV. 553, 579-85 (2001) (rejecting proposition that the states are not effective bodies to enact and 

implement environmental standards and providing past and current examples). 

168 See Kentucky General Assembly Passes Bill Aimed at Attracting “FutureGen” to the State, GLOBAL POWER 

REPORT (March 30, 2006). 

169 See Steven D. Cook, DOE Pulls Support for FutureGen Project, Will Fund Carbon Capture at Multiple Sites, 39 

ENV. REP. No. 5, p. 200 (Feb. 1, 2008). 

170 See, e.g., William Buzbee, Asymmetrical Regulation: Risk, Preemption, and the Floor/Ceiling Distinction, 82 

N.Y.U. L. REV. 1547 (2007) (arguing that the risks of regulatory failure argue for federal standards setting a 

regulatory floor but not a regulatory ceiling); Robert L. Glicksman, From Cooperative to Inoperative Federalism: 

The Perverse Mutation of Environmental Law and Policy, 41 WAKE FOREST L. REV. 719 (2006) (exploring 
31

Although there has been some recognition of this problem in recent literature, its 

solutions fall short of what may be needed to ensure sufficient compensation for public and 

private harm from the release of CO2. For instance, the “Coalition for Commodity CO2,” has 

prepared model legislation to create a federal insurance program for the long-term storage of 

CO2.

171 The legislation proposes that the federal government require states to create minimum 

standards for the injection and storage of CO2 in order to participate in the federal insurance 

program.172 Beyond requiring those minimum state standards (and it is not clear what types of 

standards would meet the minimum) and creating the federal insurance program, the Coalition 

argues for a limited federal role in CCS regulation, leaving most major requirements and 

standards to the states. The Coalition argues that requiring such minimum state standards for 

participation in the federal insurance program will prevent a race-to-the-bottom while still 

allowing a diversity of state approaches.173 

This model legislation falls short, however, because it also contains as a requirement for 

participation in the federal insurance program that the state define CO2 as a “commodity” rather 

than a “pollutant” or “waste” to avoid “unlimited” and “unfounded” environmental liability for 

states and CCS operators.174 Ultimately, it may make sense for the federal government to tailor a 

liability regime specific to CCS. If not, however, the alternative should not be to require states to 

create a regime that makes it impossible for federal or state environmental pollution laws to 

apply, particularly when the potential impacts of long-term storage of CO2 remain uncertain and 

will continue to remain uncertain for decades. Thus, the potential for a state race-to-the-bottom 

is real, and will likely require significant federal participation in creating substantive standards 

for CCS technology. 

B. Liability and Federal Preemption 

 All of the federal and state CCS legislation introduced and enacted to date recognizes the 

significance of existing liability standards that may underlie the creation of new natural resource 

technologies like CCS to address climate change. CCS will be a significant public/private 

partnership involving major corporate interests and the federal and state governments, and has 

massive start-up costs. Under those circumstances, policymakers are rightly attempting to do 

significant work in advance to allocate rights and determine who will be responsible for 

liabilities associated with CCS projects and the long-term storage of CO2. Nevertheless, there is 

a level of nuance that appeared to be missing from the efforts of Illinois, Texas and their 

respective lawmakers to provide extremely broad indemnity provisions for liability associated 

with the long-term storage of CO2. As new projects emerge, one hopes to see a fuller discussion 

of the risks of CCS and how those risks should be allocated and managed. Releasing the private 

sector partners from as much liability as possible may not be the only answer. 

 

developments in environmental law at federal and state levels and arguing that the federal government has failed to 

fulfill its mandate to protect the environment by its unwillingness to exercise its own power to promote 

environmental protection and also limiting the power of states to combat environmentally destructive activities). 

171 See Coddington, supra note 102. 

172 Id. at 6. 

173 Id. at 5-6. 

174 Id. at 7-8. For a discussion of the impact of classifying CO2 as a “commodity” for purposes of CERCLA and 

RCRA coverage, see supra note 102 and accompanying text. 
32

 Moreover, establishing a liability framework does not end with Congressional or agency 

action enacting statutes and rules on CCS and CO2 storage. Deployment of the first dozen 

projects will provide a real-world experience to identify and manage risks, and to develop a riskbased approach to both liability and funding for potential harm. As discussed in Part V, such an 

approach should ultimately take into account the stage of CO2 storage (more risk during the 

injection and closure period than in post-closure period means more operator contribution to 

pooled funding) as well as the location of CO2 storage (i.e., storage in reservoirs with less 

integrity should be required to meet higher standards and contribute more to pooled funding). 

During the initial creation of the regulatory and liability framework, however, when all eyes 

focus on the new standards, it is important not to lose sight of the role tort and property law can 

continue to play, not only as the historic basis of regulation but as a continuing vehicle for 

creating and applying legal doctrine and creating a set of incentives for CCS site selection and 

management. 

 At the present time, the trend often appears to be otherwise. In recent years, industry and 

federal agencies have relied heavily on the existence of federal standards in the health and safety 

area to argue to courts that state tort claims to recover for harm arising from actions covered by 

the legislation are preempted.175 The Supreme Court has been active in this area, having decided 

several cases in the last few years involving preemption of state public health, environmental, 

and safety matters,176 and is considering several more such cases during its 2008 term.177 In each 

 

175 See, e.g., Catherine M. Sharkey, Preemption by Preamble: Federal Agencies and the Federalization of Tort Law, 

56 DEPAUL L. REV. 227 (2007) (describing recent efforts by federal public health and safety agencies such as the 

U.S. Food and Drug Administration, the National Highway Transportation Safety Board, and the Consumer Product 

Safety Commission to achieve preemption of state regulations and common law claims for relief through the use of 

amicus briefs and statements in federal regulations). 

176 See, e.g., Bates v. Dow Agrosciences, 544 U.S. 431 (2005) (holding that the federal pesticide law does not 

preempt all state law claims for damages resulting from pesticide use); Buckman Company v. Plaintiffs’ Legal 

Committee, 531 U.S. 341 (2001) (holding that plaintiff injured by medical device could not bring a “fraud-on-the 

FDA” claim against drug manufacturer consultant because the FDA’s regulatory framework for policing fraud 

preempted attempts to have a state court jury determine such fraud); Sprietsma v. Mercury Marine, 537 U.S. 51 

(2002) (holding that Federal Boat Safety Act did not expressly or impliedly preempt common law claims for 

damages against boat manufacturer for failure to equip boat engine with propeller guard); Geier v. American Honda 

Motor Co., 529 U.S. 861 (2000) (holding Department of Transportation safety standard enacted pursuant to federal 

Motor Vehicle Safety Act preempted common law claim for design defect associated with choice of safety

restraints); Medtronic v. Lohr, 518 U.S. 470 (1996) (holding that the Medical Device Amendments to the Food, 

Drug and Cosmetic Act do not preempt state law claims for damages against manufacturer of product that was 

approved through the Section 510(k) streamlined approval process); Hillsborough v. Auto. Med. Labs., 471 U.S. 

707 (1985) (FDA regulations establishing minimum standards for the collection of blood plasma did not preempt a 

county’s local ordinance governing blood plasma centers). See also Alexandra B. Klass, State Innovation and 

Preemption: Lessons from Environmental Law, __ LOY. L.A. L. REV. __ (forthcoming 2008) (surveying preemption 

cases involving public health, safety, and environmental statutes and citing articles discussing recent trends in the 

law). 

177 See Reigel v. Medtronic, __ S. Ct. __ (U.S. Feb. 20, 2008) (holding that common law tort claims concerning a 

medical device that has undergone “pre-market approval” under the 1976 Medical Device Act Amendments to the 

Food, Drug, and Cosmetic Act are state “requirements” that violate the Act’s express preemption clause prohibiting 

state requirements “different from, or in addition to” federal requirements relating to the safety or effectiveness of 

the device); Desanio v. Warner-Lambert & Co., 467 F.3d 85 (2d Cir. 2007) (involving preemption of state law 

claims against prescription drug manufacturer), cert granted sub. nom., Warner-Lambert v. Kent, 128 S. Ct. 31 

(Sept. 25, 2007); Altria Group v. Good, __ S. Ct. __, 2008 WL 161478 (U.S. Jan. 18, 2008) (involving preemption 
33

of these cases, the issue is always one of Congressional intent (i.e., did Congress intend to 

preempt state law) but in many statutes Congress is silent and even when Congress does include 

an express preemption clause or an express savings clause (expressing an intent to preserve state 

law), the scope of such clauses remains subject to significant debate. 

 Arguments over whether existing federal legislation preempts liability under state law are 

based on principles of constitutional law,178 federalism, statutory interpretation, and, in some 

cases, the level of deference to agency positions arguing in favor of preemption.179 In the case of 

CCS, however, Congress will likely consider and perhaps adopt broad federal legislation to 

govern many aspects of the CCS process in addition to whatever legislation is enacted at the state 

level. If and when Congress considers such legislation, there undoubtedly will be arguments by 

industry, and perhaps federal agencies, that any such legislation should preempt state tort 

remedies in order to provide more settled-expectations to industry and avoid multiple liability 

standards. 

 We caution against such an approach, as Congress has generally not acted to preempt 

state law in enacting environmental health and safety legislation, even when that legislation is 

intended to cover nationwide issues such as the nuclear energy industry, or the regulation of air 

pollution, water, or waste.180 Even though CCS is new and will require significant federal, state, 

and private resources to become viable, it can look to existing liability and insurance frameworks 

to create a reasonable certainty of investment without compromising public health, safety, and 

environmental protection. Additionally, such frameworks can be structured to enhance incentives 

for proper site selection and management for CCS projects. Ensuring that existing liability 

frameworks are in place for CCS is particularly important at a time when federal agencies often 

do not have the resources to enforce their own regulations, creating an enforcement vacuum that 

had historically been filled by state tort law.181 

 Indeed, in 2005, in Bates v. Dow Agrosciences,

182 the Supreme Court rejected the 

argument that the federal pesticide law preempted a broad range of state claims seeking damages 

 

of claims under state deceptive trade practices law against cigarette manufacturer); Wyeth v. Levine, __ S. Ct. __, 

2008 WL 161474 (U.S. Jan. 18, 2008) (involving preemption of state law product liability claims against 

prescription drug manufacturer). 

178 The doctrine of federal preemption is based in the Supremacy Clause of the U.S. Constitution which states that 

“This Constitution, and the laws of the United States which be made in pursuance thereof; . . . shall be the supreme 

law of the land; and the judges in every state shall be bound thereby, anything in the Constitution or laws of any 

States to the contrary notwithstanding.”). U.S. CONST. art. VI, cl. 2. See also Gibbons v. Ogden, 9 Wheat 1, 211 

(1824) (Marshall, C.J.) (holding that the Supremacy Clause invalidates state laws that “interfere with or are contrary 

to” federal law). 

179 See Catherine M. Sharkey, Products Liability Preemption: An Institutional Approach, 76 GEO. WASH. L. REV. 

(forthcoming 2008) (discussing how much deference courts should give federal agency pronouncements on the 

scope of federal preemption of state law). 

180 See, e.g., Silkwood v. Kerr-McGee Corp., 464 U.S. 238 (1984) (holding that award of punitive damages under 

state law for exposure to nuclear materials is not preempted by the Atomic Energy Act); PERCIVAL, supra note 84, at 

104 (“Preemption of state law has been employed sparingly in the federal environmental laws” and is generally 

reserved for regulation of products that are distributed nationally); Klass, supra note 127, at 570 (“[T]he broad 

savings clauses in most federal statutes have left ample room for state common law to be a major player in 

environmental-protection efforts.”). 

181 See supra notes 75-76 and accompanying text. 

182 544 U.S. 431 (2005). 
34

for crop damage due to pesticides based not only on the law’s preemption language but also on 

the important role tort law plays in society. The Court recognized that state tort law serves an 

important role in aiding the exposure of new dangers associated with pesticides, and giving 

manufacturers “added dynamic incentives to continue to keep abreast of all possible injuries 

stemming from use of their product so as to forestall such actions through product 

improvement.”183 The same holds true for the development of CCS. Despite the best efforts of 

corporate partners and government regulators to ensure the safety of the long-term storage of 

CO2, there remains a risk of harm. Project developers will have added incentive to minimize that 

risk to the public and to the environment if they are aware that private parties who may be 

harmed have recourse through the environmental and tort liability system rather than solely 

being accountable to government regulators.184 

 In sum, the development of CCS presents critical concerns of ownership, allocation, and 

liability in the context of developing a cutting-edge technology with the potential to counteract 

climate change but that also involves risks to human health and the environment. The answer to 

these issues is not to eliminate existing liability frameworks. Instead, it is to provide incentives 

for good site selection, encourage responsible project management, and recognize and preserve 

the rights of those who may be harmed by CCS projects while at the same time create a market 

for insurance and other risk-pooling opportunities to allow predictability for stakeholders. 

Possible approaches to this issue are discussed in Parts IV and V. 

IV. MECHANISMS FOR ENSURING FINANCIAL RESPONSIBILITY AND MANAGING LIABILITIES 

The previous Parts of this Article make the case for retaining the existing liability 

protections environmental statutes and the common law provide. We recognize, however, that 

the start-up costs and long-term investment associated with CCS may require tailored solutions 

to minimize and manage risk. In this Part, we explore different mechanisms for ensuring 

financial responsibility and managing potential liabilities. Specifically, we explore bonding, 

insurance, damage caps, and federal funds which exist for other environmental and complex 

large-scale technologies and consider their potential effectiveness for CCS. We conclude that 

these potential solutions in combination hold promise for CCS development and provide a 

response to arguments that liability under environmental statutes and common law should be 

preempted or otherwise limited across the board. 

A. General considerations 

Provisions for financial responsibility and liability during post-closure care and long-term 

stewardship of CCS projects must balance the global and local risks of CCS with the climate 

benefits of CCS deployment. If long-term stewardship and liability considerations are too 

onerous, firms may choose not to invest in CCS; if they are too lax, public and ecological health 

could be compromised and public confidence in CCS may suffer. As the time-line for CCS 

projects (hundreds of years to thousands of years) is incongruous with the lifetime of a private 

entity, legislators and regulators must develop institutional structures to fund and manage CCS 

 

183 Bates v. Dow Agrosciences, 544 U.S. 431, 451 (2005). 

184 See, e.g., Axline, supra note 127 (discussing limitations of statutory law and benefits of common law in 

optimizing the protection of human health and the environment). 
35

risks over the long term. Such structures will likely be temporally segmented, with responsibility 

passing from private firms to public management for long-term stewardship.185 Ensuring 

adequate funds are available during the post-closure and long-term stewardship phases could 

follow several different formulae,186 but any approach must guarantee resources are available to 

cover public monitoring and potential remediation costs and avoid CCS projects becoming an 

unfunded public mandate. 

For CCS, augmenting statutory and common law liability within such a tailored 

regulatory structure is a crucial component of risk management. Shortcomings of relying solely 

upon general statutory and common law liability are: (1) the ability to detect and assign blame 

for harm;187 (2) the potential lack of necessary resources for firms injecting CO2 to address 

potential harms; and (3) the time horizon between cause (injection of CO2) and effect of any 

damages.188 As a result of these shortcomings, we turn to different approaches that can both 

supplement liability frameworks and also provide a compensation mechanism in cases where 

liability is imposed.189

B. Bonding 

 As a financial assurance mechanism, bonding is a potentially important tool to address 

post-closure risk management for CCS projects.190 Bonding has been widely used to enforce 

contracts and regulatory provisions in a number of different settings, including environmental 

management purposes such as requiring bonds for municipal landfills, transport of hazardous 

waste, underground injection and disposal, and others. Bonding allows for the internalization of 

future damages by requiring an up-front commitment to offset the costs of potential future 

pollution—often in the form of cash, a letter of credit, a surety bond, or a trust fund or escrow 

account. The bond is posted up front, but if the firm does not comply, the bond is forfeited and 

funds are immediately available for remediation efforts. Additionally, the bond shifts the burden 

of proof from the regulator to the operator and provides public protection up to the amount 

posted (but not necessarily the amount of the damages).191 While bonding is promising in 

 

185 See infra Part V for a discussion of the potentially different stages of operator liability during the CCS life-cycle. 

186See IOGCC, supra note 8, at 11; Christina Ulardich, Environmental Impairment Liability Insurance for 

Geological Carbon Sequestration Projects, in INTERNATIONAL RISK GOVERNANCE COUNCIL WORKSHOP ON 

REGULATION FOR CCS (March 2007), available at http://www.irgc.org/IMG/pdf/IRGC_CCS_SwissRe07.pdf. 

187 This could be especially important given the multiple effects of CO2 in the subsurface, latency between injection 

and harm, and challenges in proving a causal link between CO2 injection and harm. Current monitoring 

methodologies are limited in scope with only a few states requiring any post-closure site monitoring. See generally 

David W. Keith et al., Regulating the Underground Injection of CO2, ENVIRONMENTAL SCIENCE AND TECHNOLOGY

39(24): 499A-505A (2005).

188 See David Gerard & Elizabeth J. Wilson, Environmental Bonds and the Challenge of Long-Term Carbon 

Sequestration, __, J. ENVTL. MGMT. __ (forthcoming 2008); Steven Shavell, Liability for Harm Versus Regulation 

of Safety 13 J. LEGAL STUDIES 357-74 (1984); A. H. Ringleb & S.N. Wiggins, Liability and Large Scale, Long Term 

Hazards, 98 J. POL. ECON. 574-95 (1990). 

189 See de Figueiredo, supra note 10, at 67. 

190 Gerard & Wilson, supra note 188. 

191

 Id. 
36

environmental settings,192 there are limits to its use,193 as explained below, and success has been 

mixed.194 

 The problems associated with bonding are well-documented.195 Bonding is costly in 

terms of imposing liquidity constraints on firms and transaction costs, and becomes more costly 

as complexity increases. A problem for both liability rules and bonding is the potentially long 

lag time between the operators’ activity (injection of CO2) and the potential harm (leakage to the 

surface or resource damage). Also, over long time horizons, the responsible firm may go out of 

business, or surety providers are unlikely to underwrite bonds with such uncertainties. Thus, for 

bonding to be effectively utilized within CCS projects regulators must explicitly define periods 

of responsibility. Setting the bond amount—balancing costs to the firm and potential public 

liabilities—is often contentious.196 Knowing the potential cost of remediation is essential for 

setting the bond amount, although firms with extensive resources are likely to comply with 

cleanup requirements, even if they are higher than the posted bond amount, due in part to 

reputational effects limiting opportunistic behavior.197 With experience, establishing the bond 

amount becomes easier. Below we examine the use of bonds for mine site reclamation and to 

ensure proper closure of underground injection wells. In both contexts, bond use is wellestablished and experience highlights both the benefits and potential pitfalls of bonds 

 For mining, regulations often require post-mining site reclamation. The operator posts a 

bond to satisfy this condition and if there is insufficient compliance, the firm must forfeit the 

bond and bond proceeds are used to finance reclamation. Under the Surface Mining Control and 

Reclamation Act of 1977 bonding is compulsory for coal mining projects. It is also often 

required for hard rock mining projects on federal lands under Department of Interior (Bureau of 

Land Management) or Department of Agriculture (Forest Service) regulations. In most cases, 

states have primacy in regulating hard rock mining activities, and state agencies require some 

form of environmental assurance, typically a reclamation bond.198 In the case of hard rock 

mining, the bond premium is often one to five percent of the face value of the bond. While large 

firms can secure a surety by posting less than one percent, small firms may face premiums of 15 

to 20 percent or higher.199 

 Bonding is also used in underground injection. All injection wells regulated under the 

U.S. Environmental Protection Agency’s Underground Injection Control (UIC) Program and 

most state regulated oil and gas production wells require bonding to help ensure proper site 

closure. In the UIC program, an operator must submit a well closure and abandonment plan that 

 

192 See generally Robert Costanza & Charles Perrings, A Flexible Assurance Bonding System for Environmental 

Management, 2 ECOLOGICAL ECONOMICS 57-75 (1990). 

193 See generally Jason F. Shogren, et al., Limits to Environmental Bonds, 8 ECOLOGICAL ECONOMICS 109-133 

(1993).

194 See James Boyd, Financial Responsibility for Environmental Obligations: Are Bonding and Assurance Rules 

Fulfilling Their Promise?, RESEARCH DISCUSSION PAPER RFF-DP-41-02, RESOURCES FOR THE FUTURE (2002),

available at http://www/rff.org/documents/RFF-DP-01-42.pdf. 

195 See Boyd, supra note 194; Shogren, et al., supra note 193. 

196 Gerard & Wilson, supra note 188.

197 See generally David Gerard, The Law and Economics of Reclamation Bonds, 26 RESOURCES POLICY 189-197 

(2000). 

198 Id.

199 Gerard & Wilson, supra note 188. 
37

identifies steps for closing the well (plugs, cement, cost) and any subsequent post closure 

monitoring activity.200 While a performance bond is required to ensure proper plugging and 

abandonment, in the vast majority of cases no long-term monitoring is required and the bond is 

released upon well closure. For UIC wells, the bond is released after the operator has satisfied 

plugging and abandonment procedures established by the regulator.201 Bond amounts are 

established by the states, and differ significantly across jurisdictions.202 

 For bonding to be effectively used for long-term stewardship in a CCS project, several 

conditions would need to be met: (1) the time frame that the bond would cover must be clearly 

established; (2) the party responsible for damages must be identified; and (3) cost estimates—for 

monitoring, verification and remediation costs for damage—are needed to set the bond amount. 

The utility of bonding for CCS is inexorably linked to future regulatory requirements. Key 

decisions that will determine the role of bonding are linked to the operator’s duration of 

responsibility and scope of responsibility for long-term CSS site care. If, like current UIC 

injection wells, operator responsibility ends with plugging and closure, bonding will be of 

limited use in the CCS post-closure period. Bonding, however, could play a key role if operator 

responsibility extends beyond active injection and covers a performance-based post-closure care 

period. For maximum effectiveness, bonding amounts should be set in a fashion that reflects 

differences in site-specific risk and operator performance data. For example, the future CCS 

bond amount could be linked to the site environmental impact statement, operational 

performance data (like CO2 plume stabilization) and the site monitoring plan, as well as potential 

human or ecological health risks, thus using bonding to support a framework of site-risk 

management. 

C. Insurance 

 The use of insurance to manage environmental risk, whether operational or catastrophic, 

is well developed.203 Both RCRA and CERCLA use pollution liability insurance as a tool to 

control environmental pollution.204 Insurance serves to allocate risk through classifying the risk 

and pricing it, the use of policy exclusions and deductibles, and through the creation of 

“surrogate regulation,” where inspection, risk assessment, and risk management act as a de facto

impetus towards better management.205 Conventional private insurance rules of insurability 

include: (1) a sufficient number of similar and uncorrelated events to allow for risk pooling; (2) 

clearly calculable losses; (3) loss occurring within a well established time period; (4) frequent 

enough losses to calculate premiums; and (5) insured party has no incentive to cause loss. 206 

CCS might violate several of these conditions: (1), (2), and (4) given both the lack of experience 

with large-scale CCS and inherent geologic heterogeneity; and (3) given the long time frame for 

 

200 See 40 C.F.R. §§ 144-146. 

201 Id.

202 Gerard & Wilson, supra note 188. 

203

 See Dan R. Anderson, Limits on Liability: The Price Anderson Act versus Other Laws, 45 J. OF RISK AND 

INSURANCE 651-674 (1978); Martin T. Katzman, Pollution Liability Insurance and Catastrophic Environmental 

Risk, 55 J. OF RISK AND INSURANCE, 75-100 (1988). 

204 Katzman, supra note 203, at 82, 94. 

205

 See Kenneth S. Abraham, Environmental Liability and the Limits of Insurance, 88 COLUM. L. REV. 942, 949 

(1988). 

206 Id. at 83. 
38

CCS storage. That said, in a recent meeting held by the International Risk Governance Council, 

representatives from the insurance community stated that they had experience managing all of 

the environmental risks associated with CCS under their environmental impairment liability 

coverage, with the exception of climate risk associated with the re-release of CO2 to the 

atmosphere.207

 The development of environmental impairment liability (EIL) addresses many of these 

factors by considering specific site-by site policy coverage (unlike Comprehensive General 

Liability—which is general), and is a relatively recent insurance product, emerging in the 

London market in the early 1980’s.208 Each site must be independently evaluated for risk. EIL 

policies are claims-made and ‘backward looking’—i.e. they pay claims made on environmental 

damages that occurred in the past. Such policies are used for both sudden and gradual pollutant 

events, natural resource damage, RCRA, CERCLA, loss of business, defense of liability, and 

other types of claims.209 

 Some argue that the role of government, both as insurer and risk manager can have some 

important effects both for correcting private market failures and also establishing operational 

requirements that limit risk, which, in turn limits liability.210 The relationship between tort law 

and EIL has been challenging, as insurance requires some predictability of the tort process, 

undermined by the large damage awards from hazardous chemical exposure and cleanup, and 

complex industrial site pollution.211 Managing legal risk is a key component for insurance to be 

a useful tool for post-closure CCS. Harmonizing liability and tort law could make the 

environment more predictable for insurance in CCS. 

Like bonding, insurance could provide a key tool for financial assurance during the postsite closure phase, where the operator is actively involved in monitoring, verification, and 

potential remediation, and still bears responsibility—and liability—for any potential damages. 

EIL has experience with all risks posed by a CCS project—with the exception of climate-related 

risks—and is tailored to site-specific risks, which is important for linking geologic variability 

within a risk management framework. Thus, EIL emerges as a potentially flexible and 

appropriate mechanism for ensuring adequate financial responsibility for CCS. 

D. Federal Compensation Systems Coupled with Damage Caps and Preemption 

 One way to provide more certainty to industry while ensuring some compensation for 

harm is to create an alternative to the tort process in the form of a pooled federal fund to pay 

claims, displacing (or preempting) tort law, and setting caps on damages available from the fund. 

Congress has created these types of specialized funds to displace the standard tort process for 

 

207 See INTERNATIONAL RISK GOVERNANCE COUNCIL, WORKSHOP REPORT ON REGULATION OF

CARBON CAPTURE AND STORAGE 19 (March 15-16, 2007), available at

http://www.irgc.org/IMG/pdf/Workshop_Report_Regulation_of_Carbon_Capture_and_Storage_March_15_and_16

_2007_Washington_final.pdf.

208 Id. at 88. 

209 See Katzman, supra note 203, at 76-77. 

210 See de Figuieredo supra note 10, at 66. 

211 Katzman, supra note 203, at 89. 
39

certain types of workplace injuries,212 the federal childhood vaccine program,213 and nuclear 

power plants.214 State workers compensation statutes apply many of these same principles to 

workplace injuries on a state-by-state basis.215 In essence these provisions “provide a political 

compromise between providing compensation for victims and limiting the financial impact on 

potentially liable parties.”216 Proponents of selective damage caps on liability argue that they are 

necessary to manage uncertain risks, protect industry from large jury awards and unnecessary 

lawsuits and provide a climate for private investment while still providing some compensation 

for injured parties.217 Opponents contend liability caps unjustly limit the public’s ability to 

recover full compensation from damages, provide an unfair subsidy to industry, and are 

fundamentally unjust.218 Here, we discuss the use of liability limits in the Price-Anderson Act 

applicable to the nuclear industry. We ultimately conclude that damage caps would not be 

appropriate for CCS as a general matter, but may be appropriate in early years to encourage pilot 

projects and initial investment, or to limit long-term risk in the final stage of CO2 sequestration. 

 While the nature of risks from CCS and nuclear power are fundamentally different in 

nature, the Price-Anderson Act is instructive because it developed a mechanism to stimulate 

investment in civilian nuclear power by blending different risk management instruments into a 

coordinated framework of coverage.219 First passed by Congress in 1957 (and recently renewed 

in 2005), the Price-Anderson Act was envisioned as a temporary provision to stimulate and 

support the development of civilian nuclear energy by creating funding while at the same time 

limiting tort liability for nuclear accidents.220 The Act’s original purpose was to limit financial 

uncertainty arising from nuclear accidents by placing a cap on liability and guaranteeing that 

citizens could be compensated for damages to person and property.221 Criticized by opponents 

 

212 See, e.g., Longshore and Harbor Worker’s Compensation Act, 33 U.S.C. §§ 901-944 (providing fixed awards to 

employees or their dependents in case of employment-related injuries or deaths occurring on navigable waters). 

213 National Childhood Vaccine Injury Act of 1986, 42 U.S.C. §§ 300a-1 to 300aa-34 (creating no-fault 

compensation program for childhood vaccine-injury victims funded by an excise tax on each dose of vaccine). See 

also Robert Rabin, The Renaissance of Accident Law Plans Revisited, 64 MD. L. REV. 698, 706-07 (2005) 

(discussing federal childhood-vaccine injury program). 

214 See Price-Anderson Act, 42 U.S.C. § 2210; Duke Power v. Carolina Envtl. Study Group, 438 U.S. 59 (1978) 

(discussing Price-Anderson Act). 

215 See generally, SCHWARTZ ET AL., PROSSER, WADE & SCHWARTZ’S TORTS 1191-95 (11th ed. 2005) (discussing 

general features of state workers’ compensation laws as providing employees automatic entitlement to certain 

benefits when she suffers workplace injuries, the irrelevance of fault, a set of cash and medical benefits, waiver of 

the right to sue the employer in tort, administration of claims by a state commission, and a requirement that the 

employer secure private insurance, state-funded insurance or self-insurance; FRANKLIN ET AL., TORT LAW AND 

ALTERNATIVES 816-29 (8th ed. 2006) (discussing generally state workers’ compensation laws). 

216 See Dan M. Berkovitz, Price-Anderson Act: Model Compensation Legislation?—The Sixty-three Million Dollar 

Question , 13 HARV. ENVTL. L. REV 1, 2 (1989). 

217 Id. at 58; AMERICAN NUCLEAR SOCIETY, THE PRICE ANDERSON ACT: BACKGROUND INFORMATION (2005), 

available at http://www.ans.org/pi/ps/docs/ps54-bi.pdf. 

218 Anderson, supra note 203, at 652; Berkovitz supra note 216, at 48 (“Justice dictates that either the persons 

responsible for an accident or the beneficiaries of the activities creating the risk of the accident should bear he costs 

of damages resulting from the accident.”); Daniel W. Meek, Nuclear Power and the Price-Anderson Act: Promotion

over Public Protection, 30 STAN. L. REV. 393 (1978). 

219 See 10 C.F.R. § 140.

220 Anderson, supra note 203, at 651. 

221 See U.S. GENERAL ACCOUNTING OFFICE (“GAO”), NUCLEAR REGULATION: NRC’S LIABILITY INSURANCE 

REQUIREMENTS FOR NUCLEAR POWER PLANTS OWNED BY LIMITED LIABILITY COMPANIES 4-6 (2004), available at

http://www.gao.gov/new.items/d04654.pdf.; FRANKLIN ET AL., supra note 215, at 870 (stating that the Act’s express 
40

as a subsidy to the nuclear industry, Price-Anderson began by limiting liability from potential 

“extraordinary nuclear occurrences”222 and creating a tiered structure of financial responsibility 

combining private insurance, an industry pooled fund, and a cap on total liability. Each nuclear 

reactor over 10 megawatts was required to have $300 million per plant in insurance.223 Any 

additional claims are paid from an industry funded pool—the Price Anderson fund—with each 

company contributing up to $95.8 million if an accident occurs.224 

 In the event of an accident, companies are required to pay $15 million annually until the 

claim is met or the maximum reached and now, with 103 operating nuclear power plants, the 

fund contains approximately $10 billion.225 Any claims beyond this amount would be covered 

by funds raised by the Nuclear Regulatory Commission (NRC) from Congress using public 

monies.226 In the event of an accident with damages surpassing the total, the NRC would prepare 

a report for Congress and the Courts estimating the damages.227 The Act indemnifies licensees 

from any amount over the liability cap228 and, since amendments in 1988, any nuclear incident—

not just extraordinary nuclear occurrences—would fall under the jurisdiction of the federal 

district courts. 229 Also as part of the 1988 Amendments, however, Congress created a federal 

cause of action for any action arising from a nuclear incident, divested the state courts of 

jurisdiction, specifically barred state law claims for punitive damages, and preempted any state 

law inconsistent with the Act.230 Subsequent appellate courts have barred other state law claims, 

reasoning that they are inconsistent with the federal claims standards set fort in the 1988 

Amendments.231 

 To date, the Price-Anderson fund has paid out a total of $202 million (with $70 million 

associated with the 1979 Three Mile Island incident).232 For proponents, the Act has been key 

for nuclear industry development and obligated the nuclear plant operators and the industry to 

hold a higher level of liability insurance coverage than might otherwise be the case, and may, in 

 

intent “was to encourage investment in nuclear energy research and operations by a private sector daunted by the 

prospect of multimillion-dollar claims.”).

222 See 10 C.F.R. §140.83.

223 See 10 C.F.R. § 140.11 (specifying the amounts of protection required). 

224 See GAO, supra note 221, at 4-6. 

225 Id. at 4-5. 

226 Id.

227 Id.

228 See 42 U.S.C. § 2210(c) (setting forth indemnification provisions).

229 See 42 U.S.C. § 2210(n)(2). 

230 See 1988 Amendment to Price-Anderson Act, 42 U.S.C. § 2210(s) (providing that no court may award punitive

damages in any nuclear incident covered by the Act); 42 U.S.C. § 2014(hh) (stating that the substantive rules for 

decision in public liability actions shall be derived from state law unless state law is inconsistent with the Act). 

231 See O’Connor v. Commonwealth Edison Co., 13 F.3d 1090 (7th Cir. 1994) (discussing 1988 Amendments to 

Price-Anderson Act and finding federal preemption of state standards of care); Nieman v. NLO, Inc. 108 F.3d 1546, 

1551 & n.5 (discussing impact of 1988 Amendments on state punitive damages claims and Silkwood decision); In re 

TMI Litig. Cases (“TMI II”), 940 F.2d 832, 854 (3rd Cir. 1991) (holding Price-Anderson Act preempts state law tort 

claims that are not consistent with federal law). But see Cook v. Rockwell Int’l, 273 F. Supp.2d 1175 (D. Colo. 

2003) (holding that federal nuclear safety regulations did not preempt state standards of care in public liability 

actions); In re Hanford Nuclear Reserv. Litig., 350 F. Supp.2d 871 (holding that the Act does not require that federal 

safety standards establish the standard of care and preempt state tort remedies, including state law claims for strict 

liability). 

232 GAO, supra note 221, at 5; JOHN DEUTCH ET AL., MIT STUDY ON THE FUTURE OF NUCLEAR POWER 82 (2003). 
41

the event of a large-scale accident, end up being cost effective for both the industry and the 

government.233 For critics, the Act serves as a public subsidy to the nuclear industry and ends up 

limiting the ability of affected parties to recover adequate damages.234 

 For CCS projects, the interplay between encouraging technology deployment, protecting 

human health and the environment, and balancing the role of state and federal law played out 

under the Price-Anderson Act provides several points for discussion. First, unlike nuclear 

activities, the potential of a catastrophic accident from CCS projects is low—CCS risks are 

generally understood and likely manageable.235 Nevertheless, the blending of site-specific 

insurance and pooled industry funds could provide both site-tailored risk management and ensure 

that adequate funds are available to cover damage in the post-closure period. The tiered structure 

of site and industry responsibility would allow for funds to be available during the post-closure 

period, and some amount of risk-sharing over different projects. By pooling funds at the 

national—as opposed to state—level, the pool would also help to spread risk of leakage and 

damage across different geological formations. Say, for instance, that injection projects in 

Washington basalts proved particularly leaky. If the fund pool were held at the state level, the 

fund could be quickly drained of resources, as projects injecting into the same geologic 

formation may have correlated risk profiles. 

Second, the tension between state law and federal preemption is a constant theme in cases 

involving the Price-Anderson Act.236 For CCS, where potential damages occur in domains with 

strong state laws governing groundwater protection, mineral rights, or surface rights, it is easy to 

imagine the potential tension between state interests and Congress. As CCS projects are likely to 

be large and given that water and mineral resources are fundamental to other state interests 

(agriculture, urban development, industry, tax revenues, and others), CCS operators will lobby 

strongly in Congress (and later in the courts) that federal law should preempt state law claims for 

damages and perhaps federal environmental laws. For the reasons stated in Part III, the existing 

state and federal liability framework provides important safeguards for potential harm associated 

with CCS. Thus, federal legislation should include clear language to preserve state and federal 

bases for liability and instead focus on limiting operator liability by utilizing pooled funding, 

bonding, insurance and other methods of assuring solvency in case of claims. 

Finally, while the use of a liability cap (such as that in the Price-Anderson Act) provides 

predictability for firms, it may also undermine the credibility of CCS in the eyes of the public. 

When CCS-proponents expound on the safety of the technology while simultaneously lobbying 

for a damage cap, this contradictory position undermines CCS credibility. Significantly, PriceAnderson was originally conceived as a temporary aid to uncertainty, not a permanent subsidy to 

the industry. This precedent cautions against absolute damage caps for CCS claims that do not 

provide a resort to tort law or statutory environmental law outside available federal funding. 

 

233 DEUTCH ET AL., supra note 232, at 81-83. 

234 See generally Berkovitz, supra note 216; Meek, supra note 218. 

235 See supra Part I.C. 

236 See supra Part III.B. 
42

E. Federal Compensation Systems Coupled with Tort Law 

 Another way of structuring liability and funding is to create a specialized fund for certain 

types of harm to allow prompt payment of claims but retain the ability of claimants to seek 

damages beyond funding limits from responsible parties through the tort system. An example of 

such a system is the Trans-Alaska Pipeline Liability Fund (“TAPL Fund”), now part of the 

funding available under the Oil Pollution Act (“OPA”). This system provides information 

analogs for CCS for at least two reasons. First, the OPA reconciles existing regulatory standards 

and incorporates approaches to liability and risk management depending on the location of the 

damage. Second, it creates a significant fund for quick payout of claims in case of harm but 

allows claimants to seek damages in excess of the fund’s maximum from liable parties under 

state or federal tort law. These features make the liability structure for claims associated with the 

Trans-Alaska Pipeline (and now oil spills in general) particularly relevant for CCS. 

 Passing the Trans-Alaska Pipeline Authorization Act of 1976 (“TAPPA”)237 involved 

compromise—reconciling the interests of environmentalists, native Alaskans, and business—

and, importantly carried significant provisions which impose liability for oil spills on land and 

water.238 Owners of oil paid a 5-cent per barrel charge on oil traveling through the Trans-Alaska 

Pipeline to finance the Trans-Alaska Pipeline Liability Fund (“TAPL Fund”).239 Under TAPPA, 

if the incident occurred on water, claimants could recover under strict liability up to $100 million 

per incident, with the operator paying the first $14 million and the TAPL Fund paying the rest, 

ensuring rapid payment of funds.240 Significantly, claimants could seek any remaining amounts 

not covered by the TAPL Fund from the ship operators under other sources of federal or state 

law.241 If negligence or unseaworthiness of the vessel caused the spill, the TAPL Fund obtained 

subrogation rights associated with payment of the claims and was entitled to seek recovery of the 

payments from those legally responsible for the spill.242 After the 1989 Exxon Valdez oil spill 

the Fund paid out $23 million to Native Corporations and many millions of dollars to other 

injured parties, and Exxon ultimately reimbursed the TAPL Fund for those amounts.

243

 

 In 1990, as result of the Exxon Valdez spill, Congress enacted significant amendments to 

the Oil Pollution Act (“OPA”) and brought the TAPL Fund within the jurisdiction of the Oil 

Pollution Act for spills that occurred after 1990.244 Under the OPA, claimants may recover 

compensation for damages from the Oil Spill Liability Trust Fund (“OSTLF”) on a strict liability 

basis of up to $1 billion per oil spill incident or the balance in the OSTLF.245 Under the OPA, 

 

237 43 U.S.C. §§ 1651 – 1655; 61 AM. JUR. 2d Pipelines § 8. 

238 Anderson supra note 203, at 660; see also 43 U.S.C. § 1653(c). 

239 43 U.S.C. § 1653(c)(5). 

240 43 C.F.R. §§ 29.7-9. 

241 Id.

242 See 42 U.S.C. § 1653(c)(8); In re Glacier Bay, 944 F.2d 577, 581 (9th Cir. 1991). 

243 See Chenega Corp. v. Exxon Corp., 991 P.2d 769, 791-92 (Ala. 1999). 

244 See FRANK P. GRAD, 2 ENVIRONMENTAL LAW § 3.03[i] (2007) (detailing impact of 1990 Oil Pollution Act on 

TAPPA and TAPL Fund). 

245 See 26 U.S.C. § 9509 (amendment to Internal Revenue Code creating OSTL and setting $1 billion per incident 

limit). See also U.S. Coast Guard, Oil Pollution Act of 1990 (discussing funding and noting that the Energy Policy 

At of 2005 raised the limit of the OSLTF to $2.7 billion), available at

www.uscg.mil/hq/npfc/About%20Us/opa.htm; U.S. Coast Guard, Oil Pollution Act (OPA) Frequently Asked 

Questions (stating that Energy Policy Act increased funding for the LSLTF by re-instating the 5-cents-per-barrel tax 
43

the responsible party is liable for payment of damages up to a certain amount based on the size of 

the vessel, up to a maximum of $350 million per spill at onshore facilities and deepwater ports, 

and up to $75 million at offshore facilities, plus removal costs.246 Claimants can seek a wide 

range of damages under the OSTLF including removal costs, natural resource damages, damage 

to real or personal property, other economic losses, lost profits, and loss of subsistence use.247 

Between 1995 and 2004, the OSTLF paid out $492.3 million associated with removal costs and 

claims and recovered $130.6 million from responsible parties.248 Significantly, the OPA, like 

TAPAA, includes a strong savings clause which provides that nothing in the OPA should be 

construed as preempting the authority of any state or political subdivision from imposing 

additional liability or in any way to affect the obligations or liabilities of any person under 

RCRA or state law, including common law.249 As a result, potential claimants can obtain 

compensation from the OSTLF on a strict liability basis but also pursue, if they wish, claims for 

punitive damages or other damages not recoverable under the OPA. 

 

 TAPPA and OPA provide a potential model for CCS that includes differentiation of harm 

based on location (on-shore or off-shore) as well as on a legal and regulatory adaptation to new 

technology and novel environmental risk. Significantly, the TAPPA and the OPA leave federal 

and state liability law in place and build on top of it a federal compensation scheme. This allows 

parties to recover from pooled funds in an expeditious manner and, for those claims not fully 

covered by the pooled funds, to pursue them in full under federal or state law. As noted above, 

the plaintiffs in the Exxon Valdez oil spill were allowed to recover quickly against the Fund and 

then litigate their remaining claims, including the multi-billion dollar punitive damage claim 

against Exxon that is currently pending before the Supreme Court.250 A similar compensation 

regime that does not preempt, or displace, existing federal or state environmental and tort law 

can serve as a partial model for creating a liability structure for CCS. 

 What is unique about CCS, however, is the scale of projects and necessary deployment. 

A lowered liability cap within a strict liability federal fund for the first dozen or so full-sized 

CCS projects could help industry to gain the confidence and experience for transition to a full 

commercial CCS deployment. Such a cap would let first movers manage financial risk of new 

CCS technologies and serve to more rapidly transition from demonstration projects to 

commercial deployment. Although claimants could still resort to tort or environmental liability 

to obtain compensation for those claims not covered by the strict liability fund, if the total fund 

amounts are high enough, and the in-fund liability caps low enough, this may help encourage 

operator development of initial projects. 

 

on imported and domestic oil beginning in April 2006 until the fund reaches $2.7 million. The tax will be 

discontinued, regardless of fund balance, on December 31, 2014), available at

http://www.uscg.mil/hq/npfc/About%20Us/opa_faqs.htm#faq3. 

246 See 33 U.S.C. § 1004 (setting forth responsible party limits on liability). 

247 See 33 U.S.C. § 2702(b). See also U.S. DEPARTMENT OF HOMELAND SECURITY, UNITED STATES COAST GUARD,

OIL SPILL LIABILITY TRUST FUND (OSTLF) FUNDING FOR OIL SPILLS 7 (Jan. 2006). 

248 U.S. DEPARTMENT OF HOMELAND SECURITY, UNITED STATES COAST GUARD, REPORT ON IMPLEMENTATION OF 

THE OIL POLLUTION ACT OF 1990 7 (2005). 

249 See 33 U.S.C. §§ 2717-2718. 

250 See Exxon Shipping Co. v. Baker, 128 S. Ct. 492 (U.S. 2007) (granting review of whether plaintiffs’ punitive 

damages claims are preempted by the Clean Water Act or barred under federal maritime law). 
44

V. CREATING A FRAMEWORK FOR MANAGING LIABILITY AND ENSURING LONG-TERM 

 FINANCIAL RESPONSIBILITY FOR CCS 

 One of the challenges of managing risk and liability with CCS is the long-term nature of 

CCS projects. To achieve a significant climate benefit, CCS projects must store CO2

underground for hundreds to thousands of years. As the lives of firms are much shorter than the 

period necessary to ensure public and environmental health protection, a transfer of 

responsibility from a single firm to a pooled fund held by a private or public entity must occur. 

 One potential structure would be to adopt a post-closure care program of graduated 

responsibility which both ensures that the CCS project operator is responsible for CCS care after 

closure. Over the first post-closure phase, the project operator would bear full responsibility for 

all liability and be required to provide some type of financial assurance. Over the longer-term, 

stewardship of CCS projects—and funds to ensure remediation—would be transferred to a public 

or private organization with a pool of resources to ensure public and environmental health are 

managed over the long term.251 Bonds, insurance, and selective damage caps (for early pilot 

projects and the long-term stewardship periods only) could all play a role to ensure CCS risk is 

managed over the long-term. 

 Developing a framework to manage CCS project liability requires several conditions to 

be met: (1) Assign responsibility for damages from a CCS project over a defined time period; 

(2) Funds must be available for monitoring, remediation, and damage payment throughout the 

CCS project lifecycle; and (3) The regulatory framework must be adaptive and incorporate sitespecific data into CCS risk management. Additionally, regulatory and liability frameworks 

should be structured to provide incentives for good site selection and operation and an effective 

monitoring regime. These conditions must be met not only for managing environmental, health, 

and safety risk but also in order to integrate CCS within a larger climate policy. In the following 

Sections, we provide more detail on these conditions and propose a framework to incorporate 

adaptive approaches into CCS site management. 

A. Who Is Responsible For CCS Damages and For How Long? 

 Currently, no party is explicitly tasked with post-closure care of CCS sites, nor is a time 

period for care yet defined. For using any of the mechanisms specified in Part IV, the regulatory 

framework must create a defined period of post closure responsibility and liability which covers 

monitoring and any necessary remediation activities. For this Article we assume that the CCS 

life-cycle will follow a pattern of active injection, closure, post-closure, and long-term 

stewardship,252 with monitoring, remediation, and liability responsibility shifting from private to 

third-party (public or private) ownership with the transition from post-closure care to long-term 

stewardship.253 

 

251 Gerard & Wilson, supra note 188.

252 See Edward S. Rubin et al. Regulatory and Policy Needs for Geological Sequestration of Carbon Dioxide, PAPER 

NO. 156 IN PROCEEDINGS OF THE SIXTH ANNUAL CONFERENCE ON CARBON CAPTURE AND SEQUESTRATION,

PITTSBURGH, PA; EXCHANGE MONITOR PUBLICATIONS: PITTSBURGH, 14 (2007). 

253 While for this paper we discuss transfer to a public entity, it is possible that a private or semi-private organization 

with sovereign durability could play this role as well. See Wilson et al., supra note 9. 
45

 Additionally, the regulatory framework must clarify how the transition from private 

operator to a public entity for long-term stewardship will occur. Several different models are 

possible. First, there could be a fixed time period of operator responsibility (e.g., up to and 

including 20 or 30 years of post-closure care), at which time project responsibility would be 

passed to a public entity. This approach, however, might not provide sufficient incentives for 

responsible risk management. A better option would be to create a performance-based measure 

that would initiate the site transfer when, for example, site pressures decrease to a specified 

threshold and reservoir models accurately predict CO2 behavior underground. We believe that a 

performance-based measure is preferable as it allows site-specific risk criteria to be incorporated 

into the decision to transfer responsibility. The advantage of this approach is that it has the 

potential to provide incentives for good site selection and operation and allows the operator to 

actively manage long-term liability. Whether the transition metric is time or performance-based, 

any transition to public responsibility must be accompanied by sufficient funds to cover costs of 

long-term stewardship. This issue is discussed below.

B. Establishing a System of Financial Responsibility and Assurance over the CCS Life-cycle 

 Any transition to public responsibility of CCS projects must be accompanied by funds 

which cover costs of long-term stewardship. In addition to stimulating early CCS demonstration 

projects through the use of trust funds,254 several papers255 have proposed different funding 

models to ensure resources are available for post-closure and long-term stewardship phases of 

the CCS life-cycle. The basic model would use normal operational insurance to cover CCS 

projects during the active injection phase and post-closure phase. Additionally, during the 

injection phase, a fee is collected, based either on a per-ton injected basis or, preferably, a riskweighted per ton fee, and pooled to cover costs of long-term stewardship by a public entity. This 

approach has the advantage of synchronizing CCS project income and payment schemes. 

 

 We propose establishment of a three-tired payment system that covers: (1) the active CO2

injection phase; (2) the post-closure period; and (3) long-term stewardship. During active CO2

injection, the CCS project operator holds insurance and site liability and she pays into a central 

fund, as pre-payment for long-term stewardship. Having this pool held at a federal level will 

help to spread risk across different geologic basins. In the second phase, the post-closure period, 

the operator is still responsible for site monitoring, verification, and necessary remediation, and 

is fully liable for damages under CCS-specific legislation that is enacted, existing federal 

environmental law, or state common law or statutory law. During this phase, bonding or 

insurance mechanisms could effectively be used to cover monitoring and necessary remediation. 

If an industry-funded pool were created, these funds could be used to ensure adequate cover for 

any damages sustained above individual operator liability caps set within the fund (similar to the 

OPA).256 When the CCS site meets pre-determined performance based measures it then transfers 

 

254 See generally Naomi Peña & Edward S. Rubin, A Trust Fund Approach to Accelerating Deployment of CCS: 

Options and Considerations, COAL INITIATIVE REPORTS, WHITE PAPER SERIES, PEW CENTER ON GLOBAL CLIMATE 

CHANGE (2008). 

255 See generally IOGCC, supra note 8; Ulardic supra note 186; Peña & Rubin, supra note 254. 

256 See supra Part IV.E. 
46

to the third phase. In the third phase, covering long-term stewardship, any necessary monitoring, 

remediation and damages are funded from the federal pool, financed by the performance-based 

fees collected during the active injection phase. This pool could be administered by a public or 

semi-private entity and would be responsible for ensuring management and data of CCS 

injection sites is supported and available in perpetuity. The advantage of having this pool 

financed at the federal, as opposed to state level is two fold. First, risks of leakage or damage 

may be correlated with certain geologic formations, and this approach would spread the risk 

more widely. Second, if this pool were linked to a site-specific damage cap, federal standards 

would provide regulatory consistency and could avoid “race to the bottom” problems outlined in 

Part III. 

C. Creating an Adaptive Regulatory Framework 

Because subsurface geology is heterogeneous, the behavior of CO2 within and between 

CCS sites—and the resulting risks—will vary substantially. Variation in risk across sites will 

depend both on CO2 behavior in the subsurface and surface ecological and human health

considerations. It will only be possible to assess geologic site performance (and CO2 behavior) 

during and after CO2 injection. While mapping and modeling of CCS sites will be a major 

component of siting and permitting, incorporating actual site performance data into CO2

dispersion models—not currently practiced for underground injection activities—will help 

operators, regulators, and insurance underwriters predict site performance and manage risk. 

Such adaptive approaches incorporating actual data into management and subsequent regulation 

are regularly used in ecosystem management.257

To create an adaptive regulatory approach for CCS, site performance data must be 

integrated into site management and monitoring. We propose a modified “true-up,” linked to a 

mechanical integrity test schedule.258 Under this system, every five years or with any significant 

project change (extra wells drilled, more CO2 injected, or other modifications) new and 

additional site data would be incorporated into site models, verifying the models and providing 

updated risk assessments and, if necessary allowing operators the chance to change site 

management. After these “true-up” periods, the amount paid into the long-term stewardship 

fund would be adjusted to reflect a more accurate level of site risk, with riskier sites paying more 

and lower risk sites paying proportionally less into the long-term management fund. Such an 

approach has three benefits. First, additional information will help risk management over the 

CCS life-cycle and allow for bond and insurance premiums to be correctly set. Second, 

additional information gathered during “true-ups” will lower asymmetric information gaps 

between regulators and site operators, which is important for site transfer to public management. 

Third, if correctly set, risk-based premiums will help to establish incentives for good site 

selection, responsible management and adequate monitoring and verification. 

If properly structured, liability and risk can help to motivate responsible CCS site 

selection and project management. Incorporating site information can lead to better risk 

management, and this approach allows site managers to stimulate risk-reducing behaviors and 

 

257 See generally KAI N. LEE, COMPASS AND GYROSCOPE: INTEGRATING SCIENCE AND POLITICS FOR THE 

ENVIRONMENT (ISLAND PRESS 1994). 

258 40 C.F.R. §146.8(b)(2). 
47

provide incentives for site selection with better performance characteristics. This information 

will help to ensure that insurance premiums and bond amounts are tailored to the actual risks 

posed by the site, and that data is available for the eventual site transfer to a public entity for 

long-term stewardship. Integrating adaptive management approaches with risk management, 

supports a regime with adequate financial responsibility to manage liability and enhances public 

confidence in CCS technology. 

Separate from this phased liability and funding approach is the issue of how to encourage 

the development of the first CCS “pilot” projects. For those projects, Congress could create a 

special federal fund with a damage cap that allows claimants to recovery on a strict liability basis 

with the operator paying only the lowered damage cap and the federal government paying the 

rest. Like the OPA, however, claimants could resort to tort and environmental law for any 

damages not covered by the fund. So long as enough money is paid into the fund, Congress and 

operators can limit the amount any one operator may be responsible for any particular claim. 

In sum, this approach contemplates potential damage caps on operator liability (with 

associated federal funding for damages or remediation in excess of the cap), for selected CCS 

pilot projects to encourage technology development. After the first several projects have been 

established, those caps would be raised to the risk-based site specific caps described above, and 

operators would be subject to existing tort and environmental statutory liability (along with 

liability under any CCS-specific legislation), coupled with pooled federal funding, insurance, and 

bonding. This system would remain in place until the project began the long-term stewardship 

phase, at which time any necessary monitoring, remediation and damages would be funded 

exclusively from the federal pool, financed by the performance-based fees collected during the 

active injection phase. As a result, the federal government would take on a larger compensation 

burden in cases of harm in pilot projects throughout the CCS life-cycle, and for the long-term 

stewardship phase of all CCS projects. 

This graduated and risk-based structure is designed to both encourage CCS development 

and ensure incentives are in place to encourage safe site-selection and project operation as well 

as compensate those who may be harmed by CO2 storage. In the end, there are certainly risks 

associated with CCS and the long-term storage of CO2. There are also, however, significant 

risks of climate change. Although there are many possible ways to deal with climate change, 

CCS is a technology that has the potential to play a major role in addressing climate change 

before reliable substitutes for coal can be found. As a result, policymakers should encourage the 

development of this technology while at the same time taking care not to limit operator liability 

to such an extent as to unduly burden or endanger human health and the environment. 

CONCLUSION

 In this Article, we have attempted to create a framework to address liability and funding 

issues associated with the long-term storage of CO2 in connection with CCS. We propose that 

states and the federal government can encourage the development of CCS without abandoning or 

placing significant limitations on existing tort law or statutory environmental law protections. In 

order to accomplish this, we take advantage of the inherent life-cycle of CCS and the stage of 

technology deployment on a national basis. We propose a system that maintains existing tort and 
48

statutory liability for harm associated with CCS and then places on top of it a funding system 

consisting of insurance, bonding, selected damage caps (for early pilot projects only) and pooled 

federal funding to provide protection both for CCS operators and for those potentially harmed by 

CCS. Such a system can go a long way to decreasing the risks of climate change while 

managing the risks of CCS. 
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UNITED NATIONS FRAMEWORK CONVENTION 

ON CLIMATE CHANGE 

UNITED NATIONS 

1992 

FCCC/INFORMAL/84 

GE.05-62220 (E) 200705
UNITED NATIONS FRAMEWORK CONVENTION 

ON CLIMATE CHANGE 

The Parties to this Convention, 

Acknowledging that change in the Earth’s climate and its adverse effects are a common 

concern of humankind, 

Concerned that human activities have been substantially increasing the atmospheric 

concentrations of greenhouse gases, that these increases enhance the natural greenhouse effect, 

and that this will result on average in an additional warming of the Earth’s surface and 

atmosphere and may adversely affect natural ecosystems and humankind, 

Noting that the largest share of historical and current global emissions of greenhouse 

gases has originated in developed countries, that per capita emissions in developing countries are 

still relatively low and that the share of global emissions originating in developing countries will 

grow to meet their social and development needs, 

Aware of the role and importance in terrestrial and marine ecosystems of sinks and 

reservoirs of greenhouse gases, 

Noting that there are many uncertainties in predictions of climate change, particularly 

with regard to the timing, magnitude and regional patterns thereof, 

Acknowledging that the global nature of climate change calls for the widest possible 

cooperation by all countries and their participation in an effective and appropriate international 

response, in accordance with their common but differentiated responsibilities and respective 

capabilities and their social and economic conditions, 

Recalling the pertinent provisions of the Declaration of the United Nations Conference 

on the Human Environment, adopted at Stockholm on 16 June 1972, 

Recalling also that States have, in accordance with the Charter of the United Nations and 

the principles of international law, the sovereign right to exploit their own resources pursuant to 

their own environmental and developmental policies, and the responsibility to ensure that 

activities within their jurisdiction or control do not cause damage to the environment of other 

States or of areas beyond the limits of national jurisdiction, 

Reaffirming the principle of sovereignty of States in international cooperation to address 

climate change, 

Recognizing that States should enact effective environmental legislation, that 

environmental standards, management objectives and priorities should reflect the environmental 

and developmental context to which they apply, and that standards applied by some countries 

may be inappropriate and of unwarranted economic and social cost to other countries, in 

particular developing countries,
- 2 - 

Recalling the provisions of General Assembly resolution 44/228 of 22 December 1989 

on the United Nations Conference on Environment and Development, and resolutions 43/53 

of 6 December 1988, 44/207 of 22 December 1989, 45/212 of 21 December 1990 and 46/169 

of 19 December 1991 on protection of global climate for present and future generations of 

mankind, 

Recalling also the provisions of General Assembly resolution 44/206 of 

22 December 1989 on the possible adverse effects of sea-level rise on islands and coastal 

areas, particularly low-lying coastal areas and the pertinent provisions of General Assembly 

resolution 44/172 of 19 December 1989 on the implementation of the Plan of Action to 

Combat Desertification, 

Recalling further the Vienna Convention for the Protection of the Ozone Layer, 1985, 

and the Montreal Protocol on Substances that Deplete the Ozone Layer, 1987, as adjusted and 

amended on 29 June 1990, 

Noting the Ministerial Declaration of the Second World Climate Conference adopted 

on 7 November 1990, 

Conscious of the valuable analytical work being conducted by many States on climate 

change and of the important contributions of the World Meteorological Organization, the 

United Nations Environment Programme and other organs, organizations and bodies of the 

United Nations system, as well as other international and intergovernmental bodies, to the 

exchange of results of scientific research and the coordination of research, 

Recognizing that steps required to understand and address climate change will be 

environmentally, socially and economically most effective if they are based on relevant 

scientific, technical and economic considerations and continually re-evaluated in the light of 

new findings in these areas, 

Recognizing that various actions to address climate change can be justified economically 

in their own right and can also help in solving other environmental problems, 

Recognizing also the need for developed countries to take immediate action in a flexible 

manner on the basis of clear priorities, as a first step towards comprehensive response strategies 

at the global, national and, where agreed, regional levels that take into account all greenhouse 

gases, with due consideration of their relative contributions to the enhancement of the 

greenhouse effect, 

Recognizing further that low-lying and other small island countries, countries with 

low-lying coastal, arid and semi-arid areas or areas liable to floods, drought and desertification, 

and developing countries with fragile mountainous ecosystems are particularly vulnerable to the 

adverse effects of climate change, 

Recognizing the special difficulties of those countries, especially developing countries, 

whose economies are particularly dependent on fossil fuel production, use and exportation, as a 

consequence of action taken on limiting greenhouse gas emissions, 
- 3 - 

Affirming that responses to climate change should be coordinated with social and 

economic development in an integrated manner with a view to avoiding adverse impacts on 

the latter, taking into full account the legitimate priority needs of developing countries for the 

achievement of sustained economic growth and the eradication of poverty, 

Recognizing that all countries, especially developing countries, need access to resources 

required to achieve sustainable social and economic development and that, in order for 

developing countries to progress towards that goal, their energy consumption will need to grow 

taking into account the possibilities for achieving greater energy efficiency and for controlling 

greenhouse gas emissions in general, including through the application of new technologies on 

terms which make such an application economically and socially beneficial, 

Determined to protect the climate system for present and future generations, 

Have agreed as follows: 

Article 1 

DEFINITIONS*

 For the purposes of this Convention: 

1. “Adverse effects of climate change” means changes in the physical environment or biota 

resulting from climate change which have significant deleterious effects on the composition, 

resilience or productivity of natural and managed ecosystems or on the operation of 

socio-economic systems or on human health and welfare. 

2. “Climate change” means a change of climate which is attributed directly or indirectly to 

human activity that alters the composition of the global atmosphere and which is in addition to 

natural climate variability observed over comparable time periods. 

3. “Climate system” means the totality of the atmosphere, hydrosphere, biosphere and 

geosphere and their interactions. 

4. “Emissions” means the release of greenhouse gases and/or their precursors into the 

atmosphere over a specified area and period of time. 

5. “Greenhouse gases” means those gaseous constituents of the atmosphere, both natural 

and anthropogenic, that absorb and re-emit infrared radiation. 

6. “Regional economic integration organization” means an organization constituted by 

sovereign States of a given region which has competence in respect of matters governed by this 

Convention or its protocols and has been duly authorized, in accordance with its internal 

procedures, to sign, ratify, accept, approve or accede to the instruments concerned. 

 

* Titles of articles are included solely to assist the reader. 
- 4 - 

7. “Reservoir” means a component or components of the climate system where a 

greenhouse gas or a precursor of a greenhouse gas is stored. 

8. “Sink” means any process, activity or mechanism which removes a greenhouse gas, an 

aerosol or a precursor of a greenhouse gas from the atmosphere. 

9. “Source” means any process or activity which releases a greenhouse gas, an aerosol or a 

precursor of a greenhouse gas into the atmosphere. 

Article 2 

OBJECTIVE 

 The ultimate objective of this Convention and any related legal instruments that the 

Conference of the Parties may adopt is to achieve, in accordance with the relevant provisions of 

the Convention, stabilization of greenhouse gas concentrations in the atmosphere at a level that 

would prevent dangerous anthropogenic interference with the climate system. Such a level 

should be achieved within a time frame sufficient to allow ecosystems to adapt naturally to 

climate change, to ensure that food production is not threatened and to enable economic 

development to proceed in a sustainable manner. 

Article 3 

PRINCIPLES 

 In their actions to achieve the objective of the Convention and to implement its 

provisions, the Parties shall be guided, inter alia, by the following: 

1. The Parties should protect the climate system for the benefit of present and future 

generations of humankind, on the basis of equity and in accordance with their common but 

differentiated responsibilities and respective capabilities. Accordingly, the developed country 

Parties should take the lead in combating climate change and the adverse effects thereof. 

2. The specific needs and special circumstances of developing country Parties, especially 

those that are particularly vulnerable to the adverse effects of climate change, and of those 

Parties, especially developing country Parties, that would have to bear a disproportionate or 

abnormal burden under the Convention, should be given full consideration. 

3. The Parties should take precautionary measures to anticipate, prevent or minimize the 

causes of climate change and mitigate its adverse effects. Where there are threats of serious or 

irreversible damage, lack of full scientific certainty should not be used as a reason for postponing 

such measures, taking into account that policies and measures to deal with climate change should 

be cost-effective so as to ensure global benefits at the lowest possible cost. To achieve this, 

such policies and measures should take into account different socio-economic contexts, be 

comprehensive, cover all relevant sources, sinks and reservoirs of greenhouse gases and 

adaptation, and comprise all economic sectors. Efforts to address climate change may be carried 

out cooperatively by interested Parties.
- 5 - 

4. The Parties have a right to, and should, promote sustainable development. Policies and 

measures to protect the climate system against human-induced change should be appropriate 

for the specific conditions of each Party and should be integrated with national development 

programmes, taking into account that economic development is essential for adopting measures 

to address climate change. 

5. The Parties should cooperate to promote a supportive and open international economic 

system that would lead to sustainable economic growth and development in all Parties, 

particularly developing country Parties, thus enabling them better to address the problems of 

climate change. Measures taken to combat climate change, including unilateral ones, should not 

constitute a means of arbitrary or unjustifiable discrimination or a disguised restriction on 

international trade. 

Article 4 

COMMITMENTS 

1. All Parties, taking into account their common but differentiated responsibilities and their 

specific national and regional development priorities, objectives and circumstances, shall: 

 (a) Develop, periodically update, publish and make available to the Conference of 

the Parties, in accordance with Article 12, national inventories of anthropogenic emissions by 

sources and removals by sinks of all greenhouse gases not controlled by the Montreal Protocol, 

using comparable methodologies to be agreed upon by the Conference of the Parties; 

 (b) Formulate, implement, publish and regularly update national and, where 

appropriate, regional programmes containing measures to mitigate climate change by 

addressing anthropogenic emissions by sources and removals by sinks of all greenhouse gases 

not controlled by the Montreal Protocol, and measures to facilitate adequate adaptation to 

climate change; 

 (c) Promote and cooperate in the development, application and diffusion, 

including transfer, of technologies, practices and processes that control, reduce or prevent 

anthropogenic emissions of greenhouse gases not controlled by the Montreal Protocol in all 

relevant sectors, including the energy, transport, industry, agriculture, forestry and waste 

management sectors; 

 (d) Promote sustainable management, and promote and cooperate in the conservation 

and enhancement, as appropriate, of sinks and reservoirs of all greenhouse gases not controlled 

by the Montreal Protocol, including biomass, forests and oceans as well as other terrestrial, 

coastal and marine ecosystems; 

 (e) Cooperate in preparing for adaptation to the impacts of climate change; develop 

and elaborate appropriate and integrated plans for coastal zone management, water resources and 

agriculture, and for the protection and rehabilitation of areas, particularly in Africa, affected by 

drought and desertification, as well as floods;
- 6 - 

 (f) Take climate change considerations into account, to the extent feasible, in their 

relevant social, economic and environmental policies and actions, and employ appropriate 

methods, for example impact assessments, formulated and determined nationally, with a view 

to minimizing adverse effects on the economy, on public health and on the quality of 

the environment, of projects or measures undertaken by them to mitigate or adapt to climate 

change; 

 (g) Promote and cooperate in scientific, technological, technical, socio-economic and 

other research, systematic observation and development of data archives related to the climate 

system and intended to further the understanding and to reduce or eliminate the remaining 

uncertainties regarding the causes, effects, magnitude and timing of climate change and the 

economic and social consequences of various response strategies; 

 (h) Promote and cooperate in the full, open and prompt exchange of relevant 

scientific, technological, technical, socio-economic and legal information related to the climate 

system and climate change, and to the economic and social consequences of various response 

strategies; 

 (i) Promote and cooperate in education, training and public awareness related to 

climate change and encourage the widest participation in this process, including that of 

non-governmental organizations; and 

 (j) Communicate to the Conference of the Parties information related to 

implementation, in accordance with Article 12. 

2. The developed country Parties and other Parties included in Annex I commit themselves 

specifically as provided for in the following: 

 (a) Each of these Parties shall adopt national1

 policies and take corresponding 

measures on the mitigation of climate change, by limiting its anthropogenic emissions of 

greenhouse gases and protecting and enhancing its greenhouse gas sinks and reservoirs. These 

policies and measures will demonstrate that developed countries are taking the lead in modifying 

longer-term trends in anthropogenic emissions consistent with the objective of the Convention, 

recognizing that the return by the end of the present decade to earlier levels of anthropogenic 

emissions of carbon dioxide and other greenhouse gases not controlled by the Montreal Protocol 

would contribute to such modification, and taking into account the differences in these Parties’ 

starting points and approaches, economic structures and resource bases, the need to maintain 

strong and sustainable economic growth, available technologies and other individual 

circumstances, as well as the need for equitable and appropriate contributions by each of these 

Parties to the global effort regarding that objective. These Parties may implement such 

policies and measures jointly with other Parties and may assist other Parties in contributing 

to the achievement of the objective of the Convention and, in particular, that of this 

subparagraph;

 

1

 This includes policies and measures adopted by regional economic integration organizations. 
- 7 - 

 (b) In order to promote progress to this end, each of these Parties shall communicate, 

within six months of the entry into force of the Convention for it and periodically thereafter, and 

in accordance with Article 12, detailed information on its policies and measures referred to in 

subparagraph (a) above, as well as on its resulting projected anthropogenic emissions by sources 

and removals by sinks of greenhouse gases not controlled by the Montreal Protocol for the 

period referred to in subparagraph (a), with the aim of returning individually or jointly to 

their 1990 levels these anthropogenic emissions of carbon dioxide and other greenhouse gases 

not controlled by the Montreal Protocol. This information will be reviewed by the Conference of 

the Parties, at its first session and periodically thereafter, in accordance with Article 7; 

 (c) Calculations of emissions by sources and removals by sinks of greenhouse gases 

for the purposes of subparagraph (b) above should take into account the best available scientific 

knowledge, including of the effective capacity of sinks and the respective contributions of such 

gases to climate change. The Conference of the Parties shall consider and agree on 

methodologies for these calculations at its first session and review them regularly thereafter; 

 (d) The Conference of the Parties shall, at its first session, review the adequacy of 

subparagraphs (a) and (b) above. Such review shall be carried out in the light of the best 

available scientific information and assessment on climate change and its impacts, as well as 

relevant technical, social and economic information. Based on this review, the Conference of 

the Parties shall take appropriate action, which may include the adoption of amendments to the 

commitments in subparagraphs (a) and (b) above. The Conference of the Parties, at its first 

session, shall also take decisions regarding criteria for joint implementation as indicated in 

subparagraph (a) above. A second review of subparagraphs (a) and (b) shall take place not later 

than 31 December 1998, and thereafter at regular intervals determined by the Conference of the 

Parties, until the objective of the Convention is met; 

 (e) Each of these Parties shall: 

(i) coordinate as appropriate with other such Parties, relevant economic and 

administrative instruments developed to achieve the objective of the 

Convention; and 

(ii) identify and periodically review its own policies and practices which 

encourage activities that lead to greater levels of anthropogenic emissions 

of greenhouse gases not controlled by the Montreal Protocol than would 

otherwise occur; 

 (f) The Conference of the Parties shall review, not later than 31 December 1998, 

available information with a view to taking decisions regarding such amendments to the lists 

in Annexes I and II as may be appropriate, with the approval of the Party concerned; 

 (g) Any Party not included in Annex I may, in its instrument of ratification, 

acceptance, approval or accession, or at any time thereafter, notify the Depositary that it intends 

to be bound by subparagraphs (a) and (b) above. The Depositary shall inform the other 

signatories and Parties of any such notification.
- 8 - 

3. The developed country Parties and other developed Parties included in Annex II shall 

provide new and additional financial resources to meet the agreed full costs incurred by 

developing country Parties in complying with their obligations under Article 12, paragraph 1. 

They shall also provide such financial resources, including for the transfer of technology, needed 

by the developing country Parties to meet the agreed full incremental costs of implementing 

measures that are covered by paragraph 1 of this Article and that are agreed between a 

developing country Party and the international entity or entities referred to in Article 11, in 

accordance with that Article. The implementation of these commitments shall take into account 

the need for adequacy and predictability in the flow of funds and the importance of appropriate 

burden sharing among the developed country Parties. 

4. The developed country Parties and other developed Parties included in Annex II shall 

also assist the developing country Parties that are particularly vulnerable to the adverse effects of 

climate change in meeting costs of adaptation to those adverse effects. 

5. The developed country Parties and other developed Parties included in Annex II shall 

take all practicable steps to promote, facilitate and finance, as appropriate, the transfer of, or 

access to, environmentally sound technologies and know-how to other Parties, particularly 

developing country Parties, to enable them to implement the provisions of the Convention. In 

this process, the developed country Parties shall support the development and enhancement of 

endogenous capacities and technologies of developing country Parties. Other Parties and 

organizations in a position to do so may also assist in facilitating the transfer of such 

technologies. 

6. In the implementation of their commitments under paragraph 2 above, a certain degree of 

flexibility shall be allowed by the Conference of the Parties to the Parties included in Annex I 

undergoing the process of transition to a market economy, in order to enhance the ability of these 

Parties to address climate change, including with regard to the historical level of anthropogenic 

emissions of greenhouse gases not controlled by the Montreal Protocol chosen as a reference. 

7. The extent to which developing country Parties will effectively implement their 

commitments under the Convention will depend on the effective implementation by developed 

country Parties of their commitments under the Convention related to financial resources and 

transfer of technology and will take fully into account that economic and social development and 

poverty eradication are the first and overriding priorities of the developing country Parties. 

8. In the implementation of the commitments in this Article, the Parties shall give full 

consideration to what actions are necessary under the Convention, including actions related to 

funding, insurance and the transfer of technology, to meet the specific needs and concerns of 

developing country Parties arising from the adverse effects of climate change and/or the impact 

of the implementation of response measures, especially on: 

 (a) Small island countries; 

 (b) Countries with low-lying coastal areas; 

 (c) Countries with arid and semi-arid areas, forested areas and areas liable to forest 

decay;
- 9 - 

 (d) Countries with areas prone to natural disasters; 

 (e) Countries with areas liable to drought and desertification; 

 (f) Countries with areas of high urban atmospheric pollution; 

 (g) Countries with areas with fragile ecosystems, including mountainous ecosystems; 

 (h) Countries whose economies are highly dependent on income generated from the 

production, processing and export, and/or on consumption of fossil fuels and associated 

energy-intensive products; and 

 (i) Landlocked and transit countries. 

Further, the Conference of the Parties may take actions, as appropriate, with respect to this 

paragraph. 

9. The Parties shall take full account of the specific needs and special situations of the least 

developed countries in their actions with regard to funding and transfer of technology. 

10. The Parties shall, in accordance with Article 10, take into consideration in the 

implementation of the commitments of the Convention the situation of Parties, particularly 

developing country Parties, with economies that are vulnerable to the adverse effects of the 

implementation of measures to respond to climate change. This applies notably to Parties with 

economies that are highly dependent on income generated from the production, processing and 

export, and/or consumption of fossil fuels and associated energy-intensive products and/or the 

use of fossil fuels for which such Parties have serious difficulties in switching to alternatives. 

Article 5 

RESEARCH AND SYSTEMATIC OBSERVATION 

 In carrying out their commitments under Article 4, paragraph 1 (g), the Parties shall: 

 (a) Support and further develop, as appropriate, international and intergovernmental 

programmes and networks or organizations aimed at defining, conducting, assessing and 

financing research, data collection and systematic observation, taking into account the need to 

minimize duplication of effort; 

 (b) Support international and intergovernmental efforts to strengthen systematic 

observation and national scientific and technical research capacities and capabilities, particularly 

in developing countries, and to promote access to, and the exchange of, data and analyses thereof 

obtained from areas beyond national jurisdiction; and 

 (c) Take into account the particular concerns and needs of developing countries and 

cooperate in improving their endogenous capacities and capabilities to participate in the efforts 

referred to in subparagraphs (a) and (b) above. 
- 10 - 

Article 6 

EDUCATION, TRAINING AND PUBLIC AWARENESS 

 In carrying out their commitments under Article 4, paragraph 1 (i), the Parties shall: 

 (a) Promote and facilitate at the national and, as appropriate, subregional and regional 

levels, and in accordance with national laws and regulations, and within their respective 

capacities: 

(i) the development and implementation of educational and public awareness 

programmes on climate change and its effects; 

(ii) public access to information on climate change and its effects; 

(iii) public participation in addressing climate change and its effects and 

developing adequate responses; and 

(iv) training of scientific, technical and managerial personnel; 

 (b) Cooperate in and promote, at the international level, and, where appropriate, using 

existing bodies: 

(i) the development and exchange of educational and public awareness 

material on climate change and its effects; and 

(ii) the development and implementation of education and training 

programmes, including the strengthening of national institutions and the 

exchange or secondment of personnel to train experts in this field, in 

particular for developing countries. 

Article 7 

CONFERENCE OF THE PARTIES 

1. A Conference of the Parties is hereby established. 

2. The Conference of the Parties, as the supreme body of this Convention, shall keep under 

regular review the implementation of the Convention and any related legal instruments that the 

Conference of the Parties may adopt, and shall make, within its mandate, the decisions necessary 

to promote the effective implementation of the Convention. To this end, it shall: 

 (a) Periodically examine the obligations of the Parties and the institutional 

arrangements under the Convention, in the light of the objective of the Convention, the 

experience gained in its implementation and the evolution of scientific and technological 

knowledge;
- 11 - 

 (b) Promote and facilitate the exchange of information on measures adopted by the 

Parties to address climate change and its effects, taking into account the differing circumstances, 

responsibilities and capabilities of the Parties and their respective commitments under the 

Convention; 

 (c) Facilitate, at the request of two or more Parties, the coordination of measures 

adopted by them to address climate change and its effects, taking into account the differing 

circumstances, responsibilities and capabilities of the Parties and their respective commitments 

under the Convention; 

 (d) Promote and guide, in accordance with the objective and provisions of the 

Convention, the development and periodic refinement of comparable methodologies, to be 

agreed on by the Conference of the Parties, inter alia, for preparing inventories of greenhouse gas 

emissions by sources and removals by sinks, and for evaluating the effectiveness of measures to 

limit the emissions and enhance the removals of these gases; 

 (e) Assess, on the basis of all information made available to it in accordance with the 

provisions of the Convention, the implementation of the Convention by the Parties, the overall 

effects of the measures taken pursuant to the Convention, in particular environmental, economic 

and social effects as well as their cumulative impacts and the extent to which progress towards 

the objective of the Convention is being achieved; 

 (f) Consider and adopt regular reports on the implementation of the Convention and 

ensure their publication; 

 (g) Make recommendations on any matters necessary for the implementation of the 

Convention; 

 (h) Seek to mobilize financial resources in accordance with Article 4, paragraphs 3, 4 

and 5, and Article 11; 

 (i) Establish such subsidiary bodies as are deemed necessary for the implementation 

of the Convention; 

 (j) Review reports submitted by its subsidiary bodies and provide guidance to them; 

 (k) Agree upon and adopt, by consensus, rules of procedure and financial rules for 

itself and for any subsidiary bodies; 

 (l) Seek and utilize, where appropriate, the services and cooperation of, and 

information provided by, competent international organizations and intergovernmental and 

non-governmental bodies; and 

 (m) Exercise such other functions as are required for the achievement of the objective 

of the Convention as well as all other functions assigned to it under the Convention.
- 12 - 

3. The Conference of the Parties shall, at its first session, adopt its own rules of procedure 

as well as those of the subsidiary bodies established by the Convention, which shall include 

decision-making procedures for matters not already covered by decision-making procedures 

stipulated in the Convention. Such procedures may include specified majorities required for the 

adoption of particular decisions. 

4. The first session of the Conference of the Parties shall be convened by the interim 

secretariat referred to in Article 21 and shall take place not later than one year after the date of 

entry into force of the Convention. Thereafter, ordinary sessions of the Conference of the Parties 

shall be held every year unless otherwise decided by the Conference of the Parties. 

5. Extraordinary sessions of the Conference of the Parties shall be held at such other times 

as may be deemed necessary by the Conference, or at the written request of any Party, provided 

that, within six months of the request being communicated to the Parties by the secretariat, it is 

supported by at least one third of the Parties. 

6. The United Nations, its specialized agencies and the International Atomic Energy 

Agency, as well as any State member thereof or observers thereto not Party to the Convention, 

may be represented at sessions of the Conference of the Parties as observers. Any body or 

agency, whether national or international, governmental or non-governmental, which is qualified 

in matters covered by the Convention, and which has informed the secretariat of its wish to be 

represented at a session of the Conference of the Parties as an observer, may be so admitted 

unless at least one third of the Parties present object. The admission and participation of 

observers shall be subject to the rules of procedure adopted by the Conference of the Parties. 

Article 8 

SECRETARIAT 

1. A secretariat is hereby established. 

2. The functions of the secretariat shall be: 

 (a) To make arrangements for sessions of the Conference of the Parties and its 

subsidiary bodies established under the Convention and to provide them with services as 

required; 

 (b) To compile and transmit reports submitted to it; 

 (c) To facilitate assistance to the Parties, particularly developing country Parties, on 

request, in the compilation and communication of information required in accordance with the 

provisions of the Convention; 

 (d) To prepare reports on its activities and present them to the Conference of the 

Parties;
- 13 - 

 (e) To ensure the necessary coordination with the secretariats of other relevant 

international bodies; 

 (f) To enter, under the overall guidance of the Conference of the Parties, into such 

administrative and contractual arrangements as may be required for the effective discharge of its 

functions; and 

 (g) To perform the other secretariat functions specified in the Convention and in any 

of its protocols and such other functions as may be determined by the Conference of the Parties. 

3. The Conference of the Parties, at its first session, shall designate a permanent secretariat 

and make arrangements for its functioning. 

Article 9 

SUBSIDIARY BODY FOR SCIENTIFIC AND 

TECHNOLOGICAL ADVICE 

1. A subsidiary body for scientific and technological advice is hereby established to provide 

the Conference of the Parties and, as appropriate, its other subsidiary bodies with timely 

information and advice on scientific and technological matters relating to the Convention. This 

body shall be open to participation by all Parties and shall be multidisciplinary. It shall comprise 

government representatives competent in the relevant field of expertise. It shall report regularly 

to the Conference of the Parties on all aspects of its work. 

2. Under the guidance of the Conference of the Parties, and drawing upon existing 

competent international bodies, this body shall: 

 (a) Provide assessments of the state of scientific knowledge relating to climate 

change and its effects; 

 (b) Prepare scientific assessments on the effects of measures taken in the 

implementation of the Convention; 

 (c) Identify innovative, efficient and state-of-the-art technologies and know-how and 

advise on the ways and means of promoting development and/or transferring such technologies; 

 (d) Provide advice on scientific programmes, international cooperation in research 

and development related to climate change, as well as on ways and means of supporting 

endogenous capacity-building in developing countries; and 

 (e) Respond to scientific, technological and methodological questions that the 

Conference of the Parties and its subsidiary bodies may put to the body. 

3. The functions and terms of reference of this body may be further elaborated by the 

Conference of the Parties. 
- 14 - 

Article 10 

SUBSIDIARY BODY FOR IMPLEMENTATION 

1. A subsidiary body for implementation is hereby established to assist the Conference of 

the Parties in the assessment and review of the effective implementation of the Convention. This 

body shall be open to participation by all Parties and comprise government representatives who 

are experts on matters related to climate change. It shall report regularly to the Conference of 

the Parties on all aspects of its work. 

2. Under the guidance of the Conference of the Parties, this body shall: 

 (a) Consider the information communicated in accordance with Article 12, 

paragraph 1, to assess the overall aggregated effect of the steps taken by the Parties in the 

light of the latest scientific assessments concerning climate change; 

 (b) Consider the information communicated in accordance with Article 12, 

paragraph 2, in order to assist the Conference of the Parties in carrying out the reviews required 

by Article 4, paragraph 2 (d); and 

 (c) Assist the Conference of the Parties, as appropriate, in the preparation and 

implementation of its decisions. 

Article 11 

FINANCIAL MECHANISM 

1. A mechanism for the provision of financial resources on a grant or concessional basis, 

including for the transfer of technology, is hereby defined. It shall function under the guidance 

of and be accountable to the Conference of the Parties, which shall decide on its policies, 

programme priorities and eligibility criteria related to this Convention. Its operation shall be 

entrusted to one or more existing international entities. 

2. The financial mechanism shall have an equitable and balanced representation of all 

Parties within a transparent system of governance. 

3. The Conference of the Parties and the entity or entities entrusted with the operation of the 

financial mechanism shall agree upon arrangements to give effect to the above paragraphs, 

which shall include the following: 

 (a) Modalities to ensure that the funded projects to address climate change are in 

conformity with the policies, programme priorities and eligibility criteria established by the 

Conference of the Parties; 

 (b) Modalities by which a particular funding decision may be reconsidered in light of 

these policies, programme priorities and eligibility criteria;
- 15 - 

 (c) Provision by the entity or entities of regular reports to the Conference of the 

Parties on its funding operations, which is consistent with the requirement for accountability set 

out in paragraph 1 above; and 

 (d) Determination in a predictable and identifiable manner of the amount of funding 

necessary and available for the implementation of this Convention and the conditions under 

which that amount shall be periodically reviewed. 

4. The Conference of the Parties shall make arrangements to implement the 

above-mentioned provisions at its first session, reviewing and taking into account the interim 

arrangements referred to in Article 21, paragraph 3, and shall decide whether these interim 

arrangements shall be maintained. Within four years thereafter, the Conference of the Parties 

shall review the financial mechanism and take appropriate measures. 

5. The developed country Parties may also provide and developing country Parties avail 

themselves of, financial resources related to the implementation of the Convention through 

bilateral, regional and other multilateral channels. 

Article 12 

COMMUNICATION OF INFORMATION RELATED 

TO IMPLEMENTATION 

1. In accordance with Article 4, paragraph 1, each Party shall communicate to the 

Conference of the Parties, through the secretariat, the following elements of information: 

 (a) A national inventory of anthropogenic emissions by sources and removals by 

sinks of all greenhouse gases not controlled by the Montreal Protocol, to the extent its capacities 

permit, using comparable methodologies to be promoted and agreed upon by the Conference of 

the Parties; 

 (b) A general description of steps taken or envisaged by the Party to implement the 

Convention; and 

 (c) Any other information that the Party considers relevant to the achievement of the 

objective of the Convention and suitable for inclusion in its communication, including, if 

feasible, material relevant for calculations of global emission trends. 

2. Each developed country Party and each other Party included in Annex I shall incorporate 

in its communication the following elements of information: 

 (a) A detailed description of the policies and measures that it has adopted to 

implement its commitment under Article 4, paragraphs 2 (a) and 2 (b); and 

 (b) A specific estimate of the effects that the policies and measures referred to in 

subparagraph (a) immediately above will have on anthropogenic emissions by its sources and 

removals by its sinks of greenhouse gases during the period referred to in Article 4, 

paragraph 2 (a). 
- 16 - 

3. In addition, each developed country Party and each other developed Party included 

in Annex II shall incorporate details of measures taken in accordance with Article 4, 

paragraphs 3, 4 and 5. 

4. Developing country Parties may, on a voluntary basis, propose projects for financing, 

including specific technologies, materials, equipment, techniques or practices that would be 

needed to implement such projects, along with, if possible, an estimate of all incremental costs, 

of the reductions of emissions and increments of removals of greenhouse gases, as well as an 

estimate of the consequent benefits. 

5. Each developed country Party and each other Party included in Annex I shall make its 

initial communication within six months of the entry into force of the Convention for that Party. 

Each Party not so listed shall make its initial communication within three years of the entry into 

force of the Convention for that Party, or of the availability of financial resources in accordance 

with Article 4, paragraph 3. Parties that are least developed countries may make their initial 

communication at their discretion. The frequency of subsequent communications by all Parties 

shall be determined by the Conference of the Parties, taking into account the differentiated 

timetable set by this paragraph. 

6. Information communicated by Parties under this Article shall be transmitted by the 

secretariat as soon as possible to the Conference of the Parties and to any subsidiary bodies 

concerned. If necessary, the procedures for the communication of information may be further 

considered by the Conference of the Parties. 

7. From its first session, the Conference of the Parties shall arrange for the provision to 

developing country Parties of technical and financial support, on request, in compiling and 

communicating information under this Article, as well as in identifying the technical and 

financial needs associated with proposed projects and response measures under Article 4. Such 

support may be provided by other Parties, by competent international organizations and by the 

secretariat, as appropriate. 

8. Any group of Parties may, subject to guidelines adopted by the Conference of the Parties, 

and to prior notification to the Conference of the Parties, make a joint communication in 

fulfilment of their obligations under this Article, provided that such a communication includes 

information on the fulfilment by each of these Parties of its individual obligations under the 

Convention. 

9. Information received by the secretariat that is designated by a Party as confidential, in 

accordance with criteria to be established by the Conference of the Parties, shall be aggregated 

by the secretariat to protect its confidentiality before being made available to any of the bodies 

involved in the communication and review of information. 

10. Subject to paragraph 9 above, and without prejudice to the ability of any Party to make 

public its communication at any time, the secretariat shall make communications by Parties 

under this Article publicly available at the time they are submitted to the Conference of the 

Parties. 
- 17 - 

Article 13 

RESOLUTION OF QUESTIONS REGARDING IMPLEMENTATION 

 The Conference of the Parties shall, at its first session, consider the establishment of a 

multilateral consultative process, available to Parties on their request, for the resolution of 

questions regarding the implementation of the Convention. 

Article 14 

SETTLEMENT OF DISPUTES 

1. In the event of a dispute between any two or more Parties concerning the interpretation or 

application of the Convention, the Parties concerned shall seek a settlement of the dispute 

through negotiation or any other peaceful means of their own choice. 

2. When ratifying, accepting, approving or acceding to the Convention, or at any time 

thereafter, a Party which is not a regional economic integration organization may declare in a 

written instrument submitted to the Depositary that, in respect of any dispute concerning the 

interpretation or application of the Convention, it recognizes as compulsory ipso facto and 

without special agreement, in relation to any Party accepting the same obligation: 

 (a) Submission of the dispute to the International Court of Justice; and/or 

 (b) Arbitration in accordance with procedures to be adopted by the Conference of the 

Parties as soon as practicable, in an annex on arbitration. 

A Party which is a regional economic integration organization may make a declaration with like 

effect in relation to arbitration in accordance with the procedures referred to in subparagraph (b) 

above. 

3. A declaration made under paragraph 2 above shall remain in force until it expires in 

accordance with its terms or until three months after written notice of its revocation has been 

deposited with the Depositary. 

4. A new declaration, a notice of revocation or the expiry of a declaration shall not in any 

way affect proceedings pending before the International Court of Justice or the arbitral tribunal, 

unless the parties to the dispute otherwise agree. 

5. Subject to the operation of paragraph 2 above, if after twelve months following 

notification by one Party to another that a dispute exists between them, the Parties concerned 

have not been able to settle their dispute through the means mentioned in paragraph 1 above, the 

dispute shall be submitted, at the request of any of the parties to the dispute, to conciliation. 

6. A conciliation commission shall be created upon the request of one of the parties to the 

dispute. The commission shall be composed of an equal number of members appointed by each 

party concerned and a chairman chosen jointly by the members appointed by each party. The 

commission shall render a recommendatory award, which the parties shall consider in good faith. 
- 18 - 

7. Additional procedures relating to conciliation shall be adopted by the Conference of the 

Parties, as soon as practicable, in an annex on conciliation. 

8. The provisions of this Article shall apply to any related legal instrument which the 

Conference of the Parties may adopt, unless the instrument provides otherwise. 

Article 15 

AMENDMENTS TO THE CONVENTION 

1. Any Party may propose amendments to the Convention. 

2. Amendments to the Convention shall be adopted at an ordinary session of the Conference 

of the Parties. The text of any proposed amendment to the Convention shall be communicated to 

the Parties by the secretariat at least six months before the meeting at which it is proposed for 

adoption. The secretariat shall also communicate proposed amendments to the signatories to the 

Convention and, for information, to the Depositary. 

3. The Parties shall make every effort to reach agreement on any proposed amendment to 

the Convention by consensus. If all efforts at consensus have been exhausted, and no agreement 

reached, the amendment shall as a last resort be adopted by a three-fourths majority vote of the 

Parties present and voting at the meeting. The adopted amendment shall be communicated by 

the secretariat to the Depositary, who shall circulate it to all Parties for their acceptance. 

4. Instruments of acceptance in respect of an amendment shall be deposited with the 

Depositary. An amendment adopted in accordance with paragraph 3 above shall enter into 

force for those Parties having accepted it on the ninetieth day after the date of receipt by the 

Depositary of an instrument of acceptance by at least three fourths of the Parties to the 

Convention. 

5. The amendment shall enter into force for any other Party on the ninetieth day after the 

date on which that Party deposits with the Depositary its instrument of acceptance of the said 

amendment. 

6. For the purposes of this Article, “Parties present and voting” means Parties present and 

casting an affirmative or negative vote. 

Article 16 

ADOPTION AND AMENDMENT OF ANNEXES TO THE CONVENTION 

1. Annexes to the Convention shall form an integral part thereof and, unless otherwise 

expressly provided, a reference to the Convention constitutes at the same time a reference to any 

annexes thereto. Without prejudice to the provisions of Article 14, paragraphs 2 (b) and 7, such 

annexes shall be restricted to lists, forms and any other material of a descriptive nature that is of 

a scientific, technical, procedural or administrative character.
- 19 - 

2. Annexes to the Convention shall be proposed and adopted in accordance with the 

procedure set forth in Article 15, paragraphs 2, 3 and 4. 

3. An annex that has been adopted in accordance with paragraph 2 above shall enter into 

force for all Parties to the Convention six months after the date of the communication by the 

Depositary to such Parties of the adoption of the annex, except for those Parties that have 

notified the Depositary, in writing, within that period of their non-acceptance of the annex. The 

annex shall enter into force for Parties which withdraw their notification of non-acceptance on 

the ninetieth day after the date on which withdrawal of such notification has been received by the 

Depositary. 

4. The proposal, adoption and entry into force of amendments to annexes to the Convention 

shall be subject to the same procedure as that for the proposal, adoption and entry into force of 

annexes to the Convention in accordance with paragraphs 2 and 3 above. 

5. If the adoption of an annex or an amendment to an annex involves an amendment to the 

Convention, that annex or amendment to an annex shall not enter into force until such time as the 

amendment to the Convention enters into force. 

Article 17 

PROTOCOLS 

1. The Conference of the Parties may, at any ordinary session, adopt protocols to the 

Convention. 

2. The text of any proposed protocol shall be communicated to the Parties by the secretariat 

at least six months before such a session. 

3. The requirements for the entry into force of any protocol shall be established by that 

instrument. 

4. Only Parties to the Convention may be Parties to a protocol. 

5. Decisions under any protocol shall be taken only by the Parties to the protocol concerned. 

Article 18 

RIGHT TO VOTE 

1. Each Party to the Convention shall have one vote, except as provided for in paragraph 2 

below. 

2. Regional economic integration organizations, in matters within their competence, shall 

exercise their right to vote with a number of votes equal to the number of their member States 

that are Parties to the Convention. Such an organization shall not exercise its right to vote if any 

of its member States exercises its right, and vice versa. 
- 20 - 

Article 19 

DEPOSITARY 

 The Secretary-General of the United Nations shall be the Depositary of the Convention 

and of protocols adopted in accordance with Article 17. 

Article 20 

SIGNATURE 

 This Convention shall be open for signature by States Members of the United Nations or 

of any of its specialized agencies or that are Parties to the Statute of the International Court of 

Justice and by regional economic integration organizations at Rio de Janeiro, during the 

United Nations Conference on Environment and Development, and thereafter at United Nations 

Headquarters in New York from 20 June 1992 to 19 June 1993. 

Article 21 

INTERIM ARRANGEMENTS 

1. The secretariat functions referred to in Article 8 will be carried out on an interim 

basis by the secretariat established by the General Assembly of the United Nations in its 

resolution 45/212 of 21 December 1990, until the completion of the first session of the 

Conference of the Parties. 

2. The head of the interim secretariat referred to in paragraph 1 above will cooperate closely 

with the Intergovernmental Panel on Climate Change to ensure that the Panel can respond to the 

need for objective scientific and technical advice. Other relevant scientific bodies could also be 

consulted. 

3. The Global Environment Facility of the United Nations Development Programme, the 

United Nations Environment Programme and the International Bank for Reconstruction and 

Development shall be the international entity entrusted with the operation of the financial 

mechanism referred to in Article 11 on an interim basis. In this connection, the Global 

Environment Facility should be appropriately restructured and its membership made universal to 

enable it to fulfil the requirements of Article 11. 

Article 22 

RATIFICATION, ACCEPTANCE, APPROVAL OR ACCESSION 

1. The Convention shall be subject to ratification, acceptance, approval or accession by 

States and by regional economic integration organizations. It shall be open for accession from 

the day after the date on which the Convention is closed for signature. Instruments of 

ratification, acceptance, approval or accession shall be deposited with the Depositary.
- 21 - 

2. Any regional economic integration organization which becomes a Party to the 

Convention without any of its member States being a Party shall be bound by all the obligations 

under the Convention. In the case of such organizations, one or more of whose member States is 

a Party to the Convention, the organization and its member States shall decide on their respective 

responsibilities for the performance of their obligations under the Convention. In such cases, the 

organization and the member States shall not be entitled to exercise rights under the Convention 

concurrently. 

3. In their instruments of ratification, acceptance, approval or accession, regional economic 

integration organizations shall declare the extent of their competence with respect to the matters 

governed by the Convention. These organizations shall also inform the Depositary, who shall in 

turn inform the Parties, of any substantial modification in the extent of their competence. 

Article 23 

ENTRY INTO FORCE 

1. The Convention shall enter into force on the ninetieth day after the date of deposit of the 

fiftieth instrument of ratification, acceptance, approval or accession. 

2. For each State or regional economic integration organization that ratifies, accepts or 

approves the Convention or accedes thereto after the deposit of the fiftieth instrument of 

ratification, acceptance, approval or accession, the Convention shall enter into force on the 

ninetieth day after the date of deposit by such State or regional economic integration 

organization of its instrument of ratification, acceptance, approval or accession. 

3. For the purposes of paragraphs 1 and 2 above, any instrument deposited by a regional 

economic integration organization shall not be counted as additional to those deposited by States 

members of the organization. 

Article 24 

RESERVATIONS 

 No reservations may be made to the Convention. 

Article 25 

WITHDRAWAL 

1. At any time after three years from the date on which the Convention has entered into 

force for a Party, that Party may withdraw from the Convention by giving written notification to 

the Depositary. 

2. Any such withdrawal shall take effect upon expiry of one year from the date of receipt by 

the Depositary of the notification of withdrawal, or on such later date as may be specified in the 

notification of withdrawal. 

3. Any Party that withdraws from the Convention shall be considered as also having 

withdrawn from any protocol to which it is a Party. 
- 22 - 

Article 26 

AUTHENTIC TEXTS 

 The original of this Convention, of which the Arabic, Chinese, English, French, Russian 

and Spanish texts are equally authentic, shall be deposited with the Secretary-General of the 

United Nations. 

IN WITNESS WHEREOF the undersigned, being duly authorized to that effect, have 

signed this Convention. 

DONE at New York this ninth day of May one thousand nine hundred and ninety-two. 
- 23 - 

Annex I 

Australia 

Austria 

Belarusa

Belgium 

Bulgariaa

Canada 

Croatiaa * 

Czech Republica * 

Denmark 

European Economic Community 

Estoniaa

Finland 

France 

Germany 

Greece 

Hungarya

Iceland 

Ireland 

Italy 

Japan 

Latviaa

Liechtenstein*

Lithuaniaa

Luxembourg 

Monaco*

Netherlands 

New Zealand 

Norway 

Polanda

Portugal 

Romaniaa

Russian Federationa

Slovakiaa * 

Sloveniaa * 

Spain 

Sweden 

Switzerland 

Turkey 

Ukrainea

United Kingdom of Great Britain and Northern Ireland 

United States of America 

 

a

 Countries that are undergoing the process of transition to a market economy. 

* Publisher’s note: Countries added to Annex I by an amendment that entered into force 

on 13 August 1998, pursuant to decision 4/CP.3 adopted at COP.3. 
- 24 - 

Annex II 

Australia 

Austria 

Belgium 

Canada 

Denmark 

European Economic Community 

Finland 

France 

Germany 

Greece 

Iceland 

Ireland 

Italy 

Japan 

Luxembourg 

Netherlands 

New Zealand 

Norway 

Portugal 

Spain 

Sweden 

Switzerland 

United Kingdom of Great Britain and Northern Ireland 

United States of America 

Publisher’s note: Turkey was deleted from Annex II by an amendment that entered into force 

28 June 2002, pursuant to decision 26/CP.7 adopted at COP.7. 

- - - - - 
Carbon Dioxide Sequestration: 

Report on Identified Statutory and Regulatory Issues 

“A BLUEPRINT FOR THE REGULATION OF GEOLOGIC SEQUESTRATION OF 

CARBON DIOXIDE IN NEW MEXICO” 

New Mexico Energy, Minerals, Natural Resources Department 

Oil Conservation Division 

DECEMBER 1, 2007 

Pursuant to Executive Order 2006-69 

Mark E. Fesmire, PE, JD 

Adam Rankin 

David Brooks, JD 

William V. Jones, PE 
2

Table of Contents

EXECUTIVE SUMMARY......................................................................................................................4 

Identified Statutory Issues ...................................................................................................5 

Identified Regulatory Issues .............................................................................................10 

INTRODUCTION ...............................................................................................................................12 

BACKGROUND.................................................................................................................................13 

Potential Current and Future Conflicts with Subsurface Interests.....................................14 

Ownership of Geologic Formation/Pore Space & the Right to Sequester.........................15 

Long-Term Liability ..........................................................................................................16

IDENTIFIED STATUTORY ISSUES......................................................................................................17 

Authority to Regulate Carbon Sequestration .....................................................................17 

Ownership of Geologic Formation/Pore Space .................................................................17 

Depleted Oil & Gas Reservoirs......................................................................................18 

Saline Aquifers...........................................................................................................24 

Deep Coal Seams........................................................................................................26 

Subsurface Trespass ....................................................................................................26 

Unitization of Recoverable Hydrocarbons.........................................................................35 

Condemnation of Pore Space & Transportation Corridors by Eminent Domain ..............37 

Authority to Transfer Liability/Ownership to State...........................................................39 

Price-Anderson Act.....................................................................................................40 

Resource Conservation and Recovery Act........................................................................43 

Comprehensive Environmental Response, Compensation and Liability Act............................46 

Safe Drinking Water Act/Underground Injection Control Program .......................................49 

Low-Level Waste Policy Act.........................................................................................53 

Liability Analysis........................................................................................................54 

Transfer to Public Sector........................................................................................56 

Strict, Joint & Several Liability, Alternative Liability, & Insurability ..............................59 

Strict Liability .............................................................................................60 

Joint & Several Liability ...............................................................................62 

Alternative Liability .....................................................................................63 

Uninsurability .............................................................................................65 
3

Authority to Impose Sequestration Fee on Injected CO2 Volumes & Exemptions ..........65 

Authority to Bond Injection Projects & Facilities .............................................................66 

Authority to Enter Land for Inspection..............................................................................67 

Protection of Surface Owners Interests..............................................................................67 

IDENTIFIED REGULATORY ISSUES ..................................................................................................68 

General...............................................................................................................................68 

Siting & Permitting............................................................................................................68 

Drilling & Operations ........................................................................................................71

Post Injection & Closure....................................................................................................72 

Post Closure .......................................................................................................................73 
4

Executive Summary 

The Governor’s Executive Order 2006-69 requires the New Mexico Energy, Minerals, and 

Natural Resources Department (EMNRD) coordinate with a stakeholder group to explore and 

identify statutory and regulatory requirements needed to geologically sequester anthropogenic 

carbon dioxide. 

The purpose of this report is to identify the issues and challenges associated with geologic 

sequestration that must be addressed by potential statutory and regulatory changes, to identify 

questions, concerns and recommendations of the stakeholder group, to present findings and 

research for policy development, and to present proposed statutory changes and identify 

regulatory changes that must be addressed once the statutory direction is established. No attempt 

was made to address or identify challenges of carbon sequestration outside the scope of 

transportation, injection and geologic storage. 

This report is due to the Governor’s Climate Change Action Implementation Team on December 

1, 2007. 

Geologic sequestration of carbon dioxide has been identified as a technically viable means to 

significantly reduce anthropogenic emissions of the greenhouse gas carbon dioxide (CO2) over 

long timescales. Studies suggest that in appropriately selected and managed geologic reservoirs it 

is very likely that the fraction of stored CO2 will be greater than 99 percent over 100 years, and 

likely that the fraction of stored CO2 will not significantly diminish below that for the first 1,000 

years.

1

Implementation of a regulatory framework for geologic sequestration of CO2 raises numerous 

property rights, siting, monitoring, storage verification, and liability issues, including the 

following: 

 Potential Current and Future Conflicts with Subsurface and Surface Interests 

Potential conflicts with mineral estate interests, pore space and storage right owners, 

surface interests, and groundwater use may arise and must be anticipated. 

 Ownership of Geologic Formation/Pore Space and the Right to Sequester 

Ownership of the pore space must be identified and made clear so that the appropriate 

interests can be remunerated for the right to sequester, or so condemnation 

proceedings can properly advance and the proper parties compensated before any 

commercial-scale sequestration can begin. 

 Long-term Liability 

 

1 IPCC Special Report on Carbon dioxide Capture and Storage (2005) p. 246. 
5

A statutory and regulatory scheme controlling CO2 sequestration should include an 

appropriate mechanism(s) to protect public and private interests against the long-term 

liability and inherent unknowns (e.g. economic, environmental, carbon dioxide 

accounting, human health and safety, etc.) of commercial-scale carbon dioxide 

sequestration projects in order to promote development of projects and to encourage 

climate mitigation. 

Such a scheme should address the questions: Should the state retain long-term 

liability (i.e. monitoring, measurement, and mitigation responsibilities, including 

personal and property damages) of all sequestration projects or a limited number of 

initial projects to promote industry and commercial participation? Should the state 

take on only those projects demonstrated to be performing as predicted to encourage 

careful and proper site selection? What is the best means to fund the state’s long-term 

liability should it opt to take on the long-term liability and ownership of sequestration 

projects? Or, should industry retain liability with liability modeled on one or more of 

current federal environmental liability schemes?

To address the potential conflicts and uncertainties outlined above and to ensure the viability and 

success of any commercial-scale carbon sequestration project, several statutory changes would 

be necessary to address a variety of issues. 

Identified Statutory Issues:

 Authority to Regulate Carbon Sequestration 

OCD currently is tasked with regulating the injection of CO2 into oil and gas 

reservoirs for the purposes of enhancing hydrocarbon recovery, prevention of CO2 

waste, and for disposal (such as acid gas injection). OCD also has the authority to 

require that CO2 be injected, even after the possibility of enhanced production has 

elapsed, to prevent the waste of CO2 that would otherwise be vented. Further, OCD 

also regulates naturally occurring CO2 and may require injection not limited to oil 

and gas reservoirs if the CO2 is a product of or used in oil and gas operations. 

However, there exists no clear authority for the state to regulate anthropogenic CO2 

injection for sequestration purposes alone, nor does it have general authority to 

regulate injection/sequestration of CO2 not produced in oil and gas operations into 

reservoirs other than those that produce oil and gas. 

Because oil and gas reservoirs are anticipated to ultimately constitute only a small 

fraction of the total sequestration volumes in New Mexico, clear authority to regulate 

the sequestration of anthropogenic CO2 into all potential geologic reservoirs, not 

limited to productive oil and gas reservoirs, for purposes of long-term/permanent 

sequestration is essential to any regulatory framework for commercial-scale geologic 

sequestration. 
6

 Ownership of Geologic Formation/Pore Space 

Pore space evacuated by the extraction of oil and gas minerals likely belongs not to 

the mineral interest but to the surface owner, who would have the sole power to grant 

storage rights for the purpose of sequestering carbon dioxide. New Mexico case law 

does not address the question of storage rights directly, but does hold that the mineral 

interest does not include the solids of the earth. 

The holdings of several other cases reinforce that New Mexico retains a preference 

for the majority view that the mineral estate includes only the oil and gas native to the 

formation, and not rights to the formation or the pore space itself, unless the 

conveyance or severance of the mineral estate explicitly states otherwise. Therefore, 

the surface owner likely retains possession of the pore space/geologic formation and 

the sole right to store non-native gas in the evacuated space, but perhaps only after the 

mineral estate has been removed or depleted. 

Clear statutory language defining the extent of surface ownership of the pore space 

and mineral estate interests could potentially avoid unnecessary litigation on this 

point. 

 Unitization of Recoverable Hydrocarbons 

To account for the enhanced recovery anticipated from injecting CO2 into depleted 

oil and gas pools, it will be necessary to unitize such pools by voluntary agreement 

among the pool operators or through an Oil Conservation Division order compelling 

it, to provide a process to equitably allocate costs and production among the various 

mineral interests. 

The authority granted by the Statutory Unitization Act currently provides for 

voluntary or compulsory unitization of a pool or part of a pool. OCD can only compel 

unitization when three-quarters of the interests consent. This may prove to provide an 

unacceptable means of blocking planned sequestration projects, as minority interests 

could refuse to ratify unitization orders, making the operation of the unit as a 

sequestration project difficult. 

Under an effective CO2 sequestration program it is anticipated that OCD would need 

to unitize larger areas than is now the practice. While not definitive, the language in 

the Unitization Act may be flexible enough to allow OCD to properly unitize pools of 

adequate size. 

The Act also requires OCD to find that unitization will “substantially increase the 

ultimate recovery of oil and gas from the pool or unitized portion thereof.” Because 

substantially increased recovery may not always be the result in a program designed 

primarily for the sequestration of CO2, this language may pose a barrier. 
7

The Act further requires OCD to find “that the estimated additional costs, if any, of 

conducting such operations will not exceed the estimated value of the additional oil 

and gas so recovered plus a reasonable profit.” Interpreted to mean the costs of 

production of additional hydrocarbons (CO2 separation and re-injection/cycling, etc.) 

as opposed to the costs of the entire sequestration project, this language may not pose 

a barrier, but the statute may need to be clarified. 

Also, statutory continuation of expiring leases may be considered to facilitate preproject planning of CO2 sequestration projects. 

Unitization of federal minerals with non-federal minerals is provided for in the 

federal “Mineral Leasing Act,” and must be approved by the Secretary of the Interior 

for the purpose of more properly conserving the oil and gas resources. 

 Condemnation of Storage Space and Transportation Corridors by Eminent Domain 

Subsurface storage space and surface easements for pipelines and injection facilities 

will be necessary for a large-scale sequestration effort. There will be significant upfront costs associated with the projects, and there will have to be some certainty that 

an operator who makes those investments will not be prevented from completing the 

project by not having the authority to condemn minority interests. 

No authority exists under current law to provide for the acquisition by eminent 

domain of subsurface pore space for the purposes of CO2 sequestration. Authority to 

condemn subterranean storage space, similar to current statutory provisions 

authorizing the condemnation of underground storage space for natural gas, would be 

necessary for CO2 sequestration operators to acquire the storage rights from property 

owners with whom they have not reached an agreement, however, the scale for 

sequestration will be significantly greater that gas storage projects. 

Authority currently exists to condemn surface land for pipeline construction, 

including CO2 pipelines. This provision applies only to trunk lines, or primary 

transportation lines, and not to gathering lines. 70-3A-1 et seq. establishes the means 

by which easements for smaller disposal lines and gathering lines may be acquired 

across private property. 

 Long-term liability 

The various forms of liability (e.g. economic and environmental) inherent in proposed 

sequestration projects and how they will be addressed within a given regulatory 

framework are perceived as being significant factors in making sequestration projects 

feasible and for attaining public acceptance of the technologies, processes and 

regulations. 

Sufficient financial assurances and appropriate and reasonable liability standards 

together with thorough, clear and reasonable regulations can create the required 
8

degree of certainty and predictability necessary for insurers to offer adequate 

coverage in this new and unexplored field and for operators to develop realistic 

business models. 

Similarly, sufficient financial assurances and a properly scaled liability standard, 

combined with protective regulations, can also instill confidence in the public that the 

state can manage and control this largely untested field while providing adequate 

protections and ensuring a mechanism for compensation and environmental 

mitigation should accidents occur. Further, developing the right level of legal liability 

can create in insurers an additional layer of regulatory oversight beyond what the 

state itself could otherwise provide. All of this must be accomplished without placing 

an undue financial burden on the industry, stifling development of carbon dioxide 

sequestration projects, which are viewed as an important component of the state’s 

climate change mitigation strategy. 

Liability and financial assurance can be accommodated on essentially four levels: (1) 

the federal government; (2) state government; (3) industry; or (4) the individual 

corporation or owner/operator. 

Short-term liabilities inherent in any drilling or injection project can likely be best 

addressed through the contractual arrangements between CO2 generator and injector. 

But liabilities following the injection and closure phases of the projects present a 

unique problem given the long-term economic and environmental unknowns and the 

anticipated scale of sequestration projects, both in terms of time and space, required 

for successful CO2 mitigation. 

Much of the sequestration literature assumes that long-term liability must be 

transferred to the public sector to maintain economic viability and to encourage 

industry participation. 

However, such transfer of liability raises concerns that with limited liability, 

operators may have a reduced incentive to ensure sequestration is successful beyond 

the endurance of their direct liability. Another difficulty would be determining what 

level of funding would be necessary for a post-closure fund that would be used to 

cover the costs of monitoring, verification, mitigation and liability. As no true 

precedent exists with which to determine adequate and reasonable funding levels for 

the areal extent and duration contemplated for sequestration projects, this factor will 

pose a significant planning and actuarial challenge. 

Alternatives include having the state accept liability for a limited number of projects 

(e.g. the first enhanced oil recovery project, the first deep saline project, the first deep 

coal project, etc.) or for a limited time frame (e.g. projects permitted during the first 

five years of CO2 sequestration), or for injectors and the carbon sequestration 

industry to retain ownership and liability with coverage provided by some 

combination of individual liability, insurance, or an industry-funded trust fund. 
9

Transfer of liability and ownership of injected CO2 to the state

Transfer of liability to the state would require the authority to impose a sequestration 

fee on injected CO2 volumes in order to fund the state’s future liabilities, monitoring, 

measurement and verification (MMV)obligations. 

Liability for injected CO2

The injectors liability can be modeled on any one or a combination of programs such 

as the Price Anderson Act, CERCLA, the Safe Drinking Water Act’s Underground 

Injection Control Program, the Low-Level Radioactive Policy Act or on traditional 

private insurance options. 

One possible liability scheme could include some or all of the following: 

• Statutorily imposed strict liability for extraordinary occurrences, e.g. for 

contamination of protected groundwater sources, or for catastrophic releases 

(above a certain volume) of CO2 to the atmosphere or to non-storage 

formations. 

• Negligence standard for all other events and occurrences. 

• Imposition of strict liability for total response costs if willful misconduct or 

willful negligence is proven, or if the event was due to a violation of some 

applicable standard or regulation or if the operator failed to provide reasonable 

assistance with response operations. 

• Creation of an industry-funded pool with deferred premiums for accident 

coverage and environmental mitigation costs that exceed an individual’s 

insurance liability. 

• Demonstration of financial assurance for insurance and industry-funded 

deferred premiums. 

• Creation of a closure and post-closure trust fund (measuring, monitoring, 

mitigation and accidents (property and human health)), paid on a per-volumeinjected basis. 

• Declaration in the permit of who the primary responsible parties will be and 

who will bear the liability. 

• Limitation of defenses, as in CERCLA, to: 1) act of God; 2) act of war; and 3) 

an act or omission on the part of a third party or agent if the Defendant 

exercised due care to address precautions against potential consequences of 

third party acts or omissions that could have been reasonably foreseen to result. 

• Financial assurance for plugging and abandonment of individual wells, as well 

as the injection project as a whole, based on an approved cost estimate (updated 

and maintained annually by the injector). 

• Submission of a closure plan and post-closure plan for review and approval by 

the Division. 

 Authority to Bond Injection Projects & Facilities 
10

Aside from the costs associated with post-closure MMV and potential mitigation, are 

the costs associated with reclaiming project sites and facilities following injector 

abandonment or insolvency. The state would need to ensure that injectors provide 

adequate financial assurance to cover the cost of any necessary plugging, reclamation 

or mitigation required as a result of abandonment or insolvency. 

 Authority to Enter Land for Inspection Purposes 

The state will need clear authority to enter surface estates to inspect facilities and the 

integrity and functioning of injection wells and other bore holes that may penetrate 

the CO2 sequestration zone. And in the event of the transfer of ownership/liability to 

the state, the Division will require authority to enter surface properties to plug 

abandoned wells and reclaim sequestration surface facilities. 

 Protection of Surface Owner Interests 

The Surface Owners Protection Act applies only to exploration, drilling or production 

of oil and gas, and would need to be amended to include activities related to the 

sequestration of carbon dioxide to adequately protect the interests of surface owners 

in the same way they are currently protected during and after oil and gas production. 

Identified Regulatory Issues

Regulatory changes will be necessary to impliment the statutory requirements and policy 

decisions, as well as EPA Underground Injection Control (UIC) program requirements that are 

forthcoming. The following is an outline of the general regulatory issues identified to date. 

General 

 Statement of Division’s General Authority 

 Enforcement/Penalties 

 Prohibit venting of CO2 

 Definition of Permanent Sequestration 

 CO2 Registry 

Siting & Permitting 

 Property Rights 

 Mineral Leases 

 Site & Reservoir characterization and mapping (baseline data) 

 Injection 

 Radius of Influence/Area of Review 
11

 Proposed public safety and emergency response plan 

 Siting 

 Bonding 

 Notice Requirements 

 Permit conditions 

 Procedure and Requirements for Transfer/Sale of Sequestration Project 

Drilling & Operations 

 OCD Right of Entry 

 Casing requirements 

 CO2 purity 

 Operators right of surface entry 

 Monitoring during injection 

 CO2 safety 

Post-Injection & Closure 

 10-year demonstration of reservoir and well integrity after cessation of injection phase 

before evaluation for potential transfer of ownership/liability? Or proper length of time to 

demonstrate integrity after injection phase (when formation pressures stabilize)? 

 Monitoring 

 Plugging 

 Reclamation/Restoration of surface 

 Qualifications for transfer 

Post-Closure

 Transfer of liability 

 Long-term monitoring plan 

 Mitigation plan 
12

Introduction 

The Governor’s Executive Order 2006-69 requires EMNRD to “explore requirements needed to 

... geologically sequester significant amounts of anthropogenic carbon dioxide in the state, 

including but not limited to geologic surveys, infrastructure, and ownership of liabilities. ... In 

addition, EMNRD shall coordinate with the stakeholder group to develop and propose rules 

regarding carbon dioxide ... storage.” 

The New Mexico Climate Change Advisory Group in its final report of December 2006 

identified the Oil Conservation Division as the likely agency to oversee development and 

implementation of a regulatory framework for geologic sequestration of CO2 due to its 

institutional and technical expertise in drilling, deep-well injection, current regulatory oversight 

of ongoing carbon dioxide injection projects, as well as the anticipated synergies with enhanced 

oil recovery. 

Pursuant to the foregoing Executive Order, EMNRD’s Oil Conservation Division (OCD) held a 

series of public stakeholder meetings with representatives from community and nongovernmental organizations, oil and gas exploration and production companies, power 

generation companies, and industry groups to gather input and recommendations for a proposed 

statutory and regulatory framework for CO2 sequestration. 

The purpose of this report is: 1) to identify the issues and challenges that must be addressed 

through statutory and/or regulatory changes to fully develop a comprehensive regulatory 

framework for the safe and effective sequestration of carbon dioxide in furtherance of the 

Governor’s Executive Order; 2) identify questions, concerns and recommendations presented to 

the Division through the stakeholder process; 3) present findings and research to date for policy 

development; and 4) present an outline of proposed statutes and regulations. 
13

Background 

Based on current sequestration pilot projects and decades of enhanced oil recovery efforts, 

evidence suggests that geologic sequestration is a technically viable means to significantly 

reduce anthropogenic emissions of CO2 and permanently separate it from the atmosphere. 

In its December 2006 Final Report, the New Mexico Climate Change Advisory Group (CCAG) 

included carbon capture and storage/re-use among its greenhouse gas emissions reductions 

strategies.2

 Governor Richardson directed the CCAG in Executive Order 2005-033 to develop 

proposals to reduce New Mexico’s greenhouse gas emissions to 2000 levels by the year 2012, 10 

percent below 2000 levels by 2020, and 75 percent below 2000 levels by 2050 as part of a 

climate change mitigation strategy. 

In recommendation ES-11, focused primarily on the capture and re-injection/re-use of CO2 in 

the processing of natural gas, the CCAG proposed a CO2 capture and re-injection/re-use target 

of 7 percent of CO2 emissions every year, based on the prior year’s emissions, for a total of 25.1 

million metric tons of CO2 equivalent captured and stored/re-used by 2020.3

 

For context, there are currently 70 CO2 injection projects in the United States, injecting more 

than 35 million tons of CO2 annually, primarily for enhanced oil recovery.4 In 2000, New 

Mexico emitted approximately 83 million metric tons of CO2 equivalent,5

 of which 30 million 

metric tons CO2 equivalent came from the burning of coal.6 As CO2 is emitted from coalburning facilities and natural gas processing plants, it is also being mined in Union and Harding 

counties at the rate of about 8.6 billion cubic feet per month (452,800 metric tons/month on 

average since January 2006). In 2006, these counties produced more than 104 billion cubic feet 

(5.5 million metric tons) of CO2, primarily for enhanced oil recovery in southeastern New 

Mexico and west Texas. 

A recent MIT report concluded that “CO2 capture and sequestration is the critical enabling 

technology that would reduce CO2 emissions significantly while also allowing coal to meet the 

world’s pressing energy needs.”7

 Geologic storage of CO2 is also considered a viable and 

effective means of successfully sequestering CO2 from the atmosphere over long timescales. 

Based on decades of studies in analogous hydrocarbon systems, natural gas storage operations 

and enhanced oil recovery projects, a 2005 Special Report by Intergovernmental Panel on 

Climate Change reported that “[f]or large-scale operational CO2 storage projects, assuming that 

sites are well selected, designed, operated and appropriately monitored ... [i]t is very likely the 

fraction of stored CO2 retained is more than 99% over the first 100 years [and that] [i]t is likely 

the fraction of stored CO2 retained is more than 99% over the first 1000 years.”8

 

 

2

 New Mexico Climate Change Advisory Group, Final Report (December 2006) 

http://www.nmclimatechange.us/ewebeditpro/items/O117F10150.pdf 3

 Id. Appendix H-43-H-46. 

4

 David Hawkins and George Peridas, “No Time Like the Present: NRDC’s Response to MIT’s ‘Future of Coal’ 

Report,” p. 4 (2007). 

5

 New Mexico Climate Change Advisory Group, Final Report, Appendix D-5 (December 2006). 6

 Id., Appendix D-20. 

7

 MIT Interdisciplinary Study, “The Future of Coal: Options for a Carbon-Constrained World,” p. x (2007). 8 IPCC Special Report on Carbon dioxide Capture and Storage (2005) p. 246. 
14

While CO2 has been injected into various geologic formations in New Mexico for decades for 

enhanced oil recovery and acid gas disposal, the idea of permanent CO2 storage, or 

sequestration, for the purpose of mitigating global climate change is a fairly novel one with few 

commercial-scale prototypes upon which to draw guidance in the development of a regulatory 

framework. To date, there exist no comprehensive regulatory models that address the unique 

long-term measurement, monitoring and verification requirements, or the liability and property 

rights issues such a comprehensive and large-scale effort presents. There are, however, numerous 

useful analogs, mostly developed in the oil and gas fields and by oil and gas regulatory agencies 

that can serve as models. Similarly, current federal environmental regulations offer useful 

models for controlling and assigning liability. 

Current estimates suggest that New Mexico has a CO2 storage capacity of 6 gigatons in its oil 

and gas fields and roughly twice that capacity within the state’s deep saline aquifers.9

 As a 

consequence, oil and gas reservoirs, and more specifically enhanced oil recovery, are expected to 

ultimately play a relatively small role in carbon sequestration. But because the infrastructure for 

CO2 injection is already largely in place in oil and gas fields, and because of the potential market 

interest and synergy with enhanced hydrocarbon recovery and the known geology of those fields, 

oil and gas fields will likely be among the first commercial-scale sequestration targets in the 

state. 

Primary considerations in the development of CO2 sequestration regulations are to reduce the 

effects of climate change by ensuring the permanent geologic sequestration of anthropogenic 

CO2, to protect human health and the environment, groundwater supplies, property interests, and 

to avoid disturbing current CO2 injection and enhanced oil recovery practices. 

Any CO2 sequestration program must achieve the protection of underground drinking water 

sources required under the U.S. Environmental Protection Agency’s Underground Injection 

Control Program (UIC), which is managed in the state by the OCD and the New Mexico 

Environment Department (NMED). OCD has developed proposed regulations tailored to ensure 

safe and effective CO2 sequestration while complying with EPA’s UIC program requirements. 

OCD contemplates coordinating with appropriate regulatory agencies, both state and federal, to 

achieve optimal protection of human health and the environment under any CO2 sequestration 

framework that is ultimately adopted. 

Before advancing to statutory and regulatory issues raised by proposed CO2 sequestration, a 

review of some important concepts will serve as useful background for understanding the policy 

implications any regulatory framework for the sequestration of carbon dioxide may have. 

Potential Current and Future Interference with Subsurface Interests 

Sequestration of CO2 in the subsurface geology, while identified as a viable and important 

means of mitigating climate change and greenhouse gas emissions, will also invariably lead to 

potential conflicts with other subsurface interests, such as the mineral estate (oil, gas and coal) 

 

9

 David Borns, Underground Storage Technology Program Manager, Sandia National Laboratories, personal 

communication. 
15

and associated interests, groundwater users and surface ownership (who are owners of the 

subsurface geologic formations and pore spaces). Given the areal extent and long timeframes 

required for sequestration of CO2 – on the order of hundreds to thousands of years – 

consideration must also be given to the future discovery of subsurface minerals or the ascendant 

value of currently non-economic resources, such as saline waters, that might conflict with CO2 

sequestration. 

Ownership of Geologic Formation/Pore Space & the Right to Sequester 

Related to the concept of CO2 ownership is the property rights issue of the ownership of the 

target pore space and the right to sequester CO2. In New Mexico, the common law on this issue 

is somewhat unsettled as no case directly tests theories of pore space ownership. However, 

several cases from the New Mexico Supreme Court indicate preference for the majority view 

among states that the pore space and subsurface geologic formation belongs to the surface 

owner, not the mineral estate. 

There are essentially two competing theories that ultimately define the liability of CO2 injectors 

in relation to pore space owners. 

One legal theory, not widely adopted, is the “reverse” or “negative rule of capture,” which holds 

that just as an owner may capture such oil or gas that migrates from adjoining property to a well 

on his own land under the “rule of capture,” so may he inject into a formation substances which 

might migrate to the property of others. Under this rule, liability for the migration of injected 

substances is essentially limited in preference for polices encouraging enhanced hydrocarbon 

recovery, or, as in this case, possibly in preference for policies encouraging the mitigation of 

climate change through sequestration of CO2. 

This approach may be justified by positing that sequestration of CO2, and the consequent 

reduction of greenhouse gas emissions, is a public benefit, or a mitigation of a public nuisance. A 

likely impediment to this approach is the 5th Amendment of the U.S. Constitution, which 

provides that no property shall be taken for public use without just compensation. Assuming that 

the pore space containing the mineral estate is the property of the surface owner and not the 

mineral estate, this property right presents problems for the application of the negative rule of 

capture because the non-consensual occupation of privately held space is considered a taking. 

The alternative, and more widely adopted theory, is that an injector is liable to the surface owner 

for any provable subsurface trespass or nuisance he may commit. As the majority of states hold 

that the subsurface geologic structures – including the pore space as distinct from the mineral 

estate – belongs to the surface property owner, an injector of CO2 must acquire the right to 

access and sequester CO2 from the appropriate surface owner(s) or face liability for trespass, 

nuisance, or numerous other possible tortious or equitable claims. 

Rights to sequester can be acquired either through negotiation, or ultimately by means of 

condemnation proceedings pursuant to the state’s powers of eminent domain. This concept 

addresses the important distinction between the rights of the pore space owner and the mineral 
16

estate, which are two separate interests, even though they may share the same geologic strata. 

Generally, the mineral interest, being fugacious, is limited to the minerals themselves, whereas 

the pore space interest includes the sand, and gravel, etc., which comprise the geologic 

formation, but do not extend to the hydrocarbons occupying the interstices. 

A minority view is that a severance of the mineral estate should be construed as granting 

exclusive rights to the subterranean strata for all purposes relating to minerals, whether “native” 

or “injected,” absent explicit language to the contrary in the severance of the mineral estate. This 

view would eliminate the problem of having to secure storage rights from the surface owner, but 

it is a minority view, and may not withstand a constitutional takings challenge. 

Long-term Liability 

Drawing from current oil and gas practices, the short-term liabilities inherent in any drilling or 

injection project – whether environmental or economic – can likely be best addressed through the 

contractual arrangements between generator and injector, as they are now. But liabilities 

following the injection and closure phases of projects present a unique problem given the 

anticipated scale, both in terms of time (hundreds to thousands of years) and space, required for 

successful CO2 sequestration and accurate CO2 inventories. For example, literature and studies 

to date on the topic suggest that wells and boreholes will present the most common risk of 

leakage. 

Because of the breadth and depth of the unknowns over the long time scales anticipated 

necessary for successful CO2 sequestration, transfer of liability to the public sector has been 

conceived of as one way to encourage the development of sequestration projects by limiting 

potential liabilities. But this liability model also raises many issues, such as how to control the 

burden on the public and how to fund monitoring and verification efforts, as well as any potential 

long-term mitigation that may be required. 

The alternative would be to require the injector to retain liability in combination with a fund or 

some other financial assurance mechanism to ensure the storage field is adequately covered for 

long-term monitoring and verification purposes, as well personal and property liability. Several 

pre-existing models culled from federal environmental statutes and regulations present workable 

examples of how this might be accomplished. 

In considering implementation of a liability system in which the injector would retain liability, 

public confidence and safety, as well as environmental protection should be foremost 

considerations given the scale of the anticipated injections and the potential the unknowns of 

such a new technology. 
17

Identified Statutory Issues 

To address the potential conflicts and uncertainties outlined above, several statutory and 

regulatory changes are anticipated. 

Authority to Regulate Carbon Sequestration 

Issue: 

OCD would need to have clear authority to regulate the sequestration of anthropogenic CO2 into 

all potential geologic reservoirs, not limited to oil and gas, for purposes of long-term/permanent 

sequestration. In the case of oil and gas reservoirs, the OCD may require the authority to dissolve 

or modify previously established field(s) or producing unit(s) contained within the boundaries of 

the proposed carbon storage field.

Analysis: 

OCD currently has authority under NMSA 70-2-6 and 70-2-11 to regulate the 

injection/sequestration of CO2 into oil and gas reservoirs for the purposes of enhancing 

hydrocarbon recovery, prevention of CO2 waste, and for disposal. OCD also has the authority 

under NMSA 70-2-12.B(21) to require that CO2 be injected, even after the possibility of 

enhanced production has elapsed, to prevent the waste of CO2 that would otherwise be vented. 

Further, OCD also has the authority to regulate naturally occurring CO2 and require 

sequestration/injection not limited to oil and gas reservoirs if the CO2 is a product of or used in 

oil and gas operations. However, there exists no clear authority for the Division to regulate 

anthropogenic CO2 injection for sequestration purposes alone, nor does it have general authority 

to regulate injection/sequestration of CO2 not produced in oil and gas operations into reservoirs 

other than those of oil and gas. 

Because oil and gas reservoirs are anticipated to ultimately constitute only a small fraction of the 

total sequestration volumes in New Mexico, clear authority to regulate the sequestration of 

anthropogenic CO2 into all potential geologic reservoirs, not limited to productive oil and gas 

reservoirs, for purposes of long-term/permanent sequestration is essential to any regulatory 

framework for commercial-scale geologic sequestration. 

OCD is believed to be the proper entity for such authority given its institutional and technical 

expertise in drilling, deep-well injection, and its current regulatory oversight of ongoing carbon 

dioxide injection projects. Further, it is believed that the earliest carbon sequestration projects 

will probably take place in depleted oil and gas reservoirs given existing infrastructure, 

knowledge of the target reservoirs and a proven ability to contain gases over geologic timescales, 

as well as the industry’s expertise in injection and CO2. 

Ownership of Pore Space/Geologic Formation 

Issue: 
18

No statutory language currently exists defining the extent of surface owner property rights with 

respect to the geologic formation or the pore space within it. New Mexico common law in this 

area remains largely undeveloped because the question of ownership of the formation or pore 

space has not been directly tested in the courts. However, several cases from the New Mexico 

Supreme Court indicate preference for the majority view among states that the pore space and 

subsurface geologic formation belongs to the surface owner. A majority of jurisdictions, 

including a preponderance of oil and gas producing states, follow this common-law American 

rule. A consequence is that any large-scale CO2 sequestration effort will likely require the 

acquisition of underground storage rights from surface owners by negotiation or condemnation. 

Issues Raised During the Workgroup: 

 Is it possible for the state to claim ownership of the pore space as part of the public 

domain for a beneficial use (e.g. similar to common law rules guiding aquifer recharge)? 

 Any proposed regulatory framework should protect the future interests of mineral interest 

holders – injection of CO2 may impede or prevent future technologies from extracting 

currently non-economic hydrocarbons, so these future interests must be protected. 

 Currently, injection of CO2 for enhanced oil recovery is considered part of the mineral 

lease operations and does not require the consent of the pore space owner – at what point 

does CO2 injection become storage and require acquisition of storage space rights? 

 Any sequestration regulatory framework must include but not be limited to hydrocarbon 

reservoirs and contain provisions for injection into other formations, such as saline 

aquifers. 

Analysis: 

Pore space for CO2 sequestration has been identified in three major reservoir types, each with 

similar ownership interests: 

 Depleted Oil & Gas Reservoirs 

Pore space evacuated by the extraction of oil and gas minerals likely belongs not to the mineral 

interest, but to the surface owner, who would have the sole power to grant storage rights for the 

purpose of sequestering carbon dioxide. New Mexico case law does not address the question of 

storage rights directly, but does hold that the mineral interest does not include the solids of the 

earth. The holdings of several other cases reinforce that New Mexico retains a preference for the 

majority view that the mineral estate includes only the oil and gas native to the formation, and 

not rights to the formation or the pore space itself, unless the conveyance or severance of the 

mineral estate explicitly states otherwise. Therefore, the surface owner likely retains possession 

of the pore space/geologic formation and the sole right to store non-native gas in the evacuated 

space, but perhaps only after the mineral estate has been removed or depleted. 

In general, case law holds that the mineral interest retains the right to access by reasonable 

means subsurface minerals as long as there are recoverable minerals remaining to be extracted 

and as long as there has been no abandonment, but that the right to the pore space/geologic 

formation reverts to the surface owner once the minerals have been depleted. Westerman v. 

Pennsylvania Salt Mfg. Co, 260 Pa. 140, 146 (1918). In Westerman, the Supreme Court of 

Pennsylvania held that the coal mining interest had “no perpetual right of way” through the land 

and that “its right will cease when the coal therein is exhausted or abandoned.” Westerman, 260 
19

Pa. at 146. Years later, the West Virginia Supreme Court of Appeals ruled in accordance, 

holding that the evacuated space following mineral extraction remains the property of the surface 

owner. Tate v. United Fuel Gas Co., 137 W.Va. 272, 282, 71 S.E.2d 65, 72 (1952) (“as long as 

there remain recoverable minerals which are mined in good faith, the space may be used by the 

owner of the minerals"). 

While there had been division among jurisdictions as to the extent of the surface owners rights 

vis-à-vis the mineral estate owners (compare Tate, supra, (holding that when there are no 

recoverable minerals remaining, the mineral interest has no “right to use the space” in the 

geologic formation which is property of the surface owner) with Central Kentucky Natural Gas 

Co. v. Smallwood, 252 S.W.2d 866 (1952) (holding that the mineral interest owner, not the 

surface owner, has authority to grant a gas storage lease)), a majority position seems to have 

taken hold following the ruling in Emeny v. United States, 188 Ct.Cl. 1024, 412 F.2d 1319 

(1969), which held that the surface owner retains ownership of the evacuated pore space. In 

Emeny the court found that “[t]he surface of the leased lands and everything in such lands, 

except the oil and gas deposits covered by the leases, were still the property of the respective 

landowners according to the language of the mineral conveyance. Property retained by the 

landowner included the “geological structures beneath the surface, including any such structure 

that might be suitable for the underground storage of ‘foreign’ or ‘extraneous' gas produced 

elsewhere.” Emeny, 412 F.2d at 1323. See Ellis v. Arkansas Louisiana Gas Co., 450 F.Supp. 412 

(E.D. Okla. 1978) aff'd 609 F.2d 436 (10th Cir. 1979) (holding that it is the surface owner’s 

power to grant storage rights and that it is “the American view is that the cavern is owned by 

surface owners”); Southern Natural Gas Co. v. Sutton, 406 So.2d 669 (La. App. 2nd Cir. 1981) 

(“Surface ownership, however, includes the right to use the reservoir underlying ... for storage 

purposes”); Department of Transportation v. Goike, 560 N.W.2d 365, 365-366 (Mich. Ct. App. 

1997) (holding that subterranean storage space, once it has been evacuated of the minerals and 

gas, belongs to the surface owner and that a mineral right is a right to the minerals themselves, 

not to the land surrounding the minerals); Pomposini v. T.W. Phillips Gas & Oil Co., 580 A.2d 

776 (1990) aff’d sub nom. Keppel v. Fairman Drilling Co., 615 A.2d 1298 (1992) (“the right to 

extract gas did not include the right to use the cavernous spaces owned by the lessor for the 

storage of gas in the absence of an express agreement therefore”); M.J. Harvey, Jr., 109 IBLA 31 

at 33, GFS (O&G) 1989-75 (May 25, 1989) (to the extent that no valuable minerals underlay the 

tract in question, the owner of the surface estate rather than the owner of the mineral estate 

owned the non-mineral strata); and Phillips Petroleum Co., 105 IBLA 345, GFS (O&G) 1989-9 

(Nov. 17, 1988) (operator who had consent of surface owner but not of mineral owner was 

entitled to use a dry hole as a salt water injection well). It is possible to read the holding of 

Emeny narrowly, as turning on the language of the lease, and not a general proclamation that the 

pore space is absolutely retained by the surface owner. Since Emeny, this paradigm of subsurface 

interest has become well established for cases where the intent of the original conveyance did not 

clearly include the subsurface geologic formation/pore space. 

However, the rights of the surface owner to the geologic formation appear to be qualified by any 

persistent rights of the mineral estate, which survive as long as there remain minerals to extract 

and the interest has not been abandoned. In the New York case of International Salt Co. v. 

Geostow the court found that the surface owners were precluded from executing a waste storage 
20

contract with a third party to use the excavated space created by the salt mining activities, as 

there still remained minerals in place and International Salt Co. required use of the previously 

mined sections as a means of access to the un-mined portions of their mineral property. 

International Salt Co., 878 F.2d 570, 575 (2nd Cir. 1989) (“[A] grantee of subsurface minerals, 

until exhaustion of the mine, has the exclusive right to use the excavated chamber in connection 

with its mining activities”). The court relied on an earlier case to hold that the mineral owner’s 

interest in the location of the minerals “reverts to the surface landowner by operation of law at 

some time subsequent to removal of the [minerals].” Id. (quoting United States Steel Corp. v. 

Hoge, 503 Pa. 140, 148, 468 A.2d 1380, 1384 (1983)) (internal quotations omitted). Citing 

Westerman and Tate, supra, the International Salt Co. court indicated preference for a definition 

of exhaustion “when no ‘mineable’ or ‘recoverable’ minerals remain.” Id. In the recent case of 

Goike, supra, the Michigan Court of Appeals appears to have clarified this issue somewhat in 

holding that while “[a] surface owner possesses the right to the storage space created after the 

evacuation of underground minerals or gas ... [the] mineral estate holder may ‘store’ any fluid 

minerals or gas native to the chamber that has not yet been extracted, [but] they cannot introduce 

any foreign or extraneous minerals or gas into the chamber. Only the surface owner possesses the 

right to use the cavern for storage of foreign minerals or gas, and then only after defendants have 

extracted the native gas from the cavern.” Goike, 560 N.W.2d at 366. 

A survey of case law through 1986 revealed the trend among jurisdictions toward recognizing in 

the surface owner the exclusive rights to the subsurface formation and pore space had, by that 

point, already been well established among most jurisdictions. Fred McGaha, Underground Gas 

Storage: Opposing Rights and Interests, 46 La. L. Rev. 871, 873 (1986). McGaha attributed this 

paradigm in both case law and legal thinking to an increase in the scientific understanding of the 

nature of minerals and of geology. Early understanding suggested that minerals had the potential 

to migrate freely beneath the surface, so that once extracted “the depleted reservoir may one day 

be refilled by one of these migrating fluids.” 46 La. L. Rev. at 876; see Hammonds v. Central 

Kentucky Natural Gas, 75 sw2d 204, 204 (ky ct app 1934); Central Kentucky Natural Gas Co. v. 

Smallwood, 252 sw2d 866 (Ky. Ct. App. 1952) (“the geological formations or strata common to 

this class of minerals may be exhausted a thousand times and the mineral owner still retain the 

exclusive rights to take all the minerals which find their way into the formation, whether through 

injection or in any other way”). But as McGaha explained: 

For this reason, in the past it was recommended that storage 

companies acquire the interests of mineral owners as to any 

remaining oil or gas and also as to any future migrating minerals. 

...We now realize that minerals are locked in non-permeable 

container-like formations and do not freely flow through 

underground rivers, making it unnecessary to protect a mineral 

owner’s interest in a depleted reservoir. It is not going to refill 

absent a geological event connecting two underground reservoirs. 

Since the surface owner owns the land ‘from core to crust’ it only 

makes sense that he, rather than the mineral owner, owns depleted 

reservoirs. The ‘container’ in which minerals are locked should not 

be considered a part of the mineral estate. 

Id. (citations omitted). 
21

The opposing minority view is most clearly articulated in Smallwood, supra, and endorsed by the 

authors of Williams & Meyers, Oil and Gas Law. In Smallwood, which was overruled by Texas 

American Energy Corp. v. Citizens Fidelity Bank & Trust Co., 736 S.W.2d 25 (Kentucky S. Ct. 

1987), on a different issue, the court held that it is the mineral interest that has the right to assign 

or convey storage rights to the pore space or geologic formation, not the surface owner. 

Smallwood, 252 S.W.2d at 868 (“We conclude that the mineral rather than the surface owner is 

entitled to the rental or royalty accruing under a gas storage lease”). While acknowledging the 

counterargument based on the ancient legal principle of “Cuius est solum, eius est usque ad 

coelum et ad inferos” (for whomsoever owns the soil, it is theirs up to the sky and down to the 

depths), especially in situations where strata have been depleted of oil and gas or never contained 

recoverable minerals, Williams & Meyers urges adoption of the view that severance of minerals 

from the surface estate “should be construed as granting exclusive rights to the subterranean 

strata for all purposes relating to minerals, whether “native” or “injected,” absent contrary 

language in the instrument severing such minerals.” W&M 1:222, p.334-335. 

Somewhat in support of this minority view, the Ohio court and more recently the Colorado court, 

for example, have for different reasons placed limits on the rights of the surface owner to the 

subsurface pore space below with the qualification by the deciding courts that the particular facts 

in each case were not appropriate for the application of oil and gas law. In Chance v. BP 

Chemicals, 670 N.E.2d 985 (Ohio 1996) the defendants/appellees were injecting waste 

byproducts from the production of industrial chemicals, unrelated to oil and gas production, 

which plaintiffs/appellants alleged damaged the substrata, making it unusable for other purposes. 

Chance, 670 N.E.2d at 989. As such, the court declined to apply various rules developed from oil 

and gas cases (e.g. the negative rule of capture and the determination of compensation based on 

appropriation of underground gas storage), “around which a special body of law has arisen on 

special circumstances not present here.” Id. at 991. But most significantly, the court limited the 

rights of the surface owner to the pore space below, holding that “subsurface ownership rights 

are limited ... [c]onsequently, we do not accept appellants’ assertion of absolute ownership of 

everything below the surface of their properties.” Id. at 992. In limiting surface ownership rights, 

the court looked to Willoughby Hills v. Corrigan, 29 Ohio St.2d 39, 49, 58 O.O.2d 100, 105, 278 

N.E.2d 658, 664 (1972), which cited United States v. Causby, 328 U.S. 256, 66 S.Ct. 1062, 90 

L.Ed. 1206 (1946), to state that the doctrine of “Cuius est solum” “has no place in the modern 

world.” Id. at 991. The Ohio court also extended the reasoning of Hinman v. Pacific Air Transp., 

84 F.2d 755, 758 (C.A. 9, 1936) (“We own so much of the space above the ground as we can 

occupy or make use of, in connection with the enjoyment of our land”) to apply equally to 

below-ground interests. Id. at 991-992. The Ohio court in Chance, however, recognized that 

appellants did have a limited property interest in the rock into which the injectate was placed, so 

that injectors could be liable in situations where there is demonstrable interference with the 

surface owner’s “reasonable and foreseeable use of their properties.” Id. at 992 (emphasis 

added). Thus, the court held, “appellants [had] the burden of establishing that the injectate 

interfered with the reasonable and foreseeable use of their properties.” Id. at 993. 

Colorado recently similarly extended the reasoning of Willoughby Hills “to apply as well to 

ownership of subsurface rights” in a case where appellants alleged trespass following the 

injection of water for aquifer recharge. Bd. of County Comm'rs v. Park County Sportsmen's 
22

Ranch, 45 P.3d 693, 701 (Colo. 2002). The Colorado supreme court held that “[w]ater is not a 

mineral” and, as in Chance, that “[t]he law of minerals and property ownership ... is 

inapplicable” to the particular situation. Id. at 710. Relying on distinctions between water law 

and oil and gas law derived from the Colorado constitution, water law statutes and legislative 

intent, as well as from state common law, the Colorado court distinguished the application of 

water law from that of oil and gas law. Specifically, the court found that the legislature, “in 

authorizing the use of aquifers for storage of artificially recharged waters ... has ... supplanted 

the Landowners’ common-law property ownership theory.” Id. at 703. The court then found that 

based on the state’s constitution, statutes and case law “neither surface water, nor ground water, 

nor the use rights thereto, nor the water-bearing capacity of natural formations belong to a 

landowner as a stick in the property rights bundle,” but do belong to the legitimate holders of 

water use rights. Id. 707, 710. Further, the project in Sportsmen’s included “constructed wells, 

dams, recharge reservoirs, and other water works,” but the project did not include “the location 

of any artificial features on or in the Landowners’ properties,” which, the court held, meant that 

no consent was required, that an easement or just compensation was unnecessary, and that no 

trespass occurred “simply as the result of water moving into an aquifer and being contained or 

migrating in the course of the aquifer’s functioning underneath the lands of another.” Id. at 713-

714 (emphasis added). The court reasoned that “[t]his construction of the Colorado constitution 

and statutes implements Colorado’s policy that water is a public resource available for public 

agency and private use in a system of maximum utilization for beneficial use under decreed 

rights,” because: 

Allowing property owners to control who may store water in natural 

formations, or charging water right use holders for easements to occupy 

the natural water bearing surface or underground formations with their 

appropriated water, would revert to common-law ownership principles 

that are antithetical to Colorado water law and the public's interest in a 

secure, reliable, and flexible water supply made available through the 

exercise of decreed water use rights. It would disharmonize Colorado's 

historical balance between water use rights and land ownership rights. It 

would inflate and protract litigation by adding condemnation actions to 

procedures for obtaining water use decrees. It would counter the state's 

goals of optimum use, efficient water management, and priority 

administration. 

 

Id. at 714. 

Thus, the Ohio and Colorado courts stand for the fairly unique propositions that subsurface rights 

can be limited by the extent to which the surface owner has a reasonable and foreseeable use that 

would be or has been demonstrably impeded by the injector, and that there is no action for 

trespass in the case of injected water when there is no artificial structure on the property of the 

landowner and the injected water has been decreed to be a beneficial resource to the public 

domain. 

In New Mexico, where storage of natural gas in the subsurface is not a common practice and the 
23

law on this point is less than fully developed, the early case of Jones-Noland Drilling Co. v. 

Bixby, 282 P. 383 (1929) seems to have established in New Mexico the holding that the mineral 

estate is limited and does not include rights to the geologic formation. Specifically, the Supreme 

Court of New Mexico held that the oil and gas lease conveys the right to ingress and egress to 

explore for, discover, develop and remove oil and gas only. And while the mineral interest is a 

real estate interest, “it does not convey a greater interest in the soil, except the oil and gas, than to 

enable the owner of the lease to use the soil in carrying out and availing the leases of the abovenamed rights.” Id. at 383. Therefore, “[t]he lessee is not the owner of the solids of the earth ... 

and merely has the right to use the solid portion so far as necessary to bore for, discover, and 

bring to the surface oil and gas.” Id. 

While no New Mexico case law is directly on point, several cases do comport with Bixby and 

imply a strong preference for the majority position that subsurface pore space is strictly a surface 

interest by acknowledging that an action for subsurface trespass is available to surface owners. In 

Snyder Ranches, Inc. v. Oil Conservation Comm’n of New Mexico, 110 NM 637, 798 P.2d 587 

(NM 1990), for example, Mobil had acquired authority from the New Mexico Oil Conservation 

Division to inject salt water through a disposal well into an underground formation on land 

adjoining the plaintiff. Snyder Ranches, Inc., 798 P.2d at 588. Expert testimony established that a 

“sealing fault line” would block the further migration of the salt water and that the fault line and 

plaintiff’s boundary line merge at some point. Id. at 590. Plaintiffs alleged that this merger 

indicates Mobil’s injected salt water would encroach upon their subsurface property, thereby 

constituting trespass, but “[t]he fact that the fault line and the boundary line merge at a particular 

point does not mean that the fault line encompasses land beyond the boundary line.” Id. at 589. 

Because of this evidentiary problem the plaintiffs were unable to prove trespass, nonetheless, the 

Snyder Ranches court went on to state in dicta that Mobil could be held liable for actual 

subsurface trespass on account of its injected salt water if trespass could ever be proven, even 

though such injection was authorized and licensed by the Oil Conservation Division. Id. at 590. 

Subsequently, in Hartman v. Texaco Inc., 1997-NMCA-032, 123 N.M. 220, 937 P.2d 979 (NM 

Ct. App. 1997), plaintiff alleged common law trespass and statutory trespass when injected water 

caused a blowout in his well. The lower court ruled in the plaintiff’s favor on the common law 

trespass claim, but ruled against the plaintiff on the statutory trespass claim; the New Mexico 

Court of Appeals affirmed both holdings. Id. at 982-983. The court made clear that New Mexico 

recognizes that “an action for common law trespass does provide relief for trespass beneath the 

surface of the land ... [so] we do not disturb [that decision] on appeal.” Id. at 983 (citing 

Schwartzman Inc. v. Atchison, Topeka & S.F. Ry., 857 F.Supp. 838, 844 (D.N.M.1994) (trespass 

for pollution of groundwater); Lincoln-Lucky & Lee Mining Co. v. Hendry, 9 N.M. 149, 155, 50 

P. 330, 332 (1897) (subsurface trespass by mining shaft); Restatement (Second) of Torts § 159 

(1965)); see also McNeill v. Rice Engineering, 139 N.M. 48, 128 P.3d 476, 2006 -NMCA- 015 

(2005). The statutory trespass claim was held inapposite because “[n]othing in the statute 

indicates that the legislature envisioned applying [the statute] to a subsurface trespass by injected 

water...” Id. at 984. 

While no case law appears to extend the reasoning of Chance and Sportsmen’s to oil and gas 
24

law, it seems that the reasoning employed could be applied to carbon dioxide sequestration, 

because most surface owners make no use of their subsurface pore space and demonstrating 

damage, harm or interference with the surface owner’s reasonable and foreseeable use and 

enjoyment could prove challenging. Adopting this argument to carbon dioxide sequestration 

would probably require the legislature to include careful language in the authorizing statutes 

establishing the public benefit of carbon dioxide sequestration. A declaration of public benefit, 

coupled with a putative lack of demonstrable harm and possibly an argument that anthropogenic 

carbon dioxide injected into the subsurface becomes part of a subsurface stream of native gases, 

could be employed as a means to avoid having to condemn pore space and pay just compensation 

to surface owners for the right to use the pore space. The benefit of this approach would be to 

avoid the expense, time, and challenge of acquiring all the necessary pore space storage rights 

from respective surface owners. As the areal extent of carbon dioxide sequestration units is 

expected to be quite large, the number of landowner interests may make the process cumbersome 

and slow. As in Sportsmen’s, common-law ownership principles applied to the pore space could 

be seen as “antithetical” to the public’s interest in a secure, reliable and efficient process for the 

injection and sequestration of carbon dioxide. 

On the other hand, storage space costs should be nominal, especially early in the development of 

carbon sequestration, and any legislative action that does not provide for compensation or legal 

condemnation of what is arguably a valid property interest poses a significant constitutional 

takings challenge. Ultimately, the volume of case law establishing a surface owner’s property 

interest in subsurface pore space and the 5th Amendment of the U.S. Constitution’s “takings” 

clause recommend the less controversial option of pursuing legitimate condemnation of the pore 

space interests through just compensation. Also, a powerful policy argument stands against a 

wholesale abrogation of landowner subsurface rights because of their inherent and historic value, 

as discussed by Steven D. McGrew, Selected Issues in Federal Condemnations for Underground 

Natural Gas Storage Rights: Valuation Methods, Inverse Condemnation, and Trespass, 51 Case 

W. Res. L. Rev. 131, 147 (Fall 2000). This argument is discussed in more detail in the section on 

subsurface trespass below. 

 Saline Aquifers 

Comprising the largest potential storage volume in New Mexico, saline aquifers will present 

significantly greater costs, technological problems and geologic unknowns than sequestration in 

depleted oil and gas reservoirs. For these reasons, it is believed that sequestration in deep saline 

aquifers will evolve after sequestration in depleted hydrocarbon reservoirs. However, any 

statutory and regulatory system must address the complexities of storage in saline aquifers. 

All ground waters of the state of New Mexico are statutorily declared to be public waters, 

belonging to the state and as such are subject to appropriation for beneficial use. However, the 

Office of the State Engineer does not have authority to regulate the appropriation of waters found 

at depths greater than 2,500 feet and in concentrations in excess of 1,000 parts per million (ppm) 

dissolved solids. While the waters themselves may be appropriable and within the public 

domain, the aquifer storage space is not in the public domain, but is the property interest of the 

surface estate. 
25

NMSA 72-12-1 and 72-12-18 both declare for different purposes that ground waters belong to 

the public and are subject to appropriation for beneficial use. The predecessors of these statutes 

were held constitutional in Yeo v. Tweedy, 34 N.M. 611, 286 P. 970 (1929) and in State ex rel. 

Bliss v. Dority, 55 N.M. 12, 225 P.2d 1007 (1950). In Dority, the New Mexico Supreme Court 

established that appropriation of public waters was not limited to waters “upon the public lands” 

because “water of underground rivers with defined banks have always been subject to 

appropriation” and so the state statute clearly meant to sever water ownership to the public 

domain ownership of the land. Dority, 225 P.2d 1007, at 1017 (emphasis added). 

However, while all ground waters of the state are within the public domain, not all ground waters 

fall within the jurisdiction of the state engineer. In Tweedy, the court determined that before the 

state engineer can assume jurisdiction over underground water bodies “he must find that they 

have boundaries reasonably ascertained by scientific investigations, or by surface indications.” 

Tweedy, 286 P. 970, 976. Nonetheless, the current statute makes clear that “[n]o past or future 

order of the state engineer declaring an underground water basin having reasonably ascertainable 

boundaries shall include water in an aquifer, the top of which aquifer is at a depth of twenty-five 

hundred feet or more below the ground surface at any location at which a well is drilled and 

which aquifer contains non-potable water.” NMSA 72-12-25. "Non-potable water," for the 

purpose of this act, means water containing not less than 1,000 ppm of dissolved solids. NMSA 

72-12-25. 

While the water itself is in the public domain, the aquifer which holds it is not. “Absent proof of 

some possessory ownership interest in land ... the State has no legally cognizable interest in the 

aquifer ...” New Mexico v. General Elec. Co., 335 F.Supp.2d. 1185, 1205 (D.N.M. 2004) aff’d 

New Mexico v. General Elec. Co., 467 F.3d 1223 (10th Cir. 2006). In General Electric, New 

Mexico brought suit to recover alleged damages to an aquifer from subsurface contamination, 

alleging contamination damaged both groundwater and the aquifer itself. Id. at 1211. But the 

court found that “[i]n contrast to the state’s water resources ... the New Mexico Constitution and 

statutes do not speak of permanent State ownership or trusteeship of all of the soils, clay, sand, 

gravel, rocks and minerals within the state-the geological constituents of which any aquifer is 

comprised.” Id. at 1203. That question – “[w]hether the State has retained an ownership or trust 

interest in the minerals, including sand and gravel, underlying parcels of state land that have 

been sold and conveyed to others is a fact-specific determination under New Mexico law, and is 

not determined by a blanket state property law rule.” Id. 

Instead, the courts look to the ownership of the surface and its soils, but in General Electric

found that the state cited neither statutory nor case authority to support their assertion that the 

state owned the aquifer as a natural resource in the same sense that it owned in trust the public’s 

water. Id. at 1203-1204. The court held that “unless the State claims some proprietary interest in 

the land or the aquifer’s subsurface geologic materials as a landowner or title holder, then it 

would seem that the chemical contamination of those geologic materials impacts the State’s 

interests in groundwater only when it results in further groundwater contamination.” Id. 1204. 

Absent such proof of ownership, the court held the state had no property interest in the aquifer 

storage space or the geologic formation itself. Id. at 1205. This holding was subsequently 
26

affirmed by the 10th Circuit, which found that “the State as guardian of the public trust has no 

possessory interest in the sand, gravel, and other minerals that make up the aquifer – a necessary 

requisite to maintaining a trespass action.” Id. 1248. 

Lacking ownership of the surface or some express property interest in the geologic formation 

itself, the state, therefore, has no property interest in the storage space contained within New 

Mexico aquifers, the ownership of which appears to abide by the same property rules discussed 

above in the analysis of oil and gas reservoirs. Consequently, barring the alternative approach 

discussed above, acquisition of storage rights, by negotiation or condemnation, would also seem 

to be required for sequestration of carbon dioxide in deep saline formations. Also, the Office of 

the State Engineer appears to have no authority over saline aquifers deeper than 2,500 feet and 

which contain total dissolved solids in excess of 1,000 ppm. 

 Deep Coal Seams 

The third likely reservoir type identified for sequestration of CO2 are unminable coal seams. 

Like depleted oil reservoirs, CO2 storage in coal seams will, under some conditions, provide 

enhanced hydrocarbon recovery. There are, however, additional technical challenges that must 

be addressed before any large scale sequestration project in coal seams is advanced. It is 

expected that the legal issues with regard to pore space will be highly analogous to those 

identified for other subsurface reservoirs, discussed above. 

 Subsurface Trespass 

As a consequence of the expected subsurface ownership theory, subsurface trespass becomes a 

significant issue that must be considered for subsurface injection plans. 

New Mexico recognizes the action of subsurface trespass but requires that there be demonstrable 

proof of physical infringement by a person or thing that results in damage. Consequently, the 

negative rule of capture – the theory derived from oil and gas law that just as a landowner may 

capture what minerals may migrate from adjoining lands to a well bottomed on his own land, so 

may he inject into a formation substances that may migrate through the subsurface to the land of 

others – is disfavored in New Mexico, as it has been similarly viewed with disfavor in other 

jurisdictions. Therefore, in the operation of carbon dioxide sequestration, landowners who 

successfully demonstrate a physical subsurface infringement into their property resulting in 

damage will likely be successful in bringing a trespass action against injectors, unless available 

remedies are statutorily limited to, for example, inverse condemnation. Such a legislative 

limitation of the available remedies could have a significant economic impact on carbon dioxide 

sequestration by limiting the liability of carbon dioxide injectors, because punitive damages are 

generally not available in inverse condemnation actions, only compensatory damages. The law of 

subsurface trespass has not developed much beyond basic first-order questions in New Mexico, 

so the law of other jurisdictions must serve as a guide for more complex subsurface trespass 

issues. 
27

Other possible causes of action available to surface owners in response to the intrusion of carbon 

dioxide into their subsurface space include negligence, private nuisance for non-physical 

infringement that affects the use and enjoyment of property (currently recognized as a cause of 

action in New Mexico only when no other theories of recovery are available, but the New 

Mexico Supreme Court is currently scheduled to review this holding, so the law may change), 

conversion (money paid to injectors, a portion of which should have been paid to the landowner 

for rental of the pore space for storage), and unjust enrichment (gaining the value of the storage 

space without having to pay for it). Surface owners may also opt to waive the tort of trespass and 

sue under assumpsit, on the theory that by injecting into the subsurface the injector assumes an 

implied contractual duty to pay rental for the right to inject into the subsurface. This latter option, 

similar to unjust enrichment, may be employed in situations where trespass damages are more 

difficult to establish. The following analysis, however, deals only with the claim of subsurface 

trespass. 

New Mexico courts have held that trespass is a direct physical infringement of another’s right of 

possession, Schwartzman, Inc. v. Atchison, Topeka & Santa Fe Ry. Co., 857 F.Supp. 838, 844 

(D.N.M. 1994) (citations and internal quotations omitted), and that a trespass may be committed 

on or beneath the surface of the earth. Id. (citing Restatement (Second) of Torts § 159 (1977)); 

see Hartman v. Texaco Inc., 1997-NMCA-032, 123 N.M. 220, 937 P.2d 979 (NM Ct. App. 

1997) (“[I]n New Mexico an action for common law trespass does provide relief for trespass 

beneath the surface of the land”); Snyder Ranches, Inc. v. Oil Conservation Comm’n of New 

Mexico, 110 NM 637, 798 P.2d 587, 590 (NM 1990) (stating in dicta that nothing would prevent 

plaintiff seeking redress for actual trespass resulting from injection operations). 

Subsurface trespass claims are limited to common-law actions, the courts having determined that 

statutory trespass is limited by legislative intent to surface trespass. Hartman, 937 P.2d at 984. 

Owing to the requirement for direct physical infringement, the New Mexico courts appear to 

require a showing of damage for subsurface trespass claims as evidence of infringement, 

Schwartzman, 857 F. Supp. at 844 (“the groundwater contamination must have reached 

Plaintiff’s property and damaged it”), which is contrary to the guidance provided by the 

Restatement (Second) of Torts (“One is subject to liability to another for trespass, irrespective of 

whether he thereby causes harm to any legally protected interest of the other, if he intentionally 

enters land in the possession of the other, or causes a thing or third person to do so”). § 158 

(1965). In explaining the general rule, the Restatement (Second) of Torts suggests that for 

indirect trespass, as when an actor causes a thing to infringe upon another’s property, that “[i]t is 

enough that an act is done with knowledge that it will to a substantial certainty result in the entry 

of the foreign matter.” § 158 cmt. h. Whether this divergence from the general rule expressed in 

Schwartzman is actually the court’s holding or whether the court merely equated proof of 

damage to groundwater to proof of direct physical infringement of the subsurface is unclear. 

Whichever the case, New Mexico courts do require direct evidence, beyond affidavits or 

testimony of experts, to demonstrate physical infringement. Schwartzman, 857 F. Supp. at 845 

(“the only evidence of physical contamination...is based on the opinions of Plaintiff’s experts,” 

but plaintiff “must identify specific facts, which show physical invasion of contaminants”) 

(citations omitted, emphasis in original). 
28

A direct physical infringement of subsurface property occurs when physical evidence supports 

the claim. Schwartzman, 857 F. Supp. at 845; Snyder Ranches, Inc., 798 P.2d at 590; Hartman, 

937 P.2d at 981, 983. In Schwartzman, the plaintiffs had done no soil or groundwater testing to 

demonstrate contamination due to the activities of defendant railway company, and instead relied 

on evidence based solely on the opinions of experts, which the court held was insufficient to 

establish actual trespass. Schwartzman, 857 F. Supp. at 845. Likewise in Snyder Ranches, the 

plaintiff’s reliance on the fact that survey maps showed his property boundary merging with a 

“sealing fault” that would block the flow of injected salt water as “proof positive that the fault 

line must include part of their land,” was insufficient to establish that salt water injected by 

defendants on the adjoining property must have infringed on their property. Snyder Ranches, 

Inc., 798 P.2d at 589, 590. Conversely, in Hartman, plaintiff’s contention that defendant’s 

injection of salt water at high pressures created vertical fractures allowing the escape of salt 

water into plaintiff’s well was supported by evidence “that a substantial volume of the injected 

water was never recovered, indicating that it had escaped the formation.” Hartman, 937 P.2d at 

981. While common law subsurface trespass was not challenged by defendant on appeal, the 

court of appeals went out of its way to make clear it would not disturb the trial court’s ruling, Id. 

at 983, effectively emphasizing the legitimacy of the subsurface trespass claim. 

New Mexico further appears to hold that there is no claim for subsurface trespass for the 

injection of salt water produced on site in the production of oil and gas due to an implied 

authorization for disposal by injection because such practice is a necessary part of the purpose of 

the lease; though the same is not true for the injection of salt water produced off site, unless, 

perhaps, an instrument or contract specifies otherwise. McNeill v. Rice Engineering and 

Operating, Inc., 133 N.M. 804, 70 P.3d 794, 798, 801 (NM Ct. App. 2003). In McNeill, the New 

Mexico Court of Appeals reviewed case law from other jurisdictions (Kansas, Louisiana and 

Illinois), which suggested that “there may be an implied authorization to dispose of salt water in 

order for the production of oil and gas on that person's land to be accomplished,” but that that 

rationale “does not apply to the disposal of salt water produced on other property,” to determine 

the trial court erred in granting a broad right to dispose of off-site salt water when the instrument 

in question did not explicitly allow it. Id. 801-802 (citations omitted). The right to inject salt 

water produced on-site from oil and gas wells stems from the theory that such production “is a 

necessary and unavoidable” result of the production of oil and gas that has been explicitly 

authorized by the original mineral conveyance. See Colburn v. Parker and Parsley Development 

Co., 17 Kan.App.2d 638, 842 P.2d 321, 326 (Ct. App. Kansas 1992) (“We hold the granting 

clause in an oil and gas lease includes an implied covenant to dispose of the salt water produced 

during operations by utilizing a saltwater disposal well drilled on the leased premises without 

additional compensation to the lessor. We hold that such a right is required in order for the 

production of oil and gas to be accomplished”); Leger v. Petroleum Engineers, Inc., 499 So.2d 

953 (La. Ct. App. 3rd cir. 1986) (“[W]e conclude that, under the facts present, the ...[salt water 

disposal], of which plaintiffs complain, is impliedly granted because such use causes no damage 

to the surface or sub-surface and is reasonably, if not absolutely, necessary for accomplishment 

of the overall purpose for which the lease was granted, i.e., production of oil from the leased 

property”); but see Gill v. McCullom, 311 N.E.2d 741 (App. Ct. 5th dist. Ill 1974) (“The injection 

must have some relation to the primary purpose of obtaining production”); Farragut v. Massey, 

612 So.2d 325 (S. Ct. Miss. 1992) (“The right of the mineral owner to use and occupy the land is 

restricted to operations for exploring for and extracting minerals from that land. Thus, the land 
29

cannot be used ... to dispose of salt water from other land”) (quoting 1 E. Kuntz, A Treatise on 

the Law of Oil and Gas, § 3.2 at 87-88 (1987)). 

The method employed in New Mexico to calculate damage to subsurface property from trespass 

depends on whether the damage is permanent or temporary. McNeill v. Burlington Resources Oil 

& Gas Co., 141 NM 212, 153 P.3d 46, 54 (N.M. Ct. App. 2007). McNeill applied trespass 

damage calculations developed in Amoco v. Carter Farms, 103 NM 117, 703 P.2d 894 (NMSC 

1985), to subsurface trespass. For permanent subsurface injuries the measure for damages is the 

diminution in the fair market value of the entire property; for temporary injuries, “the measure of 

damages is the cost of repair or remediation, so long as this cost is less than the diminution in fair 

market value.” Id. at 54-55 (citations omitted). When the actions of the owner of the mineral 

estate have rendered the surface totally unusable for a period of time, then the damages are 

determined by the land’s rental value for that period. Id. For these purposes, “[t]emporary 

damages are generally defined as damages that can be remedied, removed, or abated within a 

reasonable period and at a reasonable expense,” and “permanent damages are defined as those 

damages caused by an injury that is fixed and where the property will always remain subject to 

that injury” so that they are “damages for the entire injury done – past, present, and prospective” 

and are “practically irremediable.” Id. (citing Morsey v. Chevron, USA, Inc., 94 F.3d 1470, 1476 

(10th Cir.1996)). 

While the issue of subsurface trespass has been reviewed in only a handful of cases in New 

Mexico, discussed above, the issue has been more fully considered in other jurisdictions, offering 

guidance for conflicts that have not yet been addressed in this state. 

The law of subsurface trespass has, by and large, paralleled the development of oil and gas law 

in that, in many ways, whether an action lies in the former has been dependent on the reasoning 

of the latter. One of the earlier subsurface trespass claims exemplifies this dependent relationship 

addressing the question of ownership of injected gas to determine whether a trespass claim was 

valid. In Hammonds v. Central Kentucky Natural Gas, 75 S.W.2d 204 (Ky. Ct. App. 1934) 

(overruled by Texas American Energy Corp. v. Citizens Fidelity Bank & Trust Co., 736 S.W.2d 

25, 28 (Kentucky S. Ct. 1987)), the plaintiff/appellant brought an action for trespass given that 

her 54 acres of property were included within the boundary of defendant’s/appellee’s 15,000-

acre natural gas storage field without her knowledge or consent. Hammonds, 75 S.W.2d at 204. 

The court analogized natural gas to wild animals and thereby applied the ancient rule of ferae

naturae to the natural gas, even that which had been previously reduced to possession and 

controlled on the surface. Id. at 205; see Bezzi v. Hocker, 370 F.2d 533 (10th Cir.1966) (stating 

that ownership was lost when gas was re-injected into the common source of supply and 

commingled with virgin gas). Following this analogy, the court found that “if in fact the gas 

turned loose in the earth wandered into the plaintiff’s land, the defendant is not liable to her for 

the value of the use of her property, for the company ceased to be the exclusive owner of the 

whole of the gas – it again became the mineral ferae naturae.” Id. at 207. 

This holding was met with contemporaneous disapproval in numerous other jurisdictions, Fred 

McGaha, Underground Gas Storage: Opposing Rights and Interests, 46 La. L. Rev. 871, 873 
30

(1986), but was not explicitly overruled in Kentucky until 1987. See Texas American Energy 

Corp., supra, (“[I]n those instances when previously extracted oil or gas is subsequently stored 

in underground reservoirs capable of being defined with certainty and the integrity of said 

reservoirs is capable of being maintained, title to such oil or gas is not lost”). During the 

intervening time many jurisdictions followed the contradictory reasoning of White v. New York 

State Natural Gas Corp., 190 F. Supp. 342 (W.D.Pa. 1960), which held that gas in storage “has 

not escaped from its owners,” but “is yet very much in the possession of the storage companies, 

being within a well-defined storage field ... and being subject to the control of the storage 

companies...” Id. at 348. See also Lone Star Gas Company v. Murchison, 353 S.W.2d 870 (Ct. 

Civ. App. Texas 1962) (“the owner of gas does not lose title thereof by storing the same in a 

well-defined underground reservoir”); but see Anderson v. Beech Aircraft Corp., 237 Kan. 336, 

699 P.2d 1023 (Kansas S. Ct. 1985) (injector not a natural gas public utility lost ownership to gas 

stored when no certificate authorizing storage was obtained and the use of subsurface storage 

space was without authorization or consent of landowner). 

In holding that ownership of injected gas previously reduced to possession is retained by the 

injector, the courts have had to distinguish between native gas and non-native gas. See White v. 

New York State Natural Gas Corporation, 190 F.Supp. 342, 347-348, 349 (W.D.Pa.1960) 

(distinguishing between chemical and physical properties of depleted native gas and injected 

stored gas); Humble Oil & Refining v. West , 508 S.W.2d 812, 817 (Tex. 1974) (distinguishing 

between native gas and “extraneous gas” for purposes of determining royalty payments); Reese 

Exploration v. Williams Natural Gas 983 F.2d 1514 (10th Cir. 1993) (distinguishing between 

non-native and native gas); Ellis v. Arkansas Louisiana Gas Co., 450 F.Supp. 412, 419 (E.D. 

Okla. 1978) (holding there is no commingling of economically recoverable native gas and 

storage gas). 

Having established ownership of stored gas and distinguishing between native and non-native 

gas, courts then began holding storage companies liable for damage arising from their injections 

of extraneous gas, including actions for subsurface trespass. 46 La. L. Rev. 871, 879 (1986). In 

New Mexico, the state legislature has statutorily declared that gas storage companies are the 

owners of injected gas. NMSA 70-6-8 (1995). 

The issue of subsurface trespass quickly becomes complex and how it has been analyzed 

depends greatly upon whether the materials involved in the alleged trespass are part of normal 

hydrocarbon recovery (enhanced recovery), a function of natural gas storage, or whether they are 

part of a disposal process, as each appears to be governed by a semi-distinct set of policy-based 

trespass rules. 

In the case of enhanced hydrocarbon recovery, a theory favoring the senior mineral estate 

developed in oil and gas law known as the “negative rule of capture,” which has been applied to 

the injection of fluids generally involved in the secondary or tertiary recovery of hydrocarbons, 

and which is now viewed with disfavor by most jurisdictions and legal scholars, Fred McGaha, 

Underground Gas Storage: Opposing Rights and Interests, 46 La. L. Rev. 871, 884 (1986), but 

is nonetheless worthy of note. In upholding the rule, the Texas Supreme Court explained in 
31

Railroad Comm’n of Texas v. Manziel, 361 S.W.2d 560 (Texas 1962), that the negative rule of 

capture suggests that “[j]ust as under the rule of capture a land owner may capture such oil or gas 

as will migrate from adjoining premises to a well bottomed on his own land, so also may he 

inject into a formation substances which may migrate through the structure to the land of others, 

even if it thus results in the displacement under such land of more valuable with less valuable 

substances.” Manziel, 361 S.W.2d at 568 (quoting Williams & Meyers: Oil and Gas Law, § 

204.5). Adopting this theory, the court laid out that the policy reasons for doing so were to 

encourage the maximal recovery of hydrocarbon resources, the extraction of which by secondary 

or tertiary recovery methods could otherwise be blocked by any adjoining property interest on 

the basis of subsurface trespass claims. Id. The court held that the rules and principles of surface 

trespass are not applicable to subsurface invasions resulting from secondary recovery of natural 

resources when authorized by the state commission. Id. This position, while not tested directly 

in New Mexico, has been preemptively and explicitly rejected by the state’s Supreme Court in 

dicta. Snyder Ranches, Inc., 798 P.2d at 590 (“The issuance of a license by the State does not 

authorize trespass or other tortious conduct by the licensee, nor does such license immunize the 

licensee from liability for negligence or nuisance which flows from the licensed activity”). 

Rather than employing the negative rule of capture, most jurisdictions hold that mineral interests 

may make valid claims of subsurface trespass against injectors causing impairment to or 

displacement of their valid mineral interest. The New Mexico court has expressed its willingness 

to recognize trespasses upon the mineral estate as in Snyder Ranches, supra, and in Hartman v. 

Texaco Inc., 1997-NMCA-032, 123 N.M. 220, 937 P.2d 979 (NM Ct. App. 1997). In Hartman, 

the court recognized, but declined to review, the lower court’s holding that Texaco’s injected 

water had trespassed upon Hartman’s lease. Hartman, 937 P.2d at 983. For more complex cases 

of mineral trespass, rulings from other jurisdictions must serve as guide. 

In Humble Oil & Refining v. West , 508 S.W.2d 812 (Texas 1974), the action was not strictly 

one of trespass, but plaintiffs (West) sought to enjoin Humble Oil from using a gas field as a 

storage facility until all native gas, which had been reserved from the conveyance of the storage 

rights and mineral and surface estates, had been depleted. Humble Oil owned the mineral 

interests and the surface estate, subject to West’s royalty interest, and had produced 89 percent of 

the recoverable gas reserves, averring that production of the remaining recoverable gas would 

have resulted in destruction of the reservoir’s gas storage capacity due to “watering out” of the 

pore space. West, 508 S.W.2d at 814, 816. Humble Oil had injected extraneous gas into the 

formation for storage. The Supreme Court of Texas refused to require Humble Oil to produce the 

remaining native gas to depletion for that would destroy their property right to the storage space. 

Id. at 816. Instead, the court attempted to balance the competing interests and ruled that the 

burden is on the party commingling gases to properly identify the “aliquot share” of each owner 

and to pay a royalty on that amount, but if that share is not possible to establish with “reasonable 

certainty,” the injector is then responsible for paying royalties on all gas subsequently produced 

from the field, extraneous stored gas and native gas alike. Id. at 817-819. 

In the case of natural gas storage, the federal Natural Gas Act, 15 U.S.C. § 717 et seq., provides 

for the right of eminent domain for the construction of pipelines over private land, which has 
32

been interpreted to include the right to condemn subsurface storage space (“the necessary land or 

other property, in addition to right-of-way, for the location of compressor stations, pressure 

apparatus, or other stations or equipment necessary to the proper operation of such pipe line”). 

15 U.S.C. § 717f(h) (emphasis added); see Columbia Gas Transmission Corp. v. Exclusive Gas 

Storage Easement, 776 F.2d 125, 128 (“we read the words ... [compressor stations, pressure 

apparatus or other stations or equipment] as sufficiently broad to encompass the underground gas 

storage facility”). At the state level, subsurface storage of natural gas and the condemnation of 

subsurface storage space is provided for in NMSA 70-6-1 et seq. 

By enacting the Natural Gas Act, Congress, it is argued, has effectively preempted common-law 

trespass claims, leaving only the action of inverse condemnation available to property holders. 

Steven D. McGrew, Selected Issues in Federal Condemnations for Underground Natural Gas 

Storage Rights: Valuation Methods, Inverse Condemnation, and Trespass, 51 Case W. Res. L. 

Rev. 131, 147 (Fall 2000). The resolution of this question has significant financial implications 

as punitive damages are available for trespass claims, but only compensatory damages are 

available for inverse condemnation claims. Id. at 150, 163-164. This concern, however, may not 

apply to the sequestration of carbon dioxide because there has been no federal preemption of this 

regulatory field, as there has arguably been for storage of natural gas in the enactment of the 

Natural Gas Act. See Columbia Gas Transmission Corp. v. An Exclusive Natural Gas Storage 

Easement in the Clinton Subterranean Geological Formation Beneath 80 Acres, Worthington 

Twp., Richland County, Ohio, 747 F.Supp. 401, 403 (N.D. Ohio, E. Division 1990). Without 

pursuing this issue further, it is presumed that common law trespass remains a viable action for 

carbon dioxide sequestration and has not been federally preempted. However, it is possible 

landowner actions could be constrained statutorily by the state legislature to inverse 

condemnation, which would have the desirous effect of limiting an injector’s liability, and 

thereby encourage sequestration by eliminating the possibility of punitive damage awards. 

In the case of hazardous waste disposal, the courts have been careful to distinguish injections 

related to the extraction of oil and gas from injections unrelated to hydrocarbon production. In 

Chance v. BP Chemicals, 670 N.E.2d 985 (Ohio 1996), the Ohio Supreme Court found that “a 

special body of law has arisen [around oil and gas cases] based on special circumstances,” Id. at 

991, not present with the injection of other materials. However, this distinction seems to have 

been made for the primary purpose of avoiding the application of the negative rule of capture. Id. 

(“Since appellee's injection well operation has nothing to do with the extraction or storage of oil 

or gas, we find the negative rule of capture inapplicable to our consideration of this case”). 

Perhaps the most interesting holding in Chance is the limitation of the surface owner’s 

subterranean interests, discussed above. The Ohio court looked to Willoughby Hills v. Corrigan, 

29 Ohio St.2d 39, 49, 58 O.O.2d 100, 105, 278 N.E.2d 658, 664 (1972), which cited United

States v. Causby, 328 U.S. 256, 66 S.Ct. 1062, 90 L.Ed. 1206 (1946), to state that the doctrine of 

“Cuius est solum” “has no place in the modern world.” Id. at 991. The Ohio court also extended 

the reasoning of Hinman v. Pacific Air Transp., 84 F.2d 755, 758 (C.A. 9, 1936) (“We own so 

much of the space above the ground as we can occupy or make use of, in connection with the 

enjoyment of our land”) to apply equally to below-ground interests. Id. at 991-992. While 

ultimately limiting the surface owners’ subterranean interests, the court did not go so far as to 

preclude subsurface trespass, but required that any injection must be shown to interfere with a 

landowner’s “reasonable and foreseeable use” of the property. Id. at 992. 
33

A powerful policy argument, however, has been made to limit the application of the holding in 

Chance. Steven D. McGrew has posited that “subsurface rights should be treated differently than 

air rights because the historical use of subsurface property has been much more extensive and 

profitable for property owners than the historical use of air rights.” 51 Case W. Res. L. Rev. 131, 

178. Landowners have had the right to profit off the valuable subsurface resources, including 

caves and mineral resources, such as natural gas. Id. Because the landowner has an 

unquestionable right to profit from and alienate these subsurface interests: 

...storage operators cannot plausibly argue that property owners 

have no protectable property interest in the same geological 

formation in which they did have a protectable and alienable 

interest when the formation contained native natural gas. Such a 

reversal should require strong justification. While it is true that 

underground natural gas storage serves an important public 

interest, that alone would not provide sufficient justification, for 

the Constitution forbids the taking of property for the public 

interest without the payment of just compensation.... Given these 

considerations, it is not difficult to come to the conclusion that a 

storage operator that knowingly uses property – even subsurface 

property – without paying for the right to do so should be liable for 

trespass. 

Id. at 178-179. 

The 10th Circuit has employed a slightly lower standard of proof for subsurface trespass claims 

than the standard, discussed above, that New Mexico courts appear to apply. In the 10th Circuit, 

subsurface trespass claims have been successful when circumstantial evidence was sufficient to 

demonstrate that the injectors expected the injected material to enter the landowner’s subsurface. 

Beck v. Northern Natural Gas Co., 170 F.3d 1018 (10th Cir. 1999). In Beck, the court did not 

require each landowner to “directly prove” that storage gas was actually located under each 

property because the circumstantial evidence presented was sufficient to demonstrate that the 

target formation was highly permeable, continuous and interconnected beneath the plaintiffs’ 

properties. Id. at 1022 Also, and most importantly, the defendant itself had earlier sought to 

prove the entire acreage was suitable for gas storage, had demonstrated that a significant portion 

of the field’s storage capacity was in the formation below each plaintiff, and testimony from 

defendant’s senior engineer stated that defendant “had actually been storing gas in 

the...formation under all of the landowners for the prior seventeen years.” Id. 

Subsurface infringement can, by the common law process of adverse possession, establish a 

prescriptive easement to the subsurface pore space. Ellis v. Arkansas Louisiana Gas Co., 450 

F.Supp. 412 (E.D. Okla. 1978) aff'd 609 F.2d 436 (10th Cir 1979). In Ellis, the court held that, as 

required by Oklahoma law, a prescriptive right may be acquired by establishing each of the 

elements of adverse possession (actual, adverse, open, notorious, peaceable, exclusive and 

hostile possession) for a period of fifteen years. Ellis, 450 F.Supp. at 423-424. In Ellis the court 
34

held that the plaintiffs, seeking damages for unauthorized storage of gas beneath their property, 

and their predecessors in title knew that a geologic formation under their land was part of the 

region’s gas storage facility, that it had been used as such continuously for nearly 30 years, and 

that the injection facilities were obviously visible and that plaintiffs knew their purpose, thereby 

establishing the prescriptive easement and the right to store gas. Id. at 424. 

Injection of carbon dioxide (CO2) into the subsurface would qualify in New Mexico and 

elsewhere as a direct physical infringement adequate to establish the action of trespass. CO2 is 

no different than the various injected materials contemplated for subsurface infringement in 

Schwartzman (chemical contaminants), Snyder (salt water) Hartman (salt water), and Beck

(natural gas). The Texas Supreme Court, for example, has held that fracing can be a subterranean 

trespass. Mission Resources, Inc., v. Garza Energy Trust, 166 S.W.3d 301, 310-311, 160 Oil & 

Gas Rep. 1144 (Tx. Ct. App. 2005) (“fracing can create a subsurface trespass if the invasion 

alleged is direct and the action taken intentional”). 

The difficulty in establishing a valid action for subsurface trespass will be in demonstrating 

actual physical infringement, especially as New Mexico appears to apply a more stringent 

standard of proof than, for example, the 10th Circuit. Proof of infringement in New Mexico 

appears to require more than mere affidavits or expert testimony, but some demonstration of 

actual, physical infringement, such as sampling evidence from groundwater monitoring wells, 

soil samples, air monitoring or geophysical surveys. Landowners seeking to establish a trespass 

claim against CO2 injectors would also likely have to demonstrate that any CO2 detected is 

injected gas, as opposed to native gas. As explained in Schwartzman, such burden is on the 

landowner to establish, which means the landowner would have to pay for the monitoring and 

analysis. This burden makes establishing non-obvious, minimally intrusive CO2 trespass actions 

difficult. However, if the New Mexico courts were to adopt a standard more akin to that 

expressed by the 10th Circuit in Beck, subsurface trespass could be easier to establish if the 

property in question is within the contemplated storage field or its designated buffer zone. This 

would likely be so because, as part of the permitting process, the state will likely require a 

description of the formation and its areal extent targeted for CO2 injection; such information that 

the court found to be adequate circumstantial evidence to establish subsurface trespass in Beck. 

By the same token, such claims should be eliminated by a requirement that any CO2 injection 

project acquire the storage rights for the proposed project area, either through negotiation or 

condemnation proceedings. Trespass claims are more likely to arise in cases where the storage 

project has exceeded its proposed area of influence, and injected CO2 has migrated beyond the 

intended project boundaries, in which cases such circumstantial evidence is not likely to be as 

readily available or may be non-existent for landowners to rely upon to establish the validity of 

their claims. 

The implied authorization for injection that applies to secondary recovery of hydrocarbons likely 

won’t be applicable to the vast majority of CO2 injection projects as CO2 floods and enhanced 

oil and gas recovery are anticipated to make up only a small fraction of the total sequestration 

volume in New Mexico. 
35

If carbon dioxide emissions become federally regulated, its storage/injection would likely be 

considered permanent, as subsequent release back to the atmosphere will face a number of 

significant policy, regulatory and practical barriers. For this reason calculation of damage awards 

for subsurface trespass claims in New Mexico may be figured based on the diminution of value 

of the entire property, as outlined in McNeill. However, compensating the landowner at a rate 

equivalent to the loss of rental value, since the storage space is no longer available to the surface 

owner for other rental/storage purposes, seems to make better policy sense, while also perhaps 

more effectively protecting the interests of the landowner, because it avoids the difficulties 

inherent in calculating the diminution of value to the entire property. Where the market rental 

value for the storage space will be conceivably more ascertainable than an uncertain and 

nebulous determination of the diminution of value, the more certain, comparable and measurable 

method should probably be employed. This measure, however, may be something that is 

addressed by the courts unless the legislature develops a subsurface trespass statute that spells 

out damages. Alternatively, surface owners may opt to claim unjust enrichment or sue under 

assumpsit for breach of implied contract, as discussed above, to avoid the difficulty of 

ascertaining damages under trespass. 

Further Issues Raised During Analysis: 

1. At what point does CO2 injection become storage and require acquisition of storage 

space rights? (Because there are limited CO2 sequestration/storage projects, this question 

has not been tested yet in the courts). 

2. At what point is a mineral interest considered depleted/non-economic? 

3. Can non-depleted mineral interests claim trespass against injector of carbon dioxide? 

4. Would the injection of carbon dioxide constitute temporary or permanent trespass? 

5. Does the state have authority to condemn federal pore space? How will 

condemnation/storage be handled within federally owned pore space? 

6. What is the proper process upon termination of a mineral lease to transition to CO2 

sequestration from EOR? 

7. What uses of aquifer storage require compensation? Compensation to whom? 

8. How will condemnation of pore space for CO2 sequestration affect current acid gas and 

saline water injection practices? 

Unitization of Recoverable Hydrocarbons 

Issue: 

In order to account for the enhanced recovery anticipated from injecting CO2 into depleted oil 

and gas pools it will be necessary to unitize such pools. That is, by either voluntary agreement 

among the pool operators or through a Division order compelling it, depleted oil and gas fields 

subject to CO2 sequestration/injection will need to be operated as a unit in order to equitably 

allocate costs and production among the various interests. Distinguishing between the pore space 

interests and the mineral interests, such unitization will apply only to the mineral interests. 
36

In anticipation of the scale of commercial CO2 sequestration, it is expected that most, if not all, 

depleted oil and gas fields in the state will be evaluated for sequestration and may therefore 

require unitization on a large scale. 

Analysis: 

The authority granted by the Statutory Unitization Act (NMSA 70-7-1 et seq.), provides for 

voluntary or compulsory unitization of a pool or part of a pool. The Act requires that the plan of 

unitization, whether voluntary or compulsory, be ratified by three-quarters of the working 

interest, royalty interest and overriding royalty interest owners. The consequence is that OCD 

can only compel unitization against the minority interest. This may prove an unacceptable means 

of blocking planned sequestration projects, as minority interests could refuse to ratify unitization 

orders, making operation of the unit as a sequestration field difficult. Non-unitized interests may 

have available to them legal remedies such as nuisance and trespass actions for any provable 

interference with their mineral production. It may, however, be desirable for injectors to have 

acquired some level of voluntary agreement for unitization among mineral interests before 

enabling compulsory unitization by Division order. 

Under an effective CO2 sequestration program it is anticipated that OCD would need to unitize 

larger areas than is now normally the practice. However, there is a precedent in the nearly 1 

million acre Bravo Dome Unit that produces CO2 in northwest New Mexico.. 

The Act also requires OCD to find that unitization will “substantially increase the ultimate 

recovery of oil and gas from the pool or unitized portion thereof.” NMSA 70-7-5. Because 

increased recovery may not always result in a program designed primarily for the sequestration 

of CO2, this language may pose a barrier. 

The Act further requires OCD to find “that the estimated additional costs, if any, of conducting 

such operations will not exceed the estimated value of the additional oil and gas so recovered 

plus a reasonable profit.” NMSA 70-7-6.A(3). Interpreted to mean the costs of production of 

additional hydrocarbons (CO2 separation and re-injection/cycling, etc.) as opposed to the costs 

of the entire sequestration project, this language should not pose a barrier. 

Statutory continuation of expiring leases may be considered to facilitate planning and 

implementation of CO2 sequestration projects. 

Unitization of federal minerals with non-federal minerals is provided for in the federal “Mineral 

Leasing Act,” 30 USC Code, Chapter 3A, Subchapter 1 § 184a: “...any State owning lands or 

interests therein acquired by it from the United States may consent to the operation or 

development of such lands or interests, or any part thereof, under agreements approved by the 

Secretary of the Interior made jointly or severally with lessees or permittees of lands or mineral 

deposits of the United States or others, for the purpose of more properly conserving the oil and 

gas resources within such State. Such agreements may provide for the cooperative or unit 

operation or development of part or all of any oil or gas pool, field, or area; for the allocation of 

production and the sharing of proceeds from the whole or any specified part thereof regardless of 

the particular tract from which production is obtained or proceeds are derived; and, with the 

consent of the State, for the modification of the terms and provisions of State leases for lands 
37

operated land developed thereunder, including the term of years for which said leases were 

originally granted, to conform said leases to the terms and provisions of such agreements...” 

Further Issues Raised During Analysis: 

1. Does the unitization of federal minerals conflict with the purpose of CO2 sequestration? 

How to handle sequestration units that include strata with federal minerals? 

2. What is the effect of Indian ownership on unitization for carbon sequestration? 

Condemnation of Storage Space and Transportation Corridors by Eminent Domain 

Issue: 

Subsurface sequestration space and surface easements for pipelines and injection facilities will 

be necessary for a large-scale sequestration program. 

OCD does not have the power under existing law to provide for the acquisition by eminent 

domain of subsurface pore space for the purposes of CO2 sequestration. Authority to condemn 

subterranean storage space, similar to provisions in NMSA 70-6-1 through 70-6-8 authorizing 

the condemnation of underground storage space for natural gas, would be necessary for CO2 

sequestration operators to acquire the storage rights from property owners who have not reached 

an agreement. 

Compensable parties may not be limited to the target pore space owners, however, as there may 

be room for mineral interests to argue that since oil and gas reservoirs may never be fully 

depleted, CO2 sequestration constitutes interference with their estate and requires just 

compensation if interference or harm is provable. Currently, New Mexico law prohibits the 

condemnation of storage space for gas storage in strata capable of producing oil in paying 

quantities through any known recovery method. Likewise, no strata capable of producing gas in 

paying quantities can be condemned unless the recoverable volumes of native gas are 

substantially depleted and unless the formation has greater value or utility as a storage reservoir. 

The state currently has authority under 70-3-5 to condemn surface land for pipeline construction, 

including CO2 pipelines. This provision applies only to trunk lines, or primary transportation 

lines, and not to gathering lines or presumably to CO2 injection lines. NMSA 70-3A-1 et seq. 

establishes the means by which easements for smaller disposal lines and gathering lines may be 

acquired across private property. 

All condemnation proceedings must be done in accord with and pursuant to NMSA 42-1-1 to 

42A-1-33. 

Issues Raised During Workgroup Meeting: 

 Will the size and scale of the units/formations make condemnation difficult or cost 

prohibitive? 

 If the goal is to condemn only the target storage space/interval/strata, what’s the effect on 

the other intervals? Can hydrocarbon exploration/production continue in other intervals? 
38

 What’s the method of valuation for condemnation? 

 Compensation to the pore space owner should be offset by the value of any liability 

assumed by the state that would otherwise reside with the pore space/surface owner 

Analysis: 

NMSA 70-6-1 et seq. can either be amended to include condemnation for CO2 sequestration or 

condemnation provisions may be included in a separate statute, but because the target pore space 

and geologic formations are the property interests of the surface owner, a process for the 

condemnation of the pore space for CO2 storage must be established to accommodate situations 

where surface owners and injectors are unable to agree on sequestration terms. 

Several methods of valuation have been analyzed by the courts for determining the fair market 

value of pore space for storage of natural gas that may be applicable to valuation of sequestration 

space for CO2: 

 Comparable agreements/rentals/sales 

 Capitalization of rental income: multiply acreage rental by comparable storage rights to 

arrive at present worth of the future income stream, using filing date of condemnation as 

start date and termination of storage field as end date. Fair market value is equated to a 

capital sum which, when invested as of the date of the filing, would earn income equal to 

comparable storage rentals for the future 

 Depreciation in the fair market value of condemned tract as a whole by reason of the 

taking of the storage easement: based on the difference in the fair market value of the 

entire condemned tract before and after the taking. 

 Viewpoint of value: just compensation should be measured from the point of view of the 

landowner (what the landowner has lost, not what the petitioner (injector) has gained), 

e.g., if there are still quantities of native oil or gas in the storage easement not in paying 

quantities (having no effect on the tract’s market value), then these volumes would not be 

taken into account in the valuation. 

On the issue of whether compensation is necessary for the mineral estate interests, CO2 

sequestration might be sufficiently distinguishable from the storage of natural gas in that it does 

not preclude later or even concurrent production of hydrocarbons, and may be anticipated to 

generate, facilitate or increase such production. Unlike the situation for storage of natural gas 

which essentially precludes concurrent hydrocarbon recovery, there may be no ostensibly 

negative impact or interference with the production of the mineral estate beyond the cost of 

segregating the CO2 from production volumes (which production is expected to be enhanced by 

the CO2) and re-injecting/cycling it back into the formation. 

Further Issues Raised During Analysis: 

1. Valuation of otherwise non-recoverable/non-economic minerals 
39

Authority to Transfer Liability/Ownership to State 

Issue: 

The various forms of liability (e.g. economic and environmental) inherent in proposed 

sequestration projects and how they will be addressed within a given regulatory framework are 

perceived as being significant factors in making sequestration projects feasible on the industry 

side, but also as being crucial for advancing public acceptance of the technologies, processes and 

regulations. 

Short-term liabilities inherent in any drilling or injection project – whether environmental or 

economic – can likely be best addressed through the contractual arrangements between CO2 

generator and injector, as such liabilities are currently handled. But liabilities following the 

injection and closure phases of the projects present a unique problem given the long-term 

economic and environmental unknowns and the anticipated scale of sequestration projects, both 

in terms of time and space, required for successful CO2 mitigation. 

Nearly all of the sequestration literature assumes that long-term liability must be transferred to 

the public sector to maintain economic viability and to encourage industry participation. Because 

the lifespan of sequestration projects after closure, which would include continuous monitoring, 

measurement and verification (MMV) of the reservoir integrity, is contemplated to endure for 

possibly hundreds to thousands of years, the public sector (because of the longevity of public 

institutions and the ease of transferability of institutional knowledge) is seen as the most viable 

entity capable of maintaining these projects over the long term. Alternatives include having the 

state accept liability for a limited number of projects (e.g. the first enhanced oil recovery project, 

the first deep saline project, the first deep coal project, etc.) or for a limited time frame (e.g. first 

5 years of CO2 sequestration), or for injectors and the carbon sequestration industry to retain 

ownership and liability with coverage provided by a combination of individual liability, 

insurance, and an industry-funded trust fund. 

Policy Considerations: 

 Is transfer of liability and ownership of CO2 to the public sector the proper model? 

 Should there be a limit to the liability that is transferred? Should the state be indemnified 

against claims or mitigation costs above a certain amount? 

 Should the state accept liability for only a certain number of projects (e.g. the first 

enhanced oil recovery project, the first several deep saline projects, the first deep coal 

projects, etc.) or should the state accept liability for those projects initiated within a 

limited time frame (e.g. first 5 years of CO2 sequestration)? 

 If liability is transferred to the public sector, how shall the costs be funded – a fee 

program based on volume of CO2 injected? 

 Should the generator or injector retain any liability – environmental, economic or for 

CO2 accounting purposes? 

 Should CO2 generators/injectors have the choice to transfer liability to the public sector 

and pay a long-term liability fee or maintain liability with bonding to cover insolvency or 

abandonment? 

 Who owns the sequestered CO2 should it become a viable product in the future? 
40

Issues Raised During Workgroup Meetings: 

 Will the state be liable for mitigation/damages after transfer? Should state liability 

beyond the amount covered by the fee pool be protected as a sovereign immunity? 

 Texas proposes to accept liability only for FutureGen sites. 

 If there is a fee, it should be used only for mitigation, long-term monitoring, and 

verification of sequestration projects (i.e. protected against other legislative 

appropriations). 

 State should only take on ownership/liability of projects where monitoring following 

cessation of injection/operations indicates the project is performing as predicted. 

 State should only take on ownership/liability of projects with a demonstrated leakage rate 

of less than 1 percent? 

 How will parties/individuals injured be able to recover? Through industry fund? 

 An alternative to a sequestration fee is to fund the long-term monitoring, measurement, 

verification and mitigation through a portion of the severance taxes collected on the 

enhanced recovery made possible by the CO2 injections. 

 Having the state take on the long-term liability makes the project more appealing – the 

sooner the state takes on liability the more appealing the project 

 If there is a transfer of liability, the state must have the right to enter private land and 

plug/re-plug problem wells within the sequestration unit to ensure field/storage integrity. 

 Is/will CO2 be considered a “hazardous substance” under federal CERCLA/RCRA laws 

and how might that impact liability for generators, transporters and disposers/injectors? 

Analysis: 

Because the issues of financial assurance and liability are, in many ways, so tightly interrelated, 

the review and analysis of these issues have been addressed jointly. 

The literature reviewing carbon dioxide sequestration liability and financial assurance issues 

looks to several pre-existing regulatory models for possible guidance. Those regulatory schemes 

are reviewed and discussed below. Finally, drawing from these models and the workgroup 

comments, a proposed regulatory and liability scheme is presented for discussion, however, 

OCD makes no recommendation as to the proper liability scheme at this time. 

Price-Anderson Nuclear Industries Indemnity Act: 42 U.S.C. s. 2210 

The Price-Anderson Nuclear Industries Indemnity Act (Act), passed into law in 1957 and revised 

and extended on several occasions since, serves to partially indemnify the nuclear industry 

against liability claims arising from nuclear incidents while making available a large pool of 

funds to cover public compensation for claims of personal injury and property damage. The Act 

holds nuclear reactor operators/owners strictly liable for “extraordinary nuclear occurrences,” as 

defined by the Act and within the financial limits imposed by the Act. Claimants must establish 

negligence or that there was a violation of some standard or regulation to demonstrate liability 

for other “nuclear incidents.” 
41

The Act was originally deemed necessary to jump start a private nuclear power industry, which 

otherwise viewed the then-unquantified liability risks associated with nuclear power production 

as a complete deterrent. (American Nuclear Society, Background for Position Statement 54). 

Licensees under the Act must obtain the maximum amount of liability insurance available on the 

market, which is currently set at $300 million per reactor. Any valid monetary claims that fall 

within this amount are paid for by the insurers. Beyond that, the Price Anderson fund, financed 

by the licensees themselves as provided for by the Act, makes up the difference. Each licensee is 

responsible for a maximum contribution to the fund of $95.8 million in the event of an accident. 

The total fund would currently cover about $10 billion in public liability claims (based on the 

number of operational reactors at present), but no licensee must pay more than $15 million for 

any given incident in a single year. In this scheme, any costs exceeding the coverage provided by 

first the insurance and then the fund would be covered by the federal government. 

The Act requires as a condition of the operating license issued by the Nuclear Regulatory 

Commission that the licensee “have and maintain financial protection of such type and in such 

amounts as the [Commission] in the exercise of its licensing and regulatory authority and 

responsibility shall require ... to cover public liability claims.” 42 U.S.C. § 2210(a). The Act 

further provides that the Commission may, also as a condition of the license, “maintain an 

indemnification agreement,” but also “that an applicant waive any immunity from public liability 

conferred by Federal or State law.” Id. According to 42 U.S.C. § 2210 (c), the NRC shall “with 

respect to licenses issued between August 30, 1954, and December 31, 2025,” for which 

financial protection of less than $560,000,000 is required, “agree to indemnify and hold harmless 

the licensee and other persons indemnified, as their interest may appear, from public liability 

arising from nuclear incidents which is in excess of the level of financial protection required of 

the licensee.” Further, “[t]he aggregate indemnity for all persons indemnified in connection with 

each nuclear incident shall not exceed $500,000,000 excluding costs of investigating and settling 

claims and defending suits for damage, provided, however, “that this amount of indemnity shall 

be reduced by the amount that the financial protection required shall exceed $60,000,000. 42 

U.S.C. § 2210(c). Such indemnification contracts “shall cover public liability arising out of or in 

connection with the licensed activity.” Id. 

The Act goes on to provide that the NRC or the Energy Secretary may incorporate provisions in 

indemnity agreements or insurance policies or contracts as proof of financial protection that 

waive “any issue or defense as to conduct of the claimant or fault of persons indemnified” for 

“any extraordinary nuclear occurrence” to which an insurance policy or contract furnished as 

proof of financial protection or an indemnity agreement applies. 42 U.S.C. § 2210(n). This 

section of the Act essentially establishes that nuclear facilities “stand strictly liable” for an 

“extraordinary nuclear occurrence,” so that nuclear incidents that are not deemed “extraordinary” 

do not trigger strict liability and a claimant must prove negligence or establish a regulatory 

violation. 14 Am. Jur. Proof of Facts 3d 85 § 16. According to the Act, an “extraordinary 

occurrence” is defined as “any nuclear event causing a discharge or dispersal of course, special 

or nuclear, or by-product material from its intended place of confinement in amounts off site, or 

causing radiation levels off site, which the Nuclear Regulatory Commission or Secretary of 

Energy, as appropriate, determines to be substantial, and which , determines has resulted or will 

probably result in substantial damages to persons off site or property off site.” Id. (citing 42 
42

U.S.C. § 2214 (j)). 

The Act requires that the primary financial protection required for large nuclear reactors (larger 

than 100 mega-Watts) “shall be the maximum amount available at reasonable cost and on 

reasonable terms from private sources.” 42 U.S.C. § 2210(a)(1). The Act provides that “primary 

financial protection may include private insurance, private contractual indemnities, selfinsurance, other proof of financial responsibility, or a combination of such measures, and shall 

be subject to such terms and conditions as the Commission may, by rule, regulation, or order, 

prescribe.” Id. But the Act allows a licensee to defer premiums under an industry “retrospective 

rating plan” that defers in whole or in major part the premium charges “until public liability from 

a nuclear incident exceeds or appears likely to exceed the level of the primary financial 

protection [i.e. the insurance] required of the licensee involved in the nuclear incident.” Id. The 

Act also limits the maximum amount of the deferred premium that may be charged against a 

licensee following any nuclear incident to no more than $95.8 million, subject to adjustment for 

inflation, and not more than $15 million in any single year, also subject to adjustment for 

inflation. Id. The Act further limits a licensee’s liability by limiting the amount that may be 

charged following a nuclear incident to the licensee’s pro rata share of the aggregate public 

liability claims and costs. Id. 

According to the Act, the aggregate public liability for a single nuclear incident of persons 

indemnified, including legal costs authorized within the Act, is limited to the maximum amount 

of financial protection required of large nuclear reactors (100 mega-Watts or more). 42 U.S.C.A. 

§ 2210 (e)(1)(A). But in the event that a nuclear incident involves damages in excess of the 

amount of the aggregate public liability, “Congress will thoroughly review the particular incident 

... and take whatever action is determined to be necessary (including approval of appropriate 

compensation plans and appropriation of funds) to provide full and prompt compensation to the 

public for all public liability claims resulting from a disaster of such magnitude.” 42 U.S.C.A. § 

2210 (e)(2). 

In such cases, the Act provides that the Energy Secretary or the Nuclear Regulatory Commission 

(NRC) shall “make a survey of the causes and extent of damage” and “expeditiously” submit a 

report to Congress, the Representatives of the affected districts, the Senators of the affected 

states and to the public, the parties involved, and to the courts. 42 U.S.C.A. § 2210 (i)(1)(A)-(B). 

Within three months of the incident the President must submit to Congress an estimate of the 

dollar value of personal injuries and property damage in excess of the aggregate public liability 

and recommendations for additional sources of funds to pay claims. 42 U.S.C.A. § 2210 

(i)(2)(A)-(B). 

The NRC codifies the conditions for indemnity agreements, liability limits, and fees for the 

different classes of licenses in 10 CFR pt. 140. Generally, reactors rated below 100 mega-Watts 

have lower primary insurance requirements than larger reactors. 10 CFR § 140.11 (a)(1)-(4). 

Coverage for non-profit educational reactors is a function of their maximum power and the size 

of the neighboring population (x = B(P), where x is the amount of financial protection; B is the 

base amount of financial protection ($185 times the maximum power level); and P is the 
43

population factor (on a scale from 1 to 2; and area considered is within a radius in miles equal to 

the square root of the maximum reactor power level)). 10 CFR § 140.12. Large commercial 

reactors are required to obtain financial protection “[i]n an amount equal to the sum of 

$300,000,000 and the amount available as secondary financial protection (in the form of private 

liability insurance available under an industry retrospective rating plan providing for deferred 

premium charges equal to the pro rata share of the aggregate public liability claims and costs 

...).” 10 CFR § 140.11 (a)(4). As discussed above, such deferred premium charges are limited to 

$95.8 million with respect to any nuclear incident and $15 million per incident within a single 

year. Id.; 42 U.S.C. § 2210(a)(1). In cases where a licensee is authorized to operate two or more 

nuclear reactors at the same location, the total primary financial protection required is the highest 

amount that would otherwise be required for any one of those reactors. 10 CFR § 140.11 (b). 

The NRC’s regulations further require that each licensee at the issuance of the license, and 

annually, demonstrate to the Commission that it maintains one of several types of guarantee of 

payment of deferred premium (surety bond, letter of credit, revolving credit/term loan 

arrangement, maintenance of escrow deposits of government securities, annual certified financial 

statement showing that cash can be generated and made available, or other type of guarantee “as 

may be approved by the Commission”) in an amount of $15 million for each reactor licensed for 

operations. 10 CFR § 140.21. 

Resource Conservation and Recovery Act (RCRA); 42 U.S.C. § 6901, et seq. 

Enacted in 1976, the Resource Conservation and Recovery Act (RCRA) was passed to encourage 

the recycling of materials, establish a means to regulate the cleanup and proper storage and 

handling of hazardous wastes that pose a threat to human health and the environment, and to 

reduce dependence on foreign energy. 42 U.S.C. § 6901. Unlike the Comprehensive 

Environmental Response, Compensation and Liability Act (CERCLA, discussed below), 

however, RCRA regulates actively managed and operational sites, facilities and processes. 

Similar to the philosophy employed subsequently in the writing of CERCLA and in the 

formulation of the Underground Injection Control program (UIC), infra, RCRA directs the 

Administrator of the U.S. Environmental Protection Agency to promulgate regulations that, 

among other things, provide for the financial responsibility (including financial responsibility for 

corrective actions) of the responsible parties. 

According to the regulations, “[a]n owner or operator of each facility must establish financial 

assurance for closure of the facility” in accord with one of several options provided in the 

regulations. 40 C.F.R. § 264.143. One option is to establish a “closure trust fund.” § 264.143 

(a)(1). Payments into the trust fund must be made annually by the owner or operator over the 

term of the facility’s RCRA permit, or over the term of its remaining operating life, whichever is 

shorter. § 264.143 (a)(3). Annual payments are based on a formula where the payment is equal to 

the current closure cost estimate, subtracted by the current value of the trust fund, then divided 

by the years remaining in the pay-in period. § 264.143 (a)(3)(i). 
44

A second option is a surety bond, guaranteeing payment into a closure trust fund. § 264.143 (b). 

RCRA mandates that the wording of the surety bond be identical to that specified in § 264.151 

(b). When a surety bond is employed, the owner or operator must also establish a standby trust 

fund, so that under the terms of the bond, all payments made to the bond get deposited by the 

surety into the standby trust fund. § 264.143 (b). 

Another option is a surety bond guaranteeing performance of closure. § 264.143 (c). Such bonds 

must be effective before the initial receipt of hazardous waste for treatment, storage or disposal. 

§ 264.143 (c)(1). The surety company issuing the bond must, at a minimum, be among those 

listed as acceptable sureties on Federal Bonds in Circular 570 of the U.S. Department of the 

Treasury. Id. The wording of the bond must be identical to § 264.151 (c). As above, the owner or 

operator using a surety bond must also establish a standby trust fund. § 264.143 (c)(3). 

Also available as an option for financial assurance is a closure letter of credit, § 264.143 (d), 

which is established when an owner/operator obtains an irrevocable standby letter of credit from 

an issuing institution which has the authority to issue letters of credit and whose letter-of-credit 

operations are regulated and examined by a Federal or State agency. § 264.143 (d)(1). The 

wording of the letter of credit must be identical to the wording specified in § 264.151 (d). As 

above, an owner/operator who uses a letter of credit to satisfy the financial assurance 

requirements must also establish a standby trust fund. § 264.143 (d)(3). The letter of credit must 

be irrevocable, issued in an amount at least equal to the current closure cost estimate, and issued 

for a period of at least 1 year, providing that the expiration date will be automatically extended 

for a period of at least 1 year. § 264.143 (d)(5)-(6). 

Owner/operators can also meet their financial assurance requirements by obtaining closure 

insurance. § 264.143 (e). The closure insurance policy must be issued for an amount at least 

equal to the current closure cost estimate and must guarantee that funds will be available to close 

the facility whenever final closure occurs. § 264.143 (e)(3)-(4). The policy must provide that the 

insurer may not cancel, terminate, or fail to renew the policy except for failure to pay the 

premium, and the automatic renewal of the policy must provide, at a minimum, the insured with 

the option of renewal at the face value of the expiring policy. § 264.143 (e)(8). And, the policy 

must contain a provision allowing assignment of the policy to a successor owner or operator, 

though such assignment may be conditioned upon the consent and approval of the insurer, 

provided it is not unreasonably refused. § 264.143 (e)(7). Once final closure begins, an 

owner/operator may request reimbursements for closure expenditures by submitting itemized 

bills to EPA’s regional administrator, who will, if the expenses are in accordance with the 

approved closure plan or are otherwise justified, instruct the insurer to make reimbursements in 

the proper amounts if the cost of closure do not exceed the current insurance policy. § 264.143 

(e)(5). 

RCRA financial assurance can also be established through a financial test and corporate 

guarantee for closure, whereby an owner/operator demonstrates the ratio of its total liabilities to 

net worth is less than 2; a ratio of the sum of net income, plus depreciation, depletion, and 

amortization to total liabilities greater than 0.1; and a ratio of current assets to current liabilities 
45

of greater than 1.5; and a net working capital and net worth at least six times the sum of the 

current closure and post-closure cost estimates, and the current plugging and abandonment cost 

estimates; and tangible net worth of at least $10 million. § 264.143 (f)(1). To demonstrate that an 

owner/operator meets this test, it must submit a letter signed by the entity’s chief financial officer 

worded as specified in § 264.151 (f), and a copy of an independent, certified public accountant’s 

report. § 264.143 (f)(3). The owner/operator must submit updated information within 90 days 

after the close of each succeeding fiscal year; if it no longer meets the requirements above, the 

owner/operator must send notice of intent to establish alternate financial assurance, which must 

be obtained within 120 days after the end of such fiscal year. § 264.143 (f)(6). This financial test 

alternative can also be met by obtaining a written guarantee from a guarantor that is the direct or 

higher-tier parent corporation of the owner/operator, or a firm with a “substantial business 

relationship” with the owner or operator. § 264.143 (f)(10). 

Finally, an owner/operator may choose to use multiple financial mechanisms to achieve its 

financial assurance requirements. § 264.143 (g). Available mechanisms, however, “are limited to 

trust funds, surety bonds guaranteeing payment into a trust fund, letters of credit, and insurance. 

Id. Likewise, a single financial mechanism may be used to cover multiple facilities. § 264.143 

(h). For all mechanisms, whenever the current closure cost estimate increases to an amount 

greater than the amount of credit or financial assurance, the owner/operator must within 60 days 

after the increase, increase the financial assurance accordingly; whenever the current closure cost 

decreases, the amount of assurance required may be reduced accordingly with written approval 

by the EPA regional administrator. § 264.143 (a)(7), (b)(7), (c)(7), (d)(7), (e)(9), (f)(6). 

Similar mechanisms are available for funding post-closure financial assurance. § 264.145 et. seq. 

And, an owner/operator may satisfy the requirements for financial assurance for both closure and 

post-closure care for one or more facilities by using a trust fund, surety bond, letter of credit, 

insurance, financial test, or corporate guarantee that meets the specifications of §§ 264.143 and 

264.145. § 264.146. 

 

Beyond closure and post-closure financial assurance mandates, RCRA requires that 

owners/operators demonstrate financial responsibility “for bodily injury and property damage to 

third parties caused by sudden accidental occurrences arising from operations of the facility or 

group of facilities.” § 264.147(a). As such, RCRA requires liability coverage “in the amount of 

at least $1 million per occurrence with an annual aggregate of at least $2 million, exclusive of 

legal defense costs.” Id. Coverage may be achieved by acquiring a liability insurance policy, 

through a financial test or corporate guarantee, a letter of credit, a surety bond, by obtaining a 

trust fund, or a combination of such mechanisms. § 264.147 (a)(1)-(6). 

Liability coverage must also account for non-sudden accidental occurrences, as well, in the 

amount of at least $3 million per occurrence with an annual aggregate of at least $6 million, 

exclusive of legal defense costs. § 264.147 (b). Coverage for sudden and non-sudden accidents 

can be combined into a single coverage, which must be at least $4 million per occurrence and $8 

million annual aggregate. Id. Coverage, as above, may be achieved by acquiring a liability 

insurance policy, through a financial test or corporate guarantee, a letter of credit, a surety bond, 
46

by obtaining a trust fund, or a combination of such mechanisms. § 264.147 (b)(1)-(6). 

According to RCRA, evidence that the “past or present” handling, storage, treatment, 

transportation or disposal of any solid waste or hazardous waste “may present an imminent and 

substantial endangerment to human health or the environment” is basis for suit by the EPA 

administrator. 42 U.S.C. § 6973 (a). 

In applying RCRA liability standards, established in 42 U.S.C. § 6973 (a), supra, federal courts 

have held that “from the legislative history ... it is clear that Congress intended RCRA ... to 

impose liability without fault or negligence and to apply to the present conditions resulting from 

past activities.” United States v. Northeastern Pharmaceutical & Chemical Co., Inc., 810 F.2d 

726, 741 (8th Cir. 1987). The Eighth Circuit held that RCRA “imposes strict liability upon any 

person who is contributing or who has contributed to the disposal of hazardous substances that 

may present an imminent and substantial endangerment to human health or the environment.” 

Northeastern Pharmaceutical & Chemical Co., Inc., 810 F.2d at 745. According to American 

Jurisprudence Proof of Facts 3d, RCRA is a public welfare statute, “designed to protect the 

public and the environment from the dangers posed by improper handling of wastes,” so 

“compliance with the statute is a matter of strict liability, and a defendant’s lack of negligence, 

intention to comply, or good-faith attempt to do so, are irrelevant to the question of a defendant’s 

civil liability for violating a RCRA permit provision, standard, regulation, condition, 

requirement, prohibition, or order, and to civil liability for the defendant’s past or present 

contribution to the creation of an imminent and substantial endangerment.” 40 Am. Jur. Proof of 

Facts 3d 457 § 46. 

Comprehensive Environmental Response, Compensation and Liability Act, CERCLA (Superfund) 

42 U.S.C. §§ 9601-9675. 

Passed by Congress in 1980, CERCLA was designed to address abandoned hazardous waste 

sites, as opposed to active sites managed under RCRA, supra. The CERCLA Superfund, or the 

Hazardous Substances Response Trust, is maintained by assessing a tax on petroleum and 

chemical industries and also by general fund appropriations for the cleanup and management of 

sites for which no responsible party can be identified or held accountable, most commonly 

because of dissolution or bankruptcy. Under CERCLA, four classes of parties, known as 

“potential responsible parties,” may be liable for contamination at a Superfund site: the current 

owner or operator of the site; the owner or operator of a site at the time that disposal of a 

hazardous substance, pollutant or contaminant occurred; a person who arranged for the disposal 

of a hazardous substance, pollutant or contaminant at a site; or a person who selected a site for 

disposal and transported a hazardous substance, pollutant or contaminant to that site. Liability is 

also limited by recognizing in the statute certain defenses and by limiting the financial 

responsibility. Generally, courts have imposed strict and joint and several liability under 

CERCLA. Northeastern Pharmaceutical & Chemical Co., Inc., 810 F.2d at 732, n. 3. See 

(http://www.epa.gov/Compliance/cleanup/superfund/liability.html, Last updated on Thursday, 
47

March 23rd, 2006). 

According to CERCLA, “the owner and operator,” “any person who at the time of disposal 

owned or operated any facility at which such hazardous wastes were disposed of,” “any person 

who by contract, agreement, or otherwise arranged for disposal of hazardous substances,” and 

“any person who accepts or accepted any hazardous substances for transport to disposal or 

treatment facilities ... or sites selected by such person, from which there is a release, or a 

threatened release which causes the incurrence of a response costs, of a hazardous substance” 

shall be liable. 42 U.S.C.A. § 9607 (a)(1)-(4). Liability includes “all costs of removal or remedial 

action incurred by the United States Government, or a State or an Indian tribe,” “any other 

necessary costs of response incurred by any other person consistent with the national 

contingency plan,” “damages for injury to, destruction of, or loss of natural resources, including 

the reasonable costs of assessing such injury, destruction, or loss,” and “the costs of any health 

assessment or health effects study carried out” pursuant to CERCLA. 42 U.S.C.A. § 9607 (a)(A)-

(D). 

The liability imposed by CERCLA is joint and several, strict and retroactive. 80 Am. Jur. Proof 

of Facts 3d 281 § 4; see Violet v. Picillo, 648 F.Supp. 1283, 1290 (D.R.I. 1986) (“Courts have 

universally acknowledged that in enacting section 107 Congress created a strict liability 

scheme”). The joint and several liability imposed by CERCLA “means that any single defendant 

can be held responsible for the entire cost of a cleanup or other response costs.” 80 Am. Jur. 

Proof of Facts 3d 281 § 4. Strict liability means that a complainant need not establish negligence 

or breach of duty. Violet, 648 F.Supp at 1292 (“CERCLA section 107 requires only a minimal 

causal nexus between the defendant's hazardous waste and the harm caused by the release at a 

particular disposal site. CERCLA only requires that the plaintiff prove by a preponderance of the 

evidence that the defendant deposited his hazardous waste at the site and that the hazardous 

substances contained in the defendant's waste are also found at the site”). To establish a prima 

facie case of liability under CERCLA, the claimant must demonstrate that the contaminated site 

in question is a facility as defined in § 101(9) of CERCLA; that the defendant is among one of 

the four categories of potentially responsible parties listed in § 107 (a); a release or threat of 

release of a hazardous substance has occurred at the facility; and the release or threatened release 

has caused the government or private party to incur “necessary” response costs consistent with 

the National Contingency Plan. Violet, 648 F.Supp. at 1289. (“Courts have generally held that 

liability under section 107(a)(3) requires proof of four basic elements: 1) that the generator 

disposed of hazardous substances; 2) at a facility which contains at the time of discovery 

hazardous substances of the kind the generator disposed; 3) there is a release or a threatened 

release of that or any hazardous substance; 4) which triggers the incurrence of response costs”); 

see also 80 Am. Jur. Proof of Facts 3d 281 § 2. 

Liability, however, is expressly limited by statutorily defined defenses, including “(1) an act of 

God; (2) an act of war; (3) an act or omission of a third party other than an employee or agent of 

the defendant, or than one whose act or omission occurs in connection with a contractual 

relationship ... with the defendant ... if the defendant establishes by a preponderance of the 

evidence that (a) he exercised due care ... and (b) he took precautions against foreseeable acts or 
48

omissions of any such third party and the consequences that could foreseeably result from such 

acts or omissions; or (4) any combination of the foregoing paragraphs [(1) through (3)].” 42 

U.S.C.A. § 9607 (b)(1)-(4). 

CERCLA holds that “the liability of an owner or operator or other responsible person ... shall be 

the full and total costs of response and damages, if (A)(i) the release or threat of release of a 

hazardous substance was the result of willful misconduct or willful negligence within the privity 

or knowledge of such person, or (ii) the primary cause of the release was a violation ... of 

applicable safety, construction, or operating standards or regulations; or (B) such person fails or 

refuses to provide all reasonable cooperation and assistance requested by a responsible public 

official” in connection with cleanup response activities. 42 U.S.C.A. § 9607 (c)(2). Liability 

shall not exceed $300 per gross ton or $5 million, whichever is greater, for vessels carrying 

hazardous substances, or $50 million or a lesser amount as may be established by the President 

in regulation, but not less than $5 million, for motor vehicles, aircraft, hazardous liquid pipeline 

facilities or rolling stock. 42 U.S.C.A. § 9607 (c)(1)(A)-(C). For other facilities or vessels not 

covered in the subsequent sections, liability is limited to “the total of all costs of response plus 

$50,000,000 for any damages ...” 42 U.S.C.A. § 9607 (c)(1)(D). 

Despite limiting liability for non-willful releases and those abiding by applicable operating 

standards and regulations, CERCLA does provide for punitive damages “in an amount at least 

equal to, and not more than three times, the amount of any costs incurred by the Fund as a result 

of such failure to take proper action.” 42 U.S.C.A. § 9607 (c)(3). This subparagraph authorizes 

civil action against any such person to recover the punitive damages, which will be in addition to 

any costs recovered from such person...” Id. 

The original version of CERCLA included a provision establishing a “Post-Closure Liability 

Fund”, 42 U.S.C.A. § 9607, designed to accept the transfer of liability for the costs of 

monitoring, care and maintenance of a hazardous waste disposal facility incurred by other parties 

after the period of monitoring required by the Solid Waste Disposal Act (42 U.S.C. § 6921), but 

this section was repealed by Pub. L. 99-499, Title V, § 514(b), Oct. 17, 1986, 100 Stat. 1767. 

In addition to the Post-Closure Fund, which applied to hazardous waste disposal sites, CERCLA 

directed the comptroller general to conduct a study of options for post-closure management of 

the liabilities associated with hazardous waste treatment, storage and disposal sites that assures 

the protection of human health and the environment. 42 U.S.C.A. § 9607 (k)(6)(A). The study 

was to look at options for developing a post-closure program that (1) assured incentives for the 

safe management and disposal of hazardous wastes for the protection of human health and the 

environment; (2) so that members of the public will have reasonable confidence that hazardous 

wastes will be disposed of safely and that resources will be available to address any problems 

that may arise, and to cover costs of long-term monitoring, care and maintenance of such sites; 

and (3) so that people who seek to become owners and operators of hazardous waste disposal 

facilities will be able to manage their potential future liabilities and attract the investment capital 

necessary to build, operate, and close such facilities in a manner which assures protection of 

human health and the environment. § 9607 (k)(6)(B). 
49

The study was to focus on ways to ensure hazardous waste facilities will be adequately financed 

and that the costs “to the greatest extent possible” are borne by the owners and operators. § 9607 

(k)(6)(E). Among the options the comptroller general was explicitly directed to consider were (1) 

voluntary risk pooling by owners and operators; (2) legislation to require risk pooling by owners 

and operators; (3) limiting the transfer of liability to the Post-Closure Trust Fund only in cases of 

insolvency of owners and operators; (4) private insurance; (5) insurance provided by the federal 

government; (6) co-insurance, re-insurance, or pooled-risk insurance, whether provided by the 

private sector or provided by or partially subsidized by the federal government; and (7) the 

creation of a new program to be administered by a new or existing federal agency or by a 

federally chartered corporation. Id. 

To protect against the possibility of un-reimbursed expenses related to the management, care or 

cleanup of sites being borne by the government, CERCLA provided for liens against all real 

property and rights to such property belonging to parties subject to CERCLA authority. § 9607 

(l). 

CERCLA provides that financial responsibility, as established and determined by § 9607, 

discussed above, “may be established by any one, or any combination, of the following: 

insurance, guarantee, surety bond, or qualification as a self-insurer.” § 9608 (a)(1). Lacking 

certification of such financial responsibility, CERCLA provides for various penalties, such as 

withholding or revoking clearances for vessels and blocking entry into ports, for example. § 9608 

(a)(2), (3). 

CERCLA provides in § 9611 for the expenditure of the Superfund for payment of governmental 

response costs, compensable claims that have not been satisfied, and claims from a release or 

threat of release of a hazardous substance for injury to or destruction or loss of natural resources, 

including costs for damage assessment. § 9611 (b)(1). The Act provides that natural resources 

claims can only be paid from the Superfund if the President determines the claimant has 

exhausted all administrative and judicial remedies to recover the sum from liable parties. § 9611 

(b)(2)(A). 

Safe Drinking Water Act, Underground Injection Control Program (SDWA UIC): 42 U.S.C. § 

300f et seq. 

The Safe Drinking Water Act’s (SDWA) Underground Injection Control (UIC) program 

regulates the underground injection of wastes to prevent the contamination of current and 

potential future drinking water sources. Enacted in 1974, the SDWA directed the EPA to set and 

maintain health-based standards for contaminants in drinking water. In the early 1980s the Act 

was amended to include the UIC program, which consists of regulations promulgated under Part 

C of the SDWA, for which primacy has been delegated to 34 states, including New Mexico, 
50

operating under the authority of EPA to enforce the program. 

(http://www.epa.gov/safewater/uic/primacy.html Last updated on Tuesday, February 28th, 

2006). 

The UIC lumps the injection of wastes into five classes, each class includes wells with similar 

functions, construction and operating features so that technical requirements can be applied 

consistently. Class I wells include the emplacement of hazardous and non-hazardous fluids 

(industrial and municipal wastes) into isolated formations beneath the lowermost underground 

source of drinking water (USDW). Id. Because they may inject hazardous wastes, Class I wells 

are the most strictly regulated and are further regulated under RCRA. Id. Operators of Class I 

wells “must demonstrate that their hazardous injectate will not migrate from the injection zone 

for as long as it remains hazardous. Stephanie M. Haggerty, Legal Requirements for Widespread 

Implementation of CO2 Sequestration in Depleted Oil Reservoirs, 21 Pace Envtl. L. Rev. 197, 

206 (2003) (citations omitted). Class I well operators must continuously monitor the injection 

well, the fluid within the well, and any possible migration out of the target injection zone. Id

(citations omitted). 

Class II wells include those that inject brines and other fluids associated with oil and gas 

production, including injections for enhanced oil recovery, such as carbon dioxide. Id (citations 

omitted). Operators of Class II wells in New Mexico must also ensure the injectate does not 

migrate beyond the target injection zone, and must identify other wells in the vicinity that could 

serve as pathways for migration. Id. at 206-207 (citations omitted). Class III wells cover the 

injection of fluids associated with solution mining of minerals. Class IV wells cover the injection 

of hazardous or radioactive wastes into or above a USDW and are banned unless authorized 

under other statutes for groundwater remediation. Class V wells cover all underground injection 

not included in Classes I-IV and cover the injection of non-hazardous fluids into or above a 

USDW. Class V wells are typically shallow, on-site disposal systems, such as floor and sink 

drains which discharge directly or indirectly into groundwater, dry wells, leach fields, and 

similar types of drainage wells, but also include experimental wells, such as those used to 

conduct carbon dioxide sequestration. Groundwater recharge wells, for aquifer storage or 

prevention of saltwater intrusion, are included within the Class V designation, as well. 

 

According to the statutory authority granted by the SDWA, 42 U.S.C. § 300f et seq., regulations 

for state underground injection programs promulgated under the SDWA “shall contain minimum 

requirements for effective programs to prevent underground injection which endangers drinking 

water sources,” § 300h (b)(1), and that those regulations “may not prescribe requirements which 

interfere with or impede (A) the underground injection of brine or other fluids which are brought 

to the surface in connection with oil or natural gas production or natural gas storage operations, 

or (B) any underground injection for the secondary or tertiary recovery of oil or natural gas, 

unless such requirements are essential to assure that underground sources of drinking water will 

not be endangered by such injection.” § 300h (b)(2) (emphasis added). 

Underground injection of carbon dioxide for purposes of climate mitigation would be/is 

regulated under the SWDA UIC program. (See 
51

http://www.epa.gov/safewater/uic/wells_sequestration.html). Currently, the U.S. EPA is urging 

state directors and regional administrators to consider permitting proposed carbon dioxide 

sequestration projects, as distinct from enhanced oil recovery (EOR) projects, under UIC’s Class 

V category as an experimental technology. (Using the Class V Experimental Technology Well 

Classification for Pilot Geologic Sequestration Projects – UIC Program Guidance (UICPG #83), 

March 1, 2007). In its guidance document, EPA recognizes that carbon dioxide sequestration 

could fit within the classification of Class I wells, as well. Id. at 5. EPA is clear in its guidance 

document, however, that no carbon dioxide sequestration project should be permitted as a Class 

II well, but that in the case where an EOR project using CO2 injection intends to transition to a 

sequestration project, that project should seek re-permitting as a Class V well before 

transitioning. Id. at 6. No specific liability and financial assurance requirements exist for Class V 

wells beyond that which is standard for UIC injections wells. 40 C.F.R. §§ 144.51 and 144.52 

(a)(7)(i) (“The permittee, including the transferor of a permit, is required to demonstrate and 

maintain financial responsibility and resources to close, plug, and abandon the underground 

injection operation in a manner prescribed by the Director”). However, Class I wells, because 

they may be permitted to inject hazardous wastes, do have separate financial assurance 

requirements, discussed below. 

The current federal UIC program provides minimum rules for siting, testing, installing, 

operating, monitoring, reporting, and abandonment of underground injection wells, but 

“provisions that would provide for widespread application of carbon sequestration are absent 

from the current statutes.” 21 Pace Envtl. L. Rev. at 208 (citations omitted). This is because the 

UIC program “was not developed with carbon dioxide storage in mind and the regulatory 

framework that governs carbon dioxide storage will probably deviate from the current system.” 

Mark de Figueriedo, David Reiner, Howard Herzog, Kenneth Oye, The Liability of Carbon 

Dioxide Storage, (unpublished). That said, it is anticipated “EPA’s regulatory framework for 

underground injection will shape the regulatory environment for geologic carbon storage and 

may inform assessments of the risks.” M.A. De Figueiredo, D.M. Reiner, H.J. Herzog, Framing 

the Long-Term In-Situ Liability Issue for Geologic Carbon Storage in the United States, 

Mitigation and Adaptation Strategies for Global Change, (2005) 10:647-657, 653 (citations 

omitted) (henceforth Framing the Liability Issue). This is especially likely given the final 

guidance released by EPA in March 2007. 

Like RCRA and CERCLA, liability created under the UIC is borne by the owner/operator of the 

facility or process who must provide financial assurance and demonstrate financial responsibility 

in case of accidents. Unlike either RCRA or CERCLA, however, the SDWA includes no 

statutory provisions for financial assurance, which are instead found wholly within federal 

regulations promulgated pursuant to Part C of the SDWA. The general permit conditions 

themselves require financial responsibility for the adequate plugging and abandonment of all 

injection wells. 40 C.F.R. §§ 144.51 and 144.52 (a)(7)(i) (“The permittee, including the 

transferor of a permit, is required to demonstrate and maintain financial responsibility and 

resources to close, plug, and abandon the underground injection operation in a manner prescribed 

by the Director”). The UIC regulations do, however, have specific liability and financial 

assurance requirements that apply only to Class I wells. § 144.60 (stating that §§ 144.61 through 

144.70 apply only to Class I wells). These financial assurance requirements are modeled on those 
52

established by RCRA. Framing the Liability Issue at 654. As such, the wording is nearly 

identical to the financial assurance requirements in the RCRA regulations. 

Before selecting a method of financial assurance, Class I well operators/owners must first 

establish a cost estimate for plugging and abandonment. § 144.62. The written cost estimate must 

be in accordance with the plugging and abandonment plan, as specified in §§ 144.28 and 144.51, 

and “must equal the cost of plugging and abandonment at the point in the facility’s operating life 

when the extent and manner of its operation would make plugging and abandonment the most 

expensive, as indicated by its plugging and abandonment plan.” § 144.62 (a). This cost estimate 

must be adjusted annually for inflation, according to § 144.62 (b), and whenever a change 

increases the estimated cost. § 144.62 (c). 

As is the case for RCRA, owners/operators of Class I wells can meet the financial assurance 

requirements by selecting one of several mechanisms: a plugging and abandonment trust fund, a 

surety bond guaranteeing payment into a plugging and abandonment trust fund, a surety bond 

guaranteeing performance of plugging and abandonment, an irrevocable letter of credit, private 

plugging and abandonment insurance, financial test and corporate guarantee, or a combination of 

these financial mechanisms. § 144.63 (g). And, as in the case for RCRA and CERCLA, any of 

the above financial assurance mechanisms can be used to cover multiple injection wells. § 

144.63 (h). 

In addition to plugging and abandonment requirements, the UIC regulations also require the 

owner/operator of Class I wells to “prepare, maintain, and comply with” a closure plan, which 

“survives the termination of a permit or the cessation of injection activities.” § 146.71 (a). The 

closure plan must be submitted as part of the permit application and, with approval, becomes a 

condition of the permit issued. § 146.71 (a)(1) (§§ 146.61 through 146.73 are the criteria and 

standards applicable to Class I wells). As discussed above, the permit conditions themselves 

require financial responsibility for the adequate plugging and abandonment of all injection wells, 

not just Class I wells. § 144.52 (a)(7). According to the criteria and standards for Class I wells, 

the closure plan must include assurance for financial responsibility to “close, plug and abandon 

the underground injection in a manner prescribed by the Director,” as required in § 144.52(a)(7). 

§ 146.71. 

Beyond the requirement for maintaining a closure plan and financial assurance for proper 

plugging and abandonment, owners/operators of Class I wells must also prepare and maintain a 

post-closure plan, which survives the termination of a permit or the cessation of injection. § 

146.72. Among the plan’s mandated elements is an estimate for the cost of post-closure care. § 

146.72 (a)(4)(vi). Section 146.73 requires that an owner/operator “shall demonstrate and 

maintain financial responsibility for post-closure care by creating a trust fund, surety bond, letter 

of credit, financial test, insurance, or corporate guarantee that meets the specifications for the 

mechanisms and instruments revised as appropriate to cover closure and post-closure care in 40 

CFR Part 144, Subpart F” and “shall be no less” than the amount identified in by the estimate in 

§ 146.72 (a)(4)(vi). The obligation to maintain financial responsibility for post-closure care 

survives the termination of a permit or the cessation of injection and is enforceable regardless of 
53

whether the requirement is a condition of the permit. § 146.73. 

Unlike RCRA, UIC does not extend its regulatory language to include coverage responsibility 

for accidents, nor does it provide coverage for damage to personal property. 67 Am. Jur. Proof of 

Facts 3d 95 § 33. And unlike CERCLA, which has a focus on the protection of human health 

and environment, the UIC regulatory language is somewhat more narrowly confined to the 

protection of USDW against contamination which may result in a drinking water system not 

complying with any national primary drinking water regulations or may otherwise adversely 

affect the health of people. 42 U.S.C. § 300h (d)(2). 

New Mexico has been delegated primacy for the oversight and enforcement of its underground 

injection program (except for Indian lands) pursuant to 40 C.F.R. § 147.1600, Part 147, Subpart 

GG of the federal regulations. According to the delegation the Oil Conservation Division 

administers the UIC program for Class II wells, except for those on Indian Lands, which are 

administered by EPA. This authority incorporates by reference the New Mexico Oil and Gas Act 

(§§ 70-2-1 through -36), the Oil Conservation Division Rules and Regulations rules 701 through 

708, the New Mexico Water Quality Control Commission Regulations (rules 5000 through 

5299), as well as the New Mexico Water Quality Act, the Geothermal Resources Conservation 

Act, the Surface Mining Act, the Memorandum of Agreement between the EPA Region VI and 

the New Mexico Water Quality Control Commission, the Environmental Improvement Division, 

and the Oil Conservation Division (1983), and other documents listed in § 147.1601. None of 

these regulations impose additional liability or financial assurance requirements beyond what is 

required by the federal regulations. 

The liability standard applied to the UIC program and the Safe Drinking Water Act in general, 

appears to be one of strict liability, 42 U.S.C. § 300h-2, but no case law nor secondary sources 

have been found to offer any guidance on that point. 

Low-Level Radioactive Waste Policy Act (LLWPA): 42 U.S.C. § 2021b et seq. 

Unlike any of the liability models discussed, the Low-Level Radioactive Waste Policy Act 

(LLRWPA) provides that each state may be responsible for handling the disposal of low-level 

radioactive waste generated within the state, except essentially that which was created by the 

federal government. 42 U.S.C. § 2021b et seq. The Act also encourages states to work 

cooperatively to form compact regions as a means to handle commercially produced low-level 

waste. 

According to the Act, each state or compact region in which low-level radioactive waste is 

generated “upon the request of the generator or owner of the waste, shall take title to the waste, 

shall be obligated to take possession of the waste, and shall be liable for all damages directly or 

indirectly incurred by such generator or owner as a consequence of the failure of the State to take 
54

possession of the waste as soon after January 1, 1993, as the generator or owner notifies the State 

that the waste is available for shipment.” § 2021e (d)(2)(C). If the state or compact region “elects 

not to take title to, take possession of, and assume liability for such waste,” it must repay with 

interest any amount collected as a surcharge” over a certain period. Id. However, this provision 

of the Act, which was intended to provide states with an incentive to manage its low-level waste, 

was deemed by the Supreme Court to be unconstitutional and violative of the 10th Amendment. 

New York v. United States, 505 U.S. 144, 175, 112 S.Ct. 2408, 2428, 120 L.Ed.2d 120 (1992) 

(“Because an instruction to state governments to take title to waste, standing alone, would be 

beyond the authority of Congress, and because a direct order to regulate, standing alone, would 

also be beyond the authority of Congress, it follows that Congress lacks the power to offer the 

States a choice between the two”). 

Written according to the proposals of the National Governor’s Association with the purpose of 

giving states more control over the siting of low-level waste dumps, the Act has been widely 

perceived as less than successful, for despite the formation of several compact regions no new 

low-level radioactive waste dumps have been established “largely because no state regulatory 

agency will approve a disposal facility within its borders.” Framing the Liability, supra, at 653. 

In effect, the incentives built into the Act are generally perceived to be too weak to prompt siting 

of new dump sites by host states which generally do not want dump sites located in their state. 

Deborah M. Mosteghel, The Low-Level Radioactive Waste Policy Amendments Act: An 

Overview, 43 DePaul L. Rev. 379 (Winter 1994). According to at least one interpretation, “[t]he 

example of low-level radioactive waste shows that liability regimes may discourage storage,” 

and “also raises questions of the efficacy of turning over liability to the states.” Framing the 

Liability, supra, at 653. 

Liability Analysis 

Literature evaluating the impediments to and feasibility of large-scale, commercial carbon 

dioxide sequestration has explored possible mechanisms to address the liability and financial 

assurance levels that might be required. This aspect of the regulatory framework can have a 

significant impact on the success and viability of any carbon sequestration program, as noted in 

the comments received from environmental groups and industry representatives on the draft 

interim report. Sufficient financial assurances and an appropriate and reasonable liability 

standard together with thorough, clear and reasonable regulations can create the required degree 

of certainty and predictability necessary for insurers to offer adequate coverage in this new and 

unexplored field and for operators to develop realistic business models. Similarly, sufficient 

financial assurance and a properly scaled liability standard, combined with protective 

regulations, can also instill confidence in the public that the state can manage and control this 

largely untested field while providing adequate protections and ensuring a mechanism for 

compensation and environmental mitigation should accidents occur. Further, as the literature 

discussed below explores, developing the right level of legal liability can create in insurers an 

additional layer of regulatory oversight beyond what the state itself could otherwise provide. All 

of this must be accomplished without placing an undue financial burden on the industry, or 
55

otherwise stifling development of carbon dioxide sequestration projects, which are viewed as an 

important component of the state’s climate change mitigation strategy. 

According to the literature reviewed to date, liability and financial assurance can be 

accommodated on essentially four levels: (1) the federal government; (2) state government; (3) 

industry; or (4) the individual corporation or owner/operator. Framing the Liability, supra, at 

653. Some combination of these will likely need to be employed to achieve the best balance of 

liabilities and to ensure adequate incentive exists to undertake sequestration projects, but 

selecting the right combination or balance will require careful consideration of the various 

interests and inherent risks. 

Drawing on current oil and gas practices, the short-term liabilities inherent in any drilling or 

injection project – whether environmental or economic – can likely be best addressed through the 

contractual arrangements between generator and injector and the private market, as they are now. 

This may not be true, however, for the largest sequestration projects. Likewise, liabilities 

following the injection and closure phases of projects present a unique problem given the 

anticipated scale, both in terms of time (hundreds to thousands of years) and space, required for 

successful CO2 sequestration and accurate CO2 inventories. Liabilities facing this new field 

include potential trespass actions involving both surface and subsurface interests (e.g. hard-rock 

minerals, hydrocarbon minerals, and pore space), and harm to human health, private property, 

and/or to the environment due to sudden events or as a result of a leakage over longer time 

scales. Literature and studies to date on the topic suggest that wells and boreholes will present 

the most common risk of leakage to the surface and other non-target formations, but unknown or 

unanticipated sources of leakage or other unanticipated problems may represent the greatest risks 

in terms of actual costs and liability.10

Because of the breadth and depth of the unknowns over the requisite time scales involved in 

successful sequestration, transfer of liability to the public sector has been conceived of as one 

way to encourage the development of sequestration projects by limiting potential liabilities that 

must be born by the individual injector or the industry. But this liability model also raises many 

issues, such as how to limit the burden on the public and how to fund continued, long-term 

monitoring and verification efforts, as well as any potential long-term environmental mitigation 

or property compensation that may be required. 

Alternatively, drawing from current environmental regulatory frameworks, the long-term 

liability could be maintained by the injectors themselves and managed according to the models 

established by one of several pre-existing environmental regulations, discussed above. An 

example of some combination of these models is presented below: 

A liability scheme may: 

• Impose strict liability for extraordinary occurrences, e.g. for contamination of protected 

groundwater sources, or for catastrophic releases (above a certain volume) of CO2 to the 

atmosphere or to non-storage formations. 

 

10 David Borins, personal communication. 
56

• Impose a negligence standard for all other events and occurrences 

• Impose strict liability for total response costs if willful misconduct or willful negligence 

is proven, or if the event was due to a violation of some applicable standard or regulation 

or if the operator failed to provide reasonable assistance with response operations 

• Create an industry-funded pool with deferred premiums for accident coverage and 

environmental mitigation costs that exceed an individual’s insurance liability 

• Require demonstration of financial assurance for insurance and industry-funded deferred 

premiums 

• Create a closure and post-closure trust fund (measuring, monitoring, mitigation and 

accidents (property and human health)), paid on a per-volume-injected basis 

• Declare in the permit who the primary responsible parties will be who will bear the 

liability 

• Limit defenses, as in CERCLA, to: 1) act of God; 2) act of war; and 3) an act or omission 

on the part of a third party or agent if the Defendant exercised due care to address 

precautions against potential consequences of third party acts or omissions that could 

have been reasonably foreseen to result 

• Require financial assurance for plugging and abandonment of individual wells, as well as 

the injection project as a whole, based on an approved cost estimate (updated and 

maintained annually by the injector) 

• Require submission of a closure plan and post-closure plan for review and approval by 

the Division 

Transfer of Liability to Public Sector 

Transfer of liability to the public sector is not without precedent, as a similar scheme was 

contemplated and employed briefly by CERCLA, which had in its original form created a “PostClosure Liability Fund,” 42 U.S.C. § 9607, that was designed to accept the transfer of liability 

for the costs of monitoring, care and maintenance of a hazardous waste disposal facility incurred 

by other parties after a period of required monitoring by the owner/operator (a maximum fiveyear period before eligibility for transfer with a $200 million fund cap). The fund was obligated 

to pay all costs arising out of liability imposed by CERCLA with respect to a hazardous waste 

disposal facility after its closure, provided that the facility received a permit under Subtitle C of 

the Solid Waste Disposal Act, and complied with other regulatory requirements designed to 

protect against future releases of hazardous substances. Superfund Amendments and 

Reauthorization Act of 1986: Hearing on S. 2892 Before the S. Comm. On Finance, 98th Cong. 

64 (Sept. 19, 1984) (statement of Mikel M. Rollyson, acting tax legislative counsel, Dept. of the 

Treasury). Thus, if these prerequisites were satisfied, future liabilities arising from the operation 

of the facility were shifted from the responsible parties to the Federal Government. Id. Because 

payment of the tax shifted liability for post-closure damages to the Federal Government, the tax 

payments could be equated with premium payments for post-closure Government liability 

insurance paid by such owners and operators. Id. Conversely, in the absence of such insurance, 
57

owners and operators of disposal facilities would be liable for post-closure claims in perpetuity. 

Id. 

 

Solid waste operators sought to retain the Post-Closure Liability Fund and the policy of shifting 

liability to the federal government. Reauthorization of and Possible Amendments to the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hearing on 

H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 

98th Cong. 62 (May 15, 1984) (statement of Richard L. Hanneman, Dir. of Gov. Affairs, Nat. 

Solid Wastes Mgmt. Assoc.). According to testimony from the National Solid Waste 

Management Association, the Post-Closure Liability Fund was a prepaid, pooled-risk fund 

generated by payments from operators during the active life of a facility. Id. Those sites that 

operated with a Solid Waste Disposal Act permit, remained trouble free, and did not pose a threat 

to public health qualified for the fund, but the operator of the site remained responsible for 

monitoring and maintenance for 30 years after closure of the facility. Id. Arguments in favor of 

eliminating the fund included the concern that with limited liability, operators had no incentive 

to design facilities to last any longer than their liability endured. Id. The Association, however, 

argued that the performance of facilities would not be affected, as performance criteria were 

dictated by regulations guiding the issuance of operating permits, and that without such a fund, 

the public and government were gambling that the CERCLA Superfund or the responsible 

parties would still be around to pay for future cleanups, mitigation and compensation. Id. The 

Association argued that the fund “internalized” into the cost of disposal the cost of long-term 

protection and monitoring, so that generators of waste pay that cost upfront, thereby avoiding 

public subsidy of disposal. Id at 67. As a compromise to those voicing concerns over the fund, 

the Association indicated its willingness to extend the waiting period for the transfer of liability 

and to increase or eliminate altogether the $200 million cap on the fund, which was seen by some 

to be inadequate. Id. 

At the time of these debates, the Hazardous Waste Council argued against the retention of the 

Post-Closure Liability Fund because “[t]he more rapid the transfer of liability to a federallybacked fund, the less incentive there is to pursue permanent and protective methods of 

management.” Id. at 129 (statement of Richard C. Fortuna, Exec. Dir., Hazardous Waste 

Treatment Council). Further, “[t]his attractive liability transfer also exacerbates the cost 

differential between treatment and disposal by allowing the long-term cost of facility liability, 

monitoring and maintenance to be assumed by the Federal government, rather than having these 

post-closure expenses internalized in the price of individual and land disposal transactions.” 

Before the Subcommittee on Commerce, Transportation and Tourism, H. Comm. on Energy and 

Commerce, 98th Cong. 197-198 (Feb. 28, 1984) (statement of Dr. Nelson Mossholder, Technical 

Dir., Stablex Corp., on behalf of the Hazardous Waste Treatment Council) 

 

Criticism came from environmental groups, as well, which saw the Post-Closure Liability Fund 

as creating “an incentive to do the most modest, minimal cleanup, adopt the most minimal 

approach, that would get you by that first 5 years and not assume responsibility for the 

subsequent acceptability of the disposal practice.” Reauthorization of and Possible Amendments 

to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980: 

Hearing on H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works 

and Trans., 98th Cong. 474 (June 13, 1984) (statement of Kenneth Kamlet, Dir. Pollution and 
58

Toxic Substances Div. Nat. Wildlife Fed.). According to the National Wildlife Federation’s 

testimony, the fund “put() the incentive in the wrong place, in short, and we think that the 

environment and the public would be better protected without it, putting the liability on the 

shoulders of those that pursue these alternatives rather than on the shoulders of a less 

accountable trust fund of this sort.” Id. 

Another factor to be considered in the creation of such a post-closure fund is the level of funding 

that should be required. The CERCLA fund was criticized as being arbitrarily set at $200 

million, when the actual costs of any future mitigation that might be necessary were completely 

unknown and perhaps totally unpredictable. A similar difficulty will be faced when trying to 

determine the appropriate level of funding for a carbon dioxide sequestration post-closure fund, 

as no true precedent exists with which to determine adequate and reasonable funding levels for 

the areal extent and duration contemplated for sequestration projects. 

 

The OCD makes no recommendation regarding management of post-closure liability for 

sequestration projects. Numerous policy issues and concerns must be addressed that could weigh 

heavily on any nascent sequestration industry and could have far-reaching consequences for the 

state’s populace. Instead, an outline of issues is presented below for the contemplation of policy 

makers with the intention to pursue more in depth research following initial policy guidance. 

The concept of a post-closure liability fund presents features that make it both attractive and 

problematic. Such a fund could establish a long-term money source for environmental mitigation 

and personal property and injury compensation far into the future that could potentially outlive 

the viability of any injector/operator or its insurance plan. Difficulties inherent in establishing 

such a fund include the challenge of determining proper payment levels and the concern that 

injectors/operators will engineer their operations to a minimum level necessary only to achieve 

transfer to the public sector, rather than to that which is most protective. Funding levels can be 

fluid and adapted on an interim basis as more data and experience accrues, but the risk remains 

that any funding level will be considered arbitrary to some extent; if it is set too high, the funding 

requirements will pose a disincentive to the industry; if it is too low, the fund won’t be adequate 

to achieve the necessary protection and public confidence. Coupled with adequate and 

reasonable regulatory standards and oversight, concerns about minimally engineered systems can 

be addressed, but given the range of unknowns in this new field, these may never be fully 

eliminated. 

Ultimately, a liability system similar to that established by the Price-Anderson Act might offer 

the greatest level of assurance and flexibility through, essentially, a triple layer of accountability. 

Initial liability could be addressed through a private insurance requirement, then for claims and 

mitigation that exceed an individual operator’s insurance capacity, liability would be covered 

through an industry-funded deferred compensation program. For events that exceed the capacity 

of both, the state could step in to offer compensation and mitigation, either directly or through a 

re-insurance program of part or all of the industry’s liability. This would have the benefit of 

creating an immediately available funding pool for liability claims through the insurance 

program, while extending liability to the entire industry for larger claims. 
59

The primary drawback to such a system is the concept of indemnity, for which the PriceAnderson Act has received significant criticism. In a new field, such as carbon sequestration, the 

idea of indemnifying operators against liability for the most catastrophic events could be 

politically unpalatable and a non-starter. However, unlike the nuclear power industry, carbon 

dioxide sequestration likely poses a far-reduced threat compared to nuclear energy production 

and likely won’t be considered an abnormally dangerous activity, similar to natural gas 

transportation and storage. For this reason, indemnifying the sequestration industry against 

catastrophic events should be considered less of a risk and less of an industry give away than it is 

perceived for the nuclear power industry. 

Tagging the industry with a double layer of liability – private insurance and an industry-wide 

fund, in addition to well-bonding and project bonding requirements – could add up to a financial 

burden that is too unwieldy to spur industry development. Price-Anderson’s approach to this 

problem, allowing the industry fund to be a deferred payment (until an event appears likely to 

exceed the insurance capacity), could be adapted to lessen the immediate and overall financial 

impact on any one operator and the industry as a whole. In addition, the deferred payment could 

be limited to a set amount/fraction of a larger total, as it is in the Price-Anderson scheme, for 

which each operator/injector would be liable in a given year or per occurrence. 

 

The benefit of this approach is that owners/operators remain directly accountable through private 

insurance up to, perhaps, a maximum bearable level, before the burden shifts first to the industry 

itself, then to the public sector. To keep premiums to a minimum, operators would be encouraged 

to maintain demonstrably safe operations and the insurance industry, to limit their exposure, 

would serve as an added layer of oversight, in addition to the state’s regulatory and statutory 

framework. 

Transfer of liability and ownership of the injected gas to the public sector may pose too great a 

financial burden, especially for a state with a populace of limited means and other significant 

resource-demanding needs (e.g. education, health care). However, philosophically, everyone – 

not just industry – is responsible in part for climate change and should bear some burden for its 

mitigation. Transferring liability for sequestration projects accords with this philosophy. 

An alternative to an outright transfer of liability to the public sector could be a program where 

the state acts as a re-insurer. More research needs to be done to determine how such a system 

might work. 

Strict, Joint and Several Liability, Alternative Liability & Insurability 

What level of liability, if any, ought to be imposed and whether that liability should be dictated 

by statute or left to the common-law system of the courts are additional determinations requiring 

initial policy guidance. Several factors speak to the benefit of statutorily defining the level of 

liability for different parties (e.g. injectors, generators, transporters) and for different events (e.g. 

catastrophic leaks, trespass, nuisance, contamination of drinking water sources), perhaps chief 

among them the predictability and public confidence gained that could eliminate to some extent 
60

uncertainty that would otherwise serve as an impediment to development. At the same time, 

much can be said for limiting the initial regulatory and statutory framework overseeing a new 

field for which little practical data exists, allowing for greater flexibility in permitting until data 

can dictate appropriate and reasonable standards. Likewise, as more knowledge, data and 

practical experiences accrue, especially specific to New Mexico geology, proper and reasonable 

liability standards (e.g. strict liability, negligence, joint and several, alternative liability) may 

become apparent and applied in due course through the courts or by statutory amendments. The 

experience of national environmental laws provides some insight into this issue. 

The nation’s two chief environmental laws, RCRA and CERCLA, impose – through judicial 

interpretation in the case of RCRA and by express congressional intent in the case of CERCLA – 

strict liability against potentially responsible parties, and in the case of CERCLA, impose the 

additional burden of joint and several liability. In the early years of these laws insurers and 

industry representatives objected to the expansive nature of this liability scheme, urging 

Congress to eliminate language that allowed the courts to impose that level of liability, especially 

with regard to CERCLA. See Reauthorization of and Possible Amendments to the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hearing on 

H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 

98th Cong. 518-527 (May 15, 1984). Around that time in the mid-1980s, law reviews noted that 

“[i]nsurers no longer offer pollution policies because of unpredictable judicial determinations of 

the scope and extent of insurer liability. The future availability of pollution insurance is 

doubtful.” Judith M. Nixon, The Problem with RCRA – Do the Financial Responsibility 

Provisions Really Work?, 36 Am. U. L. Rev. 133 (Fall 1986). 

In the case of strict liability, however, it has been suggested that such a standard “probably 

makes claims more predictable than they would be under a negligence standard,” Jeffrey Kehne, 

Encouraging Safety Through Insurance-Based Incentives: Financial Responsibility For 

Hazardous Wastes, 96 Yale L. J. 403 (1986), because it is easier to predict when and under what 

conditions the insured will be held accountable. Generally, at common law, strict liability is 

reserved for those activities deemed to be abnormally dangerous or ultra-hazardous, which, at 

best, is an unanswered question in the case of carbon dioxide sequestration, but which will most 

likely be found not to be abnormally dangerous, similar to natural gas storage and transportation. 

 

Strict liability 

The hazardous waste industry argued that strict liability is a “harsh standard” applied under 

CERCLA and RCRA because many defendants could be liable even if they followed the 

standard of reasonable care and violated no regulations for releases “over which they had no 

actual control.” Reauthorization of and Possible Amendments to the Comprehensive 

Environmental Response, Compensation, and Liability Act of 1980: Hearing on H.R. 5640 

Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 98th Cong. 

520 (May 15, 1984) (statement of John J. Fitzpatrick, Jr., Washington counsel to Gulf Oil 

Corporation). The American Insurance Association argued before Congress that strict liability 

applied under CERCLA verged on a standard of absolute liability, improperly lacking any 

evaluation of the conduct or nature of the activities of the defendant, and that such a standard 
61

“necessarily depreciates incentives otherwise available to encourage defendants to act carefully 

and responsibly” because they were being held liable whether or not they spent time and 

resources acting responsibly. Reauthorization of and Possible Amendments to the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hearing on 

H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 

98th Cong. 628 (June 13, 1984) (statement of The American Insurance Association). 

It has been argued, however, that in the case of hazardous substances and waste managed by both 

CERCLA and RCRA, two public policy goals designed to protect human health and the 

environment are served by the imposition of strict liability: cleanup of hazardous waste 

contamination and deterrence of future contamination. Edmund B. Frost, Strict Liability as an 

Incentive for Cleanup of Contaminated Property, 25 Hous. L. Rev. 951 (1988). By imposing 

strict liability, federal regulators are assured of determining a responsible party, which in turn is 

a powerful motivator for operators to properly handle hazardous wastes. Applied to CERCLA, 

owner-operator liability “is both broader and narrower than the owner’s liability under the 

common law” strict liability standard. Id. “It is broader because it can attach whenever a facility 

is contaminated with any hazardous substances warranting response costs,” and “narrow[er] 

because it applies only to response costs (costs of investigation and cleanup), natural resources 

damages, and the cost of health assessments,” but not “to any liability for personal injury or any 

third party economic damages which may be attributed to the condition.” Id. As such, the 

statutory construction of CERCLA both assures the accountability of owners/operators for 

specified, targeted claims, while essentially limiting liability for personal injury and economic 

damages by requiring a higher standard of proof (negligence) for those claims. 

In the larger scheme, a regulatory framework that includes detailed and protective criteria for the 

site selection, drilling, operations, closure and post-closure management and monitoring of 

sequestration wells and project areas together with express statutory language creating strict 

liability for certain events and/or parties could go a long way toward eliminating, or at least 

reducing, the unknown risks inherent in a developing technology so that insurers would be 

willing to provide at least some coverage. Further, such a scheme could offer significant benefits 

in terms of public acceptance of an unknown and potentially risky mitigation technology by 

providing for a lower standard of proof for some important claims and associated damages (e.g. 

apply a strict liability standard to any impairment of drinking water resources, vegetation die-off 

from leakage of CO2, and subsurface trespass). This approach could provide for a more 

conservative (protective) handling of some high-profile concerns (drinking water sources), while 

allowing a higher standard of proof (negligence) to be applied to property damage and personal 

injury claims as a means of statutorily limiting injector liability. Without clear statutory language 

to dictate liability standards, injectors, insurers and the public must await the uncertain process of 

litigation for the courts to determine applicable liability standards, a process cited in the early 

years of CERCLA as a significant deterrent to insurers. Any imposition of a strict liability 

scheme, however, should be implemented with care and flexibility to ensure the standard is not 

onerous and properly serves the goals of protection and deterrence and does not cause project 

avoidance by being overly prescriptive, as opposed to being performance based. 

Joint and Several Liability 
62

Unlike strict liability, which has been argued increases the predictability of liability, joint and 

several liability potentially expands liability well beyond what an individual operator may have 

contributed to an accident or situation to the point that it may prevent insurers or injectors from 

participating, as in the early days of CERCLA. A consideration favoring a closer evaluation of 

the utility of joint and several liability in the field of carbon sequestration is that it ensures direct 

accountability regardless of the number and variety of parties involved in a given project, and 

may hasten settlement among potentially responsible parties, avoiding the cost of dilatory 

litigation proceedings. 

Hazardous waste handlers argued against the imposition of joint and several liability because it 

“allows parties that contribute only small quantities of hazardous substances to release sites to be 

held liable for the full amount of cleanup costs and resource damages.” Id. This argument that 

joint and several liability presented a gross inequity constituted the repeated refrain from 

industry and insurance groups during the CERCLA amendment hearings in the mid-1980s. “By 

imposing joint and several liability, potentially responsible parties have no incentive to come 

forward, absent an enforcement action, to initiate a voluntary cleanup ... [this] not only 

discourages responsible corporate behavior, but it also guarantees cleanups will have to be 

initiated under adversarial conditions.” Reauthorization of and Possible Amendments to the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hearing on 

H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 

98th Cong. 518-519 (May 15, 1984) (statement of John J. Fitzpatrick, Jr., Washington counsel to 

Gulf Oil Corporation). 

On the other hand, joint and several liability was seen as an ideal means to maintain 

responsibility and achieve a speedy, extra-judicial settlement among the parties, who have the 

best and most accurate knowledge of their own contributions, without the cost and dilatory effect 

of typically prolonged lawsuits. See Reauthorization of and Possible Amendments to the 

Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hearing on 

H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans., 

98th Cong. 87-95 (April 3, 1985). The policy motivation driving the application of joint and 

several liability is that it “appropriately reverses or transfers the burden of proof to those who do 

have the knowledge or should have the knowledge of what materials went to those sites and that 

it is in their best interest to negotiate among themselves and come forward with a settlement.” 

Reauthorization of and Possible Amendments to the Comprehensive Environmental Response, 

Compensation, and Liability Act of 1980: Hearing on H.R. 5640 Before the H. Subcomm. on 

Water Res. of the Comm. On Public Works and Trans., 98th Cong. 29 (April 3, 1985) (statement 

of Thomas C. Jorling, Prof. of Env. Studies and Dir., Center for Env. Studies, Williams College). 

Though joint and several liability may make sense for hazardous waste, where numerous parties 

may have had access to various waste sites with varying degrees of responsibility (transporters, 

generators, etc.) over a long period of time, fewer parties are likely to be involved in any given 

carbon sequestration project. While there will be transporters, injectors, generators and 

landowners involved in carbon dioxide sequestration, because of the nature of the project relative 

to the handling of hazardous waste, joint and several liability seems to be an unnecessary 

standard to impose. Hazardous waste sites may contain a wide variety of wastes of varying 

dangers deposited by numerous responsible parties, whereas carbon dioxide waste would involve 
63

disposal of a single, consistent waste from far fewer potential sources. All of these factors seem 

to suggest that the utility of imposing joint and several liability on carbon dioxide sequestration 

is less valuable than perhaps has been for the field of hazardous waste management. However, 

management of a single sequestration field would be unitized, so that if there were multiple 

injectors into a single field, there would be multiple potentially responsible parties, therefore 

parsing responsibility for a leak or other event might be difficult. In such cases, assigning joint 

and several liability might speed the resolution of any disputes over responsibility and encourage 

settlement among the parties while ensuring someone, ultimately, is held accountable. Courts 

have generally applied joint and several liability where two or more persons cause a single and 

indivisible harm. Thus, the assignment of joint and several liability might be best left to the 

courts as the facts of a given situation that might require its application cannot be completely 

anticipated and to impose it statutorily precludes the flexibility inherent in the courts. 

Alternative Liability 

Somewhat related to joint and several liability is the theory of alternative liability, which 

essentially shifts the burden of proving causation from the plaintiff to the defendants after the 

plaintiffs meet a threshold level of proof (that a harm occurred and that one of the defendants is 

the cause of the harm). Melinda H. Van der Reis, An Amendment for the Environment: 

Alternative Liability and the Resource Conservation and Recovery Act, 34 Santa Clara L. Rev. 

1269, 1270 (1994). Before the successful advancement of alternative liability theory, plaintiffs 

were unable to recover if they could not apportion responsibility or establish which among 

several tortfeasors were responsible for the harm. Where alternative liability has been established 

and accepted, plaintiffs The theory of alternative liability is codified in section 433(B) of the 

Second Restatement of Torts, subsection (3), which states: “Where the conduct of two or more 

actors is tortious, and it is proved that harm has been caused to the plaintiff by only one of them, 

but there is uncertainty as to which one has caused it, the burden is upon each such actor to prove 

that he has not caused the harm.” 34 Santa Clara L. Rev. 1269 (citing Restatement (Second) of 

Torts § 433(B)(3)). In the comments on subsection (3), the Second Restatement of Torts explains 

that the rule “applies only where it is proved that each of two or more actors has acted tortiously, 

and that the harm has resulted from the conduct of some one of them,” which still remains the 

plaintiff’s burden of proof. Restatement (Second) of Torts § 433(B) cmt. (g). Further, the 

Restatement notes that “[t]he cases thus far decided ... have all been cases in which all of the 

actors involved have been joined as defendants. All of these cases have involved conduct 

simultaneous in time, or substantially so, and al of them have involved conduct of substantially 

the same character, creating substantially the same risk of harm, on the part of each actor.” 

Restatement (Second) of Torts § 433(B)(3) cmt. (h). 

As comment (d) explains, “[t]he reason for the exceptional rule placing the burden of proof as to 

apportionment upon the defendant or defendants is the injustice of allowing a proved wrongdoer 

who has in fact caused harm to the plaintiff to escape liability merely because the harm which he 

has inflicted has combined with similar harm inflicted by other wrongdoers...” Restatement 

(Second) of Torts § 433(B)(3) cmt. d. The Restatement suggests that “in such a case the 

defendant may justly be required to assume the burden of producing that evidence, or if he is not 

able to do so, of bearing the full responsibility. Id. 
64

In California, alternative liability theory has been extended to environmental cases where 

proving causation among numerous potential defendants has proved impossible. 34 Santa Clara 

L. Rev. at 1287 (citing Zands v. Nelson, 779 F. Supp. 1254 (S.D. Cal. 1991)). According to Van 

der Reis, “[a]pplication of modified burden-of-proof requirements [alternative liability] permits 

and encourages enforcement of environmental protection statutes, and should be applied more 

broadly to environmental regulations, leading to greater compliance and more careful handling 

by operators. 34 Santa Clara L. Rev. at 1270, 1287. She suggests that vague statutes, problems 

with burden of proof, and lapse of time between an event and injury, pose substantial difficulties 

for legislators trying to craft workable environmental statutes. 34 Santa Clara L. Rev. at 1287. 

She argues that for environmental statutes to be workable “[t]he potential liability of the actors 

involved in a hazardous waste generation, transportation, and treatment regime requires clear and 

unambiguous legislation” so that parties are aware of their potential liability at the outset of an 

undertaking. Id. Stating a clear and unambiguous liability standard has the additional benefit of 

allowing court to look at the legislation and understand the intent of the legislators, allowing 

them to rule accordingly, which they cannot do under RCRA, for example. Id. 

In her recommendations for amending RCRA to establish an alternative liability standard, Van 

der Reis suggests that language should make clear that alternative liability applies in situations 

where multiple tortfeasors caused harm and where causation is difficult for a plaintiff to prove. 

34 Santa Clara L. Rev. at 1296. Further, language should require plaintiffs to meet a slightly 

higher initial threshold of proof before the burden is shifted to the defendants to maintain equity, 

and language “should delineate the defendant’s burden if alternative liability is implicated.” Id. 

Where the liability standard is clear and does not favor environmental defendants, there will be 

less confusion and debate over what level of liability is imposed, and there will be greater 

consistency in enforcement and compliance. Id. However, the author does acknowledge that 

broader application of the alternative liability theory may also “significantly” widen the scope of 

environmental litigation, encouraging plaintiffs to redress their injuries in court. 34 Santa Clara 

L. Rev. at 1270. 

Statutorily instituting alternative liability may induce the benefits ascribed to it by Van der Reis; 

certainly the literature tends to support the concept that predictability and certainty rooted in 

clear statutory language can aid the development and growth of an un-tested industry. At the 

same time, shifting the burden of proof to the defendants early in the life of a regulatory scheme 

might prevent a liability standard from naturally settling out of its own accord in a way that 

meets the needs of the disparate parties, and such an imposition could simply add to the burden 

of a nascent and unproven industry. However, similar to the argument for strict liability, 

imposing alternative liability could serve as an effective means of reassuring the public that 

operators and injectors of carbon dioxide will be held liable when at fault for harm, even if 

causation is difficult to prove, as it may very well be given the size and duration of anticipated 

projects. 

Un-insurability 

Also discussed in the CERCLA reauthorization debates of 1984-85 was the issue of the uninsurability of hazardous waste facilities and waste disposal sites given the retroactivity of the 

Act, a perceived certainty that seepage would occur at some point, and the unknown and 
65

seemingly expansive liabilities an insurance company would be taking on. Superfund 

Amendments and Reauthorization Act of 1986: Before the S. Comm. On Environment and Public 

Works 87-95 (April 3, 1985). See also L. De-Wayne Layfield, CERCLA, Successor Liability, and 

the Federal Common Law: Responding to an Uncertain Legal Standard, 68 Tex. L. Rev. 1237 

(May 1990). At the time several prominent leaders in the insurance industry testified to the uninsurability of hazardous waste sites; they were critical of provisions that allowed for the uncontracted for extension of liability of a responsible party through joint and several liability – 

potentially making one party financially liable for all the costs associated with a hazardous waste 

site even though their privately negotiated insurance contract specified a lower-level of liability. 

Id. at 26-37. The difficulties identified and associated with insuring hazardous waste sites are 

that numerous parties may be responsible over decades for delivering waste to a given site, so 

identifying responsible parties and allocating their culpability is a challenge and may be done 

somewhat arbitrarily through joint and several liability. Also, insurers suggested that “because of 

the near certainty that leakage will occur and the open-ended nature of the resulting liability” it 

was impossible for the private sector to provide insurance. Superfund Amendments and 

Reauthorization Act of 1986: Before the S. Comm. On Environment and Public Works 35 (April 

3, 1985) (statement of William O. Bailey, president of Aetna Life & Casualty and the immediate 

past chairman of the American Insurance Association). Further, insurance companies asserted 

that the provision for strict liability was a significant impediment to insurability given that even 

if a party acted with reasonable care and violated no regulations they could still be held liable for 

harm done. Id. at 140-141. 

In these debates, insurers tended to want to shift the burden for what they perceived as an uninsurable practice, due in large part to the certainty of seepage, to the public sector, similar to the 

way flood insurance has been handled jointly between the public and private sectors. Superfund 

Amendments and Reauthorization Act of 1986: Before the S. Comm. On Environment and Public 

Works 38 (April 3, 1985) (statement of Jones, T. Lawrence, President American Insurance 

Association). At that time, insurers felt that responsible parties were attempting to unfairly 

transfer liability, beyond what the premiums were intended to cover, to the insurers. Id. at 97-

102. 

Authority to Impose Sequestration Fee on Injected CO2 Volumes & Tax Exemptions 

Issue: 

If it is decided that a transfer of liability and ownership of sequestered CO2 to the public sector is 

proper, it is contemplated that there should be some fund available to cover the monitoring, 

measurement, verification (MMV) and mitigation costs associated with long-term management 

of sequestration projects following operational and post-closure phases. 

Such a fund could be managed by the state and based on a fee assessed per volume sequestered. 

Issues Raised During Workgroup Meetings: 

 Will the fee apply only to CO2 injected for sequestration purposes and not to EOR 

projects? 
66

 How will the state handle out-of-state CO2 generators sequestering in state? Will out-ofstate generators be assessed a fee at the state line? Or at the point of injection? 

 EOR associated with sequestration should be subject to an increased severance tax, 

reflecting the benefit conferred to interest owners by the recovery of otherwise noneconomic resources, reserving the proceeds in a Superfund-type account to address 

potential future environmental remediation. 

 The possibility of exemptions/financial incentives was not discussed to any great extent. 

Analysis: 

CO2 sequestration literature has proposed a per-volume injection fee as a means to cover the 

unknown costs of long-term monitoring, measurement, verification and mitigation: 

 Injection Fee 

o Mandatory contributions by injection operators to a fund managed by the state, to 

be used exclusively for the long-term monitoring, measurement, verification and 

mitigation of CO2 storage once liability transfers to the state. 

Texas has proposed a tax-exemption provision for anthropogenic CO2 sequestration (H.B. 3431). 

The major provisions of the exemption are as follows: 

 Producer of oil or gas recovered through an enhanced recovery project is entitled to a 

reduction in severance tax rate if recovery of oil uses carbon dioxide that is from an 

anthropogenic source, would otherwise be released to the atmosphere, and is ultimately 

sequestered (per OCD definition) in one or more geological formations 

 Qualification for tax reduction is granted following certification by regulatory agency 

 Certification requires demonstration based on substantial evidence that there is a 

reasonable expectation that sequestration will result in at least 99 percent of CO2 

remaining sequestered for at least 1,000 years 

 Monitoring and verification for a period sufficient to demonstrate whether the 

sequestration is performing as expected 

 Tax reduction does not apply if measuring and verification determine a different amount 

is being stored 

Authority to Bond Injection Projects & Facilities 

Issue: 

Aside from the costs associated with post-closure MMV and potential mitigation, are the costs 

associated with reclaiming project sites and facilities following injector abandonment or 

insolvency. The state would need to ensure that injectors provide adequate financial assurance to 

cover the cost of any necessary plugging, reclamation or mitigation required as a result of 

abandonment or insolvency. 

Issues Raised During Workgroup Meetings: 
67

 Should bonds be required for a project and surface facilities, as well as for individual 

wells. 

 Excessive bonding will discourage operators from undertaking sequestration projects and 

make them cost prohibitive given the range of cost unknowns already contemplated. 

Authority to Enter Land for Inspection 

Issue: 

The state will need clear authority to enter surface estates to inspect facilities and the integrity 

and functioning of injection wells and other bore holes that may penetrate the CO2 sequestration 

zone. And in the event of the transfer of ownership/liability to the state, the Division will require 

authority to enter surface properties to plug abandoned wells and reclaim sequestration surface 

facilities. 

Protection of Surface Owner Interests 

Issue: 

The Surface Owners Protection Act applies only to exploration, drilling or production of oil and 

gas, and would need to be amended to include activities related to the sequestration of carbon 

dioxide to adequately protect the interests of surface owners in the same way they are currently 

protected for oil and gas production. 

CONCLUSION OF STATUTORY ISSUES 
68

IDENTIFIED REGULATORY ISSUES 

The above issues will need to be considered or addressed in any statutory scheme to facilitate the 

geologic sequestration of Carbon Dioxide. Once the policy decisions are made and the 

regulatory direction is determined, the rules to support those decisions will need to be 

implemented. An outline of the regulatory issues that must be addressed is as follows: 

General 

 Statement of Division’s General Authority 

 Enforcement/Penalties 

o Adopt OCD rules and penalties for noncompliance (70-2-31) 

 Maximum of $1,000/day/violation 

 Some provision for criminal penalties 

o Prevent operator from selling product (if CO2 used to enhance hydrocarbon 

recovery) 

o OCD can seize and sell product (if CO2 used to enhance hydrocarbon recovery) 

o OCD can revoke permits 

o OCD can shut in injection wells 

o Prohibit the degradation of groundwater (UIC) 

 Prohibit venting of CO2 

o Provide for emergency venting provisions. 

o Allowance for equipment failure. 

 Definition of Permanent Sequestration 

o Establish maximum acceptable leakage rate ( 1% over 1000 years?). 

 CO2 Registry 

o Mesh CO2 sequestration accounting requirements with state registry program? 

o Ensure proper accounting of net anthropogenic CO2 sequestration in cycled 

enhanced hydrocarbon projects. 

Siting & Permitting 

 Property Rights 

o Injector must demonstrate sufficient/adequate property rights 

 Pore space 

• Agreement/rentals with surface owners 

• Condemnation via eminent domain 

• Threshold interest to establish right to condemn 

 Mineral interests 

• Unitization (voluntary or compelled) 
69

o Guidelines for compelling unitization of CO2 sequestration 

zone 

o Parties to unitization 

 Provide for contractual relationship 

o Procedure for federal/Indian minerals 

o Notice to surface owners and mineral interests within unit 

and extending to a defined distance beyond (1 mile?) 

 Opportunity to contest/protest unitization through 

hearing process 

o Provision to allocate costs when not covered by contract 

(compelled unitization) 

 What costs included? 

• Cycling/re-injecting CO2? 

• Costs of original CO2 injection? 

o Capital costs 

o Operating costs 

• Transportation of CO2 to site? 

o Allocation of production 

 Mineral Leases 

o Existing 

 Establish which party must ensure the integrity of existing wells 

penetrating the storage zone. 

o New Operations 

 Can drill through storage zone if successfully demonstrate that drilling 

won’t impact storage reservoir integrity 

 Require new wells to analyze strata above and below storage unit for CO2 

and report findings 

 Site & Reservoir characterization and mapping (baseline data) 

o Reservoir 

 Type 

• Depleted oil 

o Water drive 

o Depletion drive 

• Depleted gas 

• Unminable coal seam 

• Saline aquifer 

 Original reservoir pressure 

• Injection pressures should not exceed fracture pressure and 

reservoir pressure should not exceed the original reservoir pressure 

unless the injector can demonstrate otherwise through a formal 

hearing process 

 Determine Reservoir size and areal extent (final storage volume) 

 Depth (average depth) and volume of proposed storage reservoir 

 Groundwater/drinking water sources (depth/height to source) 
70

• Include deepest groundwater source 

o Map faults 

o Seismic/tectonic history and activity 

o Regional pressure gradients 

o Baseline measurements 

 Groundwater chemistry 

 Surface soils 

 Connate fluids 

o Wells (determine location and status of all wells within unit and buffer zone) 

 Fracturing history of existing wells. 

o Trapping mechanism (geochemical, stratigraphic, etc.) 

 Stratigraphic position and thickness of all confining strata 

 Determination of confinement mechanism to prevent CO2 mobility 

 Stratigraphic discontinuities/spill points and likely potential leakage points 

 Injection 

o Proposed Injection pressures below reservoir fracture pressure 

o Proposed volumes and rates of injection 

o Demonstrate Frac gradient (frac pressure limits) 

o Proposed monitoring and modeling methods for injected CO2 plume 

 Radius of Influence/Area of Review 

o Locate all wells (water, oil and gas, plug & abandoned) 

 Determine if properly cased/plugged to prevent leakage/seepage of CO2 

into other formations or to surface 

o Areal extent of monitoring defined 

 Proposed public safety and emergency response plan 

o Worker safety and training plan 

o Corrosion monitoring and prevention plan 

o Leak detection and monitoring plan for all wells and surface facilities within the 

areal extent of unit 

 Siting 

o OCD/Commission to approve proposed injection well site and 

containment/reservoir modeling 

 Bonding 

o Establish independent bonding requirements (separate from oil and gas 

production bonding) to cover abandoned CO2 injection projects and surface 

facilities 

o Bonding for individual wells 

o Effect on CO2 generator? Need some bail out if contractual injector fails to meet 

contractual agreement? 

 Notice Requirements 
71

o Surface owners within x distance (1 mile ?) beyond unit area 

o Mineral interests within unit area 

o Interests within a buffer zone beyond areal extent of unit (1 mile?) 

o Include legal description of permit area, date, time and place of hearing for permit 

 Permit conditions 

o Fully revocable by OCD 

o Monthly reporting 

 Injected volumes 

 Reservoir pressures 

 Groundwater monitoring 

o 5-year major permit review 

 Injector demonstrates full permit compliance and containment 

 Procedure and Requirements for Transfer/Sale of Sequestration Project 

o Require permit review at time of transfer if prior to post-closure period (?) 

o Allow for modification of permit at time of transfer(?) 

o Allowing full permit review at transfer may impose too many uncertainties 

o Continuation of bonding 

Drilling & Operations 

 OCD Right of Entry 

o Monitoring 

o Inspection 

o Plug/re-plug problem/abandoned wells 

 Casing requirements 

o Ensure protection against acid degradation with proper casing 

o Demonstrate well is cemented to adequately confine injectate 

o To protect fresh water 

 CO2 purity 

o 90-95 percent (?) (90 percent recommendation by Southwest Regional 

Partnership; 95 percent in Sen. Bingaman’s bill) 

o Re-circulation of CO2 

 Account for volumes circulated (mass balance, how much CO2 is 

circulated in EOR projects; avoid double sequestration credit) 

 Operators right of surface entry 

o Injection operator has right to enter and properly plug abandoned or problem 

wells within project area to ensure integrity of sequestration project 

 Monitoring during injection 

o Injection well integrity 
72

 Corrosion monitoring 

o Integrity of wells producing in or drilled thru injection zone 

 casings 

o groundwater 

o surface soils 

o formation pressure 

o Distributed observation wells 

o CO2 plume 

 OCD to approve monitoring/modeling proposal 

o CO2 leakage (out of formation/target zone) and seepage (to the surface) 

 Measure/trap CO2 emissions from surface facilities (plants/compressors) 

o CO2 purity 

 CO2 safety 

o Public and worker safety and emergency response plans 

 Demonstrate adequate worker training 

 Posted contact info at all surface facilities and wells within unit area? 

o Contingency plans 

 Individual wells and project 

o Venting prevention 

 Allowable leak rate 

• From injection well? 

• From formation? 

• Mechanical Emergencies 

Post-Injection & Closure 

 10-year demonstration of reservoir and well integrity after cessation of injection phase 

before evaluation for potential transfer of ownership/liability? Or proper length of time to 

demonstrate integrity after injection phase (when formation pressures stabilize)? 

o Demonstrate site/formation stability (Gorgon/Australia) 

o Alternative: set up a closure/transfer window – transfer/closure shall occur no 

sooner than a given length of time after injection ceases and no later than a certain 

time after injection ceases 

o Demonstrate integrity of wells (both injection and those perforating unit) 

o Can petition Commission to shorten demonstration period 

o Allowable leak rate/percentage? 

o Disallow blowdown of formation in CO2 sequestration projects (without reinjection of CO2) 

o Transfer liability of only those projects that meet expectations/minimum leak 

rates? 

 Monitoring 

o Well Pressures 

 Inject N2 at end of injection phase for monitoring/safety (Dr. Lee) 
73

o Soil 

o Groundwater 

 Groundwater monitoring wells 

• 1 up-gradient, 3 down-gradient (gradient may change over long 

time spans)? Adequate for areal extent? 

o Status/behavior of CO2 plume over time? 

 Proposed monitoring/modeling to be approved by OCD 

 Plugging 

o Within a certain time of termination of injection phase, all injection wells must be 

plugged 

o State inspector on site at time of well closure/plugging 

 Reclamation/Restoration of surface 

o All surface facilities to be removed and surface reclaimed 

 Qualifications for transfer 

o Closure report 

 Final assessment of operations 

 Volumes injected/extracted 

• CO2 purity 

 Chemical analyses of injectate/groundwater 

 Summary of monitoring 

 Current position and characteristics of areal extent of CO2 plume 

 Model and predicted behavior of plume 

Post-Closure 

 Transfer of liability 

o Option for injector/operator to retain ownership/liability 

o Notification of transfer 

 Long-term monitoring plan 

 Mitigation plan 
This document is not available in Regulations.gov since it 

contains copyrighted material that may not be reproduced 

without consent of the copyright holder. 

Contact the EPA Docket Center, Public Reading Room to view 

or receive a copy of this document. Requests for copies may be 

made as follows: 

In person/writing: 

Environmental Protection Agency, Docket Center 

1301 Constitution Ave NW, 2822T, Room 3334 

Washington, DC. 20004 

Telephone: 

202-566-1744 

Fax: 

202-566- 9744 

Email: 

docket-customerservice@epa.gov
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1

Evaluating the costs of desalination and water transport

Yuan Zhoua,b, Richard S.J. Tolb,c,d

a

 International Max Planck Research School of Earth Systems Modeling, Hamburg, Germany

b Research unit Sustainability and Global Change, Hamburg University and Center for Marine and 

Atmospheric Science, Hamburg, Germany

c Institute for Environmental Studies, Vrije Universiteit, Amsterdam, The Netherlands

d Department of Engineering and Public Policy, Carnegie Mellon University, Pittsburgh, PA, USA

December 9, 2004

Working paper FNU-41 revised

Abstract

Many regions of the world are facing formidable freshwater scarcity. Although there is

substantial scope for economizing on the consumption of water without affecting its service 

level, the main response to water scarcity has been to increase the supply. To a large extent, this 

is done by transporting water from places where it is abundant to places where it is scarce. At a 

smaller scale, and without a lot of public and political attention, people have started to tap into 

the sheer limitless resource of desalinated water. This study looks at the development of 

desalination and its costs over time. The unit costs of desalinated water for five main processes 

are evaluated, followed by regressions to analyze the main influencing factors to the costs. The 

unit costs for all processes have fallen considerably over the years. This study suggests that a cost 

of 1 $/m3 for seawater desalination and 0.6 $/m3 for brackish water would be feasible today. The 

costs will continue to decline in the future as technology progresses. In addition, a literature 

review on the costs of water transport is conducted in order to estimate the total cost of 

desalination and the transport of desalinated water to selected water stress cities. Transport costs 

range from a few cents per cubic meter to over a dollar. A 100 m vertical lift is about as costly as 

a 100 km horizontal transport (0.05-0.06$/m3). Transport makes desalinated water prohibitively 

expensive in highlands and continental interiors, but not elsewhere.

Keywords: water cost, desalination, water transport, MSF, RO, water shortage

1. Introduction

Water is a crucial resource for survival and growth of life, as well as sustaining the environment. 

However, the vast majority of water on the earth is too salty for human use. Ninety-seven 

percent of the earth’s water is found in the oceans, with a salt content of more than 30,000 

milligrams per liter (mg/l) (Gleick, 2000). Water, with a dissolved solids (salt) content below 

about 1000 mg/l, is considered acceptable for a community water supply (IDA, 2000). Because 

of the potentially unlimited availability of seawater, people have made great efforts to try to 

develop feasible and cheap desalting technologies for converting salty water to fresh water.

A variety of desalting technologies has been developed over the years, including primarily 

thermal and membrane processes. The main thermal processes include multi-stage flash

evaporation (MSF), multiple effect evaporation (ME), and vapor compression (VC). The

membrane processes contain reverse osmosis (RO), electrodialysis (ED) and nanofiltration (NF). 

The MSF and RO processes dominate the market for both seawater and brackish water 

desalination, sharing about 88% of the total installed capacity (IDA, 2002)(Fig. 1). Raw water 
2

with different qualities has been treated in desalting plants, dominated by seawater and brackish 

water (IDA, 2002)(Fig. 2). Seawater is desalted often by various thermal processes and also by 

RO, whereas brackish water is treated by means of mainly RO and ED.

Desalination of brackish and seawater has been expanding rapidly in recent decades, primarily to 

provide water for municipal and industrial uses in arid, semi-arid or water-short areas. It is driven 

by water stress generated from limited water resources and ever growing demands for water. 

Continuous progress in desalination technology makes it a prime, if not the only, candidate for 

alleviating severe water shortages across the globe (Ettouney et al., 2002). The market is also 

driven by the falling costs of desalination, which are due to the technological advances in the 

desalination process (Tsiourtis, 2001). Till 2002 over 15,000 industrial scale desalination units, 

with a total capacity of 32.4 million m3/d, had been installed or contracted worldwide. Among 

them, non-seawater desalination plants contributed with 13.3 million m3/d, whilst the capacity of 

the seawater desalination plants reached 19.1 million m3/d (IDA, 2002). 

 

Fig. 1. Installed desalting capacity by process. Fig. 2. Installed capacity by raw water quality. 

The costs of water produced by desalination have dropped considerably over the years as a result 

of reductions in price of equipment, reductions in power consumption and advances in system 

design and operating experiences. As the conventional water supply tends to be more expensive 

due to over-exploitation of aquifers and increasing contaminated water resources, desalted water 

becomes a viable alternative water source. Desalination costs are competitive with the operation 

and maintenance costs of long-distance water transport system (Ettouney et al., 2002). This study 

defines the main economic parameters used in estimation of desalination costs and calculates the 

unit costs of desalted water for five main processes based on simplified assumptions. It then uses 

multiple regression to estimate the trends of unit costs over time and analyze the significant 

factors that affect the cost of desalination. Moreover, in this study a literature survey on the costs 

of water transport is conducted in order to estimate the total cost of desalination and the transport 

of desalinated water to where water is short.

2. An overview of desalination costs by various processes

The costs of desalination vary significantly depending on the size and type of the desalination 

plant, the source and quality of incoming feed water, the plant location, site conditions, qualified 

labor, energy costs and plant lifetime. Lower feed water salinity requires less power consumption 

and dosing of antiscale chemicals. Larger plant capacity reduces the unit cost of water due to 

economies of scale. Lower energy costs and longer plant period reduce unit product water cost. 
3

The primary elements of desalination costs are capital cost and annual running cost. The capital 

cost includes the purchase cost of major equipment, auxiliary equipment, land, construction, 

management overheads, contingency costs etc. The capital costs for seawater desalination plants 

have decreased over the years due to the ongoing development of processes, components and 

materials. Annual running costs consist of costs for energy, labor, chemicals, consumables and 

spare parts. A typical breakdown of running costs for thermal processes is that the ratio of 

energy: chemicals: labor equals 0.87:0.05:0.08 (IDA, 2002). The energy costs play a dominant 

role for thermal processes. Distillation costs will fluctuate more than RO with changing energy 

costs. In regions where the energy is fairly expensive, RO is a favorable choice compared to any 

other thermal processes due to its lower energy consumption. 

To provide the overview of the desalination costs worldwide, we evaluate the unit costs for the 

main processes based on rough assumptions. All the plants rated at 600 m3/d per unit or more for 

the five main processes in IDA Worldwide Desalting Plants Inventory Report No.17 (2002) are 

included in the calculation. The report provides information on land-based desalting plants rated 

at more than 100 m3/d per unit and contracted, delivered or under construction as of the end of 

2001. The report is considered to be the most comprehensive and complete of its kind worldwide 

though not high quality especially in providing more detailed information on single plant. The 

dataset should be handled with caution since there are no other dataset available to cross check 

on it. The data regarding desalting plants include country, location, total capacity, units, process, 

equipment, water quality, user, contract year and investment costs. The detailed annual running 

costs are not available for the plants so it is hard to differentiate what kind of costs exactly are 

included and how. The total costs are assumed to be split up into 40% capital costs for interest 

and depreciation on the investment and 60% of running costs referring to IDA (2002). The load 

factor is assumed to be 90% for all the plants. These assumptions are the same for all desalination 

techniques, again for want of better information. We use the IDA (2002) despite the crudeness of 

the data. The alternative would be to build our own database that may have higher quality and 

more detailed cost data, but which would also have a much smaller number of observations, have 

a more limited geographic scope, and cover a much shorter period of time.

The annual amortized capital costs are obtained by multiplying the costs by an amortization 

factor, given as follows:

 ( ) ( )

1

1 1 1 n n C P i i i −= × × +   + −   

where C is amortized annual capital cost, P the investment in the original year, i the annual 

discount rate, and n the economic plant life. In this study, a discount rate of 8% and a plant life of 

30 years are applied for amortization for all the cases. For the purpose of comparison, all unit 

costs are given in terms of 1995 US dollars calculated based on the United States Consumer Price 

Index. The cost data and our calculation are available on the web http://www.unihamburg.de/Wiss/FB/15/Sustainability/Models.htm.

2.1. Costs of the MSF process

This study considers 442 desalting plants using MSF processes worldwide from year 1957 to 

2001, with a total capacity of 12.6 million m3/d. The process accounts for the second largest 

installed desalting capacity in the world next to RO. The major consumers of MSF are in the 

Middle Eastern and North African (ME&NA) countries, such as Saudi Arabia, United Arab 

Emirates, Kuwait, Libya and Iran. The main users of desalinated water are municipality, industry 

and power plants. The majority of plants are designed to treat seawater.
4

0.0

3.0

6.0

9.0

12.0

0 2,000,000 4,000,000 6,000,000 8,000,000 10,000,000 12,000,000

Total installed capacity(m3/d)

Unit cost($/m

3

)

Fig. 3. Unit costs vs. total installed capacity by the MSF process.

Fig. 3 illustrates the unit costs of all the desalting plants using the MSF process over the total 

cumulative installed capacity. The unit cost has been reduced substantially since the initial stage 

of MSF technology. The average unit cost has fallen from about 9.0 $/m3 in 1960 to about 1.0 

$/m3 at present, which indicates that there has been a great improvement of MSF technology. The 

average annual reduction rate of unit costs has been about 5.3% in last 40 years.

We use regression methods to estimate the unit costs of these desalting plants. The original data 

for the plant include the location, the year, the plant capacity and raw water quality. The 

calculated data include unit costs and the total cumulative installed capacity. The major

consumers for MSF are located in the Middle East and North Africa (ME&NA), therefore 

regional dummies are included to analyze the significance of location differences. The raw water 

quality dummies are also included. The model for this process is specified in (1).

F(UNITC) ( = G TIC,CAP,YEAR,&,) ME NA SEA (1)

where UNITC is the average unit cost of desalting one cubic meter of water, TIC refers to the 

total cumulative installed capacity, which reflects the expansion of desalting plants over time. 

CAP is the capacity of a single plant. YEAR is the contract year of the plant. ME&NA is the 

regional dummy, and SEA is the raw water quality dummy. The model was estimated with OLS 

for two different equations, namely semi-log and double log. Since TIC and YEAR are correlated 

and non-stationary, we estimate separate equations with either (but not both) explanatory

variable. UNITC cointegrates with both TIC and YEAR, and TIC and YEAR cointegrate with each 

other. Statistical techniques for multi-cointegration have yet to be developed (cf. Banerjee et al., 

1993; Chatfield, 2004), except when there is strong prior information (Tol and de Vos, 1998), 

which we lack in this case. Note that the two alternative regressions have a different

interpretation. With YEAR as an explanatory variable, costs reductions are due to technological 

progress outside the water desalination industry. In contrast, with TIC as an explanatory variable, 

cost reductions are due to technological progress inside the water desalination industry through 

learning by doing. The estimation results are presented in Table 1.
5

Table 1. Unit cost estimation results

Variable Log-log Semi-log

Log-log (energy 

adjusted )

Constant 6.93* 798.76* 1.21* 109.49* 5.83* 672.22*

(38.96) (38.73) (14.85) (36.65) (29.11) (31.36)

TIC -0.35* -1.71E -07* -0.26*

(-30.22) (-33.95) (-20.21)

YEAR -105.02* -0.06* -88.33*

(-38.59) (-36.31) (-31.22)

C AP -0.16* -0.14* -2.21E -06* -2.14E-06* -0.17* -0.14*

(-12.85) (-13.30) (-7.93) (-8.01) (-12.19) (-13.24)

ME&NA 0.10* 0.05 -0.06 -0.05 0.21* 0.17*

(2.76) (1.54) (-1.85) (-1.41) (4.94) (5.05)

SEA 0.63* 0.69* 0.73* 0.68* 0.66* 0.73*

(7.35) (9.54) (8.74) (8.57) (29.12) (9.71)

R

2

-adj. 0.77 0.84 0.78 0.80 0.64 0.78

F value 369.37 571.16 393.55 445.83 195.08 397.89

Log likelihood -161.29 -85.85 -150.44 -130.84 -213.46 -102.99

n 442 442 442 442 442 442

The t statistics are in parentheses.

*Significance at the 0.01 level. 

The regressions show that all the variables but ME&NA are statistically significant in unit cost 

estimation. The negative values imply that the unit cost declines with the increase of the 

variables. As TIC represents the total installed capacity of all the desalting plants, the decline of 

the unit cost can be explained as a result of the technological development and gained

experiences. CAP also influences the unit cost of a plant, as the cost tends to be lower with the 

increase of plant capacity due to economies of scale. It is thus suggested from this study that 

seawater desalting plants using the MSF process will be economically favorable to have a larger 

capacity. However, the correlation is not obvious for plants with a capacity less than 50,000 m3/d 

(Zhou and Tol, 2004). YEAR is significant, reflecting that the technology change outside the 

sector also plays an important role in the cost reduction ove r time. The positive value of SEA

implies the higher unit cost for seawater desalting than for other raw water quality. 

According to the regression results, the unit cost will continue to decrease with the increasing 

cumulative capacity and over the time. The double log estimation with TIC suggests a total 

installed capacity elasticity of –0.35, that is, for every 1% extension of the total installed

capacity, the unit costs decrease by 0.35%. For the year 2001 alone, the total contracted capacity 

has increased by about 8%. That would mean a decrease of unit cost by 2.8%. The study also 

indicates an elasticity of –0.16 for the plant capacity, that is, increasing returns to scale.

As energy cost played such a significant role in the total cost of desalination, one may wonder 

why the curve in Fig. 3 does not reflect the oil crisis in the 1970’s, which had led to the dramatic 

increase of oil prices. The reason is that the above estimation is conducted irrespective of energy 

prices due to lack of information on actual energy consumption for all the plants. In order to get 

an idea of how the energy prices may influence the whole cost of desalination, we report a 

sensitivity analysis by calculating the unit cost over time based on the correlation between energy 

costs and oil prices. Although some plants run on natural gas instead of oil, here we take only oil 

prices since the gas price typically follows the oil price. One may argue that the production costs 

of plants would not be affected by changes in oil prices because the Middle Eastern countries, 
6

where most desalination plants are located, have plenty of cheap oil and gas. However, the 

market price reflects the “opportunity cost” incurred for not selling oil and gas. The crude oil 

prices are obtained from the websites of the Office of Transportation Technologies

(http://www.ott.doe.gov) and the Energy Information Administration (http//www.eia.doe.gov). 

We assume that the energy costs account for 50% of the total cost in the year 1995, and then 

correlate the energy cost in a particular year with oil prices of the time. If the oil price doubles in 

that year compared to 1995 level, then the energy cost also doubles. Fig. 4 illustrates the unit 

costs of MSF plants with and without adjustment for oil prices. Without oil prices, there is a 

comparatively neater trend than with prices adjustment. Fig. 4b shows clearly higher costs during 

the period 1970-1985. Since 1990, the unit costs are more or less similar in 4a and 4b. This 

analysis indicates that you could expect more or less similar fluctuations of costs for other 

thermal processes such as ME and VC and perhaps a smaller scale of fluctuations for membrane 

processes. The regression using log-log model was conducted again with oil prices adjusted data 

and the result was presented in Table 1. Clearly, there is a less correlation for the energy-adjusted 

data and it also suggests a less total installed capacity elasticity and the significance of plant 

locations (ME&NA). 

Due to the crudeness of data, it is difficult to come up with a realistic analysis of energy costs for 

all the plants. This analysis is presented here for illustrative purposes only. For the rest of the 

paper, energy costs are not adjusted particularly with oil prices for desalination cost estimation.

 a. Without oil prices b. With oil prices

Fig. 4. Sensitivity analysis of unit costs regarding energy costs.

2.2. Costs of the RO process

The RO process has become more popular during the past decades due to advancing technology 

and falling costs. It should be noted, though, that RO plants are more difficult to operate than 

other types of desalination plants, the main attraction being costs. The operating cost of RO 

plants has been reduced, thanks to two developments: (1) lower-cost, higher-flux, higher saltrejecting membranes that can efficiently operate at lower pressures and (2) the use of pressure 

recovery devices (Gleick, 2000). This study contains 2514 desalting plants using RO processes 

worldwide, with a total capacity of 12.7 million m3/d since the 1970’s. The process has become 

to have the largest installed desalting capacity throughout the world. RO is often used to treat less 

saline water, such as brackish, river and wastewater. Since the last decade, it has been

increasingly applied for seawater as well and has become competitive to thermal processes. Till 
7

2001, a breakdown of capacity according to feed water quality is that the ratio of brackish: 

seawater: river&pur e: other is about 40:14:40:6. The users include municipal and industrial use, 

power plants and also tourism. 

Fig. 5. Unit costs vs. total installed capacity by the RO process.

Fig. 5 shows the unit costs of all desalting plants using RO processes over the total cumulative 

installed capacity. The different feed water qualities are indicated with different symbols. In 

general, the unit costs for seawater are the highest, followed by waste-, brackish- and river & 

pure water. Raw water quality plays an important role in the costs of RO desalination. The 

average unit costs of RO processes have declined from 5.0 $/m3 in 1970 to less than 1.0 $/m3

today. Fig. 5 also shows that the unit costs for seawater desalination are still above 1.0 $/m3

whilst the costs for desalting brackish-, river- and pure-water has been reduced to less than 0.6 

$/m3 level. Note that recent tenders costs of large seawater RO indicate even lower costs. For 

instance, some field estimates suggest a cost of $0.55/m3 for a large RO project in Florida 

(Ettouney, 2002); more recent cost proposals such as for the Ashkelon desalination in Israel have 

included costs as low as US$0.52/m3 (Busch and Mickols, 2004). 

Essentially we did similar regressions to estimate the unit cost as for the MSF process. The major 

consumers for RO are located quite dispersedly worldwide such as in the USA, Saudi Arabia, 

Spain, Japan and Korea, which give no information about grouping countries, therefore the 

regional dummies are excluded. Various raw water qualities such as brackish-, sea-, river-, pure-, 

wastewater are included. The model specification is in (2). 

F(UNITC) ( = G TIC,CAP,YEAR, SEA, BRACK, ) RIVERPURE (2)

where SEA, BRACK, and RIVERPURE refer to seawater, brackish water and river plus pure 

water dummies. Wastewater and brine water are in category OTHER, which does not show in the 

equation. The regression results for double-log and semi-log models are presented in Table 2. 
8

Table 2. Unit cost estimation results

Variable Log-log Semi-log

Constant 5.19* 652.68* 0.60* 88.66*

(53.99) (47.42) (19.66) (47.84)

TIC -0.29* -9.03E -08*

(-50.20) (-36.85)

YEAR -85.81* -0.04*

(-47.34) (-47.77)

CAP -0.10* -0.09* -3.55E -06* -3.74E-06*

(-15.85) (-14.42) (-6.72) (-7.89)

SEA 0.50* 0.50* 0.46* 0.49*

(17.82) (17.02) (13.89) (16.19)

BRACK -0.41* -0.42* -0.38* -0.41*

(-16.17) (-15.89) (-12.66) (-15.16)

RIVERPURE -0.66* -0.67* -0.70* -0.66*

(-25.17) (-24.86) (-22.74) (-23.76)

R

2

-adj. 0.72 0.71 0.62 0.69

F value 1322.63 1216.75 813.19 1122.73

Log likelihood -639.38 -716.31 -1050.91 -787.04

n 2514 2514 2514 2514

The t statistics are in parentheses.

*Significance at the 0.01 level.

The results show that all the variables are statistically significant at the 0.01 level. The negative 

coefficient values of TIC and CAP imply a lower unit cost with the increase of the total installed 

capacity and the plant capacity, which is similar to the estimation of MSF. Raw water qualities 

give both positive and negative values. The positive coefficient value of SEA implies that there is 

a higher unit cost for seawater desalination than OTHER (wastewater). Negative coefficient 

values of BRACK and RIVERPURE indicate a lower unit cost for brackish-, river-, pure- water 

than wastewater. Moreover, RIVERPURE (-0.66) shows a smaller value than BRACK (-0.41), 

which implies that the unit cost of desalting river & pure water is lower relative to that of 

brackish water. These results make sense in that cleaner and less saline water requires relatively 

less energy than low quality water in treatment process.

The double-log regression results suggests a total installed capacity elasticity of –0.29, which 

means that for every 1% extension of the total installed capacity, the unit costs fall by 0.29%. For 

the year 2001 alone, the total contracted capacity has increased by about 13%, which would 

mean a fall of unit cost by 3.77%. It also indicates an elasticity of –0.10 for the plant capacity, 

which is lower than for MSF.

2.3 Costs of the ME, VC and ED processes

Three other processes, namely multiple effect evaporation (ME), vapor compression (VC) and 

electrodialysis (ED), also contribute significantly to desalination. ME and VC are thermal

processes applied mainly to seawater desalination whilst ED is a membrane process often used to 

desalt less saline water. According to IDA Report 17, there are about 143 desalting plants using 

the ME process worldwide, with a total capacity of 907,000 m3/d and 289 desalting plants using 

the VC process with a total capacity of about 1.4 million m3/d. The VC process was introduced 

in the 1970s, later than MSF and ME. It was generally used for small and medium scale seawater 

desalination, but has been developed rapidly in recent decades. In addition, the report comprises 

427 desalting plants by the ED process, with a total capacity of 1.3 million m3/d. 
9

Fig. 6. Unit costs by the ME process. Fig. 7. Unit costs by the VC process.

Fig. 8. Unit costs by the ED process.

Fig. 6-8 show the unit costs of each process over the total installed capacity. The cost of 

desalination by the ME process has fallen from 10.0 $/m3 in the 1950’s to about 1.0 $/m3 today. 

For the VC process, the cost has also decreased considerably over time, from 5.0 $/m3 in 1970 to 

about 1.0 $/m3 at present. As to the ED process, it is remarkable that it has a relatively lower cost 

than other processes. The average unit cost has gone down from 3.5 $/m3 in the 1960’s to less 

than 1.0 $/m3 today. One reason is that brackish water was largely used as fee d water. However, 

the costs seem to go up a bit at the end of the curve, it is because there are a few plants with 

unknown water quality, which can be wastewater or even seawater. For brackish water

desalination, the average unit cost by ED is about 0.6 $/m

3

 at present. 

Similar regressions were conducted for these three processes as well. Given the dispersed spatial 

distribution of major consumers, the regional dummies are not included. SEA and OTHER are 

included as water quality dummies for the ME and VC processes whilst BRACK and OTHER are 

taken for the ED process. The estimation results with double log function for each process are 

presented in Table 3. For ME and VC processes, all the explanatory variables are significant at 

the 0.01 level. For the ED process, however, it is somewhat surprising that brackish water is not 

significant, which indicates that the unit costs are independent from raw water quality (excluding 

seawater). The regression results also suggest an elasticity of the total installed capacity of -0.40 

for the ME process, -0.26 for VC, and -0.38 for ED. ME and ED learn faster than MSF and RO 
10

and may potentially challenge the two dominant technologies; VC is a slow learner and may 

never be used for anything but niche applications.

Table 3. Unit cost estimation results 

Variable ME (log-log) VC (log -log) ED (log-log)

Constant 6.06* 684.72* 4.53* 727.39* 5.42* 677.53*

(16.26) (30.80) (21.35) (18.20) (25.08) (23.88)

TIC -0.40* -0.26* -0.38*

(-15.76) (-17.75) (-26.87)

YEAR -0.90* -95.59* -89.15*

(-30.73) (-18.16) (-23.86)

C AP -0.08* 0.09* -0.13* -0.12* -0.08* -0.07*

(-2.85) (-4.99) (-7.04) (-6.54) (-5.09) (-3.91)

SEA 0.74* 0.76* 0.44* 0.39*

(9.52) (16.54) (11.31) (9.94)

BRACK 0.0006 -0.03

(0.02) (-0.71)

R

2

-adj. 0.67 0.88 0.60 0.61 0.68 0.63

F value 94.86 347.57 146.05 148.97 298.47 240.38

Log likelihood -52.31 20.34 -44.80 -54.55 -65.80 -99.37

n 142 142 288 288 427 427

The t statistics are in parentheses.

*Significance at the 0.01 level.

To summarize, the unit cost of desalination has fallen considerably since the past 50 years. It was 

due to the advancing technology in desalination and membrane fields as well as accumulated 

experiences. The MSF process is still the leading process in seawater desalination, followed by 

VC and ME processes. The unit cost of desalting seawater has been reduced to about 1.0 $/m3 or 

less. RO and ED processes are most often used to treat brackish-, waste- and river water. The unit 

cost of desalting brackish water has fallen to about 0.6 $/m3. Due to the lower costs, the 

expansion of the total capacity of RO plants has been pronounced during the last few years. 

Particularly for seawater RO, recent tenders have indicated lower costs of large seawater RO 

plants. RO has shown the great potential to become the most economical process for seawater 

desalination in the future. As technology and practices grow, the cost of desalination will further 

decrease. 

3. Costs of water transport

An extensive search of the scientific literature revealed that little has been published on the costs 

of transporting water. A few informal interviews with engineers made clear that cost information 

is held by engineering companies and is considered to be commercially sensitive. The literatur e 

search also revealed that most of the few articles that discuss water transport costs refer back to 

Kally (1993). Kally’s 1993 book, however, only sketches the cost estimates, referring for details 

back to earlier reports in Hebrew. It does contain a few useful estimates, though, particularly with 

regard to the costs of transferring water from the Nile to Gaza. Our estimates below should be 

treated with great caution, however.

Transporting 100 million cubic metre (MCM) of water per year over a distance of 200 km would 

cost 21.4 ¢/m3. Of this, 4.0 ¢/m3 are for the purchase of Egyptian water, and 5.2 ¢/m3 for lifting 

the water some 100 m. Consequently, it costs 6.1 ¢/m3 per 100 km to transport water. If the 

transfer scheme would be extended to 500 MCM, total costs would fall to 19.8 ¢/m3 and transport 
11

costs to 5.3 ¢/m3 per 100 km. The unit costs of energy and water purchase would not be affected 

by the extension. This suggests a capacity elasticity of transport cost of 0.92, that is, for every 1% 

extension of capacity, total costs increase by 0.92% and unit costs fall by 0.08%.

Kally’s (1993) cost estimates make clear that horizontal distance is not the main driver of water 

transport costs, but the vertical distance is. Kally (1993) implicitly makes this point a number of 

times, but unfortunately does not present cost estimates for alternative lift heights. We therefore 

assume that the costs of pumping water are linear in the height pumped, in line with Kally’s 

assumption on the energy costs of lifting water.

In his discussion of a possible Red Sea - Dead Sea transfer (for hydropower), Kally (1993) 

provides the effects of soil type and transfer mode on costs. The Nile -Gaza transfer is by canal in 

soft but stable soil. If the soil is rocky, transport costs would be 13% higher, and if the soil is 

sandy, costs would be 175% higher. Transporting water by pipe would lead to a cost increase of 

271%, while a tunnel would cost 108% more than a canal.

Gruen (2000) provides estimates of water transport costs from Turkey to Turkish Cyprus. A 78 

km pipeline with a capacity of 75 mln m3 a year would deliver water at 25-34 ¢/m3. According to 

Kally’s data, the horizontal transport alone would cost 16 ¢/m3, while effectively lifting the water 

by 300 m (the sea between Turkey and Cyprus is at least 1000 m deep) would raise the price to 

34 ¢/m3. However, Kally uses an 8% discount rate, while Gruen uses a 4% discount rate; Kally 

reports that investment and operation and maintenance have an equal share in the costs of 

transporting water. Correcting for this, Kally’s data suggest a cost of some 26 ¢/m3. The cost 

estimates of Kally (1993) seem to be consistent with those of Gruen (2000).

Uche et al. (2003) report the costs of transporting water in the National Hydrological Plan of 

Spain. This would involve canals of 900 km long, transporting 1000 mln m3 of water from the 

Ebro to Barcelona and Southern Spain. Uche et al. (2003) estimate that this can be done at some 

36 ¢/m3if a 4% discount rate is taken. Based on Kally’s data, the horizontal transport alone 

would cost at least 52 ¢/m3. Kally’s estimates seem to be on the high side.

Hahnemann (2002) discusses the Central Arizona Project, which brings some 1800 mln m3/yr 

from the Colorado river to amongst others Phoenix and Tucson, a horizontal distance of some 

550 km, and a vertical distance of some 750 m. Kally’s data suggest that this would cost some 74 

¢/m3, but Hahnemann (2002) reports an otherwise unspecified marginal cost of only 5 ¢/m3.

Liu and Zheng (2002) estimate the costs of transferring water of the Yangtze to China’s north. 

They provide most detail about the eastern route, which is in a more advanced stage of planning 

than the middle and western routes. The total amount of water transferred is 32 bln m3/yr, 

although only less than a fifth of that will reach the final destination. The main canal would be 

1150 km long, and the water would need to be pumped 65 m high. Liu and Zheng (2002) 

estimate the costs at 10-16 ¢/m3; using Kally’s estimates, we find this to be 38 ¢/m3. However, 

Liu and Zheng’s estimates only include capital; according to Kally, operation and maintenance 

are of the same order of magnitude as investment costs. Moreover, Liu and Zheng apparently use 

a zero discount rate, and part of the eastern route uses already existing canals. This suggests that 

the costs estimated by Liu and Zheng are in fact slightly above Kally’s estimates.

In sum, the cost estimates of transporting water by Kally (1993) are the most detailed in the open 

literature. Comparing these estimates to those of other studies suggests that Kally may have been 

overly pessimistic. However, most of these studies are ex ante engineering studies of government 
12

projects, which suggests that the actual costs would have been higher. Therefore, we continue to 

use Kally’s estimates.

4. The potential of desalination

Seawater desalination plants are typically located in the coastal area. However, not all the water 

scarce regions are close to the coast, which generate a need to transport water from desalination 

plants to where water is needed. In this study, we calculate the total cost comprising the cost of 

desalination and the cost of transporting desalinated water to the nearest point of distribution. 

Here we estimate only the cost of source water, not the ultimate costs to the end users. The costs 

for different end-uses vary according to the system of distribution, blending and purification. For 

agriculture, the cost is perhaps similar to the cost presented here, but for potable water the cost 

could be increased as much as $0.1/m3 (the cost of additional treatment).

Table 4 contains some sample calculations for the costs of desalinated water in selected waterstressed cities. We assume a transport of 100 MCM/yr. Transport costs are assumed to be 6 ¢ per 

100 km horizontal transport plus 5 ¢ per 100 m vertical transport. Distances and elevations are 

taken from the Times Atlas of the World. The calculations are illustrative only.

The costs of desalination, here assumed to equal 100 ¢/m3, are typically larger than the costs of 

transport. Indeed, one needs to lift the water by 2000 m, or transport it over more than 1600 km 

to get transport costs equal to the desalination costs. Thus, desalinated water is only really 

expensive in place far from the sea, like New Delhi, or in high places, like Mexico City. 

Desalinated water is also expensive in places that are both somewhat far from the sea and 

somewhat high, such as Riyadh and Harare. In other places, the dominant cost is desalination, not 

transport. This leads to relatively low costs in places like Beijing, Bangkok, Zaragoza, Phoenix, 

and, of course, coastal cities like Tripoli.

Table 4. The cost of desalinated water to selected cities

City, country Distance Elevation Transport Desalination Total 

(km) (m) (c/m3) (c/m3) (c/m 3)

Beijing, China 135 100 13 100 113

Delhi, India 1050 500 90 100 190

Bangkok, Thailand 30 100 7 100 107

Riyadh, Saudi Arabia 350 750 60 100 160

Harare, Zimbabwe 430 1500 104 100 204

Crateus, Brazil 240 350 33 100 133

Ramallah, Palestina 40 1000 54 100 154

Sana, Yemen 135 2500 138 100 238

Mexico City, Mexico 225 2500 144 100 244

Zaragoza, Spain 163 500 36 100 136

Phoenix, USA 280 320 34 100 134

Tripoli, Libya 0 0 0 100 100

5. Conclusions and discussions

In energy-rich, arid and water-scarce regions of the world, desalination is already an important 

option. As with all new technologies, progress in desalinating water has been rapid. Whereas it 
13

costed about 9.0 $/m3 to desalinate seawater around 1960, the costs are now around 1.0 $/m3 for 

the MSF process. For RO, the most popular method, the costs have fallen to 0.6 $/m3 for brackish 

water desalination. There is no reason to believe that the trend will not continue in the future. 

However, it should be noted that the costs of desalination still remain higher than other 

alternatives for most regions of the world. 

Transporting water horizontally is relatively cheap whilst the main cost is lifting it up. We find 

that desalinated water could be delivered to Bangkok and Beijing for 1.1 $/m3, to Phoenix for 1.3 

$/m3 and to Zaragoza for 1.4 $/m2. These are probably competitive prices at the moment, and 

they may well fall in the future. However, getting water to New Delhi would cost 1.9 $/m3, to 

Harare 2.0 $/m3, and to Mexico City 2. 4 $/m3. Desalinated water may be a solution for some 

water-stress regions, but not for places that are poor, deep in the interior of a continent, or at high 

elevation. Unfortunately, that includes some of the places with biggest water problems.

It should be noted that desalination processes are accompanied by some negative impacts on the 

environment. The environmental costs associated with desalination – such as production of 

concentrated brine and carbon dioxide emissions – are not considered in the study due to lack of 

data. From the literature, the cost of brine disposal is estimated to be 4-5% of the capital cost for 

a seawater RO plant (Hafez and El-Manharawy, 2002), which is well within the margin of error 

of our data. In the case of inland brine disposal, brine removal costs can be a more significant 

portion of desalination costs (10-25%) depending on the circumstances. Therefore, when

considering options for massive implementation of desalination, environmental impacts will have 

to be internalized and to be minimized by proper planning.

In line with desalination, water reuse and recycling are considered and applied increasingly to 

provide extra usable water. Combining strategies of wastewater reuse and desalination

technology makes it possible to convert wastewater into high quality water that suits various 

users in industry and agriculture. Wherever there is water stress, the improvement of water use 

efficiencies should be considered in the first place, but its marginal costs should not exceed the 

marginal costs of enhancing the water supply through desalination.

The analysis presented here provides a general trend of costs under rough assumptions. The 

selection of most appropriate technology and approach for a particular plant should therefore be 

based on the careful study of site-specific conditions and economics, as well as local needs. The 

cost analysis could be improved by having a more detailed and precise running costs for all the 

desalting plants. For instance, if we know actual energy costs for each plant, the cost estimates 

would be more realistic. This could be done by collecting a relative smaller amount of plants 

with high quality data. It would also be interesting to have information on the costs of delivering 

desalinated water on a geographically explicit basis throughout the world. If we would know the 

costs of water supply from all other sources for a region, we could then evaluate the potential of 

desalination. This would require further study in the field.

Acknowledgements

Financia l support by the Michael Otto Foundation for Environmental Protection is gratefully 

acknowledged. Uwe A. Schneider provided valuable comments for improving the paper. The 

comments and suggestions from two anonymous reviewers are highly appreciated. All errors and 

opinions are ours.
14

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Working Papers

Research Unit Sustainability and Global Change

Hamburg University and Centre for Marine and Atmospheric Science

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Hansen, O. and R.S.J. Tol (2003), A Refined Inglehart Index of Materialism and Postmaterialism, FNU-35

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Heinzow, T. and R.S.J. Tol (2003), Prediction of Crop Yields across four Climate Zones in Germany: An Artificial 

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Yetkiner, I.H. (2003), A Short Note On The Solution Procedure Of Barro And Sala-i-Martin for Restoring Constancy 

Conditions, FNU-24

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Letter ID: 0183 

Commenter: Wendy Jacobs 

Organization: Harvard Law School Environmental Law and Policy Center 

Letter ID: 0183 Comment ID: 25137 Letter Lines: 62 to 91 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2 

Comment: The ELPC’s primary objection to the proposed regulation is that regulation of 

geologic sequestration under the SDWA is too narrow in focus to ensure that 

carbon capture and sequestration ("CCS") fulfills its potential to be "a key 

mitigation technology for achieving domestic [greenhouse gas] emissions 

reductions." 73 Fed. Reg. at 43,496. EPA is proposing to regulate GS by 

creating a new category of injection well ("Class VI") for GS under its existing 

UIC program under the SDWA. As EPA acknowledges, however, its authority under 

the SDWA is limited. See 42 U.S.C. 300h(a)-(b)(1), (d); 73 Fed. Reg. at 43,495. 

Other rules and regulations are needed to address CCS issues falling outside the 

scope of the SDWA (e.g., establishing mechanisms for protecting private drinking 

water supplies, funding costs and damages associated with injury to persons 

and/or water supplies despite compliance with the UIC regulations, accidental 

releases of CO2 to the atmosphere, and compensation for and remediation of harm 

to public health or the environment other than the endangerment of underground 

sources of drinking water ("USDWs")). See infra Part III(c)(1)(b); 73 Fed. Reg. 

at 43,495, 43,497, 43,520, 43,522 (discussing EPA’s view of CCS issues that fall 

outside purview of SDWA). Other issues related to the capture and transport of 

CO2 also need to be considered and addressed. 

Many of these issues are of critical importance and will likely need to be 

addressed before large-scale industry investment in CCS will take place. See, 

e.g., infra Part III(C)(1)(b)(ii) (discussing industry’s need for a clear and 

comprehensive long-term liability scheme). Piecemeal regulation of CCS is 

likely to cause confusion, inefficiency, potentially conflicting requirements or 

policies, and other problems that could be avoided by a comprehensive approach 

to regulation of CCS. Although ELPC and ETIP believe comprehensive regulations 

addressing CCS would more likely ensure that CCS becomes a successful climate 

change mitigation technology, we recognize that Congress may need to enact 

legislation enabling EPA (or another federal agency) to take such a 

comprehensive approach. 

Individual Response: 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 

1
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. 

Letter ID: 0183 Comment ID: 25139 Letter Lines: 93 to 111 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: ELPC and ETIP commend EPA for including precautionary measures for Class VI 

wells above and beyond what is required for other classes of wells. The 

proposed regulation allows the owner or operator the flexibility to choose 

particular cements or metal well components for Class VI wells while still 

requiring that such materials meet or exceed the standards developed by the 

American Petroleum Institute, ASTM International or comparable standards 

acceptable to the Director. 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 

146.86(b)(1)). By doing so, the proposed regulation addresses the potential 

corrosion of cement and metal well components by the CO2 stream (plus water 

impurities) that can compromise the structure of the well and result in leaks of 

stored CO2. ELPC and ETIP laud other precautionary measures required in the 

proposed regulation, including down-hole shut off valves, continuous and 

frequent monitoring of the integrity of the internal and external portions of 

the well, tracking the plume and pressure front, and detailed electronic record 

keeping. Id. at 43,511, 43,538-40 (proposed 40 C.F.R. §§ 146.88-.91). The 

requirements in the proposed regulation reflect EPA’s understanding of and 

sensitivity to the challenges posed by CCS. Because CO2 GS entails new 

technology with a potentially large impact and lasting duration, ELPC and ETIP 

support these precautionary measures. 

Individual Response: EPA acknowledges the comment and agrees that protection of USDWs 

from endangerment and prevention of fluid movement between formations is paramount. 

Appropriately designed and constructed wells are necessary to prevent endangerment to USDWs 

and maintain integrity of the well throughout the lifetime of a GS project. This is the foundation 

of the requirements for construction and pre-operational testing of Class VI wells at §§146.86 

and 146.87. 

2
Please see the remainder of EPA's responses to this comment and the final rule and preamble for 

further details. 

Letter ID: 0183 Comment ID: 25140 Letter Lines: 102 to 107 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: impurities) that can compromise the structure of the well and result in leaks of 

stored CO2. ELPC and ETIP laud other precautionary measures required in the 

proposed regulation, including down-hole shut off valves, continuous and 

frequent monitoring of the integrity of the internal and external portions of 

the well, tracking the plume and pressure front, and detailed electronic record 

keeping. Id. at 43,511, 43,538-40 (proposed 40 C.F.R. §§ 146.88-.91). The 

Individual Response: EPA agrees with commenters on the importance of monitoring at GS 

sites, including continuous monitoring and MITs. EPA emphasizes that monitoring of injection 

activities will be an important component of every GS project. Monitoring (and related reporting 

and recordkeeping) 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. 

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. 

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. EPA 

believes that requiring the installation of automatic surface shut-off devices for onshore wells 

(and affording Director's discretion to require down-hole devices where necessary) ensures that 

proper precautions are taken to prevent subsurface fluid movement and ensure protection of 

USDWs, human health, and the environment. 

Additionally, the GS rule, at §146.88(e)(3), requires the installation of down-hole shut-off 

devices for Class VI wells located in the offshore submerged lands within the jurisdiction of a 

State UIC program. The Agency believes that the unique construction and operational conditions 

for offshore Class VI wells, including isolation from shorelines and the need to construct wells 

through the water column and the subsurface, may delay response time in the event of well 

difficulties. These conditions merit requiring automatic down-hole shut-off devices for offshore 

wells in the submerged lands of a State. 

EPA believes that requiring the installation of automatic surface shut-off devices for onshore 

wells (and affording Director's discretion to require down-hole devices where necessary) ensures 

that proper precautions are taken to prevent subsurface fluid movement and ensure protection of 

USDWs, human health, and the environment. 

3
Letter ID: 0183 Comment ID: 25142 Letter Lines: 184 to 254 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment: II. Ensuring the Long-Term Containment of CO2 at Sequestration Sites 

A. EPA Should Require Owners or Operators to Demonstrate that CO2 Will Be 

Contained for the Long-Term 

The purpose of GS is to store anthropogenic CO2 for the "long term." See 73 

Fed. Reg. at 43,535 (proposed 40 C.F.R. § 146.81) (defining "geologic 

sequestration" as the "long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations"). If-but 

only if-the sequestered CO2 is contained (i.e., not allowed to escape into the 

atmosphere) for a sufficiently long period of time will CCS fulfill its 

potential to be "a key mitigation technology for achieving domestic emissions 

reductions" and "help to mitigate climate change." 73 Fed. Reg. at 43,492, 

43,496. As drafted, however, the proposed regulation fails to tackle the 

question of how long is "long term." 

EPA should provide a sense of the time scales involved and require 

owners/operators to make a reasonable demonstration that the injected CO2 will 

not migrate in such a way that will frustrate the broader climate change related 

goals of GS, lead to human endangerment, or threaten USDWs. 

Despite the fact that long-term containment is critical to the success of a 

climate change mitigation program and to satisfy the public protection mandate 

of the SDWA, EPA’s proposed GS regulation fails to require permit applicants to 

demonstrate that long-term containment will be achieved and maintained. In this 

respect, the proposed rule is less stringent than the requirements for Class I 

hazardous waste injection wells, which require the permit applicant to show to a 

reasonable degree of certainty that no hazardous materials will migrate from the 

injection zone for 10,000 years.[FN3] 40 C.F.R. § 148.20(a)(1)(i). The differences 

between hazardous waste and CO2 suggest that a 10,000 year demonstration may be too 

stringent for GS within Class VI wells, but the existence of a 10,000 year 

demonstration standard for Class I wells confirms that EPA can reasonably impose 

and administer a reasonable demonstration standard for Class VI wells. 

[FN3] In the alternative, the owner or operator may demonstrate that, "[b]efore the 

injected fluids migrate out of the injection zone or to a point of discharge or 

interface with USDW, the fluid will no longer be hazardous because of 

attenuation, transformation, or immobilization of hazardous constituents within 

the injection zone by hydrolysis, chemical interactions or other means . . . ." 

40 C.F.R. §148.20(a)(1)(ii). 

4
In its regulations for GS of CO2, Washington State requires GS permit applicants 

to demonstrate to a high degree of confidence that "substantially ninety-nine 

percent of the greenhouse gases will remain contained for at least one thousand 

years." Wash. Admin. Code §§ 173-218-115(4)(a)(i)(A), 173-407-110 (2008). 

Though Washington’s one thousand year requirement seems consistent with the 

timescales imagined in EPA’s preamble, see 73 Fed. Reg. at 43,496 (total GS 

capacity is expressed as the ability to sequester CO2 emissions for "hundreds, 

if not thousands" of years), no comparable requirement is imposed on a permit 

applicant under EPA’s proposed regulation for Class VI wells (or on the owner or 

operator during the construction, injection, post-site injection care, site 

closure, and post-closure phases of a GS project). See id. at 43,536-37, 

43,537-41 (proposed 40 C.F.R. §§ 146.82-.84, 146.86-.94).[FN4] 

Given the central importance of "long-term" containment to any GS project, EPA 

should add a long-term containment demonstration requirement to the proposed 

regulation. At a minimum, a permit applicant should be required to demonstrate 

long-term containment as a precondition to being issued an injection permit, 

similar to the requirement in the Class I UIC program and Washington State’s GS 

regulation.[FN5] ELPC and ETIP recommend adopting a 1,000 year containment 

standard. 

[FN4] Texas imposes a demonstration requirement similar to Washington State as a 

condition for tax exemptions to encourage GS. Tex. Tax Code Ann. § 202.0545(d) 

(1)(2007) ("The operator’s planned sequestration program will ensure that at 

least 99 percent of the carbon dioxide sequestered . . . will remain sequestered 

for at least 1,000 years."). 

[FN5] EPA also should consider requiring the owner or operator to demonstrate 

long-term containment again as a precondition to granting site closure, and/or 

periodically during various phases of the GS project. 

Individual Response: EPA clarifies that setting a "confinement standard" is outside the scope of 

the Class VI GS rulemaking. However, the Class VI GS rule requires that CO2 injected for GS 

remain confined in the injection zone. Leakage outside of the injection zone/to the surface would 

be a permit violation. The purpose of the Class VI GS rule 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. 

Letter ID: 0183 Comment ID: 25143 Letter Lines: 256 to 309 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: B. EPA Should Impose More Specific Well Plugging Standards 

5
In the preamble, EPA states that the proposed regulation will ensure that 

injection wells are plugged at the end of an injection project so that the wells 

will not serve as conduits for CO2 movement into USDWs. See 73 Fed. Reg. at 

43,499, 43,518. If an improperly plugged well allows CO2 to escape into the 

atmosphere, the climate change mitigation purpose underlying Class VI wells is 

undermined. See id. at 43,492 (discussing how improper well plugging of an 

abandoned oil exploration well allows a geyser of CO2 and water to erupt 

periodically from the well, releasing 12,000 gigatons per year of CO2 into the 

atmosphere). The proposed regulation, however, does not provide enough 

meaningful guidance for owners/operators regarding how to "plug wells in a 

manner that does not endanger USDWs." Id. at 43,518. Owners/operators are 

directed simply to "prepare, maintain, and comply with a [well plugging] plan 

that is acceptable to the Director." Id. at 43,540 (proposed 40 C.F.R. § 

146.92(b)). EPA neglects to specify "the types of materials or tests that must 

be used during well plugging because there are a variety of methods that are 

appropriate and new materials and tests may become available in the future." 

Id. at 43,518. Its general outline for the well plugging plan is intended "to 

give owners or operators flexibility in . . . choos[ing] from available 

materials and tests to carry out the proposed requirements." Id. Allowing 

flexibility is certainly important. It does not, however, preclude EPA from 

providing specific performance requirements, preferred methods, or a nonexhaustive list of approved materials and techniques. 

EPA’s existing regulations for other UIC wells and surface impoundments and 

landfills under the Resource Conservation and Recovery Act, 42 U.S.C. § 6901, 

et. seq., ("RCRA"), provide good models in this regard. The existing 

regulations for Class I, II, and III wells require plugging in a manner to 

"prevent the movement of fluids" into a USDW. 40 C.F.R. 

§ 146.10(a)(1). In addition, the existing regulation lists three accepted 

plugging techniques. 40 C.F.R. § 146.10(a)(2)(i)-(iii)). It builds in 

flexibility by allowing the Director to approve plugging techniques outside of 

the enumerated categories if the technique will "reliably provide a comparable 

level of protection to USDWs." 40 C.F.R. § 146.10(a)(2)(iv); see also 40 C.F.R. 

§§ 264.228(a)(2)(iii)(A)-(E), 264.310(a)(1)-(5) (plugging requirements for 

surface impoundments and landfills, respectively, which include specific targets 

to be met (permeability) as well as general performance goals (minimum 

maintenance and migration)). 

By specifying a baseline of plugging techniques that EPA already knows will work 

for GS, EPA would provide valuable GS-specific guidance to owners/operators (and 

Directors). This may be especially valuable in this early stage of development 

for GS technology as it will give all involved parties a brighter line by which 

to measure compliance. Additionally, existing regulations demonstrate that more 

specificity need not, as EPA suggests in the preamble to the proposed regulation 

6
(73 Fed. Reg. at 43,518), constrain the use of future technologies. The 

proposed regulations can preserve flexibility by vesting the Director with the 

authority to consider and approve new plugging techniques. Accordingly, EPA 

should revise the proposed Class VI UIC program regulation to include a list of 

specific materials and tests that it deems suitable for plugging GS wells, in 

addition to providing the Director with the discretion to approve new techniques 

as they become available, provided they will perform at least as well. 

Individual Response: EPA believes that the required information required to be included in the 

injection well plugging plan, as specified in §146.92(b), provides a framework for acceptable 

well plugging procedures. EPA clarifies that the injection well plugging plan must include the 

following information: (1) appropriate test or measure to determine bottomhole reservoir 

pressure; (2) appropriate testing methods to ensure mechanical integrity as specified in §146.89; 

(3) the type and number of plugs to be used; (4) the placement of each plug including the 

elevation of the top and bottom of each plug; (5) the type and grade and quantity of material to 

be used in plugging (the material must be compatible with the CO2 stream); and (6) the method 

of placement of the plugs. EPA believes that these requirements in conjunction with Agency 

technical guidance provide sufficient information to the owner or operator and the Director to 

allow for the development of a well plugging plan and will help ensure protection of USDWs 

from endangerment. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans required under §146.92 and §146.93. The guidance describes 

recommended approaches for how an owner or operator could plug injection and monitoring 

wells; perform post-injection monitoring; demonstrate non-endangerment; and perform site 

closure activities. The guidance will be available at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0183 Comment ID: 25144 Letter Lines: 311 to 345 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: C. EPA Should Clarify the Site Closure Standard 

EPA is proposing a "combination of fixed timeframe and performance standard" 

approach to site closure. 73 Fed. Reg. at 43,519. Under the proposal, the owner 

or operator would be required to undertake "post-injection site care" following 

the permanent cessation of injection activities at the site, which would include 

"submit[ting] periodic reports providing monitoring results and updated modeling 

results as appropriate until a demonstration of nonendangerment to USDWs can be 

made." Id. at 43,520. Specifically, the owner or operator would need to 

demonstrate "that the carbon dioxide plume and pressure front have stabilized 

7
and that no additional monitoring is needed to assure that the geologic 

sequestration project does not pose an endangerment to USDWs." Id. at 43,541 

(proposed 40 C.F.R. § 146.93(b)(3)). Once the owners or operators provide 

documentation to show that this standard has been met, they can request that the 

Director authorize site closure. Id. at 43,520. By default, the "post-injection 

site care" period would last for 50 years following cessation of injection 

activities; however, the Director would have discretion to shorten the 50-year 

timeframe if the owner or operator could demonstrate "stabilization/no 

endangerment" in less than 50 years, or conversely, to lengthen the timeframe if 

the owner or operator failed to make a demonstration within 50 years. Id. 

As a general matter, ELPC and ETIP agree that a combination of a fixed timeframe 

and a performance standard strikes a good balance and is preferable to relying 

upon only one of those elements. Adherence to an exacting performance standard 

alone, defined before commercial deployment of CCS technologies, could preclude 

owner or operators from taking advantage of best practices as they are 

developed. Adherence to a single fixed timeframe could allow owner or operators 

to abandon well sites even as monitoring data indicates a threat to a USDW. 

Requiring the owner or operator to meet a flexible performance standard 

throughout a baseline period of 50 years would ensure that post-injection site 

care, including monitoring and verification, would continue as long as necessary 

to prevent endangerment of USDWs and require post-injection monitoring and 

modeling even if the data appear to show "stabilization" within a short 

timeframe. This would be especially prudent in the short term, given lack of 

data and experience with large-scale, long-term GS projects. 

Individual Response: EPA agrees and has implemented a combination fixed timeframe and 

performance standard approach for post-injection site care monitoring for Class VI wells. EPA 

believes that a default PISC timeframe of 50 years, with Director's discretion to shorten or 

lengthen this timeframe, combined with a site-specific Director’s discretion to create an 

alternative PISC time frame, ensures that USDWs are protected. The GS 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 sitespecific 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 nonendangerment 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. 

8
Letter ID: 0183 Comment ID: 25145 Letter Lines: 347 to 425 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: EPA should, however, clarify the performance standard element by defining the 

key term "stabilized" in the context of GS.[FN6] See 73 Fed. Reg. at 43,540-41 

(proposed 40 C.F.R. § 146.93(b)(2)). It is unclear whether "stabilized" refers 

to certain measurable physical properties of the "carbon dioxide plume and 

pressure front" (such as pressure), or broadly describes some macro-state (for 

example, no movement of the CO2 over a specified period of time) that EPA is 

using as a proxy for USDW safety, or something else. EPA has promulgated more 

specific closure and post-closure standards for Class I wells and should follow 

suit here to avoid confusion, uncertainty, and potential threats to drinking 

water supplies. 

[FN6] The term "stabilize" is also used in existing regulations governing 

surface impoundments under RCRA. See 40 C.F.R. § 264.228(a)(2)(ii) ("At closure, 

the owner or operator must . . . stabilize remaining wastes to a bearing 

capacity sufficient to support final cover . . . ."). Although the term is not 

defined in those regulations either, those regulations do impose other specific 

requirements on the owner or operator (e.g., cover the surface impoundment with 

a final cover) that are measured in terms of specific factors like migration, 

erosion, maintenance, and permeability. See 40 C.F.R. § 264.228(a)(2)(iii) 

(A)-(E). 

The owner or operator of a Class I hazardous waste injection well must observe 

and record "pressure decay" observations and show conformance to predicted 

values before site closure will be authorized. 40 C.F.R. § 146.71(d). During 

post-closure care, the owner or operator of a Class I well is required to 

continue monitoring "until pressure in the injection zone decays to the point 

that the well’s cone of influence no longer intersects the base of the lowermost 

USDW." 40 C.F.R. § 146.72(b)(2). These standards provide more guidance than 

does the proposed regulation. 

ELPC and ETIP are sensitive to the numerous outstanding technical issues 

surrounding wide-scale use of CCS technologies and the importance of 

demonstration projects to solve many of those questions. Accordingly, while we 

view the EPA’s undefined use of the term "stabilization" as problematic for a 

closure standard, we are not prepared to recommend numerical monitoring targets 

or reach the specificity of the Class I well regulations. Even so, there is 

ample room for the EPA to adopt a stronger and better-defined post-injection 

site care standard that gives greater assurances that USDWs will not be 

threatened while still allowing flexibility for innovation. 

9
The World Resources Institute (WRI) recommendations avoid explicit use of the 

term "stabilization" and instead focus on the endangerment issue. Completion of 

the WRI post-injection monitoring requirements occurs when the owner or operator 

demonstrates "with a high degree of confidence that the storage project does not 

endanger human health or the environment." SARAH M. FORBES ET AL., WORLD 

RESOURCES INSTITUTE, CCS GUIDELINES: GUIDELINES FOR CARBON DIOXIDE 

CAPTURE, 

TRANSPORT, AND STORAGE 103 (2008) [hereinafter WRI GUIDELINES]. WRI suggests 

that an owner or operator can make this demonstration by showing: 

1.the estimated magnitude and extent of the project footprint (CO2 plume and the 

area of elevated pressure), based on measurements and modeling; 

2.that CO2 movement and pressure changes match model predictions; 

3.the estimated location of the detectable CO2 plume based on measurement and 

modeling (measuring magnitude of saturation within the plume or mapping the edge 

of it); 

4.either (a) no evidence of significant leakage of injected or displaced fluids 

into formations outside the confining zone, or (b) the integrity of the 

confining zone; 

5.that, based on the most recent geologic understanding of the site, including 

monitoring data and modeling, the [CO2 plume and formation water] are not 

expected to migrate in the future in a manner that encounters a potential 

leakage pathway; and 

6.that wells at the site are not leaking and have maintained integrity. 

Id. Requirements four, five, and six all address stabilization, but in language 

more precise than the approach offered by EPA. Where EPA leaves open the 

definition of "stabilize," WRI offers a more exacting standard built from terms 

like "leakage," "integrity," and "migrate." The WRI approach provides a 

standard more certain to ensure that non-endangerment is achieved while 

preserving flexibility for owner or operators to develop best practices as CCS 

continues to develop. In addition, WRI’s more specific closure standard is more 

consistent with the models employed in existing EPA regulations for Class I 

wells. See supra pp. 9-10. 

Individual Response: EPA acknowledges that many site-specific factors will influence the 

determination of when the CO2 plume and pressure front no longer pose a risk of endangerment 

to USDWs. It is for this reason that EPA believes that individual UIC Directors, in consultation 

with operators, will be in the best position to determine whether additional post-injection site 

care is needed. EPA expects this decision to be made based on relevant site data and in 

consultation with all potentially impacted parties. 

10
EPA disagrees that the rule should specify the criteria for setting the monitoring timeframe. 

Instead, EPA believes that such determinations are site-specific and should be described in a 

project specific post-injection site care and site closure plan. EPA also believes that periodic 

reviews and updates, where necessary, to the plan are important to ensuring that the site 

continues to be managed effectively and to determine whether shortening the monitoring 

timeframe is appropriate. 

EPA agrees that a complete cessation of plume movement may not occur at some sites for long 

time periods due to density differences, natural formation flow gradients and diffusion. EPA 

clarifies that a complete cessation of plume movement is not required, only a demonstration that 

the plume and pressure front no longer pose a risk of endangerment to USDWs. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate non endangerment; and perform site closure activities. 

The guidance will be available at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0183 Comment ID: 25146 Letter Lines: 427 to 475 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: D. EPA Should Expand the Emergency and Remedial Response Requirements 

The proposed emergency and remedial response provisions are meant to address 

threats to USDWs that may arise during the lifetime of a Class VI well. 73 Fed. 

Reg. at 43,541 (proposed 40 C.F.R. § 146.94(a)). As part of the permitting 

process, the owner or operator is required to submit a remedial response plan 

describing responses "address[ing] movement of the injection or formation fluids 

that may cause an endangerment to a USDW." Id. The plan should cover the 

"construction, operation, closure and post-closure" phases of the GS project.[FN7] 

Id. No additional guidance for the plan’s contents is provided by the proposed 

regulation. 

[FN7] It is unclear whether EPA intended the term "operation" to include the 

post-injection site care period (which precedes site closure). See 73 Fed. Reg. 

at 43,540-41 (proposed 40 C.F.R. § 146.93). EPA should clarify this language 

and require that the emergency and remedial response plan specifically cover the 

post-injection site care period. 

The emergency and remedial response provisions are too narrow in that they fail 

11
to address ways in which GS may endanger USDWs other than "movement of the 

injection or formation fluids." For example, as a result of the CO2 mixing with 

fluid during or after injection, two problems may occur. First, the mixture can 

be highly corrosive, thereby potentially weakening the well and/or the 

containment boundaries and increasing the risk inherent to all Class VI wells 

that injected fluids will migrate outside the containment zone. Second, the 

corrosive liquid can cause metals and minerals present in a specific containment 

zone to leach, migrate, and threaten USDWs. Under the proposed regulation, 

these dangers would not be accounted for in the owner or operator’s emergency 

and remedial response plan. The emergency and remedial response provisions 

should be expanded to address these concerns. 

Further, the draft regulations require the owner or operator to report and 

implement its emergency and remedial response plan only if the "owner or 

operator obtains evidence that the injected carbon dioxide stream and associated 

pressure front may cause an endangerment to a USDW." Id. at 43,541 (proposed 40 

C.F.R. §146.94(b)). As an initial matter, the phrase "obtains evidence" is 

undefined and has no clear meaning within the regulation. ELPC and ETIP 

recommend that EPA clarify the term. Further, like proposed 40 C.F.R. section 

146.94(a), proposed section 146.94(b) is too narrow, for two reasons. First, it 

is unclear why EPA should rely solely on evidence obtained from owners or 

operators. ELPC and ETIP recommend that EPA require that remedial (or at least 

investigatory) responses be triggered by information from third parties in 

addition to owners or operators, including but not limited to sub-surface, 

surface or adjacent property owners, as well as government entities. Second, 

the owner or operator’s duty to report and implement the remedial response plan 

would not be triggered in every instance in which a USDW may be endangered. 

ELPC and ETIP recommend expanding the trigger to include, for example, instances 

where leaching of metals or minerals is detected (by the owner or operator or 

third parties). 

Individual Response: In response to comments on the duration of the emergency and remedial 

response plan, EPA clarifies that the plan will apply over the life of the GS project through the 

post-injection site care period (§146.94(a)). EPA has added a requirement at §146.94(d) that 

owners or operators must review their emergency and remedial response plan within one year of 

an AoR reevaluation required under §146.84 or following significant changes to the facility. 

Subsequently, the owners or operators must submit an amended plan or demonstrate to the 

Director that no amendment to the plan is needed based on the AoR reevaluation or any 

significant changes made to the facility. 

In response to the comment that the rule language should be expanded to require the plan to 

address potential problems that can result when CO2 combines with other fluids during or after 

the injection process, EPA clarifies that emergency and remedial response actions would be 

triggered by any evidence that USDWs are endangered, which would include evidence of 

interactions between CO2 and other fluids that have the potential to affect USDWs. 

12
EPA notes that in developing Class VI requirements, the Agency identified the potential 

corrosivity of CO2 in the presence of water (or other formation fluids) as a unique challenge that 

warranted requirements tailored for GS and has addressed this concern throughout the GS rule. 

EPA requires corrosion monitoring, MIT, and ground water sampling (at §146.90) to provide 

early warning of any potential problem with a GS project that could endanger USDWs. While 

the multiple barriers of protection afforded by other aspects of the regulation should make such 

adverse events unlikely, the purpose of the emergency and remedial response plan is to ensure 

that procedures are in place to address adverse events, including corrosion of the well, as 

expeditiously as possible. 

In response to the recommendation that remedial responses be triggered by information from 

third parties, EPA clarifies that the GS rule requires that if the owner or operator obtains any 

evidence (regardless of the source of that evidence) that USDWs may be endangered, he or she 

must cease injection, take all steps reasonably necessary to identify and characterize any release, 

notify the Director, and implement the approved emergency and remedial response plan 

(§146.94(b)). EPA clarifies that §1421 of SDWA mandates protection of USDWs from 

endangerment due to injection activities; the purpose of the emergency and remedial response 

requirements is to ensure that if other protective measures afforded by the regulations fail, timely 

actions will be taken to address contamination. Failure to respond to any evidence that USDWs 

may be endangered would be considered a violation of the UIC permit and would be subject to 

applicable civil, criminal, or administrative penalties. 

Additionally, EPA is developing guidance on the development and implementation of emergency 

and remedial response plans for GS sites. 

Letter ID: 0183 Comment ID: 25147 Letter Lines: 477 to 673 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: III.Providing Certainty with Respect to Financial Assurance Requirements and 

Short- and Long-Term Liability 

A. Financial Assurance 

The role of financial assurance requirements, generally, is "to ensure that 

owners and operators maintain adequate financial resources to fulfill their 

current and future environmental obligations [and] to minimize the number of 

facilities that are orphaned and abandoned; thereby, reducing the potential that 

these costs will be borne by the public." OFFICE OF WATER, U.S. ENVTL. PROT. 

AGENCY, APPROACHES TO GEOLOGIC SEQUESTRATION SITE STEWARDSHIP 

AFTER SITE CLOSURE 

3 n.2 (July 2008) [hereinafter, "EPA SITE STEWARDSHIP"]. To serve these 

purposes, "[f]inancial responsibility must span the entire life of a project 

(from capture through post-closure stewardship) and must include adequate 

13
assurance that there is sufficient funding to cover the net present value of 

estimated closure . . . and post-closure[.]" WRI GUIDELINES at 58. The adequacy 

of financial assurances is not tested, however, until the owner or operator is 

unable or unwilling to fulfill its obligations at a facility. "The ultimate 

test of whether financial assurances are adequate is an owner’s bankruptcy. If 

an owner declares bankruptcy and the financial assurances are found to be 

inadequate, drinking water sources may be at risk and the public may be required 

to bear the cost of closing a well. Consequently, any uncertainties about the 

adequacy of financial assurances need to be minimized." U.S. GENERAL ACCOUNTING 

OFFICE, GAO-03-761, DEEP INJECTION WELLS: EPA NEEDS TO INVOLVE 

COMMUNITIES 

EARLIER AND ENSURE THAT FINANCIAL ASSURANCE REQUIREMENTS ARE 

ADEQUATE 22 (2003) 

[hereinafter GAO REPORT], cited in 73 Fed. Reg. at 43,521 (discussing financial 

assurances for Class I wells). 

The proposed regulation for GS require owners and operators to make financial 

assurances, but the requirements are so vague that they likely will lead to 

uncertainty, confusion, inconsistent and/or fiscally imprudent practices by the 

states, and other problems. The proposed regulation also does not do enough to 

ensure that the amount of the financial assurances reflects the most current 

cost estimates and includes some margin of error or fund to cover unplanned 

costs. As a result of these failures, drinking water sources (and the broader 

environment) and the public are at risk of finding that financial assurances are 

inadequate to cover actual operational, closure or post-closure costs for a GS 

facility in the event the facility is unwilling or unable to cover such costs. 

EPA should revise the proposed regulation in the various ways described below to 

minimize that risk. 

1.EPA Should Prescribe the Use of Specific Financial Assurance Instruments. 

The proposed regulation establishes that the owner or operator must demonstrate and 

maintain financial assurance: 

The owner or operator must demonstrate and maintain financial responsibility and 

resources for corrective action (that meets the requirements of § 146.84), 

injection well plugging (that meets the requirements of § 146.92), post 

injection site care and site closure (that meets the requirements of § 146.93), 

and emergency and remedial response (that meets the requirements of § 146.94) in 

a manner described by the Director . 

73 Fed. Reg. at 43,537 (proposed 40 CFR § 146.85(a)), but it does not adequately 

inform owners and operators (and state Directors) how to satisfy that duty. EPA 

admits as much, stating in the preamble that for now, it "is proposing that the 

rule only specify a general duty to obtain financial responsibility acceptable 

to the Director," and that it will publish guidance "that describes recommended 

14
types of financial mechanisms that owners or operators can use to meet this 

requirement" at some unspecified future date. Id. at 43,520. 

As discussed below, EPA’s long experience with Class I wells, RCRA, and other 

regulatory frameworks demonstrates that vague financial assurance standards do 

not work. EPA should specify" now, not later, and in the regulation itself"the 

mechanisms by which a well owner or operator may demonstrate financial 

assurance.[FN8] In developing its list of acceptable financial assurance 

mechanisms for GS, EPA should incorporate the recommendations made by the 

General Accounting Office ("GAO") and EPA Office of Inspector General ("OIG") in 

the reports that EPA describes in the preamble (for example, by not allowing 

captive insurance, see p. 22, infra). 73 Fed. Reg. at 43,521-22. Also, EPA 

should make sure to provide detailed guidance, especially regarding the problem 

areas highlighted by GAO and OIG in their reports (for example, regarding cost 

estimation methodology or pay-in period for trust funds). Id. at 43,521. 

[FN8] Merely providing EPA guidance on the subject, as EPA is proposing to do, 

is insufficient given the fact that guidance is not legally binding on EPA. EPA 

is free to follow the guidance or to act at variance with it, depending onthe 

facts of a particular case. See e.g., Memorandum from Victor J. Kimm, Office of 

Drinking Water, U.S. EPA, to Water Division Directors and Water Supply Branch 

Chiefs, Regions I-X, U.S. EPA, 1-2 (May 29, 1985) ("This manual is a guidance 

piece to be used on a case-by-case basis, taking into consideration all relevant 

factors.") (emphasis in original); see also Cement Kiln Recycling Coalition v. 

EPA, 493 F.3d 207, 227 (D.C. Cir. 2007) (holding that a different EPA guidance 

was designed to "have the flexibility to make adjustments for the specific 

conditions" and was non-binding on EPA). EPA should follow the recommendation 

that the states and regions made (in the RCRA context), to address concerns 

about insufficient guidance with respect to financial assurance on a national 

level, by including detailed guidance in the regulations themselves. See OFFICE 

OF INSPECTOR GENERAL, U.S. ENVTL. PROT. AGENCY, REPORT NO. 2005-P-00026, 

CONTINUED EPA LEADERSHIP WILL SUPPORT STATE NEEDS FOR INFORMATION 

AND GUIDANCE 

ON RCRA FINANCIAL ASSISTANCE 2 (2005) [hereinafter OIG REPORT], cited in 73 Fed. 

Reg. at 43,521 ("The States and regions . . . expressed consistent concerns with 

aspects of financial assurance. They believed these concerns would be best 

addressed at the national level by EPA, including a rulemaking process that 

would revise the existing financial assurance regulations [under RCRA]."). 

To minimize uncertainty (and the attendant risk to drinking water supplies and 

the public), EPA must provide as much detailed guidance as possible. It should 

look to existing lists of acceptable financial mechanisms in other EPA programs 

as just a starting point. EPA’s RCRA regulations (40 C.F.R. § 264.143) include 

a list of acceptable financial mechanisms, yet OIG reports that states 

implementing the RCRA regulations have "expressed consistent concerns" regarding 

"insufficient guidance' in a number of important areas, prompting OIG to 

15
recommend that EPA issue additional guidance for its RCRA financial assurance 

mechanisms. OIG REPORT at 3, 9-12. OIG found that a lack of clear guidance led 

states to accept a broad range of financial assurance mechanisms, some of which 

were "not explicitly allowed by Federal regulations" and others that were not 

fiscally prudent. See OIG REPORT at 11. To avoid those same problems in the GS 

context, EPA should provide a list of acceptable financial mechanisms like that 

included in the existing RCRA regulations, but make sure to add more detailed 

guidance to the GS financial assurance provisions. Such guidance should be 

based on "best practices" for each of the acceptable financial mechanisms. OIG 

REPORT at 12. 

Further, time is of the essence. For maximum benefit, EPA should act as soon as 

possible to include detailed guidance on financial assurance in any regulation 

for GS, while large-scale CCS projects are still in the early planning stages 

(or are not yet being planned). "Experience shows that it is often necessary to 

put [financial responsibility] mechanisms in place before [a] project can move 

forward." WORLD RESOURCES INSTITUTE, WORKSHOP SUMMARY: ADDRESSING 

LONG-TERM 

LIABILITY OF CARBON DIOXIDE CAPTURE AND GEOLOGICAL SEQUESTRATION 5 

(2007) 

[hereinafter WRI WORKSHOP SUMMARY]. A clear description of required financial 

mechanisms allows "[p]roject developers, financiers, and insurers . . . to know 

the operational and regulatory requirements up front in order to manage costs 

and risks." Id. at 1. Without a clear description from EPA of which mechanisms will be allowed, 

project owners and operators will have to account for the additional risk that 

their chosen financial mechanism will not be acceptable to the Director. EPA 

should also provide this guidance as soon as possible so that states do not 

create conflicting financial assurance requirements. A lack of clear standards 

creates a potential "race-to-the-bottom" as states compete to set the lowest 

standards for financial assurances in an effort to attract GS projects. See 

ALEXANDRA B. KLASS AND ELIZABETH J. WILSON, CLIMATE CHANGE AND 

CARBON 

SEQUESTRATION: ASSESSING A LIABILITY REGIME FOR LONG-TERM STORAGE 

OF CARBON 

DIOXIDE 30 (2008), available at 

http://works.bepress/com/alexandra_klass/4,_(discussing the presence of the 

"race-to-thebottom" in connection with FutureGen). As financial assurance 

requirements are relaxed, the public loses its assurance "that adequate care and 

funding will be in place to manage storage facilities." WRI WORKSHOP SUMMARY at 

1. With states unsure, industry also would have uncertainty over the fact that 

assurances now accepted by a state Director later may be deemed inadequate under 

more detailed guidance. This uncertainty is especially problematic under market 

conditions, such as today’s, in which financing may be difficult to secure in 

the first place. See Peter S. Goodman, Credit Enters a Lockdown, N.Y. TIMES, 

Sep. 26, 2008, at A1. 

16
EPA’s implementing regulations under the Class I deep injection well program 

provide at least a starting point for EPA to use in compiling the list of 

acceptable financial assurance mechanisms for GS.[FN9] 40 C.F.R. § 144.63 provides 

that "an owner or operator of each facility must establish financial assurance 

for the plugging and abandonment of each existing and new Class I hazardous 

waste injection well" in one of the following ways: (a) establishing a 

"plugging and abandonment trust fund"; (b) "surety bond guaranteeing payment 

into a plugging and abandonment trust fund"; (c) "surety bond guaranteeing 

performance of plugging and abandonment"; (d) "plugging and abandonment letter 

of credit"; (5) "plugging and abandonment insurance"; (6) corporate guarantee of 

plugging and abandonment (after passing a financial test); or (7) a combination 

of "trust funds, surety bonds guaranteeing payment into a trust fund, letters of 

credit, and insurance." These mechanisms are similar to, but more detailed, 

than the Class II mechanisms which EPA suggests it intends to use as a model for 

the financial mechanisms for GS. See 73 Fed. Reg. at 43,521. They are also 

nearly identical to the financial assurance options available under the RCRA 

program. See 40 C.F.R. § 264.143. EPA should use the Class I regulations, as 

opposed to the Class II guidance, as a starting point, eliminate any that are 

not suitable for long-term CO2 containment, and include a list of acceptable 

financial assurance mechanisms in the proposed regulation for GS. 

[FN9] We recommend, however, that EPA only adopt these standards with the GAO 

and OIG’s recommendations in mind. See section III(A)(2) below. 

2. EPA Should Implement OIG’s and GAO’s Recommendations. 

Regardless of whether EPA chooses the Class I, Class II or RCRA program (or a 

combination) as a model when developing the financial assurance requirements for 

GS, EPA should make sure to implement OIG’s and GAO’s recommendations as well. 

See 73 Fed. Reg. at 43,522-23 (discussing OIG’s and GAO’s recommendations for 

EPA’s financial assurance requirements). 

OIG’s and GAO’s criticisms and recommendations are well described in the 

preamble, but then are entirely ignored in the actual regulation. See 73 Fed. 

Reg. at 43,521. Those offices "have raised issues regarding the use of financial 

responsibility instruments applicable to site closure for several EPA programs." 

73 Fed. Reg. at 43,521. The Class I, Class II and RCRA guidance and regulations 

have not been updated to reflect OIG’s and GAO’s recommendations, so many of the 

financial assurance mechanisms criticized by the OIG and GAO are still accepted 

in those programs. Id. According to GAO, those "financial assurance 

requirements may not ensure that adequate resources are available to close a 

commercial deep injection well in the event of bankruptcy or ceased operations." 

GAO REPORT at 1. 

In fact, GAO found that of the four Class I wells which "have gone into 

bankruptcy or ceased operating since the program began in 1980; two did not have 

17
adequate financial resources to plug and abandon wells." Id. Financial assurance 

for the other two wells "was not tested because other companies purchased and 

continued operating the wells." Id. GAO recognized that "it is increasingly 

difficult for owners to meet [existing] financial assurance requirements" for 

injection wells, but cautioned that "failure to do so risks contaminating 

underground drinking water sources." Id. at 21. 

Individual Response: EPA clarifies that the GAO Report and OIG Report have been reviewed 

for purposes of finalizing this rule. 

EPA has also clarified and specified acceptable financial responsibility instruments in the final 

regulation under §146.85(a) of the GS rulemaking. Under the final GS rule, 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. 

These financial responsibility requirements are tailored to the unique nature of the long term GS 

of CO2. 

EPA adds that the financial responsibility requirements under the rule are legally binding: and 

failure to meet the requirements at §146.85 will be considered a violation of the UIC permit and 

subject to applicable civil, criminal, or administrative penalties under SDWA §1423. 

In addition, the final rule includes requirements for updating cost estimates to ensure that 

financial assurance is adequate. Regarding periodic reevaluations and possible revisions to the 

AoR, EPA clarifies that the GS rule, at §146.85(a), requires the Director to evaluate the financial 

responsibility demonstration annually to confirm that the instrument(s) used remain adequate. At 

§146.85(e), the rule states that if the Director determines during the annual evaluation that the 

original demonstration is no longer adequate to cover the cost of activities for which it is 

required, the owner or operator must provide an adjustment to the cost estimate within 60 days. 

In addition, at §146.85(c)(2), the rule requires updating of cost estimates following amendments 

to the AoR and corrective action plan, the injection well plugging plan, the post-injection site 

care and site closure plan, and the emergency and remedial response plan. The same provision 

requires annual updates of the cost estimates for inflation. 

EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) on financial responsibility 

for GS wells that will provide information about the appropriateness of various financial 

instruments. This guidance will include recommendations to help permitting authorities 

determine whether an owner or operator's plan for financial responsibility is adequate. 

18
EPA clarifies that the goal of financial responsibility is to ensure that resources are available to 

prevent endangerment of USDWs from improper plugging, remediation, and management of 

wells in the event that the owner or operator experiences financial difficulties. 

Letter ID: 0183 Comment ID: 25148 Letter Lines: 675 to 716 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: a. EPA Should Pay Special Attention to GAO’s and OIG’s Recommendations for 

Reforming Financial Test and Corporate Guarantee Mechanisms. 

EPA should reform the means for meeting the financial test and corporate 

guarantee in accordance with the recommendations of OIG and the Environmental 

Finance Advisory Board ("EFAB"). EFAB has recommended the use of "independent 

third-party assessment" of a company’s credit ratings. Letter from A. Stanley 

Meiburg, Executive Director, Environmental Finance Advisory Board to Stephen L. 

Johnson, Administrator, U.S. EPA 6 (Jan. 11, 2006). "Using an independent third 

party will relieve [the Director] of the administrative burden of reviewing 

financial statements" as well as alleviate concerns about the Director’s 

"capacity to adequately undertake such review." Id. EPA should also follow OIG’s 

recommendations by making sure that any financial tests are in conformance with 

the generally accepted accounting principles of today. OIG REPORT at 17. 

EPA should indicate that it will review financial test practices on a periodic 

basis to avoid acceptance of a "financial test on a less stringent opinion [from 

a certified public accountant] than those that certify conformance with 

generally accepted accounting principles." Id. at 15. 

EPA states that it is also "considering whether adjustments should be made to 

the absolute net worth threshold of $10 million currently required under the UIC 

regulations." 73 Fed. Reg. at 43,522. EPA notes that other Federal Agencies and 

programs require different measures of net worth. Id. For instance, both Class 

I and RCRA regulations require a showing of "at least six times the sum" of 

covered costs as measured in the current cost estimate. 40 C.F.R. §§ 144.63(f) 

(1)(i)(b); 265.143(e)(1)(i)(b). EPA also cites as an example the Minerals 

Management Service, which "requires a net worth threshold at least 10 times the 

amount of the obligations being assured." 73 Fed. Reg. at 43,522. A study of 

cost estimates for GS suggests that estimates "can be made with confidence" 

given that storage "technologies and equipment" are already being used in the 

oil and gas industries. INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE, IPCC 

SPECIAL 

REPORT ON CARBON DIOXIDE CAPTURE AND STORAGE 345 (2005). Although costs 

may vary 

significantly from project to project due to the "geological characteristics of 

19
the storage formation," the "reservoir depth," the monitoring mechanism, and 

other factors, once these factors are identified, costs estimates can be made 

with some reliance. Id. 

In determining whether either threshold-or another alternative-is appropriate, 

the EPA should consider other factors as well, including a company’s net 

worth/obligations ratio, cash flow, commitments to other projects, and 

percentage of assets that may not be reachable under United States law. 

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 to assist Directors in evaluating the appropriateness of the financial 

test in specific circumstances. EPA's financial responsibility guidance will describe the types of 

financial instruments, including financial tests, that owners or operators can use to meet financial 

responsibility requirements for GS wells. The financial responsibility guidance will include 

considerations for Directors, such as creditworthiness, regarding how to evaluate the 

appropriateness of a specific financial responsibility instrument for a specific project. The 

guidance will also provide recommendations on the minimum tangible net worth an owner or 

operator should demonstrate to qualify for self insurance. The guidance will be available on 

EPA's website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0183 Comment ID: 25149 Letter Lines: 718 to 746 

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment) 

Comment: b. EPA Should Implement the Recommendations Made by OIG and GAO Regarding 

Insurance Mechanisms Before Allowing Their Use by Owners or Operators 

EPA also notes that it "is assessing whether to provide guidance on the use of 

insurance providers" and whether to allow insurance as a financial assurance 

mechanism for GS wells at all. 73 Fed. Reg. at 43,521. Given the lack of 

experience using private commercial insurance for injection wells, EPA should 

develop clear guidelines for its use in this context. The guidance should take 

into account the "numerous problems" with insurance reported by states in the 

RCRA context, "including the difficulty of getting claims paid and lack of State 

awareness of the true coverage provided by the policy." OIG REPORT at 3. 

20
Furthermore, "the lack of standardized language for policies" creates problems 

for Directors in approving the plan. Id. At the very least, EPA should consult 

with insurers currently involved in sequestration and oil and gas injection 

projects in the United States and abroad. This will allow EPA to better 

understand the role of insurance in providing financial assurances and how to 

best manage the use of insurance for this purpose. EPA should include 

representatives from OIG, GAO and EFAB in those consultations. 

If insurance is allowed, EPA should make sure to exclude "captive insurance" 

from the definition of acceptable insurance. GAO defines captive insurance 

companies as "wholly owned subsidiaries of the corporation they are insuring." 

GAO REPORT at 20. This kind of insurance provides the public with "little 

confidence that the captive insurance company will provide the funds to pay for 

closure" if "the parent company experiences financial difficulty." Id. Captive 

insurance leaves "no independence of risk between the corporate parent and the 

company insured." OIG REPORT at 15-16. These policies "are also high risk if 

they cannot be assigned to different owners" if a GS site is sold. GAO REPORT at 

20. 

Individual Response: Under the final GS rule, 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. 

EPA recognizes that there are some concerns about the use of captive insurance, including those 

mentioned by the commenter. Note that under the GS regulation, Directors can choose not to 

allow certain financial instruments if they feel the instruments are too risky or otherwise 

inappropriate to protect USDWs from endangerment. 

The financial responsibility guidance will include considerations for Directors regarding how to 

evaluate the appropriateness of a specific financial responsibility instrument, including captive 

insurance, for a specific project. The guidance will include model forms and templates for 

financial responsibility instruments but will not include standard language for insurance policies. 

The guidance will also address policy exclusions. 

EPA has reviewed OIG and GAO perspectives and is considering all comments in the guidance 

development process, including recommendations made by OIG and GAO. These guidances will 

be available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA clarifies that the Agency will retain self insurance as an option for financial responsibility 

21
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 

credit-worthy, 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. 

Letter ID: 0183 Comment ID: 25150 Letter Lines: 748 to 760 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: c. EPA Should Set a Firm Timeline for Issuing More Detailed Regulations on 

Financial Assurance Mechanisms. 

EPA’s bare promise that it will develop further guidance at some unspecified 

later date runs afoul of the recommendations made by OIG and referenced by the 

proposed regulation. 73 Fed. Reg. at 43,520-21. In 2005, OIG urged the EPA to 

"[d]evelop and communicate EPA’s plan for addressing concerns with the existing 

financial assurance regulations . . . ." OIG REPORT at 17. "The plan should 

include milestones, decision points, and timelines for taking action, and 

indicate when and how EPA will determine if a rulemaking is necessary." Id. 

Although OIG made that recommendation in reference to updating existing 

financial assurance regulations under RCRA, the reasoning underlying the 

recommendation applies equally in this situation. 

Individual Response: EPA agrees that guidance is necessary, which is why EPA is developing 

guidance on financial responsibility for class VI wells that will provide information about the 

appropriateness of various financial instruments. This guidance will consider the 

recommendations in the OIG report and will include recommendations to help permitting 

authorities determine whether an owner or operator's plan for financial responsibility is adequate. 

The guidance, to be issued at the time the final rule is published, is available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

In addition, under the final rule 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 

22
final rule and preamble for further discussion of EPA's final approach to financial responsibility. 

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. 

Letter ID: 0183 Comment ID: 25151 Letter Lines: 762 to 792 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: 3. EPA Should Require Owners or Operators to Re-Demonstrate Financial 

Assurance 

Throughout the Life of the Project. 

The proposed regulation states that the "owner or operator must demonstrate and 

maintain financial responsibility and resources" until the post-injection site 

care period ends and the Director has approved the site closure plan. 73 Fed. 

Reg. at 43,538 (proposed 40 C.F.R. § 146.85(a)) (emphasis added). At certain 

times during the life of the GS project, the owner or operator is required to 

provide to the Director adjustments to the cost estimates upon which the 

financial assurances are based. See 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 

146.85). For example, proposed 40 C.F.R. § 146.85(b) requires the owner or 

operator to "provide to the Director, at a frequency determined by the Director, 

written updates of adjustments to the cost estimate," but only when the owner or 

operator amends a plan (area of review and corrective action plan, injection 

well plugging plan, etc.). Meanwhile, proposed 40 C.F.R. § 146.85(d) requires 

the operator to "provide an adjustment of the cost estimate to the Director if 

the Director has reason to believe that the original demonstration is no longer 

adequate to cover the cost of injection well plugging . . . and post-injection 

site care and site closure[.]" The regulation, however, does not automatically 

require an owner or operator to re-demonstrate financial assurances to reflect 

adjustments in cost estimates. See id. at 43,537 (proposed 40 C.F.R. § 146.85). 

As a result, the financial assurances "maintained" by the owner or operator may 

become outdated over time. Instead, EPA should require that the owner or 

operator re-demonstrate financial assurances on a regular basis (perhaps with 

each adjustment of cost estimates) so that an owner or operator "maintains" 

financial assurance that reflects the most upto-date cost estimate information. 

In the same vein, EPA should require periodic re-demonstration of financial 

assurance to account for inflation. See id. at 43,522 (stating that EPA is still 

"considering" whether to include provisions for annual inflationary 

adjustments).. 

Individual Response: EPA agrees that it is important to periodically update cost estimates that 

support financial responsibility determinations. EPA clarifies that the GS rule, at §146.85(c) 

23
requires the owner or operator to provide periodic adjustments (at least every 5 years) to the cost 

estimate to account for any amendments to the AoR and corrective action plan, the injection well 

plugging plan, the PISC and site closure plan, and the emergency and remedial response plan. 

EPA adds that the Director can also require the owner or operator to provide an adjustment of the 

cost estimate if the Director determines that the original demonstration is no longer adequate, as 

specified at §146.85(e). The owner or operator must also update the cost estimate annually to 

adjust for inflation under §146.85(c)(2). 

Letter ID: 0183 Comment ID: 25152 Letter Lines: 794 to 918 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: 4. The Regulation Fails to Require Financial Assurance for All Contingencies and 

Costs of Protecting Drinking Water Supplies. 

The amount of financial assurance required by the proposed regulation is based 

entirely on the costs estimated by the owner or operator (and accepted by the 

Director) in its plans for corrective action, well plugging, post-injection site 

care, site closure, and emergency and remedial response as defined by the 

regulations. 73 Fed. Reg. at 43,537 (proposed 40 C.F.R. § 146.85(a)). There are 

many reasons why the demonstrated amount could turn out to be inadequate to 

cover actual costs, yet EPA has not addressed financing to cover these 

contingencies. [FN10] For example, the owner or operator may simply 

underestimate costs for the various covered operations, because of lack of 

experience with the new technology, or confusion regarding cost estimation 

techniques, or other reasons. Or, any part of the GS operation may take longer 

than expected and in turn incur more costs. Or, the demonstrated amount was not 

updated to reflect adjusted cost estimates or was not adjusted for inflation. 

Then there is the problem of occurrences or accidents that are completely 

unanticipated and unplanned. In light of the many unknowns associated with 

large-scale GS at this time, it seems prudent to factor in a margin of error to 

the owner or operator’s cost estimates, which would allow for some unplanned 

costs to be covered by financial assurances. To address catastrophic, "breakthe-bank" accidents, however, EPA should consider utilizing a funding mechanism 

based upon the Price-Anderson Nuclear Indemnities Act or other models. 

[FN10] ELPC and ETIP also are concerned that the financial assurance does not 

cover costs not contemplated by the plans or harms caused by the GS activity but 

affecting interests other than public drinking water supplies, such as, for 

example, harms to private drinking water supplies. 

The proposed regulation requires the owner or operator to "provide the Director 

with an emergency and remedial response plan that describes actions to be taken 

to address movement of the injection or formation fluids that may cause an 

endangerment to a USDW." Id. at 43,541 (proposed 40 C.F.R. § 146.94(a)). 

24
Proposed 40 C.F.R. § 146.85 requires the owner or operator to maintain financial 

assurance to cover the emergency plan. However, neither that provision nor 

proposed section 146.94 indicates how the costs should be estimated. 73 Fed. 

Reg. at 43,537, 43,541. Proposed 40 C.F.R. § 146.94 also does not explain how 

the owner, operator or Director will cover the costs of emergencies not 

anticipated by the plan. In fact, since the only emergencies covered are those 

already anticipated by the emergency planning provisions, truly unanticipated 

events are not covered. 

Given the many uncertainties surrounding GS, the prospect that a GS operation 

will proceed, or that a CO2 plume will behave, in a way that is "unplanned" is 

real. See WRI ISSUE BRIEF at 9 ("A need remains for ongoing research and 

analysis into the post-injection risk profile."). Furthermore, EPA notes, "it 

may be difficult to estimate the appropriate amount of funds that may be 

required at either an individual site or collectively at all sites." EPA SITE 

STEWARDSHIP at 25. In light of this, tying the financial assurance requirement 

to the owner or operator’s plans, without providing any margin of error or 

guidance for acceptable models to measure these costs, is risky and 

inappropriate. 

EPA should provide the regulated community and the public with greater assurance 

that project owners/operators will have the financial wherewithal to cover "the 

financial consequences of potential cost overruns" and of "unanticipated 

events." WRI GUIDELINES at 78. The proposed regulations refer to updates of the 

"cost estimates" to reflect changes in costs of well operation, but do not set 

any standards for these estimates. 73 Fed. Reg. at 43,537. The Agency should 

require owners/operators to use rigorous cost estimation techniques to make sure 

that the owner or operator’s estimation of "planned" costs is as accurate as 

possible. "Sound cost estimation requirements ensure that sufficient funds are 

set aside in the financial assurance instrument." Id. at 43,521; see also WRI 

ISSUE BRIEF at 8 ("Understanding . . . the attendant costs associated with 

mitigating each stage of risk [is] essential to assess the utility of, and 

appropriately price, various financial instruments for purposes of financial 

responsibility."). Cost estimates should "be updated annually" and account for 

"inflation." OIG REPORT at 2. EPA should require independent verification of 

all cost estimates as well. See 73 Fed. Reg. at 43,521. 

EPA should also proceed with "allowing separate financial demonstrations to be 

submitted for the plugging of the injection well and for the post-injection site 

care requirements" in order to tie the most up-to-date cost estimation to 

financial assurance for later parts of the GS process. Id. at 43,522. Although 

EPA notes in the preamble that it "may be appropriate to re-demonstrate 

financial responsibility on a periodic basis," to "take into account any 

amendments to the area of review and corrective action plan . . . and 

adjustments for inflation," it has not addressed this sentiment in the proposed 

regulations. Id. at 43,520. EPA should make it explicit that a re-demonstration 

25
of financial responsibility is necessary any time there is a change in cost 

estimates, amendment to the area of review, or change in the corrective action 

plan. EPA also should require periodic re-demonstration of financial assurance 

to account for inflation as it indicates it is considering. 

Here again, EPA can draw upon its experience with cost estimation in the RCRA 

program. Under RCRA regulations, the "closure cost estimate must be based on 

the costs to the owner or operator of hiring a third party to close the 

facility." 40 C.F.R. § 265.142(a)(2). This consideration better approximates 

the true costs to government of continuing post-injection operations. RCRA’s 

model provides enough collateral to cover closure costs should the owner or 

operator become insolvent and the financial assurance mechanism fail to cover 

the true costs of closure. EPA could also adopt the RCRA requirement that the 

estimate equal costs "at the point in the facility’s active life when the extent 

and manner of its operation would make closure the most expensive, as indicated 

by its closure plan," thereby providing a margin of error in financial 

assurances for cost estimates. 40 C.F.R. § 265.142(a)(1). 

Perhaps more importantly, however, unplanned costs that could "break the bank" 

of the owner or operator must be addressed (such as, for example, costs 

associated with a catastrophic accident). See WRI WORKSHOP SUMMARY at 6 

(identifying -‘break the bank’ risks- as one of the key issues that must be 

addressed by a financial assurance scheme for GS). Several commentators have 

suggested addressing such risks through the use of a funding scheme for GS that 

resembles that developed under the Price-Anderson Nuclear Industries Indemnity 

Act of 1957, 42 U.S.C. § 2210, or the National Flood Insurance Act of 1968, 42 

U.S.C. 4001 et. seq. WORLD RESOURCES INSTITUTE, WORKSHOP SUMMARY: 

ADDRESSING 

LONG-TERM LIABILITY OF CARBON DIOXIDE CAPTURE AND GEOLOGICAL 

SEQUESTRATION 5 

(2007), at 6-8; EPA SITE STEWARDSHIP at 13-24 (discussing Price-Anderson and 

National Flood Insurance models, among others); ALEXANDRA B. KLASS & ELIZABETH 

J. WILSON, CLIMATE CHANGE AND CARBON SEQUESTRATION: ASSESSING A 

LIABILITY REGIME 

FOR LONG-TERM STORAGE OF CARBON DIOXIDE 30 (2008), at 38-39, available at 

http://works.bepress/com/alexandra_klass/4. Creation of such a fund would 

provide the means to pay for costs in excess of any covered by financial 

assurance posted under proposed 40 C.F.R. § 146.85. 

The Price-Anderson Act, for instance, makes available a large pool of funds to 

cover public compensation for claims of personal injury and property damage. 

Although each large nuclear plant must obtain "primary financial protection" 

through financial assurance mechanisms similar to those acceptable under the UIC 

and RCRA programs, each company also contributes to a collective fund in order 

to pay for accidents beyond the scope of the financial assurance. 42 U.S.C. § 

2210(a)(1). A similar funding mechanism could be useful in the GS context to 

26
provide an additional source of funding in the event that financial assurance is 

insufficient to meet actual costs, for example in the case of a catastrophic 

incident. 

Individual Response: EPA disagrees that the GS requirements for financial responsibility are 

inadequate. Under the final rule owners or operators must develop cost estimates that accurately 

address the potential costs of adverse impacts associated with the GS project, and demonstrate 

and maintain financial responsibility to address the entire cost of such events. The rule also 

requires that the cost estimates for each phase of the project to be based on the cost of having a 

third party do the work. 

The final rule also includes requirements for updating cost estimates to ensure that financial 

assurance is adequate. At §146.85(c)(2), the rule requires updating of cost estimates following 

amendments to the AoR and corrective action plan, the injection well plugging plan, the postinjection site care and site closure plan, and the emergency and remedial response plan. Note that 

the final rule also requires that the AoR and corrective plan and the emergency and remedial 

response plan be updated at least every five years. The same provision requires annual updates of 

the cost estimates for inflation. 

EPA further clarifies that the final rule requires adjustments to the financial assurance 

demonstration following an adjustment to the cost estimate. The final rule, at §146.85(c)(4), 

requires the owner or operator to increase the face value of the financial instrument or to obtain 

an additional financial responsibility instrument if the most recent cost estimate is above the 

value of the existing financial instruments. 

Additionally, EPA is developing guidance on financial responsibility for Class VI wells. The 

guidance will include a discussion on recommended approaches to estimating costs to assist 

Class VI 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. 

The cost estimation methodology guidance will also contain instructions on how best to adjust 

cost estimates for inflation to help account for the long-term nature of GS. EPA is not requiring 

independent third-party reviews of owner or operator cost estimates. 

Upon Director-approved closure of a Class VI well under §146.93, the owner or operator is 

generally no longer subject to enforcement for regulatory noncompliance and their financial 

instrument will be released if it was not used. However, even if a site closure is approved under 

§146.93, the owner or operator may still be held liable for regulatory noncompliance in a variety 

of circumstances, including endangerment of a USDW or an erroneous approval decision (e.g. 

the Director’s decision relied on erroneous information supplied by owner or operator). Please 

see further clarification on the issue of long-term liability in the preamble of the final GS rule. 

Regarding the suggestion to create a trust fund, EPA clarifies that 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 

27
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. 

Letter ID: 0183 Comment ID: 25153 Letter Lines: 823 to 834 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: The proposed regulation requires the owner or operator to "provide the Director 

with an emergency and remedial response plan that describes actions to be taken 

to address movement of the injection or formation fluids that may cause an 

endangerment to a USDW." Id. at 43,541 (proposed 40 C.F.R. § 146.94(a)). 

Proposed 40 C.F.R. § 146.85 requires the owner or operator to maintain financial 

assurance to cover the emergency plan. However, neither that provision nor 

proposed section 146.94 indicates how the costs should be estimated. 73 Fed. 

Reg. at 43,537, 43,541. Proposed 40 C.F.R. § 146.94 also does not explain how 

the owner, operator or Director will cover the costs of emergencies not 

anticipated by the plan. In fact, since the only emergencies covered are those 

already anticipated by the emergency planning provisions, truly unanticipated 

events are not covered. 

Individual Response: In response to the comment about funding for emergency actions, EPA 

clarifies that §146.85 requires owners or operators to demonstrate and maintain financial 

responsibility for performing any necessary remedial actions associated with the requirements at 

§146.94, including the actions outlined in their GS project-specific emergency and remedial 

response plans. EPA believes the emergency and remedial response plan required under §146.94 

will be a comprehensive plan that should include all possible events. EPA is also developing 

guidance on how to demonstrate financial responsibility. 

Letter ID: 0183 Comment ID: 25154 Letter Lines: 864 to 876 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: EPA should also proceed with "allowing separate financial demonstrations to be 

submitted for the plugging of the injection well and for the post-injection site 

care requirements" in order to tie the most up-to-date cost estimation to 

financial assurance for later parts of the GS process. Id. at 43,522. Although 

EPA notes in the preamble that it "may be appropriate to re-demonstrate 

financial responsibility on a periodic basis," to "take into account any 

amendments to the area of review and corrective action plan . . . and 

adjustments for inflation," it has not addressed this sentiment in the proposed 

regulations. Id. at 43,520. EPA should make it explicit that a re-demonstration 

of financial responsibility is necessary any time there is a change in cost 

estimates, amendment to the area of review, or change in the corrective action 

28
plan. EPA also should require periodic re-demonstration of financial assurance 

to account for inflation as it indicates it is considering. 

Individual Response: EPA agrees with the commenter. The final GS rule, at §146.85(c), 

requires the owner or operator to provide annual updates to the cost estimate to account for any 

amendments to the AoR and corrective action plan, the injection well plugging plan, the PISC 

and site closure plan, and the emergency and remedial response plan. Owners or operators must 

also adjust the estimates for inflation annually under §146.85(c)(2). EPA adds that the Director 

can also require the owner or operator to provide an adjustment of the cost estimate if the 

Director determines that the original demonstration is no longer adequate, as specified at 

§146.85(e). 

In order to assist owners or operators and financial institutions in achieving accurate cost 

estimates for all GS activities, EPA plans to issue financial responsibility guidance that will 

include a discussion of how best to estimate costs, including how to adjust cost estimates for 

inflation to account for the long-term nature of GS projects, in its guidance on meeting financial 

responsibility requirements for Class VI wells. This guidance will be available on EPA's website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0183 Comment ID: 25155 Letter Lines: 920 to 977 

Comment Code: 1300 1.1.2.3 Comments on other aspects of CCS (capture, transport) 

Comment: B. The Proposed Regulation Does Not Cover All Parties Involved in CCS Even 

Though Their Actions Create a Risk of Endangerment to USDWs. 

The proposed regulation applies only to "owners or operators of injection wells 

that will be used to inject CO2 into the subsurface for the purposes of GS." 73 

Fed. Reg. at 43,492; see id. at 43,534 (proposed 40 C.F.R. §144.18). Other 

parties involved in a CCS project, including the CO2 generator, transporter and 

surface and sub-surface property owner(s), are not covered. As EPA notes, 

though, "[t]he SDWA provides EPA with the authority to develop regulations to 

protect USDWs." Id. at 43,495; see also 42 U.S.C. §300h(a)-(b), (d). That 

authority extends over all actors involved in the CCS process (not just the 

injection well owner or operator), at least to the extent their actions may 

contribute to the risk of harm to USDWs.[FN11] 

For instance, EPA has recognized that "co-contaminants in the CO2 stream could 

endanger a USDW if the injectate migrates into a USDW." 73 Fed. Reg. at 43,497. 

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." Id. at 43,503. Yet the proposed regulation’s current 

standard for stream purity is loosely defined. The proposed regulation allows 

injection of a stream with "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." Id. at 43,535 (proposed 40 CFR § 

29
146.81(d) (definition of "carbon dioxide stream")). By regulating CO2 

generators and CO2 stream treatment (purification) facilities directly, EPA 

could reduce the likelihood that a contaminated CO2 stream would be injected 

into a GS well and thereby reduce the likelihood that such contaminants would 

endanger a USDW.[FN12] EPA should therefore consider setting specific requirements 

for the maximum concentrations of "incidental substances" in injected CO2 

streams to reduce the uncertainty about the proper level of treatment required. 

By imposing financial assurance requirements on those parties, EPA could also 

reduce the likelihood that costs and damages arising from such contamination 

would go unpaid, for example, if such costs exceeded the security posted by the 

owner or operator. Regulatory oversight would make these firms "more likely to 

undertake operating decisions that consider environmental (and remediation) 

costs." WRI ISSUE BRIEF at 6. 

[FN11] ELPC agrees, however, that EPA does not have authority under the SDWA to 

address all of the conduct of all of the parties involved in CCS or all of the 

risks posed by CCS, and therefore urges EPA to advocate on behalf of a broader 

mandate from Congress. See discussion at Part III(C)(1)(b). supra. 

[FN12] Note that even such a consideration would fall short of protecting many 

private sources of well-water which could be harmed by CO2 migration. EPA should 

provide for mandatory consultation with owners of private wells before 

permitting any sequestration project in an area with private well use. 

As a matter of equity, parties other than owners and operators should also be 

regulated to "ensure that risks are borne by those who share in the benefit of 

[GS] technologies." Id. at 9. For example, geological sequestration may "allow 

some [generators of CO2] to extend the life of their existing capital investment 

in plant machinery or plant processes." 73 Fed. Reg. at 43,531. Moreover, since 

"it is caps on greenhouse gas emissions that will explicitly establish a price 

for CO2 and will encourage utilities and others to invest in CCS in order to 

meet those caps," it is the generators of the CO2 -along with their 

customers-who may receive credits for sequestration. KLASS AND WILSON at 13. 

All parties who benefit from GS of CO2 should help bear the risks attendant to 

that sequestration. 

Individual Response: EPA clarifies that the Class VI GS rule applies to owners or operators of 

wells that will be used to inject CO2 into the subsurface for the purpose of long-term storage. 

EPA clarifies that regulating CO2 generators and transporters is outside the scope of the Class VI 

GS rulemaking. The Class VI GS rule is designed 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. 

The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent 

CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners 

30
or operators to submit information on the source of the CO2 and its physical and chemical 

properties. Specifically, the GS rule requires the owner or operator to submit data about the site, 

including an analysis of the chemical and physical characteristics of the CO2 stream, as required 

at §146.82(a)(7)(iv), and information on the compatibility of the CO2 stream with fluids in the 

injection zone and minerals in both the injection and the confining zones and the materials used 

to construct the well, per §146.82(c)(3). This information can help the Director determine the 

potential for geochemical reactions between the injectate (CO2) and the host geologic 

formations, which could result in the plugging of pore spaces or the dissolution of formation 

minerals. 

Letter ID: 0183 Comment ID: 25156 Letter Lines: 934 to 955 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: For instance, EPA has recognized that "co-contaminants in the CO2 stream could 

endanger a USDW if the injectate migrates into a USDW." 73 Fed. Reg. at 43,497. 

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." Id. at 43,503. Yet the proposed regulation’s current 

standard for stream purity is loosely defined. The proposed regulation allows 

injection of a stream with "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." Id. at 43,535 (proposed 40 CFR § 

146.81(d) (definition of "carbon dioxide stream")). By regulating CO2 

generators and CO2 stream treatment (purification) facilities directly, EPA 

could reduce the likelihood that a contaminated CO2 stream would be injected 

into a GS well and thereby reduce the likelihood that such contaminants would 

endanger a USDW.[FN12] EPA should therefore consider setting specific requirements 

for the maximum concentrations of "incidental substances" in injected CO2 

streams to reduce the uncertainty about the proper level of treatment required. 

By imposing financial assurance requirements on those parties, EPA could also 

reduce the likelihood that costs and damages arising from such contamination 

would go unpaid, for example, if such costs exceeded the security posted by the 

owner or operator. Regulatory oversight would make these firms "more likely to 

undertake operating decisions that consider environmental (and remediation) 

costs." WRI ISSUE BRIEF at 6. 

Individual Response: EPA clarifies that the financial responsibility requirements in the GS rule 

apply to owners or operators of Class VI wells, and not to the generator of the CO2. The goal of 

financial responsibility is to ensure that financial resources are available to prevent 

endangerment of USDWs from improper plugging, remediation, and management of wells in the 

event that the owner or operator experiences financial difficulties. See the final rule and 

preamble for further discussion of EPA's final approach to financial responsibility. 

31
Furthermore, comments related to the need to regulate CO2 generators and CO2 stream 

treatment facilities are outside the scope of this rulemaking. 

The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent 

CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners 

or operators to submit information on the source of the CO2 and its physical and chemical 

properties. Specifically, the GS rule requires the owner or operator to submit data about the site, 

including an analysis of the chemical and physical characteristics of the CO2 stream, as required 

at §146.82(a)(7)(iv), and information on the compatibility of the CO2 stream with fluids in the 

injection zone and minerals in both the injection and the confining zones and the materials used 

to construct the well, per §146.82(c)(3). This information can help the Director determine the 

potential for geochemical reactions between the injectate (CO2) and the host geologic 

formations, which could result in the plugging of pore spaces or the dissolution of formation 

minerals. 

Letter ID: 0183 Comment ID: 25157 Letter Lines: 979 to 1003 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: C. EPA’s Long-Term Liability Scheme for GS Does Not Adequately Protect the 

Public or Address the Concerns of Industry 

The proposed regulation sets out the following long-term liability scheme for 

GS: (1) owners and operators remain liable for the GS operation and all damages 

arising from it, in perpetuity; however, (2) owner and operators are required to 

post financial security only until the end of the site-care period, and are 

freed from this responsibility at site closure. 

The combination of these two elements, perpetual liability plus limited 

financial assurance, means that: (1) the public is at risk of more orphaned 

sites and uncompensated post-closure costs and damages; and (2) the industry is 

left with liability that is unlimited in scope or time. EPA should minimize the 

risks to the public by requiring owners and operators to post financial security 

and/or contribute to a national fund to cover costs and damages arising from 

post-closure incidents that endanger USDWs and to provide for the costs of postclosure monitoring, measurement, and verification ("MMV"). 

To address the issue of long-term care of GS facilities in a way that would 

balance the public interest in having the private sector pay for CCS with the 

private sector’s interest in removing obstacles to deployment of CCS, a longterm liability scheme for GS that would transfer post-closure site care and MMV 

to the government once closure conditions are met should be developed. EPA 

should seek from Congress the additional authority it would need to establish 

such a scheme. 

Individual Response: Under the final GS rule, once an owner or operator has met all regulatory 

32
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. Furthermore, EPA does not have authority under 

SDWA to create a fund for long term liability of GS sites. See the final rule preamble for further 

discussion of EPA's final approach. 

Letter ID: 0183 Comment ID: 25158 Letter Lines: 1005 to 1042 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: 1. The Problem of Long-Term Care of GS Facilities 

Long-term liability "comprises both anticipated costs associated with the longterm care of a storage facility and the potential for costs associated with 

unanticipated damages." WRI WORKSHOP SUMMARY at 1. EPA has discussed the issue 

of long-term liability for GS in various workshops leading up to the proposed 

regulation and seems to recognize that it is a key issue that must be addressed. 

See 73 Fed. Reg. at 43,500-01 (discussing EPA’s participation in, or hosting of, 

workshops to discuss "key questions and considerations" including long-term 

financial assurance and liability); see also UNITED NATIONS FRAMEWORK CONVENTION 

ON CLIMATE CHANGE ("UNFCCC"), FACT SHEET: INVESTMENT AND FINANCIAL 

FLOWS FOR A 

STRENGTHENED RESPONSE TO CLIMATE CHANGE 1 (2007) (discussing critical factors 

33
for large scale implementation of CCS: developing the technology, managing 

public perception, and deciding upon a long-term liability regime); MARK E. 

FESMIRE ET. AL., NEW MEXICO ENERGY, MINERALS, NATURAL RESOURCES 

DEPARTMENT, 

CARBON DIOXIDE SEQUESTRATION: REPORT ON IDENTIFIED STATUTORY AND 

REGULATORY 

ISSUES 40 (2007). ("The various forms of liability (e.g., economic and 

environmental) inherent in proposed sequestration projects and how they will be 

addressed within a given regulatory framework are perceived as being significant 

factors in making sequestration projects feasible and for attaining public 

acceptance of the technologies, processes and regulations."); WRI WORKSHOP 

SUMMARY at 1 ("Long-term liability is one of the several important challenges 

that CCS faces."). 

Given the indefinite long-term lifespan of GS projects, stakeholders and policy 

makers have struggled with how to establish a framework that balances the 

interests of the private sector (in avoiding perpetual, limitless liability) and 

the public (in being protected against adverse impacts and the risk of 

uncompensated costs and damages). One prominent view among policymakers is that 

a regulatory regime for GS should include a transfer of liability to the public 

at some point in time. ELPC and ETIP favor an approach that would require the 

GS owner/operator to calculate and pay into a fund or otherwise set aside the 

funds needed to cover the costs with (1) MMV or its Class VI wells and (2) 

remediation, corrective action, personal injury, natural resource damages, 

treatment of contaminated drinking water supplies, and the like that, while 

unlikely, are nonetheless possible, and, hence the public sector should not bear 

the entire cost (or risk). EPA’s proposal to regulate GS within a UIC framework 

applies a different long-term liability regime to GS, as discussed below. 

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: 0183 Comment ID: 25159 Letter Lines: 1044 to 1116 

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: 2. EPA’s Proposed Regulation 

34
Under the proposed regulation, "the owner or operator of a GS site is released 

from post-injection site care responsibilities" (including all monitoring or 

reporting responsibilities) upon site closure. 73 Fed. Reg. at 43,535 (proposed 

40 C.F.R. § 146.81(d)) (defining "site closure" as "the point/time, as 

determined by the Director following the requirements under § 146.93, at which 

the owner or operator of a GS site is released from post-injection site care 

responsibilities")). The owner or operator also is released from responsibility 

for posting any financial assurance. 73 Fed. Reg. at 43,522 ("[O]bligation for 

financial responsibility ends for owners or operators after the post-injection 

site care period has ended and the Director has authorized site closure[.]"). 

Thus, once the site is closed, the owner or operator’s only remaining regulatory 

responsibility is to retain its records for a period of three years. See id. at 

43,541 (proposed 40 C.F.R. § 146.93(g)). 

As the EPA notes in the preamble to the proposed regulation, it is assuming that 

post-closure liability will remain with the owner or operator of the site. 73 

Fed. Reg. at 43,522 ("[O]wners or operators may still be held responsible after 

the post-injection site care period has ended . . . . Trust responsibility for 

potential impacts to USDWs remains with the owner or operator indefinitely under 

current SDWA provisions."). Presumably, this would apply to liability for both 

anticipated costs associated with the long-term care of a storage facility and 

the potential for costs associated with unanticipated damages. See 42 U.S.C. § 

300j-8(e) ("Nothing in this section shall restrict any right which any person 

(or class of persons) may have under any statute or common law to seek 

enforcement of any requirement prescribed by or under this subchapter or to seek 

any other relief."). 

There are a number of significant problems with this perpetual-liability-butlimitedfinancial-assurance approach. 

a. The Public Is at Risk 

The limited financial assurance element puts the public at risk. The proposed 

regulation’s failure to require the owner or operator to maintain any financial 

assurance during the post-closure period means that the public has (by 

definition) no assurance that the owner or operator will in fact be able to pay 

the cost of post-closure incidents. The owner or operator may no longer be in 

existence or otherwise unable to pay, leaving the public, the state, or the 

individual victims to bear the uncompensated damages of any migration, leakage, 

or damage that occurs after a site is closed. Given the uncertainties of CCS 

technology at this time and the anticipated indefinite lifetime for GS wells, 

the government must anticipate that some number of post-closure incidents will 

occur, and it must provide the public with assurance that any costs or damages 

arising from them will be paid. 

b. Industry Lacks Certainty 

35
In addition to burdening the public with risks of future costs, the proposed 

regulation’s infinite liability leaves potential owners/operators with much 

uncertainty as to the management of their responsibilities. This uncertainty 

could significantly hamper large-scale industry investment in CCS. EPA is aware 

of this problem, but the proposed regulation does not offer a solution: 

Responsibility for long-term care is often considered an important topic related 

to GS because of cost implications of indefinite responsibility for GS sites. 

Because of the focus of the SDWA on endangerment to USDWs and the absence of 

provisions to allow transfer of liability, stakeholders have expressed interest 

in alternative instruments for addressing financial responsibility after the 

post-injection care period has ended. As a result of the interest in 

alternative instruments, including indemnity programs, EPA has compiled 

information on a variety of alternative instruments not currently available 

under the SDWA. . . . EPA has not determined whether any of the models are 

appropriate for GS wells, however, EPA is aware that these models may contain 

important concepts that may become the model for future strategies for long-term 

care. 

73 Fed. Reg. at 43,522. 

Until those "future strategies" are incorporated into the regulations for GS, 

however, industry is left with indefinite long-term liability (in the proposed 

regulation), which could impede implementation of large-scale GS. 

Individual Response: EPA acknowledges the commenter's need for certainty. The agency is 

working to create a nationally consistent financial responsibility regime for GS within its 

authority under SDWA while providing permitting authorities an appropriate level of flexibility. 

.The SDWA provides EPA the general authority to set minimum federal requirements for 

financial responsibility to ensure that financial resources are available to protect USDWs from 

endangerment throughout the life of the GS project. The final rule requires that an owner or 

operator must conduct monitoring as specified in the Director-approved 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 

36
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 

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. 

EPA clarifies that site closure will not be authorized (and therefore financial responsibility must 

continue) until the owner or operator has demonstrated that the site poses no further risk to 

USDWs. 

Letter ID: 0183 Comment ID: 25160 Letter Lines: 1118 to 1130 

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: 3. EPA Should Extend Its Financial Assurance Requirements Into The Post-Closure 

Period and Transfer MMV Responsibilities to the Government. 

The risk to the public can be addressed by requiring owners/operators to post 

financial security and/or pay into a national fund to cover costs and damages 

arising after site closure. There is no reason why EPA cannot do this using its 

existing authority under the SDWA. As EPA itself states, "[a]lthough the SDWA 

does not have explicit provisions for financial responsibility, as included in 

RCRA, EPA believes that the general authorities provided under the SDWA 

authority to prevent endangerment of USDWs include the authority to set 

standards for financial responsibility to prevent endangerment of USDWs from 

improper . . . management of wells after site closure." 73 Fed. Reg. at 43,520 

37
(emphasis added). 

Individual Response: As described above, EPA notes that 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. Furthermore, EPA does not have authority in the SDWA to 

create a trust fund. The Agency clarifies that the trust funds that are addressed as financial 

responsibility instruments through 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: 0183 Comment ID: 25161 Letter Lines: 1132 to 1194 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: Many commentators have suggested that government should put in place a long-term 

liability scheme which includes the transfer of liability to the public at a 

reasonable point in time and after satisfaction of performance standards. See 

generally WRI WORKSHOP SUMMARY at 6 ("Some participants voiced the opinion that 

the private sector could adequately deal with the risks, but would need the 

public sector to take over the long-term responsibility for monitoring."); MIT, 

THE FUTURE OF COAL: OPTIONS FOR A CARBON-CONSTRAINED WORLD 60 (2008), 

available 

at http://web.mit.edu/coal/The_ Future_ of_Coal.pdf ("The government needs to 

assume liability for the sequestered CO2 once injection operations cease and the 

site is closed. The transfer of liability would be contingent on the site 

meeting a set of regulatory criteria . . . and the operators paying into an 

insurance pool to cover potential damages from any future CO2 leakage."). The 

New Mexico Report summarizes neatly, 

Nearly all of the sequestration literature assumes that long-term liability must 

be transferred to the public sector to maintain economic viability and to 

encourage industry participation. Because the lifespan of sequestration 

projects after closure, which would include continuous [MMV] of the reservoir 

integrity, is contemplated to endure for possibly hundreds to thousands of 

years, the public sector (because of the longevity of public institutions and 

the ease of transferability of institutional knowledge) is seen as the most 

viable entity capable of maintaining these projects over the long term. 

FESMIRE ET AL., supra, at 39. 

ELPC and ETIP agree that transferring liability to the public during the postclosure period is sensible so long as there are effective cost-sharing 

arrangements and other limitations on the financial burden to be borne by the 

public. Notably, the transference of liability is not the only way to monitor 

38
and maintain these projects over the long term. For example, Australia’s 

proposed regulations for off-shore sequestration of CO2 intend that when a site 

is "closed" and the owner or operator vacates the site, post-closure long-term 

monitoring will be carried out by the Commonwealth, the cost of such monitoring 

nevertheless remains the responsibility of the operator, who must post financial 

security for the estimated cost of long-term monitoring and is liable to the 

Commonwealth for actual costs incurred. See Offshore Petroleum Amendment 

(Greenhouse Gas Storage) Bill 2008 § 249CZGAA & Explanatory Memorandum 

Attachment A at 27. 

A regulatory regime for GS in the U.S. too, could incorporate financial 

assurances and/or funding to address the long-term costs of MMV post-closure.[FN13] 

See Jeffrey W. Moore, The Potential Law of On-Shore Geological Sequestration of 

CO2 Captured From Coal-Fired Power Plants, 28 ENERGY L.J. 443, 468 (2007) 

(advocating a site-specific, risk-based approach to GS regulation). 

Additionally, the long-term liability scheme could provide for a national fund 

to address all other costs (e.g., remediation and corrective action), as well as 

damages relating to any incident at any closed GS facility. 

[FN13] The proposed UIC regulations address MMV post-site closure very 

minimally. The ELPC and ETIP believe that given the uncertainties of GS and the 

great discretion which the proposed regulation grants the Director in 

determining when a site no longer poses a risk to USDW, EPA should address longterm, post-closure MMV practices. We accept the scientific assessment that 

sequestered CO2 becomes more stable over time as secondary trapping mechanisms 

engage; however, given that the CO2 is meant to be contained indefinitely, postclosure monitoring and associated costs should be addressed. 

The ELPC and ETIP support the transfer of responsibility not only because it is 

a practical solution to the problems of ensuring long-term care and 

responsibility of GS sites while encouraging sufficient investment, but also 

from a moral standpoint-"philosophically, everyone-not just industry-is 

responsible in part for climate change and should bear some burden for its 

mitigation." FESMIRE ET AL., supra, at 59. 

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: 0183 Comment ID: 25162 Letter Lines: 1196 to 1210 

39
Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: a. EPA’s Need for Additional Authority 

In the preamble to the proposed regulation, EPA notes (probably correctly) that 

it lacks authority under the SDWA to establish a comprehensive long-term 

liability scheme for GS such as the one outlined above. "The SDWA authority . . . does not cover 

transfer of owner or operator financial responsibility to other 

entities [such as a government entity], or creation of a third party financial 

mechanism where EPA is the trustee." 73 Fed. Reg. at 43,520. 

Nonetheless, a comprehensive long-term liability regime for GS, which includes 

an eventual transfer of responsibility to the government and the creation of a 

national fund, would facilitate large-scale implementation of CCS. EPA should 

advocate for the best approach that will not impede GS while giving maximum 

protection to USDWs and the public and, to the extent that EPA lacks authority 

under the SDWA to implement such an approach, it should seek additional 

authority from Congress. 

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: 0183 Comment ID: 25163 Letter Lines: 1212 to 1257 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: b. Long-Term Liability Should Be Addressed at a National Level, Not Left to the 

States 

EPA seems to suggest that because it lacks the authority to transfer liability 

from the owner or operator to the federal government, this piece of the 

liability puzzle could be left to the states to establish (or not). See U.S. 

EPA, PROPOSED UIC REGULATIONS FOR GEOLOGICAL SEQUESTRATION OF 

CARBON DIOXIDE 

FEBRUARY 26-27, 2008 MEETING SUMMARY 6 (2008) (noting that individual states, 

exercising primacy under SDWA, could choose to assume responsibility for GS 

sites after closure, but that the EPA could not require the transfer of 

liability). Leaving it to the states to create appropriate liability and 

financial mechanisms for GS is inadvisable for the reasons stated below. A 

uniform national framework is needed. 

40
First, individual states may not be able to achieve the economies of scale and 

pooling of resources that would make fund measures able to generate adequate 

coverage for CCS. Moreover, the "[t]ransfer of liability and ownership of the 

injected gas to the public sector may pose too great a financial burden, 

especially for a state with a populace of limited means and other significant 

resource-demanding needs (e.g. education, health care)." FESMIRE ET. AL., 

supra, at 59. 

Second, much if not all of the energy industry is composed of companies that 

operate and/or supply energy in multiple states. We could see races to the 

bottom in which states compete with each other to attract CCS investment. 

Indeed, this has already been seen in reaction to the Department of Energy’s 

FutureGen project, where both Texas and Illinois extended indemnification and 

significant tax benefits to CCS projects in order to attract the investment. 

This competition increases the likelihood that state-implemented liability 

assumption and creation of trusts may not be adequate to cover the long-term 

costs of monitoring or future accidents. MOORE, supra, at 463 ("Disparities in 

state UIC programs could also lead to a concentration of [GS] activity in states 

with more lenient regulations . . . ."). 

Third, geological realities mean that some states (i.e., those with suitable 

storage formations) may bear a disproportionate share of the costs and risks of 

geological sequestration relative to those states’ consumption of the 

electricity or other products which generated the CO2. 

Fourth, given the fact that stored CO2 is expected to migrate, in cases where 

the CO2 crosses state boundaries, liability and remediation issues would impact 

more than the single state in which the GS facility (well) is situated. 

For these and other reasons, a national approach to GS regulation of long-term 

liabilities should be taken, which includes the creation of a national fund to 

address costs associated with unexpected damages or remediation measures. 

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. Furthermore, EPA does not have the authority 

under SDWA to create a national fund to address costs associated with unexpected damages or 

remediation associated with Class VI wells. See the final rule preamble for further discussion of 

EPA's final approach. 

41
Letter ID: 0183 Comment ID: 25164 Letter Lines: 1259 to 1386 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: IV. EPA Should Update the Definition of USDW So that All Current and Viable 

Future Drinking Water Supplies are Protected from GS. 

EPA’s definition of what constitutes an "underground source of drinking water" 

("USDW") is critical, because non-USDWs are not protected against potential 

endangerment from GS operations under the proposed regulation.[FN14] EPA’s 

continued use of a 1980 definition for USDWs, however, means that many nowviable sources of drinking water fall outside the technical definition of 

"USDW," leaving valuable water supplies unprotected by the proposed UIC 

regulation. See 73 Fed. Reg. at 43,492, 43,494. EPA should update the definition 

of USDW to reflect the current state and foreseeable further advancement of 

desalination technology. The definition of USDW should meet the statutory goal 

of ensuring that all aquifers that "can reasonably be expected to supply any 

public water system" are protected from potential contamination. See 42 U.S.C. 

§300h (a)-(b), (d)(2). 

[FN14] 40 C.F.R. §144.3 provides: "[U]SDW means an aquifer or its portion: (a) 

(1) Which supplies any public water system; or 

(2) Which contains a sufficient quantity of ground water to supply a public 

water system; and 

(i) Currently supplies drinking water for human consumption; or 

(ii)Contains fewer than 10,000 mg/L total dissolved solids; and 

(b) Which is not an exempted aquifer." 

Thus, the definition also excludes from "USDW" any aquifer that contains fewer 

than 10,000 mg/L TDS but does not contain "a sufficient quantity of groundwater 

to supply a public water system." 

Since 1980, when EPA first promulgated the UIC regulations, "USDW" has been 

defined narrowly to exclude any aquifer with waters containing more than 10,000 

mg/L (also known as 10,000 p.p.m.) total dissolved solids (TDS). See 

Consolidated Permit Regulations and Technical Criteria and Standards; State 

Underground Injection Programs, 45 Fed. Reg. 42,472, 42,502 (June 24, 1980) 

(Final Rule for 40 C.F.R. § 146 and Amendments to § 122; 40 C.F.R. §146.03 

(1980)). This numerical limit is the creation of regulation, not statute: the 

SDWA directed EPA to protect USDWs by publishing regulations for underground 

injection control programs that include "minimum requirements for effective 

programs to prevent underground injection which endangers drinking water 

sources," which the SDWA defined to mean injection which may contaminate any 

"underground water which supplies or can reasonably be expected to supply any 

public water system." See 42 U.S.C. §300h(a)-(b), (d)(2) (emphasis added). 

42
The legislative history supports the position that Congress intended these terms 

to be construed broadly to effectuate Congress’s "overriding intent to maximize 

protection of the public health." In a 1974 report accompanying the SDWA, the 

House Committee on Interstate and Foreign Commerce explained: 

[Section 1421 of the SDWA] . . . defines "underground injection which endangers 

drinking water sources." It is the Committee’s intent that the definition be 

liberally construed so as to effectuate the preventive and public health 

protective purposes of the bill. The Committee seeks to protect not only 

currently-used sources of drinking water, but also potential drinking water 

sources for the future. This may include water sources which presently exceed 

minimum intake water quality requirements or maximum contaminant levels or which 

are not presently accessible for use as a community drinking water supply 

source. 

Thus, for example, the Committee expects the [EPA] Administrator’s regulations 

at least to require States to provide protection for subsurface waters having 

less than 10,000 p.p.m. dissolved solids, as is currently done in Illinois and 

Texas, even though water containing as much as 9,000 p.p.m. would probably 

require treatment prior to human consumption. 

Further contamination of such sources should not be permitted if there is any 

easonable likelihood that these sources will be needed in the future to meet 

the public demand for drinking water and if these sources may be used for such 

purpose in the future. H. R. Rep. No. 93-1185, pt. C, at 32 (1974) (emphasis 

added). 

Thus, the House Committee offered the 10,000 mg/L standard, in 1974, as a 

reference point. Then in 1980, EPA stated that it considered alternative 

proposed concentrations to determine whether any offered "any superior 

justification in terms of current State practice, human health, or technological 

considerations," but found that none did. 45 Fed. Reg. at 42,483. Accordingly, 

"[i]n the absence of any overriding argument to the contrary, the Agency will 

follow the standard in the House Committee Report accompanying the SDWA." Id. 

However, improvements in desalination technology since 1974 and 1980 provide 

"superior justification" for increasing the 10,000 mg/L standard. Water with 

TDS concentrations above 10,000 mg/L is desalinated using Reverse Osmosis (RO) 

or Distillation processes that include multistage flash evaporation (MSF), 

multiple effect distillation (MED), and vapor compression (VC). See YUAN ZHOU & 

RICHARD S.J. TOL, EVALUATING THE COSTS OF DESALINATION AND WATER 

TRANSPORT, 

WATER RESOURCES RESEARCH, VOL. 41, available at http://www.unihamburg.de/Wiss 

/FB/15/Sustainability/wrrdesalt.pdf (discussing the variety of desalting 

technologies). The cost-efficiency of these technologies vary with specific site 

characteristics. Accordingly, the cost per unit depends on size and location of 

43
the desalination plant and is highly linked to the price of electricity. 

"Larger plant capacity reduces the unit cost of water due to economies of scale. 

Lower energy costs and longer plant period reduce unit product water cost." Id. 

The data on desalination costs indicate that per unit cost has decreased since 

the EPA first promulgated the UIC program in 1980. The average cost of 

desalinating high TDS concentrations through RO has fallen from $3.70 per m3 in 

1979 to about $1.33 per m3 in 2001. For the MSF process, the cost has gone down 

from $3.04 m3 in 1979 to $.66 m3 in 2001. As for the ME process, the cost has 

also decreased from $3.56 m3 in 1979 to $1.21 m3 in 2001. Lastly, the average 

unit cost of VC has gone down from $3.72 m3 in 1979 to $1.50 m3 in 2001.[FN15] See 

RESEARCH UNIT SUSTAINABILITY AND GLOBAL CHANGE, HAMBURG 

UNIVERSITY AND CENTRE 

FOR MARINE AND ATMOSPHERIC SCIENCE, available at 

http://www.unihamburg.de/Wiss/FB/15/Sustainability/Models.htm cited in YUAN ZHOU 

& TOL. at 4. 

[FN15] Unit costs are given in terms of 1995 US dollars. See YUAN ZHOU & TOL, 

supra, at 4. 

For EPA to meet SDWA’s goal of ensuring that not only all current, but also all 

reasonably expected, sources of drinking water are protected from GS, EPA must 

update the 10,000 mg/L reference to reflect the "reasonable expectations" of 

today based on the current state and foreseeable further advancement of 

desalination technology.[FN16] 

[FN16] Going forward, EPA should consider revising the definition of USDWs on a 

rolling basis to prevent the TDS standard from becoming outdated and the 

resulting endangerment of viable sources of drinking water by GS. In this way, 

EPA will comply with its Congressional mandate to prevent endangerment of USDWs. 

In addition, ELPC and ETIP note that the proposed regulation excludes from 

protection aquifers and wells that likely would not be sufficient to supply 

water to public water systems [FN17] but that are used as a supply of water for 

smaller, private systems. At a minimum, EPA should require that owners of small 

wells be consulted and included in the planning and permitting process for GS 

wells and that provision be made to provide them with an alternative drinking 

water source if necessary. 

[FN17] "The term ‘public water system’ means a system for the provision to the 

public of piped water for human consumption, if such system has at least fifteen 

service connections or regularly serves at least twenty-five individuals." 42 

U.S.C. § 300F(4). 

Individual Response: EPA recognizes that there is increasing demand for water resources and 

that technology improvements may make high TDS aquifers viable drinking water sources. EPA 

44
believes these potential resources should be considered when injection depth waivers are sought. 

Therefore, the final GS rule at §146.95(b) requires the Director to consider these issues in 

determining whether an injection depth waiver is appropriate. Specifically, the Director must 

consider whether alternative injection sites are available; community needs, demands, and supply 

from drinking water resources; planned needs, potential and/or future use of USDWs and nonUSDWs in the area; and a plan for securing alternative resources or treating USDW formation 

waters in the event of contamination related to the Class VI injection activity. 

EPA is not changing the USDW definition; changing the definition of a USDW is outside the 

scope of the GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required 

under the SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term 

storage. 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: 0183 Comment ID: 25165 Letter Lines: 1388 to 1459 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: V. EPA Should Not Allow, or Should At Least Severely Restrict, Grandfathering of 

Existing Wells. 

Under proposed 40 C.F.R. § 146.81(c), "[i]f the Director determines that USDWs 

will not be endangered," existing Class I and II wells and Class V experimental 

GS wells may be used for large-scale GS under the Class VI regulations but "are 

exempt, at the Director’s discretion, from the casing and cementing requirements 

at [proposed] §§ 146.86(b) and 146.87(a)(1) through (3)." See also 73 Fed. Reg. 

at 43,502 (discussing how the grandfathering proposal "requires that the owner 

or operator make a demonstration that the well will maintain integrity and 

stability in a CO2 rich environment for the life of the GS project"). All wells 

would need to meet all other requirements for Class VI wells, including the area 

of review and site characterization, operating, monitoring, mechanical 

integrity, well plugging, post-injection site care, and site closure 

requirements. Id. 

As EPA points out, "GS projects are anticipated to have long lifespans in 

comparison to other types of deep injection wells. Not only must GS wells be 

able to function safely and properly over the lifespan of the GS project, but 

they must be constructed such that USDWs remain protected after well plugging." 

Id. at 43,510. In terms of construction materials, it appears from EPA’s 

discussion that the selection of the cement and metal well materials is of 

central importance given the potential of the CO2 stream (including water and 

impurities) to corrode cement and metal well components. See id. at 43,509. 

Therefore, proposed 40 C.F.R. § 146.86(b)(1) requires that "[a]ll well materials 

must be compatible with fluids with which the materials may be expected to come 

into contact and meet or exceed standards developed for such materials by the 

45
American Petroleum Institute, ASTM International, or comparable standards 

acceptable to the Director." [T]he owner or operator must provide [the Director] 

the following information [including] Corrosiveness of the carbon dioxide 

stream, and formation fluids; [and] [t]ype or grade of cement ..." Id. at 

43,537-38 (proposed 40 C.F.R. § 146.86(b)(1)). EPA concludes that "[t]he 

quality of the well materials, proper well construction, composition and 

placement of appropriate cement along the wellbore, and appropriate maintenance 

are crucial, because a leaking annulus would be a significant route of escape 

for CO2." Id. at 43,509(emphasis added). 

It is not clear why bypassing the "crucial" safeguards of proposed 40 C.F.R. § 

146.86(b) and 146.87(a)(1) through (3) in favor of the Director’s general 

determination that use of the well would not endanger USDWs is a good idea. See 

73 Fed. Reg. at 43,535 (Proposed 40 C.F.R. § 146.81(c)). The need to 

"grandfather" implies that the existing wells would not necessarily meet EPA’s 

proposed construction standards for Class VI wells.[FN18] To the extent that 

the specific proposed casing and construction requirements for GS wells provide 

assurance beyond "no endangerment of USDWs," that "extra" assurance seems 

appropriate in light of industry’s inexperience with large- scale, long-term GS 

of CO2 and should be preserved. EPA has not articulated any justification for 

why grandfathering is necessary. See 73 Fed. Reg. at 43,502. 

[FN18] The construction requirements for Class I hazardous waste injection wells 

include similar language to the Class VI standards. For example, "[a]ll well 

materials must be compatible with fluids with which the materials may be 

expected to come into contact. A well shall be deemed to have compatibility as 

long as the materials used in the construction of the well meet or exceed 

standards developed for such materials by the American Petroleum Institute, The 

American Society for Testing Materials, or comparable standards acceptable to 

the Director." 40 C.F.R. §146.65(b). However, the Class I well would have been 

evaluated for "compatibility" with respect to the waste that was initially 

injected into the well, which may be less (or more) corrosive than CO2 to the 

particular well materials used to construct the well. Thus, the Class I 

requirements would not necessarily ensure compatibility with CO2. 

If grandfathering is permitted, EPA should limit its availability so as to not 

create an unintended loophole from Class VI construction requirements. EPA 

should require the Director to engage in a rigorous review of the design, 

purpose, and suitability of the original well before allowing grandfathering in 

any particular case. Also, grandfathering should only be allowed (if at all) 

for existing Class I, II or GS Class V wells that are in operation as of the 

final date of adoption of the GS regulations. If a well owner or operator 

anticipates using a well constructed after that date for GS at any point in the 

future, he or she should be required to plan accordingly and use the well 

materials required by the most protective applicable standard. 

46
Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, 

particularly given that the converted well will be used for a substantially different process, which 

involves increased reservoir pressures associated with large volumes of stored CO2 and the 

corrosivity of CO2 in the presence of water. The final GS rule provides for the construction of 

these wells to be grandfathered (per 146.81(c)). EPA has included a requirement in the final GS 

rule that owners or operators seeking to convert existing wells for long term storage must 

demonstrate to the Director that the grandfathered wells were engineered and constructed 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 will be grandfathered under the final GS 

rule; following re-permitting as Class VI wells, these projects are 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: 0183 Comment ID: 25166 Letter Lines: 1461 to 1532 

Comment Code: 4300 2.4.4 Injection Depth 

Comment: VI. EPA Should Rank Sites With GS Capability Based On Their Specific Leakage 

Risk Profiles. 

In the preamble to the proposed regulation, EPA states that it is soliciting 

comment on: 

(1) Whether CO2 injection should be allowed into an injection zone above the 

lowermost USDW, when the Director determines that geologic conditions (e.g., 

thousands of feet of intervening formations between the injection zone and the 

overlying and/or underlying USDWs) exist that will prevent fluid movement into 

adjacent USDWs; and 

(2) Whether aquifer exemptions should be allowed for the purpose of Class VI 

injection, and under what conditions should such aquifer exemptions be approved. 

73 Fed. Reg. at 43,511-12 

EPA suggests that its rationale for allowing the injection of CO2 above the 

lowermost aquifer is to increase the available storage capacity for CO2. See id. 

at 43,512. In other contexts (e.g., for Class I injection wells), however, EPA 

has refrained from compromising USDWs to increase the available storage capacity 

for fluids. The Agency has not presented a case for a departure from that 

general principle here. 

47
The WRI Guidelines avoid explicit use of the terms "exemption" or "injection 

above the lowermost aquifer" and instead propose guidelines for site selection 

and characterization of storage capacity. WRI GUIDELINES at 91. Building on the 

WRI’s guidelines and on further research, the EPA should rank sites with 

geological storage capacity depending on the specific risk profile of CO2 

leakage to lower geological formations and other relevant factors. The WRI 

Guidelines suggest the following "General Guidelines for Site Characterization 

and Selection": 

1. Potential storage reservoirs should be ranked using a set of criteria 

developed to minimize leakage risks. Future work is needed to clarify such 

ranking criteria. 

2. Low-risk sites should be prioritized for early projects. 

3. As required by regulation, storage reservoirs should not be freshwater 

aquifers or potential underground sources of drinking water. 

4. Confining zone(s) should be present that possess characteristics sufficient 

to prevent the injected or displaced fluids from migrating to drinking water 

sources or the surface. 

5. Site-specific data should be collected and used to develop a subsurface 

reservoir model to predict/simulate the injection over the lifetime of the 

storage project and the associated project footprint. These simulations should 

make predictions that can be verified by history-matching within a relatively 

short period of time after initial CO2 injection or upon completion of the first 

round of wells. The reservoir model and simulations should be updated 

periodically as warranted and agreed with regulators. 

6. Saline formations and mature oil and gas fields should be considered for 

initial projects. Other formations, such as coal seams, may prove viable for 

subsequent activity with additional research. 

WRI GUIDELINES at 91. 

According to the WRI Guidelines, EPA would first authorize GS at sites with low 

risk. However, as more GS projects are deployed and the availability of low 

risk sites decreases (eventually, perhaps, to zero), EPA would then determine 

whether to authorize GS at higher-risk sites. In that case, ELPC and ETIP 

suggest that EPA consider conditioning its approval on a demonstration by the 

owner or operator that it is technically feasible to treat groundwater that may 

become contaminated as a result of the GS activity if needed to supply public or 

smaller water systems at a future date. EPA could also require the owner or 

operator to provide financial assurance to cover the costs of such treatment. 

48
Individual Response: EPA disagrees that a ranking of sites is appropriate, or that permitting 

sites on the basis of whether treatment of ground water contamination is feasible. EPA believes 

that requiring appropriate site characterization by the owner or operator, as required under 

§146.82 and providing an appropriate degree of flexibility to the Director to evaluate sitespecific geologic data will afford the greatest protection of USDWs from endangerment. EPA 

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 believes 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, sitespecific 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. It establishes: 1) requirements specifying information that owners 

or operators must submit, and Directors must consider, in consultation with PWSS Directors; 2) 

procedures for public notice of a waiver application and for Director-Regional Administrator 

communication; 3) the waiver issuance process; and, 4) additional requirements that apply to 

owners or operators of Class VI wells granted a waiver of the injection depth requirements to 

ensure USDW protection above and below the injection zone. The final rule also establishes 

limited circumstances under which expansions of the areal extent of aquifer exemptions may be 

granted for owners or operators of Class II EOR/EGR wells transitioning to Class VI injection 

for GS. Additionally, the rule does not categorically preclude or prohibit injection into any type 

of formation. 

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: 0183 Comment ID: 25167 Letter Lines: 1534 to 1583 

Comment Code: 4320 2.4.4.1 Injection beneath the lowermost formation containing a USDW 

Comment: A. CO2 Injection Above The Lowermost USDW 

The proposed regulation prohibits GS above the lowermost USDW. 73 Fed. Reg. at 

43,535 (proposed 40 C.F.R. § 146.5(f)) (defining Class VI wells as "[w]ells used 

for geologic sequestration of carbon dioxide beneath the lowermost formation 

containing an underground source of drinking water (USDW)"). EPA explains in 

the preamble that this safeguard is "a very important protective component of 

the UIC program. Placing distance between the point of injection and USDWs 

allows for the necessary confining and buffer formations, and further provides 

for opportunity for additional monitoring to detect any excursions from the 

intended injection zone." Id. at 43,511. 

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The regulations for Class I hazardous and non-hazardous waste injection wells 

contain a similar prohibition against injection above a lowermost USDW. See id. 

at 43,511; U.S. EPA, CLASS I UNDERGROUND INJECTION CONTROL PROGRAM: 

STUDY OF THE 

RISKS ASSOCIATED WITH CLASS I UNDERGROUND INJECTION WELLS 2 (March 

2001) ("By 

definition, Class I wells inject industrial or municipal wastewater beneath the 

lowermost USDW."). EPA explains that this restriction is one of "multiple 

barriers" to a release of injected fluid into a USDW. Id. at 40. It is unclear, 

however, why lowermost USDWs should be afforded less protection from GS, 

especially in light of the anticipated long life spans of GS projects. 

Given the emerging state of technology associated with GS and the lack of data 

available regarding the likely behavior of injected CO2 over hundreds or 

thousands of years, EPA should at minimum ensure that multiple safeguards are in 

place before USDWs are put at risk. Indeed, EPA itself admits that it currently 

lacks data to demonstrate if injection above or between USDWs is appropriate and 

protective of USDWs. 73 Fed. Reg. at 43,512. Nonetheless, EPA is considering 

giving the Director discretion to allow CO2 injection above the lowermost USDW 

when he or she determines that geologic conditions such as thousands of feet of 

intervening formations between the injection zone and the overlying and/or 

underlying USDWs exist that will prevent fluid movement into adjacent USDWs. Id. 

EPA anticipates that such discretion would allow GS "in specific geologic 

settings where the depth of the USDWs may preclude GS, make GS technically 

challenging, or significantly limit CO2 storage capacity." Id. (suggesting that 

"[a]n example where such injection may be appropriate presents itself in areas 

such as the Williston and Powder River Basins in Wyoming, North Dakota, and 

South Dakota, where receiving formations (formations with large CO2 storage 

capacity) for GS have been identified above the lowermost USDW and where there 

may be thousands of feet of rock strata between the injection zone and the 

overlying and underlying USDWs"). 

Before allowing such injections, EPA should first carry out further research and 

rank sites with geological storage capacity according to specific factors such 

as risk of leakage of impure streams of CO2 to lowermost geological formations, 

distance between the injection zone and the lowermost USDW, composition of the 

rock strata that will prevent contamination of underground reservoirs, and the 

specific characteristics of the aquifer such as the quantity of water and the 

depth of the aquifer. 

Individual Response: As described above, EPA disagrees that a ranking of sites is appropriate, 

and believes that decisions regarding the suitability of a proposed site should be made based on 

site-specific data. 

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EPA agrees that protecting USDWs from endangerment must be a top priority. The Agency 

believes 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. 

EPA believes that the requirements at §146.95 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: 0183 Comment ID: 25168 Letter Lines: 1585 to 1627 

Comment Code: 4470 2.4.4.4.2 Comments opposing aquifer exemptions in all cases 

Comment: B. Exempting USDWs for the Purpose of GS 

Under current UIC Program regulations, the Director has the discretion to exempt 

USDWs pursuant to 40 C.F.R. § 146.4 when the following conditions are met: 

a) [the USDW] does not currently serve as a source of drinking water; and 

b) It cannot now and will not in the future serve as a source of drinking water 

because: 

(1) It is mineral, hydrocarbon or geothermal energy producing, or can be 

demonstrated by a permit applicant as part of a permit application for a Class 

II or III operation to contain minerals or hydrocarbons that considering their 

quantity and location are expected to be commercially producible. 

(2) It is situated at a depth or location which makes recovery of water for 

drinking water purposes economically or technologically impractical; 

(3) It is so contaminated that it would be economically or technologically 

impractical to render that water fit for human consumption; or 

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(4) It is located over a Class III well mining area subject to subsidence or 

catastrophic collapse; or 

(c) The total dissolved solids content of the ground water is more than 3,000 

and less than 10,000 mg/l and it is not reasonably expected to supply a public 

water system. 

40 C.F.R. § 146.4. 

Once a USDW is exempted, it is no longer afforded protection as a USDW, now or 

in the future. See 73 Fed. Reg. at 43,512; 40 C.F.R. §144.7(b)(1). 

Allowing exemptions of USDWs for the purpose of GS is premature. By definition, 

a (non-exempted) USDW is a source that has less than 10,000 mg/L total dissolved 

solids, the level that EPA already has determined "can reasonably be expected to 

supply any public water system." 42 U.S.C. §300 (h)(d)(2). Thus, given the 

expected increase in demand for water resources and the available technology, it 

does not make sense to allow current or potential USDWs as GS reservoirs until 

it is either cost effective to secure water for human consumption from other 

sources or lower risk GS sites are no longer available. 

Individual Response: EPA believes that there are limited circumstances where aquifer 

exemptions for GS may be warranted, and the final GS 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. 

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. 

The Agency developed the waiver process to address comments and concerns about current and 

future drinking water resources and the use of climate mitigation technology at appropriate sites. 

The aquifer exemption requirements in the final rule provide flexibility and afford owners or 

operators an opportunity to assess and select a suitable GS site while also preserving USDWs 

(i.e., formations/aquifers afforded SDWA protection). 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. EPA agrees with the commenter's 

concerns about USDW preservation and protection and believes that, in most cases, the injection 

depth waiver is a more appropriate option than aquifer exemptions for Class VI injection, and 

that aquifer exemption expansions for GS should be granted in limited circumstances. 

52
EPA agrees that future water resources needs are an important consideration, and believes that 

the injection depth waiver process at §146.95 responds to concerns about future drinking water 

resource availability and the need to ensure high quality water remains available in sufficient 

quantities to supply drinking water supply needs. 

For additional information on the waiver approach and 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: 0183 Comment ID: 25169 Letter Lines: 1629 to 1640 

Comment Code: 1260 1.1.1.5 More certainty/stringency is needed 

Comment Code: 1420 1.2.1.1 Support the GS rulemaking 

Comment: VII. Conclusion 

ELPC and ETIP support many portions of the EPA's proposed regulations and 

commend the EPA for implementing safeguards for GS that go beyond those required 

for other classes of injection wells. For example, we are pleased to see that 

EPA has provided flexibility in the choice of construction materials used by 

well owners while preserving rigorous construction standards. Our primary 

objection to the regulations, however, is that they constitute a piecemeal 

approach to regulation ofGS (and CCS), thus leaving several issues unaccounted 

for. The lack of certainty on issues of liability, financial assurance, and 

well-closure standards, could both stifle the use ofGS as a climate change 

mitigation tool and place the public at greater risk. 

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 recognizes that liability is an important issue to owners or operators; however the Agency 

does 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. EPA 

notes that the final rule clarifies the requirements for the use of financial responsibility 

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54

instruments for GS. In addition, the final rule requires owners or operators to address well 

plugging in well plugging plans submitted with the Class VI permit application. EPA is 

developing guidance manuals for owners or operators that describe the financial responsibility 

and injection well plugging requirements in the GS rule.