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

E NVIRONMENTAL 

### L AW 

### & P OLICY 

### C LINIC

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 Environmen tal 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 sequestrati on of carbon dioxide in geologic formations

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

Control (“UIC”) Program for Carbon Dioxide (“CO 2 ”) 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 “propos ed 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 Clin ical 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 En vironmental Law & Policy Clinic

The ELPC’s primary objection to the proposed re gulation is that regu lation 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 inject ion well (“Class VI”) for GS under its existing

UIC program under the SDWA. As EPA acknowledge s, however, its aut hority under the SDWA

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

are needed to address CCS issues fa lling 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 CO 2 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 fa ll outside purview of SD WA). Other issues

related to the capture and transport of CO 2 also need to be considered and addressed.

Many of these issues are of critical importa nce 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 industr y’s need for a clear and comp rehensive long-term liability

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

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

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

comprehensive regulations addressing CCS w ould 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 agen cy) to take such a comprehensive approach.

Page 2 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

ELPC and ETIP commend EPA for including pre cautionary measures for Class VI wells

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

the owner or operator the flexibility to choose pa rticular 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 th e potential corrosion of cement and metal well components by

the CO 2 stream (plus water impurities) that can compro mise the structure of the well and result in

leaks of stored CO 2 . ELPC and ETIP laud other precauti onary measures required in the

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

the integrity of the internal and external porti ons of the well, tracking the plume and pressure

front, and detailed elect ronic 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 CO 2 GS entails new technology with a

potentially large impact and lasting dura tion, ELPC and ETIP support these precautionary

measures.

With the reservation that comprehensive re gulations would be preferable to partial

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

regulation.

I. Summary of Comments

I. Summary of Comments

II. Ensuring Long-Term Containment of CO 2 at Sequestration Sites A. EPA Should Require Owners or Op erators to Demonstrate that CO 2 Will Be Contained for the Long-Term B. EPA Should Impose More Sp ecific Well Plugging Standards C. EPA Should Clarify the Site Closure Standard D. EPA Should Expand the Emergency and Remedial Response Requirements

Page 3 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

III. Providing Certainty with Respect to Financ ial 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 Mechan isms 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 Op erators 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 Protec ting Drinking Water Supplies. B. The Proposed Regulation Does Not C over 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 Assu rance Requirements into the PostClosure Period and Transfer MMV Re sponsibilities 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 Capab ility Based On Their Specific Leakage Risk
Profiles.
A. CO 2 Injection above the Lowermost USDW B. Exempting USDWs for the Purpose of GS

VII.Conclusion

Page 4 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

II. Ensuring the Long-Term Containment of CO 2 at Sequestration Sites

A. EPA Should Require Owners or Operators to Demonstrate that CO 2 Will Be Contained for the Long-Term

The purpose of GS is to store anthropogenic CO 2 for the “long term.” See 73 Fed. Reg.

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

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

formations”). If—but onl y if—the sequestered CO 2 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 emi ssions 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 demonstra tion that the injected CO 2 will not migrate in such a way that will

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

threaten USDWs.

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

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

GS regulation fails to require pe rmit applicants to demonstrate th at 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 injectio n 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 demonstrat e 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 immobiliz ation of hazardous constitu ents within the injection zone by hydrolysis,
chemical interactions or other means . . . .” 40 C.F.R. §148.20(a)(1)(ii).

Page 5 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

hazardous waste and CO 2 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 sta ndard for Class I wells

confirms that EPA can reasonably impose and ad minister a reasonable demonstration standard

for Class VI wells.

In its regulations for GS of CO 2 , 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 expres sed as the ability to sequester CO 2 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 re quirement to the proposed regulation. At a

minimum, a permit applicant should be require d 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 se questered . . . will remain sequestered for at least 1,000 years.”).

5 EPA also should consider requiring the owner or oper ator to demonstrate long-term containment again as a precondition to granting site closure, and/or pe riodically during various phases of the GS project. Page 6 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

B. EPA Should Impose More Specifi c Well Plugging Standards

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

are plugged at the end of an in jection project so that the wells will not serve as conduits for CO 2

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

allows CO 2 to escape into the atmosphere, the climate change mitigation purpose underlying

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

abandoned oil exploration well allows a geyser of CO 2 and water to erupt pe riodically from the

well, releasing 12,000 gigatons per year of CO 2 into the atmosphere). The proposed regulation,

however, does not provide enough meaningful guida nce 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 comp ly 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 plug ging plan is intended “to give owners or

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

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

EPA from providing specific perf ormance 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 regar d. The existing regulations for Cl ass I, II, and III wells require

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

Page 7 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

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

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

a comparable level of prot ection 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 incl ude specific targets to be met (permeability)

as well as general performance goals (min imum maintenance and migration)).

By specifying a baseline of plugging techni ques 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 partie s a brighter line by which to measur e compliance. Additionally, existing

regulations demonstrate that more specificity ne ed 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 pluggi ng techniques. Accordingly, EPA should revise the proposed

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

suitable for plugging GS wells, in addition to pr oviding 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 un dertake “post-injection site care” following the permanent cessation of

injection activities at the s ite, which would include “submit[ti ng] periodic reports providing

monitoring results and updated modeling result s as appropriate until a demonstration of nonPage 8 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental 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 dioxid e 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 ce ssation of injection ac tivities; however, the

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

demonstrate “stabilization/no enda ngerment” 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 relyi ng upon only one of those

elements. Adherence to an ex acting performance standard alon e, defined before commercial

deployment of CCS technologies, co uld preclude owner or operat ors from taking advantage of

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

or operators to abandon well site s even as monitoring data indi cates a threat to a USDW.

Requiring the owner or operator to meet a flex ible performance standa rd throughout a baseline

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

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

require post-injection monitoring a nd modeling even if the data a ppear to show “stabilization”

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

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

Page 9 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

EPA should, however, clarify the performance st andard 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 “stabili zed” refers to certain measurable physical

properties of the “carbon dioxide plume and pre ssure front” (such as pr essure), or broadly

describes some macro-state (for example, no movement of the CO 2 over a specified period of

time) that EPA is using as a proxy for USDW sa fety, 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” observa tions 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 in fluence 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 r each the specificity of the Cla ss I well regulations. Even so,

there is ample room for the EPA to adopt a stro nger 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 re quirements on the owner or operator (e.g., cover the surface impoundment with a final cover) that are measured in terms of sp ecific factors like migration, erosion, maintenance, and permeability. See 40 C.F.R. § 264.228( a)(2)(iii)(A)-(E). Page 10 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

standard that gives greater assurances that US DWs 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 enda ngerment issue. Completion of the WRI postinjection monitoring requirements occurs when the owner or operator de monstrates “with a high

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

environment.” S ARAH M. F ORBES ET AL

., W ORLD R ESOURCES I NSTITUTE

, CCS G UIDELINES :

G UIDELINES FOR C ARBON D IOXIDE C APTURE

, T RANSPORT

, AND S TORAGE 103 (2008) [hereinafter

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

showing:

1. the estimated magnitude and exte nt of the project footprint (CO 2 plume and the area of elev ated pressure), based on measurements and modeling;

2. that CO 2 movement and pressure changes match model predictions;

3. the estimated location of the detectable CO 2 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 [CO 2 plume and formation water] are not expe cted to migrate in the future in a manner that encounters a pot ential leakage pathway; and

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

Id. Requirements four, five, and si x 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 “lea kage,” “integrity,” and “migrate.” The WRI

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

Page 11 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental 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 respons e 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 desc ribing responses “address[ ing] movement of the

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

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

.

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

The emergency and remedial response provisi ons 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 CO 2 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 boundari es and increasing the ri sk inherent to all

Class VI wells that injected fluids will migr ate 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 pr oposed regulation, these dangers would not be

accounted for in the owner or operator’s emergenc y 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. Page 12 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

emergency and remedial response plan only if the “owner or operator obtai ns 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 clea r meaning within the regulation. ELPC and ETIP

recommend that EPA clarify the term. Furthe r, 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 owne rs or operators, incl uding 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 trigge red in every instance

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

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

operator or third parties).

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

A. Financial Assurance

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

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

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

reducing the potential that these costs will be borne by the public.” O FFICE OF W ATER

, U.S.

E NVTL

. P ROT

. A GENCY

, A PPROACHES TO G EOLOGIC S EQUESTRATION S ITE S TEWARDSHIP A FTER

S ITE C LOSURE 3 n.2 (July 2008) [hereinafter, “EPA S ITE S TEWARDSHIP ”]. To serve these

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

Page 13 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

cover the net present value of estimat ed closure . . . and post-closure[.] ” WRI G UIDELINES at 58.

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

or unwilling to fulfill its obligati ons at a facility. “The ultima te test of whether financial

assurances are adequate is an owner’s bankrupt cy. 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 clos ing a well. Consequentl y, any uncertainties about

the adequacy of financial assuran ces need to be minimized.” U.S. G ENERAL A CCOUNTING

O FFICE

, GAO-03-761, D EEP I NJECTION W ELLS : EPA N EEDS TO I NVOLVE C OMMUNITIES E ARLIER

AND E NSURE THAT F INANCIAL A SSURANCE R EQUIREMENTS A RE A DEQUATE 22 (2003)

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

Class I wells).

The proposed regulation for GS require ow ners and operators to make financial

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

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

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

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

costs. As a result of these failures, drinking wa ter 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 propos ed regulation in the various ways described

below to minimize that risk.

Page 14 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

1. EPA Should Prescribe the Use of Specific Financial Assurance
Instruments.

The proposed regulation establishes that th e 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), injecti on 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 requirement s 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 Dire ctor,” 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 dem onstrate 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 w ith respect to financial assurance on a national level, by including detailed guidance in the regulations themselves. See O FFICE OF I NSPECTOR G ENERAL

, U.S. E NVTL

. P ROT

. A GENCY

, R EPORT N O

. 2005-P-00026, C ONTINUED EPA L EADERSHIP W ILL S UPPORT S TATE N EEDS FOR I NFORMATION AND G UIDANCE ON RCRA F INANCIAL A SSISTANCE 2 (2005) [hereinafter OIG R EPORT ],
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].”). Page 15 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

not

r trust funds). Id . at 43,521. acceptable financial assurance mechanisms for GS, EPA should incorporate the

recommendations made by the General A ccounting 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, re garding 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 guidan ce as possible. It shou ld look to existing lists

of acceptable financial mechanisms in othe r 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 impl ementing the RCRA regulations have “expressed

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

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

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

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

“not explicitly allowed by Federal regulations” a nd others that were no t fiscally prudent.

See OIG R EPORT 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 existi ng RCRA regulations, but

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

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

mechanisms. OIG R EPORT at 12.

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

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

Page 16 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

“Experience shows that it is of ten necessary to put [financial re sponsibility] mechanisms in place

before [a] project can move forward.” W ORLD R ESOURCES I NSTITUTE

, W ORKSHOP S UMMARY :

A DDRESSING L ONG -T ERM L IABILITY OF C ARBON D IOXIDE C APTURE AND G EOLOGICAL

S EQUESTRATION 5 (2007) [hereinafter WRI W ORKSHOP S UMMARY ]. A clear description of

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

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

1

. Without a clear description from EPA of whic h mechanisms will be allowed, project owners

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

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

so that states do not create c onflicting financial assurance re quirements. 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 e ffort to attract GS projects. See A LEXANDRA B. K LASS AND

E LIZABETH J. W ILSON

, C LIMATE C HANGE AND C ARBON S EQUESTRATION : A SSESSING A L IABILITY

R EGIME FOR L ONG -T ERM S TORAGE OF C ARBON D IOXIDE 30 (2008), available at

http://works.bepress/com/alexa ndra_klass/4,_(discussi ng the presence of the “race-to-thebottom” in connection with FutureGen). As fi nancial assurance requirements are relaxed, the

public loses its assurance “that adequate care a nd funding will be in pl ace to manage storage

facilities.” WRI W ORKSHOP S UMMARY at 1. With states unsure, industry also would have

uncertainty over the fact that assurances now acc epted 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 fi nancing may be difficult to secure in the first

place. See Peter S. Goodman, Credit Enters a Lockdown , N.Y. T IMES

, Sep. 26, 2008, at A1.

Page 17 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

least a starting point for EPA to use in compili ng 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 pl ugging and abandonment of each existing and new

Class I hazardous waste injecti on well” in one of the followi ng ways: (a) establishing a

“plugging and abandonment trust fund”; (b) “sur ety 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 guarant ee of plugging and abandonment (aft er passing a financial test);

or (7) a combination of “trust funds, surety bonds guaranteeing pa yment 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 id entical 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 Cla ss II guidance, as a starting poi nt, eliminate any that are not

suitable for long-term CO 2 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 Cl ass I, Class II or RCRA program (or a

combination) as a model when developing th e 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. Page 18 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

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

“have raised issues regarding th e use of financial res ponsibility 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 update d 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 “financi al 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 R EPORT 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 adequa te financial resources

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

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

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

for injection wells, but cautioned that “failure to do so risks contamin ating 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 a nd 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. Stan ley Meiburg, Executive Di rector, Environmental

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

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

Page 19 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

reviewing financial statements” as well as allevi ate concerns about the Di rector’s “capacity to

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

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

principles of today. OIG R EPORT at 17.

EPA should indicate that it will review financia l test practices on a pe riodic basis to avoid

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

than those that certify conformance w ith 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 cu rrently required under th e UIC regulations.”

73 Fed. Reg. at 43,522. EPA notes that other Federa l 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 cost s 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 ti mes the amount of the

obligations being assured.” 73 Fed. Reg. at 43,5 22. 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 th e oil and gas industries. I NTERGOVERNMENTAL P ANEL ON C LIMATE

C HANGE

, IPCC S PECIAL R EPORT ON C ARBON D IOXIDE C APTURE AND S TORAGE 345 (2005).

Although costs may vary significantly from pr oject 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, cost s estimates can be made with some reliance.

Id.

In determining whether eith er threshold—or another alte rnative—is appropriate, the

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

Page 20 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

cash flow, commitments to other projects, and per centage 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 whethe r 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 e xperience using private commercial insurance for

injection wells, EPA should devel op 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 cl aims paid and lack of State awareness of the

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

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

.

At the very least, EPA should consult with insu rers 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 shoul d 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 corporat ion they are insuring.” GAO R EPORT 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 be tween the corporate parent and the company

Page 21 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

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

c. EPA Should Set a Firm Timelin e for Issuing More Detailed Regulations on Financial Assurance Mechanisms.

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

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

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

plan for addressing concerns with the existing financial a ssurance regulations . . . .”

OIG R EPORT at 17. “The plan should include mileston es, 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 refere nce to updating existing financial assurance

regulations under RCRA, the reas oning underlying the recommendati on applies equally in this

situation.

3. EPA Should Require Owners or Operato rs to Re-Demonstrate Financial Assurance Throughout the Life of the Project.

The proposed regulation states that the “o wner 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 pl an. 73 Fed. Reg. at 43,538 (proposed 40 C.F.R.

§ 146.85(a)) (emphasis added). At ce rtain 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 (propos ed 40 C.F.R. § 146.85).

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

Director, at a frequency determin ed by the Director, written update s of adjustments to the cost

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

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

Page 22 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

has reason to believe that the original demonstrat ion 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 shoul d require that the owner or operator redemonstrate financial assurances on a regular ba sis (perhaps with each adjustment of cost

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

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

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

provisions for annual inflationary adjustments)..

4. The Regulation Fails to Requi re 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 operato r (and accepted by the Director) in its plans for

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

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

§ 146.85(a)). There are many reasons why the de monstrated 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. Page 23 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

regarding cost estimation techni ques, or other reasons. Or, a ny part of the GS operation may

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

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

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

the many unknowns associated with large-scale GS at this time, it seems pr udent 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 catastrophi c, “break-the-bank”

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

The proposed regulation requires th e owner or operator to “pr ovide the Director with an

emergency and remedial response plan that describe s 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 em ergency 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 emergenc y planning provisions, truly

un anticipated events are not covered.

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

proceed, or that a CO 2 plume will behave, in a way that is “unplanned” is real. See WRI I SSUE

B RIEF at 9 (“A need remains for ongoing research a nd 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 indi vidual site or collectively at all sites.” EPA S ITE

Page 24 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

S TEWARDSHIP at 25. In light of this, tying the financ ial 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 a nd the public with grea ter assurance that

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

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

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

well operation, but do not set any standards fo r 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 operato r’s estimation of “planned” costs is as accurate as possible.

“Sound cost estimation requirements ensure that su fficient funds are set as ide in the financial

assurance instrument.” Id. at 43,521; see also WRI I SSUE B RIEF at 8 (“Understanding . . . the

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

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

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

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

43,521.

EPA should also proceed with “allowing sepa rate financial demonstrations to be

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

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

process. Id . at 43,522. Although EPA notes in the preamble that it “may be appropriate to redemonstrate financial responsibil ity on a periodic basis,” to “t ake 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

Page 25 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

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

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

indicates it is considering.

Here again, EPA can draw upon its experi ence 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 approxi mates the true costs to government of continuing post-injection

operations. RCRA’s model provides enough collater al 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 ex tent and manner of its ope ration would make closure

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

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

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

owner or operator must be addressed (such as, fo r example, costs associat ed with a catastrophic

accident). See WRI W ORKSHOP S UMMARY at 6 (identifying “‘break th e bank’ risks” as one of

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

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

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

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

.

W ORLD R ESOURCES I NSTITUTE

, W ORKSHOP S UMMARY : A DDRESSING L ONG -T ERM L IABILITY OF

C ARBON D IOXIDE C APTURE AND G EOLOGICAL S EQUESTRATION 5 (2007)

, at 6-8; EPA S ITE

S TEWARDSHIP at 13-24 (discussing Price-Anderson a nd National Flood Insurance models, among

Page 26 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

others); A LEXANDRA B. K LASS & E LIZABETH J. W ILSON

, C LIMATE C HANGE AND C ARBON

S EQUESTRATION : A SSESSING A L IABILITY R EGIME FOR L ONG -T ERM S TORAGE OF C ARBON

D IOXIDE 30 (2008), at 38-39, available at http://works.bepress/co m/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 inju ry and property damage . Although each large

nuclear plant must obtain “primary financial pr otection” through financial assurance mechanisms

similar to those acceptable under the UIC and RC RA 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 assuran ce is insufficient to meet actual

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

B. The Proposed Regulation Does Not Cov er 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 CO 2 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

CO 2 generator, transporter and surface and sub-surface property owner( s), are not covered.

As EPA notes, though, “[t]he SDWA provides EPA w ith 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 ju st the injection well owner or operator), at

Page 27 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

For instance, EPA has recognized that “co-contaminants in the CO 2 stream could

endanger a USDW if the injectate migrates in to a USDW.” 73 Fed. Reg. at 43,497. The “types

of impurities and their concentrations in the CO 2 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 standa rd for stream purity is loosely defined.

The proposed regulation allows in jection of a stream with “inc idental associated substances

derived from the source materi als and the capture process, a nd any substances added to the

stream to enable or impr ove the injection process.” Id. at 43,535 (proposed 40 CFR § 146.81(d)

(definition of “carbon dioxide stream”)). By regulating CO 2 generators and CO 2 stream

treatment (purification) facilities directly, EP A could reduce the likelihoo d that a contaminated

CO 2 stream would be injected into a GS we ll 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 CO 2 streams

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

assurance requirements on those parties, EPA co uld 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 w ould make these firms

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

costs.” WRI I SSUE B RIEF 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. Page 28 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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

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

For example, geological sequestration may “allow some [generators of CO 2 ] 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 emissi ons that will explicitly establish a price for

CO 2 and will encourage utilities and ot hers to invest in CCS in order to meet those caps,” it is the

generators of the CO 2 —along with their customers—who may receive credits for sequestration.

K LASS AND W ILSON at 13. All parties who benefit from GS of CO 2 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 followi ng 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 orpha ned sites and uncompensated postclosure costs and damages; and (2) the industry is le ft with liability that is unlimited in scope or

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

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

post-closure incidents that e ndanger USDWs and to provide fo r the costs of post-closure

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

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

public interest in having the priv ate 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 car e and MMV to the government once closure conditions are met

should be developed. EPA should seek from Cong ress 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 associat ed with the long-term care

of a storage facility and the pot ential for costs associated w ith unanticipated damages.” WRI

W ORKSHOP S UMMARY 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 U NITED N ATIONS F RAMEWORK C ONVENTION ON C LIMATE

C HANGE (“UNFCCC”), F ACT S HEET : I NVESTMENT AND F INANCIAL F LOWS FOR A S TRENGTHENED

R ESPONSE TO C LIMATE C HANGE 1 (2007) (discussing critical factors for large scale

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

upon a long-term liability regime); M ARK E. F ESMIRE ET

. AL

., N EW M EXICO E NERGY

, M INERALS

,

N ATURAL R ESOURCES D EPARTMENT

, C ARBON D IOXIDE S EQUESTRATION : R EPORT ON I DENTIFIED

S TATUTORY AND R EGULATORY I SSUES 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 fram ework are perceived as being significant factors

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

processes and regulations.”); WRI W ORKSHOP S UMMARY at 1 (“Long-term liability is one of the

several important challenges that CCS faces.”).

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

have struggled with how to establish a framework th at balances the interest s of the private sector

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(in avoiding perpetual, limitless liability) and th e 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 s hould include a transfer of liability to the public

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

owner/operator to calculate and pa y into a fund or otherwise set as ide 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 co ntaminated drinking water supplies, and the like

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

entire cost (or risk). EPA’s proposal to regulat e GS within a UIC framew ork 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 responsibili ties” (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 Dire ctor 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 fr om responsibility for posting any

financial assurance. 73 Fed. Re g. at 43,522 (“[O]bligation for fina ncial responsibility ends for

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

authorized site closure[.]”). T hus, once the site is cl osed, the owner or oper ator’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 pr oposed regulation, it is assuming that postclosure liability will remain w ith 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 respon sible after the post-injection site care period has

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

operator indefinitely under current SDWA provi sions.”). 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 cla ss of persons) may have under any

statute or common law to seek enforcement of any requirement prescrib ed 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 th e 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 inci dents. The owner or operator

may no longer be in existence or otherwise unable to pay, leavi ng 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 uncer tainties of CCS technology at this time and the

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

post-closure incidents will occur, and it must provi de 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 risk s 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 pr oblem, 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. Becau se of the focus of the SDWA on endangerment to USDWs and the absence of provisions to allow transfer of liability, stakeholde rs have expressed interest in
alternative instruments for addressi ng financial responsibility after the post-injection care period has en ded. As a result of the interest in alternative instruments, incl uding 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 a ppropriate 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 regul ation), which could

impede implementation of large-scale GS.

3. EPA Should Extend Its Financial Assu rance Requirements Into The PostClosure Period and Transfer MMV Re sponsibilities to the Government.

The risk to the public can be addressed by re quiring 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 usi ng 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 gove rnment should put in place a long-term

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

and after satisfaction of performance standards. See generally WRI W ORKSHOP S UMMARY at 6

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

risks, but would need the pub lic sector to take over th e long-term responsibility for

monitoring.”); MIT, T HE F UTURE OF C OAL : O PTIONS FOR A C ARBON -C ONSTRAINED W ORLD 60

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

to assume liability for the sequestered CO 2 once injection operations ceas e 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 poo l to cover potential damages from any future CO 2

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 enc ourage industry participation. Because the lifespan of sequestra tion 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.

F ESMIRE ET AL

., supra , at 39.

ELPC and ETIP agree that tran sferring liability to the publ ic 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 o ff-shore sequestration of CO 2 intend that when a site is “closed” and

the owner or operator vacates th e site, post-closure long-term m onitoring will be carried out by

the Commonwealth, the cost of su ch monitoring nevertheless rema ins 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, c ould incorporate financia l 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 CO 2 Captured From Coal-Fired Power

Plants , 28 E NERGY L.J. 443, 468 (2007) (advocating a site-speci fic, risk-based approach to GS

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

address all other costs (e.g., remediation and co rrective 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 re sponsibility of GS sites while

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

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

burden for its mitigation.” F ESMIRE ET AL

., supra , at 59.

a. EPA’s Need for Additional Authority

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

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

as the one outlined above. “The SDWA author ity . . . 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 CO 2 becomes more stable over time as secondary trapping mechanisms engage; however, given that the CO 2 is meant to be contained indefinitely, post-closure monitoring and associated costs should be addressed. Page 35 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

operator financial responsibility to other entitie s [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 lia bility regime for GS, which includes an

eventual transfer of responsibility to the gove rnment 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 prot ection 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 Add ressed at a National Level, Not
Left to the States

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

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

states to establish (or not). See U.S. EPA, P ROPOSED UIC R EGULATIONS FOR G EOLOGICAL

S EQUESTRATION OF C ARBON D IOXIDE F EBRUARY 26-27, 2008 M EETING S UMMARY 6 (2008)

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

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

liability). Leaving it to the states to create appropri ate liability and financ ial 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 econo mies of scale and pooling of

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

Moreover, the “[t]ransfer of liabi lity and ownership of the inject ed 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 need s (e.g. education, health care).” F ESMIRE ET

. AL

.,

supra , at 59.

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

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

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

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

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

investment. This competition increases th e likelihood that state- implemented liability

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

or future accidents. M OORE

, supra , at 463 (“Disparities in state UI C programs could also lead to

a concentration of [GS] activity in states with more leni ent 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

CO 2

.

Fourth, given the fact that stored CO 2 is expected to migrate, in cases where the CO 2

crosses state boundaries, liability an d remediation issues would imp act more than the single state

in which the GS facility (well) is situated.

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

should be taken, which includes th e 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 ar e 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 unpro tected by the proposed

UIC regulation. See 73 Fed. Reg. at 43,492, 43,494. EPA sh ould 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 UI C 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 Undergr ound 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 st atute: the SDWA directed EPA

to protect USDWs by publishing regulations fo r underground injection control programs that

include “minimum requirements for effective pr ograms 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 suffi cient 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 fe wer than 10,000 mg/L TDS but does not contain “a sufficient quantity of groundw ater to supply a public water system.” Page 38 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

The legislative history supports the position that Congress intended these terms to be

construed broadly to effectuate Congress’s “ overriding intent to maxi mize protection of the

public health.” In a 1974 report accompanying the SDWA, the House Committee on Interstate

and Foreign Commer ce explained:

[Section 1421 of the SDWA] . . . defines “underground injection which endangers drinking water s ources.” 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 wa ters 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 consid ered alternative proposed concentrations to

determine whether any offered “any superior just ification 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 overridi ng argument to the contrary, the Agency will

follow the standard in the House Comm ittee Report accompanying the SDWA.” Id.

However, improvements in desalinati on technology since 1974 and 1980 provide

“superior justification” for incr easing the 10,000 mg/L standard. Water with TDS concentrations

Page 39 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

above 10,000 mg/L is desalinated using Reverse Osmosis (RO) or Distillation processes that

include multistage flash evaporation (MSF), mu ltiple effect distillation (MED), and vapor

compression (VC). See Y UAN Z HOU & R ICHARD S.J. T OL

, E VALUATING THE C OSTS OF

D ESALINATION AND W ATER T RANSPORT

, W ATER R ESOURCES R ESEARCH

, V OL

. 41, available at

http://www.unihamburg.de/Wiss /FB/15/Sustainabili ty/wrrdesalt.pdf (discussing the variety of

desalting technologies). The co st-efficiency of these technolog ies vary with specific site

characteristics. Accordingly, the cost per unit depends on size and loca tion of the desalination

plant and is highly linked to the pr ice of electricity. “L arger 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 in dicate 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 m 3 in 1979 to about $1.33 per m 3 in 2001.

For the MSF process, the cost has gone down from $3.04 m 3 in 1979 to $.66 m 3 in 2001. As for

the ME process, the cost has also decreased from $3.56 m 3 in 1979 to $1.21 m 3 in 2001. Lastly,

the average unit cost of VC has gone down from $3.72 m 3 in 1979 to $1.50 m 3 in 2001. 15

See R ESEARCH U NIT S USTAINABILITY AND G LOBAL C HANGE

, H AMBURG U NIVERSITY AND

C ENTRE FOR M ARINE AND A TMOSPHERIC S CIENCE , available at

http://www.unihamburg.de/Wiss/FB/ 15/Sustainability/Models.htm cited in Y UAN Z HOU & TOL

.

at 4

.

For EPA to meet SDWA’s goal of ensuring that not only all cu rrent, 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 Y UAN Z HOU & TOL

, supra , at 4.

Page 40 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

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 pr oposed regulation excludes from protection

aquifers and wells that likely w ould not be sufficient to supply water to public water systems 17

but that are used as a supply of water for smalle r, 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 Leas t 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 Cl ass V experimental GS wells may be used for

large-scale GS under the Class VI regulations but “are exempt, at the Dir ector’s discretion, from

the casing and cementing requirements at [p roposed] §§ 146.86(b) a nd 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 demons tration that the well will mainta in integrity and stability in a

CO 2 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 car e, and site closure

requirements. Id.

16 Going forward, EPA should consider revising the defi nition of USDWs on a rolling basis to prevent the TDS standard from becoming outdated and the resulting endangerment of viable sources of drinki ng water by GS. In this way, EPA will comply with its Congressional ma ndate 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 re gularly serves at least twenty-five individuals.” 42 U.S.C. § 300F(4). Page 41 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

As EPA points out, “GS projects are anticipated to have long lifespans in comparison to

other types of deep injection we lls. 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 CO 2 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 we ll 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 oper ator must provide [the Director] the following

information [including] Corrosiveness of the car bon dioxide stream, and fo rmation 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 CO 2 .” Id. at

43,509(emphasis added).

It is not clear why bypassing the “crucial” sa feguards of proposed 40 C.F.R. § 146.86(b)

and 146.87(a)(1) through (3) in favor of the Director’s general dete rmination 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 co mpatible 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 Page 42 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

proposed casing and construction requirements for GS wells provide assurance beyond

“no endangerment of USDWs,” that “extra” assurance seems appropr iate in light of industry’s

inexperience with large-s cale, long-term GS of CO 2 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. EP A should require the Director

to engage in a rigorous review of the design, purpose, and suitabili ty of the original well before

allowing grandfathering in any pa rticular case. Also, grandfat hering 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 mo st protective applicab le standard.

VI. EPA Should Rank Sites With GS Capabilit y Based On Their Sp ecific Leakage Risk
Profiles.

In the preamble to the proposed regulation, EPA states that it is soliciting comment on:

(1) Whether CO 2 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 unde r 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 Materi als, or comparable standards acceptab le to the Director.” 40 C.F.R. §146.65(b). However, the Class I well would have been ev aluated for “compatibility” with respect to the waste that was initially injected into the well, which may be less (or more) corrosive than CO 2 to the particular well materials used to construct the well. Thus, the Class I requirem ents would not necessarily ensure compatibility with CO 2

. Page 43 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

EPA suggests that its rationale for allowing the injection of CO 2 above the lowermost

aquifer is to increase the available storage capacity for CO 2

. See id. at 43,512. In other contexts

(e.g., for Class I injection wells), however, EP A 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 expl icit use of the terms “exemp tion” or “injection above the

lowermost aquifer” and instead propose guidelines for site selection a nd characterization of

storage capacity. WRI G UIDELINES at 91. Building on the WRI’s guidelines and on further

research, the EPA should rank sites with geologi cal storage capacity depending on the specific

risk profile of CO 2 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, storag e reservoirs should not be freshwater aquifers or po tential underground sources of drinking water.

4. Confining zone(s) should be pres ent that possess characteristics sufficient to prevent the inject ed or displaced fluids from migrating to drinking wate r sources or the surface.

5. Site-specific data should be co llected and used to develop a
subsurface reservoir model to predict/simulate the injection over the lifetime of the storag e project and the associated project footprint. These simulations should make predictions that can be verified by histor y-matching within a relatively short period of time after initial CO 2 injection or upon completion of the first round of wells. The reservoir model and simulations should be updated pe riodically 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 fo r subsequent activity with
additional research.

Page 44 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

WRI G UIDELINES at 91.

The According to the WRI Guidelines, EPA would fi rst 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 th at 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 opera tor to provide financial

assurance to cover the co sts of such treatment.

A. CO 2 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 pr ogram. 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 inj ection above a lowermost USDW. See id. at 43,511; U.S. EPA,

C LASS I U NDERGROUND I NJECTION C ONTROL P ROGRAM : S TUDY OF THE R ISKS A SSOCIATED WITH

C LASS I U NDERGROUND I NJECTION W ELLS 2 (March 2001) (“By defin ition, Class I wells inject

industrial or municipal wastewat er 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 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

unclear, however, why lowermost USDWs should be afforded less protection from GS,

especially in light of the anticipated long life sp ans of GS projects.

Given the emerging state of technology associated with GS and the lack of data available

regarding the likely behavior of injected CO 2 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 inje ction above or between

USDWs is appropriate and protectiv e of USDWs. 73 Fed. Reg. at 43,512. Nonetheless, EPA is

considering giving the Direct or discretion to allow CO 2 injection above the lowermost USDW

when he or she determines that geologic conditio ns such as thousands of feet of intervening

formations between the injection zone and the overlying and/or underlyi ng USDWs exist that

will prevent fluid movement into adjacent USDWs. Id

.

EPA anticipates that such disc retion would allow GS “in specif ic geologic settings where

the depth of the USDWs may preclude GS, make GS technically challenging, or significantly

limit CO 2 storage capacity.” Id . (suggesting that “[a]n exampl e 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 receivi ng formations (formations with large CO 2 storage

capacity) for GS have been identified above the lowermost USDW and where there may be

thousands of feet of rock st rata between the injection zone and the overlying and underlying

USDWs”).

Before allowing such injections, EPA should fi rst carry out further research and rank sites

with geological storage capacity according to spec ific factors such as ri sk of leakage of impure

streams of CO 2 to lowermost geological formations, dist ance between the inje ction zone and the

lowermost USDW, composition of the rock stra ta that will prevent contamination of

Page 46 of 49RE: Docket ID No. EPA – HQ – OW – 2008 – 0390 Submitted by Harvard Law School En vironmental Law & Policy Clinic

underground reservoirs, and the specific characteris tics 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 wh en the following conditions are met:

a) [the USDW] does not currently se rve 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 pe rmit 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 II I 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 affo rded 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 le ss 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, give n 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

E NVIRONMENTAL 

### L AW 

### & P OLICY 

### C LINIC

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 th e Comments submitted by the Clinic regarding

Docket ID No. EPA–HA–OW–2008–0390:

1) S ARAH M. F ORBES ET AL

., W ORLD R ESOURCES I NSTITUTE

, CCS G UIDELINES : G UIDELINES FOR C ARBON D IOXIDE C APTURE

, T RANSPORT

, AND S TORAGE (2008);

2) W ORLD R ESOURCES I NSTITUTE

, W ORKSHOP S UMMARY : A DDRESSING L ONG -T ERM
L IABILITY OF C ARBON D IOXIDE C APTURE AND G EOLOGICAL S EQUESTRATION (2007);

3) A LEXANDRA B. K LASS AND E LIZABETH J. W ILSON

, C LIMATE C HANGE AND C ARBON S EQUESTRATION : A SSESSING A L IABILITY R EGIME FOR L ONG -T ERM S TORAGE OF C ARBON D IOXIDE (2008);

4) I NTERGOVERNMENTAL P ANEL ON C LIMATE C HANGE

, IPCC S PECIAL R EPORT ON C ARBON D IOXIDE C APTURE AND S TORAGE (2005).

5) U NITED N ATIONS F RAMEWORK C ONVENTION ON C LIMATE C HANGE (“UNFCCC”),

F ACT S HEET : I NVESTMENT AND F INANCIAL F LOWS FOR A S TRENGTHENED R ESPONSE

TO C LIMATE C HANGE (2007);

6) M ARK E. F ESMIRE ET

. AL

., N EW M EXICO E NERGY

, M INERALS

, N ATURAL R ESOURCES
D EPARTMENT

, C ARBON D IOXIDE S EQUESTRATION : R EPORT ON I DENTIFIED S TATUTORY

AND R EGULATORY I SSUES (2007);

7) MIT, T HE F UTURE OF C OAL : O PTIONS FOR A C ARBON -C ONSTRAINED W ORLD (2008);

8) J EFFREY W. M OORE

, T HE P OTENTIAL L AW OF O N -S HORE G EOLOGICAL S EQUESTRATION OF CO 2 C APTURED F ROM C OAL -F IRED P OWER P LANTS , (2007); and,

9) Y UAN Z HOU & R ICHARD S.J. T OL

, E VALUATING THE C OSTS OF D ESALINATION AND
W ATER T RANSPORT

, W ATER R ESOURCES R ESEARCH

, V OL

. 41, available at http://www.unihamburg.de/Wiss /FB/ 15/Sustainability/wrrdesalt.pdf.

Page 1 of 11 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 5 th 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 fi nding from the June 5 workshop is that long-term liability comprises both anticipated costs associate d with the long term care of a storage facility and the potential for costs associated w ith unanticipated damages. Another key finding of the workshop is that there are important inter-relations am ong the different stages of a project (siting, operation, closure, and post-closure). These i nter-relations are important both in terms of reducing the long-term risk of liability and in crea ting 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 deve loping 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, energ y, governmental and NGO communities (see Appendix B). The goal was to assess the ne ed and options for sharing the long-term liability associated with CCS between the publi c and private

sectors.

Long-term liability is an important issue from many perspectives. The publ ic 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 require ments up front in order to manage costs and risks. There is a need for much greater clari ty 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 liability2

This discussion was a great success in that it brought together a diverse set of s takeholders, revealed a set of informational needs and identified a concrete set of steps towar ds 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 pot ential risks associated with CCS. Rather than attempting to assess models for mitiga ting long-term liability, the group called for an interim step to develop a common vocabulary and more cle arly 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 li ability associated with the various potential risks from CCS.

Review of Discussions Slides were used throughout the day except for the general discussions which took pla ce 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 i mportant points from the presentations as well as a summary of the important points from the di scussions.

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 mid dle of this century and beyond. This will require fundamental changes to our energy system.

• Integrated assessment modeling of the global energy system suggests tha t no single technology (e.g., renewable energy, energy efficiency, nuclear energy, c oal CCS) will be sufficient to achieve the reductions necessary. In fact, it suggests that al l will be needed.

• CCS involves the capture and storage of the most common GHG, known as carbon dioxide
or CO 2 . 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 stabi lization 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 pr ovide a cost-effective reduction option for large sources of CO 2 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 repr esent several orders of magnitude increase in deployment over what we have today. This might incl ude 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 mi dcentury. 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 t he3

predicted costs to reduce CO 2 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 envi ronmental risks of geological storage, and (c) risk management and mitigation (including the st orage security pyramid). It seemed that several participants did not have prior exposure to t he information in this presentation and it stimulated significant discussion. In particular, the pr esentation 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 effe ct. There was discussion about the ability of an operator to impact the risk profile through operationa l changes.

• CCS can take place in several types of geologic formations including depleted oil a nd gas fields, unmineable coal seams and saline (brine) formations. It’s possible t hat other formations can be used as well, but there is less known about such formations.

• There are four ways that injected CO 2 is contained in the injection zone. The primary trapping mechanism is the overlying caprock. Secondary trapping mechanisms incl ude CO 2 dissolving in brine, capillary trapping, and eventual “mineralization”.

• IPCC experts agreed that for well-selected sites that are operated a nd monitored properly, there is a greater than 99% probability that CO 2 will remain in the selected storage reservoir for 1,000 years or more. An important caveat was noted that this figure was based on nat ural and industrial analogues and not specific modeling results. However, there is consi derable evidence for this found in the natural and industrial analogs.

• The potential risks from CCS stem primarily from the unintended release of CO 2 (and also include potential industrial accidents conventionally associated with constructi on and drilling projects). Potential release pathways include well leakage (injection and a bandoned 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 CO 2 release.

Source: Sally Benson, Stanford.4

• Jumping to the top tier, financial responsibility (please see the slides for det ailed information on each tier), the group was presented with a conceptual risk profile for CCS proje cts (shown below). The concept is that if storage projects do not demonstrate any problems duri ng the operation stage, the risk of CO 2 release is expected to decrease as injection stops and the secondary trapping mechanisms take effect. However, the concept also shows tha t the risk will remain greater than zero for a long time in the future, suggesting that fina ncial responsibility mechanisms may be needed to address long-lived, but low-probability r isks. 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 busi ness of storage and a call for a more precise articulation of the perceived risks. Som e of the issues touched on and included the differences between long-term responsibility for measure s such as ongoing MMV and well maintenance versus long-term liability for damages to human health and property through accidental future release of injected CO 2

.

• 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 t imelines for compliance are so much shorter than the timelines for completing CCS projects. T his 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 requireme nts 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 ass ociated with fully reducing the risk associated with CCS projects. If investors ar e going to be held responsible for the long-term risks of CCS, it will make those investments unatt ractive in5

comparison to many other investments with shorter term payouts or more certain ex it strategies.

• Likewise, investors will be interested in the transferability of the environme ntal 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 bar rier.

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 incentivizi ng sound siting and operations practices, ensuring adequate funding to cover LT responsibilitie s 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 fo r and the difficulty in adopting a flexible approach so that a FR mechanism can adapt t o changes in scientific knowledge, technical capacity, and economic tools. Thus, the earlie r conversation calling for a better definition of the risks was reiterated and it was refi ned to suggest distinguishing the interests of the public, investor groups and industry/carbon emitte rs.

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 dif ferences between the general approach to environmental regulation, litigation and ownership of por e space/mineral rights in the EU and the US, but nonetheless useful comparisons eme rged in thinking about managing the long-term care of storage facilities.

• The discussion reiterated the need for and difficulty in allowing flexibili ty 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 proje ct experience is gained and/or markets change.

• There were different views about whether we need to figure out all the LT liabi lity solutions now. An effective framework must evolve with the technology and experience. It wa s suggested that this framework could perhaps be modified annually as we learn more a bout the risks and project performance.6

• How FR is structured will impact larger companies very differently than sm aller ones. For example, larger companies may be able to self insure whereas, smaller ones ma y 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 eff ectively. There are concerns that a publicly run program would not have these built-in incentives. In addi tion, 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 wi th 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 A ssociated 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 acti vities that might need to take place after closing or decommissioning a storage facility, (b) the nat ure 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 car e to the public (either funded or unfunded, state or federal, and via creation of 3 rd party institutions or other administrative options). This led to a reiterated call for an articulation of ri sk by stage, type and interested party.

• A well structured FR framework will encourage proper siting, operation, and clos ure— 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 tha t might happen.” This mixed message will undermine public acceptability. Public perc eption 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 wa s tasked to managing these sites after closure.

• One suggested criteria for transferring liability to the public was proje ct 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, informa tion, and experience.

• There was wide agreement on a strong need for defining and distinguishing risks, characterizing their timing and probability, identifying how to prioritize the m, estimating their costs, and defining who should be responsible for what risks. Answers to these questions wi ll 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 t hey addressed certain issues. The group called for more of a bottom-up approach that first i dentified the full suite of issues (risks) and then looked at ways to prioritize the risks and ef ficiently mitigate them. In the absence of having this analysis done, the group offered some re flections on the top-down analysis:

• Transferring LT responsibility to a public-private corporation was discusse d. One reason that transfer to government or a public-private corporation is needed at some point is to ens ure that the entity will be around to deal with any problems.

• There were some concerns that the term “liability” was being used by parti cipants 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 cost ly.

• There was discussion about the pros and cons of a one-size-fits all federal approa ch to liability versus a state-by-state approach. In a worst case scenario, unequal approac hes across the states could result in a race to the bottom, creating perverse incentives for siti ng, operation,
and closure.

• One suggested approach involved developing different models for liability based on ris k 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 associ ated with the various stages of CCS. There are several papers and significant other work r elated to CCS risk assessment. The risk log proposed here will attempt to draw from those and als o to contemplate a broad group of stakeholders including project developers, the public, and investors. Once complete, we will initiate an iterative process to solicit i nput 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 efficie ntly 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 s uggestions 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, investme nt 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 process9 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 Voorhees10

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 W ebster Duke Energy

Fred Wellington
World Resources Institute

Elizabeth Wilson University of Minnesota1



### C LIMATE 

### C HANGE AND 

### C ARBON 

### S EQUESTRATION 

### : A SSESSING A 

### L IABILITY 

### R EGIME FOR 

### L ONG



### - TERM 

### S TORAGE OF 

### C ARBON 

### D IOXIDE

A LEXANDRA B. K LASS ∗

E LIZABETH J. W ILSON **

A BSTRACT

As the nation struggles with how to address climate change, one of the m ost significant questions is how to reduce increasing levels of carbon dioxide i n the atmosphere. One promising technology is carbon capture and sequestration (“CCS”), which consi sts of capturing carbon dioxide emissions from power plants and industrial sour ces and sequestering them in deep geologic formations for long periods of tim e. Areas for potential

CO 2 sequestration include oil and gas fields, saline aquifers, and coal seam s. 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 str ucture liability for the short-term or long-term risks associated with the geologic sequestration of C O 2 in connection with CCS. Until now, federal and state legislators, when they have a cted at all, have appeared to be in a rush to limit corporate liability for potential ha rm in order to encourage the development of CCS. We take a different approach. In this Article, we surve y the existing liability regimes that may cover potential harm from escaping or migrating CO 2 . 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 legisl ation specific to CCS should leave this basic liability framework in place. We also propose sev eral different compensation mechanisms including bonding, insurance, and pooled federal funding, to provide financial security to investors without destroying existing liability prote ctions for those who may suffer harm from CCS.

I NTRODUCTION

One of today’s most pressing environmental challenges is climat e change 1 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 managi ng traditional criteria air

∗ Associate Professor of Law, University of Minnesota Law School. ** Assistant Professor, Center for Science, Technol ogy and Public Policy, Humphrey Institute of Public Affairs, University of Minnesota. This work was supported b y the Doris Duke Charitable Foundation under a gran t to develop a regulatory framework for Carbon Capture a nd Sequestration.

1 The term “climate change” (which is often used syn onymously with the term “global warming”), refers t o “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 I nformation, available at http://www.epa.gov/climatechange/basicinfo.html ; EPA, Climate Change, Emissions, available at http://www.epa.gov/climatechange/emissions/index.ht ml

. 2 See I NTERGOVERNMENTAL P ANEL ON C LIMATE C HANGE (“IPCC”) F OURTH A SSESSMENT R EPORT

, W ORKING G ROUP 1 R EPORT

, T HE P HYSICAL S CIENCE B ASIS 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 criteri a pollutants (e.g., sulfur dioxide or oxides of nitrogen) is only a few hours or days, pollution control and emi ssion reduction at the source is sufficient for reducing atmospheric concentrations of the se 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 ena ble deep emission
reductions. 5 Carbon capture and sequestration (“CCS”) is emerging as a te chnology that would enable the continued use of fossil fuels while dramatically reducin g accompanying greenhouse gas emissions. This technology drastically reduces emissions from power plants and industrial sources by capturing CO 2 emissions and storing or sequestering them in deep geologic formations for long periods of time. Areas for potential CO 2 sequestration include oil and gas fields, saline aquifers, and coal seams. Natural geologic analo gs, like geologic formations containing crude oil, natural gas, brine, and CO 2, have proven storage capabilities for millions of years. CCS technologies would attempt to take advantage of these natural storage capacities to
reduce CO 2 emissions.

From a legal perspective, CCS owners and operators must manage compl ex projects and technologies that involve injecting large volumes of buoyant CO 2 and storing them underground over long timeframes. The volumes of CO 2 sequestered from an individual site are likely to be large (millions of tons of CO 2 per year) and the corresponding subsurface property area is vast (injected CO 2 potentially taking up tens of miles for a single project, with pres sure effects felt over great distances). 6 The injected CO 2 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 CO 2 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 Cha nge, 1992, Art. 2, at p. 5 (“The ultimate objective of this Convention and any related legal instruments t hat the Conference of the Parties may adopt is to a chieve, in accordance with the relevant provisions of the Conv ention, stabilization of greenhouse gas concentrati ons 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 suffic ient to allow ecosystems to adapt naturally to clim ate change, to ensure that food production is not threatened and t o enable economic development to proceed in a susta inable manner.”), available at http://unfccc.int/resource/docs/convkp/conveng.pdf

. 5 See Stephen Pacala & Robert Socolow, Stabilization Wedges: Solving the Climate Problem f or the Next 50 Years with Current Technologies , S CIENCE 305, 968-972 (2004); James A. Edmonds, et al, Modeling Greenhouse Gas Energy Technology Responses to Climate Change , 29 E NERGY 1529 (2004); E LECTRIC P OWER R ESEARCH I NSTITUTE (EPRI), T HE P OWER TO R EDUCE CO 2 E MISSIONS : T HE F ULL P ORTFOLIO (Discussion Paper Aug. 2007), available at http://epri-reports/org/DiscussionPaper2007.pdf

. 6 Kartsen Preuss, et al., Numerical Modeling of Aquifer Disposal of CO 2 , 8 S OCIETY OF P ETROLEUM E NGINEERS J. 49, 52-53 (2003).

7 See, e.g., Mihn Ha-Duong & David W. Keith, Carbon Storage: The Economic Efficiency of Storing CO 2 in Leaky Reservoirs, in 5 C LEAN T ECH

. & E NVTL

. P OLICY 181 (2003).3

In this Article, we focus on the relationships among CCS technolog ies, risk management, and potential liability for accidental leakage of stored CO 2 . 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 CO 2 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 r ecovery can and should serve an important risk management role in ensuring protection of human health and the environm ent in the process of developing and commercializing this new technology. In our view, the g oal 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 liabi lity frameworks to promote and encourage safe practices and allow recovery for those who ma y be subject to harm. We believe that the anticipated level of risk from long-term storage of CO 2 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-specif ic remediation plan. This, as well as the potential monetary benefits to investors and operators assoc iated 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 lar ge.

There are two caveats to this approach. First, given the inherent uncertainties of technology research, development, and demonstration, and the strong governmenta l role in getting initial CCS projects off the ground, the first dozen or s o CCS projects could be encouraged under a shared public-private liability regime if the priva te sector is willing to share project data and information to aid in the development of a risk-man agement framework. 9
Second, commercial projects which are developed after these first “demonstration projects” will likely require some transfer of long-term liability—approximat ely 20-30 years after project injection has ceased—and a successful monitoring and verification pr ogram has demonstrated that the injected CO 2 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 feasibili ty of CCS technology. Other important issues include the nature of the statutory and regulatory f ramework 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 Sequestratio n of CO 2 Captured from CoalFired Power Plant s, 28 E NERGY L.J. 443, 444 (2007) (arguing that the federal gove rnment should limit long-term liability for stored CO 2 under existing federal statutes and state common l aw); T HE I NTERSTATE O IL AND G AS C OMPACT C OMMISSION (“IOGCC”), T ASK F ORCE ON C ARBON C APTURE AND G EOLOGIC S TORAGE

, A L EGAL AND
R EGULATORY G UIDE FOR S TATES AND P ROVINCES 11 (2007) (proposing, among other things, that afte r a 10-year period the operator of the CO 2 storage site would be released from any bonding re quirements and liability for ensuring that the site remains a secure storage sit e would transfer to the state).

9 Elizabeth J. Wilson et al., Regulating Geologic Carbon Sequestration

, in E NVIRONMENTAL S CIENCE AND
T ECHNOLOGY (forthcoming 2008).4

the stored CO 2 , the subsurface pore-space that will hold the CO 2 , and subsurface minerals in the
area of the stored CO 2

. 10 This Article acknowledges these important issues but will lea ve them for future analyses. We have chosen to focus on the issue of liabil ity for harm instead of these other key issues because it is often too easy to limit or elimi nate 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 CO 2 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 CO 2 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 unde rstanding how some of these issues would be resolved is critical in creating the legal st ructures that will govern any widescale use of CCS.

In Part III, we look at actions federal and state policymaker s 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-t he-bottom” in an effort to lure CCS development to their state. In this Part, we also consider the pote ntial role of federal preemption of state tort law and regulatory standards. In Part IV, we sur vey 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 at tempt to provide guidance to policymakers at the state and federal levels to address potentia l liability issues associated with CCS that goes beyond arguing that such liability should be severe ly limited or eliminated. As we show in this Part, the continuing existence of liability for ha rm can help to balance divergent interests and provide important safeguards to complement whatever r egulatory regime is created to guide the long-term storage of CO 2 . 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 CC S, they must be balanced against the even more significant long-term risks of climate change. A s a result, the goal of this Article is to present options for creating liability and funding frameworks t hat encourage the development of CCS and its corresponding benefits while ensuring t hat the potential risks of CCS do not fall too heavily on states or individuals that may be vulnerable to harm.

I. E LECTRIC P OWER G ENERATION

, I NDUSTRIAL S OURCES

, G REENHOUSE G AS E MISSIONS

, 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 emis sions and explaining how CCS

10 For a detailed discussion of the potential propert y right and liability frameworks associated with st ored CO 2 , see M ARK A NTHONY DE F IGUEIREDO

, T HE L IABILITY OF C ARBON D IOXIDE S TORAGE (MIT Ph.D. Thesis Feb. 2007).5

technology is being developed as a means to control such emissions. I t then proceeds to provide some detail on the CCS projects that exist today and those that ar e planned for the near future. Finally, this Part introduces some of the potential environmental an d public health risks associated with CCS and the long-term storage of CO 2

.

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 el ectric 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 gener ation. 13 Coal is plentiful in the
United States 14 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 Ger many as well as in the United States.

Using coal for electricity generation, however, has also been li nked to many environmental ills. Upstream impacts from coal combustion include t he 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, g reenhouse gases implicated in global climate change. Regulations have been developed t o manage these impacts with varying degrees of success. Federal law has attempte d 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. E NVIRONMENTAL P ROTECTION A GENCY

, I NVENTORY OF U.S. G REENHOUSE G AS E MISSIONS 1990-2005 Table ES-3 (2007), available at http://www.epa.gov/climatechange/emissions/download s06/07CR.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, pl ants typically are run as either base load or peaki ng plants. Base load generating plants are plants that run almost c ontinuously. Typically, base load plants—tradition ally 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 Util ization and Market Reforms , 27 E NERGY J. 119-28 (2006).

14 See Energy Information Administration Coal Reserves Da ta, available at http://www.eia.doe.gov/cneaf/coal/reserves/chapter1 .html

. 15 Coal reserves are especially prominent in North Am erica, Europe and Asia. See BP, BP S TATISTICAL R EVIEW OF
W ORLD E NERGY 2007, available at http://www.bp.com/liveassets/bp_internet/globalbp/g lobalbp_uk_english/reports_and_publications/statist ical_energ y_review_2007/STAGING/local_assets/downloads/pdf/st atistical_review_of_world_energy_full_report_2007.p df

. 16 For a good summary of the above data sources see E nergy Information Administration (“EIA”), Annual En ergy 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/coa lmar.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.p df

. 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

regulations 20 and the Clean Air Act 21 have led to the successful deployment of technologies to control particulate matter, sulfur dioxide emissions, 22 and oxides of nitrogen. Reducing CO 2 emissions from coal, however, is a fundamentally different—and difficult—chall enge.

CCS has been examined in detail in a Special Report by the Int ergovernmental Panel on Climate Change. 23 The IPCC report outlines sources of CO 2, capture technologies, transportation modes, geologic storage and risks, and covers economic potential and cost, a long 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 rela tively inexpensive greenhouse-gas emissions reductions. At a sequestration cost estim ated from twenty-five to ninety dollars per metric ton, depending upon the source for CO 2 captured and sequestered, large energy-economic models predict CCS could help to reduce the overall s ocietal cost of deep
emission reductions. 24 Table 1 outlines the quantities of CO 2 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 C O 2 emission sources and candidates
for CCS. 25

TABLE 1 26

PROCESS NUMBER OF
SOURCES EMISSIONS

(MILLION TONS OF
CO 2 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 J OEL A. T ARR

, T HE S EARCH FOR THE U LTIMATE S INK : U RBAN P OLLUTION IN H ISTORICAL P ERSPECTIVE 219-62 (Univ. of Akron Press 1996) (providing environmenta l 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 Innov ation for SO 2 Control , 37

E NVTL

. S CI

. & T ECH . 4527-4534 (2003).

23 W ORKING G ROUP III OF THE I NTERGOVERNMENTAL P ANEL ON C LIMATE C HANGE

, IPCC S PECIAL R EPORT ON C ARBON D IOXIDE C APTURE AND S TORAGE (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. T IMES (July 5, 2006).

26 See IPCC S PECIAL R EPORT ON C ARBON C APTURE AND S TORAGE

, S UMMARY FOR P OLICYMAKERS SPM-3 (worldwide large stationary CO 2 sources with emissions greater than 0.1 million to ns per year).7

B. How CCS Works

CCS projects must capture CO 2 from power plants or industrial sources 27 and transport
it 28 to a geological sequestration site. The CO 2 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 CO 2 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 CO 2 fills the permeable pore space within the sedimentary rocks, essentially trapped by less permeable ro ck layers which impede upward fluid migration. CO 2 will be sequestered either as a gas, a dense supercritical g as, or a liquid. 30
Depending on reservoir temperature and pressure injected, in almost a ll circumstances, except deep ocean subsurface sequestration, CO 2 will be less dense than the brine present in the reservoir. This makes buoyancy flow an important force governing supercritical CO 2 behavior in
the subsurface. 31 The life-cycle of a geological storage project progresse s from site selection, characterization, and demonstration and regulatory review (1-10 ye ars); active CO 2 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 act ivities take place throughout the life-cycle. 33

Because injected CO 2 will initially be more buoyant than the in situ waters, upwards and lateral migration within the subsurface is an important considerat ion for modeling and monitoring subsurface behavior. Due to geological heterogeneity, CO 2 behavior in the subsurface will vary between sequestration sites. Importantly, s torage integrity will become more secure over time as geochemical reactions dissolve CO 2 in formation waters (centuries), and eventually convert it to minerals like calcium carbonate (mil lennia). 34 Thus, an effective geologic sequestration site will keep large volumes of a buoyant f luid underground for centuries
to millennia.

27 In terms of costs of electricity generation, captu re costs are the greatest component – 1.8 to 3.4 ¢/ kWh for pulverized coal plants; 0.9 to 2.2 ¢/kWh for integr ated 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 (t he negative values are possible if captured CO 2 is sold for use in enhanced oil recovery or enhanc ed coal-bed methane production. These transport costs would be consider ably higher if sequestration sites are not located within a reasonable distance from the plant. See Howard Herzog et al., Costs and Economic Potential , IPCC S PECIAL
R EPORT ON C ARBON D IOXIDE C APTURE AND S TORAGE 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 D ioxide,

E NERGY C ONVERSION AND M ANAGEMENT 38 (Supplement): S193-S198 (1997); Sam Holloway, Storage of Fossil Fuel-Derived Carbon Dioxide Beneath the Surface of the Earth, 26 A NNUAL R EVIEW OF E NERGY AND THE
E NVIRONMENT 145-166 (2001).

30 CO 2 is considered a supercritical fluid at temperature s greater than 31.1 ° C and 7.38 MPa (critical point). See
CRC H ANDBOOK OF C HEMISTRY AND P HYSICS Table II, F-89 (60th ed. 1979); Robert G. Bruant e t al., Safe Storage of CO 2 in Deep Saline Aquifers, 36 E NVTL

. S CIENCE & T ECH . 240A-245A (2002).

31 Stefan Bachu, Sequestration of CO 2 in Geological Media: Criteria and Approach for Sit e Selection in Response to Climate Change , 41 E NERGY C ONVERSION M GMT . 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 CO 2 into the subsurface for the purpose of controlling greenhouse gas emissions may be new, the practice of injecting CO 2 into the subsurface for other purposes is not. For decades, oil producers have injected CO 2 into the subsurface to increase oil production from depleted fields. This process, known as “enhanced oil r ecovery” or EOR, is in widespread use in West Texas, where 30 million tons of CO 2 are injected into the ground annually, resulting in a total of 600 million tons injected—though not s tored for sequestration—
in that area since 1985. 35 While supporters of CCS hold up the success and safety of CO 2 injection for enhanced oil recovery purposes, it is clear that CO 2 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 CO 2 produced from U.S. coal-based power generation were to be captured and compressed to a liquid for ge ologic sequestration, its volume would about equal the total U.S. oil consumption of 20 million barrels per day,” 37
highlighting the massive volumes of CO 2 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 e mission 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 CO 2 to be injected—a 1,000 Megawatt power plant produces from 4-6 Million tons per year; (2) the fact that CO 2 will be more buoyant than the subsurface saline formation water; and (3) the need for injected CO 2 to remain in the subsurface for hundreds to thousands of years. Worldwide , there are four CCS projects, each injecting roughly 1 million tons of CO 2 annually. 38 If all of the 1.5 billion tons of
CO 2 produced from U.S. coal-fired power plants were captured, transported a nd injected for CCS, it would be equivalent to roughly one-third of the natural gas tr ansported by pipelines in the U.S. each year. 39

The IPCC report on CCS estimates that in excess of 99% of inje cted CO 2 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 R ICHARD C. M AXWELL ET AL

., O IL AND G AS 13-14 (8 th ed. 2007) (discussing enhanced recovery technology ); Steven D. Cook, Researchers Optimistic on Prospects for Successful Carbon Capture, Storage , D AILY E NV

. R EP

. No. 94 at A-1 (BNA May 16, 2007) (discussing the us e of enhanced oil recovery in Texas as a current ex ample of subsurface injection of CO 2 ).

36 See U.S. Environmental Protection Agency, Guidance Doc ument, Using Class V Experimental Technology Well Classification for Pilot Geologic Sequestration Pro jects, UIC Program Guidance (UICPG #83) at 2 (March 1, 2007) (stating that “[w]hile injection of fluids, includi ng CO 2 into the subsurface, e.g., for enhanced oil recove ry (EOR) and enhanced gas recovery (EGR), is a long-standing practice, injection of CO 2 [for CCS] is an experimental application of this existing technology.”).

37 MIT, T HE F UTURE OF C OAL xi (2007).

38 These projects are Sleipner in the North Sea, run by StatoilHydro; In Salah in Algeria by BP, Sonatra ch and StatoilHydro; Weyburn in Canada, operated by EnCana ; and Snøhvit in the Barents Sea, operated by Stato ilHydro. A comprehensive list of commercial and pilot CCS pr ojects is maintained by the International Energy Ag ency (“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 a nalogues as well as models suggest that the fractio n retained in appropriately selected and managed geol ogical reservoirs is very likely to exceed 99% over 100 years9

sites, and potential leakage manageable, identifying potential ris ks 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) CO 2 leakage back to the atmosphere will negate the climate benefi ts from sequestration. 41 Persistent leakage could result in diminishing benefits in car bon emissions reductions associated with a CCS program.

CCS risks seem to be well within the bounds of other industrial acti vities 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 m aterial, as well as the specific properties of CO 2 , and vary for given stages in the life-cycle of a CCS proj ect. 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 CO 2 upward through pathways in undetected faults or abandoned well bores. Larg e surface releases, albeit unlikely, could pose health risks to humans, both in the form of im mediate death from asphyxiation or effects from prolonged exposure to high concentrations of CO 2

. 45 Slow CO 2 seepage into the near subsurface could harm flora and fauna, and potenti ally cause local disruptions of ecology or agriculture. 46 There are also a number of potential risks associated with injected CO 2 even if it remains underground, including displacement of saline groundwat er into potable aquifers, contamination of hydrocarbon resources, pressure c hanges causing ground

and is likely to exceed 99% over 1,000 years. For well-selected, designed and managed geological stor age sites, the vast majority of the CO 2 will gradually be immobilized by various trapping mechanisms and, in that case, could be retained for up to millions of years. Because of th ese mechanisms, storage could become more secure ov er longer timeframes.”).

41 See generally , Minh Ha-Duong & David W. Keith, Carbon Storage: The Economic Efficiency of Storing CO 2 in Leaky Reservoirs , C LEAN T ECHNOLOGIES AND E NVIRONMENTAL P OLICY 181-89 (2003); Stephen W. Pacala, Global Constraints on Reservoir Leakage , S IXTH I NTERNATIONAL C ONFERENCE FOR G REENHOUSE G AS C ONTROL
T ECHNOLOGIES

, K YOTO

, J APAN (2002); Robert P. Hepple & Sally M. Benson, Implications of Surface Seepage on the Effectiveness of Geological Storage of Carbon D ioxide as a Climate Change Mitigation Strategy , S IXTH
I NTERNATIONAL C ONFERENCE ON G REENHOUSE G AS C ONTROL T ECHNOLOGIES , Kyoto, Japan 30 (2002).

42 Sally Benson et al., Underground Geological Storage

, in IPCC S PECIAL R EPORT ON C ARBON D IOXIDE C APTURE

AND S TORAGE

, supra note 6, at 196-276.

43 Elizabeth J. Wilson & David Gerard, Geologic Sequestration Under Current U.S. Regulatio ns, in C ARBON C APTURE AND S EQUESTRATION : I NTEGRATING T ECHNOLOGY

, M ONITORING

, R EGULATION 169-93 (Elizabeth J. Wilson & David Gerard, eds. 2007).

44 In several modeling simulation studies, complete d issolution of the CO 2 in the formation water is predicted on the order of 5,000-100,000 years, depending on the form ation. See Erik Lindeberg & Per Bergmo, The Long-term Fate of CO 2 Injected Into an Aquifer, S IXTH I NTERNATIONAL C ONFERENCE ON G REENHOUSE G AS C ONTROL
T ECHNOLOGIES

, K YOTO , Vol. I, 489-94 (John Gale and Yoichi Kaya eds. 20 03); J. Ennis-King, & L. Paterson, Rate of Dissolution Due to Convective Mixing in the Unde rground Storage of Carbon Dioxide, in S IXTH I NTERNATIONAL C ONFERENCE ON G REENHOUSE G AS C ONTROL T ECHNOLOGIES

, K YOTO , Vol. I, 507-10 (John Gale & Yoichi Kaya eds. 2003).
45 See Kay Damen et al., Health, Safety and Environmental Risks of Underground CO 2 Storage – Overview of Mechanisms and Current Knowledge, 74 C LIMATIC C HANGE 297 (2006); S ALLY M. B ENSON ET AL

., L ESSONS
L EARNED FROM N

ATURAL AND I

NDUSTRIAL A NALOGUES FOR S TORAGE OF C ARBON D IOXIDE IN D EEP G EOLOGICAL
F ORMATIONS

, E ARTH S CIENCES D IVISION

, E.O. L AWRENCE B ERKELEY N ATIONAL L ABORATORY

, B ERKELEY , 135 (2002).

46 See Prasad Saripalli et al., Risk and Hazard Assessment for Projects Involving t he Geological Sequestration of

CO 2 , in S IXTH I NTERNATIONAL C ONFERENCE ON G REENHOUSE G AS C ONTROL T ECHNOLOGIES

, supra note 44, at
511-16.10

heave, and even triggering seismic events—though these risks likely wi ll be small with properly managed sites. 47 Experience with remediation of leaking well-bores is well deve loped, 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 CO 2 , including groundwater contamination, surface ecological damage, harm to human health, geologic hazards, and damage from hydrocarbons where CO 2 injection is linked with enhanced oil recovery operations. 49 While the probability of these risks is site specific and e stimated to be low and manageable, ensuring CCS projects project human and environment al 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 CO 2 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 CO 2

. 51
Compared directly with the 1.5 billion tons of CO 2 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 al l of the CO 2 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 f rom Geologic Carbon Dioxide Sequestration Sites, 3 V ADOSE Z ONE J OURNAL 858-866 (2004).

49 Elizabeth J. Wilson et al., Liability and Financial Responsibility Frameworks f or Carbon Capture and Sequestration , W ORLD R ESOURCES I NSTITUTE I SSUE B RIEF 1, 3-4 (Dec. 2007).

50 See U.S. D EPARTMENT OF E NERGY

, C ARBON S EQUESTRATION A TLAS OF THE U.S. AND C ANADA (2006), available

at http://www.netl.doe.gov/technologies/carbon_seq/ref shelf/atlas/index.html , Lawrence J. Speer, DOE Finds Large Capacity for Storing Carbon Dioxide Across U.S., Ca nada , D AILY E NVT

. R EP . No. 60 at A-5 (BNA March 29, 2007). See also E RIC W ILLIAMS

, ET AL

., C ARBON C APTURE

, P IPELINE AND S TORAGE : A V IABLE O PTION FOR N ORTH C AROLINA U TILITIES ?, W ORKING P APER

, N ICOLAS I NSTITUTE FOR E NVIRONMENTAL P OLICY S OLUTIONS AND THE C ENTER ON G LOBAL C HANGE

, D UKE U NIVERSITY (March 8, 2007), available at www.nicholas.duke.edu/institute/carboncapture.pdf

. 51 See Dustin Bleizeffer, State has Vast Capacity for CO 2 Sequestration , C ASPER S TAR T RIBUNE (April 5, 2007).

52 Steven D. Cook, Power Industry Officials Disagree on Future, Feasib ility of Carbon Capture, Storage , D AILY
E NVT

. R EP . No. 186 at A-1 (BNA Sept. 26, 2007).

53 Id.11 TABLE 2 54

RESERVOIR TYPE LOWER ESTIMATE OF
STORAGE CAPACITY (BILLIONS OF TONS OF
CO 2 ) UPPER ESTIMATE OF
STORAGE CAPACITY (BILLIONS OF TONS OF
CO 2 )

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 CO 2 per year from natural gas production projects, with Sleipner and Snohvit in the North Sea injecting CO 2 captured from the produced natural gas deep below the seafloor, and In Salah in Algeri a injecting
the CO 2 into a deep gas formation. 56 The Weyburn enhanced oil recovery project in Saskatchewan injects roughly one metric ton of CO 2 each year and monitors it for storage. The
CO 2 injected in this project is captured from a coal gasification pla nt 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 gover nment’s commitment to large-scale CCS in general. Specifically, in 2005, the U.S. Depart ment of Energy (“DOE”) began an initiative to build the world’s first integrated sequestr ation and hydrogen production research power plant. This project was designed as a $1.5 billion pub lic/private partnership made up of member power companies working with DOE to build the wor ld’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 par tners agreed to provide the remaining 26 percent. 59

54 See supra note 50. Estimated storage capacity for different geological storage sites, including non-economic s ites. These numbers would increase 25% if currently “undi scovered” 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 incl ude 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 W arnings of Possible Restructuring , D AILY E NVT

. R EP . 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 cle an legal title to the site for both the plant and the site for CO 2 injection, it has ready access to plentiful water, and the geolog y of
the site is suitable for CO 2 injection. 61 In January 2008, however, DOE announced that it was withdrawing support for the FutureGen project in favor of supporting m ultiple 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 t hat would allow broader commercial-scale deployment than was envisioned with FutureGen. 63

Putting FutureGen aside, Congress and DOE have been attempting to author ize significant funding for CCS projects across the country. Competin g 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 seque stration partnerships in connection with pilot projects to store 1 million tons or more of CO 2 in deep saline reservoirs to test the feasibility of long-term CO 2 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 t he balance of the funds. In January 2008, DOE funded a fourth project in the Midwest to inject 1 mil lion tons of CO 2 one mile below the earth’s surface within the Illinois basin. 69

Many recognize, however, that such subsidies alone will not be suffic ient to spur commercial deployment. Instead, commercial deployment will f ollow federal and/or state law that establishes regulatory limits on greenhouse gas emissions, coupl ed with a sufficiently high and stable price on CO 2 , which together will provide an incentive for new technology t o meet those limits. 70 For instance, the States of California and Washington have enacte d legislation setting greenhouse gas emission performance standards for electric utilities beginning January 1,

60 Cook & Bologna, supra note 59.

61 Id. See also F UTURE G EN A LLIANCE

, F INAL S ITE S ELECTION R EPORT (Dec. 18, 2007) (discussing FutureGen project, the incentives provided by state and local governments to attract the project, and analysis o f 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

, D AILY E NVT

. R EP . No. 20, at A-1 (BNA Jan. 31, 2008); U.S. Departme nt 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 Carb on Sequestration, Markey Says , D AILY E NVT

. R EP . No. 173 at A-4 (Sept. 7, 2007).

65 DOE Funds Three Large-Scale Projects to Test Feasib ility of Carbon Dioxide Storage , D AILY E NVT

. R EP . No. 196 at A-7 (Oct. 11, 2007).

66 This project is the Plains CO2 Reduction Partnersh ip led by the Energy & Environmental Research Cente r at the University of North Dakota. Id.

67 This project is the Southeast Regional Carbon Sequ estration Partnership. Id.

68 This project is the Southwest Regional Partnership for Carbon Sequestration coordinated by the New Me xico Institute of Mining and Technology. Id.

69 Michael Bologna, Energy Department, Midwest Partners Launch Carbon S equestration Project in Illinois Basin

, D AILY E NVT

. R EP . No. 3, at A-1 (Jan. 7, 2008). The project is a j oint effort by the Midwest Geological Sequestration Consortium, the Illinois State Geolog ical 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 a llow utilities to exempt from their emissions calculations those emissions that ar e injected permanently into geologic formations or otherwise permanently sequestered by ot her approved means. 71 Thus, even more than federal or state financial incentives, it is c aps on greenhouse gas emissions that will explicitly establish a price for CO 2 and will encourage utilities and others to invest in CCS in order to meet those caps.

II. CCS AND L IABILITY FOR H ARM TO H UMAN H EALTH AND THE E NVIRONMENT

The scope, scale, and duration of any full-fledged CCS project wi ll create the potential for liability associated with CO 2 leakage, and other adverse impacts on resources, human health and the environment. This Part focuses on liability for harm associ ated with the post-closure and long-term sequestration of CO 2 , as opposed to liability associated with the operation of the CCS project itself. This Part concludes that the potential liabili ty associated with long-term storage of
CO 2 is an issue which must be addressed, and will be subject to signifi cant debate by federal and state policymakers wishing to encourage CCS deployment. These deba tes 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, s tate and federal governments, and other interested parties.

Before any widespread, large-scale implementation of CCS te chnologies, there likely will be thousands of pages of statutes and regulations governing all aspec ts of the CCS process. This regulatory framework is critical to creating technology and s afety standards to guide development, manage risk, and protect human health and the environment. The int ense 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, st orage, 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 discus sion of the existing environmental laws that may govern the long-term st orage of CO 2

. 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 inj unctive relief in case of harm from the long-term storage of CO 2 . These laws may act as important gap-fillers in any federal regulatory system governing CCS.

71 CA P UB

. U TIL

. C ODE § 8341(d)(5); Wash. Rev. Code Ann. § 80.80.040. See also Rick Valliere, State Lawmakers Briefed on Development of Carbon Capture, Storage I nitiatives , D AILY E NVT

. R EP . No. 151, at A-3 (Aug. 7, 2007) (discussing efforts by legislatures in Texas, Wyomi ng, California, and Maine to provide regulatory app roval for CCS projects and to use CCS technology as an offset in setting caps on greenhouse gas emissions); West ern Governors’ Association, Clean and Diversified Energy Initiative

, available at http://www.westgov.org/wga/initiatives/cdeac/progre ss-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 Compr ehensive 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 cas e of harm without federal government involvement. In this way, these statutes provide potential inc entives 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 enforce ment 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 percept ion 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-r ecovery 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 Conting ency 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 M INN

. L. R EV . 83, 127-28 (2007) (discussing the important role Congress envisioned for citizen enforcement of environmental laws).

76 Id. at 126-27 (discussing difficulties federal governm ent faces in enforcing existing environmental laws and importance of suits by non-federal parties under st atutes and common law to fill the enforcement gap).

77 The term “Superfund” is from the five-year, $1.6 b illion Hazardous Substances Response Trust Fund cre ated to finance cleanups at CERCLA’s inception. See 28 U.S.C. § 9507 (establishing fund). Superfund i s funded by special taxes on oil and chemical companies and other busin esses and supplemented by general revenues, as well as cleanup costs recovered from responsible parties. See S USAN M. C OOKE & C HRISTOPHER P. D AVIS

, T HE L AW OF
H AZARDOUS W ASTE : M ANAGEMENT

, C LEANUP

, L IABILITY AND L ITIGATION § 12.03[3] (2004) [hereinafter
“C OOKE ”].

78 See generally Alexandra B. Klass, From Reservoirs to Remediation, The Impact of CERCL A on Common Law Strict Liability Environmental Claims , 39 W AKE F OREST L. R EV . 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 substanc e”).

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 cas e 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 contam ination resulting from a wide-range of harmful substances.

CERCLA, however, only allows recovery by private parties for m oney 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 i n value to property, personal injury, lost rents, punitive damages, or other damages associated wi th contamination of property
or the environment. 85 By contrast, some state superfund statutes, such as those in Ala ska, Minnesota, and Washington, allow recovery for personal injury, lost profits , diminution in value to property, attorneys fees, expenses, or other losses stemming f rom the contamination of property or harm to human health and the environment. 86

In order for CERCLA to apply to any releases of CO 2 , however, the stored CO 2 must be a
“hazardous substance.” CERCLA defines a hazardous substance as incl uding any substance designated as hazardous by EPA under CERCLA and/or various other environm ental statutes such as the Clean Air Act, the Clean Water Act, and the Solid Wa ste Disposal Act. 87 As CO 2 is non-toxic at low concentrations and is not a listed waste, CERCLA l ikely does not apply to
current CO 2 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 a re 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 cove r stored
CO 2 if it was classified as a “commodity” rather than a was te. 89 Most important, CERCLA does
not define CO 2 as a hazardous substance and neither does any other federal environment al

statute.

While CERCLA (and most state analogs) do not appear to cover C O 2 , 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 criti cal 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 numbe r of potential defendants

84 See 42 U.S.C. § 9607(a). See also R OBERT V. P ERCIVAL ET AL

., E NVIRONMENTAL R EGULATION : L AW

, S CIENCE

, & P OLICY 370-71 (5 th ed. 2006) (discussing retroactivity of CERCLA’s li ability provisions).

85 Klass, supra note 78, at 923.

86 See, e.g., A LASKA S TAT . § 46.03.422(a), 46.03.824, and 46.03.822(m) (allo wing cost recovery and broadly defined damages as well as costs of containment and cleanup in connection with the release of hazardou s substances); M INN

. S TAT . §§ 115B.05, 115B.14 (allowing recovery for person al injury, lost profits, diminution in value to property and other damages associated with the release of hazardous substances as well as rea sonable costs and attorneys fees); W ASH

. R EV

. C ODE § 70.105D.080 (allowing recovery of expenses and r easonable attorneys fees in connection with cost recovery actions).

87 See 42 U.S.C. § 9601(14) (defining “hazardous substanc e”).

88 See id

. See also Klass, supra note 78, at 937 & n.139 (discussing CERCLA’s petro leum exclusion).

89 See M. S TUART M ADDEN & G ERALD W. B OSTON

, L AW OF E NVIRONMENTAL AND T OXIC T ORTS 627-28 (3 rd ed. 2005) (discussing lack of CERCLA coverage for usefu l products); infra note 102 and accompanying text (discussing efforts to classify stored CO 2 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 si gnificant contamination but those companies or individuals responsible for the contamination were lon g 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 def endants. 92

There are some obvious differences and similarities between the goals of CERCLA and the realities of a CCS regulatory regime. First, there wi ll undoubtedly be many more safeguards in place in connection with the injection and storage of CO 2 than there were with regard to the handling and disposal of hazardous substances in the decades prior to CERC LA. Thus, there may be no immediate concerns with regard to orphan sites. On the other hand, CCS operators envision storing CO 2 for hundreds of years, which means that harm may not occur until long after the original operators are gone. Likewise, even if re gulatory safeguards are created, unforeseen long-term problems associated with the storage CO 2 in these amounts raises significant uncertainty with regard to the success of any regulatory struc ture.

In sum, CERCLA is probably a crude tool to apply directly to CCS operators, par ticularly in light of the fact that CO 2 is not inherently the type of “hazardous substance” Congress envisioned when it enacted CERCLA. Nevertheless, a federal liabi lity statute tailored to CCS that includes some of the signature elements of CERCLA (creat ion 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 liabi lity model were applied to the long-term storage of CO 2 , public and private actors that suffer injury would be able to take advantage of strong liability and funding provisions t o 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” regula tory system for identifying, listing, and tracking hazardous wastes; setting sta ndards for the generation, handling,

90 See P ERCIVAL

, supra note 84, at 429-30 (discussing “orphan” shares und er CERCLA); Klass, supra note 78, at 926-27 (discussing legislative history of CERCLA wh ich justified “the need for federal legislation to address what was seen as a major crisis of abandoned hazardous w aste facilities.”).

91 See M ADDEN & B OSTON

, 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 l iability 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 b efore a cleanup begins on the property. See infra notes 143-150 and accompanying text (discussing st atutes of limitation for common law claims).

93 42 U.S.C. §§ 42 U.S.C. §§ 6901-6992k. RCRA is som etimes also referred to as the Solid Waste Disposal Act, the name of the federal law governing solid waste issue s prior to the RCRA amendments to that Act in 1976. RCRA was substantially revised in 1984 by the Hazardous and Solid Waste Amendments. See P ERCIVAL ET AL

., supra note 84, at 317.17

storage, and disposal of hazardous wastes; and assisting states wit h the management of solid
wastes from active facilities. 94 Section 7002 of RCRA authorizes suits by any person to restra in anyone who has contributed or is contributing to the past or present handli ng of any solid or hazardous waste that may present an imminent and substantial endangerm ent 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 r elief to address contamination as well as attorneys’ fees and expert costs resul ting from the disposal of solid or
hazardous wastes. 97 In such a suit, the plaintiff need not establish an emergency si tuation but only that there is a reasonable prospect of potentially serious ha rm. 98 Relief can include an order that the defendant is responsible for site investigation, monitoring, tes ting costs, cleanup costs and an order barring further endangerment but does not include money damag es, such as the plaintiff’s past cleanup costs. 99

RCRA’s provisions thus may provide liability for harm arising fr om the long-term storage of CO 2 if stored CO 2 is determined to be a solid or a hazardous waste and may also impose stringent handling, storage, and disposal requirements on the C CS process. RCRA defines solid waste as including “any garbage, refuse, sludge f rom a waste treatment plant, water supply treatment plant, or air pollution control facility and other disc arded 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 CO 2 in connection with CCS operations because the CO 2 is arguably “discarded material,” is in “gaseous” or “liquid” form, and results from indust rial or commercial activities. It is possible that EPA will exclude CO 2 from the definition of solid waste (as it has done for domestic sewage, certain mining wastes, and certain nuclear ma terials covered by other laws), or
that the stored CO 2 can qualify for a recycling exemption if it is seen as bei ng 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 CO 2 as a “commodity,” thus avoiding a classification as a “waste” and bring ing it outside the scope of
RCRA. 102 Without such actions by EPA, however, it is likely that stored CO 2 meets the
definition of a solid waste.

94 See P ERCIVAL 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 attorney s fees and expert fees to prevailing party).

98 See Maine People’s Alliance v. Mallinckrodt, Inc., 471 F.3d 277 (1 st Cir. 2006) (noting the courts have liberally construed the term “imminent and substantial endang erment” 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 P ERCIVAL

, supra note 84, at 329-31 (discussing RCRA solid wastes a nd exclusions from the definition of solid waste); Moore, supra note 8, at 471-72 (discussing same in context of s tored CO 2 and noting that EPA and the courts have determined that injected CO 2 does not qualify for the natural gas exemption to RCRA).

102 See, e.g., Kipp Coddington & Bob Reynolds, Carbon Dioxide Poised for a Comeback , A MERICAN C OAL , Issue 2, at 58-59 (American Coal Council 2006) (discussing w hat “label” to place on CO 2 stored or injected for hydrocarbon18

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 l ist of hazardous wastes; (3) is a waste mixed with a listed waste (“mixture rule”); or (4) i s a waste “derived from” a listed waste (“derived from rule”). 103 CO 2 is not a listed hazardous waste and it seems unlikely that CO 2 alone would be considered a hazardous waste, although co-injection with othe r waste stream constituents (e.g. hydrogen sulfide (H2S) could cause it to be defined so. It is also possible EPA
would exclude stored CO 2 from the definition of hazardous waste, as it has done with inciner ator ash and, more applicably, for wastes produced during the exploration, devel opment, and production of crude oil, natural gas, and geothermal energy. 104

Although there remains significant regulatory uncertainty with r egard to the status of
stored CO 2 under RCRA, without specific action by Congress or EPA it is l ikely CO 2 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 acc urate, then Section 7002 of RCRA provides a right of action for injunctive relief to compel the remediation of any migration or release of stored CO 2 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 de cades 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 ha rm to human health and the environment resulting from the long-term storage of CO 2

.

B. Recovery for Harm under State Law

In many ways, in comparison to federal environmental statutes, state law, and pa rticularly state common law, has the potential to provide non-federal actors more comprehensive relief from harm related to the long-term storage of CO 2 , 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 Tec hnology Deployment , Conference Proceedings, at 7-8 (proposing model federal legislation that would cre ate a federal insurance program for CCS but requiri ng that states
define CO 2 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 underminin g protection under federal environmental laws).

103 See 42 U.S.C. § 6904(5); P ERCIVAL ET AL

., supra note 84, at 341-45 (discussing hazardous wastes).

104 See P ERCIVAL ET AL

., supra note 84, at 330-31, 347 (discussing and listing EP A exclusion of certain wastes from definition of solid waste or hazardous waste); Regu latory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes, 53 Fed. Reg. 25,446, 25,447 (July 6, 1988). H2S is al so exempted under this provision.

105 Under current regulation, a CO 2 and H2S stream from a hydrocarbon associated proje ct—where the H2S is an exempted waste—would be treated differently than th e 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 (1 st 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 CO 2 . This means that the common law may play a significant role in creating liability for the l ong-term storage of CO 2 . At the same time, however, it is state common law that is most vulnerable to ar guments by industry or federal regulators that Congress should preempt the availability of such cl aims through federal legislation. 109 The potential claims of trespass, nuisance, and strict liabilit y, 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 stat e law claims that could result in liability associated with the long-term storage of C O 2 , we focus on these claims because they provide potentially the broadest scope of relief and will signi ficantly 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 ce ase storage operations or remediate pollution) but they also need not be based on arguments that the defendant br eached a duty of care (negligence) or violated a statute or permit (neglige nce 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 prote ction 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 manage ment.

1. Property rights, fugitive resources, and trespass

As far back as the middle of the 19 th 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 subsur face 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 s torage of CO 2

. 111 While state and federal statutes and regulations will almost certainly creat e 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 statut es.

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 thei r own accord. As a result, early courts often drew analogies to legal doctri nes 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 an d unauthorized invasion of the property of another where the entry is either intended by the defendant, caused b y the defendant’s recklessness or negligence, or th e result of the defendant’s carrying on an ultrahazardous activity. See H ENDERSON ET AL

., T HE T ORTS P ROCESS 380-81 (2003).

111 For a more detailed discussion of the property rig hts associated with injected gas in the context geo logic storage
of CO 2 see Mark A. de Figueiredo, Property Interests and Liability of Geologic Carbon Dioxide Storage, in
C ARBON C APTURE AND S EQUESTRATION

, I NTEGRATING T ECHNOLOGY

, M ONITORING AND R EGULATION 243 (Elizabeth J. Wilson & David Gerard eds. 2007).

112 See O WEN L. A NDERSON ET AL

., H EMMINGWAY O IL AND G AS L AW AND T AXATION 29-30 (4 th ed. 2004).20

that a landowner did not own oil and gas located beneath her land until i t 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 dra ined to other tracts and also discouraged the use of underground storage reservoirs as a safe and ec onomic 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 ana logy 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 circumstan ces the owner of reinjected oil or gas would be liable for trespass or other tort lia bility if the oil or gas migrated and interfered with neighboring property or persons. Generally, if s ubstances 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 w here public policy favors the injection. 115

The cases refusing to find a trespass based on public policy favo ring injection of dry gas or salt water for enhanced oil recovery are particularly instr uctive. 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 t heir property. 116 The supreme court held that there was no actionable trespass because the defend ants had injected the dry gas to obtain secondary recovery of oil and gas resources within an ar ea 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 avoi d 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 i t was injected into the subsurface).

114 See, e.g., Texas American Energy Corp. v. Citizens Fidelity B ank & 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 r etain ownership of injected gas, and that trespass can occur if gas migrates).

115 See West Edmonds Salt Water Disposal Ass’n v. Rosencra ns, 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 exten ded under neighboring property because neighbor could not est ablish 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 publi c policy favoring injection of salt water for secondary reco very of oil); Phillips Petroleum Co. v. Stryker, 72 3 So. 2d 585 (Ala. 1998); A NDERSON 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 CO 2 into the subsurface on a scale that dwarfs today’s current injection of CO 2 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 ana logies 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 CO 2 . What this will look like remains to be seen, but it may be that public policy favoring reducti on of greenhouse gas emissions might weigh in favor of applying liability sparingly a s a common law matter, as has been done in the past with traditional oil and gas operations. Neve rtheless, in a case of significant harm to human health and the environment the sheer volume of injected CO 2 associated with CCS may also cause courts to pause before wei ghing the costs and benefits of
stored CO 2 in the same way as has been done for the injection of CO 2 in connection with traditional oil and gas recovery.

2. Nuisance

While the trespass claims discussed above represent one classi c, property-based tort, nuisance law provides another means for holders of property rights to recover for harm resulting from the long-term storage of CO 2 . Nuisance law is based on the principle that a defendant may not engage in activity that unreasonably interferes with public rig hts or a private party’s interest in land. Nuisance law underlies much of environmental law, and has be en used by private and public parties to obtain injunctive and monetary relief from air, wat er, soil, and noise pollution resulting from industrial and commercial activities such as landf ills, 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 gove rnment) 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 intere st in the private use and enjoyment of land” and may be brought by anyone wit h 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 unreasonab le or (2) unintentional but negligence, reckless, or subject to strict liability becaus e it is an abnormally dangerous activity. 122 An invasion is unreasonable if the gravity of harm outweighs the uti lity of the actor’s conduct or the harm caused by the conduct is serious and the financial burden of compensating

119 See W ILLIAM H. R ODGERS

, J R

., E NVIRONMENTAL L AW § 2.1 at 112-113, 114-15 (2d ed. West 1994) (stati ng that to “a surprising degree, the legal history of the e nvironment has been written by nuisance law” and de tailing the various types of nuisance actions that have been br ought in connection with harm arising from various industrial and commercial activities).

120 See R ESTATEMENT (S ECOND ) OF T ORTS §§ 821B, 821C.

121 See R ESTATEMENT (S ECOND ) OF T ORTS §§ 821D-828 (setting forth principles of private n uisance).

122 See R ESTATEMENT (S ECOND ) OF T ORTS § 822. For a discussion of activities that are co nsidered “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 nuisa nce. 124

Notably, even lawful operations that result in harm to public resourc es 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 wastewate r discharge permit was liable under a private nuisance theory for $2.5 million in damages to nearby potat o 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 injunct ion against a metal tube manufacturer under a public nuisance theory where the defendant’s dum ping of hazardous chemicals resulted in contaminating a subterranean aquifer. 126

In the context of the long-term storage of CO 2 , migrating or leaking CO 2 that harms nearby soil, surface water, groundwater, mineral, or other resour ces, or interferes with human health could constitute either a public or private nuisance. This could r esult in an injunction requiring remediation of any harm caused by CO 2 or preventing the continued storage of CO 2 . It could also result in an award of monetary damages for harm associ ated with the release. Such injunctive or monetary relief could be awarded under a nuisance the ory even if the CCS project or storage area was in full compliance with all federal or sta te 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 CO 2 . Under such a balancing, it may be that the public interest associated with storing CO 2 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 CO 2 owner or operator to bear the risks and at least pay damages for the harm, even if the stored CO 2 is allowed to remain. 128

In sum, harm to human health, the environment, or private property from the m igration or
release of stored CO 2 would seem to fit fairly easily within a public or private nuisa nce framework, barring any Congressional actions to preempt such cla ims as part of federal

123 See R ESTATEMENT (S ECOND ) OF T ORTS §§ 826-27.

124 See R ESTATEMENT (S ECOND ) OF T ORTS § 936 (setting forth balancing factors for injunct ions); D AN B. D OBBS

, L AW OF R EMEDIES § 5.7(2) (discussing judicial discretion in balanc ing benefits and harms in nuisance cases).

125 Tiegs v. Watts, 954 P.2d 877, 883 (Wash. 1998) (st ating that pollution caused by the defendant consti tuted a nuisance even if the state had approved the dischar ge).

126 California v. Campbell, 138 F.3d 772 (9 th Cir. 1998) (upholding lower court injunction findi ng that pollution of subterranean percolating waters caused by dumping o f hazardous chemicals was a public nuisance). See also Denise E. Antolini & Clifford L. Rechtschaffen, Common Law Remedies: A Refresher, in C REATIVE C OMMON L AW S TRATEGIES FOR P ROTECTING THE E NVIRONMENT 23-30 (Rechtschaffen & Antolini eds. 2007) (discussing th eories of private and public nuisance and describing cases in which courts granted injunctions and awarded da mages under nuisance theories for polluting activities).

127 See Michal D. Axline, The Limits of Statutory Law and the Wisdom of Commo n Law, in C REATIVE C OMMON
L AW S TRATEGIES FOR P ROTECTING THE E NVIRONMENT

, supra note 126, at 74-76 (discussing how compliance with federal or state statutes or permits is not a defen se to a common law claim for relief); Alexandra B. Klass , Common Law and Federalism in the Age of the Regulatory Sta te , 92 I OWA L. R EV . 545, 583 & n.215 (2007) (same).

128 See Zhang et al., supra note 48. Remediation techniques can use passive te chniques, vertical or horizontal extraction wells and pumping, though remediation de pends largely on the site geology.23

legislation governing CCS and the storage of CO 2

. 129 Even if a nuisance claim for such harm is possible, however, most courts would balance carefully the benefits of CCS and CO 2 storage against the nature of the harm before finding either that a nuisan ce 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 di d 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 cause s 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 (Sec ond) of Torts. 132

Under Rylands v. Fletcher , a defendant is liable if it engages in a “non-natural” or “a bnormal”
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 act ivity 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 t o the community is outweighed by its dangerous attributes. 134

Courts have held defendants strictly liable for harm to public heal th and the environment
under both Rylands and the Restatement for a broad range of activities that incl ude the release of petroleum or oil that contaminated groundwater, seeping salt wate r from an oil and gas well that contaminated a water supply, the release of toxic and hazardous was tes from industrial operations and disposal facilities, the release of PCBs from a na tural 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. P AGE K EETON ET AL

., P ROSSER & K EETON ON THE L AW OF T ORTS § 75 at 534 (5 th ed. 1984).

131 See Klass, supra note 78, at 907 (citing P ROSSER & K EETON

, supra note 130, § 75, at 536; Mark Geistfeld, Should Enterprise Liability Replace the Rule of Str ict Liability for Abnormally Dangerous Activities , 45 UCLA L.

R EV . 611 (1998); William K. Jones , Strict Liability for Hazardous Enterprises , 92 C OLUM

. L. R EV . 1705, 1712 (1992); Virginia E. Nolan & Edmund Ursin, The Revitalization of Hazardous Activity Strict Lia bility , 65 N.C. L.

R EV . 257, 297 (1987).

132 See Rylands v. Fletcher, L.R. 3 H.L. 330 (1868); R ESTATEMENT (S ECOND ) OF T ORTS §§ 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); P ROSSER & K EETON

, supra note 130, at 545-46 (discussing Rylands case).

134 R ESTATEMENT (S ECOND ) OF T ORTS § 520. See also R ESTATEMENT (T HIRD ) OF T ORTS § 20 (Proposed Final Draft No. 1 2005) (proposing to revise the Restatement of Torts on abnormally dangerous activities to provid e that an activity is abnormally dangerous if it (1) creates a foreseeable and highly significant risk of physic al 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 stri ct liability (or only in narrow circumstances), twenty-one out of twenty-seven jurisdiction s that have squarely considered the issue have applied the doctrine of strict liability t o activities resulting in
environmental contamination. 136

Whether courts will find the long-term storage of CO 2 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 CO 2 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 th e answer different in Texas, where injection of CO 2 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 CO 2 may be significant if it has a measurable impact on reduci ng greenhouse gas
emissions.

As may be evident from these questions, different courts in differe nt jurisdictions may reach widely varying results on whether harm from stored CO 2 is subject to strict liability. This is true, however, for most industrial and commercial activities ar ound the country, with different laws applying in different jurisdictions. While there is an a rgument that CCS and the large-scale storage of CO 2 should be subject to a uniform standard of liability, there is perhaps a more compelling argument that operators should recognize the existence of pot ential strict liability in multiple jurisdictions, and conduct their operations accordingly but wi th 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 the ories discussed above, parties responsible for the long-term storage of CO 2 may be liable for remediation costs, diminution in value to private or public property (i.e., stigma damages), lost profi ts, personal injury, and other damages flowing from harm to human health and the environment. In r ecent years, there have been significant lawsuits against gasoline producers over contaminat ion from the gasoline additive methyl tertiary butyl ether (“MTBE”) which has contam inated 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 ag reed 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 ha rm 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 da mage 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 Taho e—the Long Running Case Will Not Mark a Legal Precedent Because of the Deal, but Wil l Surely Have a Wide Impact , S.F. D AILY J. (Aug. 6, 2002).

139 See Klass, supra note 127, at 596-97 (discussing MTBE lawsuits); Mo ore, supra note 8, at 482-83 (discussing MTBE suits and potential application to contaminati on from storage of CO 2 ).25

Even beyond these high-profile suits, courts are more willing today t o award “stigma” damages arising from property contamination in addition to cleanup cos ts. Environmental “stigma” is defined as an adverse impact on the value of a propert y 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 perce ived as posing a risk of
harm. 141 Although some jurisdictions require some minimal physical impac t 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 thr ough “stigma” simply by being
near contamination. 142 Thus, in most jurisdictions, a subsurface invasion of CO 2 or a release of
CO 2 to the surface that interferes with use of the property will s upport stigma damages while in others, any significant release of CO 2 near the property may suffice so long as the release constitutes a trespass, nuisance, abnormally dangerous activity, or other acti onable 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 w hich a plaintiff may bring a lawsuit for injuries. Because of the long time-frame associ ated with the storage of CO 2 , questions will inevitably arise as to when various causes of ac tion 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 CO 2 is “continuing,” thus allowing the plaintiff to maintain an action or successive actions until the conta mination is remediated. 143
This issue of whether the wrongdoing is “continuing” arises frequentl y in cases of environmental contamination, where the illegal conduct ceased decades ago but cont amination 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 pl aintiff that may continue decades after the wrongful conduct ceases? Many courts and comme ntators have argued that proof of continuing harm supports a claim of continuing trespass which pre vents the statute of

140 See U NIFORM S TANDARDS OF P ROFESSIONAL A PPRAISAL P RACTICE , 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 stigm a damages may be due to fear of potential liability for cleanup costs, potential liability to third parties affecte d by existing or prior contamination, or concerns r egarding the ability to obtain financing for the property) (citing Peter J. Patchin, Valuation of Contaminated Properties , 56 A PPRAISAL 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 st rata by deepwell injectate is not sufficient) with Dealers Mfg ., 615 N.W.2d at 79-80 (finding that stigma may exi st for a property that is merely in proximity to property th at is contaminated because “of the heavy burden on the value of the property due to the perception of risk of liabi lity, or government imposed restrictions on the use or transferability of the property, among other concerns.”).

143 See R ESTATEMENT (S ECOND ) OF T ORTS § 899, cmt. d (stating that a continuing trespass “confers on the possessor of the land an option to maintain a succession of a ctions based on a theory of continuing trespass, or to treat the continuing of the thing on the land as an aggravati on of the original trespass.”); M ADDEN & B OSTON

, supra note 89, at 29-31 (discussing the arguments surrounding the relationship between continuing trespass and statut es 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 h arm, 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 sel ection and operation of a storage area or the improper injection of CO 2 , it may take years or decades for sufficient CO 2 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 br inging a suit. In such a case, whether the wrong is deemed to be continuing is critical to the sc ope 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 continue s 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, w hich can be extremely difficult in
cases where CO 2 or contaminants react with native rock and potentially affect groundwa ter 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 afte r 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 acti on 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 i s not yet aware of the harm. 147
Many states have created statutes of repose in connection with i mprovements to real property, resulting in the extinguishment of claims against asbestos manufac turers or other manufacturers

144 See Nieman v. NLO, Inc. 108 F.3d 1546 (6 th Cir. 1997) (holding that under Ohio law, the statu te of limitations does not expire because the time period has elapsed from the defendant’s last affirmative act of wrong doing but instead continues based on proof of continuing dama ges); Jacques v. Pioneer Plastics, Inc. 676 A.2d 50 4 (Me. 1996) (focusing on the hazardous material that remained o n the site rather than the dumping itself in decidi ng whether the limitations period had run); Hoery v. United States , 64 P.3d 214 (2003) (holding that under Colorado l aw, continuing migration of contaminants and ongoing pr esence of contaminates constitute a continuing tres pass and continuing nuisance rendering the plaintiff’s claim timely); R ESTATEMENT (S ECOND ) OF T ORTS §§ 161(1) and 899 (discussing continuing nature of trespass when defe ndant fails to remove a thing from land that was wr ongfully 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 year s of the last instance of unlawful conduct and a continuing nuisa nce or trespass must be based on “recurring tortiou s or unlawful conduct, and is not established by the continuing o f harmed caused by previous but terminated tortious or unlawful conduct.”).

146 See M ADDEN & B OSTON

, 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 t he statute of limitations. For instance, the New York legislature in 1986 enacted a statute to revi ve expired claims related to exposure to certain toxic substances for one year. 149

In the context of CCS, federal and state legislators can crea te limitations periods, repose periods, or revival periods specific to claims involving stored C O 2 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 citize ns with particular injuries in other cases. In light of the unique concerns associated with CCS clai ms such as potentially long latency periods prior to knowledge of harm and the difficulties in obse rving the movement of CCS underground, existing common law principles associated with statutes of li mitations 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 purpos es, and whether a state statute of repose might apply in the CCS context. This is one are a where there is ample common law precedent on which to draw but where a legislatively-tailore d solution would appear to be superior.

C. Conclusion

This Part illustrates that there is a significant body of f ederal and state law that may apply to claims for harm associated with the long-term storage of CO 2 . The challenges of balancing the benefits of CCS with the potential risks must be weighed both l ocally and within the larger context of climate change. This structure is not and cannot be a subst itute for the adoption of carefully tailored state and federal regulation governing all a spects of the development of CCS. Such CCS-specific laws can consider the unique features of CCS, c reate 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 re levance. 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 C CS 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 frame work in place.

148 Id. at 940-41 (citing cases and discussing challenges to statutes of repose under state constitutions tha t 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 CERC LA provides that the statute of limitations for recovery of response costs does not even begin to r un until the plaintiff begins remediating the prope rty). 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 sta te common law claims for relief. See 42 U.S.C. § 9658 (imposing a “federally required commencement date” for state la w causes of action defined as the date the plaintif f knew or reasonably should have known that the personal inju ry or property damages were caused or contributed b y the hazardous substance, pollutant, or contaminant).28

III. S TATUTORY D EVELOPMENTS

, C OMPETITION

, AND THE S PECTER OF THE “R ACE

- TO

- THE

- B OTTOM ”

No federal or state program currently regulates CCS and rel ated storage of CO 2 , although
CO 2 storage projects may now be permitted pursuant to a March 2007 EPA Guidance Memorandum under EPA’s Underground Injection Control (“UIC”) Program cr eated under the Safe Drinking Water Act of 1974. 151 EPA has begun the process of developing regulations on the injection of CO 2 under the UIC program. 152 Federal and state legislators, however, are keenly aware of the importance of defining property rights and tor t liability in advance of implementing CCS and the long-term storage of CO 2 . Although little has been enacted thus far, recent efforts to do so are instructive and show recognition of the i mportance of tort liability in the development of this new technology. As shown below, much of this le gislation attempts to significantly limit project operators’ liability for long-term storage of CO 2 , raising the issue of whether a “race-to-the-bottom” mentality may influence the a bility 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 liabilit y for harm associated with the long-term storage of CO 2 . For instance, in 2006, the U.S. House of Representatives considered a bill to authorize and appropriate funds for the FutureGen project 153 “to demonstrate the feasibility of the commercial application of advanced clean coal energy technology, including carbon capture and geological sequestration, for electricity generat ion.” 154 One of the failed amendments to that bill was to allow the Secretary of the Depa rtment of Energy to “indemnify the consortium and its member companies for liability associate d 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 intenti onal 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, Illi nois and Texas, were in keen competition for the project which would bring cutting-edg e 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 legislati on 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 Undergroun d Storage of Carbon Dioxide , D AILY
E NVT

. R EP . No. 232, at A-11 (BNA Dec. 4, 2007).

153 See supra notes 59-63 and accompanying text (discussing Futu reGen project and DOE decision in January 2008 to withdraw support for the project in favor of oth er commercial CCS projects).

154 See Energy Research, Development, Demonstration, and C ommercial 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 Re search, Development, and Demonstration Act of 2007, H.R. 1933 (April 18, 2007) (bill to amend the Energy Policy Act of 2005 to reauthorize and im prove the carbon capture and storage research, development, a nd demonstration program of the Department of Energ y).

157 See supra note 60 and accompanying text.29

site, including offering freedom from tort liability through statut ory indemnification and transfer of property rights in CO 2 . For instance, Texas enacted legislation in 2006 providing that the state would acquire title to carbon dioxide captured by a clean coal proce ss, thus releasing the owner of the project from any liability after capture of the CO 2

. 158 In 2007, additional bills were introduced in the Texas legislature to strengthen those indemnificati on provisions and make clear that “once the State of Texas assumes ownership of CO 2 , 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 becaus e 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 enacte d legislation to offer liability protections similar to those enacted in Texas in order to “comp ete” with Texas and put Illinois “on an even playing field.” 161

Specifically, the Illinois legislation provided that if the FutureG en project was located in Illinois, Illinois would take title to injected CO 2 , would obtain at its own expense insurance from private carriers against loss from stored CO 2 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 ca ses of intentional or willful misconduct by the Operator or if the loss stemmed from the Opera tor’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 Futur eGen 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 arti cles on environmental regulation, the initial push for statutes and regulati on providing minimal federal environmental standards in the 1970s was believed to be necessary to pre vent 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 T EX

. N AT

. R ES

. C ODE 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 Ac t); See also Kate Clemens, Illinois Senate Passes Bill to Help Land FutureGen Plant , T HE N EWS -G AZETTE (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 incentive s and noting that “all the candidate sites
came with financial inducements from state and loca l governments.”).

165 See P ERCIVAL ET AL

, supra note 84, at 104 (explaining the “race-to-the-botto m” rationale and citing scholarly debates on the subject); Kirsten H. Engel, State Environmental Standard-Setting: Is There a “R ace and Is It “To The Bottom,” 48 H ASTINGS L.J. 271, 283 (1997) (stating that the “race-to-the -bottom” in the debate over federal environmental standards refers to a lowering of sta te environmental standards that also results in a l owering in net social welfare).30

evidence that states will reduce environmental protections to attra ct business. 166 They point to state innovation in the environmental protection field that was in pla ce 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 environment al 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) e nvironmental standards that will cover a wide range of industries (the power industry, the auto industry, manuf acturing) 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 t o a host of issues including taxes, land availability, and geography in addition to potential liabil ity. Notably, prior to the potential sites being narrowed to those in Illinois and Texas, Kentuc ky 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 int ense competition to be selected as the site, as was the case with FutureGen. For instance, the cur rent 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 feder al lawmakers to ensure that any regulatory structure governing t he long-term storage of CO 2 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 hi story of adopting more protective regulations. California currently serves as such as e xample, 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 a ir, 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 Re gulation: A Response to the

Critics , 82 M INN

. L. R EV . 535, 540-42 (1997) (rejecting a “race-to-the-bott om” rationale as a justification for federal environmental standards). See also Klass, supra note 127, at 579-84 (discussing recent state effor ts 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 C hoice Analysis , 115

H ARV

. L. R EV . 553, 579-85 (2001) (rejecting proposition that th e states are not effective bodies to enact and implement environmental standards and providing pas t and current examples).

168 See Kentucky General Assembly Passes Bill Aimed at Attracting “FutureGen” to the State , G LOBAL P OWER
R EPORT (March 30, 2006).

169 See Steven D. Cook, DOE Pulls Support for FutureGen Project, Will Fund Carbon Capture at Multiple Sites , 39

E NV

. R EP . 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. R EV . 1547 (2007) (arguing that the risks of regulatory failure argue for federal standards setting a regulatory floor but not a regulatory ceiling); Rob ert L. Glicksman, From Cooperative to Inoperative Federalism: The Perverse Mutation of Environmental Law and Poli cy , 41 W AKE F OREST L. R EV . 719 (2006) (exploring31

Although there has been some recognition of this problem in recent lit erature, its solutions fall short of what may be needed to ensure sufficient com pensation for public and private harm from the release of CO 2 . For instance, the “Coalition for Commodity CO 2 ,” has prepared model legislation to create a federal insurance progr am for the long-term storage of
CO 2

. 171 The legislation proposes that the federal government require state s to create minimum standards for the injection and storage of CO 2 in order to participate in the federal insurance

program. 172 Beyond requiring those minimum state standards (and it is not cle ar what types of standards would meet the minimum) and creating the federal insuranc e 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 suc h 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 contai ns as a requirement for participation in the federal insurance program that the state de fine CO 2 as a “commodity” rather than a “pollutant” or “waste” to avoid “unlimited” and “unfounded” envi ronmental 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 t o require states to create a regime that makes it impossible for federal or st ate environmental pollution laws to apply, particularly when the potential impacts of long-term stora ge of CO 2 remain uncertain and will continue to remain uncertain for decades. Thus, the potential f or a state race-to-the-bottom is real, and will likely require significant federal participa tion in creating substantive standards for CCS technology.

B. Liability and Federal Preemption

All of the federal and state CCS legislation introduced and e nacted to date recognizes the significance of existing liability standards that may underl ie 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 sta te governments, and has massive start-up costs. Under those circumstances, policymakers a re rightly attempting to do significant work in advance to allocate rights and determine who wi ll be responsible for liabilities associated with CCS projects and the long-term st orage of CO 2 . Nevertheless, there is a level of nuance that appeared to be missing from the efforts of Il linois, Texas and their respective lawmakers to provide extremely broad indemnity provisions for liability associated with the long-term storage of CO 2 . 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 answe r.

developments in environmental law at federal and st ate levels and arguing that the federal government has failed to fulfill its mandate to protect the environment by i ts unwillingness to exercise its own power to promo te environmental protection and also limiting the powe r of states to combat environmentally destructive a ctivities).

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 classif ying CO 2 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 Cong ressional or agency action enacting statutes and rules on CCS and CO 2 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 discus sed in Part V, such an approach should ultimately take into account the stage of CO 2 storage (more risk during the injection and closure period than in post-closure period means more operat or contribution to pooled funding) as well as the location of CO 2 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 fra mework, 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 inc entives for CCS site selection and
management.

At the present time, the trend often appears to be otherwise. In r ecent years, industry and federal agencies have relied heavily on the existence of federa l standards in the health and safety area to argue to courts that state tort claims to recover f or 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 stat e 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 Fe deralization of Tort Law

, 56 D E P AUL L. R EV

. 227 (2007) (describing recent efforts by federal pu blic health and safety agencies such as the U.S. Food and Drug Administration, the National Hig hway Transportation Safety Board, and the Consumer Product Safety Commission to achieve preemption of state re gulations 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 plaint iff injured by medical device could not bring a “fr aud-on-the FDA” claim against drug manufacturer consultant bec ause the FDA’s regulatory framework for policing fr aud preempted attempts to have a state court jury deter mine such fraud); Sprietsma v. Mercury Marine, 537 U.S. 51 (2002) (holding that Federal Boat Safety Act did no t expressly or impliedly preempt common law claims for damages against boat manufacturer for failure to eq uip boat engine with propeller guard); Geier v. Ame rican 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 clai ms for damages against manufacturer of product that was approved through the Section 510(k) streamlined app roval process); Hillsborough v. Auto. Med. Labs., 4 71 U.S. 707 (1985) (FDA regulations establishing minimum st andards for the collection of blood plasma did not preempt a county’s local ordinance governing blood plasma cen ters). See also Alexandra B. Klass, State Innovation and Preemption: Lessons from Environmental Law , __ L OY

. L.A. L. R EV . __ (forthcoming 2008) (surveying preemption cases involving public health, safety, and environm ental statutes and citing articles discussing recen t trends in the law).

177 See Reigel v. Medtronic, __ S. Ct. __ (U.S. Feb. 20, 2 008) (holding that common law tort claims concernin g a medical device that has undergone “pre-market appro val” under the 1976 Medical Device Act Amendments t o the Food, Drug, and Cosmetic Act are state “requirement s” 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 stat e 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 p reemption33

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 (expre ssing 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 fe deral legislation to govern many aspects of the CCS process in addition to whatever legislation is enac ted at the state level. If and when Congress considers such legislation, there undoubtedl y will be arguments by industry, and perhaps federal agencies, that any such legislation shoul d 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 legis lation, 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 liabili ty and insurance frameworks to create a reasonable certainty of investment without compromisi ng public health, safety, and environmental protection. Additionally, such frameworks can be structure d to enhance incentives for proper site selection and management for CCS projects. Ensuring t hat 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 pree mption of state law product liability claims agains t prescription drug manufacturer).

178 The doctrine of federal preemption is based in the Supremacy Clause of the U.S. Constitution which st ates that “This Constitution, and the laws of the United Stat es which be made in pursuance thereof; . . . shall be the supreme law of the land; and the judges in every state shal l be bound thereby, anything in the Constitution or laws of any States to the contrary notwithstanding.”). U.S. C ONST

. 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 App roach , 76 G EO

. W ASH

. L. R EV

. (forthcoming 2008) (discussing how much deference c ourts 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); P ERCIVAL

, supra note 84, at 104 (“Preemption of state law has been employed spa ringly in the federal environmental laws” and is ge nerally reserved for regulation of products that are distri buted 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 playe r 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 preempt ion language but also on the important role tort law plays in society. The Court recognize d that state tort law serves an important role in aiding the exposure of new dangers associated wit h 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 t he long-term storage of
CO 2 , 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 pr ivate parties who may be harmed have recourse through the environmental and tort liability sy stem rather than solely being accountable to government regulators. 184

In sum, the development of CCS presents critical concerns of own ership, 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 envir onment. The answer to these issues is not to eliminate existing liability framewo rks. 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 t he same time create a market for insurance and other risk-pooling opportunities to allow predictabilit y for stakeholders. Possible approaches to this issue are discussed in Parts IV and V.

IV. M ECHANISMS FOR E NSURING F INANCIAL R ESPONSIBILITY AND M ANAGING L IABILITIES

The previous Parts of this Article make the case for retaining the existing liability protections environmental statutes and the common law provide. We recog nize, 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 m echanisms for ensuring financial responsibility and managing potential liabilities. Spec ifically, we explore bonding, insurance, damage caps, and federal funds which exist for other environme ntal and complex large-scale technologies and consider their potential effective ness for CCS. We conclude that these potential solutions in combination hold promise for CCS development a nd 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-closur e 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 liabili ty 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 t ime-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 struc tures 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 a nd benefits of common law in optimizing the protection of human health and the e nvironment).35

risks over the long term. Such structures will likely be temporally segment ed, with responsibility passing from private firms to public management for long-term ste wardship. 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 projec ts becoming an unfunded public mandate.

For CCS, augmenting statutory and common law liability within suc h 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 abili ty to detect and assign blame for harm; 187 (2) the potential lack of necessary resources for firms inje cting CO 2 to address potential harms; and (3) the time horizon between cause (injection of CO 2 ) and effect of any damages. 188 As a result of these shortcomings, we turn to different approac hes that can both supplement liability frameworks and also provide a compensation mechanis m in cases where liability is imposed. 189

B. Bonding

As a financial assurance mechanism, bonding is a potentially import ant 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, tra nsport of hazardous waste, underground injection and disposal, and others. Bonding allows for t he 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, o r 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. Additi onally, 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 differe nt stages of operator liability during the CCS life -cycle.

186 See IOGCC, supra note 8, at 11; Christina Ulardich , Environmental Impairment Liability Insurance for Geological Carbon Sequestration Projects

, in I NTERNATIONAL R ISK G OVERNANCE C OUNCIL WORKSHOP ON
R EGULATION FOR CCS (March 2007), available at http://www.irgc.org/IMG/pdf/IRGC_CCS_SwissRe07.pdf

. 187 This could be especially important given the multi ple effects of CO 2 in the subsurface, latency between injection and harm, and challenges in proving a causal link b etween CO 2 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 CO 2 , E NVIRONMENTAL S CIENCE AND T ECHNOLOGY 39(24): 499A-505A (2005).

188 See David Gerard & Elizabeth J. Wilson, Environmental Bonds and the Challenge of Long-Term Carbon Sequestration , __, J. E NVTL

. M GMT . __ (forthcoming 2008); Steven Shavell, Liability for Harm Versus Regulation of Safety 13 J. L EGAL S TUDIES 357-74 (1984); A. H. Ringleb & S.N. Wiggins, Liability and Large Scale, Long Term Hazards , 98 J. P OL

. E CON . 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 cos ts, and becomes more costly as complexity increases. A problem for both liability rules a nd bonding is the potentially long lag time between the operators’ activity (injection of CO 2 ) and the potential harm (leakage to the surface or resource damage). Also, over long time horizons, the re sponsible firm may go out of business, or surety providers are unlikely to underwrite bonds with such unc ertainties. Thus, for bonding to be effectively utilized within CCS projects regulators m ust 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 l ikely 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 s ite reclamation and to ensure proper closure of underground injection wells. In both contexts, bond us e is wellestablished and experience highlights both the benefits and potential pitfalls of bonds

For mining, regulations often require post-mining site reclamati on. 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 Depart ment of Interior (Bureau of Land Management) or Department of Agriculture (Forest Servic e) 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, sma ll firms may face premiums of 15 to 20 percent or higher. 199

Bonding is also used in underground injection. All injection wells reg ulated 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 hel p ensure proper site closure. In the UIC program, an operator must submit a well clos ure and abandonment plan that

192 See generally Robert Costanza & Charles Perrings, A Flexible Assurance Bonding System for Environment al Management , 2 E COLOGICAL E CONOMICS 57-75 (1990).

193 See generally Jason F. Shogren, et al., Limits to Environmental Bonds , 8 E COLOGICAL E CONOMICS 109-133 (1993).

194 See James Boyd, Financial Responsibility for Environmental Obligati ons: Are Bonding and Assurance Rules Fulfilling Their Promise?, R ESEARCH DISCUSSION PAPER RFF-DP-41-02, R ESOURCES FOR THE F UTURE (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 R ESOURCES P OLICY 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 an d abandonment, in the vast majority of cases no long-term monitoring is r equired 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 jurisdicti ons. 202

For bonding to be effectively used for long-term stewardship in a C CS project, several conditions would need to be met: (1) the time frame that the bond would cove r must be clearly established; (2) the party responsible for damages must be identif ied; 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 regulat ory requirements. Key decisions that will determine the role of bonding are linked to the ope rator’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 performanc e-based post-closure care period. For maximum effectiveness, bonding amounts should be set in a f ashion that reflects differences in site-specific risk and operator performance da ta. For example, the future CCS bond amount could be linked to the site environmental impact statement, oper ational performance data (like CO 2 plume stabilization) and the site monitoring plan, as well as potent ial 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 t he 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 event s 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 inc entive to cause loss. 206
CCS might violate several of these conditions: (1), (2), and (4) gi ven both the lack of experience with large-scale CCS and inherent geologic heterogeneity; a nd (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 R ISK AND
I NSURANCE 651-674 (1978); Martin T. Katzman, Pollution Liability Insurance and Catastrophic Envi ronmental
Risk , 55 J. OF R ISK AND I NSURANCE , 75-100 (1988).

204 Katzman, supra note 203, at 82, 94.

205 See Kenneth S. Abraham, Environmental Liability and the Limits of Insurance

, 88 C OLUM

. L. R EV . 942, 949 (1988).

206 Id. at 83.38

CCS storage. That said, in a recent meeting held by the Interna tional 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 CO 2 to the atmosphere. 207

The development of environmental impairment liability (EIL) addres ses many of these factors by considering specific site-by site policy coverage (unlike Comprehensive General Liability—which is general), and is a relatively recent insura nce 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 clai ms 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, def ense of liability, and other types of claims. 209

Some argue that the role of government, both as insurer and risk mana ger 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 predictabi lity of the tort process, undermined by the large damage awards from hazardous chemical e xposure 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 d uring the postsite closure phase, where the operator is actively involved in monitori ng, 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 t he 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 pot entially 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 s ome 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 d amages available from the fund. Congress has created these types of specialized funds to displa ce the standard tort process for

207 See I NTERNATIONAL R ISK G OVERNANCE C OUNCIL

, W ORKSHOP R EPORT ON R EGULATION OF C ARBON C APTURE AND S TORAGE 19 (March 15-16, 2007), available at http://www.irgc.org/IMG/pdf/Workshop_Report_Regulat ion_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 sam e 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 th ey are necessary to manage uncertain risks, protect industry from larg e jury awards and unnecessary lawsuits and provide a climate for private investment while stil l 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 indus try, 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 dam age 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 CO 2 sequestration.

While the nature of risks from CCS and nuclear power are fundamenta lly 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 mana gement 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 provisi on 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 v ictims funded by an excise tax on each dose of vacc ine). See
also Robert Rabin, The Renaissance of Accident Law Plans Revisited , 64 M D

. L. R EV . 698, 706-07 (2005) (discussing federal childhood-vaccine injury progra m).

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 , S CHWARTZ ET AL

., P ROSSER

, W ADE & S CHWARTZ ’ S T ORTS 1191-95 (11 th ed. 2005) (discussing general features of state workers’ compensation law s as providing employees automatic entitlement to c ertain benefits when she suffers workplace injuries, the i rrelevance of fault, a set of cash and medical bene fits, waiver of the right to sue the employer in tort, administrati on of claims by a state commission, and a requireme nt that the employer secure private insurance, state-funded ins urance or self-insurance; F RANKLIN ET AL

., T ORT L AW AND A LTERNATIVES 816-29 (8 th ed. 2006) (discussing generally state workers’ com pensation laws).

216 See Dan M. Berkovitz, Price-Anderson Act: Model Compensation Legislation? —The Sixty-three Million Dollar Question , 13 H ARV

. E NVTL

. L. R EV 1, 2 (1989).

217 Id. at 58; A MERICAN N UCLEAR S OCIETY

, T HE P RICE A NDERSON A CT : B ACKGROUND I NFORMATION (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 s hould bear he costs of damages resulting from the accident.”); Daniel W . Meek, Nuclear Power and the Price-Anderson Act: Promotion over Public Protection, 30 S TAN

. L. R EV . 393 (1978).

219 See 10 C.F.R. § 140.

220 Anderson, supra note 203, at 651.

221 See U.S. G ENERAL A CCOUNTING O FFICE (“GAO”), N UCLEAR R EGULATION : NRC’ S L IABILITY I NSURANCE
R EQUIREMENTS FOR N UCLEAR P OWER P LANTS O WNED BY L IMITED L IABILITY C OMPANIES 4-6 (2004), available at http://www.gao.gov/new.items/d04654.pdf .; F RANKLIN ET AL

., supra note 215, at 870 (stating that the Act’s express40

as a subsidy to the nuclear industry, Price-Anderson began by limi ting 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 liabi lity. 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 Ande rson 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) f rom Congress using public
monies. 226 In the event of an accident with damages surpassing the total, the NRC would pre pare a report for Congress and the Courts estimating the damages. 227 The Act indemnifies licensees from any amount over the liability cap 228 and, since amendments in 1988, any nuclear incident— not just extraordinary nuclear occurrences—would fall under the juri sdiction 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, dive sted 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 s tandards set fort in the 1988
Amendments. 231

To date, the Price-Anderson fund has paid out a total of $202 mill ion (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 other wise be the case, and may, in

intent “was to encourage investment in nuclear ener gy research and operations by a private sector daun ted 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 prot ection 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 substantiv e rules for decision in public liability actions shall be deriv ed from state law unless state law is inconsistent with the Act).

231 See O’Connor v. Commonwealth Edison Co., 13 F.3d 1090 (7 th Cir. 1994) (discussing 1988 Amendments to Price-Anderson Act and finding federal preemption o f 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 (3 rd Cir. 1991) (holding Price-Anderson Act preempts st ate law tort claims that are not consistent with federal law). But see Cook v. Rockwell Int’l, 273 F. Supp.2d 1175 (D. Co lo. 2003) (holding that federal nuclear safety regulati ons did not preempt state standards of care in publ ic liability actions); In re Hanford Nuclear Reserv. Litig., 350 F. Supp.2d 871 (holding that the Act does not requ ire that federal safety standards establish the standard of care and preempt state tort remedies, including state law c laims for strict liability).

232 GAO, supra note 221, at 5; J OHN D EUTCH ET AL

., MIT S TUDY ON THE F UTURE OF N UCLEAR P OWER 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 deplo yment, protecting human health and the environment, and balancing the role of state and feder al law played out under the Price-Anderson Act provides several points for discussion. F irst, unlike nuclear activities, the potential of a catastrophic accident from CCS proj ects 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 tier ed structure of site and industry responsibility would allow for funds to be availabl e 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 insta nce, 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 the me 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. A s CCS projects are likely to be large and given that water and mineral resources are fundame ntal to other state interests (agriculture, urban development, industry, tax revenues, and others), CCS ope rators will lobby strongly in Congress (and later in the courts) that federal l aw should preempt state law claims for damages and perhaps federal environmental laws. For the reasons s tated in Part III, the existing state and federal liability framework provides important safe guards for potential harm associated with CCS. Thus, federal legislation should include clear languag e to preserve state and federal bases for liability and instead focus on limiting operator liabil ity 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 credibilit y of CCS in the eyes of the public. When CCS-proponents expound on the safety of the technology while simultane ously lobbying for a damage cap, this contradictory position undermines CCS credibili ty. 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 federa l funding.

233 D EUTCH 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 abil ity of claimants to seek damages beyond funding limits from responsible parties through the tor t 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 syste m provides information analogs for CCS for at least two reasons. First, the OPA r econciles 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 cla ims in case of harm but allows claimants to seek damages in excess of the fund’s maxi mum 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 rel evant for CCS.

Passing the Trans-Alaska Pipeline Authorization Act of 1976 (“TA PPA”) 237 involved compromise—reconciling the interests of environmentalists, native Al askans, 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 (“T APL Fund”). 239 Under TAPPA, if the incident occurred on water, claimants could recover under stric t 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 sourc es of federal or state
law. 241 If negligence or unseaworthiness of the vessel caused the s pill, the TAPL Fund obtained subrogation rights associated with payment of the claims and was e ntitled 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 dol lars to other injured parties, and Exxon ultimately reimbursed the TAPL Fund for those amount s. 243

In 1990, as result of the Exxon Valdez spill, Congress enacted s ignificant amendments to the Oil Pollution Act (“OPA”) and brought the TAPL Fund within the j urisdiction 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 O STLF. 245 Under the OPA,

237 43 U.S.C. §§ 1651 – 1655; 61 A M

. J UR . 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.2 d 577, 581 (9 th Cir. 1991).

243 See Chenega Corp. v. Exxon Corp., 991 P.2d 769, 791-92 (Ala. 1999).

244 See F RANK P. G RAD

, 2 E NVIRONMENTAL L AW § 3.03[i] (2007) (detailing impact of 1990 Oil Pol lution Act on TAPPA and TAPL Fund).

245 See 26 U.S.C. § 9509 (amendment to Internal Revenue Co de creating OSTL and setting $1 billion per inciden t limit). See also U.S. Coast Guard, Oil Pollution Act of 1990 (discu ssing funding and noting that the Energy Policy At of 2005 raised the limit of the OSLTF to $2.7 bi llion), available at www.uscg.mil/hq/npfc/About%20Us/opa.htm ; U.S. Coast Guard, Oil Pollution Act (OPA) Frequen tly Asked Questions (stating that Energy Policy Act increased funding for the LSLTF by re-instating the 5-cents- per-barrel tax43

the responsible party is liable for payment of damages up to a certain amount base d on the size of the vessel, up to a maximum of $350 million per spill at onshore facili ties 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 re source damages, damage to real or personal property, other economic losses, lost profits, and l oss 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 subd ivision from imposing additional liability or in any way to affect the obligations or l iabilities 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 dif ferentiation of harm based on location (on-shore or off-shore) as well as on a legal and re gulatory adaptation to new technology and novel environmental risk. Significantly, the TAPPA and t he 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 t hose 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 re cover quickly against the Fund and then litigate their remaining claims, including the multi-billi on 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 st ate 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 nece ssary deployment. A lowered liability cap within a strict liability federal f und 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 ma nage financial risk of new CCS technologies and serve to more rapidly transition from demonstrat ion projects to commercial deployment. Although claimants could still resort t o tort or environmental liability to obtain compensation for those claims not covered by the strict li ability fund, if the total fund amounts are high enough, and the in-fund liability caps low enough, this m ay help encourage operator development of initial projects.

on imported and domestic oil beginning in April 200 6 until the fund reaches $2.7 million. The tax wil l be discontinued, regardless of fund balance, on Decemb er 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. D EPARTMENT OF H OMELAND S ECURITY

, U NITED S TATES C OAST G UARD

, O IL S PILL L IABILITY T RUST F UND (OSTLF) F UNDING FOR O IL S PILLS 7 (Jan. 2006).

248 U.S. D EPARTMENT OF H OMELAND S ECURITY

, U NITED S TATES C OAST G UARD

, R EPORT ON I MPLEMENTATION OF

THE O IL P OLLUTION A CT 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’ punit ive damages claims are preempted by the Clean Water Act or barred under federal maritime law).44

V. C REATING A F RAMEWORK FOR M ANAGING L IABILITY AND E NSURING L ONG -T ERM
F INANCIAL R ESPONSIBILITY 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 pr ojects must store CO 2 underground for hundreds to thousands of years. As the lives of firms ar e much shorter than the period necessary to ensure public and environmental health protection, a tr ansfer of responsibility from a single firm to a pooled fund held by a private or public enti ty 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 ass urance. 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 envi ronmental 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 pla y a role to ensure CCS risk is managed over the long-term.

Developing a framework to manage CCS project liability requir es 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 b e adaptive and incorporate sitespecific data into CCS risk management. Additionally, regulatory a nd liability frameworks should be structured to provide incentives for good site selection and ope ration and an effective monitoring regime. These conditions must be met not only for managi ng environmental, health, and safety risk but also in order to integrate CCS within a lar ger climate policy. In the following Sections, we provide more detail on these conditions and propose a fram ework 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 ca re of CCS sites, nor is a time period for care yet defined. For using any of the mechanisms speci fied in Part IV, the regulatory framework must create a defined period of post closure responsibilit y 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, pos t-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 Sequestr ation of Carbon Dioxide, P APER
N O

. 156 IN P ROCEEDINGS OF THE S IXTH A NNUAL C ONFERENCE ON C ARBON C APTURE AND S EQUESTRATION

, P ITTSBURGH

, PA; E XCHANGE M ONITOR P UBLICATIONS : P ITTSBURGH , 14 (2007).

253 While for this paper we discuss transfer to a publ ic entity, it is possible that a private or semi-pr ivate organization with sovereign durability could play this role as w ell. See Wilson et al

. , supra note 9.45

Additionally, the regulatory framework must clarify how the tra nsition from private operator to a public entity for long-term stewardship will occ ur. Several different models are possible. First, there could be a fixed time period of operator res ponsibility (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 suffi cient incentives for responsible risk management. A better option would be to create a perf ormance-based measure that would initiate the site transfer when, for example, site pre ssures decrease to a specified threshold and reservoir models accurately predict CO 2 behavior underground. We believe that a performance-based measure is preferable as it allows site-s pecific risk criteria to be incorporated into the decision to transfer responsibility. The advantage of this a pproach is that it has the potential to provide incentives for good site selection and operation and al lows the operator to actively manage long-term liability. Whether the transition m etric is time or performance-based, any transition to public responsibility must be accompanied by suffi cient 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 a ccompanied 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 papers 255 have proposed different funding models to ensure resources are available for post-closure and long-te rm 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. Addit ionally, during the injection phase, a fee is collected, based either on a per-ton inje cted 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 CO 2 injection phase; (2) the post-closure period; and (3) long-term stewa rdship. During active CO 2 injection, the CCS project operator holds insurance and site liabilit y 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 pha se, the post-closure period, the operator is still responsible for site monitoring, verificati on, 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 t his 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 w ithin the fund (similar to the OPA). 256 When the CCS site meets pre-determined performance based mea sures it then transfers

254 See generally Naomi Peña & Edward S. Rubin, A Trust Fund Approach to Accelerating Deployment of CCS: Options and Considerations , C OAL I NITIATIVE R EPORTS

, W HITE P APER S ERIES

, P EW C ENTER ON G LOBAL C LIMATE C HANGE (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 stewardshi p, any necessary monitoring, remediation and damages are funded from the federal pool, financed b y the performance-based fees collected during the active injection phase. This pool could b e administered by a public or semi-private entity and would be responsible for ensuring manageme nt 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. Fir st, risks of leakage or damage may be correlated with certain geologic formations, and this a pproach 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” probl ems outlined in

Part III.

C. Creating an Adaptive Regulatory Framework

Because subsurface geology is heterogeneous, the behavior of CO 2 within and between CCS sites—and the resulting risks—will vary substantially. Vari ation in risk across sites will depend both on CO 2 behavior in the subsurface and surface ecological and human health considerations. It will only be possible to assess geologic site performance (and CO 2 behavior) during and after CO 2 injection. While mapping and modeling of CCS sites will be a maj or component of siting and permitting, incorporating actual site perform ance data into CO 2 dispersion models—not currently practiced for underground injection activi ties—will help operators, regulators, and insurance underwriters predict site per formance and manage risk. Such adaptive approaches incorporating actual data into management and subs equent regulation are regularly used in ecosystem management. 257

To create an adaptive regulatory approach for CCS, site performanc e 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 CO 2 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 th e 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 ri sk, 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 hel p risk management over the CCS life-cycle and allow for bond and insurance premiums to be corre ctly set. Second, additional information gathered during “true-ups” will lower asy mmetric 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 establ ish incentives for good site selection, responsible management and adequate monitoring and verification.

If properly structured, liability and risk can help to motivate r esponsible CCS site selection and project management. Incorporating site information ca n lead to better risk management, and this approach allows site managers to stimulate ri sk-reducing behaviors and

257 See generally K AI N. L EE

, C OMPASS AND G YROSCOPE : I NTEGRATING S CIENCE AND P OLITICS FOR THE
E NVIRONMENT (I SLAND P RESS 1994).

258 40 C.F.R. §146.8(b)(2).47

provide incentives for site selection with better performance cha racteristics. This information will help to ensure that insurance premiums and bond amounts are tai lored to the actual risks posed by the site, and that data is available for the eventual si te transfer to a public entity for long-term stewardship. Integrating adaptive management approaches with risk management, supports a regime with adequate financial responsibility to mana ge liability and enhances public confidence in CCS technology.

Separate from this phased liability and funding approach is the iss ue of how to encourage the development of the first CCS “pilot” projects. For those projec ts, 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 feder al government paying the rest. Like the OPA, however, claimants could resort to tort and envir onmental 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 part icular claim.

In sum, this approach contemplates potential damage caps on operator liabi lity (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 speci fic 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 l ong-term stewardship phase, at which time any necessary monitoring, remediation and da mages would be funded exclusively from the federal pool, financed by the performance-b ased fees collected during the active injection phase. As a result, the federal government would ta ke on a larger compensation burden in cases of harm in pilot projects throughout the CCS life-cycl e, 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-select ion and project operation as well as compensate those who may be harmed by CO 2 storage. In the end, there are certainly risks associated with CCS and the long-term storage of CO 2 . 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, pol icymakers should encourage the development of this technology while at the same time taking ca re not to limit operator liability to such an extent as to unduly burden or endanger human health and the environment.

C ONCLUSION

In this Article, we have attempted to create a framework to address liability and funding issues associated with the long-term storage of CO 2 in connection with CCS. We propose that states and the federal government can encourage the development of C CS without abandoning or placing significant limitations on existing tort law or statutor y environmental law protections. In order to accomplish this, we take advantage of the inherent life-cy cle of CCS and the stage of technology deployment on a national basis. We propose a system that maintains ex isting tort and48

statutory liability for harm associated with CCS and then plac es 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 ris ks of climate change while managing the risks of CCS.

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Email: docket-customerservice@epa.govUNITED NATIONS FRAMEWORK CONVENTION
ON CLIMATE CHANGE

UNITED NATIONS
1992

FCCC/INFORMAL/84 GE.05-62220 (E) 200705UNITED 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 thes e 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 de veloping countries are still relatively low and that the share of global em issions originating in developing countries will grow to meet their social and development needs,

Aware of the role and importance in terrestri al 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 eff ective 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 Declar ation 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 la w, the sovereign right to exploit their own resources pursuant to
their own environmental and de velopmental 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 c ooperation to address climate change,

Recognizing that States should enact effectiv e environmental legislation, that environmental standards, management objectives and priorities should refl ect the environmental and developmental context to whic h they apply, and that standa rds applied by some countries may be inappropriate and of unwarranted econo mic and social cost to other countries, in particular devel oping countries,- 2 - Recalling the provisions of General Assemb ly resolution 44/228 of 22 December 1989
on the United Nations Conference on Environmen t 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 impl ementation 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 S ubstances 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 be ing conducted by many States on climate change and of the important contributions of the World Meteorological Organization, the United Nations Environment Prog ramme and other organs, organizations and bodies of the United Nations system, as well as other intern ational and intergovernmental bodies, to the exchange of results of sc ientific research and the coordination of research,

Recognizing that steps required to understand a nd address climate change will be environmentally, socially and economically mo st 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 firs t 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 rela tive 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, droug ht and dese rtification, and developing countries with fragile mountainou s ecosystems are particularly vulnerable to the adverse effects of climate change,

Recognizing the special difficulties of those countri es, especially deve loping 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 s hould 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 grow th and the eradication of poverty,

Recognizing that all countries, especially devel oping countries, need access to resources required to achieve sustainabl e social and economic developm ent and that, in order for developing countries to progress towards that go al, 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 delete rious effects on the composition, resilience or productivity of natural and managed ecosyst ems 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 wh ich 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 cons tituents of the atmosphere, both natural and anthropogenic, that absorb and re-emit infrared radiation.

6. “Regional economic integration organizati on” means an organization constituted by sovereign States of a given region which has comp etence in respect of matters governed by this Convention or its protocols a nd 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 com ponents of the climate system where a greenhouse gas or a precursor of a greenhouse gas is stored.

8. “Sink” means any process, activity or me chanism 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 a nd any related legal instruments that the Conference of the Parties may adopt is to achie ve, in accordance with the relevant provisions of the Convention, stabilization of gr eenhouse gas concentrations in th e atmosphere at a level that would prevent dangerous anthropogenic interfer ence with the climate system. Such a level
should be achieved within a time frame sufficien t 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 objectiv e of the Convention and to implement its provisions, the Parties shall be guided, inter alia, by the following:

1. The Parties should protect th e climate system for the bene fit of present and future generations of humankind, on the basis of equity and in accordance with their common but differentiated responsibilities a nd respective capabilities. Accord ingly, 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 give n full consideration.

3. The Parties should take precautionary measur es to anticipate, prevent or minimize the causes of climate change and mitigate its adverse e ffects. 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 an d 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 rele vant sources, sinks and reser voirs of greenhouse gases and adaptation, and comprise all economic sectors. Ef forts to address climate change may be carried out cooperatively by interested Parties.- 5 - 4. The Parties have a right t o, and should, promote sustainabl e development. Policies and measures to protect the climate system agains t human-induced change should be appropriate for the specific conditions of each Party and s hould be integrated with national development programmes, taking into account that economic development is e ssential for adopting measures to address climate change.

5. The Parties should cooperate to promote a supportive a nd open international economic system that would lead to su stainable economic growth and development in all Parties, particularly developing country Parties, thus enabling them be tter to address the problems of climate change. Measures taken to combat climate change, including unilateral ones, should not constitute a means of arbitrary or unjustifiabl e discrimination or a disguised restriction on
international trade.

Article 4

COMMITMENTS

1. All Parties, taking into account their co mmon but differentiated re sponsibilities and their specific national and regional development priorities, objectives and circumstances, shall:

(a) Develop, periodically up date, publish and make available to the Conference of the Parties, in accordance with Article 12, nationa l inventories of anthr opogenic emissions by sources and removals by sinks of all greenhouse gases not contro lled by the Montreal Protocol, using comparable methodologies to be agre ed upon by the Conference of the Parties;

(b) Formulate, implement, publish a nd 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 de velopment, 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, trans port, industry, agriculture, forestry and waste
management sectors;

(d) Promote sustainable ma nagement, and promote and c ooperate 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 c limate change; develop and elaborate appropriate and integrated plans fo r 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 in to account, to the extent feasible, in their relevant social, economic and environmental policie s and actions, and employ appropriate methods, for example impact assessm ents, 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 undert aken 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 understandi ng 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, techni cal, socio-economic and legal info rmation related to the climate system and climate change, and to the economic and social cons equences 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 Partie s and other Parties included in Annex I commit themselves specifically as provided for in the following:

(a) Each of these Par ties shall adopt national 1 policies and take corresponding measures on the mitigation of climate change , by limiting its anthropogenic emissions of greenhouse gases and protecting a nd enhancing its greenhouse gas si nks and reservoirs. These policies and measures will demonstr ate that developed countries are taking the lead in modifying longer-term trends in anthropogenic emissions co nsistent 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 ga ses not controlled by the Montreal Protocol
would contribute to such modifica tion, 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, av ailable 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 C onvention and, in partic ular, 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 th e 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 resulti ng projected anthropogenic emissions by sources and removals by sinks of gree nhouse gases not controlled by th e Montreal Protocol for the period referred to in subparagraph (a), with th e 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 in formation 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 ta ke 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 sh all 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 ta ke appropriate action, which may include the adoption of amendments to the commitments in subparagraphs (a) a nd (b) above. The Conference of the Parties, at its first session, shall also take decisions regarding crite ria for joint implementation as indicated in subparagraph (a) above. A second review of subp aragraphs (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 appropria te with other such Partie s, 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 great er levels of anth ropogenic 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 ma y, in its instrument of ratification, acceptance, approval or accession, or at any time th ereafter, notify the Depositary that it intends to be bound by subparagraphs (a) and (b) above . The Depositary shall inform the other signatories and Pa rties of any such notification.- 8 - 3. The developed country Partie s and other developed Partie s included in Annex II shall provide new and additional fina ncial resources to meet the agreed full costs incurred by developing country Parties in complying with their obligations under Ar ticle 12, paragraph 1. They shall also provide such fi nancial resources, including for th e transfer of technology, needed by the developing country Parties to meet th e 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 th e international entity or entitie s referred to in Article 11, in accordance with that Article. The implementa tion of these commitments sh all take into account the need for adequacy and predictability in the flow of funds and the im portance of appropriate burden sharing among the de veloped country Parties.

4. The developed country Partie s and other developed Partie s 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 Partie s and other developed Partie s included in Annex II shall take all practicable steps to promote, facilitate an d finance, as appropriate, the transfer of, or access to, environmentally sound technologies an d know-how to other Pa rties, particularly developing country Parties, to enable them to implement the provisions of the Convention. In this process, the developed c ountry Parties shall support the de velopment and enhancement of endogenous capacities and technologies of developing country Parties. Ot her 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 unde r 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 th e Montreal Protocol ch osen as a reference.

7. The extent to which developing country Parties will effectiv ely implement their
commitments under the Convention w ill depend on the effective imp lementation by developed country Parties of their commitme nts 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 unde r 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 advers e effects of climate change and/or the impact of the implementation of res ponse 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 pr one to natural disasters;

(e) Countries with areas liable to drought and desertification;

(f) Countries with areas of hi gh urban atmospheric pollution;

(g) Countries with areas with fragile ec osystems, including mountainous ecosystems;

(h) Countries whose economies are highly dependent on income generated from the production, processing and export, and/or on c onsumption 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 acc ount of the specific needs and special situations of the least developed countries in their actions with re gard to funding and transfer of technology.

10. The Parties shall, in accordance with Ar ticle 10, take into c onsideration in the implementation of the commitments of the Convention the situati on of Parties, particularly developing country Parties, w ith economies that are vulnerable to the adverse effects of the implementation of measures to re spond to climate change. This a pplies 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 as sociated energy-intensi ve 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 appropr iate, international a nd intergovernmental programmes and networks or organizations aimed at de fining, conducting, assessing and financing research, data collecti on and systematic observation, taki ng into account the need to minimize duplication of effort;

(b) Support international and intergovernm ental 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 pa rticular concerns and needs of developing countries and cooperate in improving their endogenous capacitie s 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 appropria te, subregional and regional levels, and in accordance with national laws and regulations, and within their respective capacities:

(i) the development and imp lementation 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 particip ation in addressing climate change and its effects and developing adequate responses; and

(iv) training of scientific, te chnical and managerial personnel;

(b) Cooperate in and promote, at the inte rnational 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 implement ation 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 Partie s is hereby established.

2. The Conference of the Parties, as the supr eme body of this Convention, shall keep under regular review the implementation of the Conven tion and any related legal instruments that the Conference of the Parties may a dopt, 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 lig ht of the objective of the Convention, the experience gained in its implementation and th e evolution of scientific and technological knowledge;- 11 - (b) Promote and facilitate the exchange of information on measures adopted by the
Parties to address c limate change and its effect s, taking into account th e differing circumstances, responsibilities and capabilities of the Parties and their re spective commitments under the Convention;

(c) Facilitate, at the request of two or mo re Parties, the coordination of measures adopted by them to address clima te change and its effects, taki ng 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 refine ment 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 Conventi on by the Parties, the overall effects of the measures taken pursuant to the C onvention, 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 subsid iary bodies and provide guidance to them;

(k) Agree upon and adopt, by consensus, ru les of procedure and financial rules for itself and for any subsidiary bodies;

(l) Seek and utilize, wh ere appropriate, the servi ces and cooperation of, and information provided by, competent internati onal 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 f unctions 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 esta blished by the Convention, which shall include decision-making procedures for matters not al ready 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, or dinary sessions of the Co nference 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 agenci es 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 Confer ence of the Parties as observers. Any body or agency, whether national or international, gove rnmental or non-governme ntal, which is qualified in matters covered by the Conven tion, and which has informed the se cretariat 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 th e Parties present object. The admission and participation of observers shall be subject to th e 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 Conventio n and to provide them with services as required;

(b) To compile and transmit reports submitted to it;

(c) To facilitate assi stance to the Parties, particularly developi ng country Parties, on request, in the compilation and communication of information re quired 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 functi ons specified in the Convention and in any of its protocols and such other f unctions 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 technolog ical advice is hereby established to provide the Conference of the Parties and, as appropri ate, its other subsidiary bodies with timely
information and advice on scien tific 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 Partie s 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 stat e-of-the-art technologies and know-how and advise on the ways and means of promoting devel opment and/or transferring such technologies;

(d) Provide advice on scien tific programmes, internati onal cooperation in research and development related to c limate change, as well as on ways and means of supporting endogenous capacity-building in developing countries; and

(e) Respond to scie ntific, technological and met hodological questions that the
Conference of the Parties and its s ubsidiary bodies may put to the body.

3. The functions and terms of reference of th is 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 here by established to assist the Conference of
the Parties in the assessment and review of the effective implement ation of the Convention. This body shall be open to participa tion 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 communi cated in accordance with Article 12, paragraph 1, to assess th e 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 communi cated 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 here by defined. It shall function under the guidance
of and be accountable to the Conference of the Parties, which shall d ecide on its policies, programme priorities and eligibility criteria relate d to this Convention. Its operation shall be entrusted to one or more existing international entities.

2. The financial mechanism shall have an e quitable and balanced representation of all Parties within a transparen t 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 pr ojects to address c limate change are in conformity with the policies, pr ogramme priorities and eligibility criteria established by the Conference of the Parties;

(b) Modalities by which a par ticular 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 pred ictable and identifiable manne r of the amount of funding necessary and available for th e implementation of this Conve ntion 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, re viewing and taking into account the interim arrangements referred to in Article 21, paragr aph 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 pr ovide and developing country Parties avail themselves of, financial resour ces related to the implementa tion 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 c ontrolled by the Montreal Protoc ol, to the extent its capacities permit, using comparable methodol ogies 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 c onsiders relevant to the achievement of the objective of the Convention and suitable for in clusion in its communication, including, if feasible, material relevant for calcu lations of global emission trends.

2. Each developed country Party and each othe r 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 unde r 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 e missions by its sources and removals by its sinks of greenhouse gases dur ing the period referred to in Article 4, paragraph 2 (a).- 16 - 3. In addition, each developed country Party and each other deve loped 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 volunt ary basis, propose projects for financing, including specific technologies, materials, equi pment, 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 othe r 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 co mmunication within three years of the entry into force of the Convention for that Party, or of th e availability of financial resources in accordance with Article 4, paragraph 3. Pa rties 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 Pa rties, 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 Partie s and to any subsidiary bodies concerned. If necessary, the procedures for th e communication of information may be further considered by the Conference of the Parties.

7. From its first session, the Conference of th e Parties shall arrange for the provision to developing country Parties of technical and financial suppor t, on request, in compiling and communicating information under this Article, as well as in identifying the technical and financial needs associated with proposed project s and response measures under Article 4. Such support may be provided by other Parties, by co mpetent 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 Artic le, provided that such a communication includes information on the fulfilment by each of these Parties of its individua l 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 be fore 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 availa ble 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, th e 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 econom ic integration organization may declare in a written instrument submitted to the Depositary that, in respect of any dispute concerning the interpretation or applic ation 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 In ternational 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 para graph 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 th e expiry of a declaration shall not in any way affect proceedings pending before the Interna tional 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 dis pute exists between them , the Parties concerned have not been able to settle their dispute thr ough 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, wh ich the parties shall c onsider in good faith.- 18 - 7. Additional procedures relating to conciliation shall be adopted by the Conference of the Parties, as soon as practicab le, in an anne x on conciliation.

8. The provisions of this Artic le shall apply to any related legal instrument which the Conference of the Parties may adopt, unl ess 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 adopt ed at an ordinary session of the Conference of the Parties. The text of any proposed ame ndment 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 accordan ce with paragraph 3 a bove 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 an y 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 pr esent 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 th e same time a reference to any annexes thereto. Without prejudice to the provisi ons 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 propos ed and adopted in accordance with the procedure set forth in Artic le 15, paragraphs 2, 3 and 4.

3. An annex that has been adopted in accordan ce with paragraph 2 above shall enter into
force for all Parties to the C onvention six months after the date of the communication by the Depositary to such Parties of the adoption of the annex, excep t for those Parties that have notified the Depositary, in writing, within that pe riod of their non-acceptance of the annex. The
annex shall enter into force fo r 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 amendmen t 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 an y 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 sh all be taken only by the Partie s 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 vot es equal to the number of their member States that are Parties to the Convention. Such an organi zation 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 Deve lopment, 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 t echnical advice. Other relevant scientific bodies could also be
consulted.

3. The Global Environment Facility of the United Nations Development Programme, the
United Nations Environment Pr ogramme and the Internationa l 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 requ irements of Article 11.

Article 22

RATIFICATION, ACCEPTANCE, APPROVAL OR ACCESSION

1. The Convention shall be subject to ratifi cation, acceptance, approval or accession by States and by regional economic integration orga nizations. 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 accessi on shall be deposited with the Depositary.- 21 - 2. Any regional economic integration orga nization which becomes a Party to the Convention without any of its member States be ing a Party shall be bound by all the obligations under the Convention. In the case of such organiza tions, 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 obliga tions under the Convention. In such cases, the organization and the member Stat es shall not be entitled to exer cise rights under the Convention concurrently.

3. In their instruments of ratification, accep tance, approval or a ccession, 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 ni netieth 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 afte r the deposit of the fiftieth instrument of ratification, acceptance, approva l 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 instrume nt of ratification, acceptance, approval or accession.

3. For the purposes of paragraphs 1 and 2 a bove, any instrument deposited by a regional economic integration organi zation shall not be counted as add itional 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 da te 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 Conventi on 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
Belarus a Belgium Bulgaria a

Canada
Croatia a * Czech Republic a *
Denmark European Economic Community
Estonia a

Finland

France Germany
Greece Hungary a

Iceland
Ireland Italy Japan
Latvia a

Liechtenstein *
Lithuania a Luxembourg

Monaco *
Netherlands
New Zealand Norway
Poland a Portugal
Romania a

Russian Federation a

Slovakia a *
Slovenia a * Spain
Sweden
Switzerland Turkey
Ukraine a United Kingdom of Great Britain and Northern Ireland
United States of America

a Countries that are underg oing 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, PE2 Table of Contents

E XECUTIVE S UMMARY ......................................................................................................................4

Identified Statutory Issues ................................................................................................... 5

Identified Regulatory Issues .............................................................................................10

I NTRODUCTION

............................................................................................................................... 12

B ACKGROUND

............................................................................................................................... ..13

Potential Current and Future Conf licts with Subsurface Interests.....................................14

Ownership of Geologic Formation/Po re Space & the Right to Sequester.........................15

Long-Term Liability ..........................................................................................................16

I DENTIFIED S TATUTORY I SSUES ......................................................................................................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 & Transpor tation Corridors by Eminent Domain ..............37

Authority to Transfer Liab ility/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 .............................................................................................653 Authority to Impose Sequestration Fee on Injected CO2 Volumes & Exemptions ..........65

Authority to Bond Injecti on Projects & Facilities .............................................................66

Authority to Enter Land for Inspection..............................................................................67

Protection of Surface Owners Interests..............................................................................67

I DENTIFIED R EGULATORY I SSUES ..................................................................................................68

General........................................................................................................................ .......68

Siting & Permitting............................................................................................................ 68

Drilling & Operations ........................................................................................................71

Post Injection & Closure....................................................................................................72

Post Closure ................................................................................................................... ....734 Executive Summary

The Governor’s Executive Order 2006-69 requi res the New Mexico Energy, Minerals, and Natural Resources Department (EMNRD) coordina te 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 pres ent proposed statutory changes and identify regulatory changes that must be addressed once the statutory direc tion is established. No attempt was made to address or identify challenges of carbon sequestration ou tside the scope of transportation, injection and geologic storage.

This report is due to the Gove rnor’s Climate Change Action Implementation Team on December 1, 2007.

Geologic sequestration of carbon dioxi de has been identified as a technically viable means to significantly reduce anth ropogenic emissions of the greenhouse gas carbon dioxide (CO2) over long timescales. Studies suggest th at in appropriately selected a nd 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 si gnificantly 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, monitori ng, storage verification, and liab ility issues, including the following:

 Potential Current and Future Conflict s with Subsurface and Surface Interests

Potential conflicts with mineral estate inte rests, pore space and storage right owners, surface interests, and groundwater use may arise and must be anticipated.

 Ownership of Geologic Formation/Po re 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 ri ght 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 sc heme 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 promot e development of projects and to encourage climate mitigation.

Such a scheme should address the questi ons: Should the state retain long-term liability (i.e. monitoring, measurement, and mitigation responsibilities, including personal and property damages) of all sequest ration projects or a limited number of initial projects to promote industry and co mmercial participatio n? 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 a nd 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 a nd to ensure the viability and success of any commercial-scale carbon sequestrati on 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 enhanci ng 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 ve nted. Further, OCD also regulates naturally occu rring CO2 and may require in jection 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 regul ate 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 anticipat ed 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 regulato ry framework for commercial-scale geologic sequestration.6  Ownership of Geologic Formation/Pore Space

Pore space evacuated by the extraction of o il and gas minerals likely belongs not to
the mineral interest but to the surface owne r, who would have the sole power to grant storage rights for the purpose of sequest ering carbon dioxide. New Mexico case law does not address the question of storage rights directly, bu t does hold that the mineral
interest does not include the solids of the earth.

The holdings of several other cases reinfor ce 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 forma tion 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 th e 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 poten tially avoid unnecessary litigation on this point.

 Unitization of Recoverable Hydrocarbons

To account for the enhanced recovery anticip ated 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 O il Conservation Division order compelling it, to provide a process to equitably a llocate 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 interest s consent. This may prove to provide an unacceptable means of blocking planned seque stration projects, as minority interests could refuse to ratify uni tization 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 pract ice. While not definitive, the language in the Unitization Act may be flexible enough to allow OC D 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 al ways be the result in a program designed primarily for the sequestration of CO 2, 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 th e estimated value of the additional oil and gas so recovered plus a reasonable pr ofit.” Interpreted to mean the costs of production of additional hydrocarbons (CO2 se paration and re-injection/cycling, etc.) as opposed to the costs of the entire sequest ration project, this language may not pose a barrier, but the statute ma y need to be clarified.

Also, statutory continuation ofexpiring leases may be considered to facilitate preproject planning of CO2 sequestration projects.

Unitization of federal minerals with non-fe deral 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 co nserving the oil and gas resources.

 Condemnation of Storage Space and Transpor tation Corridors by Eminent Domain

Subsurface storage space and surface easements for pipelines and injection facilitieswill 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 pur poses of CO2 sequestration. Authority to condemn subterranean storage space, si milar to current statutory provisions authorizing the condemnation of underground st orage space for natural gas, would be necessary for CO2 sequestration operators to acquire the storage rights from property owners with whom they have not reache d 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 a pplies only to trunk lines, or primary transportation lines, and not to gathering lin es. 70-3A-1 et seq. establishes the means by which easements for smaller disposal li nes 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 significan t factors in making sequestration projects feasible and for attaining public accept ance of the technol ogies, processes and regulations.

Sufficient financial assurances and appropr iate and reasonable liability standards together with thorough, clea r and reasonable regulations can create the required8 degree of certainty and pred ictability necessary for in surers to offer adequate coverage in this new and unexplored field and for opera tors 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 largel y untested field while providing adequate protections and ensuring a mechanis m for compensation and environmental mitigation should accidents occur. Further, de veloping the right level of legal liability
can create in insurers an additional la yer 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) industr y; or (4) the individual corporation or owner/operator.

Short-term liabilities inherent in any drilling or injecti on project can likely be best addressed through the contractual arrangeme nts 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 sequestr ation projects, both in terms of time and space, required for successful CO2 mitigation.

Much of the sequestration literature assu mes that long-term liability must be transferred to the public sector to main tain economic viability and to encourage industry participation.

However, such transfer of liability rais es 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, verificati on, mitigation and liability. As no true precedent exists with which to determine ad equate and reasonable funding levels for the areal extent and duration contemplated fo r 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, th e 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 fo r injectors and the carbon sequestration industry to retain ownership and liab ility with coverage provided by some
combination of individual li ability, insurance, or an industry-funded trust fund.9 Transfer of liability and ownershi p of injected CO2 to the state

Transfer of liability to the state would re quire the authority to impose a sequestration fee on injected CO2 volumes in order to f und the state’s future liabilities, monitoring,
measurement and verifica tion (MMV)obligations.

Liability for injected CO2

The injectors liability can be modeled on a ny one or a combination of programs such as the Price Anderson Act, CERCLA, th e Safe Drinking Water Act’s Underground Injection Control Program, the Low-Level Radioactive Policy Ac t or on traditional private insurance options.

One possible liability scheme could in clude some or all of the following:

• Statutorily imposed strict liability fo r 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 ot her 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 w ith deferred premiums for accident coverage and environmental mitigati on costs that exceed an individual’s insurance liability.

• Demonstration of financial assuran ce for insurance and industry-funded deferred premiums.

• Creation of a closure and post-closur e 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 th ird 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 reas onably foreseen to result.

• Financial assurance for plugging and aba ndonment 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-cl osure plan for review and approval by
the Division.

 Authority to Bond Injecti on Projects & Facilities10 Aside from the costs associated with post-closure MMV and potential mitigation, are the costs associated with reclaiming projec t 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 author ity 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 aut hority to enter surface properties to plug abandoned wells and reclaim seque stration surface facilities.

 Protection of Surface Owner Interests

The Surface Owners Protection Act applies on ly to exploration, drilling or production of oil and gas, and would need to be am ended to include activities related to the sequestration of carbon dioxide to adequately protect the interest s of surface owners in the same way they are currently prot ected 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 characteriza tion and mapping (baseline data)

 Injection

 Radius of Influence/Area of Review11  Proposed public safety and emergency response plan

 Siting

 Bonding

 Notice Requirements

 Permit conditions

 Procedure and Requirements for Tran sfer/Sale of Seque stration 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 cessati on of injection phase before evaluation for potential transfer of owne rship/liability? Or proper length of time to demonstrate integrity after injection pha se (when formation pressures stabilize)?

 Monitoring

 Plugging

 Reclamation/Restoration of surface

 Qualifications for transfer

Post-Closure

 Transfer of liability

 Long-term monitoring plan

 Mitigation plan12 Introduction

The Governor’s Executive Order 2006-69 require s EMNRD to “explore requirements needed to ... geologically sequester significant amounts of anthropogenic carbon dioxide in the state, including but not limited to geol ogic surveys, infrastructure, a nd ownership of liabilities. ... In addition, EMNRD shall coordinate with the st akeholder 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 th e likely agency to oversee development and implementation of a regulatory framework fo r geologic sequestration of CO2 due to its institutional and technical exper tise in drilling, deep-w ell injection, current regulatory oversight of ongoing carbon dioxide injection pr ojects, as well as the anticipa ted synergies with enhanced oil recovery.

Pursuant to the foregoing Executive Order, EM NRD’s Oil Conservation Division (OCD) held a series of public stakeholder meetings w ith representatives from community and nongovernmental organizations, oil and gas expl oration and production companies, power generation companies, and industry groups to ga ther input and recommen dations for a proposed statutory and regulatory fram ework for CO2 sequestration.

The purpose of this report is: 1) to identify the issues and chal lenges that must be addressed through statutory and/or regulatory changes to fully develop a comp rehensive regulatory framework for the safe and effective sequestra tion of carbon dioxide in furtherance of the Governor’s Executive Order; 2) identify questions, concerns a nd recommendations presented to the Division through the stakeholde r 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 se questration is a technically viable means to significantly reduce anthropogenic emissions of CO2 and perm anently separate it from the atmosphere.

In its December 2006 Final Report, the New Me xico Climate Change Advisory Group (CCAG) included carbon capture and storage/re-use amon g its greenhouse gas em issions reductions strategies. 2 Governor Richardson directed the CC AG in Executive Order 2005-033 to develop proposals to reduce New Mexico’s greenhouse ga s emissions to 2000 levels by the year 2012, 10 percent below 2000 levels by 2020, and 75 percen t below 2000 levels by 2050 as part of a climate change mitigation strategy.

In recommendation ES-11, focused primarily on th e capture and re-injection/re-use of CO2 in the processing of natural gas, the CCAG proposed a CO2 capture and re-inj ection/re-use target of 7 percent of CO2 emissions every year, based on the prior year’s emi ssions, 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, pr imarily for enhanced oil recovery. 4 In 2000, New Mexico emitted approximately 83 milli on metric tons of CO2 equivalent, 5 of which 30 million metric tons CO2 equivalent cam e 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 cubi c feet per month (452,800 metric tons/month on average since January 2006). In 2006, these counties pr oduced 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 em issions significantly while also allowing coal to meet the world’s pressing energy needs.” 7 Geologic storage of CO2 is al so considered a viable and effective means of successfully sequestering CO2 from the atmosphere over long timescales. Based on decades of studies in analogous hydroc arbon systems, natural gas storage operations and enhanced oil recovery projects, a 2005 Special Report by Inter governmental Panel on Climate Change reported that “[f]or large-scale operational CO2 storage projects, assuming that sites are well selected, designed, operated and appropriate ly 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/ew ebeditpro/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 A dvisory 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 geolog ic 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 comprehensiv e regulatory models th at address the unique long-term measurement, monitoring and verificati on requirements, or the liability and property rights issues such a comprehensive and large-scal e 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 fe deral environmental regul ations 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 speci fically enhanced oil rec overy, 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 an d gas fields, and because of the potential market interest and synergy with enha nced hydrocarbon recovery and th e 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 perm anent geologic sequestration of anthropogenic CO2, to protect human health and the environmen t, 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 underg round drinking water sources required under the U.S. Environmental Protection Ag ency’s Underground Injection Control Program (UIC), which is managed in the state by the OCD and the New Mexico Environment Department (NMED). OCD has develope d proposed regulations tailored to ensure safe and effective CO2 sequestration while co mplying with EPA’s UIC program requirements. OCD contemplates coordinating with appropriate re gulatory 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 th e sequestration of carbon dioxide may have.

Potential Current and Future Interf erence with Subsurface Interests

Sequestration of CO2 in the s ubsurface geology, while identified as a viable and important means of mitigating clim ate change and greenhouse gas emissi ons, will also invariably lead to potential conflicts with other subs urface interests, such as the mi neral estate (oil, gas and coal)

9 David Borns, Underground Storage Technology Program Manager, Sandia National Laboratories, personal
communication.15 and associated interests, gr oundwater 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 re sources, such as saline waters , that might conflict with CO2 sequestration.

Ownership of Geologic Formation/Po re 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 CO 2. In New Mexico, the common law on this issue is somewhat unsettled as no case directly te sts theories of pore space ownership. However, several cases from the New Mexico Supreme Cour t indicate preference fo r the majority view among states that the pore space and subsurf ace geologic formation belongs to the surface owner, not the mineral estate.

There are essentially two competing theories that ultimately define the lia bility of CO2 injectors in relation to por e space owners.

One legal theory, not widely adopt ed, is the “reverse” or “negativ e rule of capture,” which holds that just as an owner may capture such oil or ga s 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 th is rule, liability for the migration of injected substances is essentially limited in preferen ce 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 th at sequestration of CO 2, and the consequent reduction of greenhouse gas emissions, is a public be nefit, or a mitigation of a public nuisance. A likely impediment to this approach is the 5 th 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 probl ems 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 liab le 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 su rface owner(s) or face li ability for trespass, nuisance, or numerous other possibl e tortious or equitable claims.

Rights to sequester can be ac quired either throu gh negotiation, or ultimately by means of condemnation proceedings pursuant to the state’s powers of eminent domain. This concept addresses the important distinct ion between the rights of the por e space owner and the mineral16 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 include s the sand, and gravel, etc., which comprise the geologic formation, but do not extend to the h ydrocarbons occupying the interstices.

A minority view is that a seve rance of the mineral estate sh ould be construed as granting exclusive rights to the subterranean strata for al l purposes relating to minerals, whether “native” or “injected,” absent explicit langua ge to the contrary in the severa nce of the mineral estate. This view would eliminate the problem of having to se cure 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 s hort-term liabilities inhere nt in any drilling or injection project – whether environmental or eco nomic – can likely be be st 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 term s of time (hundreds to thousands of years) and space, required for successful CO2 sequestration and accurate CO2 inve ntories. For example, literature and studies to date on the topic suggest th at 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 seque stration, transfer of liability to the public sector has been conceived of as one way to encourage the de velopment of sequestrati on projects by limiting potential liabilities. But this liab ility model also raises many issu es, such as how to control the burden on the public and how to fund monitoring and verification effo rts, as well as any potential long-term mitigation that may be required.

The alternative would be to requir e the injector to reta in liability in combination with a fund or
some other financial assurance mechanism to ensu re the storage field is adequately covered for long-term monitoring and verifica tion purposes, as well personal a nd property liability. Several pre-existing models culled from federal environm ental 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 e nvironmental protection should be foremost considerations given th e scale of the anticipat ed injections and the potential the unknowns of such a new technology.17 Identified Statutory Issues

To address the potential conflicts and uncer tainties outlined above, several statutory and regulatory changes are anticipated.

Authority to Regulate Carbon Sequestration

Issue : OCD would need to have clear authority to regul ate 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 o il and gas reservoirs, the OCD may require the authority to dissolve or modify previously established field(s) or producing unit(s) c ontained 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 afte r the possibility of enhanced production has elapsed, to prevent the wa ste of CO2 that would otherwise be vented. Further, OCD also has the authority to re gulate 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 th e Division to regulate anthropogenic CO2 injection for se questration purposes alone, nor does it have general authority to regulate injection/sequestrati on 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 Ne w Mexico, clear authority to regulate the sequestration of anthropogenic CO2 into all potent ial geologic reservoirs, not li mited 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 earli est 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 contai n gases over geologic timescales, as well as the industry’s expe rtise 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 sp ace within it. New Mexico common law in this area remains largely undeveloped because the ques tion 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 major ity 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 produci ng states, follow this common-law American rule. A consequence is that any large-scale CO2 sequestration effort will likely require the acquisition of underground storag e rights from surface owners by negotiation or condemnation.

Issues Raised During the Workgroup :

 Is it possible for the state to claim ownershi p 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 thes e 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 cons ent of the pore space owner – at what point does CO2 injection become storage and requi re acquisition of st orage space rights?

 Any sequestration regulatory framework must include but not be limited to hydrocarbon reservoirs and contain provisi ons for injection into other formations, such as saline aquifers.

Analysis : Pore space for CO2 sequestration has been identifie d in three major reserv oir 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 diox ide. New Mexico case law does not address the question of storage rights directly, but does hold that the mineral interest doe s not include th e solids of the earth. The holdings of several other cases reinfo rce that New Mexico retains a preference for the majority view that the mineral estate includes only the oil and ga s native to the formation, and not rights to the formation or the pore space it self, unless the conveyan ce or severance of the mineral estate explicitly states otherwise. Therefore, the su rface 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 in terest retains the right to access by reasonable means subsurface minerals as long as there are re coverable minerals remaining to be extracted and as long as there has been no abandonment, but that the right to th e pore space/geologic
formation reverts to the surface owner on ce 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 co al therein is exhausted or abandoned.” Westerman , 26019 Pa. at 146. Years later, the West Virginia S upreme 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 mi ned 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 in terest 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 stor age 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 retain s ownership of the evacuated pore space. In Emeny the court found that “[t]he surface of the leased lands a nd everything in such lands, except the oil and gas deposits covered by the leas es, were still the prope rty of the respective landowners according to the language of the mi neral conveyance. Property retained by the landowner included the “geological structures ben eath the surface, including any such structure that might be suitable for the underground stor age of ‘foreign’ or ‘e xtraneous' 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) (holdi ng 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. 2 nd 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, on ce it has been evacuated of the minerals and gas, belongs to the surface owner and that a minera l 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 spac es owned by the lessor for the storage of gas in the absence of an express ag reement therefore”); M.J. Harvey, Jr., 109 IBLA 31 at 33, GFS (O&G) 1989-75 (May 25, 1989) (to the exte nt that no valuable minerals underlay the tract in question, the owner of th e surface estate rather than th e 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 su rface owner but not of mineral owner was entitled to use a dry hole as a salt water inject ion well). It is possible to read the holding of Emeny narrowly, as turning on the langua ge of the lease, and not a general proclamation that the pore space is absolutely retain ed by the surface owner. Since Emeny , this paradigm of subsurface
interest has become well established for cases wher e 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 surviv e as long as there remain minerals to extract
and the interest has not been ab andoned. In the New York case of International Salt Co. v.

Geostow the court found that the surface owners were precluded from executing a waste storage20 contract with a third party to use the excavat ed space created by the salt mining activities, as
there still remained minerals in place and International Salt C o. 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 ri ght 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 “rever ts to the surface landowne r 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)) (int ernal 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 th e 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 tr end 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 am ong 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 lega l thinking to an increase in th e scientific understanding of the nature of minerals and of geology. Early understa nding suggested that minerals had the potential to migrate freely beneath the surface, so that on ce extracted “the depleted reservoir may one day be refilled by one of these migratin g 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 geologic al formations or strata common to this class of minerals may be exhausted a thous and times and the mineral owner still retain the exclusive rights to take all the minerals which find their way into the fo rmation, 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 a nd 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 conne cting 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 mo st 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 mi neral rather than the surface owner is
entitled to the rental or royalty accruing under a gas storag e lease”). While acknowledging the counterargument based on the anci ent 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 wher e strata have been depleted of oil and gas or never contained recoverable minerals, Williams & Meyers urges a doption 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, wh ether “native” or “injected,” absent contrary language in the instrument severi ng such minerals.” W&M 1:222, p.334-335.

Somewhat in support of this minority view, the Oh io 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 cour ts that the particular facts in each case were not appropriate for th e application of oil and gas law. In Chance v. BP
Chemicals , 670 N.E.2d 985 (Ohio 1996) the defendant s/appellees were injecting waste byproducts from the production of industrial chem icals, 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 speci al body of law has arisen on special circumstances not present here.” Id . at 991. But most significa ntly, 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 a ppellants’ 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 wh ere 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 wh ere appellants alleged trespass following the injection of water fo r aquifer recharge. Bd. of County Comm'rs v. Park County Sportsmen's22 Ranch , 45 P.3d 693, 701 (Colo. 2002). The Colorado suprem e 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 distin ctions between water law and oil and gas law derived from the Colorado constitution, water law stat utes and legislative intent, as well as from state common law, the Colorado court distinguis hed the application of water law from that of oil and gas law. Specifi cally, the court found that the legislature, “in authorizing the use of aquifers for storage of artificially recharged wa ters ... has ... supplanted the Landowners’ common-law prop erty 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 na tural formations belong to a landowner as a stick in the prope rty 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’ propert ies,” 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 f unctioning 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 wa ter is a public resource available for public agency and private use in a system of maximu m utilization for benefi cial use under decreed rights,” because:

Allowing property owners to contro l 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 wate r supply made available through the exercise of decreed water use righ ts. It would disharmonize Colorado's
historical balance between water use rights and land ownership rights. It would inflate and protract litigati on by adding condemnation actions to procedures for obtaining water use de crees. 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 wa ter when there is no artificial structure on the property of the landowner and the injected water ha s been decreed to be a benefi cial resource to the public
domain.

In New Mexico, where storage of natural gas in the subsurface is not a common practice and the23 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 in clude rights to the geologic form ation. 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 an d gas only. And while the mineral interest is a real estate interest, “it does not convey a greater in terest in the soil, except the oil and gas, than to
enable the owner of the lease to use the soil in carryi ng 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 ac tion for subsurface trespass is av ailable 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 auth ority from the New Mexico Oil Conservation Division to inject salt wate r 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 f act that the fault line and the bounda ry line merge at a particular point does not mean that the fault line en compasses 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 trespa ss and statutory trespass when injected water
caused a blowout in his well. The lower court ru led 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 trespa ss 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 cl aim was held inapposite becaus e “[n]othing in the statute indicates that the legislature envi sioned applying [the st atute] 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 gas24 law, it seems that the reasoning employed coul d be applied to carbon dioxide sequestration,
because most surface owners make no use of their subsurface pore sp ace 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 legislat ure to include careful language in the authorizing statutes establishing the public benefit of carbon dioxide sequestration. A d eclaration 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 st ream 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 sp ace. The benefit of this approach would be to avoid the expense, time, and challenge of acquiri ng all the necessary pore space storage rights from respective surface owners. As the areal ex tent of carbon dioxide sequestration units is expected to be quite large, th e number of landowner in terests 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 th e public’s interest in a secure, reliable and efficient process for the injection and sequestration of carbon dioxide.

On the other hand, storage space cost s should be nominal, especially early in the development of carbon sequestration, and a ny legislative action that does not provide for compensation or legal condemnation of what is arguabl y a valid property interest pose s a significant constitutional takings challenge. Ultimately, the volume of case law establishing a surface owner’s property
interest in subsurf ace pore space and the 5 th Amendment of the U.S. Constitution’s “takings”
clause recommend the less controve rsial option of pursuing legiti mate condemnation of the pore space interests through just compensation. Also, a powerful policy argument stands against a wholesale abrogation of landowner s ubsurface 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, tec hnological problems and geologic unknowns than sequestration in depleted oil and gas reservoirs. For these reasons, it is believed th at sequestration in deep saline aquifers will evolve after seque stration in depleted hydrocar bon reservoirs. However, any statutory and regulatory system must address th e complexities of storage in saline aquifers.

All ground waters of the state of New Mexico ar e statutorily declared to be public waters, belonging to the state and as such are subject to appropriation fo r beneficial use. However, the Office of the State Engineer does not have author ity to regulate the appropriation of waters found at depths greater than 2,500 feet and in concen trations in excess of 1,000 parts per million (ppm)
dissolved solids. While the waters themselves may be appropriable a nd within the public domain, the aquifer storage space is not in the pub lic domain, but is the property interest of the
surface estate.25 NMSA 72-12-1 and 72-12-18 both declare for differe nt purposes that ground waters belong to the public and are subject to appropriation for bene ficial 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 appropri ation of public waters was not limited to waters “ upon the public lands” because “water of underground rivers with de fined 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 ar e within the public domai n, not all ground waters fall within the jurisdiction of the state engineer. In Tweedy , the court determined that before the state engineer can assume ju risdiction over underground water bod ies “he must find that they have boundaries reasonably ascert ained by scientific investigati ons, or by surface indications.” Tweedy , 286 P. 970, 976. Nonetheless, the current statut e makes clear that “[n]o past or future order of the state engineer de claring an underground water basin having reasonably ascertainable boundaries shall include water in an aquifer, the t op 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-potab le 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 (10 th 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 St ate has retained an ownership or trust interest in the minerals, including sand and gr avel, underlying parcels of state land that have been sold and conveyed to others is a fact-spe cific determination under New Mexico law, and is not determined by a blanket state property law rule.” Id

.

Instead, the courts look to the ownershi p 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 th e same sense that it owned in trust the public’s

water. Id . at 1203-1204. The court held that “unless the St ate claims some proprietary interest in the land or the aquifer’s subsurface geologic mate rials as a landowner or title holder, then it
would seem that the chemical contamination of those geologic materi als impacts the State’s interests in groundwater only when it resu lts 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 subsequently26 affirmed by the 10 th 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 expre ss property interest in the geologic formation itself, the state, therefore, has no property in terest in the storage space contained within New Mexico aquifers, the ownership of which appear s to abide by the same property rules discussed above in the analysis of oil and gas reservoirs . Consequently, barring th e alternative approach discussed above, acquisition of st orage 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 d eeper 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 se questration of CO2 are unminable coal seams. Like depleted oil reservoirs, CO2 storage in coal seams will, under some conditions, provide enhanced hydrocarbon recovery. Th ere are, however, additional tech nical challenges that must be addressed before any large s cale sequestration project in co al seams is advanced. It is expected that the legal issues with regard to pore space will be highly analogous to those
identified for other subsurf ace 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 tr espass but requires that there be demonstrable proof of physical infringement by a person or thing that result s in damage. Consequently, the negative rule of capture – the th eory derived from oil and gas la w that just as a landowner may capture what minerals may migrate from adjoin ing 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 in fringement into their property resulting in damage will likely be successful in bringing a tr espass action against injectors, unless available remedies are statutorily limited to, for exampl e, 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 di oxide injectors, because punitive damages are generally not available in inve rse condemnation actions, only compensatory damages. The law of subsurface trespass has not developed much bey ond 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 avai lable to surface owne rs 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 theori es of recovery are av ailable, but the New Mexico Supreme Court is currently scheduled to review this holding, so the law may change), conversion (money paid to inject ors, a portion of which should ha ve been paid to the landowner for rental of the pore space for storage), and unjust enrichment (g aining 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 injecti ng into the subsurface th e 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 tr espass damages are more difficult to establish. The following analysis, howev er, deals only with th e claim of subsurface
trespass.

New Mexico courts have held that trespass is a di rect 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 la w 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 trespa ss resulting from injection operations).

Subsurface trespass claims are limited to common-la w actions, the courts having determined that statutory trespass is limited by legisl ative intent to surface trespass. Hartman , 937 P.2d at 984. Owing to the requirement for direct physical in fringement, the New Mexico courts appear to require a showing of damage for subsurface tr espass 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 protect ed 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 Rest atement (Second) of Torts suggests that for indirect trespass, as when an act or causes a thing to infringe u pon another’s property, that “[i]t is enough that an act is done with knowledge that it w ill to a substantial certain ty result in the entry of the foreign matter.” § 158 cmt. h. Whether this divergence from the gene ral rule expressed in Schwartzman is actually the court’s holding or wh ether 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 requ ire direct evidence, beyond affidavits or testimony of experts, to dem onstrate physical infringement. Schwartzman , 857 F. Supp. at 845 (“the only evidence of physical contamination...i s 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 pr operty 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 so il or groundwater testing to
demonstrate contamination due to the activities of defendant railway company, and instead relied on evidence based solely on the opi nions of experts, which the c ourt 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 ma ps showed his property boundary merging with a “sealing fault” that would block the flow of inj ected salt water as “proof positive that the fault line must include part of their land,” was insufficient to establ ish that salt water injected by defendants on the adjoining property mu st have infringed on their property. Snyder Ranches,

Inc. , 798 P.2d at 589, 590. Conversely, in Hartman , plaintiff’s contenti on that defendant’s injection of salt water at high pr essures created vertical fractures allowing the escape of salt water into plaintiff’s well was supported by eviden ce “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 legiti macy of the subsurface trespass claim.

New Mexico further appears to hold that ther e 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 in jection of salt water pr oduced off site, unless, perhaps, an instrument or c ontract 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 fr om other jurisdictions (Kansas, Louisiana and Illinois), which suggested that “t here may be an implied authoriza tion to dispose of salt water in order for the production of oil and gas on that pe rson'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 wa ter 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 st ems from the theory that such production “is a necessary and unavoidable” result of the producti on 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 in cludes an implied covenant to di spose of the salt water produced during operations by utilizing a sa ltwater disposal well drilled on the leased premises without additional compensation to the lessor. We hold th at 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. 3 rd cir. 1986) (“[W]e concl ude that, under the facts pr esent, 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 gr anted, i.e., production of oil from the leased property”); but see Gill v. McCullom , 311 N.E.2d 741 (App. Ct. 5 th dist. Ill 1974) (“The injection must have some relation to the pr imary 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 ex tracting minerals from that land. Thus, the land29 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 subsur face injuries the measure for damages is the
diminution in the fair market value of the entire property; for temporary in juries, “the measure of damages is the cost of repair or remediation, so l ong as this cost is less th an 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 re ntal 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 wh ere the property will always remain subject to that injury” so that they are “d amages 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 addr essed 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 trespa ss claims exemplifies this dependent relationship addressing the question of ownershi p of injected gas to determin e 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. C itizens Fidelity Bank & Trust Co. , 736 S.W.2d 25, 28 (Kentucky S. Ct. 1987)), the plaintiff/appella nt brought an action fo r trespass given that her 54 acres of property were included w ithin the boundary of de fendant’s/appellee’s 15,000- acre natural gas storage field wi thout her knowledge or consent. Hammonds , 75 S.W.2d at 204. The court analogized natural gas to wild anim als and thereby applied the ancient rule of ferae

naturae to the natural gas, even that which had been previously reduc ed 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-i njected into the common source of supply and commingled with virgin gas). Following this an alogy, the court found that “if in fact the gas
turned loose in the earth wandered into the plaintiff’s land, the defe ndant is not liable to her for the value of the use of her property, for the co mpany 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 disa pproval in numerous othe r jurisdictions, Fred McGaha, Underground Gas Storage: O pposing Rights and Interests , 46 La. L. Rev. 871, 87330 (1986), but was not explicitly ove rruled in Kentucky until 1987. See Texas American Energy Corp., supra

, (“[I]n those instances when previously extr acted oil or gas is subsequently stored in underground reservoirs capable of being define d with certainty and th e integrity of said reservoirs is capable of being maintained, title to such oil or gas is not lost”). During the intervening time many jurisdictions fo llowed 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 mu ch in the possession of the storage companies, being within a well-defined stor age 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 natu ral gas public utility lost ownership to gas stored when no certificate authorizing storage wa s obtained and the use of subsurface storage space was without authorizati on or consent of landowner).

In holding that ownership of injected gas previo usly reduced to possess ion is retained by the injector, the courts have ha d to distinguish between nativ e 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 prope rties 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 (10 th 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 a nd 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 subs urface trespass. 46 La. L. Rev. 871, 879 (1986). In New Mexico, the state legislatur e has statutorily declared that gas storage companies are the owners of injected gas. NMSA 70-6-8 (1995).

The issue of subsurface trespass quickly beco mes complex and how it has been analyzed depends greatly upon whether the materials involved in the alleged trespa ss are part of normal hydrocarbon recovery (enhanced rec overy), 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 “negativ e rule of capture,” which has been applied to the injection of fluids generally involved in th e 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 in31 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 substan ces which may migrate through the st ructure to the land of others,
even if it thus results in the di splacement 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 co urt laid out that the policy reasons for doing so were to encourage the maximal recovery of hydrocarbon re sources, the extraction of which by secondary or tertiary recovery methods could otherwise be blocked by any adjoin ing property interest on the basis of subsurface trespass claims. Id . The court held that the ru les and principles of surface trespass are not applicable to s ubsurface 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 explic itly 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 th e licensee, nor does such license immunize the licensee from liability for negligence or nuisa nce which flows from the licensed activity”).

Rather than employing the negative rule of capture, most jurisdic tions hold that mineral interests may make valid claims of subsurface trespass against injectors causing impairment to or displacement of their valid mineral interest. Th e 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, rulin gs 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 b een reserved from the conveyance of the storage rights and mineral and surface estates, had b een depleted. Humble Oil owned the mineral
interests and the surface es tate, subject to West’s royalty inte rest, and had produced 89 percent of the recoverable gas reserves, averring that pr oduction of the remaini ng 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 in jected extraneous gas into the formation for storage. The Suprem e Court of Texas refused to require Humble Oil to produce the remaining native gas to depletion for that would destroy their prope rty right to the storage space.
Id . at 816. Instead, the court attempted to balanc e the competing interests and ruled that the burden is on the party commingling gases to proper ly identify the “aliquot share” of each owner and to pay a royalty on that amount , but if that share is not possi ble to establish with “reasonable certainty,” the injector is then responsible fo r paying royalties on all ga s subsequently produced from the field, extraneous stored gas and native gas alike. Id . at 817-819.

In the case of natural gas storage, th e federal Natural Gas Act, 15 U.S.C. § 717 et seq ., provides for the right of eminent domain for the constr uction of pipelines over private land, which has32 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, subsurf ace 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 effectivel y preempted common-law trespass claims, leaving only the action of inve rse condemnation available to property holders. Steven D. McGrew, Selected Issues in Federal Condem nations 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 qu estion has significant financial implications as punitive damages are available for trespa ss 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 car bon dioxide because there has been no federal preemption of this regulatory field, as there has argua bly been for storage of natura l gas in the enactment of the
Natural Gas Act. See C olumbia Gas Transmission Corp. v. An Exclusive Natural Gas Storage Easement in the Clinton Subterranean Geologi cal 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 th at common law trespass remains a viable action for carbon dioxide sequestration and ha s not been federally preempte d. However, it is possible
landowner actions could be cons trained statutorily by the st ate legislature to inverse condemnation, which would have the desirous e ffect of limiting an injector’s liability, and thereby encourage sequestration by eliminati ng the possibility of punitive damage awards.

In the case of hazardous waste disposal, the courts have been careful to distinguish injections
related to the extracti on 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 a nd gas cases] based on special circumstances,” Id . at 991, not present with the injection of other materi als. However, this distinction seems to have been made for the primary purpose of avoiding th e application of the ne gative rule of capture. Id

. (“Since appellee's injection well operation has nothi ng to do with the extrac tion or storage of oil or gas, we find the negative rule of capture inap plicable to our consider ation 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 an y injection must be shown to interfere with a
landowner’s “reasonable and forese eable 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 “subsu rface rights should be treated differently than air rights because the historical use of subsur face 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 o ff 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 plausi bly argue that property owners have no protectable property in terest in the same geological formation in which they did ha ve a protectable and alienable interest when the formation contained native natural gas. Such a reversal should require strong jus tification. While it is true that underground natural gas storage serves an important public interest, that alone would not pr ovide sufficient justification, for
the Constitution forbids the ta king 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 us es property – even subsurface property – without paying for the right to do so should be liable for
trespass.

Id . at 178-179.

The 10 th Circuit has employed a slightly lower standa rd of proof for subsurface trespass claims than the standard, discussed above, that New Mexico courts appear to apply. In the 10 th Circuit, subsurface trespass claims have been successful when circumstantial evidence was sufficient to demonstrate that the injectors expected the inject ed 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 pres ented was sufficient to demonstrate that the target formation was highly permeable, continuo us 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 suitabl e for gas storage, had demonstr ated that a significant portion of the field’s storage capacity was in the form ation 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 landown ers for the prior seventeen years.” Id

.

Subsurface infringement can, by the common la w 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 esta blishing each of the elements of adverse possession (actual, adve rse, open, notorious, peaceable, exclusive and hostile possession) for a period of fifteen years. Ellis , 450 F.Supp. at 423-424. In Ellis the court34 held that the plaintiffs, seeking damages for una uthorized storage of ga s beneath their property, and their predecessors in title knew that a geol ogic formation under their land was part of the region’s gas storage facility, that it had been used as such cont inuously for nearly 30 years, and that the injection facili ties 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 adequa te 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 Co urt, 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 crea te 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 10 th 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 sampli ng evidence from groundwater monitoring wells, soil samples, air monitoring or geophysical surv eys. Landowners seeking to establish a trespass claim against CO2 injectors would also likely ha ve to demonstrate that any CO2 detected is injected gas, as opposed to na tive gas. As explained in Schwartzman , such burden is on the landowner to establish, which means the landowne r would have to pay for the monitoring and analysis. This burden makes establishing non-obvi ous, minimally intrusive CO2 trespass actions difficult. However, if the New Mexico courts we re to adopt a standard more akin to that expressed by the 10 th Circuit in Beck , subsurface trespass could be easier to establish if the property in question is within th e contemplated storage field or its designated buffer zone. This would likely be so because, as part of the pe rmitting process, the state will likely require a description of the formation and its areal extent ta rgeted for CO2 injection; such information that the court found to be adequate circumstantial ev idence to establish subsurface trespass in Beck

. By the same token, such claims should be elim inated by a requirement that any CO2 injection project acquire the storage rights for the propos ed project area, either through negotiation or condemnation proceedings. Trespass claims are mo re likely to arise in cases where the storage project has exceeded its proposed area of influe nce, and injected CO2 has migrated beyond the intended project boundaries, in which cases such ci rcumstantial evidence is not likely to be as readily available or may be non-existent for lando wners to rely upon to establish the validity of
their claims.

The implied authorization for injection that appl ies to secondary recove ry 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 anticip ated to make up only a small fr action of the to tal sequestration
volume in New Mexico.35 If carbon dioxide emissions become federally re gulated, its storage/inje ction would likely be considered permanent, as subsequent release back to the atmosphere will face a number of significant policy, regulatory and pr actical barriers. For this reas on calculation of damage awards for subsurface trespass claims in New Mexico ma y 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 th e storage space is no longe r 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 conceivabl y 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 meas ure, however, may be something that is addressed by the courts unless the legislature de velops 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 a void the difficulty of ascertaining damage s under trespass.

Further Issues Raised During Analysis : 1. At what point does CO2 injection become st orage and require acquisition of storage space rights? (Because there are limited CO2 se questration/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 tres pass against injector of carbon dioxide?
4. Would the injection of carbon dioxide const itute temporary or permanent trespass?
5. Does the state have authority to condemn federal pore space? How will condemnation/storage be handled wi thin 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 enha nced 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 thr ough 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 in terests. Distinguishing between the pore space interests and the mineral interests, such uniti zation will apply only to the mineral interests.36 In anticipation of the scale of commercial CO2 seque stration, 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 requi res that the plan of unitization, whether voluntary or compulsory, be ratified by th ree-quarters of the working interest, royalty interest and ove rriding 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 c ould refuse to ratify unitization orders, making operation of the unit as a sequest ration field difficult. N on-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 fo r unitization among minera l interests before enabling compulsory uniti zation 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 produ ces 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 additiona l costs, if any, of conducting such operations will not exceed the estimated valu e 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 sepa ration and re-injection/cycling, etc.) as opposed to the costs of the entire sequestration project, th is language should not pose a barrier.

Statutory continuation of expi ring leases may be considered to facilitate planning and implementation of CO2 sequestration projects.

Unitization of federal minerals w ith non-federal minerals is provided for in the federal “Mineral Leasing Act,” 30 USC Code, Chapter 3A, Subcha pter 1 § 184a: “...any State owning lands or interests therein acquired by it from the Unite d States may consent to the operation or development of such lands or interests, or any part thereof, under agr eements 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 th e purpose of more properl y conserving the oil and gas resources within such State. Such agreem ents may provide for the cooperative or unit operation or development of part or all of any oil or gas pool, fiel d, or area; for the allocation of production and the sharing of proceeds from the w hole 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 th e terms and provisions of State leases for lands37 operated land developed thereund er, 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 conf lict with the purpose of CO2 sequestration? How to handle sequestration units that in clude strata with federal minerals?
2. What is the effect of Indian owners hip on unitization for carbon sequestration?

Condemnation of Storage Space and Tran sportation 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 la w to provide for the acquisition by eminent domain of subsurface pore space for the purpose s of CO2 sequestration. Authority to condemn subterranean storage space, si milar to provisions in NMSA 70- 6-1 through 70-6-8 authorizing the condemnation of underground storage space fo r natural gas, would be necessary for CO2 sequestration operators to acquire the storage rights from proper ty owners who have not reached
an agreement.

Compensable parties may not be limited to the ta rget 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 interf erence 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 recove ry method. Likewise, no strata capable of producing gas in paying quantities can be condemned unless th e 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 sma ller disposal lines and gathering lines may be acquired across private property.

All condemnation proceedings must be done in accord with and pursuan t 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 stor age space/interval/strata, what’s the effect on the other intervals? Can hydrocarbon explora tion/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 separa te statute, but because the target pore space and geologic formations are the property inte rests of the surface owner, a process for the condemnation of the pore space for CO2 storage mu st 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 applicab le to valuation of sequestration space for CO2:

 Comparable agreements/rentals/sales

 Capitalization of rental income: multiply acr eage 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 st orage field as end date. Fair market value is equated to a capital sum which, when invested as of the da te 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 di fference in the fair market value of the
entire condemned tract befo re and after the taking.

 Viewpoint of value: just comp ensation should be measured from the point of view of the landowner (what the landowner has lost, not wh at the petitioner (inj ector) has gained), e.g., if there are still qua ntities of native oil or gas in the storage easement not in paying quantities (having no effect on th e 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 produc tion of hydrocarbons, and may be anticipated to generate, facilitate or increas e such production. Unlike the situation for storage of natural gas which essentially precludes concurrent hydroc arbon recovery, there may be no ostensibly negative impact or interference with the production of the mine ral estate beyond the cost of segregating the CO2 from productio n 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-reco verable/non-economic minerals39 Authority to Transfer Liab ility/Ownership to State

Issue : The various forms of liability (e.g. economic and environmental) inherent in proposed sequestration projects and how they will be addr essed 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 pub lic acceptance of the technologies, processes and regulations.

Short-term liabilities inherent in any drilling or injection proj ect – whether environmental or economic – can likely be best addressed thr ough the contractual arra ngements between CO2 generator and injector, as such liabilities are currently hand led. 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 anticip ated scale of sequest ration projects, both in terms of time and space, requir ed for successful CO2 mitigation.

Nearly all of the sequestration literature assumes th at long-term liability mu st be transferred to the public sector to maintain economic viability and to encourage industr y participation. Because the lifespan of sequestration pr ojects after closure, which woul d include continuous monitoring, measurement and verification (MMV ) of the reservoir integrity, is contemplated to endure for possibly hundreds to thousands of years, the publi c sector (because of the longevity of public
institutions and the ease of tran sferability of institutional knowledge ) is seen as the most viable entity capable of maintaining th ese projects over the long term. Alternatives include having the state accept liability for a limited nu mber 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 an d the carbon sequestrati on industry to retain ownership and liability with coverage provided by a co mbination 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 ce rtain number of projects (e.g. the first enhanced oil recovery project, the first severa l deep saline projects, the first deep coal projects, etc.) or should the state accept liab ility for those projects initiated within a limited time frame (e.g. first 5 y ears of CO2 sequestration)?

 If liability is transf erred to the public sector, how sh all 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 f ee or maintain liability with bonding to cover insolvency or
abandonment?

 Who owns the sequestered CO2 should it b ecome a viable produc t in the future?40 Issues Raised During Workgroup Meetings :

 Will the state be liable for mitigation/dama ges after transfer? Should state liability beyond the amount covered by the fee pool be protected as a sovereign immunity?

 Texas proposes to accept liabili ty only for FutureGen sites.

 If there is a fee, it should be used onl y for mitigation, long-term monitoring, and verification of sequestrati on projects (i.e. protected against other legislative appropriations).

 State should only take on ow nership/liability of projects where monitoring following cessation of injection/operations indicates the project is performing as predicted.

 State should only take on owners hip/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 m onitoring, 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 l ong-term liability makes the pr oject more appealing – the sooner the state takes on liability the more appealing the project

 If there is a transfer of liab ility, the state must have the right to enter private land and plug/re-plug problem wells within the sequestra tion unit to ensure fi eld/storage integrity.

 Is/will CO2 be considered a “hazardous substance” under federal CERCLA/RCRA laws and how might that impact liab ility for generators, transporte rs and disposers/injectors?

Analysis : Because the issues of financial assurance and liab ility are, in many ways, so tightly interrelated, the review and analysis of these i ssues have been addressed jointly.

The literature reviewing carbon di oxide sequestration liability a nd 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 pr oper liability scheme at this time.

Price-Anderson Nuclear Industries Indemnity Act: 42 U.S.C. s. 2210

The Price-Anderson Nuclear Industr ies 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 av ailable a large pool of funds to cover public compensation for claims of personal injury and property damage. The Act holds nuclear reactor operators/ow ners 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 ju mp 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 insu rance 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 insure rs. 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 f und of $95.8 million in the event of an accident. The total fund would currently c over 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 sc heme, any costs exceeding the coverage provided by
first the insurance a nd then the fund would be cove red by the federal government.

The Act requires as a condition of the opera ting license issued by the Nuclear Regulatory
Commission that the licensee “have and maintain financial protecti on of such type and in such amounts as the [Commission] in the exercise of its licensing and re gulatory authority and responsibility shall require ... to cover public liability claims .” 42 U.S.C. § 2210(a). The Act further provides that the Comm ission may, also as a condition of the license, “maintain an indemnification agreement,” but also “that an a pplicant 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 re quired, “agree to indemnify and hold harmless the licensee and other persons indemnified, as th eir interest may appear, from public liability arising from nuclear incidents wh ich is in excess of the level of financial protection required of the licensee.” Further, “[t]he a ggregate indemnity for all persons indemnified in connection with each nuclear incident shall not exceed $500,000,000 excl uding costs of investigating and settling claims and defending suits for damage, provided, how ever, “that this amount of indemnity shall be reduced by the amount that the financ ial protection require d shall exceed $60,000,000. 42 U.S.C. § 2210(c). Such indemnifica tion 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 c ontracts 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 nuclea r 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 causi ng 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 Nu clear Regulatory Commi ssion or Secretary of Energy, as appropriate, determines to be substantia l, and which , determines has resulted or will probably result in substantial damages to persons off site or property off site.” Id . (citing 4242 U.S.C. § 2214 (j)).

The Act requires that the primary financial prot ection required for large nuclear reactors (larger than 100 mega-Watts) “shall be the maximum am ount available at reasonable cost and on reasonable terms from private sources.” 42 U.S.C. § 2210(a)(1). The Act provides that “primaryfinancial protection may include private insurance, private contractual indemnities, selfinsurance, other proof of financ ial responsibility, or a combinati on 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 pa rt 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 defe rred premium that may be charged against a licensee following any nuclear incident to no mo re 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 limiti ng the amount that may be charged following a nuclear incident to the licen see’s pro rata share of the aggregate public liability claims and costs. Id

.

According to the Act, the aggregate public liabi lity for a single nuclear incident of persons indemnified, including legal costs authorized wi thin 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 involv es damages in excess of the amount of the aggregate public lia bility, “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 Representa tives of the affected districts, the Senators of the affected states and to the public, the parties involved, a nd to the courts. 42 U.S.C.A. § 2210 (i)(1)(A)-(B).
Within three months of the incident the Presiden t 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 ag reements, 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 th an larger reactors. 10 CFR § 140.11 (a)(1)-(4). Coverage for non-profit educationa l reactors is a function of th eir maximum power and the size of the neighboring population (x = B(P), where x is the amount of financia l protection; B is the base amount of financial protection ($185 times the maximum power level); and P is the43 population factor (on a scale from 1 to 2; and area considered is w ithin a radius in miles equal to the square root of the maximum reactor pow er level)). 10 CFR § 140.12. Large commercial reactors are required to obtain financial pr otection “[i]n an amount equal to the sum of $300,000,000 and the amount available as secondary fina ncial protection (in th e form of private liability insurance avai lable under an industry re trospective rating plan providing for deferred premium charges equal to the pro rata share of the aggregate public lia bility 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 author ized to operate two or more nuclear reactors at the same location, the total pr imary financial protection required is the highest amount that would otherwise be required for a ny one of those reactors. 10 CFR § 140.11 (b).

The NRC’s regulations further re quire that each licensee at the issuance of the license, and annually, demonstrate to the Commis sion that it maintains one of several types of guarantee of payment of deferred premium (surety bond, lett er of credit, revolving credit/term loan arrangement, maintenance of escr ow deposits of government securi ties, annual certified financial statement showing that cash can be generated and made available, or othe r type of guarantee “as may be approved by the Commission”) in an amo unt of $15 million for each reactor licensed for operations. 10 CFR § 140.21.

Resource Conservation and Recovery Ac t (RCRA); 42 U.S.C. § 6901, et seq

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Enacted in 1976, the Resource Conservation and Recovery Act (RCRA) was passed to encourage the recycling of ma terials, establish a means to regul ate 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 Li ability Act (CERCLA, discussed below), however, RCRA regulates actively managed and ope rational sites, facili ties and processes. Similar to the philosophy employed subsequen tly in the writing of CERCLA and in the formulation of the Underground In jection Control program (UIC), infra , RCRA directs the
Administrator of the U.S. Environmental Protec tion Agency to promulgate regulations that, among other things, provide for the financial respons ibility (including financial responsibility for corrective actions) of the responsible parties.

According to the regulations, “[a]n owner or opera tor of each facility mu st establish financial
assurance for closure of the f acility” 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 trus t fund must be made annually by the owner or operator over the term of the facility’s RCRA perm it, or over the term of its rema ining 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 pa y-in period. § 264.143 (a)(3)(i).44 A second option is a surety bond, guaranteeing pa yment 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 pe rformance of closure. § 264.143 (c). Such bonds
must be effective before the initi al receipt of hazardous waste for treatment, storage or disposal. § 264.143 (c)(1). The surety company issuing th e 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 es tablish a standby trust fund. § 264.143 (c)(3).

Also available as an option for financial assura nce is a closure letter of credit, § 264.143 (d), which is established when an owner/operator obtain s an irrevocable standby letter of credit from an issuing institution which has the authority to is sue 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 iden tical 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 cl osure 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 financ ial assurance requirements by obtaining closure insurance. § 264.143 (e). The closur e insurance policy must be i ssued 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 al so be established through a fi nancial test and corporate guarantee for closure, whereby an owner/operator dem onstrates the ratio of its total liabilities to net worth is less than 2; a rati o of the sum of net income, pl us depreciation, depletion, and amortization to total liabilities greater than 0.1; an d a ratio of current assets to current liabilities45 of greater than 1.5; and a net working capital a nd net worth at least si x 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 owne r/operator must submit updated information within 90 days after the close of each succeeding fiscal year; if it no longer m eets the requirements above, the owner/operator must send notice of intent to esta blish 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). Av ailable 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 a ssurance, the owner/operator must within 60 days after the increase, increase the financial assurance accordingly; wh enever the current closure cost decreases, the amount of assura nce required may be reduced acco rdingly with written approval by the EPA regional administrato r. § 264.143 (a)(7), (b)(7), (c)(7 ), (d)(7), (e)(9), (f)(6).

Similar mechanisms are available for funding pos t-closure financial assurance. § 264.145 et. seq. And, an owner/operator may satisfy the requirements for financia l assurance for both closure and post-closure care for one or more facilities by us ing a trust fund, surety bond, letter of credit, insurance, financial test, or corporate guarantee that meets th e specifications of §§ 264.143 and 264.145. § 264.146.

Beyond closure and post-closure financial assurance mandates, RCRA requires that owners/operators demonstrate fina ncial responsibility “f or bodily injury a nd 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 annua l aggregate of at leas t $2 million, exclusive of legal defense costs.” Id . Coverage may be achieved by acqui ring a liability insurance policy, through a financial test or cor porate guarantee, a letter of cr edit, 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 withan 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 financia l 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 a ny 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 Congr ess 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 (8 th Cir. 1987). The Eighth Circui t 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 endange rment 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 qu estion of a defendant’s civil liability for violati ng a RCRA permit provision, stan dard, regulation, condition, requirement, prohibition, or order, and to civil liability for th e 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, Compen sation and Liability Act, CERCLA (Superfund) 42 U.S.C. §§ 9601-9675

.

Passed by Congress in 1980, CERCLA was designe d to address abandoned hazardous waste sites, as opposed to ac tive 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 ap propriations for the cleanup and management of sites for which no responsible party can be id entified or held acc ountable, most commonly because of dissolution or bankruptcy. Under CE RCLA, four classes of parties, known as “potential responsible parties,” may be liable for contamination at a Superfund s ite: the current owner or operator of the site; the owner or opera tor of a site at the tim e that disposal of a hazardous substance, pollutant or contaminant o ccurred; a person who arranged for the disposal of a hazardous substance, pollutant or contaminan t at a site; or a person who selected a site for disposal and transported a hazardous substance, pollu tant or contaminant to that site. Liability is also limited by recognizing in the statute ce rtain 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 operato r,” “any person who at the time of disposal owned or operated any facility at which such ha zardous wastes were disposed of,” “any person who by contract, agreement, or otherwise arrange d 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 wh ich 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). Liabili ty 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 c onsistent with the national contingency plan,” “damages for injury to, dest ruction of, or loss of na tural resources, including the reasonable costs of assessing such injury, dest ruction, 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 seve ral, 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 impos ed 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 th at 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 wa ste and the harm caused by the release at a particular disposal site. CERCLA only requires that the plain tiff prove by a preponderance of the evidence that the defendant depos ited his hazardous waste at the site and that the hazardous
substances contained in the defendant's waste ar e 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 defe ndant is among one of the four categories of pot entially responsible parties listed in § 107 (a); a release or threat of
release of a hazardous substance has occurred at the facil ity; and the release or threatened release has caused the government or privat e party to incur “nec essary” response cost s consistent with the National Contingency Plan. Violet , 648 F.Supp. at 1289. (“Courts ha ve generally held that liability under section 10 7(a)(3) requires proof of four basi c elements: 1) that the generator disposed of hazardous substances; 2) at a fac ility which contains at the time of discovery hazardous substances of the kind the generator dis posed; 3) there is a release or a threatened release of that or any hazardous substance; 4) wh ich triggers the incurren ce of response costs”); see also 80 Am. Jur. Proof of Facts 3d 281 § 2.

Liability, however, is expressly limited by statutorily defined defe nses, including “(1) an act of God; (2) an act of war; (3) an act or omission of a third party ot her than an employee or agent of the defendant, or than one whose act or omissi on occurs in connection with a contractual relationship ... with the defenda nt ... if the defendant estab lishes by a preponderance of the evidence that (a) he exercised due care ... and (b) he t ook precautions against foreseeable acts or48 omissions of any such third party and the conseq uences 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 respon sible person ... shall be the full and total costs of respons e and damages, if (A)(i) the rel ease or threat of release of a
hazardous substance was the result of willful mi sconduct or willful neglig ence within the privity or knowledge of such person, or (ii) the primar y cause of the release was a violation ... of applicable safety, construction, or operating standards or regulati ons; 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 ac tivities. 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 mo tor vehicles, aircraft, ha zardous 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 lim ited 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 releas es 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 thre e times, the amount of any costs incurred by the Fund as a result of such failure to take prope r action.” 42 U.S.C.A. § 9607 (c)(3). This subparagraph authorizes civil action against any such pers on 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 pr ovision 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 wast e disposal facility in curred by other parties after the period of monitoring re quired by the Solid Waste Dispos al 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 appl ied to hazardous waste di sposal sites, CERCLA directed the comptroller genera l 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 envir onment. 42 U.S.C.A. § 9607 (k)(6)(A). The study was to look at options for develo ping a post-closure program that (1) assured incentives for the safe management and disposal of hazardous wast es 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 ow ners and operators of hazardous waste disposal facilities will be able to manage their potential fu ture liabilities and attract the investment capital necessary to build, operate, and close such faci lities 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 possi ble” 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 a nd operators; (2) legislation to require risk pooling by owners and operators; (3) limiting the transf er of liability to the Post-Clo sure Trust Fund only in cases of insolvency of owners and operato rs; (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 s ubsidized 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 charte red corporation. Id

.

To protect against the po ssibility of un-reimbursed expenses related to the management, care or cleanup of sites being borne by the government, CERCLA provide d for liens against all real property and rights to such pr operty belonging to parties subj ect to CERCLA authority. § 9607 (l).

CERCLA provides that financial responsibil ity, as established a nd determined by § 9607, discussed above, “may be established by any one, or any combination, of the following: insurance, guarantee, surety bond, or qualificatio n 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 an d 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 no t been satisfied, and claims from a release or
threat of release of a hazardous s ubstance for injury to or destruct ion or loss of natural resources, including costs for damage assessment. § 9611 (b )(1). The Act provides th at 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 th e sum from liable parties. § 9611 (b)(2)(A).

Safe Drinking Water Act, Underground Injec tion Control Program (SDWA UIC): 42 U.S.C. § 300f et seq.

The Safe Drinking Water Act’s (SDWA) U nderground Injection C ontrol (UIC) program regulates the underground injecti on 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 de legated to 34 states, including New Mexico,50 operating under the authority of EPA to enforce the program. ( http://www.epa.gov/safe water/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 operatin g features so that technical requirements can be applied consistently. Class I wells include the emplace ment 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 a nd are further regulated under RCRA. Id . Operators of Class I wells “must demonstrate that their hazardous inje ctate will not migrate from the injection zone for as long as it remains hazardous. Stephanie M. Haggerty, Legal Requirements for Widespread Implementation of CO2 Sequestratio n in Depleted Oil Reservoirs , 21 Pace Envtl. L. Rev. 197, 206 (2003) (citations omitted). Cl ass I well operators must con tinuously monitor the injection well, the fluid within the well, and any possibl e migration out of the target injection zone. Id (citations omitted).

Class II wells include those that inject brines and other fluids associ ated 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 Mexi co must also ensure the injectate does not migrate beyond the target injection zone, and must identify other well s 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 w ith solution mining of minerals. Cl ass 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 inje ction of non-hazardous fluids into or above a USDW. Class V wells are typically shallow, on-s ite 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 sequestra tion. Groundwater recharge we lls, for aquifer storage or prevention of saltwater intrus ion, 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 promul gated under the SDWA “s hall 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) th e underground injection of brine or other fluids which are brought
to the surface in connection with oil or natura l gas production or natural gas storage operations, or (B) any underground injection fo r the secondary or tertiary rec overy of oil or natural gas, unless such requirements are essential to assure that underground s ources 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. (See51 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 distin ct 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 Sequestrati on Projects – UIC Program Guidance (UICPG #83), March 1, 2007). In its guidance document, EPA recognizes that carbon dioxide sequestration
could fit within the classificati on of Class I wells, as well. Id . at 5. EPA is clear in its guidance document, however, that no carbon dioxide sequest ration project should be permitted as a Class II well, but that in the case where an EOR project using CO2 injection inte nds 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 UI C 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 resour ces to close, plug, a nd abandon the underground injection operation in a manner prescribed by th e 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 progr am provides minimum rules fo r siting, testing, installing, operating, monitoring, reporting, and abandonm ent 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 shap e 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 St orage 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 th e 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 fo r 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 demons trate and maintain fina ncial responsibility and resources to close, plug, and abandon the undergr ound injection operation in a manner prescribed by the Director”). The UIC re gulations do, however, have speci fic liability and financial assurance requirements that apply only to Cl ass I wells. § 144.60 (sta ting that §§ 144.61 through 144.70 apply only to Class I wells). These financia l assurance requirements are modeled on those52 established by RCRA. Framing the Liability Issue at 654. As such, the wording is nearly
identical to the financial assurance re quirements in the RCRA regulations.

Before selecting a method of financial assuran ce, Class I well operato rs/owners must first establish a cost estimate for plugging and aba ndonment. § 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 pluggi ng 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 mech anisms: a plugging and abandonment trust fund, a surety bond guaranteeing payment into a plugg ing 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 gu arantee, 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 requireme nts, the UIC regulations also require the owner/operator of Class I wells to “prepare, maintain, and comp ly with” a closure plan, which “survives the termination of a pe rmit or the cessation of injec tion 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, th e permit conditions themselves require financial responsibility for the adequate plugging and ab andonment 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 fi nancial responsib ility to “close, plug and abandon the underground injection in a manner prescribed by the Direct or,” as required in § 144.52(a)(7). § 146.71.

Beyond the requirement for maintaining a closur e plan and financial assurance for proper plugging and abandonment, owners/ope rators of Class I wells must also prepare and maintain a post-closure plan, which survives the terminati on of a permit or the cessation of injection. § 146.72. Among the plan’s mandated elements is an es timate for the cost of post-closure care. § 146.72 (a)(4)(vi). Section 146.73 requir es that an owner/operato r “shall demonstrate and maintain financial responsibility for post-clos ure care by creating a trus t fund, surety bond, letter of credit, financial test, insurance, or corporat e 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” th an the amount identified in by the estimate in § 146.72 (a)(4)(vi). The obligation to maintain financial responsi bility for post-closure care survives the termination of a permit or the cessati on of injection and is en forceable regardless of53 whether the requirement is a condition of the permit. § 146.73.

Unlike RCRA, UIC does not extend it s regulatory language to include coverage responsibility for accidents, nor does it provide coverage for da mage 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 regulat ory language is somewhat more narrowly confined to the protection of USDW against cont amination which may result in a drinking water system not complying with any national primary drinking wa ter regulations or ma y otherwise adversely affect the health of people. 42 U.S.C. § 300h (d)(2).

New Mexico has been delegated primacy for th e 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 incorporat es 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 Contro l Commission Regulations (rules 5000 through 5299), as well as the New Mexico Water Quality Act, the Geot hermal Resources Conservation Act, the Surface Mining Act, the Memorandum of Agreement between the EPA Region VI and the New Mexico Water Quality Control Commis sion, 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 li ability, 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 Ac t (LLWPA): 42 U.S.C. § 2021b et seq.

Unlike any of the liability models discusse d, the Low-Level Radioactive Waste Policy Act (LLRWPA) provides that each stat e may be responsible for handling the disposal of low-level radioactive waste generate d within the state, except essent ially that which was created by the federal government. 42 U.S.C. § 2021b et seq. Th e Act also encourages states to work cooperatively to form compact regions as a m eans 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 ge nerator 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 take54 possession of the waste as soon after January 1, 1 993, 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 posse ssion 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 w ith an incentive to manage its low-level waste, was deemed by the Supreme Court to be unconstitutional and violative of the 10 th 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 di rect order to regulate , standing alone, would also be beyond the authority of Congress, it fo llows that Congress lacks the power to offer the States a choice between the two”).

Written according to the proposals of the National Governor’s Associati on with the purpose of giving states more control over the siting of low-level waste du mps, 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 es tablished “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 gene rally 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). Accordin g to at least one in terpretation, “[t]he example of low-level radioactive waste shows th at liability regimes ma y 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 fe asibility of large-scal e, commercial carbon dioxide sequestration has explor ed possible mechanisms to addr ess 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 gr oups and industry representatives on the draft interim report. Sufficient financial assurances and an appropriate a nd reasonable liability standard together with thorough, clear and reason able regulations can create the required degree of certainty and predictability necessary for insure rs to offer adequate coverage in this new and unexplored field and for operators to develop realisti c business models. Similarly, sufficient financial assurance and a prope rly scaled liability standar d, combined w ith protective regulations, can also instill confidence in the pub lic 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 leve l of legal liability can create in insurers an additional layer of regulatory ove rsight beyond what the state itsel f could otherwise provide. All of this must be accomplished without placing an undue financial burden on the industry, or55 otherwise stifling development of carbon dioxide sequestration proj ects, which are viewed as an important component of the state’s climate change mitigation strategy.

According to the literature reviewed to da te, liability and financial assurance can be accommodated on essentially four levels: (1) th e 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 ade quate incentive exists to undert ake sequestration projects, but selecting the right combination or balance will require carefu l consideration of the various
interests and inherent risks.

Drawing on current oil and gas practices, the shor t-term liabilities inherent in any drilling or injection project – whether environmental or eco nomic – can likely be be st 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 larges t sequestration projects. Likewise, liabilities following the injection and closure phases of projects present a unique problem given the anticipated scale, both in term s of time (hundreds to thousands of years) and space, required for successful CO2 sequestration and accurate CO2 i nventories. Liabilities facing this new field include potential trespass actions involving bot h 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 to pic suggest that wells a nd 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 developmen t of sequestration projects by lim iting potential liabilities that must be born by the individual injector or the indu stry. But this liability model also raises many issues, such as how to limit the burden on th e 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 environm ental regulatory fram eworks, the long-term liability could be maintained by the injectors themselves and managed according to the models established by one of several pre-existing envi ronmental regulations, discussed above. An example of some combination of these models is presented below:

A liability scheme may:

• Impose strict liability for extraordinary occu rrences, e.g. for contamination of protected groundwater sources, or for catas trophic releases (above a cert ain 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 cost s if willful misconduct or willful negligence is proven, or if the event was due to a violati on of some applicable standard or regulation or if the operator failed to provide reasonable assistan ce with response operations

• Create an industry-funded pool with deferre d premiums for accident coverage and environmental mitigation costs that exceed an individual’s insurance liability

• Require demonstration of financial assuranc e 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 res ponsible parties will be who will bear the liability

• Limit defenses, as in CERCLA, to: 1) act of G od; 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 ab andonment of individu al 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 pos t-closure plan for review and approval by
the Division

Transfer of Liability to Public Sector

Transfer of liability to the pub lic sector is not without preced ent, as a similar scheme was contemplated and employed briefly by CERCLA, wh ich 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 w ith 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. Rolly son, acting tax legislativ e counsel, Dept. of the Treasury). Thus, if these prerequi sites were satisfied, future liab ilities arising from the operation of the facility were shifted from the res ponsible parties to th e Federal Government. Id . Because payment of the tax shifted liability for post-clos ure damages to the Federal Government, the tax payments could be equated with premium paym ents for post-closure Government liability insurance paid by such owners and operators. Id . Conversely, in the absen ce of such insurance,57 owners and operators of disposal facilities would be liable for pos t-closure claims in perpetuity.
Id

.

Solid waste operators sought to re tain 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, Compen sation, 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.

, 98 th 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 pr epaid, 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 op erator of the site remained responsible for monitoring and maintenance for 30 year s after closure of the facility. Id . Arguments in favor of eliminating the fund included the concern that with limited liab ility, operators had no incentive to design facilities to last any l onger 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 “i nternalized” into the cost of di sposal 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 t hose 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 Wa ste Council argued agains t 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 permanen t and protective methods of management.” Id . at 129 (statement of Richard C. Fortuna, Exec. Dir., Hazardous Waste Treatment Council). Further, “[ t]his attractive liabili ty 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 a nd land disposal transactions.” Before the Subcommittee on Commerce, Transportation and Tourism, H. Comm. on Energy and

Commerce , 98 th Cong. 197-198 (Feb. 28, 1984) (statement of Dr. Nelson Mossholder, Technical Dir., Stablex Corp., on behalf of th e Hazardous Waste Treatment Council)

Criticism came from environmental groups, as we ll, which saw the Post-Closure Liability Fund as creating “an incentive to do the most mode st, minimal cleanup, adopt the most minimal approach, that would get you by that first 5 years and not a ssume responsibility for the subsequent acceptability of the disposal practice.” Reauthorization of and Possible Amendments to the Comprehensive Environmental Respons e, 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. , 98 th Cong. 474 (June 13, 1984) (statement of Kenneth Kamlet, Dir. Pollution and58 Toxic Substances Div. Nat. Wildlife Fed.). Acco rding to the National Wildlife Federation’s testimony, the fund “put() the incentive in the wr ong place, in short, and we think that the environment and the public would be better prot ected without it, putting the liability on the shoulders of those that pursue these alternat ives 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-clos ure 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 simila r difficulty will be faced when trying to determine the appropriate level of funding for a carbon dioxide sequest ration post-closure fund, as no true precedent exists with which to determine adequate and reasonable funding levels for
the areal extent and duration contem plated for sequestration projects.

The OCD makes no recommendation regarding ma nagement 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 presen ts 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 in surance plan. Difficulties inherent in establishing such a fund include the challenge of determini ng proper payment levels and the concern that injectors/operators will engineer their operations to a mini mum level necessary only to achieve transfer to the public sector, rath er than to that which is most protective. Funding levels can be fluid and adapted on an interim basis as more da ta and experience accrues, but the risk remains that any funding level will be considered arbitrar y 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 a nd 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 addre ssed through a private in surance 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 compen sation 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 availabl e funding pool for liability cl aims 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 signifi cant 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. Howe ver, unlike the nuclear power industry, carbon dioxide sequestration likely poses a far-reduced threat compar ed to nuclear energy production and likely won’t be considered an abnormally dangerous activity, si milar to natural gas transportation and storage. Fo r this reason, indemnifying the sequestration industry against catastrophic events should be consid ered 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 liabil ity – private insurance and an industry-wide fund, in addition to well-bonding an d project bonding requirements – could add up to a financial burden that is too unwieldy to spur industry de velopment. Price-Anderson’s approach to this problem, allowing the industry fund to be a deferr ed payment (until an event appears likely to exceed the insurance capacity), could be adapte d 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 liabl e in a given year or per occurrence.

The benefit of this approach is that owners/operators remain di rectly accountable through private insurance up to, perhaps, a maximum bearable leve l, before the burden shifts first to the industry itself, then to the public sector. To keep premiu ms 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 owners hip 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 sequestra tion projects accords with this philosophy.

An alternative to an outright transfer of liabil ity 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, Al ternative 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, transporte rs) and for different events (e.g. catastrophic leaks, trespass, nuisance, contamin ation of drinking water sources), perhaps chief among them the predictability and public confidence gained that c ould eliminate to some extent60 uncertainty that would otherwise serve as an impediment to development. At the same time, much can be said for limiting the initial regul atory and statutory framework overseeing a new field for which little practical data exists, allowi ng for greater flexibility in permitting until data can dictate appropriate and reasonable standa rds. Likewise, as more knowledge, data and practical experiences accrue, es pecially specific to New Mexico geology, proper and reasonable liability standards (e .g. strict liability, negligen ce, 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 expres s congressional intent in the case of CERCLA – strict liability against potentially responsible pa rties, 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 expans ive 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, Compen sation, 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.

, 98 th Cong. 518-527 (May 15, 1984). Around that time in the mid-1980s, law reviews noted that “[i]nsurers no longer offer pollution policies becaus e of unpredictable judici al determinations of the scope and extent of insurer liability. The fu ture 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-Base d 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 d eemed 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, si milar 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 re gulations for releases “over which they had no
actual control.” Reauthorization of and Possible Am endments to the Comprehensive Environmental Response, Compensation, and Li ability Act of 1980: Hearing on H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans. , 98 th Cong. 520 (May 15, 1984) (statement of John J. Fitz patrick, Jr., Washington counsel to Gulf Oil Corporation). The American Insurance Associati on 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 defenda nt, and that such a standard61 “necessarily depreciates incentives otherwise available to encourag e 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, Compen sation, 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.

, 98 th Cong. 628 (June 13, 1984) (statement of Th e 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 de signed 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 na rrower 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 fo r personal injury or any third party economic damages which ma y be attributed to the condition.” Id . As such, the statutory construction of CERCLA both assure s the accountability of owners/operators for specified, targeted claims, while essentially li miting liability for pers onal 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 a nd post-closure manageme nt and monitoring of sequestration wells and project areas together with express st atutory language creating strict liability for certain events and/ or parties could go a long way to ward 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 impairme nt of drinking water res ources, 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 in jector liability. Without clear statutory language to dictate liability standards, in jectors, insurers and the public mu st await the uncertain process of litigation for the courts to determine applicable liability standards, a pr ocess 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 deterren ce and does not cause project avoidance by being overly prescriptive, as opposed to being performance based.

Joint and Several Liability62 Unlike strict liability, which has been argued increases the predictability of liability, joint and several liability potentially expa nds liability well beyond what an individual operator may have contributed to an accident or situation to the poin t that it may prevent insu rers or injectors from participating, as in the early days of CERCLA. A considerati on favoring a closer evaluation of the utility of joint and se veral liability in the field of carbon seque stration is that it ensures direct accountability regardless of the number and variety of parties i nvolved in a given project, and may hasten settlement among potentially responsi ble parties, avoiding th e cost of dilatory litigation proceedings.

Hazardous waste handlers argued against the impos ition of joint and severa l 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 in equity constituted the repeated refrain from industry and insurance groups during the CERCL A amendment hearings in the mid-1980s. “By imposing joint and several liability, potentially re sponsible parties have no incentive to come forward, absent an enforcement action, to in itiate a voluntary clea nup ... [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, Compen sation, 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.

, 98 th Cong. 518-519 (May 15, 1984) (statement of John J. Fitzpatrick, Jr., Wa shington 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 cont ributions, without the cost and dilatory effect of typically prolonged lawsuits. See Reauthorization of and Possible Amendments to the Comprehensive Environmental Response, Compen sation, 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.

, 98 th Cong. 87-95 (April 3, 1985). The policy motivati on 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 co me forward with a settlement.” Reauthorization of and Possible Amendments to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980: Hear ing on H.R. 5640 Before the H. Subcomm. on Water Res. of the Comm. On Public Works and Trans. , 98 th 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 sens e for hazardous waste, where numerous parties may have had access to various waste sites with va rying 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 dioxid e sequestration, because of the na ture 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 c ontain a wide variety of wastes of varying dangers deposited by numerous responsible par ties, whereas carbon dioxid e waste would involve63 disposal of a single, c onsistent waste from far fewer potentia l sources. All of th ese factors seem to suggest that the utility of imposing joint and several liabi lity 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 woul d be unitized, so that if there were multiple injectors into a single field, there would be multip le 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 some one, ultimately, is held accountable. Courts have generally applied joint and several liabilit y where two or more persons cause a single and indivisible harm. Thus, the assignment of joint a nd several liability might be best left to the courts as the facts of a given situation that mi ght require its application cannot be completely anticipated and to impose it stat utorily precludes the flexibilit y 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 a nd 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 Re source 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 a pportion responsibility or establish which among several tortfeasors were responsib le for the harm. Where alternativ e 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), wh ich states: “Where the conduct of two or more actors is tortious, and it is prove d that harm has been caused to the plaintiff by only one of them, but there is uncertainty as to which one has cau sed it, the burden is upon each such actor to prove
that he has not caused the harm.” 34 Santa Cl ara L. Rev. 1269 (citing Restatement (Second) of Torts § 433(B)(3)). In the commen ts 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 deci ded ... have all been cases in which all of the actors involved have been joined as defendant s. 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 sa me 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 ex ceptional rule placing the burden of proof as to apportionment upon the defendant or defendants is the injustice of a llowing a proved wrongdoer who has in fact caused harm to the plaintiff to escape liability merely b ecause the harm which he
has inflicted has combined with similar ha rm inflicted by other wrongdoers...” Restatement (Second) of Torts § 433(B)(3) cmt. d. The Rest atement suggests that “in such a case the defendant may justly be required to assume the bur den 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 ha s been extended to environmental cases where proving causation among numerous potential defendants has prove d 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 pr otection statutes, and sh ould be applied more broadly to environmental regula tions, leading to greater complia nce 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, transpor tation, and treatment regime requires clear and unambiguous legislation” so that parties are aware of th eir potential liability at the outset of an undertaking. Id . Stating a clear and unambiguous liability standard has the a dditional benefit of allowing court to look at the legi slation and understand the intent of the legislators, allowing them to rule accordingly, which th ey cannot do under RCRA, for example. Id

.

In her recommendations for amending RCRA to esta blish an alternative li ability 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 s hould require plaintiffs to meet a slightly higher initial threshold of proof before the burden is shifted to the defenda nts to maintain equity, and language “should delineate the defendant’s burd en if alternative liab ility 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 li ability 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 th eory 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 i nduce the benefits ascribed to it by Van der Reis; certainly the literature tends to support the concept that predicta bility 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 de fendants early in the life of a regulatory scheme might prevent a liability standard from naturall y settling out of its ow n accord in a way that meets the needs of the disparate parties, and su ch an imposition could simply add to the burden of a nascent and unproven industry. However, si milar 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 si ze and duration of anticipated projects.

Un-insurability

Also discussed in the CERCLA reauthorizati on debates of 1984-85 was the issue of the uninsurability of hazardous waste f acilities and waste disposal site s given the retroactivity of the Act, a perceived certainty that seepage w ould occur at some point, and the unknown and65 seemingly expansive liabilities an in surance company would be taking on. Superfund Amendments and Reauthorization Act of 1986: Befo re 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: Respondi ng to an Uncertain Legal Standard , 68 Tex. L. Rev. 1237 (May 1990). At the time several prominent leader s in the insurance indus try testified to the uninsurability of hazardous waste sites; they were critical of provisions that allowed for the uncontracted for extension of liabi lity of a responsible party thr ough joint and several liability – potentially making one party financ ially liable for all the costs asso ciated with a hazardous waste site even though their privately negotiated insurance contract speci fied a lower-level of liability.
Id . at 26-37. The difficulties identified and associ ated with insuring hazardous waste sites are that numerous parties may be responsible over de cades for delivering waste to a given site, so identifying responsible parties and allocating th eir culpability is a challenge and may be done somewhat arbitrarily through joint and several liab ility. Also, insurers suggested that “because of the near certainty that leakage will occur and the open-ended natu re 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, presiden t of Aetna Life & Casualty and the immediate past chairman of the American Insurance Associ ation). Further, insurance companies asserted that the provision for strict liab ility was a significant impediment to insurability given that even if a party acted with reasonable ca re 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 sh ift the burden for what they perceived as an uninsurable practice, due in large part to the certaint y 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: Befo re the S. Comm. On Environment and Public
Works 38 (April 3, 1985) (statement of Jones, T. Lawrence, President American Insurance Association). At that time, insu rers felt that responsible parties were attempting to unfairly transfer liability, beyond what th e 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 ow nership of sequestered CO2 to the public sector is proper, it is contemplated th at there should be some fund av ailable to cover the monitoring, measurement, verification (MMV) and mitigation costs associated with long-term management of sequestration projects following ope rational 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 gene rators sequestering in state? Will out-ofstate generators be assessed a fee at the state line? Or at the point of injection?

 EOR associated with sequest ration 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 incen tives 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, meas urement, verification and mitigation:

 Injection Fee

o Mandatory contributions by injection operato rs to a fund managed by the state, to be used exclusively for the long-term m onitoring, measurement, verification and mitigation of CO2 storage once liab ility transfers to the state.

Texas has proposed a tax-exemption provision fo r anthropogenic CO2 se questration (H.B. 3431). The major provisions of the exemption are as follows:

 Producer of oil or gas recovered through an e nhanced recovery proj ect is entitled to a
reduction in severance tax rate if recovery of oil uses car bon dioxide that is from an anthropogenic source, would otherwise be releas ed 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 demons tration based on substantial evidence that there is a reasonable expectation that sequestration wi ll 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 a nd verification determine a different amount is being stored

Authority to Bond Injection Projects & Facilities

Issue : Aside from the costs associated with post-clos ure 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, recl amation or mitigation required as a result of abandonment or insolvency.

Issues Raised During Workgroup Meetings :67  Should bonds be required for a project and surf ace facilities, as we ll as for individual
wells.

 Excessive bonding will discourage operators fr om 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 in spect 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 ownershi p/liability to the state, the Division will require authority to enter surf ace properties to plug ab andoned 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 th e sequestration of carbon dioxide to adequately protect th e interests of surface owners in the same way they are currently protected for oil and gas production.

CONCLUSION OF STATUTORY ISSUES68 IDENTIFIED REGULATORY ISSUES

The above issues will need to be considered or a ddressed in any statutory sc heme 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 i ssues 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 degradati on 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 leakag e rate ( 1% over 1000 years?).

 CO2 Registry

o Mesh CO2 sequestration accounting require ments 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 suffi cient/adequate property rights

 Pore space

• Agreement/rentals with surface owners

• Condemnation via eminent domain

• Threshold interest to es tablish 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 define d distance beyond (1 mile?)

 Opportunity to contest/pro test unitization through hearing process

o Provision to allocate costs wh en 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 suc cessfully demonstr ate 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 characteriza tion 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 demonstr ate otherwise through a formal hearing process

 Determine Reservoir size and areal extent (final storage volume)

 Depth (average depth) and volum e of proposed storage reservoir

 Groundwater/drinking water source s (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 thic kness of all confining strata

 Determination of confinement mech anism to prevent CO2 mobility

 Stratigraphic discontinuities/spill po ints and likely potential leakage points

 Injection

o Proposed Injection pressures belo w reservoir fracture pressure

o Proposed volumes and rates of injection

o Demonstrate Frac gradient (frac pressure limits)

o Proposed monitoring and modeling me thods 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 al l wells and surface facilities within the
areal extent of unit

 Siting

o OCD/Commission to approve propos ed injection well site and containment/reservoir modeling

 Bonding

o Establish independent bonding requirem ents (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 ou t if contractual injector fails to meet contractual agreement?

 Notice Requirements71 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 Tran sfer/Sale of Seque stration Project

o Require permit review at time of transf er if prior to post-closure period (?)

o Allow for modification of pe rmit 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 r ecommendation 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; av oid double sequestration credit)

 Operators right of surface entry

o Injection operator has ri ght to enter and properly plug abandoned or problem wells within project area to ensure integrity of se questration project

 Monitoring during injection

o Injection well integrity72  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 su rface 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 f acilities 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 in tegrity after cessati on of injection phase before evaluation for potential transfer of owne rship/liability? Or proper length of time to demonstrate integrity after injection pha se (when formation pressures stabilize)?

o Demonstrate site/formation stability (Gorgon/Australia)

o Alternative: set up a closur e/transfer window – transf er/closure shall occur no sooner than a given length of time after in jection ceases and no later than a certain time after injection ceases

o Demonstrate integrity of wells (both in jection and those perforating unit)

o Can petition Commission to s horten demonstration period

o Allowable leak rate/percentage?

o Disallow blowdown of formation in CO 2 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 (g radient may change over long time spans)? Adequate for areal extent?

o Status/behavior of CO2 plume over time?

 Proposed monitoring/modeli ng to be approved by OCD

 Plugging

o Within a certain time of termination of in jection phase, all inje ction 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

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### Evaluating the costs of desalination and water transport

Yuan Zhou a,b 

### , Richard S.J. Tol b,c,d

a International Max Planck Research School of Earth Systems Modeling, Hamburg, Germany

b Research unit Sustainability and Global Change, Hamburg University and C enter 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 wit hout 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 $/m 3 for seawater desalination and 0.6 $/m 3 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 t he 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$/m 3 ). Transport makes desalinat ed 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 feasi

ble 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 water2

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 a rid, 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 desa lination units, with a total capacity of 32.4 million m 3 /d, had been installed or contracted worldwide. Among them, non

- seawater desalination plants contributed with 13.3 million m 3 /d, whilst the capacity of the seawater desalination plants reached 19.1 mi llion m

3 /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 reductio ns 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 th at 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 pr oduct 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. T he 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 typica l 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 en ergy 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 m 3 /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 o n land

- based desalting plants rated
at more than 100 m 3 /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 espec ially 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 b e 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, aga in 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 obse rvations, 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 y ears 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.uni

hamburg.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 m 3 /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 de salinated 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(m 3 /d)Unit cost($/m3)

Fig. 3. Unit costs vs. total installed capacity by the MSF process.

Fig. 3 illustrates the unit costs of all t he 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 $/m 3 in 1960 to about 1.0 $/m 3 a t 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 UNIT C G TI C CA P YEA R M E N A 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 plan t. 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), excep t 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) (

- 2 0.21)

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 4

42 442 442 442 442 442 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 cos t 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 influence s 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 larg er capacity. However, the correlation is not obvious for plants with a capacity less than 50,000 m 3 /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 incr eased 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 desalinati on, 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

co sts 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 b ecause 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 we bsites 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 energ

y 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 oi l 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 mor e 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 wa s 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 co me 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 popul ar 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 salt

rejecting membranes that can efficiently operate at lower pressures and (2) the use of pressure recovery devices (Gleick, 2000). This study contains 2514 desalting plants u sing RO processes worldwide, with a total capacity of 12.7 million m 3 /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. Till7

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 imp ortant role in the costs of RO desalination. The average unit costs of RO processes have declined from 5.0 $/m 3 in 1970 to less than 1.0 $/m 3 today. Fig. 5 also shows that the unit costs for seawater desalination are still above 1.0 $/m 3

whilst the costs f

or desalting brackish

- , river

- and pure

- water has been reduced to less than 0.6 $/m 3 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/m 3 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/m 3 (Busch and Mickols, 2004).

Essentially we did similar regressions to estimate the unit cost as for the MSF pr ocess. 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 UNIT C G TI C CA P YEA R SE A BRAC K RIVERPURE = (2)

where SEA, BRACK, and RIVERPURE refer to seawater, brackish water and river plus pure
water dummies. Wastewater an d 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* 0.6 0* 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 a nd 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 th at 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 contra cted 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 l ess 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 m 3 /d and 289 desalting plants using the VC process with a total capacity of about 1.4 million m 3 /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 m 3 /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 ov er the total installed capacity. The cost of desalination by the ME process has fallen from 10.0 $/m 3 in the 1950’s to about 1.0 $/m 3 today. For the VC process, the cost has also decreased considerably over time, from 5.0 $/m 3 in 1970 to about 1.0 $/m

3 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 $/m 3 in the 1960’s to less than 1.0 $/m 3

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 ca pacity of

- 0.40 for the ME process,

- 0.26 for VC, and

- 0.38 for ED. ME and ED learn faster than MSF and RO10

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 seawate r desalination, followed by VC and ME processes. The unit cost of desalting seawater has been reduced to about 1.0 $/m 3 or less. RO and ED processes are most often used to treat brackish

- , waste

- and river water. The unit cost of desalting brackish water h as fallen to about 0.6 $/m 3 . 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 o f 200 km would cost 21.4 ¢/m

3 . Of this, 4.0 ¢/m 3 are for the purchase of Egyptian water, and 5.2 ¢/m 3 for lifting the water some 100 m. Consequently, it costs 6.1 ¢/m 3 per 100 km to transport water. If the transfer scheme would be extended to 500 MCM, tota l costs would fall to 19.8 ¢/m 3 and transport11

costs to 5.3 ¢/m

3 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 o

f 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 poi nt 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 wou ld 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 Turke y to Turkish Cyprus. A 78 km pipeline with a capacity of 75 mln m 3 a year would deliver water at 25

- 34 ¢/m 3 . According to Kally’s data, the horizontal transport alone would cost 16 ¢/m 3 , 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 ¢/m

3 . 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 ¢/m 3 . 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
S pain. This would involve canals of 900 km long, transporting 1000 mln m 3 of water from the Ebro to Barcelona and Southern Spain. Uche et al. (2003) estimate that this can be done at some 36 ¢/m 3 if a 4% discount rate is taken. Based on Kally’s data, the ho rizontal transport alone would cost at least 52 ¢/m 3 . Kally’s estimates seem to be on the high side.

Hahnemann (2002) discusses the Central Arizona Project, which brings some 1800 mln m 3 /yr from the Colorado river to amongst others Phoenix and Tucson, a h orizontal distance of some 550 km, and a vertical distance of some 750 m. Kally’s data suggest that this would cost some 74 ¢/m 3 , but Hahnemann (2002) reports an otherwise unspecified marginal cost of only 5 ¢/m 3

.

Liu and Zheng (2002) estimate the costs o f 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 m 3 /yr, although only l

ess 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 ¢/m

3 ; using Kally’s estimates, we find this to be 38 ¢/m 3 . Ho wever, 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 alr eady 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 esti mates to those of other studies suggests that Kally may have been overly pessimistic. However, most of these studies are ex ante engineering studies of government12

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 desalinati on 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 incr

eased as much as $0.1/m 3 (the cost of additional treatment).

Table 4 contains some sample calculations for the costs of desalinated water in selected water

stressed cities. We assume a transport of 100 MCM/yr. Transport costs are assumed to be 6 ¢ per
10 0 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 ¢/m 3 , 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/m 3 ) (c/m 3 ) (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, a rid 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 it13

costed about 9.0 $/m 3 to desalinate seawater around 1960, the costs are now arou nd 1.0 $/m 3 for the MSF process. For RO, the most popular method, the costs have fallen to 0.6 $/m 3 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 f or 1.1 $/m 3 , to Phoenix for 1.3 $/m 3 and to Zaragoza for 1.4 $/m 2 . 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 $/m 3 , to Harare 2.0 $/m

3 , and to Mexico City 2. 4 $/m 3 . 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 disp osal, 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 an d 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 con vert 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

ma rginal 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
ba sed 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 f or 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 geogr aphically 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 err ors and opinions are ours.14

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- 449).Letter ID: 0183 Commenter: Wendy Jacobs Organization: Harvard Law School Envi ronmental 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 dome stic [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 acknow ledges, 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 mech anisms for protecti ng private drinking water supplies, funding costs and damages associated with injury to persons and/or water supplies despite complian ce with the UIC regulations, accidental releases of CO2 to the atmosphere, and compensation for and remediation of harm to public health or the environment ot her than the endangerment of underground sources of drinking water ("USDWs")). S ee 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 th e 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 i nvestment in CCS will take place. See, e.g., infra Part III(C)(1)(b)(ii) (discu ssing 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 recogni ze 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 broade r context of CCS and the need for regulatory

1clarity to ensure that USDWs are protected from endangerment. In develo ping 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 Stat es Geological Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau of Land Management). The Agency continues to eval uate 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 Comprehe nsive Environmental Response, Compensation, and Liability Act; and the Marine Protection, Resear ch 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 entitle d "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 pr ecautionary measures for Class VI wells above and beyond what is requir ed for other classes of wells. The proposed regulation allows the owner or operator the flexibility to choose particular cements or metal well com ponents 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 addresse s the potential corrosion of cement and metal well components by the CO2 stream (plus water impurities) that can compromise the struct ure of the well and result in leaks of stored CO2. ELPC and ETIP laud other pr ecautionary measures required in the proposed regulation, including down-hole shut off valves, continuous and frequent monitoring of the integrity of the internal and ex ternal portions of the well, tracking the plume and pressure front, and detailed electronic record keeping. Id. at 43,511, 43,538-40 (propos ed 40 C.F.R. §§ 146.88-.91). The requirements in the proposed regulat ion 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 ag rees that protection of USDWs from endangerment and prevention of fluid m ovement between formations is paramount. Appropriately designed and constructed wells ar e 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-op erational testing of Class VI wells at §§146.86
and 146.87.

2Please 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 pr ecautionary measures required in the proposed regulation, including down-hole shut off valves, continuous and frequent monitoring of the integrity of the internal and ex ternal portions of the well, tracking the plume and pressure front, and detailed electronic record keeping. Id. at 43,511, 43,538-40 (propos ed 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 ever y 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 confin ed in the target formations and does not endanger
USDWs.

After evaluating the risk s and benefits of down-hole shut-off systems and considering additional research, EPA will not require automatic down-ho le 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 s ituations that may warrant their use. EPA believes that requiring the installation of auto matic 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 inst allation of down-hole shut-off
devices for Class VI wells located in the offshor e submerged lands within the jurisdiction of a State UIC program. The Agency believes that the unique construction a nd operational conditions for offshore Class VI wells, includ ing isolation from shorelines a nd 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 au tomatic down-hole shut-off devices for offshore wells in the submerged lands of a State.

EPA believes that requiring the in stallation of automatic surfac e shut-off devices for onshore wells (and affording Director's discretion to require down-hole devices wher e necessary) ensures that proper precautions are taken to prevent subs urface fluid movement a nd ensure protection of USDWs, human health, and the environment.

3Letter 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 Operat ors to Demonstrate that CO2 Will Be Contained for the Long-Term

The purpose of GS is to store anthro pogenic 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 c ontainment of a gaseous, liquid or supercritical carbon dioxide stream in s ubsurface 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 t echnology for achieving domestic emissions reductions" and "help to mitigate c limate 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 de monstration that the injected CO2 will not migrate in such a way that will frust rate the broader climate change related goals of GS, lead to human endangerment, or threaten USDWs.

Despite the fact that long-term contai nment 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 c ontainment will be achieved and maintained. In this respect, the proposed rule is less stri ngent 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 th at a 10,000 year demonstration may be too stringent for GS within Class VI we lls, but the existence of a 10,000 year
demonstration standard for Class I wells confirms that EPA can reasonably impose
and administer a reasonable demonstr ation standard for Class VI wells.

[FN3] In the alternative, the owner or ope rator may demonstrate that, "[b]efore the injected fluids migrate out of the injec tion zone or to a point of discharge or interface with USDW, the fluid will no longer be hazardous because of attenuation, transformation, or immobili zation of hazardous c onstituents within the injection zone by hydrolysis, chemical interactions or other means . . . ." 40 C.F.R. §148.20(a)(1)(ii).

4In its regulations for GS of CO2, Washi ngton State requires GS permit applicants to demonstrate to a high degree of c onfidence that "substantially ninety-nine percent of the greenhouse gases will rema in 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 requi rement 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 comparab le 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, injec tion, post-site inje ction care, site closure, and post-closur e 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-te rm" containment to any GS project, EPA should add a long-term containment dem onstration requirement to the proposed regulation. At a minimum, a permit applic ant 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 recomme nd adopting a 1,000 year containment
standard.

[FN4] Texas imposes a demonstration require ment similar to Wa shington State as a condition for tax exemptions to enco urage GS. Tex. Tax Code Ann. § 202.0545(d) (1)(2007) ("The operator’s planned sequest ration 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 consid er requiring the owner or operator to demonstrate long-term containment again as a precondi tion 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 activ ities (seeking comment) (40 CFR 146.92)

Comment: B. EPA Should Impose More Specific Well Plugging Standards

5In the preamble, EPA states that th e 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 pe r year of CO2 into the atmosphere). The proposed regulatio n, 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 ty pes of materials or tests that must be used during well plugging because ther e are a variety of methods that are appropriate and new material s and tests may become av ailable in the future." Id. at 43,518. Its general outline for th e 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 requireme nts, 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 Conservati on 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 fl uids" 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. § 14 6.10(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 landfill s, 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 tec hniques that EPA already knows will work for GS, EPA would provide valuable GS-sp ecific guidance to owners/operators (and Directors). This may be especially valuab le in this early stage of development for GS technology as it will give all i nvolved parties a brighter line by which to measure compliance. Additionally, exis ting regulations dem onstrate 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 flexib ility by vesting the Director with the authority to consider and approve ne w plugging techniques. Accordingly, EPA should revise the proposed Cl ass VI UIC program regulat ion to include a list of specific materials and tests that it de ems suitable for plugging GS wells, in addition to providing the Dir ector 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 informa tion 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 clar ifies 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 ensu re 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 grad e and quantity of material to be used in plugging (the material must be comp atible with the CO2 stream); and (6) the method of placement of the plugs. EPA believes that th ese 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 propo sed well plugging plans a nd post-injection site care and site closure plans required u nder §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; de monstrate non-endangerment; and perform site closure activities. The guid ance 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-injecti on timeframe (seeking comment)

Comment: C. EPA Should Clarify the Site Closure Standard

EPA is proposing a "combination of fixe d timeframe and performance standard" approach to site closur e. 73 Fed. Reg. at 43,519. Unde r the proposal, the owner or operator would be require d to undertake " post-injection site care" following the permanent cessation of in jection activities at the site, which would include "submit[ting] periodic reports providing monitoring re sults and updated modeling results as appropriate until a demonstra tion of nonendangerment to USDWs can be made." Id. at 43,520. Specifically, the ow ner or operator would need to demonstrate "that the carbon dioxide plume and pressure front have stabilized

7and that no additional monitoring is n eeded 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)). On ce 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 ye ars 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 th at 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 advant age of best practices as they are developed. Adherence to a single fixed tim eframe 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 m eet a flexible performance standard throughout a baseline period of 50 years w ould ensure that pos t-injection site care, including monitoring and verificati on, 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 prude nt 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-injectio n site care monitoring for Class VI wells. EPA believes that a default PISC timeframe of 50 year s, with Director's di scretion to shorten or lengthen this timeframe, combined with a site-s pecific Director’s disc retion to create an alternative PISC time frame, ensu res that USDWs are protected. The GS rule offers owners or operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengt hen the PISC timeframe during the PISC period based on sitespecific data, pursuant to require ments at §146.93(b); or (2) afford ing the Director discretion to allow a Class VI well owner or operator to demo nstrate, based on substa ntial 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 car e 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts.

8Letter 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 perform ance 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 prope rties 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 so mething else. EPA has promulgated more specific closure and post-closure standards for Class I wells and should follow suit here to avoid confusion, uncertaint y, and potential thre ats 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 . . . stab ilize remaining wastes to a bearing capacity sufficient to suppor t final cover . . . ."). Although the term is not defined in those regulations either, t hose 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 te rms of specific factors like migration, erosion, maintenance, and permeabilit y. See 40 C.F.R. § 264.228(a)(2)(iii) (A)-(E).

The owner or operator of a Class I hazar dous 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 operato r of a Class I well is required to continue monitoring "until pressure in th e injection zone decays to the point
that the well’s cone of influence no l onger 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 nu merous outstanding technical issues surrounding wide-scale use of CCS te chnologies 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. Ev en so, there is ample room for the EPA to adopt a st ronger and better-defin ed post-injection site care standard that gives greate r assurances that USDWs will not be
threatened while still allowi ng flexibility for innovation.

9The 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 monito ring requirements occurs wh en the owner or operator demonstrates "with a high degree of conf idence that the storage project does not endanger human health or the environm ent." SARAH M. FORBES ET AL., WORLD RESOURCES INSTITUTE, CCS GUIDELINE S: GUIDELINES FO R CARBON DIOXIDE CAPTURE, TRANSPORT, AND STORAGE 103 (2008) [hereinafter WRI GUIDELI NES]. 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), base d 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 si gnificant leakage of inject ed or displaced fluids
into formations outside the confinin g 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 leak ing and have maintained integrity.

Id. Requirements four, five, and six all ad dress stabilization, but in language more precise than the approach offere d by EPA. Where EPA leaves open the definition of "stabilize," WRI offers a more exacting standard built from terms like "leakage," "integrity," and "mig rate." The WRI approach provides a
standard more certain to ensure th at non-endangerment is achieved while preserving flexibility for owner or operat ors to develop best practices as CCS continues to develop. In addition, WRI’s mo re 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-sp ecific factors will influence the determination of when the CO2 plume and pressu re front no longer pose a risk of endangerment
to USDWs. It is for this reason that EPA believe s that individual UIC Dir ectors, 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 potentia lly impacted parties.

10EPA disagrees that the rule should specify th e criteria for setting th e monitoring timeframe. Instead, EPA believes that such determinations ar e 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 pl an 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 cessa tion of plume movement may not occur at some sites for long time periods due to density differences, natura l formation flow grad ients and diffusion. EPA clarifies that a complete cessati on of plume movement is not requi red, only a demonstration that the plume and pressure front no longer pos e 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 propo sed well plugging plans a nd post-injection site care and site closure plans under §146.92 a nd §146.93. The guidance describes recommended approaches for how an owner or operator coul d plug injection and m onitoring wells; perform post-injection monitoring; dem onstrate non endangerment; and perf orm 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 re medial response (40 CFR 146.94)

Comment: D. EPA Should Expand the Emergency a nd Remedial Response Requirements

The proposed emergency and remedial re sponse 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 operat or 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, clos ure 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 intende d 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 remedi al response plan specifically cover the post-injection site care period.

The emergency and remedial response provisi ons are too narrow in that they fail

11to address ways in which GS may enda nger USDWs other than "movement of the injection or formation fluids." For exampl e, as a result of the CO2 mixing with fluid during or after injec tion, two problems may occur. First, the mixture can be highly corrosive, thereby potentia lly weakening the well and/or the containment boundaries and increasing the ri sk inherent to all Class VI wells that injected fluids will migrate out side 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 emerge ncy and remedial response provisions should be expanded to address these concerns.

Further, the draft regula tions require the owner or operator to report and implement its emergency and remedial re sponse 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 with in the regulation. ELPC and ETIP recommend that EPA clarify the term. Fu rther, like proposed 40 C.F.R. section 146.94(a), proposed section 146.94(b) is too narrow, for two r easons. First, it is unclear why EPA should rely solely on evidence obtained from owners or operators. ELPC and ETIP recommend that EPA require that reme dial (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 a nd implement the remedial response plan would not be triggered in every instan ce in which a USDW may be endangered. ELPC and ETIP recommend expanding the trigge r 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 durati on of the emergency and remedial response plan, EPA clarifies that the plan will apply over the lif e 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 follo wing significant changes to the facility. Subsequently, the owners or operators must su bmit 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 langu age 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 emer gency 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.

12EPA notes that in developing Class VI requi rements, 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 pr oblem with a GS project that could endanger USDWs. While the multiple barriers of protection afforded by ot her aspects of the regulation should make such adverse events unlikely, the purpose of the emerge ncy 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 requ ires that if the owner or operator obtains any evidence (regardless of the source of that evid ence) that USDWs may be endangered, he or she must cease injection, take all step s reasonably necessary to identif y and characterize any release, notify the Director, and implement the appr oved emergency and remedial response plan (§146.94(b)). EPA clarifies that §1421 of SD WA mandates protecti on of USDWs from endangerment due to injection activities; the pu rpose of the emergency and remedial response requirements is to ensure that if other protective measures afford ed 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 viola tion 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 financia l 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 require ments, generally, is "to ensure that owners and operators maintain adequate financial resources to fulfill their current and future environmental obliga tions [and] to minimize the number of facilities that are orphaned and abandone d; 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-c losure stewardship) and must include adequate

13assurance that there is sufficient fundi ng to cover the net present value of estimated closure . . . and post-closure[ .]" WRI GUIDELINES at 58. The adequacy
of financial assurances is not teste d, however, until the owner or operator is unable or unwilling to fulfill its obliga tions at a facility. "The ultimate
test of whether financial assurances ar e 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 INJECTI ON 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 ow ners 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 marg in of error or f und 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 f acility 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 Speci fic Financial Assura nce 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 (tha t meets the requirements of § 146.84), injection well plugging (that meet s the requirements of § 146.92), post injection site care and site closure (that meets the requirements of § 146.93), and emergency and remedial response (tha t 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 Di rectors) how to satisfy that duty. EPA admits as much, stating in the preambl e 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 pub lish guidance "that describes recommended

14types of financial mechanisms that owne rs or operators can use to meet this requirement" at some unspecifi ed future date. Id. at 43,520.

As discussed below, EPA’s long experi ence with Class I wells, RCRA, and other regulatory frameworks demonstrates that vague financial assu rance standards do not work. EPA should specify" now, not late r, and in the regulation itself"the mechanisms by which a well owner or operator may demonstrate financial assurance.[FN8] In developing its li st of acceptable financial assurance mechanisms for GS, EPA should incorporate the recommendations made by the General Accounting Office ("GAO") and EPA Of fice 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 gui dance, especially regarding the problem areas highlighted by GAO and OIG in their reports (for example, regarding cost estimation methodology or pay-in peri od for trust funds). Id. at 43,521.

[FN8] Merely providing EPA guidance on th e subject, as EPA is proposing to do, is insufficient given the fact that guid ance is not legally binding on EPA. EPA is free to follow the guidance or to ac t at variance with it, depending onthe facts of a particular case. See e.g., Memo randum from Victor J. Kimm, Office of Drinking Water, U.S. EPA, to Water Di vision Directors and Water Supply Branch Chiefs, Regions I-X, U.S. EPA, 1-2 (M ay 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) (hol ding that a different EPA guidance was designed to "have the flexibility to make adjustments for the specific
conditions" and was non-bi nding 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 financia l assurance on a national level, by including detailed guidance in th e regulations themselves. See OFFICE OF INSPECTOR GENERAL, U.S. ENVTL. PROT. AGENCY, REPO RT NO. 2005-P-00026,
CONTINUED EPA LEADERSHIP WILL SUPP ORT STATE NEEDS FOR INFORMATION
AND GUIDANCE
ON RCRA FINANCIAL ASSISTANCE 2 (2005) [hereinafter OI G 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 attenda nt risk to drinki ng water supplies and the public), EPA must provide as much detailed guidance as possible. It should look to existing lists of acceptable fina ncial mechanisms in other EPA programs as just a starting point. EPA’s RCRA re gulations (40 C.F.R. § 264.143) include a list of acceptable financial mechanisms, yet OIG reports that states implementing the RCRA regulations have "e xpressed consistent concerns" regarding "insufficient guidance' in a number of important areas, prompting OIG to

15recommend that EPA issue additional gui dance for its RCRA financial assurance mechanisms. OIG REPORT at 3, 9-12. OIG f ound that a lack of clear guidance led states to accept a broad range of financ ial 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 assuran ce provisions. Such guidance should be based on "best practices" for each of th e acceptable financial mechanisms. OIG
REPORT at 12.

Further, time is of the essence. For ma ximum 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). "Experien ce 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 CAPTUR E AND GEOLOGICAL SEQUESTRATION 5 (2007) [hereinafter WRI WORKSHOP SUMMARY]. A clear descript ion of required financial mechanisms allows "[p]roject developers, financiers, and insure rs . . . 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 possibl e so that states do not create conflicting financia l 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 LIABILIT Y REGIME FOR LONG-TERM STORAGE
OF CARBON DIOXIDE 30 (2008), available at http://works.bepress/com/alexandra_kla ss/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 woul d 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 fi nancing 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.

16EPA’s implementing regulations under the Class I deep injec tion 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 facili ty must establish financial assurance for the plugging and abandonment of each existing and new Class I hazardous waste injection well" in one of th e 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 abandonmen t"; (d) "plugging and abandonment letter of credit"; (5) "plugging and abandonmen t insurance"; (6) corporate guarantee of plugging and abandonment (after passing a fi nancial test); or (7) a combination of "trust funds, surety bonds guarantee ing payment into a tr ust fund, letters of credit, and insurance." These mechanisms are similar to, but more detailed,
than the Class II mechanisms which EPA s uggests 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 assu rance options available under the RCRA program. See 40 C.F.R. § 264.143. EPA shoul d 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 containm ent, and include a list of acceptable financial assurance mechanisms in the proposed regulation for GS.

[FN9] We recommend, however, that EPA onl y 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 Cl ass 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 recommenda tions are well de scribed in the preamble, but then are entirely ignore d in the actual regu lation. See 73 Fed. Reg. at 43,521. Those offices "have raised issues regarding the use of financial responsibility instruments a pplicable 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 adequa te resources are available to close a commercial deep injection well in the ev ent 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 pr ogram began in 1980; two did not have

17adequate 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 "fa ilure to do so risks contaminating underground drinking water sources." Id. at 21.

Individual Response: EPA clarifies that the GAO Report a nd OIG Report have been reviewed for purposes of fina lizing this rule.

EPA has also clarified and specified acceptable fi nancial 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 instru ments to meet their fi nancial responsibility obligations under the rule, provided the Director determines that the operator's proposed financial responsibility demonstration is adequa te 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 clos ure, 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 th e final rule and preamble for fu rther discussion of EPA's final approach to financial responsibility.

These financial responsibility requ irements are tailored to the unique nature of the long term GS
of CO2.

EPA adds that the financial res ponsibility 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 civi l, criminal, or administra tive penalties under SDWA §1423.

In addition, the final rule incl udes 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 Direct or to evaluate the financial responsibility demonstration annuall y to confirm that the instrument(s) used remain adequate. At §146.85(e), the rule states that if the Director determines duri ng the annual evaluation that the original demonstration is no longe r adequate to cover the cost of activities for which it is required, the owner or operator mu st provide an adjustment to th e cost estimate within 60 days. In addition, at §146.85(c)(2), the ru le requires updating of cost estimates following amendments to the AoR and corrective action plan, the inject ion well plugging plan, th e 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 (a vailable on EPA's website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm) on financial responsibility for GS wells that will provide information a bout the appropriateness of various financial instruments. This guidance will include reco mmendations to help permitting authorities determine whether an owner or operator's plan for financial responsib ility is adequate.

18EPA clarifies that the goal of financial responsibi lity is to ensure that resources are available to prevent endangerment of USDWs from imprope r plugging, remediation, and management of wells in the event that the owner or oper ator experiences fina ncial 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 meeti ng the financial test and corporate guarantee in accordance with the recomme ndations 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, E nvironmental Finance Adviso ry Board to Stephen L. Johnson, Administrator, U.S. EPA 6 (Ja n. 11, 2006). "Using an independent third party will relieve [the Director] of th e administrative burden of reviewing
financial statements" as well as alle viate concerns about the Director’s "capacity to adequately undertake such re view." Id. EPA should also follow OIG’s recommendations by making sure that any fi nancial 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 th ose that certify conformance with generally accepted accounti ng principles." Id. at 15.

EPA states that it is also "considerin g 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 requi re a showing of "at leas t six times the sum" of
covered costs as measured in the curr ent 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 ne t worth threshold at least 10 times the amount of the obligations being assu red." 73 Fed. Reg. at 43,522. A study of cost estimates for GS suggests that estim ates "can be made with confidence" given that storage "technol ogies and equipment" are al ready being used in the oil and gas industries. INTERGOVERNM ENTAL PANEL ON CLIM ATE 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

19the 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 eith er threshold-or another al ternative-is appropriate,
the EPA should consider other factor s 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 te st can be an appropriate option for some owners or operators. EPA recognizes that it is important for sel f-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 ab le to demonstrate profit ability, with a margin sufficient to cover contingencie s and unknown obligations, and stab ility. 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 fi nancial 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 dem onstrating that its corporate parent meets the financial requirements on its behalf.

EPA is developing guidance to assi st Directors in evaluating the appropriateness of the financial test in specific circumstances. EPA's financial responsibility guid ance will describe the types of financial instruments, including fina ncial tests, that owners or opera tors can use to meet financial responsibility requirements for GS wells. The fina ncial responsibility guidance will include considerations for Directors, such as cred itworthiness, regarding how to evaluate the appropriateness of a specific financial responsib ility 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://wat er.epa.gov/type/groundwater/ui c/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 Recommenda tions Made by OIG and GAO Regarding Insurance Mechanisms Before Allowing Their Use by Owners or Operators

EPA also notes that it "is assessing wh ether to provide guidance on the use of insurance providers" and whether to allo w 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 insu rance 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 provi ded by the policy." OIG REPORT at 3.

20Furthermore, "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 se questration and oil and gas injection projects in the United States and abroad. This will allow EPA to better understand the role of insurance in provi ding financial assurances and how to best manage the use of insurance for this purpose. EPA should include representatives from OIG, GAO a nd EFAB in those consultations.

If insurance is allowed, EPA should make sure to exclude "captive insurance" from the definition of acceptable insu rance. GAO defines captive insurance companies as "wholly owned subsidiaries of the corporation they are insuring."
GAO REPORT at 20. This kind of insuran ce provides the pub lic with "little confidence that the captive insurance comp any will provide the funds to pay for closure" if "the parent company experi ences financial diffi culty." Id. Captive insurance leaves "no independence of risk between the corporate parent and the company insured." OIG REPORT at 15-16. Th ese policies "are al so 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 pr oposed financial responsib ility demonstration is adequate to protect USDWs from endangerment, which means the abili ty of the owner or operator to pay for each activity for which fina ncial responsibility must be demonstrated, including corrective acti on on wells in the AoR, injection we ll 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 fi nancial 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 cap tive insurance, including those mentioned by the commenter. Note that under th e GS regulation, Directors can choose not to allow certain financial instruments if they f eel the instruments are too risky or otherwise inappropriate to protect US DWs from endangerment.

The financial responsibility guidance will include considerations for Dire ctors regarding how to evaluate the appropriateness of a specific fina ncial responsibility inst rument, including captive insurance, for a specific project. The guida nce will include model forms and templates for financial responsibility instruments but will not in clude 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 in surance as an option for financial responsibility

21for 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 demonstr ate profitability, with a margin sufficient to cover contingencies and unkn own 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 fi nancial 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 dem onstrating 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 financia l 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 devel op further guidance at some unspecified
later date runs afoul of the recommenda tions 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 necessa ry, 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 fina ncial responsibility is adequate. The guidance, to be issued at th e time the final rule is published, is available on EPA's website at http://water.epa.gov/type/groundwat er/uic/wells_se questration.cfm.

In addition, under the final rule owners or operators may choose from a variety of financial instruments to meet their financial responsib ility obligations under the rule, provided the Director determines that the operator's propos ed financial responsibil ity demonstration is adequate to protect USDWs from endangerment, which means the abili ty of the owner or operator to pay for each activity for which fina ncial responsibility must be demonstrated, including corrective acti on on wells in the AoR, injection we ll 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 fi nancial responsibility instruments. See the

22final 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 a nd appropriate documentation are being collected,
and to determine if modifications to the re quirements are appropr iate or necessary.

Letter ID: 0183 Comment ID: 25151 Letter Lines: 762 to 792

Comment Code: 5430 2.9.1 Comments on proposed financia l responsibility requirements (40 CFR 146.85)

Comment: 3. EPA Should Require Owners or Oper ators to Re-Demonstrate Financial
Assurance Throughout the Life of the Project.

The proposed regulation states that the "o wner 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 th e 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 acti on plan, injection well plugging plan, etc.). Meanwhile, pr oposed 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 pluggi ng . . . and post-injection site care and site closure[.]" The re gulation, however, does not automatically require an owner or operator to re-demons trate 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 "m aintained" by the owner or operator may become outdated over time. Instead, EPA should require that the owner or operator re-demonstrate financial assuran ces on a regular basis (perhaps with each adjustment of cost estimates) so that an owner or operator "maintains"
financial assurance that reflects the mo st upto-date cost estimate information.

In the same vein, EPA should require pe riodic re-demonstration of financial
assurance to account for inflation. See i d. at 43,522 (stating that EPA is still "considering" whether to include pr ovisions for annual inflationary adjustments)..

Individual Response: EPA agrees that it is important to periodically update cost estimates that support financial responsibility determinations. EPA clarifies th at the GS rule, at §146.85(c)

23requires 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 ow ner or operator to provide an adjustment of the
cost estimate if the Director dete rmines that the original demons tration 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 financia l responsibility requirements (40 CFR 146.85)

Comment: 4. The Regulation Fails to Require Financ ial Assurance for All Contingencies and Costs of Protecting Drinking Water Supplies.

The amount of financial assurance requi red by the proposed regulation is based entirely on the costs estimated by the owner or operator (and accepted by the Director) in its plans fo r corrective action, well pl ugging, post-injection site care, site closure, and emergency a nd 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 cove red 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 estima tes or was not adjusted for inflation. Then there is the problem of occurren ces or accidents that are completely unanticipated and unplanned. In light of the many unknowns associated with large-scale GS at this time, it seems prude nt 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 assura nces. To address catastrophic, "breakthe-bank" accidents, however, EPA shoul d 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 pl an that describes ac tions 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)).

24Proposed 40 C.F.R. § 146.85 requires the ow ner or operator to maintain financial assurance to cover the emergency pla n. However, neither that provision nor proposed section 146.94 indicates how th e 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 wi ll cover the costs of emergencies not anticipated by the plan. In fact, since the only emer gencies covered are those already anticipated by the emergency pl anning 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 beha ve, 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 appr opriate 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, ty ing the financial assurance requirement to the owner or operator’s plans, without providing any margin of error or guidance for acceptable models to m easure 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 co st 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 requiremen ts ensure that sufficient funds are
set aside in the financia l 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 shou ld "be updated annually" and account for
"inflation." OIG REPORT at 2. EPA shoul d require independent verification of
all cost estimates as we ll. See 73 Fed. Reg. at 43,521.

EPA should also proceed with "allowing se parate financial demonstrations to be submitted for the plugging of the injecti on well and for the post-injection site care requirements" in order to tie th e 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 "m ay 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 a ddressed this sentiment in the proposed regulations. Id. at 43,520. EPA should make it explicit that a re-demonstration

25of financial responsibility is necessary any time there is a change in cost estimates, amendment to the area of revi ew, 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 experi ence with cost estimation in the RCRA program. Under RCRA regulations, the "clo sure 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). Th is 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 al so adopt the RCRA re quirement that the estimate equal costs "at the point in the facility’s active life when the extent and manner of its operation would make clos ure the most expensive, as indicated by its closure plan," ther eby providing a margin of error in financial assurances for cost estimates. 40 C.F.R. § 265.142(a)(1).

Perhaps more importantly, however, unplanne d costs that could "break the bank" of the owner or operator must be ad dressed (such as, for example, costs associated with a catastrophic acciden t). 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 ri sks through the use of a fundi ng scheme for GS that resembles that developed under the Pric e-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 RESOURCE S INSTITUTE, WO RKSHOP 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 othe rs); ALEXANDRA B. KLASS & ELIZABETH J. WILSON, CLIMATE CHANGE AND CA RBON SEQUESTRATION: ASSESSING A
LIABILITY REGIME
FOR LONG-TERM STORAGE OF CARBON DIOXIDE 30 (2008) , at 38-39, available at http://works.bepress/com/alexandra_kl ass/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, ma kes 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 sim ilar to those acceptable under the UIC and RCRA programs, each company also cont ributes to a collec tive 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 coul d be useful in the GS context to

26provide 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 requireme nts for financial responsibility are inadequate. Under the final rule ow ners or operators must develop cost estimates that accurately address the potential costs of adverse impacts as sociated with the GS project, and demonstrate and maintain financial responsibility to address th e 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 upd ating 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 year s. The same provision requ ires annual updates of
the cost estimates for inflation.

EPA further clarifies that the final rule re quires adjustments to the financial assurance demonstration following an adjustment to the co st estimate. The final rule, at §146.85(c)(4), requires the owner or operator to increase the face value of the fi nancial instrument or to obtain an additional financial responsibility instrument if the most recent cost estimate is above the value of the existing fi nancial 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 provider s of financial instruments, and permitting authorities in developing estimates of th e 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 fo r regulatory noncompliance and their financial
instrument will be released if it was not used. Ho wever, even if a site closure is approved under §146.93, the owner or operator may still be held liable for regulatory noncom pliance 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 i ssue of long-term liabili ty in the preamble of the final GS rule.

Regarding the suggestion to create a trust f und, EPA clarifies that under SDWA, EPA has the general authority to set financial responsibil ity requirements for inj ection well owners or operators to ensure that adequa te resources are available to pr otect 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

27Act (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 re medial response (40 CFR 146.94)

Comment: The proposed regulation requires the owner or operator to "provide the Director with an emergency and remedial response pl an that describes ac tions 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 ow ner or operator to maintain financial assurance to cover the emergency pla n. However, neither that provision nor proposed section 146.94 indicates how th e 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 wi ll cover the costs of emergencies not anticipated by the plan. In fact, since the only emer gencies covered are those already anticipated by the emergency pl anning 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 ow ners or operators to demons trate 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 si te care (seeking comment)

Comment: EPA should also proceed with "allowing se parate financial demonstrations to be submitted for the plugging of the injecti on well and for the post-injection site care requirements" in order to tie th e 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 "m ay 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 a ddressed 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 revi ew, or change in the corrective action

28plan. 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 co st estimate to account for any amendments to the AoR and corrective action plan, the injection well pl ugging plan, the PISC and site closure plan, and the emergency and reme dial response plan. Owners or operators must also adjust the estimates for inflation annually under §146.85(c)(2). EPA a dds that the Director can also require the owner or ope rator to provide an adjustment of the cost estimate if the Director determines that the original demonstr ation is no longer adequate, as specified at §146.85(e).

In order to assist owners or operators and financial instituti ons in achieving accurate cost estimates for all GS activities, EPA plans to i ssue financial responsibil ity guidance that will
include a discussion of how best to estimate cost s, 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. Th is 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 "o wners or operators of injection wells that will be used to inject CO2 into th e subsurface for the purposes of GS." 73 Fed. Reg. at 43,492; see id. at 43,534 (p roposed 40 C.F.R. §144.18). Other parties involved in a CCS project, incl uding 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 devel op regulations to protect USDWs." Id. at 43,495; see al so 42 U.S.C. §300h(a)-(b), (d). That authority extends over all actors involve d in the CCS process (not just the injection well owner or ope rator), 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 migrat es 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. Ye t the proposed re gulation’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 a dded to the stream to enable or improve the injection process." Id. at 43,535 (proposed 40 CFR §

29146.81(d) (definition of "carbon dioxid e stream")). By regulating CO2 generators and CO2 stream treatment ( purification) facil ities directly, EPA
could reduce the likelihood that a contam inated CO2 stream would be injected
into a GS well and there by reduce the likelihood that such contaminants would endanger a USDW.[FN12] EPA shou ld therefore consider setting specific requirements
for the maximum concentrations of "inc idental substances" in injected CO2 streams to reduce the uncertainty about the proper level of treatment required. By imposing financial assurance requirem ents on those parties, EPA could also
reduce the likelihood that costs and dama ges arising from such contamination would go unpaid, for example, if such co sts exceeded the security posted by the owner or operator. Regulatory oversight would make th ese firms "more likely to undertake operating decisions that consider environm ental (and remediation)
costs." WRI ISSUE BRIEF at 6.

[FN11] ELPC agrees, however, that EPA doe s not have authority under the SDWA to
address all of the conduct of all of the parties involv ed 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 discussi on at Part III(C)(1)(b). supra.

[FN12] Note that even such a consider ation 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, part ies 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 exampl e, geological sequestration may "allow some [generators of CO2] to extend the li fe of their existing capital investment in plant machinery or plant processe s." 73 Fed. Reg. at 43,531. Moreover, since "it is caps on greenhouse gas emissions th at will explicitly establish a price for CO2 and will encourage utilities and ot hers to invest in CCS in order to meet those caps," it is the genera tors of the CO2 -along with their customers-who may receive credits fo r sequestration. KLAS S AND WILSON at 13. All parties who benefit from GS of CO2 should help be ar 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 th e subsurface for the purpose of long-term storage. EPA clarifies that regula ting CO2 generators and transporters is outside the scope of the Class VI GS rulemaking. The Class VI GS rule is de signed 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 standa rds for CO2 injectate streams (e.g., a percent CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners

30or operators to submit information on the sour ce of the CO2 and its physical and chemical properties. Specifically, the GS rule requires the owner or operator to subm it 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 compatib ility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confini ng zones and the materials used to construct the well, per §146.82(c)(3). This info rmation 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 CO 2; purity standards for CO2
Comment Code: 5400 2.9 Proposed Financial Respons ibility 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 migrat es 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. Ye t the proposed re gulation’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 a dded to the stream to enable or improve the injection process." Id. at 43,535 (proposed 40 CFR § 146.81(d) (definition of "carbon dioxid e stream")). By regulating CO2 generators and CO2 stream treatment ( purification) facil ities directly, EPA
could reduce the likelihood that a contam inated CO2 stream would be injected
into a GS well and there by reduce the likelihood that such contaminants would endanger a USDW.[FN12] EPA shou ld therefore consider setting specific requirements
for the maximum concentrations of "inc idental substances" in injected CO2 streams to reduce the uncertainty about the proper level of treatment required. By imposing financial assurance requirem ents on those parties, EPA could also
reduce the likelihood that costs and dama ges arising from such contamination would go unpaid, for example, if such co sts exceeded the security posted by the owner or operator. Regulatory oversight would make th ese firms "more likely to undertake operating decisions that consider environm ental (and remediation)
costs." WRI ISSUE BRIEF at 6.

Individual Response: EPA clarifies that the financial responsi bility 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 fi nal approach to financial responsibility.

31Furthermore, comments related to the need to regulate CO2 genera tors and CO2 stream treatment facilities are outside the scope of this rulemaking.

The GS rule does not set generic purity standa rds 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 sour ce of the CO2 and its physical and chemical properties. Specifically, the GS rule requires the owner or operator to subm it 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 compatib ility of the CO2 stream with fluids in the injection zone and minerals in both the injection and the confini ng zones and the materials used to construct the well, per §146.82(c)(3). This info rmation 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 lia bility for long-term care

Comment: C. EPA’s Long-Term Liability Scheme fo r GS Does Not Adequately Protect the
Public or Address the Concerns of Industry

The proposed regulation sets out the fo llowing long-term liability scheme for GS: (1) owners and operators remain lia ble 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 responsib ility at site closure.

The combination of these two elements, perpetual liability plus limited financial assurance, means that: (1) th e 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 a nd 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 th e private sector pay for CCS with the private sector’s interest in removing obs tacles to deployment of CCS, a longterm liability scheme for GS that woul d transfer post-closur e site care and MMV to the government once closure conditi ons are met should be developed. EPA should seek from Congress the additional authority it would n eed to establish
such a scheme.

Individual Response: Under the final GS rule, once an owne r or operator has met all regulatory

32requirements under Part 146 for Class VI wells and the Director has approved site closure pursuant to requirements at §146.93, the owner or opera tor will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, 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 ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA’s authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner 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 pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner 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 ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, 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 lia bility for long-term care

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

Long-term liability "comprises both antic ipated costs associated with the longterm care of a storage facility and th e potential for costs associated with unanticipated damages." WRI WORKSHOP SU MMARY at 1. EPA has discussed the issue of long-term liability for GS in vari ous workshops leading up to the proposed regulation and seems to recognize that it is a key issue that mu st 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 CHA NGE 1 (2007) (discussi ng critical factors

33for 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: REPO RT ON IDENTIFIED STATUTORY AND
REGULATORY ISSUES 40 (2007). ("The various form s of liability (e.g., economic and environmental) inherent in proposed seque stration projects and how they will be addressed within a given regulatory framew ork are perceived as being significant factors in making sequestration project s feasible and for attaining public acceptance of the technologies, processe s and regulations." ); WRI WORKSHOP SUMMARY at 1 ("Long-term liability is on e of the several im portant challenges that CCS faces.").

Given the indefinite long-t erm 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 agains t 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 liabi lity 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 in to 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 wate r supplies, and the like that, while unlikely, are nonetheless possible, and, he nce 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 opera tor will generally no longer be subject to enforcement for regulatory noncompliance.

EPA does not have authority to tr ansfer SDWA or other legal liab ility 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 Respons ibility and Long-Term Care Requirements
Comment Code: 5460 2.9.2 Comments on transfer of lia bility for long-term care

Comment: 2. EPA’s Proposed Regulation

34Under the proposed regulation, "the owner or operator of a GS site is released from post-injection site care respons ibilities" (including all monitoring or reporting responsibilities) upon site cl osure. 73 Fed. Reg. at 43,535 (proposed 40 C.F.R. § 146.81(d)) (defining "site cl osure" 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 pos t-injection site care period has ended and the Direct or has authorized site closure[.]"). Thus, once the site is closed, the owne r 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 e nded . . . . 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 sha ll restrict any righ t 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 problem s 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 pe riod 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 uncompensat ed damages of any mi gration, leakage, or damage that occurs after a site is closed. Given the uncertainties of CCS technology at this time a nd the anticipated indefin ite lifetime for GS wells, the government must anticipate that some number of post-closure incidents will occur, and it must provide the public w ith assurance that any costs or damages arising from them will be paid.

b. Industry Lacks Certainty

35In addition to burdening the public with risks of future costs, the proposed regulation’s infinite liability leaves po tential owners/operators with much uncertainty as to the management of th eir responsibilities. This uncertainty could significantly hamper large-scale industry investment in CCS. EPA is aware of this problem, but the proposed re gulation does not offer a solution:

Responsibility for long-term care is often considered an impo rtant 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 addres sing financial respons ibility 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 alternativ e 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 m odel 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 indefin ite long-term liability (in the proposed regulation), which could impede im plementation of large-scale GS.

Individual Response: EPA acknowledges the commenter's need for certainty. The agency is working to create a nationally consistent fina ncial responsibility regi me for GS within its authority under SDWA while providing permitting au thorities an appropriate level of flexibility. .The SDWA provides EPA the general authority to set minimum fede ral requirements for financial responsibility to ensure that financial resources are av ailable 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-a pproved PISC and site closure plan following the cessation of injection until th e 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 regulator y 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 re quired under §146.85 will be released if it was not used. However, even if a site closure is a pproved under §146.93, an owner or operator may be held liable for regulatory noncompliance (inc luding 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 a pproved if the Direct or relied on erroneous

36information (e.g., erroneous modeling data) provi ded 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 SD WA after site closure if there is unanticipated migration towards or into a US DW 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 penalt y 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 re sponsibilities are transferred to that new owner and operator, which includes all poten tial liabilities associat ed with meeting the requirements of that permit. Please see further clar ification on the issue of long term liability in the preamble of the final rule.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, 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 auth orized (and therefore fina ncial responsibility must continue) until the owner or operator has demonstr ated 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 Respons ibility and Long-Term Care Requirements
Comment Code: 5460 2.9.2 Comments on transfer of lia bility for long-term care

Comment: 3. EPA Should Extend Its Financial Assura nce Requirements Into The Post-Closure Period and Transfer MMV Respons ibilities to the Government.

The risk to the public can be addresse d by requiring owners/o perators 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 fi nancial 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 endangermen t of USDWs from improper . . . management of wells afte r 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 respons ibility requirements for injecti on well owners or operators to ensure that adequate resources are available to protect USDW s throughout the life of the GS project. However, this authorit y does not extend to allowing the Agency to create a financial
instrument with EPA as the trustee. Furthermor e, EPA does not have authority in the SDWA to create a trust fund. The Agency clarifies that th e trust funds that are addressed as financial responsibility instruments through the GS rule are set up by indivi dual owners or operators and
are different from a national-level trust desc ribed 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 lia bility for long-term care

Comment: Many commentators have suggested that gove rnment should put in place a long-term liability scheme which includes the tran sfer of liability to the public at a reasonable point in time and after satisf action of performance standards. See generally WRI WORKSHOP SUMMARY at 6 ("So me 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/coa l/The_ Future_ of_Coal.pdf ("The government needs to assume liability for the sequestered CO 2 once injection operations cease and the
site is closed. The transfer of liabi lity would be contingent on the site meeting a set of regulatory criteria . . . and the operators paying into an insurance pool to cover potential damage s 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 pub lic sector to maintain economic viability and to encourage industry participation. Be cause the lifespan of sequestration projects after closure, which would in clude 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 institu tional knowledge) is seen as the most viable entity capable of maintaini ng 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 effec tive cost-sharing arrangements and other limitations on the financial burden to be borne by the public. Notably, the transference of liabi lity is not the only way to monitor

38and maintain these projects over the long term. For example, Australia’s proposed regulations for off-shore sequest ration 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 Common wealth, the cost of such monitoring nevertheless remains the responsibility of the operator, who must post financial security for the estimated cost of l ong-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 Powe r Plants, 28 ENERGY L.J. 443, 468 (2007) (advocating a site-specifi c, risk-based approach to GS regulation). Additionally, the long-term liability sc heme could provide for a national fund
to address all other cost s (e.g., remediation and corre ctive 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 re gulation grants th e 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 ove r time as secondary trapping mechanisms engage; however, given that the CO2 is m eant 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 problem s of ensuring long-term care and responsibility of GS site s 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 opera tor will generally no longer be subject to enforcement for regulatory noncompliance.

EPA does not have authority to tr ansfer SDWA or other legal liab ility 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

39Comment Code: 5460 2.9.2 Comments on transfer of lia bility for long-term care

Comment: a. EPA’s Need for Additional Authority

In the preamble to the proposed regulati on, EPA notes (probabl y 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 fi nancial 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 facilita te large-scale implemen tation 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 opera tor will generally no longer be subject to enforcement for regulatory noncompliance.

EPA does not have authority to tr ansfer SDWA or other legal liab ility 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 lia bility 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 lack s 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 st ates 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 indi vidual states, exercising primacy under SDWA, could choos e to assume responsibility for GS sites after closure, but that the EP A could not require the transfer of liability). Leaving it to the states to create appropriate liability and
financial mechanisms for GS is inadvi sable for the reasons stated below. A
uniform national framework is needed.

40First, 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]rans fer of liability and ownership of the injected gas to the public sector ma y pose too great a financial burden, especially for a state with a populace of limited means and other significant resource-demanding needs (e.g. educati on, health care)." FESMIRE ET. AL., supra, at 59.

Second, much if not all of the energy i ndustry 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 b een seen in reaction to th e Department of Energy’s FutureGen project, where both Texas a nd Illinois extended in demnification and significant tax benefits to CCS projects in order to attract the investment. This competition increases the likelih ood 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 c oncentration of [GS] activity in states with more lenient regulations . . . .").

Third, geological realities mean that so me states (i.e., those with suitable storage formations) may bear a disproportio nate share of the costs and risks of geological sequestration relative to those states’ consumption of the electricity or other product s which generated the CO2.

Fourth, given the fact that stored CO2 is expected to migrate, in cases where
the CO2 crosses state bounda ries, liability and remedi ation issues would impact more than the single state in which the GS facility (well) is situated.

For these and other reasons, a national a pproach to GS regul ation of long-term liabilities should be taken, which incl udes the creation of a national fund to address costs associated with unexpect ed 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 opera tor will generally no longer be subject to enforcement for regulatory noncompliance.

EPA does not have authority to tr ansfer SDWA or other legal liab ility 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.

41Letter 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-USDW s are not protected against potential endangerment from GS operations under the proposed regul ation.[FN14] EPA’scontinued use of a 1980 definition for USDWs, however, means that many nowviable sources of drinking water fa ll outside the technical definition of "USDW," leaving valuable water supp lies 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 cu rrent state and foreseeabl e 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 wate r 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 "U SDW" any aquifer th at 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 th e UIC regulations, "USDW" has been defined narrowly to exclude any aquife r with waters containing more than 10,000 mg/L (also known as 10,000 p.p.m.) to tal dissolved so lids (TDS). See Consolidated Permit Regulations and T echnical 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 cr eation 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 injec tion which endangers drinking water sources," which the SDWA defined to m ean injection which may contaminate any "underground water which supplies or can r easonably be expected to supply any public water system." See 42 U.S.C. §300h(a)-(b), (d)(2) (emphasis added).

42The legislative history supports the pos ition 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] . . . define s "underground injection which endangers drinking water sources." It is the Committee’s intent that the definition be liberally construed so as to effectua te the preventive and public health protective purposes of the bill. The Committee seeks to protect not only currently-used sources of drinking wate r, 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 stat ed that it considered alternative proposed concentrations to determin e 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 argumen t to the contrary, the Agency will
follow the standard in the House Comm ittee Report accompanying the SDWA." Id.

However, improvements in desalinati on 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 de salinated using Reverse Osmosis (RO) or Distillation processes that include multistage flash evaporation (MSF), multiple effect distillati on (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, avai lable at http://www.unihamburg.de/Wiss /FB/15/Sustainability/wrrdesalt.pdf (discussing the variety of desalting technologies). The cost-efficiency of these technologies vary w ith specific site characteristics. Accordingly, the cost per unit depends on size and location of

43the desalination plant an d is highly linked to th e price of electricity. "Larger plant capacity reduces the unit cost of water due to economies of scale. Lower energy costs and longer plant peri od 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 th rough 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/Sustaina bility/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 cu rrent, but also all reasonably expected, sources of drinking water are protected from GS, EPA must update the 10,000 mg/L reference to refl ect 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 sta ndard from becoming outdated and the resulting endangerment of viable sources of drinking water by GS. In this way, EPA will comply with its Congressional manda te to prevent endangerment of USDWs.

In addition, ELPC and ETIP note that the proposed regulation excludes from protection aquifers and wells that lik ely 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 pr ovide 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 consumpti on, if such system has at least fifteen service connections or regul arly serves at least tw enty-five individuals." 42 U.S.C. § 300F(4).

Individual Response: EPA recognizes that there is increa sing demand for water resources and that technology improvements may make high TDS aquifers viable drinking water sources. EPA

44believes these potential resources should be considered when inje ction depth waivers are sought. Therefore, the final GS rule at §146.95(b) requir es the Director to consider these issues in determining whether an injection depth waiver is appropriate. Sp ecifically, the Director must consider whether alternative inje ction sites are availa ble; 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 rela ted 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 focuse s on ensuring protection of USDWs, as required under the SDWA, by establishing regul ations to ensure the safe in jection of CO2 for long-term storage. For additional information on the waiv er approach, please see the final rule and preamble, as well as EPA's responses to comments on the Notice of Da ta 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 L east 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 characterizati on, operating, monitoring, mechanical integrity, well plugging, post-injection site car e, and site closure requirements. Id.

As EPA points out, "GS projects are antic ipated to have l ong lifespans in comparison to other types of deep inj ection wells. Not only must GS wells be able to function safely and properly over the lifespan of th e GS project, but they must be constructed such that USDW s remain protected after well plugging." Id. at 43,510. In terms of constructio n materials, it appears from EPA’s
discussion that the selection of the ce ment and metal well materials is of central importance given the potential of the CO2 stream (including water and impurities) to corrode cement and me tal 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 whic h the materials may be expected to come into contact and meet or exceed standards developed for such materials by the

45American 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 w ould 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 fa vor of the Director’s general
determination that use of the well woul d 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 construc tion requirements for GS wells provide assurance beyond "no endangerment of US DWs," that "extra" assurance seems appropriate in light of industry’s inexpe rience 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 ex ample, "[a]ll well materials must be compatible with fluids with which the materials may be expected to come into contact. A well sha ll be deemed to have compatibility as long as the materials used in the co nstruction 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). Howeve r, the Class I well would have been evaluated for "compatibility" with resp ect 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 Cl ass 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, grandfatheri ng 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 re gulations. 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 pr otective applicable standard.

46Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, particularly given that the convert ed well will be used for a substa ntially different process, which involves increased reservoir pre ssures associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of water. Th e 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 c onvert existing wells for long term storage must demonstrate to the Director that the grandfathe red wells were engineered and constructed meet the requirements at §146.86(a) and ensure prot ection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a).

EPA clarifies that only the construction requir ements 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-inject ion site care and site closure requirements
in the final GS rule. See the discussion of EPA's fi nal 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 Capab ility Based On Their Specific Leakage
Risk Profiles.

In the preamble to the proposed regulati on, EPA states that it is soliciting

comment on:

(1) Whether CO2 injection should be allo wed into an injection zone above the lowermost USDW, when the Director dete rmines that geologic conditions (e.g., thousands of feet of intervening forma tions between the injection zone and the overlying and/or underlying USDWs) exist th at 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 al lowing 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 Cl ass 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.

47The 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 st orage capacity. WRI GUIDELI NES at 91. Building on the WRI’s guidelines and on further res earch, 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. Futu re work is needed to clarify such ranking criteria.

2. Low-risk sites should be prio ritized for early projects.

3. As required by regulation, storage re servoirs should not be freshwater aquifers or potential undergr ound 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 collec ted and used to develop a subsurface reservoir model to predict/simulate the injection over the lifetime of the storage project and the associated proj ect 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 woul d first authorize GS at sites with low risk. However, as more GS projects ar e deployed and the availability of low risk sites decreases (event ually, 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 technicall y 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 re quire the owner or operator to provide financial assurance to cover the costs of such treatment.

48Individual Response: EPA disagrees that a ranking of sites is appropriate, or that permitting
sites on the basis of whether tr eatment 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 ha ve as much site-specific information as possible in order to make an informed decision to pe rmit injection for GS at a specific site.

EPA believes that there are limited circumstan ces where injection above the lowermost USDW can be performed in a manner th at protects USDWs, as long as appropriate protections are in place. The final GS rule at §146.95 establishes a pr ocess by which owners or operators can seek a waiver of the Class VI injec tion depth requirements for injec tion into non-USDW formations above and/or between USDWs. The waiver approach requires the submissi on of extensive, sitespecific information (in conjuncti on with the permit application s ubmission) 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 in formation that owners or operators must submit, and Directors must c onsider, in consultation w ith PWSS Directors; 2) procedures for public notice of a waiver application and for Director-Regional Administrator communication; 3) the waiver i ssuance process; and, 4) additiona l requirements that apply to owners or operators of Class VI wells granted a waiver of the injection depth requirements to ensure USDW protection above a nd below the injection zone. The final rule also establishes limited circumstances under which expansions of th e 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 approa ch, please see the final rule and preamble, as well as EPA's responses to comments on the No tice 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 lowermos t formation containing a USDW

Comment: A. CO2 Injection Above The Lowermost USDW

The proposed regulation prohibits GS a bove the lowermost USDW. 73 Fed. Reg. at 43,535 (proposed 40 C.F.R. § 146.5(f)) (definin g Class VI wells as "[w]ells used for geologic sequestration of carbon dioxi de beneath the lowermost formation containing an underground source of dri nking 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.

49The regulations for Class I hazardous and non-hazardous waste injection wells contain a similar prohibiti on against injection above a lowermost USDW. See id. at 43,511; U.S. EPA, CLASS I UNDERG ROUND INJECTION CONTROL PROGRAM:
STUDY OF THE
RISKS ASSOCIATED WITH CLASS I UNDE RGROUND INJECTION WELLS 2 (March 2001) ("By definition, Class I wells inject industria l 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 associ ated with GS and the lack of data available regarding the likely behavi or 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 a bove or between USDWs is appropriate and protective of USDWs. 73 Fed. Reg. at 43,512. Nonetheless, EPA is considering giving the Director discreti on 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 inj ection zone and the overlying and/or underlying USDWs exist that will prevent fl uid movement into adjacent USDWs. Id.

EPA anticipates that such discretion w ould 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 a bove the lowermost USDW and where there may be thousands of feet of rock stra ta between the injection zone and the overlying and underlying USDWs").

Before allowing such injections, EPA shoul d first carry out further research and rank sites with geological storage capac ity 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 contamin ation of underground reservoirs, and the specific characteristics of the aquifer su ch 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 suitabil ity of a proposed site should be made based on site-specific data.

50EPA agrees that protecting USDWs from endange rment must be a top priority. The Agency
believes that there are limited circumstances wh ere injection above the lowermost USDW can be performed in a manner that protects USDWs, as l ong as appropriate protections are in place. The final GS rule at §146.95 establishe s a process by which owners or operators can seek a waiver of the Class VI injection depth requirements for in jection into non-USDW formations above and/or
between USDWs.

EPA believes that the requirements at §146.95 w ill ensure USDW protection while providing flexibility to UIC Program Dir ectors and owners or operators who undertake CO2 injection for GS. The Agency believes this approach: 1) responds to concerns a bout 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) allo ws 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 injecti on depth variability thr ough a waiver process responds to concerns about future drinking water resource availability and the need to ensure that high quality water remains available in sufficien t quantities to supply dr inking water needs. For additional information on the waiver approach, pleas e 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 wh en 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 futu re 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 loca tion which makes recovery of water for drinking water purposes economically or technologically impractical;

(3) It is so contaminated that it w ould be economically or technologically impractical to render that water fit for human consumption; or

51(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 reas onably 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 USDW s 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 dete rmined "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 re sources and the ava ilable 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 s ites are no longe r 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 Cl ass II EOR/EGR wells tran sitioning 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 lo cated above and/or between USDW s, the permit applicant must also apply for a waiver of the injection depth re quirements pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the inje ction zone are protected from endangerment.

The Agency developed the waiver process to ad dress comments and conc erns about current and future drinking water resources and the use of cl imate mitigation technology at appropriate sites. The aquifer exemption requirements in the final ru le provide flexibility and afford owners or operators an opportunity to asse ss and select a suitable GS si te while also preserving USDWs (i.e., formations/aquifers afforded SDWA protec tion). 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 fi nal 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.

52EPA agrees that future water resources needs ar e an important consideration, and believes that the injection depth waiver process at §146.95 res ponds to concerns about future drinking water resource availability and the need to ensure high quality water remains available in sufficient quantities to supply drinki ng water supply needs.

For additional information on the waiver approa ch and aquifer exemptions for Class VI wells, please see the final rule and pr eamble, 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. Fo r example, we are pleased to see that EPA has provided flexibility in the choi ce 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 Depart ment of Energy; United States Geological Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau of Land Ma nagement). The Agency continues to evaluate areas of potential applicability of other Federa l environmental statutes including, but not limited to: the Clean Air Act; the Resource Conserva tion and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liabili ty Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of GS a nd CCS. The Agency will continue to coordinate
on GS and CCS related issues to minimize redunda ncy and maximize efficiencies for owners or operators. For additional information, please s ee 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, li ability remains with the owner or operator. EPA
notes that the final rule clar ifies the requirements for the us e of financial responsibility

5354 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 operato rs that describe the financial responsibility and injection well plugging requirements in the GS rule.