This comment letter response contains two parts:   

(1) The original submittal from the commenter.

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

Notes about the response letters:

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

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

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

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

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

individual response. These are described and explained below.  

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

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

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

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

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

appropriately addressed.

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

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

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

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

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

construction requirements).  

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

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

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

commenter was given a unique response.

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

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

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

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

and attention to each comment letter that was submitted.   

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

Responses on each topic area are compiled and are also available in the rulemaking docket.
December 18, 2008 

Sent Via Electronic and Hand Delivery

U.S. Environmental Protection Agency 

Water Docket, EPA Docket Center (EPA/DC) 

EPA West, Room 334 

1301 Constitution Ave., NW 

Washington, DC 20460 

Re: Comments on the U.S. EPA Office of Water UIC Geologic Sequestration Rule, 

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

Dear Assistant Administrator Grumbles: 

 Spectra Energy Corp (“Spectra” or “Spectra Energy”) appreciates this opportunity 

to submit for the U.S. EPA’s (“EPA” or “Agency”) consideration the following 

comments regarding the Agency’s proposed development of Federal Requirements Under 

the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration 

Wells (hereafter referred to as the “Proposed Rule” or “GS Rule”). 73 Fed. Reg. 43491 

(July 25, 2008). We appreciate the Agency’s recognition of the importance of the GS 

Rule in the larger context of carbon, capture and sequestration (“CCS”) and we 

acknowledge the Agency’s tremendous work in proposing this rule within such a short 

schedule, especially given the complexities of the issue. Although we have a number of 

concerns and recommendations regarding the proposed technical requirements and 

potential liabilities, we believe that the Proposed Rule provides a solid foundation toward 

promulgating the Final Rule. 

 Spectra Energy has a significant interest in the GS Rule for a number of reasons. 

First, as detailed below, Spectra has extensive knowledge and experience with injection 

of CO2 and sour CO2 from natural gas processing. Spectra also has extensive knowledge 

and experience with constructing and operating natural gas storage facilities. Therefore, 

we offer working knowledge of how CO2 injection activities can be performed effectively 

and safely and, drawing upon that experience, we can provide the Agency with useful 

technical insight and recommendations on reasonable approaches to geologic 

sequestration. 

Spectra believes the GS Rule should be designed to encourage carbon capture and 

sequestration as an integral part of any national climate change policy. Second, while 
Spectra Energy UIC Comments 

Page 2 

December 18, 2008 

 

Spectra appreciates many of the unknowns that currently exist with respect to commercial 

scale GS operations, sour CO2

1

 from natural gas operations has been safely injected for 

nearly two decades and such operations present significant opportunities for further 

reductions in atmospheric CO2 emission through long-term geologic sequestration. 

Lastly, Spectra and many others within the industry have ongoing operations in North 

America and elsewhere, and we are concerned that, should EPA impose excessive or 

unreasonable requirements as part of the GS Rule, this could have negative implications 

for GS activities in other jurisdictions such as Canada – where the majority of Spectra’s 

current geologic sequestration activities occur. 

 Our comments are structured as follows. Section I (beginning on Page 3) provides 

an overview of Spectra Energy’s operations and broad experience with geologic 

sequestration. Section II (Page 6) offers an overview of some of the more technical 

provisions of the Proposed Rule and our recommendations regarding those requirements. 

Section III (Page 16) presents a review of the continuing liability impediments to CCS 

and our recommendations regarding how best to remove those barriers. Sections IV 

(Page 31) and V (Page 39) provide an evaluation of the long-term care and financial 

assurance requirements, respectively, associated with CCS and our recommendations. 

1

 The term sour CO2 (a/k/a “acid gas”) is used to describe the by-product generated from 

natural gas processing and is primarily a mixture of CO2 and H2S but may also contain a small 

amount of impurities. 
Spectra Energy UIC Comments 

Page 3 

December 18, 2008 

I. INTRODUCTION 

 

 Spectra Energy, headquartered in Houston, Texas, has one of the largest natural 

gas transportation systems in North America, encompassing more than 18,000 miles of 

transmission pipelines and 265 billion cubic feet (Bcf) of storage capacity. Our U.S. 

operations include: 

• Texas Eastern Transmission which transports up to 6.5 Bcf per day from 

producing fields in the Gulf Coast region of Texas and Louisiana to high-demand 

markets primarily in the Northeastern U.S. The pipeline comprises 8,700 miles of 

onshore pipe and 100 miles of pipe into the Gulf of Mexico. 

• East Tennessee Natural Gas which transports up to 1.3 Bcf per day mainly 

through Tennessee and Virginia across 1,432 miles of pipeline. 

• Maritimes & Northeast which transports natural gas across the northeastern U.S. 

and Atlantic Canada. The U.S. portion, comprised of 340 miles of pipeline, 

currently transports up to 420 Mcf per day. 

• Algonquin Gas Transmission which plays a key role in servicing the New 

England region. Its 1,100 miles of pipeline transport up to 1.9 Bcf per day of 

natural gas. 

• Gulfstream Natural Gas in which Spectra has a 50% interest. Its 691 miles of 

pipeline transport 1.1 Bcf per day of natural gas from the Mississippi and Alabama 

coast to Florida. 

• Southeast Supply Header in which Spectra has a 50% interest. Its 270 miles of 

pipeline transport 1 Bcf per day of natural gas from northeast Louisiana to 

southwest Alabama. 

• Market Hub Partners and Saltville Gas Storage through which Spectra Energy 

has significant gas reservoir and salt cavern natural gas storage capabilities. Our 

storage assets are strategically located in both supply and market areas, including 

Texas, Louisiana, and Virginia. 

• DCP Midstream is one of the nation’s largest natural gas gatherers and 

processors, the largest NGL producer and one of the largest NGL marketers in the 

U.S. DCP Midstream is a 50-50 joint venture between Spectra Energy and 
Spectra Energy UIC Comments 

Page 4 

December 18, 2008 

ConocoPhillips. DCP operates processing plants, gas gathering systems, and other 

assets. 

Spectra’s comments are largely influenced by our company’s expertise with CCS 

operations in western Canada. Since the mid 1990s, Spectra Energy’s Western Canadian 

business unit (SET West) has incorporated CCS/acid gas re-injection (AGR) into our 

natural gas processing facilities in British Columbia and Alberta. For example, our 

Kwoen facility is the largest CCS/AGR operation in North America, re-injecting 

approximately 100 Kt per year. An expansion currently underway at Kwoen will 

increase the reinjection and storage capacity of the project to 130 Kt CO2/year. Kwoen 

and SET West have been recognized by the Intergovernmental Panel on Climate Change 

(IPCC) as a leader in CCS. 

SET’s four main CCS/AGR projects in British Columbia safely capture and store 175 Kt 

CO2 per year. 

 The AGR/CCS at Sikanni injects 5Kt CO2/year. 

 The AGR/CCS at Jedney 1 injects 39 Kt CO2/year. 

 A partner project at the same location - Jedney 2 - injects 30 Kt CO2/year. 

 The Kwoen facility currently injects 100 Kt CO2/year., 

Further, a project at Spectra Energy’s Fort Nelson Plant, also in British Columbia, could 

result in the sequestration of over 1 million Kt CO2/year, once fully operational. Today, 

Spectra Energy’s eight CCS/AGR projects safely capture and store more than 229 Kt 

CO2 per year. 

The evolution and commercialization of these technologies into SET’s operations have 

resulted in significant positive environmental impacts: 

 Reducing carbon emissions from its operations by ~800 Kt to date. 

 Shrinking the environmental footprint of its operations. 

 Decreasing/eliminating the processing and release of sulfur. 

It has also accrued benefits to SET’s customers by moving more natural gas from 

exploration and production fields in northeast British Columbia to the Lower Mainland 

and U.S. Pacific Northwest markets. 

 Key CCS/AGR projects (Jedney and Kwoen) have been reviewed by third 

parties and benchmarked against relevant standards available at the time. 
Spectra Energy UIC Comments 

Page 5 

December 18, 2008 

 SET West continues to work with our partners in government, academia and 

industry to further evolve the technology. 

 There are now 44 CO2-rich gas re-injection projects in operation in Western 

Canada, eight of which are managed by SET West. 

The exceptional scale and relative impact of these projects are depicted in the following 

graph of CO2 injection activities. Also shown is the exploratory project currently 

contemplated for SET’s Fort Nelson facility. 

(Total Acid Gas - H2S and CO2)

(CO2)

SET Projects in B.C.

Proposed CCS/AGR Project 

at Fort Nelson, B.C.

equivalent to 1-1.2 MT/yr of CO2 

Injected into Deep Saline Aquifer

Kwoen

Figure 1: Comparison of the magnitude of CO2 injection activities 

Source: Adapted from Page 233. Carbon Dioxide Capture and Storage. IPCC (2005) 

http://arch.rivm.nl/env/int/ipcc/pages_media/SRCCS-final/SRCCS_WholeReport.pdf 

Based on the extensive project experience described above, we offer the following 

comments. 
Spectra Energy UIC Comments 

Page 6 

December 18, 2008 

II. FOR CCS TO BE VIABLE, GS REQUIREMENTS MUST BE FLEXIBLE, 

TAILORED TO SITE SPECIFIC NEEDS, AND MUST RELY UPON 

STATE EXPERIENCE. 

 Under the Proposed Rule, EPA has adopted an approach specifically tailored to 

the unique characteristics of CO2 deepwell injection. While we generally support the 

Agency’s decision not to be overly prescriptive in the development of the GS 

requirements, certain portions of the technical requirements appear to be excessive and 

unreasonable and will result in higher operational costs without meaningful benefits. In 

the promulgation of the Final Rule, we would encourage EPA to continue to build upon 

the concept of flexibility, reduce the amount of unnecessary and costly requirements, and, 

in certain cases, provide greater discretion to the States in deciding the technical 

specifications applicable to siting, well construction, and monitoring. 

A. EPA Should Allow The Use Of Proprietary Models For Modeling CO2 

Movement and Reservoir Pressure. 

 EPA correctly acknowledges that some companies use proprietary models for their 

current GS operations, and has requested comment on allowing the use of such models 

for GS sites. Spectra strongly agrees with the continued use of proprietary models. 

While Spectra would be willing to provide information pertaining to the underlying 

assumptions and scientific basis, subject to protection as confidential business 

information (“CBI”), we would object to any effort by the Agency to compel further 

disclosure regarding such models. Although we recognize that the Agency is required by 

law to take certain steps to protect CBI, we are mindful that such protections are not 

always fail-safe and inadvertent disclosures of CBI are not uncommon. Such disclosures 

in the case of the critical infrastructure we operate or may operate in the future could be 

extremely detrimental and costly. 

B. The Area of Review Should Be Determined Based On Computational 

Fluid Flow Models And Reevaluation Should Occur At A Fixed 

Frequency Not To Exceed 10 Years. 

 We agree with the Agency’s current position that the application of computational 

fluid flow models to predict the complex multi-phase buoyant flow of CO2, co-injectates, 

and compounds is an acceptable and appropriate approach to mapping out the Area of 

Review (AoR). Such computational models are currently being used by industry with 

success. Further, industry continues to refine the accuracy of these models as the data 

and science are improved. 
Spectra Energy UIC Comments 

Page 7 

December 18, 2008 

 We also support the Agency’s position that any reevaluation of the AoR occur at a 

minimum fixed frequency, not to exceed 10 years. As well, we agree with providing the 

Director discretion to require more frequent reevaluation, as appropriate, if the 

monitoring or modeling suggests that the CO2 plume is not behaving as originally 

predicted and could result in endangerment to underground sources of drinking water 

(USDWs). Based on our experience with AGR, we believe that a frequency of between 

3-5 years may be more reasonable and appropriate and would support such a 

determination; but in any event, we agree that such reevaluation should not exceed 10 

years. 

C. Phased Corrective Action Is An Appropriate Approach. 

Spectra Energy agrees with the Agency’s idea of allowing for phased corrective 

action. We believe this is a reasonable approach, given the potential size of the CO2 

plume for commercial-scale operations (50 square miles or larger). Requiring corrective 

action for the entire AoR prior to injection would likely result in substantial delays in 

permitting and project implementation. We agree that at a minimum, as part of the AoR 

process, all wells that penetrate the confining or injection zone must be identified. One 

question that warrants clarification by EPA, however, is the ability to gain access to third 

party wells that may over time require corrective action. Most states require corrective 

action to be performed prior to injection and the “right of access” is taken into 

consideration during the adequacy determination of the corrective action plan. Some 

states, such as Texas, require corrective action prior to injection unless the 

owner/operator, after best efforts, is unable to get permission to access the property of a 

third party. 30 TEX. ADMIN. CODE § 305.151 (2008). Since SDWA does not provide 

EPA the authority to require third parties to provide access to an owner/operator for the 

purposes of conducting corrective action, we believe it is important for the Agency in the 

Final GS Rule to discuss and clarify how owner/operators and states will be expected to 

implement corrective action based on an iterative approach. 

D. EPA Should Not Arbitrarily Preclude Injection Into Certain 

Formations Located Above The Lowermost USDW. 

 Under the Proposed Rule, EPA has proposed limiting the injection of CO2 to 

below the lowermost USDW. Spectra believes that it is premature for the Agency to 

preclude the injection of CO2 into formations such as unmineable coal seams, depleted oil 

and gas reservoirs, zones in between or above USDWs, or other formations. As EPA 

points out, imposing such a limit may preclude the application of GS in areas such as the 

Williston and Powder River Basins in Wyoming and North and South Dakota, where the 

lowermost USDW is located thousands of feet below the surface. In these cases, we 

agree with EPA that GS may still be appropriate and, therefore, the Director should have 
Spectra Energy UIC Comments 

Page 8 

December 18, 2008 

the discretion to make such determinations. Such determination must ultimately be made 

based on the protection of USDWs. 

E. EPA Should Not Make The Permitting Process Overly Burdensome By 

Requiring Unnecessary Or Unavailable Data. 

 Under the proposal, EPA is requiring the collection and submission of a 

significant amount of information and data. Although we understand and support the 

need for certain baseline data to support the determination that a particular project 

location is suitable, in certain cases, some of the data that EPA is requiring is irrelevant, 

excessive, or may even be unavailable. Therefore, we would recommend that the Agency 

include a provision in the Final GS Rule that would provide a waiver process and criteria, 

whereby the Director could waive certain data requirements, where such requirements are 

unnecessary. 

 EPA is proposing that an applicant include “baseline geochemical data on 

subsurface formations, including all USDWs in the area of review.” 40 C.F.R. § 

146.82(g). It is not clear how much baseline data EPA is expecting the permit applicant 

to generate and collect from additional drilling or testing of the injection zone and all 

other zones. Given the likely depth of many of the GS wells through multiple strata, this 

could involve tens (and possibly hundreds) of different formations above the injection 

zone. Therefore, we would recommend that EPA limit the baseline geochemical data 

“where feasible, to the next porous formation above the injection zone.” EPA should also 

clarify that the permit applicant may rely upon secondary sources (such as other drilling 

or geologic records) that relate to and support the data requirement. EPA should also 

clarify whether the Agency expects applicants to test private wells, where permission is 

granted, within the AoR for purposes of establishing baseline data. As a general matter, 

Spectra believes that EPA should not require testing of private wells because sampling 

results could be affected by flawed well construction or poor integrity, wholly unrelated 

to the injection project. 

 EPA has also included a requirement that the permit applicant include a “proposed 

formation testing program to obtain an analysis of the chemical and physical 

characteristics” of the injection and confining zone. 40 C.F.R. § 146.82(j). A permit 

applicant is already required to submit the underlying data as part of the permit 

application process, and it appears that this requirement is unnecessary and duplicative. 

Therefore, we request further clarification regarding the intent and scope of this 

formation testing program. 

 Spectra generally supports the requirement for the “proposed stimulation 

program” to ensure that stimulation activities will not interfere with containment. 40 
Spectra Energy UIC Comments 

Page 9 

December 18, 2008 

C.F.R. § 146.82(k). We believe it is important that EPA monitor stimulation activities of 

third parties to ensure that such activities not interfere with or damage the containment 

integrity of other GS operations or natural gas storage reservoirs. 

 EPA has proposed requiring the applicant submit “the status of corrective action 

on wells in the area of review.” 40 C.F.R. § 146.82(q). We believe it is unnecessary to 

require the inclusion of all wells within the AoR regardless of whether or not they 

penetrate the injection zone. There could be many shallow wells within the AoR located 

hundreds or thousands of feet above the CO2 injection. Therefore, EPA should limit this 

requirement to the injection zone, injection pool, and only those wells that either intersect 

or penetrate the proposed reservoir, the cap rock, and possibly the porous strata directly 

above the injection zone, or wells that penetrate or are in close proximity to a gas storage 

reservoir. 

 The Agency has stated that only information of public record pertaining to all 

types of wells (injection, producing, abandoned) be included on the AoR. Data 

availability and use raises a question regarding the possible existence of other data which 

might be private, proprietary and/or not publicly available. Such non-publicly available 

data may or may not be relevant to the application process. However, EPA should 

clarify to what extent an applicant would be expected by EPA to develop or use 

information that is not contained in the public record. 

F. Integrity Testing And Monitoring Requirements Are Excessive And 

The Definition of “Significant Leakage” Should Be Clarified. 

 A significant component of the GS Rule is focused on mechanical integrity of 

injection wells to ensure against any “significant leakage” that would endanger USDWs. 

As part of the integrity testing requirements, EPA is proposing to require owner/operators 

to at least once per year determine the absence of significant fluid movement by using 

tracers, temperature or noise logs, or casing inspections, or any other tests as required by 

the Director. 40 CFR § 146.89(c). While Spectra fully supports the need for integrity 

testing, we believe that some of the requirements are excessive and unreasonable and will 

not provide meaningful data. 

1. EPA Should Define “Significant Leakage” Within The Context Of 

Endangerment. 

 EPA has defined mechanical integrity as “no significant leakage” and “no 

significant fluid movement into a USDW through channels adjacent to the injection well 

bore.” While Spectra agrees with EPA’s general approach here, we are concerned that 

the absence of a definition regarding what constitutes “significant” could create 
Spectra Energy UIC Comments 

Page 10 

December 18, 2008 

ambiguity that could be construed against the owner/operator and beyond authority 

granted under SDWA. Therefore, we would strongly recommend that the Agency define 

what constitutes “significant” or, alternatively, clarify under what conditions significant 

leakage might be construed. Toward this end, we believe that the term should be defined 

and construed within the statutorily defined concept of “endangerment”2

 under SDWA, 

i.e., significant leakage would be defined as any leakage that could potentially endanger a 

USDW. As one court has held, Congress’ established no specific metric for measuring 

endangerment and thus the Agency has the discretion to develop UIC requirements based 

on varied geology, Miami-Dade County v. EPA, 529 F.3d 1049 (11th Cir. 2008) (court 

upheld EPA’s rule eliminating the non-endangerment finding requirement for Class I 

municipal injection wells). The amount of leakage and what constitutes significant may 

vary depending upon the geologic formations and proximity to USDWs. 

2. Annual Mechanical Integrity Testing And Quarterly Corrosion 

Monitoring Are Excessive.

 We do not believe there is any compelling reason to require annual integrity 

testing. 40 C.F.R. § 146.89(c). First, our experience in Canada with sour CO2 injection 

wells is that integrity testing every five years is more than sufficient. Alberta regulations 

require all operators to verify every five years the down hole condition to confirm 

hydraulic isolation. Many of our injection wells are reused producer wells that have been 

in corrosive environments for over 15 years. Even after 15 years, these wells are in good 

condition, based on the good design and the use of proper materials, and we have never 

experienced a leak. Annual testing and quarterly corrosion testing could also result in 

significant costs from plant shutdowns and downtime with very little benefit, if any, from 

the data generated. Many companies, including Spectra, conduct periodic plant-wide 

shutdowns to thoroughly inspect piping and equipment for corrosion and make any 

necessary equipment upgrades. These shutdowns, which ordinarily occur once every 

three to five years, are also used to inspect our injection wells, including pulling tubing 

and running cement bond logs and well casing integrity logs to determine the thickness 

and integrity of the steel in the boreholes. From these tests we are able to assess the 

 2

 Endangerment is defined as follows: 

 Underground injection endangers drinking water sources if such 

injection may result in the presence in underground water which 

supplies or can reasonably be expected to supply any public water 

system of any contaminant, and if the presence of such contaminant 

may result in such system’s not complying with any national primary 

drinking water regulation or may otherwise adversely affect the health 

of persons. 42 U.S.C. § 300h(d). 
Spectra Energy UIC Comments 

Page 11 

December 18, 2008 

cement and casing conditions, which provide the primary “isolation” mechanism from the 

reservoir fluids. We can and often do run noise logs that can assess for “channeling” 

behind the casing. While routine testing is important, the most significant part of 

maintaining well integrity is ensuring material compatibility and making certain that the 

cement and casing materials used are resistant to corrosion. We use nickel steel in some 

of our wells, which is even stronger and more corrosion resistant than stainless steel. 

 Section 146.89(d) currently gives the Director discretion to require any other test 

to evaluate mechanical integrity, provided such alternative tests are approved and 

published in the Federal Register. We would recommend that EPA revise the mechanical 

integrity testing requirements in two ways: (1) to give the Director discretion to approve 

not only different testing requirements but the timing for testing requirements, and (2) to 

require such testing no less than every five years. 

 For reasons described above, we also believe that the requirement to conduct 

corrosion monitoring on a quarterly basis is excessive and unnecessary. To require 

quarterly monitoring could negatively impact the flow rate, thus requiring operators to 

add more wells. This could limit the overall effectiveness of the project. In addition, 

quarterly corrosion monitoring would require the operator to remove the bottom hole 

configuration to perform necessary tests. This is both costly and time consuming and 

would require operations to be temporarily shutdown. 

 EPA has specifically requested comment on the use of tracers. Based on our 

experience, tracers are not typically used for monitoring the movement of the CO2 plume, 

unless it is suspected that leakage is occurring, and then they are only used to trace the 

leakage. The use of tracers can be very expensive and the results can take considerable 

time to develop, analyze, and understand. Radioactive tracers typically have long shelf 

lives (e.g., 50 or 100 years) and, if used too frequently by neighboring operators, could 

produce conflicting and indeterminate results. Due to the potential for groundwater 

contamination, the use of radioactive materials should be used only sparingly and for 

targeted purposes. 

G. The Use Of Down-Hole Devices And Coupons Should Be Limited. 

 Although we do not believe that downhole monitoring devices are necessary for 

GS wells, the use of emergency shutdown devices (ESDs) may be important. At our 

Kwoen facility where we inject a sour CO2 mixture that is 80% H2S and 20% CO2, we 

use primarily three forms of ESD: (1) a valve at the wellhead, (2) a subsurface safety 

valve, and (3) a check valve at the packer. This ESD configuration enables us to plan for 

and respond to a number of contingencies, including (1) shutting down the wellhead (2) 

shutting the subsurface safety valve in the event the wellhead is sheared off or damaged, 
Spectra Energy UIC Comments 

Page 12 

December 18, 2008 

which prevents atmospheric leaks and (3) closing the packer check valve, which enables 

us to conduct any uphole work. For gas storage involving only the injection of sweet gas, 

typically only wellhead ESD is used. 

 EPA’s proposal also calls for the use of “coupons” to monitor for corrosion. 40 

C.F.R. § 146.90(c)(1). Based on our experience with the use of coupons, we would 

recommend against this requirement, as coupons are susceptible to failure and can lodge 

deep in the injection well, thereby causing problems with flow rate. In addition, coupons 

do not identify where corrosion may or may not be taking place, due to the differences in 

temperature and pressure between ambient and downhole conditions. The results from 

the use of coupons could suggest that an entire casing or tubing string needs to be 

replaced when, in fact, only a portion of the well casing may need to be replaced. 

Therefore, coupons do not produce representative results and the data will generally not 

be helpful. Similarly, the concept of a “constructed loop” at the surface to monitor and 

test material integrity is also not recommended, as it does not replicate actual downhole 

conditions. 40 C.F.R. § 146.90(c)(2). We believe that one of the best tests for corrosion 

monitoring is the casing evaluation logs, which allow an operator to identify specific 

zones where corrosion may be occurring. 

 EPA is also proposing “periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s).” § 146.90(d). It is unclear how many 

wells would be required, and whether EPA expects all zones would be monitored. Given 

the potential size of the CO2 plume and the number of confining zones, this could 

potentially require many monitoring wells, which could be extremely expensive and 

unlikely to produce useful data. It is our strong recommendation that EPA minimize the 

amount of monitoring to the zone immediately above the confining zone, and only to the 

extent that the CO2 plume is within close proximity. For example, there may be regional 

conditions where ground water is separated by hundred or thousands of feet of confining 

strata, and where such monitoring is unnecessary. We would recommend that the 

Director be given discretion to limit or tailor ground water monitoring, as appropriate, 

based on regional and site specific factors. 

 EPA is also proposing that an owner/operator demonstrate “external mechanical 

integrity pursuant to § 146.89(c) at least once per year.” 40 C.F.R. 146.90(e). External 

mechanical integrity is not defined. Therefore, we would ask EPA to clarify what is 

meant by this term. 

H. The Requirement To Perform Ambient Monitoring Exceeds EPA’s 

Authority Under SDWA. 
Spectra Energy UIC Comments 

Page 13 

December 18, 2008 

 EPA is also proposing that the Director be given discretion to require surface air 

monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could 

endanger a USDW. 40 C.F.R. § 146.90(h). We would recommend that this provision be 

deleted. It is not clear how ambient air or soil gas monitoring is related to or supports the 

protection of USDWs. Based on our experience, the use of surface air monitoring can 

frequently result in false positives, which could prompt unnecessary and costly response 

actions and needlessly alarm the public. We believe that targeted ground water 

monitoring and other wellhead testing and monitoring requirements are sufficient to 

detect any movement of CO2 that could endanger a USDW. Given the narrow scope of 

SDWA authority, we question the Agency’s authority to directly or indirectly require 

such monitoring where it does not naturally bear on the protection of USDWs. If EPA 

should decide to retain this provision in the final rule, we would ask the Agency to clarify 

that any requirement for ambient air or soil gas monitoring would be purely discretionary 

on the part of the State, would be pursuant only to state law and not the federal UIC 

program, and thus would not be federally enforceable. Bath Petroleum Storage, Inc. v. 

Sovas, 309 F.Supp. 2d 357 (N.D. N.Y. 2004) (state law requiring sonar survey for UIC 

injection not federally enforceable). 

I. Large-Scale GS Operations Must Not Impact The Storage Of 

Hydrocarbon Natural Gases. 

 One concern with GS is the potential implications for and impact on large-scale 

natural gas storage operations. Under SDWA, hydrocarbon natural gas storage is exempt 

from current UIC regulations governing injection activities. Spectra is concerned about 

the potential implications and impacts on underground gas storage from the Proposed 

Rule. Natural gas storage is regulated by State and interstate entities, such as Interstate 

Oil and Gas Compact Commission (IOGCC), that oversee the siting, permitting, design, 

construction, and operations of wells. Within the U.S., natural gas storage is generally 

located in two major geologic formations, porous rock reservoirs and salt caverns. 

Generally, the types of storage fields that will potentially be impacted by the Proposed 

Rule are porous rock reservoirs. Because many of the areas and geologic formations 

considered for GS will be in the same basins and may occur within or in close proximity 

to the same geologic strata, there is the potential for gas storage fields to be adversely 

impacted by GS. In order to avoid any unintended impacts to natural gas storage 

operations, there are several issues that need to be considered. 

 First, gas storage wells are regulated by State oil and gas regulatory agencies. 

Individual States have a critical role in protecting and regulating the competing economic 

interests involved in utilizing the subsurface, not only for natural gas storage but also oil 

and gas production or other subsurface activities. Many State oil and gas regulations 

specify well siting or construction requirements for any wells that are drilled within a gas 
Spectra Energy UIC Comments 

Page 14 

December 18, 2008 

storage area or penetrate the storage horizon. Spectra suggests that appropriate 

regulatory agencies in individual States be active participants with the EPA in the GS 

permitting process, to ensure appropriate State knowledge of local geology is considered 

in a technical evaluation of the suitability of potential GS zones, and for the balanced 

protection of gas storage and other economic interests. We believe the EPA should 

affirm the authority of the States to require the GS operator to comply with all well 

construction and monitoring requirements to protect the integrity of gas storage 

reservoirs. 

 Second, as part of the site selection and GS permit application process, all natural 

gas storage projects within the AoR should be identified on the AoR map and 

assessments performed to determine the potential impact from CO2 or fluid migration to 

the gas reservoir. Such an assessment should also include analysis of potential leak paths 

through faulting, fracturing, or other migration paths from injected CO2 in formations in 

close proximity to gas storage reservoirs. 

 Third, we would recommend that where GS and gas storage reservoirs are in close 

proximity that additional monitoring be required. We are also concerned about the 

potential impact of hydraulic fracturing of GS wells on natural gas storage. We believe 

that an analysis should be conducted based on the proximity (laterally and vertically) of 

the GS zone to existing gas storage reservoirs and the potential for communication with a 

gas storage reservoir. For this reason, we believe it is important that all records relating 

to well logs, cementing records, and casing strings and cementing operations of any GS 

wells drilled within the reservoir or protective perimeter boundaries of a gas storage field 

must be available and accessible to the public. Conversely, and for the same reasons, we 

believe information regarding the proximity of gas storage reservoirs to GS wells is 

equally important and should be readily available to the public to ensure the integrity of 

the CO2 injection operation. 

J. The Use Of Horizontal Drilling Should Be Allowed And Encouraged. 

 As the EPA has noted in the Proposed Rule, horizontal drilling is not typical in 

deep injection wells in the UIC program. However, horizontal wells have been used 

successfully for GS, such as the In Salah project in Algeria. Spectra supports the use of 

horizontal drilling, which has many advantages. For example, a horizontal well in a 

homogenous reservoir allows the operator to open up more porosity and permeability 

than one can achieve in a vertical well as the operator is capable of extending the length 

to be many times the horizontal thickness of the reservoir. This allows the operator to 

produce or inject over a greater length of reservoir at lower wellbore pressures. Whereas, 

a horizontal well in a heterogeneous reservoir has a greater probability of intersecting 

higher permeability streaks, fractures or other geologic features that will allow the 
Spectra Energy UIC Comments 

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December 18, 2008 

operator to inject at higher rates, to reduce wellbore pressure or to access more reservoir 

per well. 

 Importantly, greater reliance on horizontal drilling also improves the safety and 

containment of the disposal gas (fluid), as well as the economics of a CCS project as 

fewer wells are required to inject a given volume. Fewer wells equate to fewer 

penetrations through the containment zone and lowers the likelihood of leaks through the 

containment zone, either from leaks around the casing or from corrosion/erosion of 

wellbore tubulars later in the life of the well. As an exploration tool, horizontal drilling 

increases the ability to reach areas of the reservoir that an operator may not otherwise be 

able to reach using vertical drilling. As more porosity and permeability are opened up, 

the pressure differential across the injection face is reduced and therefore the ability to 

inject a given volume of gas in a single well bore increases as a ratio of the increased 

reservoir exposed. As well, by keeping the build section in the cap rock, potentials for 

bore holes to breach the integrity of the storage reservoir are reduced. Under this 

concept, fewer penetrations of the cap rock result in less potential for a breach to occur. 

 Horizontal drilling is only one of a number of new technologies that are being 

developed for better management of a reservoir, whether it be for oil and gas production, 

gas storage, coal bed methane production or injection for disposal of waste fluids. EPA 

should support the use of all new technologies which contribute to better methods of 

CCS. 
Spectra Energy UIC Comments 

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December 18, 2008 

 

III. EPA MUST ADDRESS THE LEGAL UNCERTAINTIES AND 

IMPEDIMENTS TO CCS. 

As has been well documented elsewhere, including a recent GAO report,3

 the legal 

uncertainties related to underground injection of CO2, including the possible application 

of CERCLA and RCRA, are a very real legal impediment to the viability of carbon 

capture and geologic sequestration. We agree with the GAO’s recommendation that EPA 

more comprehensively examine CERCLA and RCRA as a potential barrier to CCS. As 

discussed in greater detail below, we believe the Agency has sufficient authority to 

develop responsible policies and regulations that provide the requisite protection to 

owner/operators of GS operations while still ensuring the adequate protection of human 

health and the environment. Toward this end, we would ask the EPA to further examine 

and clearly articulate what it believes is the outer bounds of its statutory and regulatory 

authority to provide such legal certainty. If, in the event EPA does not believe it has such 

authority or, for whatever reason, is unwilling to invoke such authority, we would request 

the Administration and the Agency work with Congress to enact legislation to bring 

about the needed legal certainty. 

A. The Liability Regime Under CERCLA Is Inappropriate For GS And 

EPA Must Minimize To The Fullest Extent Of Its Authority; 

Alternatively, Congress Must Act. 

 The potential application of the sweeping liability regime under the 

Comprehensive, Environmental Response, Compensation, and Liability Act of 1980 

(“CERCLA”) will have an absolute chilling effect on the underground injection of CO2. 

The threat of CERCLA litigation and the potential liability to a GS owner or operator is 

alone significant and could seriously discourage the siting and construction of a GS 

operation. Under CERCLA’s strict liability regime, an owner or operator may be held 

jointly and severally liable for response costs related to any release or potential release of 

a hazardous substance from a facility. In addition to federal and state enforcement 

actions, CERCLA also authorizes private parties to seek remediation costs from an 

owner/operator who is alleged to have caused an actionable release under CERCLA. 

Therefore, given the extensive size of the CO2 plume, covering tens of square miles, a 

private landowner within the AoR and whose property is situated above the CO2 plume 

3 GAO Report, Climate Change, Federal Actions Will Greatly Affect the Viability of 

Carbon Capture and Storage As a Key Mitigation Option, REPORT TO THE CHAIRMAN ON THE 

SELECT COMMITTEE ON ENERGY INDEPENDENCE AND GLOBAL WARMING, HOUSE OF 

REPRESENTATIVES, GAO-08-1080 (September 2008). 
Spectra Energy UIC Comments 

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December 18, 2008 

 

could potentially assert a CERCLA claim against an owner/operator of a GS operation. 

In its proposed GS Rule, EPA states as follows: 

[W]hether or not there is a hazardous substance that may result in 

CERCLA liability from a sequestration facility depends entirely on 

the make-up of the specific CO2 stream and of the environmental 

media (e.g., soil, groundwater) in which it is stored. 

Unfortunately, the Proposed Rule leaves considerable uncertainty regarding potential 

CERCLA liability. See GAO Report, Climate Change: federal actions will greatly affect 

the viability of carbon capture and storage as key mitigation option, GAO-08-1080, 

September 2008. 

 We oppose the application of CERCLA liability to owner/operators of GS 

facilities, particularly where the owners/operators may have very little control, if any, 

over the migration of the CO2 plume or geochemical reactions post-injection. As the 

Agency has acknowledged, despite all the geologic and geochemical data that is 

developed as part of the UIC permitting process, there may be unknown and 

unanticipated geochemical reactions that occur underground post-injection that could 

constitute a “release”4

 under CERCLA, thereby triggering liability. Scenarios that could 

potentially constitute a release under CERCLA include: (1) migration of CO2 from the 

injection zone into another zone or outside the AoR; (2) migration of displaced brine or 

fluids outside the injection zone, (3) geochemical reactions within or outside of the 

injection zone, and (4) atmospheric releases of CO2. Subsurface releases that are 

geologically contained (releases (1) – (3) above), even if they migrate beyond the AoR or 

out of the injection zone, ordinarily will not result in a type of release that threatens the 

ambient environment or presents an imminent and substantial endangerment to human 

health and the environment, unless a USDW is endangered. 

4

 The term “release” is broadly defined to mean “any spilling, leaking, pumping, pouring, 

emitting, emptying, discharging, injecting, escaping, leaching, dumping, or disposing into the 

environment (including the abandonment or discarding of barrels, containers, and other closed 

receptacles containing any hazardous substance or pollutant or contaminant).” 42 U.S.C. § 

9601(22). The term “release” specifically excludes “emissions from engine exhaust of a motor 

vehicle, rolling stock, aircraft, vessel, or pipeline pumping station engine.” Although this 

exemption has not been interpreted by many courts, it does represent Congress’ clear intent to 

exempt CO2 emissions (and other impurities) from vehicles or vessels that might otherwise 

constitute a release under CERCLA. Arguably, it also denotes a qualitative distinction between 

CO2 and other hazardous substances for which Congress saw fit to apply CERCLA. 
Spectra Energy UIC Comments 

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December 18, 2008 

 

 It is important to emphasize that CO2 is itself not a “hazardous substance” under 

CERCLA nor under any other federal environmental law. However, as EPA points out, 

some of the impurities potentially contained in a CO2 stream, such as mercury and 

sulfuric acid, are hazardous substances even though their concentrations, according to 

EPA, are “expected to be very low.” GS Rule at 43503. Thus, the presence and possible 

release of these impurities could give rise to CERCLA liability. 

 Spectra strongly believes that an owner/operator of a GS injection well who 

materially complies with the terms of its UIC permit as a general rule should not be 

subject to CERCLA liability. While there may be limited circumstances, such as a 

catastrophic release of CO2 to the atmosphere,5

 where CERCLA may be appropriate, we 

believe as a general matter CERCLA liability is not necessary and serves as a major 

deterrent to large-scale commercial deployment of GS. Consequently, we believe the 

Agency must seek to establish a “safe harbor” for those engaged in GS operations. Such 

safe harbor must include the CO2 and any impurities by clarifying minimum performance 

standards, employed technologies, or testing requirements, which if used, will exempt 

subsurface releases from CERCLA liability. Toward this end, the Agency has suggested 

that several enumerated defenses under CERCLA, such as the “federally permitted 

release” provision, may provide sufficient safe harbor. However, as discussed below, 

Spectra is concerned that this defense is woefully inadequate. 

B. EPA Must Clarify And Expand The Scope Of The “Federally 

Permitted Release” Defense Which Has Been Seriously Eroded By 

Court Decisions. 

 Section 107(j) of CERCLA provides that any release that occurs pursuant to an 

approved federal permit or program is not subject to CERCLA liability.6

 This provision 

is known as the “federally permitted release” exemption. Among the list of 11 

enumerated federally permitted releases is “any injection of fluids authorized under 

Federal underground injection control programs or State programs submitted for Federal 

approval . . . pursuant to part C of the Safe Drinking Water Act” (hereafter referred to as 

5

 If a catastrophic release of CO2 occurred, it would be the release of CO2 itself, and not 

the minute constituents of other impurities contained in the CO2, that would arguably threaten 

human health and the environment. However, CO2 is not a hazardous substance and therefore 

would not trigger release reporting requirements under CERCLA or the Emergency Planning 

And Community Right-to-Know Act (EPCRA). Another regulatory regime may be more 

appropriate to deal with this potential scenario. 

6

 Section 107(j) says “recovery by any person . . .for response costs or damages resulting 

from a federally permitted release shall be pursuant to existing laws in lieu of this section.” 
Spectra Energy UIC Comments 

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December 18, 2008 

 

the “UIC Exemption”). 42 U.S.C. § 9601(10)(G). Although the EPA cites the federally 

permitted release defense as a way for an owner/operator to avoid liability, this defense 

or statutory exemption has been seriously eroded in recent years by court decisions. See, 

e.g., Carson Harbor Vill, Ltd. v. Unocal Corp., 287 F. Supp. 2d 1118 (C.D. Cal. 2003) 

(court found liability for releases that (1) are not expressly permitted (2) exceed the 

limitations of the permit or (3) occur at a time when there was no permit); State of Idaho 

v. Bunker Hill Company, 635 F.Supp. 665 (D. Idaho 1986) (court held that a federally 

permitted release must be expressly identified in a permit). 7

 

 Given that subsurface plumes from commercial GS operations may encompass 50 

square miles or more (roughly the size of the District of Columbia), this defense provides 

little comfort to an owner/operator of a GS injection facility who could incur tens of 

millions of dollars in response costs under CERCLA. In order for this statutory defense 

to have any meaningful application in the context of GS, and to provide the shield 

Congress intended, EPA must resuscitate this provision by providing further clarification 

of where and how it should apply. There is precedent for the Agency providing 

clarification of the scope and extent of the “federally permitted release” exemption in the 

context of air emissions with respect to reporting requirements for releases. See 

Guidance on the CERCLA Section 101(10)(H) Federally Permitted Release Definition for 

Certain Air Emissions, 67 Fed. Reg. 18899 (April 17, 2002). As EPA acknowledged in 

this guidance, it is difficult to establish a “bright line” for when releases qualify for the 

release exemption. However, we believe the Agency needs to do just that – establish a 

bright line. 

 EPA has the authority and discretion to interpret and further clarify the scope and 

extent of the “federally permitted release” exemption to GS injection. A review of the 11 

enumerated releases under 101(10) reveals dissimilar text, wherein some of the 

exemptions include phrases like “in compliance with,” “subject to,” “identified in,” or 

“authorized under.” The language used for the UIC Exemption, does not specifically 

limit the exemption to compliance with or the terms identified in an enforceable permit; 

rather, the UIC Exemption uses a much broader phrase “authorized under.” Herein, the 

UIC Exemption applies to the (i) injection of fluids (ii) authorized under (iii) federal or 

an approved state UIC program. The EPA Environmental Appeals Board had occasion to 

construe these 11 exemptions and their dissimilar language and reasoned that Congress' 

7 See also Kurt Ryland, Saving A Disappearing Exemption To CERCLA Liability, N.Y.U.

ENV. L.J. (1995). According to the author, federal courts have threatened the utility of the 

exemption through holdings that have weakened the protective shield provided by a permit. The 

author explores these decisions and how they leave many unanswered questions concerning the 

exemption's coverage. 
Spectra Energy UIC Comments 

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December 18, 2008 

use of different phrases must be given due effect. See In re Mobil Oil Corporation, 

EPCRA Appeal No. 94-2, 5 EAD 490, 1994 WL 544260 (EAB, Sept. 29, 1994) 

(construing the meaning of the phrase “subject to” and the statutory purposes of the Clean 

Air Act and CERCLA).8

 Under the plain language of this UIC Exemption, the Agency has the authority to 

define more broadly (whether pursuant to a permit or outside the context of a permit) 

what fluids and releases are authorized by either the federal or state UIC program. This 

issue is significant in that the Agency has stated in the GS Rule: 

“Class VI requirements and permits will need to be carefully 

structured to ensure that they do not ‘authorize’ inappropriate

hazardous releases . . . include clarifying if there are potential 

release from the well which are outside the scope of the Class VI 

permit.” GS Rule at 43504. 

First, it is clear that the Agency believes there are certain releases that are “inappropriate” 

and that, if occur, would give rise to CERCLA liability. This raises many concerns and 

more questions than answers. What releases are deemed outside the scope of the Class 

VI permit? Is any subsurface release not specifically identified in a UIC permit an 

inappropriate release? Is an unanticipated geochemical reaction an inappropriate release 

or outside the scope of the Class VI permit? Is the migration of a CO2 stream out of the 

injection zone or AoR a release whether or not it endangers a USDW? How would an 

appropriate v. inappropriate release be determined? As evidenced from these questions, 

it is critical that the Agency clarify what is meant by the term “inappropriate” hazardous 

release and in what context such releases may be outside the scope of the UIC program. 

 Based on the case law, for an owner/operator to maximize its shield under the 

exemption, all potential releases should be identified and authorized under the permit, 

including appropriate and inappropriate ones. Thus, there is clear tension between EPA’s 

statement that no inappropriate release be authorized by permit and the current state of 

 8

 In the In re Mobil case, the defendant violated its Clean Air Act permit and EPA 

initiated an enforcement action for the defendant’s failure to provide notice of a release under 

EPCRA. Mobil argued that even if its emissions violated any specific permit limit, its emissions 

were subject to the federal permitting release exemption because the emissions were “subject to” 

a state issued implementation plan. Ultimately, the EAB rejected Mobil’s argument after 

concluding that Mobil’s argument would create a gap in the government’s ability to respond 

adequately to air releases of hazardous substances. 
Spectra Energy UIC Comments 

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December 18, 2008 

the law which requires all releases be identified in a permit to benefit from the 

exemption. 

 It is unambiguous from the plain text of the statute that Congress intended that 

releases authorized under the SDWA UIC program not be subject to CERCLA liability. 

It is also clear that the Agency has broad authority to clarify what releases should be 

covered under the GS Rule. Therefore, the Agency need not wait for the issuance of 

permits to decide on a case-by-case basis what is an appropriate or inappropriate release. 

EPA should make clear that all fluids injected pursuant to an authorized program or an 

approved permit will not give rise to CERCLA liability where the release occurs in and 

effects only subsurface formations and is geologically contained. The Agency could 

authorize, for example, the migration of the CO2 stream outside the injection zone or any 

other release that does threaten ambient air. 

 The extension of the UIC Exemption to subsurface or geologically contained 

releases is appropriate in that subsurface releases of CO2 are fundamentally different than 

releases of CO2 to ambient air. Releases of sufficient quantities of CO2 to ambient 

conditions can pose serious health risks and even death. Whereas, the slow movement of 

a CO2 plume in confined subsurface strata ordinarily presents little, if any, imminent or 

substantial risk to human health or the environment. EPA has recognized the distinction 

in the nature and risks of subsurface and ambient releases of CO2. See GS Rule at 43498 

(“geologic confining systems do not experience . . . rapid and complete turnover [of 

CO2]”). Thus, while the application of CERCLA may still be appropriate in the event of 

releases of CO2 to the ambient air, the statute is not necessary to address releases that 

involve only subsurface locations. Unlike the decision in In re Mobil, where the broad 

interpretation of the CERCLA air exemption would leave a gap in the government’s 

ability to respond to a release, in the case of a subsurface release from a GS injection 

well, no such gap would exist, as the Agency has broad authority under SDWA to 

respond appropriately. In addition to civil, criminal and administrative enforcement 

authorities under the UIC program, 42 U.S.C. § 300h-2, and the potential to levy 

substantial monetary penalties, the EPA Administrator has broad emergency powers 

under SDWA to respond to a threat to any source of underground drinking water. 

Specifically, Section 300i says: 

[T]he Administrator, upon receipt of information that a 

contaminant which is present in or is likely to enter a public 

water system or an underground source of drinking water . . . 

which may present an imminent and substantial 

endangerment to the health of persons, and that appropriate 

State and local authorities have not acted to protect the health 

of such persons, may take such actions as he may deem 
Spectra Energy UIC Comments 

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December 18, 2008 

 

necessary in order to protect the health of such persons. 42 

U.S.C. § 300i 

 

Under this emergency authority, the Administrator make take whatever measures 

necessary to protect human health, including ordering any corrective action or 

replacement of drinking water supplies or commencing a civil action for appropriate 

relief, including a restraining order or permanent or temporary injunction. Thus, the 

Agency has adequate authority under SDWA to address any release or contamination that 

presents an endangerment. 

C. RCRA Should Not Apply To GS Or, Alternatively, EPA Must Clarify 

And Minimize The Potential Applicability And Scope Of RCRA. 

 We begin this section by noting that CO2 re-injection from gas processing is 

currently exempt from Subtitle C requirements of RCRA. Therefore, the following 

comments regarding the potential application of RCRA pertains to injection of CO2 from 

non-exempt processes and industries. 

 Under the proposed rule, EPA has stated that it “cannot make a categorical 

determination as to whether injected CO2 is hazardous under RCRA.” See Rule at 43503. 

The Agency goes on to say that if the CO2 stream is considered hazardous under RCRA, 

then the more stringent UIC Class I requirements for injection of hazardous waste apply. 

Consequently, the Agency has defined “carbon dioxide stream” to exclude hazardous 

wastes as defined in 40 C.F.R. Part 261 (e.g., wastes that are characteristically hazardous 

due to pH or toxicity). 

 For many of the same reasons set forth above for CERCLA, Spectra likewise 

believes that RCRA’s waste regulatory regime is completely unnecessary and 

inappropriate for geologic sequestration of CO2. First, CO2 is neither a pollutant, a solid 

waste,9

 nor a hazardous waste. Second, CO2 has been properly and safely injected for 

9

 For a waste to be a hazardous waste, it must first be a solid waste. There is a legitimate 

question whether CO2 is even a solid waste based on the statutory definition of “solid waste” 

expressly including “contained gaseous material.” 42 U.S.C. § 1004(27). EPA has consistently 

interpreted this provision as excluding uncontained gases from the definition of solid waste. See, 

e.g., 47 Fed. Reg. 27530 (June 24, 1982) (gases from fume incinerators not subject to RCRA, 

because fumes are not a solid waste); 54 Fed. Reg. 50973 (Dec. 11, 1989) (uncontainerized gases 

are excluded from RCRA); In re BP Chemicals America, Inc., RCRA Appeal No. 89-4, 1991 

WL 208971, at *2 (Admin., Aug. 20, 1991) (Administrator rejected the argument that otherwise 

uncontained gas passing through piping or the facility made it “contained” and subject to 

RCRA). While CO2 emissions would clearly fit into the “uncontained” gas classification, what 

is unclear is whether the Agency’s interpretation would extend to CO2 subsequently captured and 
Spectra Energy UIC Comments 

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December 18, 2008 

decades in the context of enhanced oil recovery (EoR), without the regulatory overlay of 

Subtitle C of RCRA. Third, there are other regulatory regimes that can apply to CO2

injection that make the application of RCRA unnecessary. 

1. RCRA Hazardous Waste Requirements Would Be Costly And 

Burdensome.

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

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

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

hazardous waste program. 68 Fed. Reg. 61662, 61664 (Oct. 29, 2003). The agency 

noted, “[t]he existing hazardous waste regulations require the submittal of 334 

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

[treatment, storage, and disposal facilities] to demonstrate compliance with the RCRA 

regulations.” Id. at 61664. Reporting requirements are just one example of RCRA’s 

burdens. Others include treatment, storage, and disposal facility requirements generally, 

waste manifesting, training requirements for transporters and handlers, citizen suit 

provisions, and the fact that hazardous waste regulation often increases one’s exposure to 

Superfund liability. 

 While EPA seeks to downplay the potential applicability of RCRA, by opining 

that concentrations of impurities in a CO2 stream are “expected to be very low” there is 

no clear assurance that RCRA does not apply. As currently proposed, the EPA has 

shifted the burden to the owner/operator to determine whether its CO2 stream is not a 

hazardous waste under RCRA. The only way for an owner/operator to determine 

whether its stream is not a hazardous waste is to test the CO2 stream or apply “generator 

knowledge.” To require testing for CO2 streams would be overly burdensome and 

expensive, particularly given the diverse sources of CO2 streams and their varied 

composition. As well, the high variability of CO2 stream composition makes reliance 

upon “generator knowledge” risky if not entirely unworkable. 

2. EPA Has Authority To Exempt CO2 Under Its Contingent 

Management Approach.

 The Agency has authority under Subtitle C of RCRA to determine which wastes 

are subject to federal hazardous waste regulations. Section 3001 directs the 

Administrator of EPA to 

 

injected into an underground formation. We believe this merits further clarification by the 

Agency on what constitutes an uncontained vs. contained gas. 
Spectra Energy UIC Comments 

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December 18, 2008 

develop and promulgate criteria for identifying the 

characteristics of hazardous waste, and for listing hazardous 

waste, which should be subject to the provisions of this 

subchapter, taking into account toxicity, persistence, and 

degradability in nature, potential for accumulation in tissue, 

and other related factors such as flammability, corrosiveness, 

and other hazardous characteristics. Such criteria shall be 

revised from time to time as may be appropriate. 42 U.S.C. § 

6921(a). 

It is clear from the language of Section 3001, that Congress left to the EPA the discretion 

to determine which hazardous wastes would be subject to federal regulations and which 

ones would be exempt therefrom. See Military Toxics Project v. EPA, 146 F.3d 948, 958 

(D.C. Cir. 1998) (“Congress’ broad delegation to EPA to develop criteria for listing 

hazardous wastes . . . indicates that Congress intended the agency to have substantial 

room to exercise its expertise”). The criteria set forth above enable EPA to take into 

consideration the relative risks posed by different wastes (i.e., some wastes are by nature 

more toxic than others), the capacity for a waste to breakdown and thus become less toxic 

in the environment (i.e., some wastes degrade faster than others), how long it takes a 

waste to degrade, and the potential for human exposure and accumulation in tissue. The 

application of these criteria to CO2 weigh in the favor of exempting CO2 injection and 

disposal from hazardous waste regulations. 

 EPA considers the risk of chronic and acute health effects from airborne exposure 

from properly operated CO2 injection as minimal. GS Rule at 43498. It likewise 

considers the risk of adverse impacts to ecosystems from properly managed GS injection 

activities as minimal. Id. Overall, the Agency believes that the risks to human health and 

the environmental from properly managed CO2 injection activities are minimal. These 

risks EPA believes will be properly addressed and managed through the new Class VI 

UIC well program. 

 Given the minimal risks from properly managed CO2 pursuant to SDWA’s 

authority, EPA should exempt CO2 streams entirely from RCRA hazardous waste 

regulations or, alternatively, establish a “safe harbor” for the injection of CO2, including 

impurities, by clarifying minimum performance standards or testing requirements. The 

concept of a blanket exemption is fully consistent with the Agency’s “contingent 

management” approach under RCRA, whereby certain low-risk wastes are exempted 

entirely from RCRA Subtitle C regulations. See EPA’s Contingent Management 

Technical Background Document, October 29, 1999. According to the Agency, 
Spectra Energy UIC Comments 

Page 25 

December 18, 2008 

EPA's longstanding regulatory criteria for determining 

whether wastes pose hazards that require regulatory control 

incorporate the idea that a waste that is otherwise hazardous 

may not present a hazard if already subject to adequate 

regulation. See, e.g., 40 CFR 261.11(a)(3)(x), which requires 

EPA to consider action taken by other governmental agencies 

or regulatory programs based on the health or environmental 

hazard posed by the waste.) Thus, where a waste might pose a 

hazard only under limited management scenarios, and other 

regulatory programs already address such scenarios, EPA is 

not required to classify a waste as hazardous waste subject to 

regulation under Subtitle C. 62 Fed. Reg. 6622, 6636 (Feb. 

12, 1997). 

The D.C. Circuit Court of Appeals has upheld EPA’s contingent management approach 

on at least three occasions. Edison Electric Institute v. EPA, 2 F.3d 438 (D.C. Cir. 1993) 

(court upheld a temporary exemption from Subtitle C for petroleum-contaminated media 

based on the fact that the potential hazards of such materials are already controlled under 

the underground storage tank regulations); NRDC v. EPA, 25 F.3d 1063 (D.C. Cir. 1994) 

(court upheld EPA's finding that alternative management standards for used oil 

promulgated under RCRA section 3014 reduced the risks of mismanagement and 

eliminated the need to list as a hazardous waste); Military Toxics Project v. EPA, 146 

F.3d 948, 958 (D.C. Cir. 1998) (court upheld EPA’s military munitions rule as obviating 

the need to apply RCRA’s hazardous waste regulations). 

 As EPA has emphasized before, even the legislative history of Subtitle C supports 

the Agency’s contingent management concept. In a House Report, Congress stated that 

“the basic thrust of this hazardous waste title is to identify what wastes are hazardous in 

what quantities, qualities, and concentrations, and the methods of disposal which may 

make such wastes hazardous." 62 Fed. Reg. 6622, 6636 (citing H. Rep. No. 94-1491, 

94th Cong., 2d Sess.6 (1976), reprinted in A Legislative History of the Solid Waste 

Disposal Act, as Amended, Congressional Research Service, Vol.1, 567 (1991)). 

3. CO2 Geologic Sequestration Should Be Subject To Bevill 

Exemptions.

 Further argument for a RCRA exemption, and consistent with the concept of 

contingent management, is the fact that Congress exempted certain wastes from 

regulation under Subtitle C of RCRA. In 1980, when Congress amended the Solid Waste 

Management Act, it opted to temporarily exempt certain high-volume low toxicity wastes 

from the Subtitle C hazardous waste regulatory scheme, including, among others, “fly ash 
Spectra Energy UIC Comments 

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December 18, 2008 

waste, bottom ash waste, slag waste and flue gas emission control waste generated 

primarily from the combustion of coal or other fossil fuels” (hereafter referred to as 

“FFC” wastes) 42 U.S.C. § 6921(b)(3)(A)(i) (emphasis added). This amendment (a/k/a 

the Bevill Amendment), was prompted in large measure by Congress’ concern regarding 

the potential added recycling costs (estimated at $3B annual increase) of subjecting 

fossil-fuel combustion wastes to hazardous waste requirements. 58 Fed. Reg. 42466, 

42468 (Aug. 9, 1993). Under the Bevill Amendment, Congress directed EPA to make a 

regulatory determination on whether or not FFC needed to be regulated under Subtitle C. 

 As part of the Agency’s regulatory determination, EPA conducted a three-part 

technical analysis evaluating whether (1) the FFC wastes posed human health or 

environmental problems, (2) whether the wastes could pose significant risks at any site 

under current or plausible management scenarios, and (3) whether the wastes exhibited 

any of the characteristics of hazardous waste. EPA’s rationale for the iterative analysis 

was to determine, first, whether the wastes posed serious risks, second, whether current 

management practices and federal and state regulatory controls were adequate to manage 

the risks and, third, the economic impact on the industry before regulating the waste as 

hazardous. EPA identified a number of sites with unlined lagoons and ponds where FFC 

wastes clearly had resulted in extensive ground water impacts from arsenic, barium, 

cadmium, chromium, fluoride, lead, mercury, nickel and selenium that had leached into 

the water. Id. at 42475. EPA concluded, however, that such sites were ordinarily not 

located near populations and drinking water systems. EPA also concluded that up to 7% 

of the FFC wastes exhibited the characteristics of hazardous waste based on toxicity. 

Despite these negative findings, EPA ultimately made the determination that more 

stringent regulations were not necessary or desirable. 

 Based on a plain language reading of the Bevill Amendment, it appears that CO2 

falls within the scope of the exemption as a flue gas emission control waste. Similar to 

FFC wastes, CO2 are a high-volume low toxicity waste when properly managed in 

underground formations. Therefore, we believe the Bevill Amendment presents the 

Agency with another viable option for exempting CO2 from Subtitle C. 

D. EPA Should Create A Subclass Of Class II Or Class VI UIC Wells For 

Sour CO2 Injection Operations Irrespective Of Whether Such Gas Is 

From Hydrocarbon Production. 

Raw natural gas often contains significant impurities such as CO2, H2S, and N2. 

Sour CO2 is also generated as a by-product from the gas sweetening process used to 

produce natural gas suitable for transmission and sale. The composition of the sour CO2 

mixture is highly variable based on geological conditions, the composition of the raw 

natural gas, and the processing technology. Raw gas that is naturally higher in H2S 
Spectra Energy UIC Comments 

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results in higher concentrations of H2S as a percentage composition of the sour CO2. 

Although, in Western Canada, CO2 often accounts for most of the sour CO2 composition 

(i.e., as much as 80%), at some facilities, such as our Kwoen plant, the CO2 composition 

of the gas waste is only around 20%. 

 Historically, most of the waste gases from natural gas processing were disposed of 

by flaring, but more recently, great strides have been made toward injecting the gas 

wastes into deep geologic formations. Thus, the injection and long-term storage of sour 

CO2 is an appropriate analog to CO2 geological sequestration. Sour CO2 disposal is not 

only an integral part of natural gas production, but the management and disposal of such 

gases will be an integral part of making GS technologies viable as well. The IPCC noted 

that it will be important to reduce the acidic gas components of flue gas from coal-fired 

power plants before CO2 removal, because the acidic gas reduces the absorption capacity 

of the solvent used to remove CO2. Thus, power plants that seek to employ GS 

technologies will be required to eliminate and dispose of these gases along with the CO2. 

It is unclear whether or not the acidic qualities of flue gases would constitute a 

characteristic hazardous waste based on low pH or toxicity. Notwithstanding, UIC 

injection requirements that govern CO2 disposal must govern acidic gases of all kinds as 

part-and-parcel to the GS Rule. These requirements must be flexible and workable, 

similar to those of Class II requirements. 

 Despite the potentially hazardous characteristics of sour CO2, Section 

3001(b)(2)(A) of RCRA currently exempts sour CO2 from Subtitle C hazardous waste 

regulations provided the gas is related to oil or natural gas exploration or production and 

processing.10 Although not regulated under RCRA, sour gas injection for purposes of 

disposal is regulated under the UIC Class II well program. EPA has raised some concern 

regarding the toxicity and potential safety of sour CO2 in the context of the UIC 

program.

11 However, the management and injection of such gases has been performed 

safely over the last two decades. And, in fact, the IPCC has equated the health, safety 

and environmental risks of sour CO2 disposal with that of GS operations, if properly 

10 See U.S. EPA, Regulatory Determination for Oil and Gas Geothermal, Development 

and Production Wastes, 53 Fed. Reg. 254476, 25454 (July 6, 1988). EPA made the regulatory 

determination in 1988 to exempt sour CO2 from hazardous waste requirements. Presumably, 

sour CO2 would be subject to RCRA’s hazardous waste requirements if they were not generated 

during oil and gas production. 

11 See Vulnerability Evaluation Framework for Geologic Sequestration of Carbon 

Dioxide, U.S. EPA Technical Support Document, Report No. EPA430-R-08-009, July 10, 2008. 
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managed.12 The history and strong safety record of sour CO2 operations in North 

America provides a compelling argument to exempt CO2 injection from other nonexempt sources and activities. 

 In the U.S., the management and disposal of sour CO2 has largely been 

implemented at the state level pursuant to both federal UIC and state underground 

injection laws. Some states like Wyoming regulate sour CO2 injection solely pursuant to 

the UIC Class II requirements. Whereas, other states, such as Texas, overlay the UIC 

program requirements with additional state law requirements. For example, Texas law 

governs injection where the H2S content is at least 100 parts per million. See 16 TEX.

ADMIN. CODE § 3.36(a)(2)(C) (2008). In addition to the baseline UIC Class II 

requirements, operators are required to assess the potential impact of releases by 

determining a “radius of exposure” based on concentrations of 100 ppm and 500 ppm. 

They are also required to post warning signs in public areas, provide wellhead security, 

and use corrosion-resistant materials. Contingency planning to prepare for and respond 

to potentially dangerous releases is major component of sour gas injection operations. 

 Canada has far more experience with sour CO2 disposal than the U.S. As noted 

earlier, in Western Canada, as of 2007, there were 44 sour CO2 injection projects 

operational, injecting into 51 different formations. A total of 27 of these operations inject 

sour CO2 into deep saline formations, while 19 sites inject into depleted oil and gas 

reservoirs, and the remaining sites inject into the water leg of depleted oil and gas 

reservoirs. See Carbon Dioxide Capture and Storage, IPCC, Annex I, Properties of CO2 

and Carbon-Based Fuels, November 2005. Carbonates form the reservoir at 29 sites and 

quartz-rich sandstone at 21 sites. The overlying unit in most formations is shale, and the 

others consist of tight limestone, evaporites, and anhydrites. Since the early 1990s, when 

injection first commenced, 2.5 Mt of CO2 and 2.0 Mt of H2S have been safely injected 

without any detectable leaks. 

 Similar to the U.S., Alberta has a program to regulate activities related to the 

injection and disposal of fluids, although there are differences between the two programs. 

The Energy Resources Conservation Board (ERCB), an independent quasi-judicial 

agency of the Government of Alberta, is responsible for regulating Alberta’s energy 

12 According to the IPCC, “[w]ith appropriate site selection based on available subsurface 

information, a monitoring program to detect problems, a regulatory system, and the appropriate 

use of remediation methods to stop or control CO2 releases if they arise, the local health, safety 

and environment risks of geologic storage would be comparable to risks of current activities such 

as natural gas storage, [enhanced oil recovery], and deep underground disposal of acid gas.” 

IPCC 2005. 
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resources (oil, natural gas, oil sands, coal) and pipelines, as well as approving 

applications for oil and gas operations including underground injection.13 

 The ERCB is responsible for reviewing and approving all injection wells 

consistent with specific technical requirements pertaining to cementing and casing, 

logging to evaluate hydraulic isolation and casing integrity, and other testing for initial 

pressure, monitoring, area of review, and operating parameters. The ERCB has the 

authority to require a well to be abandoned where the location or condition of that well 

may become a source of water pollution. Alberta’s philosophy for deepwell disposal of 

oilfield and industrial wastes is a safe and viable disposal option where wells are properly 

constructed, operated, and monitored. Regulatory activities for sour gas focus on the 

following: 

● wellbore integrity to ensure initial and ongoing containment of the disposal 

fluid to protect groundwater; 

● formation suitability and hydraulic containment to ensure initial and ongoing 

confinement of the disposal fluid to protect groundwater; 

● suitability of the waste stream for deepwell disposal considering the nature of 

the fluid, the integrity of the well, and alternative waste management options; 

● maximum H2S fraction, maximum wellhead injection pressure, and rate and 

maximum injection volume; and 

● reporting and manifesting of disposed wastes. 

 

In addition, operators of sour gas processing facilities must submit monthly reports which 

provide detailed information regarding the nature of the operations, including the amount 

and quality of the sour CO2 injection. 

 Sour CO2 disposal, storage or cycling operations in Alberta are regulated as a 

Class III well (different than UIC Class III), which under Alberta’s laws are wells 

primarily used for the injection of hydrocarbons or inert or other gases. On balance, the 

injection of sour CO2 is regulated no differently than hydrocarbons. Similar to the U.S., 

13 See Injection and Disposal Wells, Well Classifications, Completions, Logging and 

Testing Requirements, ERCB, March 1994. Available at http://www.ercb.ca/docs/ 

Documents/directives/Directive051.pdf. 
Spectra Energy UIC Comments 

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sour CO2 disposal is not managed as a hazardous waste, which is regulated under 

Alberta’s Class Ia well requirements that are the most stringent. 

 Under Alberta’s regulations, matters of fluid-fluid, fluid-equipment, and fluidformation compatibility are left primarily to the disposal well operator, with provincial 

regulators relying on operating and monitoring requirements to provide for early 

detection and mitigation of potential problems. Alberta prohibits the subsurface injection 

of numerous wastes, including municipal or industrial sewage, lube oils, spent solvents, 

diesel invert drilling fluids, and surface run-off water that meets surface discharge criteria 

(some of these prohibited because they are treated as recyclable). All other waste fluids, 

including sour CO2, are suitable for deepwell disposal if they have a pH between 4.5 and 

12.5. 

 Based on the collective experience of U.S. and Canadian operators involving the 

safe disposal of many metric tons of sour CO2 over the last two decades, EPA should 

consider developing a subclass of wells under Class II or Class IV for the injection of 

sour CO2. There is simply no compelling basis for the EPA to regulate any acidic gases 

as hazardous waste under the burdensome Class I requirements. 
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IV. EPA MUST DEVELOP A FLEXIBLE FRAMEWORK TO ADDRESS 

POST-INJECTION SITE CARE, FINANCIAL ASSURANCE, AND LONG 

TERM LIABILITY THAT ELIMINATES OBSTACLES TO 

COMMERCIAL-SCALE DEPLOYMENT OF CCS. 

 Numerous studies and commentators have recognized that the principle obstacle to 

commercial-scale deployment of CCS is regulatory uncertainty over the capture, 

transport, injection, and storage of CO2. As stated by a recent GAO report: 

The IPCC, two federal advisory committee reports, and many stakeholders 

we contacted agreed that key regulatory and legal issues will need to be 

addressed if CCS is to be deployed at commercial scale. Among these 

issues are (1) confusion over the rules for injecting large volumes of CO2, 

(2) long-term liability issues concerning CO2 storage and potential leakage, 

(3) how property ownership patterns may affect CO2 storage, and (4) how 

the Clean Air Act will apply to facilities that capture CO2. ... EPA’s 2007 

UIC workshop, attended by more than 200 stakeholders, revealed liability 

associated with unintended migration of injected CO2 to be a critical 

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

liability related to CO2 storage was a large or very large barrier to 

deployment of CCS at a commercial scale, with some noting that liability 

concerns have already negatively impacted companies’ ability to initiate 

CCS projects. For example, two stakeholders reported that these concerns 

had already made it difficult to obtain insurance for CCS projects. They 

noted specifically that insurers have difficulty writing insurance policies 

because of uncertainties associated with and limited data available for CCS, 

while another added that investors will not support projects like CCS if they 

expose them to unlimited and undefined long-term liabilities, especially 

when future revenue streams are uncertain.14

14 GAO Report, Climate Change, Federal Actions Will Greatly Affect the Viability of 

Carbon Capture and Storage As a Key Mitigation Option, Report to the Chairman on the Select 

Committee on Energy Independence and Global Warming, House of Representatives, GAO-08-

1080, September 2008, at 23, 25. See also Capturing King Coal: Deploying Carbon Capture and 

Storage Systems in the US at Scale, WORLD RESOURCES INSTITUTE (2008) at 24 (“In the event of 

an accident or damage years after the well is closed, who is financially and legally responsible? 

Current law and policy is unclear on this matter, and more generally on the matter of 

responsibility for long-term measuring and monitoring of the site. In particular, the degree to 

which private parties remain responsible, or the government assumes a measure of responsibility, 

is important.”). 
Spectra Energy UIC Comments 

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December 18, 2008 

 The promise of CCS as a strategy to address climate change and promote national 

energy security hinges on resolving this regulatory uncertainty in a way that does not 

place an unreasonable burden on site owners and operators that would effectively prevent 

the development of commercial-scale CCS projects in the United States. The EPA has 

the authority under SDWA and the UIC Program to create a flexible framework to 

address issues such as post-injection site care, financial assurance, and long-term liability 

in a manner that places enough responsibility on owners and operators to ensure that all 

applicable best practices are followed, but not so much that it becomes virtually 

impossible to secure the requisite financing and insurance needed for CCS projects to be 

commercially viable. 

 The potentially unique challenge of resolving the regulatory uncertainty currently 

inhibiting the development of CCS projects, if done with inadequate attention to existing 

market dynamics and economic realities, likely will preclude any commercial-scale 

deployment of CCS and undermine its effectiveness as a strategy to reduce greenhouse 

gas emissions. Addressing the regulatory uncertainty surrounding post-injection site 

care, financial assurance, and long-term liability effectively boils down to four 

overarching questions confronting entities involved in the capture, transport, injection, 

and storage of CO2: (1) length of the post-injection site care time period; (2) aspects of 

post-injection site care for which entities will be responsible; (3) availability and 

suitability of different risk management instruments for meeting financial assurance 

requirements; and (4) permanent transfer of all liability to the State. Spectra’s comments 

on post-injection site care, financial assurance, and long-term liability focus broadly on 

these issues. 

A. The Director Should Have the Discretion To Shorten The PostInjection Site Care Period, But Not Extend It. 

 EPA is proposing a post-injection site care period of 50 years. The Director would 

have discretion to extend this period if after 50 years USDWs still face potential 

endangerment or modeling and monitoring results demonstrate that the CO2 plume and 

pressure front have not yet stabilized. The Director also could reduce this period if data 

on pressure, fluid movement, mineralization, and/or dissolution reactions indicate that the 

plume and pressure front have ceased and the injectate does not pose a risk to USDWs. 

EPA requested comment on the proposed use of a tentative 50-year fixed timeframe that 

could be modified at the Director’s discretion based on monitoring and modeling data. 

 Spectra supports EPA’s approach granting the Director discretion to adjust the 

timeframe based on the risk posed to USDWs. This approach takes into account the sitespecific nature of CCS projects and recognizes the importance of creating a rule that does 

not place unnecessary regulatory, financial, or technical burdens on site owners and 
Spectra Energy UIC Comments 

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December 18, 2008 

operators. However, Spectra proposes limiting Director discretion to the ability to 

shorten the post-injection site care period, upon meeting certain performance-based 

criteria that indicate the CO2 plume has stabilized and poses no recognizable risk to 

USDWs. This creates an incentive for project operators to adhere to best practices and 

could potentially encourage CCS project development. 

 Spectra respectfully disagrees with granting the Director the discretion to extend

the post-injection site care period beyond the fixed, pre-determined time period, on 

grounds that this places an unreasonable and potentially prohibitive financial risk on site 

operators. Specifically, owners or operators whose post-injection site care period is 

extended may be unable to secure additional financial assurance to cover the additional 

period of time. EPA cannot assume that owners or operators would be able to renew or 

extend the risk management instrument it procured prior to commencing injection and 

storage operations, nor can it assume that an owner or operator would be able to secure a 

new risk management instrument in the market. The possibility of an extension creates a 

risk for owners or operators that they may have to finance post-injection site care well 

beyond the default period, which would increase project costs and potentially inhibit CCS 

project development altogether. Furthermore, the extension of a post-injection site care 

period for an owner or operator that is no longer solvent exposes the public to 

unnecessary risk and would require governmental intervention. Rather than the 

possibility of an extension at the Director’s discretion, Spectra believes that a fixed postinjection site care period with the possibility of it being shortened upon meeting certain 

performance criteria that are evaluated on a site-by-site basis creates an incentive for 

operators to adhere to best practices and removes what would be a major deterrent from 

CCS project development. Spectra further believes that EPA should develop such 

performance criteria as soon as possible and in a manner that provides a realistic 

possibility that sites with stabilized CO2 plumes would qualify for a shorter post-injection 

site care period. 

B. EPA’s Selection Of A 50-Year Post-Injection Site Care Period Is 

Arbitrary. 

 

 Spectra respectfully disagrees with EPA’s selection of a 50-year default 

timeframe. As an alternative, Spectra recommends that EPA adopt a post-injection site 

care period of 30 years, similar to that used under RCRA for post-closure care for 

hazardous waste management units, 40 C.F.R. § 264.117, after which time all 

responsibility and liability would transfer to the State. The Director should be granted 

discretion to shorten this timeframe upon a showing that certain performance criteria are 
Spectra Energy UIC Comments 

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met that indicate USDWs are not at any recognizable risk, as discussed more fully 

above.15 

 A 30-year timeframe with Director discretion to shorten represents a better 

approach because it provides greater regulatory certainty for owners and operators, 

financiers, insurers, and other entities involved in CCS projects.16 By contrast, a 50-year 

period that could be extended or reduced depending upon periodic assessments of the 

CO2 plume creates significant uncertainty, subjecting owners and operators to a postinjection site care period that either could end at any time after approximately 10 years or 

continue indefinitely up to and beyond 100 years. In practice, it is far easier for owners 

and operators to plan for a 10-year period with the possibility of an extension than a 50-

year period that could fluctuate in either direction at the Agency’s discretion, as discussed 

more fully above. 

 Furthermore, with respect to USDW endangerment, projects with plumes likely to 

stabilize within 10 years represent the safest types of projects. A 50-year post-injection 

site care period would place an undue regulatory and financial burden on these safest of 

projects. Even with Director discretion to shorten this time period, owners and operators 

nevertheless would have to plan for a post-injection site care period of at least 50 years, 

significantly affecting the prospective costs of the project. By comparison, a 30-year 

timeframe with Director discretion to shorten would seem to favor the development of 

projects likely to have CO2 plumes that stabilize early and avoid an unnecessarily long 

post-injection site care period. Similarly, the potential of reduced regulatory and 

financial burdens that would accompany a 30-year period with Director discretion to 

shorten creates incentives for project owners and operators to develop and manage 

projects in a way that maximizes the likelihood of the CO2 plume stabilizing early. 

 For the foregoing reasons, the EPA’s 50-year post-injection site care period is 

arbitrary and risks adding to the barriers and obstacles that are currently preventing 

commercial-scale deployment of CCS. A 30-year period with Director discretion to 

shorten would provide the same level of protection for USDWs while minimizing 

regulatory and financial burdens on site owners and operators. 

15 Modeling results indicate that a CO2 plume will stabilize within 10 to 100 years after 

the cessation of injection. See Computational Modeling of Underground Injection of Carbon 

Dioxide for Determine of Are-of-Review and Potential Risk to Underground Sources of Drinking 

Water, U.S. EPA (2008). 
Spectra Energy UIC Comments 

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December 18, 2008 

C. After The Post-Injection Site Care Period And Determination That 

The CO2 Plume Has Stabilized, Owners And Operators Should Be 

Released From All Site Care Responsibility, Such As Monitoring And 

Verification Requirements, And Any Financial Assurance Instruments 

Should Be Released. 

 The GS Rule provides that owners or operators must demonstrate and maintain 

financial responsibility for certain corrective actions described in 40 C.F.R. § 146.84 of 

the Rule. The GS Rule releases owners and operators from financial responsibility 

requirements at the conclusion of the post-injection site care period once the Director has 

determined that the injected fluid no longer poses a threat of endangerment to USDWs. 

 Spectra supports EPA’s approach to releasing owners and operators from any 

further financial responsibility requirement at the conclusion of the post-injection site 

care period and upon a determination by the Director that the CO2 plume poses no further 

risk to USDWs. Establishing firm and discrete limits for post-injection obligations on 

behalf of owners and operators is essential to the viability of commercial-scale CCS. 

Open-ended requirements that could continue indefinitely, even after a showing that the 

CO2 plume has stabilized, would impose an unreasonable burden and likely inhibit 

project development. 

 Spectra also proposes that owners and operators be released from any monitoring 

or verification requirements at the conclusion of the post-injection site-care period and 

upon a showing that the CO2 plume has stabilized. This approach would have the effect 

of dovetailing the responsibilities of owners and operators in the post-injection site care 

period with the transfer of long-term liability to the State. As discussed more fully below, 

Spectra believes that the eventual transfer of long-term liability to the State should 

encompass all potential liability — both anticipated site care responsibilities, such as 

monitoring and verification requirements, as well as any unanticipated migration of the 

CO2 plume and potential endangerment of USDWs. 

D. After The Post-Injection Site Care Period And Determination That 

The CO2 Plume Has Stabilized, Owners And Operators Should Not Be 

Liable For Unanticipated Migration Of CO2 Plume And Any Potential 

Endangerment Of USDWs Or Other Environmental Impacts. 

 The successful completion of the post-injection site care period and a showing that 

the CO2 plume has stabilized and poses no further risk to USDWs should mark the end of 

any and all liability for owners and operators, absent a showing of gross negligence, 

willful misconduct, or a violation of one or more applicable federal laws. Such an 

approach would provide clarity and certainty to owners and operators with respect to 
Spectra Energy UIC Comments 

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December 18, 2008 

 

liability exposure, as well as to investors, lenders, insurers, and others. Given the 

multiple benefits conferred to the public by the successful capture, transport, injection 

and underground storage of CO2, the end of the post-injection site care period represents 

a fair and reasonable point to demarcate the end of private liability and the beginning of 

State responsibility, even in cases of unanticipated migration of the CO2 plume. And such 

an approach is fully consistent with the Interstate Oil and Gas Compact Commission’s 

(IOGCC) position, as discussed below.17 Placing a strict limit on owner/operator liability 

also offers among the best available incentives for owners and operators to adhere to best 

practices in managing the project. 

 This type of limit on liability is of critical importance, since commercial viability 

of CCS depends on the ability of owners and operators to transfer any and all long-term 

liability, either by contract to another party, or to the State upon completion of the postinjection site care period and a showing that the CO2 plume has stabilized. The World 

Resources Institute has recognized the importance of the ability to transfer long-term 

liability, stating that “[i]t is unlikely that any commercial operation would agree to 

assume responsibilities indefinitely.”18 The GAO report also noted that “[s]takeholders 

told us that they were concerned by the unspecified period of time for which they may be 

liable for stored CO2.”19

 Where owners and operators face uncertainty as to the limits of their liability, or if 

these limits are not reasonable, then prospective investors and lenders will lack any 

assurance of a return on their investment and the financing essential to commercial-scale 

deployment will not materialize. Furthermore, private insurers will similarly be deterred 

in the face of uncertain or unreasonable liability from providing sufficient insurance 

coverage. 

17 See CO2 Storage: A Legal and Regulatory Guide for States, INTERSTATE OIL & GAS 

COMPACT COMMISSION (December 2007). 

18 See also Capturing King Coal: Deploying Carbon Capture and Storage Systems in the 

US at Scale, WORLD RESOURCES INSTITUTE (2008) at 24. 

19 GAO Report, Climate Change, Federal Actions Will Greatly Affect the Viability of 

Carbon Capture and Storage As a Key Mitigation Option, REPORT TO THE CHAIRMAN ON THE 

SELECT COMMITTEE ON ENERGY INDEPENDENCE AND GLOBAL WARMING, HOUSE OF 

REPRESENTATIVES, GAO-08-1080 (September 2008) at 39. 
Spectra Energy UIC Comments 

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December 18, 2008 

 

 A useful approach to limiting liability for activities that provide valuable public 

benefits is the Oil Pollution Act (OPA) of 1990.20 Under the OPA, a responsible party’s 

liability is limited except in cases of gross negligence or willful misconduct or where 

there are violations of applicable federal laws. Where the costs or damages arising from 

an accident exceed the applicable liability limit, responsible parties may seek 

compensation from the Oil Spill Liability Trust Fund (OSLTF). 

 The OPA establishes liability limits for permit holders or pipeline right of way 

holders, vessel owners, and owners or operators of onshore facilities, offshore facilities, 

and deepwater ports. When a party pays or incurs costs or damages in excess of an 

applicable liability limit, the responsible party may present a claim to the OSLTF for 

compensation. The Fund will compensate parties for any one oil pollution incident up to 

$1 billion or the balance of the Fund, whichever is less. Natural resource damage 

assessments and claims in connection with any one incident are limited to $500 million of 

the $1 billion per incident limit. The OSLTF is funded by an oil tax, interest on fund 

principal, cost recovery from responsible parties, and penalties (which include civil 

penalties assessed to the responsible party). The OSLTF also can borrow from the U.S. 

Treasury to cover potential shortfalls. 

 A concept similar to the OSLTF for geologic storage of CO2 has been proposed 

by, among others, the IOGCC Task Force.21 Specifically, the IOGCC has proposed a 

multi-state Carbon Mutual Account that would cover damages or remediation costs that 

exceed what is already covered by private insurers. This “trust” would be funded by 

industry and administered by the States and could draw upon a variety of funding 

mechanisms, including pooled contributions by multiple projects, royalty revenues from 

coal, wire charges or carbon levy applied to regulated transmission entities, carbon 

credits from verified carbon emission reductions, tax rebates from property taxes paid by 

storage projects, or an extension fee applied to rates approved by state public service 

commission and charged by the storage facility and/or coal-burning power plant. 

 Other regulatory models have been suggested as a way to manage long-term 

liability associated with CCS, including the Price-Anderson Nuclear Industries Indemnity 

Act and the National Flood Insurance Act of 1968, both of which appear to be poor fits 

20 33 U.S.C. 2701 et seq. The OPA generally consolidated the liability and compensation 

provisions of the Trans-Alaska Pipeline Authorization Act (TAPPA) of 1973. For an additional 

discussion of OPA as a suitable model for managing CCS long-term liability, see Approaches To 

Geologic Sequestration Site Stewardship After Site Closure, U.S. EPA (July 2008). 

21 See CO2 Storage: A Legal and Regulatory Guide for States, INTERSTATE OIL & GAS 

COMPACT COMMISSION (December 2007). 
Spectra Energy UIC Comments 

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December 18, 2008 

 

for CCS and raise numerous concerns.22 Based on the collective experience using these 

other regulatory constructs, it is important to underscore the significance of creating 

certainty with respect to liability transfers to the State. 

 Given the clear advantages of placing strict limits on owner/operator liability and 

covering the balance of any further damages or remediation costs with a trust fund-type 

of approach, Spectra recommends that the EPA Office of General Counsel analyze the 

legal issues arising from the creation of a state-administered fund as discussed above, 

including in particular whether EPA believes it has the authority to do so under existing 

law. If EPA concludes it does not have the authority, then it should communicate to 

Congress so that it may act if so desired. 

E. SDWA Does Not Preclude EPA From Establishing A Framework That 

Allows The Transfer Of Long-Term Liability. 

 In the GS Rule, EPA has taken the position that “SDWA does not provide EPA 

with the authority to transfer liability from one entity to another.” GS Rule at 43522. 

Contrary to EPA’s position, Spectra believes that allowing the transfer of liability does 

not violate SDWA. Specifically, Spectra believes that EPA can proceed in the GS Rule to 

allow the full and complete transfer of liability from one entity to another without 

running afoul of SDWA on grounds that there is no express prohibition in SDWA. 

 Recently, EPA has said that SDWA does not “explicitly provide EPA the authority 

to transfer liability from the owner/operator to another entity.”23 In addition, current UIC 

regulations allow the transfer of permits to new owners or operators, although EPA has 

taken the position that trust responsibilities to the owner are in perpetuity. We 

respectfully request further clarification from the Agency as to why it believes that 

SDWA precludes the transfer of liability. 

22 See generally Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for 

Liability Risk Management, Financial Responsibility, BNA DAILY ENVIRONMENT REPORT (Sept. 

3, 2008). 

23 Approaches To Geologic Sequestration Site Stewardship After Site Closure, U.S. EPA

(July 2008). 
Spectra Energy UIC Comments 

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V. EPA MUST PROVIDE FLEXIBILITY IN DEMONSTRATING 

FINANCIAL ASSURANCE. 

 In its July 2008 paper Approaches to Geologic Sequestration Site Stewardship 

After Site Closure, EPA stated that the purpose of financial assurance is “to minimize the 

number of facilities that are orphaned and abandoned; thereby, reducing the potential that 

these costs will be borne by the public.”24 With respect to the injection and storage of 

CO2, abandoned or orphaned sites would place the public and surrounding environment 

at risk and potentially undermine the primary purpose of CCS — to reduce emissions of 

CO2. Financial assurance requirements are justified to ensure projects operate in 

accordance with applicable best practices and appropriate steps are taken to minimize 

risks in the post-closure period. 

 EPA notes repeatedly in the GS Rule that the risks of geologic storage of CO2

decrease substantially over time. However, no private market to manage the risks 

associated with CCS during a virtually indefinite post-closure time period exists or is 

likely to exist in the future.25 As a result, ensuring the commercial-scale deployment will 

depend on the eventual transfer of any and all risk to the State. Given the promise of CCS 

as a key tool to address global climate change and to promote domestic energy security, 

shifting long-term risk to the State is justified and, in certain respects, highly desirable 

given potential public benefits CCS could deliver. 

 In apportioning the risk, it is clear that owners and operators of CCS projects 

should bear responsibility for harms and risks of harms caused during the period an 

injection site is operating, and for a reasonable closure period afterwards, e.g., 30 years 

with Director discretion to shorten, as discussed more fully above. Among other things, 

this approach encourages the development and implementation of best practices. 

 Accordingly, Spectra supports EPA’s approach to releasing owners and operators 

from any further financial assurance requirement at the conclusion of the post-injection 

site care period and upon a determination by the Director that the CO2 plume poses no 

further risk to USDWs. With respect to specific aspects of financial assurance 

requirements, Spectra offers the following additional comments. 

24 Id., n.2. 

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

Management, Financial Responsibility, BNA DAILY ENVIRONMENT REPORT at 9 (Sept. 3, 2008) 

(“Because CCS is what the financial services sector would call a specialty risk, only a small part 

of the sector would be equipped and qualified to analyze the risks and place capital thereon.”). 
Spectra Energy UIC Comments 

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December 18, 2008 

A. EPA’s Requirement To Include A ‘General Duty’ To Obtain Financial 

Responsibility Is Reasonable. 

 Spectra believes that the “general duty” in the GS Rule to obtain financial 

assurance is reasonable. However, Spectra further believes that EPA should seek to 

provide detailed guidance describing recommended types of risk management 

instruments that would satisfy this requirement as soon as possible. A lengthy delay in 

clarifying what is meant by a “general duty” risks inhibiting project development and 

technology demonstrations. 

 Spectra also believes that this duty should be broadly construed and include not 

only traditional instruments such as letters of credit, insurance bonds, and owner/operator 

ratings but also other potentially more innovative instruments as well. For example, in 

the GS Rule, EPA indicates that its guidance will be similar to the requirements for 

financial assurance currently applicable to Class II owners and operators, which is 

generally limited to the provision of financial assurance by third party instruments, such 

as surety bonds, financial guarantee or performance bonds, letters of credit, or an 

irrevocable trust fund. Alternatively, Class II owners and operators can rely on selfinsurance instruments. However, modeling financial assurance guidance on what is 

currently provided for Class II wells overlooks the potential of allowing insurance 

products, which are permitted for Class I injections. Spectra believes that insurance 

products should be considered in EPA’s guidance. 

B. EPA Should Require Separate Financial Demonstrations For Well 

Plugging And Post-Injection Site Care Requirements. 

 Spectra believes the financial assurance requirements for post-injection site care 

should be separate from the financial assurance requirements for well plugging in the GS 

Rule. The high likelihood that the need for well plugging will vary greatly from site to 

site raises concern over the extent to which it could distort a given owner or operator’s 

needs for financial assurance at a particular site. Allowing for a separate well plugging 

financial assurance requirement would allow owners and operators to acquire the 

appropriate risk management instrument that takes into account a particular site’s unique 

character and well plugging needs, thereby making overall financial assurance 

requirements more cost effective and efficient. In addition, post-injection site care 

requirements will similarly vary from site to site, and maximum flexibility in selecting 

risk management instruments to meet financial assurance requirements will encourage 

CCS project development. In neither case would separate requirements result in 

diminished coverage or in any way jeopardize USDWs. Accordingly, EPA should revise 

the GS Rule to reflect Spectra’s comments on this point. 
Spectra Energy UIC Comments 

Page 41 

December 18, 2008 

C. EPA’s Three Year Pay-In Period For A Trust Fund Is Not Reasonable. 

 In the GS Rule, EPA notes that current UIC guidance describes trust funds as a 

form of financial assurance, whereby owners and operators can deposit funds into the 

trust fund in phases, e.g., either over the term of the initial permit or over the remaining 

operational life of the injection well, whichever is shorter. EPA raised concern over the 

possibility that the owner or operator may face financial distress prior to the trust being 

fully funded and stated that it is considering a guidance approach that would recommend 

adopting a pay-in period of three years for GS projects. Spectra respectfully disagrees 

with this approach, on grounds that it will create an unreasonable and unnecessary barrier 

to the use of trust funds. A three year pay-in period has the potential to increase upfront 

costs significantly and discourage use of trusts solely for the purpose of avoiding the 

unlikely scenario of an owner or operator becoming insolvent prior to the end of the 

project’s operation or the end of the permit term. While Spectra recognizes that a three 

year pay-in period would address the Agency’s concerns, the risk that this approach 

would create a drag on the use of trusts far outweighs any benefit it might afford. 

Accordingly, Spectra opposes a three year pay-in period for the foregoing reasons.

 Again, we appreciate the opportunity to submit these comments in response to 

EPA’s Proposed GS Rule. We would welcome the opportunity to visit with you and your 

staff to further discuss our comments and suggestions for a viable GS Rule. Please do 

not hesitate to contact me at 713-627-5944 or blmetzger@spectraenergy.com if the 

Agency has any questions or seeks further clarification. 

Sincerely, 

Brianne Metzger 

Climate Change Policy Manager 

Spectra Energy Corp 

69054.000020 EMF_US 26333560v9 
Letter ID: 0151 

Commenter: Brianne Metzger 

Organization: Spectra Energy Corp 

Letter ID: 0151 Comment ID: 21815 Letter Lines: 31 to 43 

Comment Code: 1420 1.2.1.1 Support the GS rulemaking 

Comment: Spectra Energy Corp ("Spectra" or "Spectra Energy") appreciates this 

opportunity to submit for the U.S. EPA’s ("EPA" or "Agency") consideration the 

following comments regarding the Agency’s proposed development of Federal 

Requirements Under the Underground Injection Control Program for Carbon Dioxide 

Geologic Sequestration Wells (hereafter referred to as the "Proposed Rule" or 

"GS Rule"). 73 Fed. Reg. 43491 (July 25, 2008). We appreciate the Agency’s 

recognition of the importance of the GS Rule in the larger context of carbon, 

capture and sequestration ("CCS") and we acknowledge the Agency’s tremendous 

work in proposing this rule within such a short schedule, especially given the 

complexities of the issue. Although we have a number of concerns and 

recommendations regarding the proposed technical requirements and potential 

liabilities, we believe that the Proposed Rule provides a solid foundation 

toward promulgating the Final Rule. 

Individual Response: EPA believes that the creation of a new injection well class (VI) under the 

existing UIC Program is necessary to enable the use of GS as a climate change mitigation 

technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC 

Program, under the authority of the SDWA, provides a strong framework for regulating injection 

of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the 

unique issues associated with large-scale GS, including large injection volumes, the relative 

buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in 

captured CO2, and its mobility within subsurface geologic formations. 

Letter ID: 0151 Comment ID: 21816 Letter Lines: 55 to 66 ; 1522 to 1524 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment Code: 1420 1.2.1.1 Support the GS rulemaking 

Comment: Spectra believes the GS Rule should be designed to encourage carbon capture and 

sequestration as an integral part of any national climate change policy. Second, 

while Spectra appreciates many of the unknowns that currently exist with respect 

to commercial scale GS operations, sour CO2 [1] from natural gas operations has been 

safely injected for nearly two decades and such operations present significant 

opportunities for further reductions in atmospheric CO2 emission through longterm geologic sequestration. Lastly, Spectra and many others within the 

industry have ongoing operations in North America and elsewhere, and we are 

concerned that, should EPA impose excessive or unreasonable requirements as part 

1
of the GS Rule, this could have negative implications for GS activities in other 

jurisdictions such as Canada - where the majority of Spectra’s current geologic 

sequestration activities occur. 

1 The term sour CO2 (a/k/a "acid gas") is used to describe the by-product 

generated from natural gas processing and is primarily a mixture of CO2 and H2S 

but may also contain a small amount of impurities. 

Individual Response: EPA clarifies that the intent of the GS rule is not to encourage GS or CCS 

in the US or elsewhere; rather, the purpose of the GS rule is to ensure that, where GS is 

deployed, it is conducted in a manner that protects USDWs from endangerment. The Agency's 

authority as it relates to GS is limited to protection of USDWs within the United States. 

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; and the 

Bureau of Land Management). The Agency continues to evaluate areas of potential applicability 

of other Federal environmental statutes including, but not limited to: the Clean Air Act; the 

Resource Conservation and Recovery Act; the Comprehensive Environmental Response, 

Compensation, and Liability Act; and the Marine Protection, Research, and Sanctuaries Act to 

various aspects of GS and CCS. The Agency will continue to coordinate on GS and CCS related 

issues to minimize redundancy and maximize efficiencies for owners or operators. For additional 

information, please see the discussion entitled "How Does This Rulemaking Relate to Other 

Federal Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

EPA is using an adaptive approach to regulating GS under the UIC Program. Even after 

finalization of the GS regulation, the Agency plans to collect and review data every six years on 

GS projects to determine whether the appropriate amount and types of information and 

appropriate documentation are being collected, and to determine if modifications to the 

requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21817 Letter Lines: 175 to 187 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment: II. FOR CCS TO BE VIABLE, GS REQUIREMENTS MUST BE FLEXIBLE, 

TAILORED TO SITE 

SPECIFIC NEEDS, AND MUST RELY UPON STATE EXPERIENCE. 

Under the Proposed Rule, EPA has adopted an approach specifically tailored to 

the unique characteristics of CO2 deepwell injection. While we generally 

support the Agency’s decision not to be overly prescriptive in the development 

of the GS requirements, certain portions of the technical requirements appear 

to be excessive and unreasonable and will result in higher operational costs 

2
without meaningful benefits. In the promulgation of the Final Rule, we would 

encourage EPA to continue to build upon the concept of flexibility, reduce the 

amount of unnecessary and costly requirements, and, in certain cases, provide 

greater discretion to the States in deciding the technical specifications 

applicable to siting, well construction, and monitoring. 

Individual Response: EPA agrees that permitting decisions for GS wells should be based on 

site-specific factors. The GS rule requires owners or operators to submit, and Directors to 

consider, extensive site-specific data, specified at §146.82, to demonstrate that a site is suitable 

for GS. Additionally, many of the permit requirements for GS wells are established through 

individualized site-specific plans for AoR and corrective action, testing and monitoring, and 

injection well plugging and post-injection site care and site closure. EPA adds that the final GS 

rule includes a balance of specific criteria to be met by the owner or operator and areas of 

Directorial discretion and considerations for how that discretion would be exercised. The Agency 

believes this balance allows for GS projects to be designed and permitted to address the unique, 

site-specific aspects of each project, while providing consistency in permitting across the U.S. 

EPA disagrees that the Class VI requirements are overly stringent; instead, the GS requirements 

are tailored to the unique nature of GS, including the large volumes of CO2 injected, its 

buoyancy and potential corrosivity in the presence of water, and impurities in the CO2 stream. 

EPA believes these tailored requirements are more appropriate than Class I or Class II 

requirements. Please see the remainder of EPA's responses to this comment for further details. 

For additional information on EPA's final regulatory approach, please see the final rule and 

preamble as well as the rulemaking docket. 

Letter ID: 0151 Comment ID: 21818 Letter Lines: 189 to 203 

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment) 

Comment: A. EPA Should Allow The Use Of Proprietary Models For Modeling CO2 

Movement and 

Reservoir Pressure. 

EPA correctly acknowledges that some companies use proprietary models for their 

current GS operations, and has requested comment on allowing the use of such 

models for GS sites. Spectra strongly agrees with the continued use of 

proprietary models. While Spectra would be willing to provide information 

pertaining to the underlying assumptions and scientific basis, subject to 

protection as confidential business information ("CBI"), we would object to any 

effort by the Agency to compel further disclosure regarding such models. 

Although we recognize that the Agency is required by law to take certain steps 

to protect CBI, we are mindful that such protections are not always fail-safe 

and inadvertent disclosures of CBI are not uncommon. Such disclosures in the 

case of the critical infrastructure we operate or may operate in the future 

could be extremely detrimental and costly. 

3
Individual Response: EPA agrees that some of the available proprietary models may meet the 

needs for calculating the AoRs of GS sites. EPA will allow their use in meeting the requirements 

for the GS regulation, but clarifies that GS well operators using proprietary models are required 

to disclose, to the Director's satisfaction, the code assumptions, relevant equations, and scientific 

basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir 

engineering professionals as well as in peer-reviewed studies to model CO2 sequestration. EPA 

adds that its Confidential Business Information requirements at 40 CFR 144.5 will apply to the 

use of proprietary models. Information including model assumptions and equations are used by 

the Director to inform his/her decision to issue the permit and ensure that the requirements are 

met and the GS well will not endanger USDWs. EPA adds that its Confidential Business 

Information requirements at 40 CFR 144.5 will apply to the use of proprietary models. 

Letter ID: 0151 Comment ID: 21819 Letter Lines: 205 to 214 

Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to 

delineate the AoR (seeking comment) 

Comment: B. The Area of Review Should Be Determined Based On Computational Fluid Flow 

Models And Reevaluation Should Occur At A Fixed Frequency Not To Exceed 10 

Years. 

We agree with the Agency’s current position that the application of 

computational fluid flow models to predict the complex multi-phase buoyant flow 

of CO2, co-injectates, and compounds is an acceptable and appropriate approach 

to mapping out the Area of Review (AoR). Such computational models are 

currently being used by industry with success. Further, industry continues to 

refine the accuracy of these models as the data and science are improved. 

Individual Response: EPA acknowledges the commenter’s support and believes that predicting 

the complex multiphase, buoyant flow of the CO2, co-injectates, and compounds that may be 

mobilized due to injection requires the sophistication of computational models, as required at 

146.84(c)(1). Models can predict CO2 fate and transport, as well as changes in formation 

pressure, in three dimensions, as a function of time in order to delineate the subsurface storage 

site and the AoR. Models can account for site-specific and predicted operating conditions as well 

as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

Letter ID: 0151 Comment ID: 21820 Letter Lines: 216 to 224 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment: We also support the Agency’s position that any reevaluation of the AoR occur at 

a minimum fixed frequency, not to exceed 10 years. As well, we agree with 

providing the Director discretion to require more frequent reevaluation, as 

appropriate, if the monitoring or modeling suggests that the CO2 plume is not 

4
behaving as originally predicted and could result in endangerment to 

underground sources of drinking water (USDWs). Based on our experience with 

AGR, we believe that a frequency of between 3-5 years may be more reasonable 

and appropriate and would support such a determination; but in any event, we 

agree that such reevaluation should not exceed 10 years. 

Individual Response: EPA agrees that reevaluations of the AoR every ten years may not be 

sufficient to appropriately model plume and pressure front movement, establish conditions for 

corrective action, and ensure protection of USDWs from endangerment. For these reasons, the 

Agency changed the minimum frequency for the AoR reevaluation at §146.84(e) from ten years 

to at least every five years in the final GS rule. EPA believes that this revised frequency 

addresses commenters' concerns about the inherent uncertainties in modeling CO2 movement, 

the emerging nature of GS technology, risk-based targeting of monitoring activities, and the 

unique nature of CO2 GS. 

Letter ID: 0151 Comment ID: 21821 Letter Lines: 226 to 246 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: C. Phased Corrective Action Is An Appropriate Approach. 

Spectra Energy agrees with the Agency’s idea of allowing for phased corrective 

action. We believe this is a reasonable approach, given the potential size of 

the CO2 plume for commercial-scale operations (50 square miles or larger). 

Requiring corrective action for the entire AoR prior to injection would likely 

result in substantial delays in permitting and project implementation. We 

agree that at a minimum, as part of the AoR process, all wells that penetrate 

the confining or injection zone must be identified. One question that warrants 

clarification by EPA, however, is the ability to gain access to third party 

wells that may over time require corrective action. Most states require 

corrective action to be performed prior to injection and the “right of access” 

is taken into consideration during the adequacy determination of the corrective 

action plan. Some states, such as Texas, require corrective action prior to 

injection unless the owner/operator, after best efforts, is unable to get 

permission to access the property of a third party. 30 TEX. ADMIN. CODE § 

305.151 (2008). Since SDWA does not provide EPA the authority to require third 

parties to provide access to an owner/operator for the purposes of conducting 

corrective action, we believe it is important for the Agency in the Final GS 

Rule to discuss and clarify how owner/operators and states will be expected to 

implement corrective action based on an iterative approach. 

Individual Response: EPA acknowledges the commenter’s support of phased corrective action 

and agrees that phased corrective action may provide many benefits to a project including, but 

not limited to, spreading the burden of cost, avoiding delays in project start-up, allowing for use 

of future, improved corrective action techniques and addressing unanticipated changes in the 

movement of the CO2 plume or pressure front. EPA believes that the phased corrective action 

5
approach is appropriate for GS projects, and retained it at §146.84(b)(2)(iv) in the final GS 

regulation. 

EPA agrees that securing access to all wells that require corrective action is important. In 

general, to meet the corrective action requirement, the owner or operator will most likely need to 

obtain the right of access to wells that may require corrective action, and demonstrate they have 

done this in their proposed AoR and corrective action plan. In the AoR and corrective action 

plan, the owner or operator must describe how site access will be guaranteed for future corrective 

action, as specified in §146.84(b)(2)(iv). The final rule retains the requirement to guarantee site 

access as proposed. 

Letter ID: 0151 Comment ID: 21822 Letter Lines: 248 to 261 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: D. EPA Should Not Arbitrarily Preclude Injection Into Certain Formations Located 

Above The Lowermost USDW. 

Under the Proposed Rule, EPA has proposed limiting the injection of CO2 to 

below the lowermost USDW. Spectra believes that it is premature for the 

Agency to preclude the injection of CO2 into formations such as unmineable coal 

seams, depleted oil and gas reservoirs, zones in between or above USDWs, or 

other formations. As EPA points out, imposing such a limit may preclude the 

application of GS in areas such as the Williston and Powder River Basins in 

Wyoming and North and South Dakota, where the lowermost USDW is located 

thousands of feet below the surface. In these cases, we agree with EPA that GS 

may still be appropriate and, therefore, the Director should have the 

discretion to make such determinations. Such determination must ultimately be 

made based on the protection of USDWs. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

6
EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0151 Comment ID: 21823 Letter Lines: 263 to 273 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: E. EPA Should Not Make The Permitting Process Overly Burdensome By Requiring 

Unnecessary Or Unavailable Data. 

Under the proposal, EPA is requiring the collection and submission of a 

significant amount of information and data. Although we understand and support 

the need for certain baseline data to support the determination that a 

particular project location is suitable, in certain cases, some of the data 

that EPA is requiring is irrelevant, excessive, or may even be unavailable. 

Therefore, we would recommend that the Agency include a provision in the Final 

GS Rule that would provide a waiver process and criteria, whereby the Director 

could waive certain data requirements, where such requirements are unnecessary. 

Individual Response: EPA disagrees that any of these protective requirements are unnecessary, 

and believes that waiving any of the requirements would not be acceptable. The GS regulation 

allows flexibility where appropriate. Certain requirements (e.g., the need to characterize 

additional confining layers) are at the Director's discretion (§146.83(b)), based on his or her 

understanding of a particular site. 

EPA believes that a detailed geologic site characterization (required under §146.82) is essential 

to evaluating the presence and adequacy of the various geologic features necessary to receive and 

confine injected CO2 for GS. The requirements for geologic site characterization are based on a 

long-standing UIC regulatory framework developed to address specific risks to USDWs posed 

by injection. The Class VI GS requirements are tailored so that they are appropriate for the 

unique nature of injecting large volumes of CO2 into a variety of geologic formations for longterm storage. 

EPA believes that a determination about whether or what information may be necessary (for a 

specific GS project) is outside of the public record will be site-specific and based on knowledge 

of the site, data availability, and data quality. For instance, in meeting the requirement to tabulate 

information on wells in the AoR, the Director has the discretion to require the owner or operator 

to supplement a data records search if there is reason to believe that the incompleteness of 

available information could compromise USDW protection from endangerment. 

7
Letter ID: 0151 Comment ID: 21824 Letter Lines: 275 to 290 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment: EPA is proposing that an applicant include "baseline geochemical data on 

subsurface formations, including all USDWs in the area of review." 40 C.F.R. § 

146.82(g). It is not clear how much baseline data EPA is expecting the permit 

applicant to generate and collect from additional drilling or testing of the 

injection zone and all other zones. Given the likely depth of many of the GS 

wells through multiple strata, this could involve tens (and possibly hundreds) 

of different formations above the injection zone. Therefore, we would 

recommend that EPA limit the baseline geochemical data "where feasible, to the 

next porous formation above the injection zone." EPA should also clarify that 

the permit applicant may rely upon secondary sources (such as other drilling or 

geologic records) that relate to and support the data requirement. EPA should 

also clarify whether the Agency expects applicants to test private wells, where 

permission is granted, within the AoR for purposes of establishing baseline 

data. As a general matter, Spectra believes that EPA should not require 

testing of private wells because sampling results could be affected by flawed 

well construction or poor integrity, wholly unrelated to the injection project. 

Individual Response: The GS regulation, at 146.82(a)(6), requires the owner or operator to 

submit baseline geochemical data on subsurface geologic formations. EPA is not specifying for 

which formations this information should be submitted in the rule to allow flexibility, but 

examples may include the following formations: a) the injection zone, b) the confining zones, c) 

containment zones above the confining zones in which any potentially migrating CO2 could be 

trapped, d) all USDWs, and e) any other geologic zone or formation that is important to the 

proposed monitoring program. The Director has the authority to request additional geochemical 

data as well. EPA does not expect that testing of private wells will be required in most cases, but 

clarifies that the Director has authority to require such sampling if it is believed to be necessary 

to ensure USDW protection. 

While each monitoring plan will be site-specific based on data collected during the initial site 

characterization and baseline geochemical monitoring, it is likely that geochemical sampling 

might include basic water quality parameters such as pH, specific conductivity, temperature, 

CO2, alkalinity, major ions, and select heavy metals. Additional parameters may be monitored 

based on the potential for leaching of minerals or the geochemistry of native fluids. 

Letter ID: 0151 Comment ID: 21825 Letter Lines: 292 to 305 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment: EPA has also included a requirement that the permit applicant include a 

"proposed formation testing program to obtain an analysis of the chemical and 

8
physical characteristics" of the injection and confining zone. 40 C.F.R. § 

146.82(j). A permit applicant is already required to submit the underlying 

data as part of the permit application process, and it appears that this 

requirement is unnecessary and duplicative. Therefore, we request further 

clarification regarding the intent and scope of this formation testing program. 

Spectra generally supports the requirement for the "proposed stimulation 

program" to ensure that stimulation activities will not interfere with 

containment. 40 C.F.R. § 146.82(k). We believe it is important that EPA 

monitor stimulation activities of third parties to ensure that such activities 

not interfere with or damage the containment integrity of other GS operations 

or natural gas storage reservoirs. 

Individual Response: The formation testing plan must be approved before the owner or operator 

can generate necessary data on the compatibility of the CO2 stream with fluids in the injection 

zone and minerals in both the injection and the confining zone. In response to comments and 

based on an evaluation of the proposed requirements, EPA revised subpart §146.82 so that the 

final regulation specifies separate requirements for information to be submitted with the permit 

application and before well construction is approved (at 146.82(a)) and information to be 

submitted before operation of the well is authorized (at §146.82(c)). 

Additionally, EPA agrees that it is important that the Agency, as manager of the national UIC 

Program, understand how various aspects of GS projects, including stimulation activities, are 

proceeding, and that operators performing well stimulation activities are not endangering 

USDWs. EPA plans to, every six years, collect and review project data on early GS projects, 

including site characterization, operational, monitoring, and modeling data, to determine whether 

the appropriate amount and types of information and appropriate documentation are being 

collected, and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21826 Letter Lines: 307 to 325 

Comment Code: 3440 2.2.2.2 Evaluation of wells in the AoR (e.g., types of data to be 

reviewed) 

Comment: EPA has proposed requiring the applicant submit "the status of corrective 

action on wells in the area of review." 40 C.F.R. § 146.82(q). We believe it 

is unnecessary to require the inclusion of all wells within the AoR regardless 

of whether or not they penetrate the injection zone. There could be many 

shallow wells within the AoR located hundreds or thousands of feet above the 

CO2 injection. Therefore, EPA should limit this requirement to the injection 

zone, injection pool, and only those wells that either intersect or penetrate 

the proposed reservoir, the cap rock, and possibly the porous strata directly 

above the injection zone, or wells that penetrate or are in close proximity to 

a gas storage reservoir. 

9
The Agency has stated that only information of public record pertaining to all 

types of wells (injection, producing, abandoned) be included on the AoR. Data 

availability and use raises a question regarding the possible existence of 

other data which might be private, proprietary and/or not publicly available. 

Such non-publicly available data may or may not be relevant to the application 

process. However, EPA should clarify to what extent an applicant would be 

expected by EPA to develop or use information that is not contained in the 

public record. 

Individual Response: EPA clarifies that, under 146.84(c)(2), operators are required to identify 

all penetrations in the AoR that penetrate the confining zone, but that corrective action is needed 

only for those wells that are determined to need corrective action in order to prevent movement 

of fluid into or between USDWs. The well inventory/identification process is more inclusive 

than the corrective action process to allow the Director to ensure that all wells in the AoR are 

identified and those that need corrective action receive it. 

Letter ID: 0151 Comment ID: 21833 Letter Lines: 327 to 338 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: F. Integrity Testing And Monitoring Requirements Are Excessive And The 

Definition of "Significant Leakage" Should Be Clarified. 

A significant component of the GS Rule is focused on mechanical integrity of 

injection wells to ensure against any "significant leakage" that would endanger 

USDWs. As part of the integrity testing requirements, EPA is proposing to 

require owner/operators to at least once per year determine the absence of 

significant fluid movement by using tracers, temperature or noise logs, or 

casing inspections, or any other tests as required by the Director. 40 CFR § 

146.89(c). While Spectra fully supports the need for integrity testing, we 

believe that some of the requirements are excessive and unreasonable and will 

not provide meaningful data. 

Individual Response: EPA disagrees that the MIT requirements for Class VI wells are 

excessive, and believes that the MITs described in the rule at §146.89 are effective methods and 

have been used successfully by injection well operators for decades and provide an important 

early warning of potential problems in the injection well system. Given the unique nature of CO2 

injection for GS (e.g., the potential corrosivity of CO2 in the presence of water and impurities on 

well materials, the potential geomechanical impacts to well integrity due to CO2 phase changes, 

the temperature and pressure effects associated with injecting supercritical CO2, and the buoyant 

nature of CO2 and the potential for its movement up a wellbore), EPA believes it is important to 

protect USDWs from endangerment by adopting MIT requirements that are tailored to CO2 

injection for GS. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement 

behind the casing, but clarifies that it is appropriate for determining the presence or absence of 

10
corrosion of the long-string casing, and is required if the Director determines that it is necessary 

based on site-specific information. EPA has revised the final GS rule to require that the 

frequency of the casing inspection log must be specified in the approved testing and monitoring 

plan. See §146.89(d). 

In addition, EPA is using an adaptive approach to regulating GS. The Agency plans to collect 

and review data every six years on GS projects to determine whether the appropriate amount and 

types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21834 Letter Lines: 340 to 359 ; 1526 to 1531 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: 1. EPA Should Define "Significant Leakage" Within The Context Of Endangerment. 

EPA has defined mechanical integrity as "no significant leakage" and "no 

significant fluid movement into a USDW through channels adjacent to the 

injection well bore." While Spectra agrees with EPA’s general approach here, 

we are concerned that the absence of a definition regarding what constitutes 

"significant" could create ambiguity that could be construed against the 

owner/operator and beyond authority granted under SDWA. Therefore, we would 

strongly recommend that the Agency define what constitutes "significant" or, 

alternatively, clarify under what conditions significant leakage might be 

construed. Toward this end, we believe that the term should be defined and 

construed within the statutorily defined concept of "endangerment" [2] under SDWA, 

i.e., significant leakage would be defined as any leakage that could 

potentially endanger a USDW. As one court has held, Congress’ established no 

specific metric for measuring endangerment and thus the Agency has the 

discretion to develop UIC requirements based on varied geology, Miami-Dade 

County v. EPA, 529 F.3d 1049 (11th Cir. 2008) (court upheld EPA’s rule 

eliminating the non-endangerment finding requirement for Class I municipal 

injection wells). The amount of leakage and what constitutes significant may 

vary depending upon the geologic formations and proximity to USDWs. 

2 Endangerment is defined as follows: Underground injection endangers drinking 

water sources if such injection may result in the presence in underground water 

which supplies or can reasonably be expected to supply any public water system 

of any contaminant, and if the presence of such contaminant may result in such 

system’s not complying with any national primary drinking water regulation or 

may otherwise adversely affect the health of persons. 42 U.S.C. § 300h(d). 

Individual Response: A properly designed and operated well should have no leakage in the 

casing, tubing, or packer and no fluid movement into a USDW through channels adjacent to the 

11
wellbore. While the intent of MITs is to detect these types of problems as early as possible, the 

goal of the well design and construction requirements at §146.86 is the complete absence of such 

problems. EPA clarifies that the purpose of the "significant leakage" language in this narrow 

context is simply to avoid triggering corrective actions for essentially de minimis situations. 

Determining whether a MIT result should trigger follow-up action is necessarily a case- and sitespecific situation; as a result, EPA does not believe it is appropriate to define the term 

"significant leakage" in the context of MITs. In addition, EPA has not defined this term for 

purposes of other injection well classes and this has not been shown to hinder permitting 

authorities' and owners' or operators' ability to assess whether injection wells have adequate 

mechanical integrity. EPA believes that this approach allows states flexibility, will not interfere 

with the implementation of existing UIC programs, and maintains protection of USDWs from 

endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data 

every six years on early GS projects, including MIT data, to determine whether the appropriate 

amount and types of information and appropriate documentation are being collected, and to 

determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21835 Letter Lines: 361 to 387 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: 2. Annual Mechanical Integrity Testing And Quarterly Corrosion Monitoring Are 

Excessive. 

We do not believe there is any compelling reason to require annual integrity 

testing. 40 C.F.R. § 146.89(c). First, our experience in Canada with sour CO2 

injection wells is that integrity testing every five years is more than 

sufficient. Alberta regulations require all operators to verify every five 

years the down hole condition to confirm hydraulic isolation. Many of our 

injection wells are reused producer wells that have been in corrosive 

environments for over 15 years. Even after 15 years, these wells are in good 

condition, based on the good design and the use of proper materials, and we 

have never experienced a leak. Annual testing and quarterly corrosion testing 

could also result in significant costs from plant shutdowns and downtime with 

very little benefit, if any, from the data generated. Many companies, 

including Spectra, conduct periodic plant-wide shutdowns to thoroughly inspect 

piping and equipment for corrosion and make any necessary equipment upgrades. 

These shutdowns, which ordinarily occur once every three to five years, are 

also used to inspect our injection wells, including pulling tubing and running 

cement bond logs and well casing integrity logs to determine the thickness and 

integrity of the steel in the boreholes. From these tests we are able to 

assess the cement and casing conditions, which provide the primary "isolation" 

mechanism from the reservoir fluids. We can and often do run noise logs that 

12
can assess for "channeling" behind the casing. While routine testing is 

important, the most significant part of maintaining well integrity is ensuring 

material compatibility and making certain that the cement and casing materials 

used are resistant to corrosion. We use nickel steel in some of our wells, 

which is even stronger and more corrosion resistant than stainless steel. 

Individual Response: EPA disagrees that a five-year external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually under §146.89(c). EPA 

believes this is justifiable for the protection of USDWs from endangerment given the unique 

nature of CO2 GS relative to other injection operations. Because of the unknown long-term 

effects of CO2 GS, EPA chose a more conservative initial approach in the early stages of 

deployment for GS. 

While EPA acknowledges the successful history of the Class II injection program, including 

injection of sour (acid) gas, the Agency believes that CO2 injection for GS is substantially 

different from Class II ER operations in that: 1) the purpose of CO2 injection for GS is 

permanent storage, whereas for ER operations, injected CO2 is often recovered (pumped from 

the sub-surface) relatively soon after injection, 2) typically there is minimal formation pressure 

build-up during ER operations because withdrawals from oil recovery wells reduce reservoir 

pressure, which is not the case in GS reservoirs, and 3) the volumes of CO2 anticipated for 

injection for GS are significantly larger than the volumes of CO2 injected for ER operations. 

These conditions illustrate that frequent internal MITs for Class VI wells are critically important 

in ensuring that USDWs are protected. EPA believes that continuous pressure monitoring to 

demonstrate internal mechanical integrity of GS wells, instead of periodic testing, which is 

required for most other types of deep injection wells, is important. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. Regarding concerns about disruptions of plant operations, EPA believes that, 

due to the expected size of GS fields, many GS operations will have more than one injection 

well, and that testing of each well can be timed to avoid complete interruption of the project. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21836 Letter Lines: 389 to 395 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

13
Comment: Section 146.89(d) currently gives the Director discretion to require any other 

test to evaluate mechanical integrity, provided such alternative tests are 

approved and published in the Federal Register. We would recommend that EPA 

revise the mechanical integrity testing requirements in two ways: (1) to give 

the Director discretion to approve not only different testing requirements but 

the timing for testing requirements, and (2) to require such testing no less 

than every five years. 

Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective methods to demonstrate external 

MI, provide an important early warning of potential problems in the injection well system, and 

represent standard techniques that have been used successfully by the drilling industry and for 

the UIC Program for decades. The Agency notes that the regulations do provide the Director 

flexibility at §146.89(e) to approve the use of alternative MIT methods. 

The final GS regulation retains the requirement that owners or operators of Class VI wells must 

demonstrate injection well external mechanical integrity at least once annually as required at 

§146.89(c). EPA believes that the annual mechanical integrity testing is appropriate for Class VI 

wells and is justifiable for the protection of USDWs from endangerment given the unique nature 

of CO2 GS relative to other injection operations, including the potential corrosive impact of CO2 

in the presence of water and impurities on well materials, the potential geomechanical impacts to 

well integrity due to CO2 phase changes, the temperature and pressure effects associated with 

injecting supercritical CO2, and the buoyant nature of the injected CO2. Because of the unknown 

long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stages 

of deployment for GS. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21837 Letter Lines: 397 to 404 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: For reasons described above, we also believe that the requirement to conduct 

corrosion monitoring on a quarterly basis is excessive and unnecessary. To 

require quarterly monitoring could negatively impact the flow rate, thus 

14
requiring operators to add more wells. This could limit the overall 

effectiveness of the project. In addition, quarterly corrosion monitoring 

would require the operator to remove the bottom hole configuration to perform 

necessary tests. This is both costly and time consuming and would require 

operations to be temporarily shutdown. 

Individual Response: EPA believes that quarterly corrosion monitoring is reasonable and 

appropriate given the potentially corrosive nature of the CO2 stream. CO2 in the presence of 

water becomes acidic, potentially accelerating corrosion of well materials. The CO2 stream for a 

GS project may also contain small volumes of impurities that could contribute to corrosion. For 

these reasons, the final rule requires quarterly corrosion monitoring (at §146.90(c)). 

Letter ID: 0151 Comment ID: 21838 Letter Lines: 406 to 415 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

Comment: EPA has specifically requested comment on the use of tracers. Based on our 

experience, tracers are not typically used for monitoring the movement of the 

CO2 plume, unless it is suspected that leakage is occurring, and then they are 

only used to trace the leakage. The use of tracers can be very expensive and 

the results can take considerable time to develop, analyze, and understand. 

Radioactive tracers typically have long shelf lives (e.g., 50 or 100 years) 

and, if used too frequently by neighboring operators, could produce conflicting 

and indeterminate results. Due to the potential for groundwater contamination, 

the use of radioactive materials should be used only sparingly and for targeted 

purposes. 

Individual Response: EPA believes that, in some circumstances, tracers can be an important 

component of a multifaceted approach to monitoring GS projects. However, the Agency 

recognizes that tracers may not be appropriate in all GS projects. For this reason, EPA does not 

require the use of tracers at all GS sites; however, the Director has discretion to require their use 

if he/she determines that the use of tracers could improve monitoring of the site and enhance 

USDW protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that 

all of the protective components of the regulation, including a comprehensive monitoring 

program per §146.90 (which includes testing of the well, ground water quality monitoring, and 

tracking of the CO2 plume and pressure front) support a multi-barrier approach to protecting 

USDWs. Additionally, some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells both at depth and at near-surface locations. At Frio, tracers enabled quantification 

of CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research related to tracer use. The Agency plans to, every six 

years, collect and review data on GS projects to determine whether the appropriate amount and 

15
types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0151 Comment ID: 21839 Letter Lines: 417 to 429 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: G. The Use Of Down-Hole Devices And Coupons Should Be Limited. 

Although we do not believe that downhole monitoring devices are necessary for 

GS wells, the use of emergency shutdown devices (ESDs) may be important. At 

our Kwoen facility where we inject a sour CO2 mixture that is 80% H2S and 20% 

CO2, we use primarily three forms of ESD: (1) a valve at the wellhead, (2) a 

subsurface safety valve, and (3) a check valve at the packer. This ESD 

configuration enables us to plan for and respond to a number of contingencies, 

including (1) shutting down the wellhead (2) shutting the subsurface safety 

valve in the event the wellhead is sheared off or damaged, which prevents 

atmospheric leaks and (3) closing the packer check valve, which enables us to 

conduct any uphole work. For gas storage involving only the injection of sweet 

gas, typically only wellhead ESD is used. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

construction and operational conditions, including isolation from shorelines and the need to 

construct wells through the water column and the subsurface, which may delay response time in 

the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of 

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA 

believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent 

subsurface fluid movement and ensure protection of USDWs. 

Letter ID: 0151 Comment ID: 21840 Letter Lines: 431 to 446 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: EPA’s proposal also calls for the use of "coupons" to monitor for corrosion. 40 

C.F.R. § 146.90(c)(1). Based on our experience with the use of coupons, we 

would recommend against this requirement, as coupons are susceptible to failure 

and can lodge deep in the injection well, thereby causing problems with flow 

rate. In addition, coupons do not identify where corrosion may or may not be 

taking place, due to the differences in temperature and pressure between 

16
ambient and downhole conditions. The results from the use of coupons could 

suggest that an entire casing or tubing string needs to be replaced when, in 

fact, only a portion of the well casing may need to be replaced. Therefore, 

coupons do not produce representative results and the data will generally not 

be helpful. Similarly, the concept of a "constructed loop" at the surface to 

monitor and test material integrity is also not recommended, as it does not 

replicate actual downhole conditions. 40 C.F.R. § 146.90(c)(2). We believe 

that one of the best tests for corrosion monitoring is the casing evaluation 

logs, which allow an operator to identify specific zones where corrosion may be 

occurring. 

Individual Response: EPA believes that the use of coupons for corrosion monitoring is feasible 

and appropriate for GS wells. Corrosion monitoring by various techniques, including the use of 

coupons, has been performed by operators of Class I hazardous waste injection wells for many 

years. Use of coupons can help provide early warning of corrosion of well materials that could 

compromise the well's integrity. 

The use of well coupons for testing with CO2 for compatibility is one of three options outlined in 

§146.90(c). Operators also have the option of routing the CO2 stream through a loop constructed 

with the material used in the well or using an alternative method approved by the Director. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0151 Comment ID: 21841 Letter Lines: 448 to 460 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: EPA is also proposing "periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s)." § 146.90(d). It is unclear 

how many wells would be required, and whether EPA expects all zones would be 

monitored. Given the potential size of the CO2 plume and the number of 

confining zones, this could potentially require many monitoring wells, which 

could be extremely expensive and unlikely to produce useful data. It is our 

strong recommendation that EPA minimize the amount of monitoring to the zone 

immediately above the confining zone, and only to the extent that the CO2 plume 

is within close proximity. For example, there may be regional conditions where 

ground water is separated by hundred or thousands of feet of confining strata, 

and where such monitoring is unnecessary. We would recommend that the Director 

be given discretion to limit or tailor ground water monitoring, as appropriate, 

17
based on regional and site specific factors. 

Individual Response: The GS rule stipulates that the monitoring frequency and spatial 

distribution of monitoring wells must be based on baseline geochemical data that were collected 

during the initial site characterization and the area of review evaluation, as described in 

§146.90(d)(2). The details of the geochemical monitoring will be described in the Directorapproved testing and monitoring plan. 

Regarding monitoring locations, section §146.90(d) requires periodic monitoring of the ground 

water quality and geochemical changes above the confining zone(s). Monitoring above the 

confining layer will provide an indication of upward movement of CO2 that might endanger a 

USDW. The exact number of formations to be tested will, however, be based on site-specific 

characteristics and vulnerabilities and described in the Director-approved testing and monitoring 

plan. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA also acknowledges that complete coverage of the potential plume area or leakage in the 

subsurface is not possible through the use of monitoring wells. However, data from an 

appropriate number of monitoring wells sited based on site-specific information will provide 

direct information that is not otherwise obtainable and, along with other monitoring data, will 

support a broader understanding of fluid behavior at the site. 

EPA acknowledges the commenters' concern about the cost of monitoring. However, EPA 

believes that monitoring is essential for protection of USDWs at GS sites. Although a significant 

cost in absolute terms, monitoring costs are expected to be a small fraction of site operating 

costs, according to EPA's cost analysis for the GS rulemaking (which is available in the docket). 

Letter ID: 0151 Comment ID: 21842 Letter Lines: 462 to 465 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Comment: EPA is also proposing that an owner/operator demonstrate "external mechanical 

integrity pursuant to § 146.89(c) at least once per year." 40 C.F.R. 146.90(e). 

External mechanical integrity is not defined. Therefore, we would ask EPA to 

clarify what is meant by this term. 

Individual Response: EPA clarifies that mechanical integrity refers to the absence (1) of 

18
significant leak in the casing, tubing, or packer and (2) of significant fluid movement into a 

USDW through channels adjacent to the injection wellbore. The second half of this definition 

refers to external mechanical integrity. 

EPA adds that a properly designed and operated well should have no leakage in the casing, 

tubing, or packer and no fluid movement into a USDW through channels adjacent to the 

wellbore. While the intent of MITs is to detect these types of problems as early as possible, the 

goal of the well design and construction requirements at §146.86 is the complete absence of such 

problems. For additional information, please see the discussion of MITs in the final rule 

preamble. 

Letter ID: 0151 Comment ID: 21843 Letter Lines: 467 to 488 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: H. The Requirement To Perform Ambient Monitoring Exceeds EPA’s Authority 

Under 

SDWA. 

EPA is also proposing that the Director be given discretion to require surface 

air monitoring and/or soil gas monitoring to detect movement of carbon dioxide 

that could endanger a USDW. 40 C.F.R. § 146.90(h). We would recommend that 

this provision be deleted. It is not clear how ambient air or soil gas 

monitoring is related to or supports the protection of USDWs. Based on our 

experience, the use of surface air monitoring can frequently result in false 

positives, which could prompt unnecessary and costly response actions and 

needlessly alarm the public. We believe that targeted ground water monitoring 

and other wellhead testing and monitoring requirements are sufficient to detect 

any movement of CO2 that could endanger a USDW. Given the narrow scope of SDWA 

authority, we question the Agency’s authority to directly or indirectly require 

such monitoring where it does not naturally bear on the protection of USDWs. If 

EPA should decide to retain this provision in the final rule, we would ask the 

Agency to clarify that any requirement for ambient air or soil gas monitoring 

would be purely discretionary on the part of the State, would be pursuant only 

to state law and not the federal UIC program, and thus would not be federally 

enforceable. Bath Petroleum Storage, Inc. v. Sovas, 309 F.Supp. 2d 357 (N.D. 

N.Y. 2004) (state law requiring sonar survey for UIC injection not federally 

enforceable). 

Individual Response: The final rule at §146.90(h) retains the allowance for surface air and soil 

gas monitoring at the discretion of the Director as a means of identifying leaks that may pose a 

risk to USDWs and informing emergency notification of a Class VI owner or operator and UIC 

Director in the event of a USDW endangerment, pursuant to requirements at §146.91(c). EPA 

clarifies that the decision to use surface monitoring and the selection of monitoring methods will 

19
be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) 

and must be based on potential risks to USDWs within the AoR. 

EPA believes that surface air and soil gas monitoring are within the scope of the SDWA in that 

they can provide additional data to pinpoint the location and magnitude (or absence) of leaks that 

could endanger USDWs. Used in conjunction with deep subsurface monitoring, as required at 

§146.90, and as part of a multi-barrier approach to protecting USDWs from endangerment, 

surface air and soil gas monitoring are within the scope of SDWA’s general authority (SDWA 

sections 1421 et al). 

The Agency believes that surface air and soil gas monitoring, when coupled with subsurface 

monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA also 

acknowledges that surface air and soil gas measurements are subject to variability and may not 

be suitable in all settings as a method to ensure USDW protection. However, EPA does not 

believe that this should entirely preclude their use. The decision to use surface monitoring and 

the selection of monitoring methods will be site-specific (e.g., may be influenced by geology, 

injection depth, and operational conditions) and must be based on potential risks to USDWs 

within the AoR. 

Letter ID: 0151 Comment ID: 21844 Letter Lines: 490 to 545 

Comment Code: 2100 1.6 Target Geologic Formations for GS 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: I. Large-Scale GS Operations Must Not Impact The Storage Of Hydrocarbon Natural 

Gases. 

One concern with GS is the potential implications for and impact on large-scale 

natural gas storage operations. Under SDWA, hydrocarbon natural gas storage is 

exempt from current UIC regulations governing injection activities. Spectra is 

concerned about the potential implications and impacts on underground gas 

storage from the Proposed Rule. Natural gas storage is regulated by State and 

interstate entities, such as Interstate Oil and Gas Compact Commission (IOGCC), 

that oversee the siting, permitting, design, construction, and operations of 

wells. Within the U.S., natural gas storage is generally located in two major 

geologic formations, porous rock reservoirs and salt caverns. Generally, the 

types of storage fields that will potentially be impacted by the Proposed Rule 

are porous rock reservoirs. Because many of the areas and geologic formations 

considered for GS will be in the same basins and may occur within or in close 

proximity to the same geologic strata, there is the potential for gas storage 

fields to be adversely impacted by GS. In order to avoid any unintended 

impacts to natural gas storage operations, there are several issues that need 

to be considered. 

First, gas storage wells are regulated by State oil and gas regulatory 

agencies. Individual States have a critical role in protecting and regulating 

20
the competing economic interests involved in utilizing the subsurface, not only 

for natural gas storage but also oil and gas production or other subsurface 

activities. Many State oil and gas regulations specify well siting or 

construction requirements for any wells that are drilled within a gas storage 

area or penetrate the storage horizon. Spectra suggests that appropriate 

regulatory agencies in individual States be active participants with the EPA in 

the GS permitting process, to ensure appropriate State knowledge of local 

geology is considered in a technical evaluation of the suitability of potential 

GS zones, and for the balanced protection of gas storage and other economic 

interests. We believe the EPA should affirm the authority of the States to 

require the GS operator to comply with all well construction and monitoring 

requirements to protect the integrity of gas storage reservoirs. 

Second, as part of the site selection and GS permit application process, all 

natural gas storage projects within the AoR should be identified on the AoR map 

and assessments performed to determine the potential impact from CO2 or fluid 

migration to the gas reservoir. Such an assessment should also include 

analysis of potential leak paths through faulting, fracturing, or other 

migration paths from injected CO2 in formations in close proximity to gas 

storage reservoirs. 

Third, we would recommend that where GS and gas storage reservoirs are in close 

proximity that additional monitoring be required. We are also concerned about 

the potential impact of hydraulic fracturing of GS wells on natural gas 

storage. We believe that an analysis should be conducted based on the 

proximity (laterally and vertically) of the GS zone to existing gas storage 

reservoirs and the potential for communication with a gas storage reservoir. 

For this reason, we believe it is important that all records relating to well 

logs, cementing records, and casing strings and cementing operations of any GS 

wells drilled within the reservoir or protective perimeter boundaries of a gas 

storage field must be available and accessible to the public. Conversely, and 

for the same reasons, we believe information regarding the proximity of gas 

storage reservoirs to GS wells is equally important and should be readily 

available to the public to ensure the integrity of the CO2 injection operation. 

Individual Response: EPA believes that the extensive requirements for geologic site 

characterization (at §146.82), AoR evaluation (§146.84), and testing of the well during drilling 

(§146.87) are appropriate to ensure that permitting authorities have the necessary information to 

evaluate whether a specific site will allow safe injection of CO2. EPA adds that submittal and 

review of monitoring data (as required at §146.90) and the AoR reevaluation process 

(§146.84(e)) will provide an opportunity for an ongoing review of the site and a dialogue 

between the Director and the owner or operator to ensure that the project is being operated in a 

manner that protects USDWs from endangerment. 

Under §146.82(a)(2) owners or operators must identify all injection and production wells, which 

will most likely include evidence of and information about the location of natural gas storage 

21
sites. The Director must evaluate this information when determining whether to issue a permit. 

While the GS rule does not explicitly require the owner or operator to identify natural gas storage 

sites within the AoR, the Director may require additional site-characterization or data collection 

at his or her discretion. For example, the Director may require additional monitoring under 

§146.90(i) to ensure that GS does not interfere with existing natural gas storage projects. The site 

characterization requirements at §146.82 will also help determine the existence and locations of 

any faults and fractures. 

EPA is developing guidance on site characterization for GS projects to assist owners or operators 

and Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations to owners or operators regarding characterizing the regional geology 

and hydrogeology of a proposed GS site as well as performing the necessary geochemical, 

geomechanical, and geophysical analyses of the injection and confining zone. Additionally, EPA 

expects that this guidance will support permitting authorities as they evaluate initial permits for 

Class VI injection wells with technical assistance as needed. The guidance can be found on 

EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA expects permitting authorities to retain an administrative record for the project, which at the 

discretion of the permitting authority might be available online and at the authority's office. EPA 

encourages (but does not require) operators and permitting agencies to begin involving the public 

by providing information as early in the GS project development process as possible. 

In response to the comment that state gas agencies should be involved in permitting decisions, 

EPA clarifies that the decision to issue a permit rests with the agency implementing the Class VI 

Program, as identified in the state's approved primacy application. If a state or tribe chooses not 

to seek primacy for Class VI program implementation, EPA will directly implement the program 

for the state or tribe. However, the final rule includes a requirement that state and local oil and 

gas regulatory agencies and state agencies regulating mineral exploration and recovery must be 

notified when a draft Class VI permit is available for public comment, at §124.10(c)(1)(xi). 

Letter ID: 0151 Comment ID: 21851 Letter Lines: 547 to 583 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

Comment: J. The Use Of Horizontal Drilling Should Be Allowed And Encouraged. 

As the EPA has noted in the Proposed Rule, horizontal drilling is not typical 

in deep injection wells in the UIC program. However, horizontal wells have 

been used successfully for GS, such as the In Salah project in Algeria. Spectra 

supports the use of horizontal drilling, which has many advantages. For 

example, a horizontal well in a homogenous reservoir allows the operator to 

open up more porosity and permeability than one can achieve in a vertical well 

as the operator is capable of extending the length to be many times the 

horizontal thickness of the reservoir. This allows the operator to produce or 

inject over a greater length of reservoir at lower wellbore pressures. Whereas, 

a horizontal well in a heterogeneous reservoir has a greater probability of 

22
intersecting higher permeability streaks, fractures or other geologic features 

that will allow the operator to inject at higher rates, to reduce wellbore 

pressure or to access more reservoir per well. 

Importantly, greater reliance on horizontal drilling also improves the safety 

and containment of the disposal gas (fluid), as well as the economics of a CCS 

project as fewer wells are required to inject a given volume. Fewer wells 

equate to fewer penetrations through the containment zone and lowers the 

likelihood of leaks through the containment zone, either from leaks around the 

casing or from corrosion/erosion of wellbore tubulars later in the life of the 

well. As an exploration tool, horizontal drilling increases the ability to 

reach areas of the reservoir that an operator may not otherwise be able to 

reach using vertical drilling. As more porosity and permeability are opened 

up, the pressure differential across the injection face is reduced and 

therefore the ability to inject a given volume of gas in a single well bore 

increases as a ratio of the increased reservoir exposed. As well, by keeping 

the build section in the cap rock, potentials for bore holes to breach the 

integrity of the storage reservoir are reduced. Under this concept, fewer 

penetrations of the cap rock result in less potential for a breach to occur. 

Horizontal drilling is only one of a number of new technologies that are being 

developed for better management of a reservoir, whether it be for oil and gas 

production, gas storage, coal bed methane production or injection for disposal 

of waste fluids. EPA should support the use of all new technologies which 

contribute to better methods of CCS. 

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In 

the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. 

Letter ID: 0151 Comment ID: 21852 Letter Lines: 585 to 601 ; 1533 to 1536 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: III. EPA MUST ADDRESS THE LEGAL UNCERTAINTIES AND 

IMPEDIMENTS TO CCS. 

As has been well documented elsewhere, including a recent GAO report, [3] the 

legal uncertainties related to underground injection of CO2, including the 

possible application of CERCLA and RCRA, are a very real legal impediment to 

23
the viability of carbon capture and geologic sequestration. We agree with the 

GAO’s recommendation that EPA more comprehensively examine CERCLA and RCRA as a 

potential barrier to CCS. As discussed in greater detail below, we believe the 

Agency has sufficient authority to develop responsible policies and regulations 

that provide the requisite protection to owner/operators of GS operations while 

still ensuring the adequate protection of human health and the environment. 

Toward this end, we would ask the EPA to further examine and clearly articulate 

what it believes is the outer bounds of its statutory and regulatory authority 

to provide such legal certainty. If, in the event EPA does not believe it has 

such authority or, for whatever reason, is unwilling to invoke such authority, 

we would request the Administration and the Agency work with Congress to enact 

legislation to bring about the needed legal certainty. 

3 GAO Report, Climate Change, Federal Actions Will Greatly Affect the Viability 

of Carbon Capture and Storage As a Key Mitigation Option, REPORT TO THE 

CHAIRMAN ON THE SELECT COMMITTEE ON ENERGY INDEPENDENCE AND 

GLOBAL WARMING, 

HOUSE OF REPRESENTATIVES, GAO-08-1080 (September 2008). 

Individual Response: EPA agrees that any requirements for the CO2 stream should be clearly 

identified. EPA received many comments regarding the applicability of the RCRA regulations 

and statute to CO2 streams that are geologically sequestered under the final Class VI UIC well 

requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

The GS Rule is being promulgated appropriately under the SDWA. Injection wells are regulated 

under the authority of Part C of the SDWA (42 U.S.C. 300h et seq.). Under the SDWA, the 

underground injection of any "fluid" is subject to the requirements of the UIC program. "Fluid" 

is defined under 40 CFR 144.3 as any material or substance which flows or moves, whether in a 

semisolid, liquid, sludge, gas or other form or state, and includes liquids, gases, and semisolids 

(i.e., slurries) injected into the subsurface. EPA adds that comments related to requesting 

Congress for additional authority are outside the scope of this rulemaking. 

Letter ID: 0151 Comment ID: 21853 Letter Lines: 603 to 632 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: A. The Liability Regime Under CERCLA Is Inappropriate For GS And EPA Must 

24
Minimize To The Fullest Extent Of Its Authority; Alternatively, Congress Must 

Act. 

The potential application of the sweeping liability regime under the 

Comprehensive, Environmental Response, Compensation, and Liability Act of 1980 

("CERCLA") will have an absolute chilling effect on the underground injection 

of CO2. The threat of CERCLA litigation and the potential liability to a GS 

owner or operator is alone significant and could seriously discourage the 

siting and construction of a GS operation. Under CERCLA’s strict liability 

regime, an owner or operator may be held jointly and severally liable for 

response costs related to any release or potential release of a hazardous 

substance from a facility. In addition to federal and state enforcement 

actions, CERCLA also authorizes private parties to seek remediation costs from 

an owner/operator who is alleged to have caused an actionable release under 

CERCLA. Therefore, given the extensive size of the CO2 plume, covering tens of 

square miles, a private landowner within the AoR and whose property is situated 

above the CO2 plume could potentially assert a CERCLA claim against an 

owner/operator of a GS operation. In its proposed GS Rule, EPA states as 

follows: 

[W]hether or not there is a hazardous substance that may result in CERCLA 

liability from a sequestration facility depends entirely on the make-up of the 

specific CO2 stream and of the environmental media (e.g., soil, groundwater) in 

which it is stored. 

Unfortunately, the Proposed Rule leaves considerable uncertainty regarding 

potential CERCLA liability. See GAO Report, Climate Change: federal actions 

will greatly affect the viability of carbon capture and storage as key 

mitigation option, GAO-08-1080, September 2008. 

Individual Response: The Agency acknowledges the commenter's concerns regarding the scope 

and possible impacts of CERCLA liability on CCS activities, however EPA notes that the GS 

rule is not promulgated under CERCLA, therefore the applicability of that statute will not be 

determined under the SDWA or the terms of the GS rule, but rather according to the CERCLA 

statute itself and any implementing regulations that may apply. To the extent the commenter is 

seeking interpretations of RCRA or CERCLA, such interpretations are beyond the scope of this 

rulemaking. 

Letter ID: 0151 Comment ID: 21854 Letter Lines: 634 to 803 ; 1538 to 1577 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: We oppose the application of CERCLA liability to owner/operators of GS 

facilities, particularly where the owners/operators may have very little 

control, if any, over the migration of the CO2 plume or geochemical reactions 

post-injection. As the Agency has acknowledged, despite all the geologic and 

25
geochemical data that is developed as part of the UIC permitting process, there 

may be unknown and unanticipated geochemical reactions that occur underground 

post-injection that could constitute a "release" [4] under CERCLA, thereby 

triggering liability. Scenarios that could potentially constitute a release 

under CERCLA include: (1) migration of CO2 from the injection zone into 

another zone or outside the AoR; (2) migration of displaced brine or fluids 

outside the injection zone, (3) geochemical reactions within or outside of the 

injection zone, and (4) atmospheric releases of CO2. Subsurface releases that 

are geologically contained (releases (1) - (3) above), even if they migrate 

beyond the AoR or out of the injection zone, ordinarily will not result in a 

type of release that threatens the ambient environment or presents an imminent 

and substantial endangerment to human health and the environment, unless a USDW 

is endangered. 

It is important to emphasize that CO2 is itself not a "hazardous substance" 

under CERCLA nor under any other federal environmental law. However, as EPA 

points out, some of the impurities potentially contained in a CO2 stream, such 

as mercury and sulfuric acid, are hazardous substances even though their 

concentrations, according to EPA, are "expected to be very low." GS Rule at 

43503. Thus, the presence and possible release of these impurities could give 

rise to CERCLA liability. 

Spectra strongly believes that an owner/operator of a GS injection well who 

materially complies with the terms of its UIC permit as a general rule should 

not be subject to CERCLA liability. While there may be limited circumstances, 

such as a catastrophic release of CO2 to the atmosphere,[5] where CERCLA may be 

appropriate, we believe as a general matter CERCLA liability is not necessary 

and serves as a major deterrent to large-scale commercial deployment of GS. 

Consequently, we believe the Agency must seek to establish a "safe harbor" for 

those engaged in GS operations. Such safe harbor must include the CO2 and any 

impurities by clarifying minimum performance standards, employed technologies, 

or testing requirements, which if used, will exempt subsurface releases from 

CERCLA liability. Toward this end, the Agency has suggested that several 

enumerated defenses under CERCLA, such as the "federally permitted release" 

provision, may provide sufficient safe harbor. However, as discussed below, 

Spectra is concerned that this defense is woefully inadequate. 

B. EPA Must Clarify And Expand The Scope Of The "Federally Permitted Release" 

Defense Which Has Been Seriously Eroded By Court Decisions. 

Section 107(j) of CERCLA provides that any release that occurs pursuant to an 

approved federal permit or program is not subject to CERCLA liability.[6] This 

provision is known as the "federally permitted release" exemption. Among the 

list of 11 enumerated federally permitted releases is "any injection of fluids 

authorized under Federal underground injection control programs or State 

programs submitted for Federal approval . . . pursuant to part C of the Safe 

26
Drinking Water Act" (hereafter referred to as the "UIC Exemption"). 42 U.S.C. 

§ 9601(10)(G). Although the EPA cites the federally permitted release defense 

as a way for an owner/operator to avoid liability, this defense or statutory 

exemption has been seriously eroded in recent years by court decisions. See, 

e.g., Carson Harbor Vill, Ltd. v. Unocal Corp., 287 F. Supp. 2d 1118 (C.D. Cal. 

2003) (court found liability for releases that (1) are not expressly permitted 

(2) exceed the limitations of the permit or (3) occur at a time when there was 

no permit); State of Idaho v. Bunker Hill Company, 635 F.Supp. 665 (D. Idaho 

1986) (court held that a federally permitted release must be expressly 

identified in a permit). [7] 

Given that subsurface plumes from commercial GS operations may encompass 50 

square miles or more (roughly the size of the District of Columbia), this 

defense provides little comfort to an owner/operator of a GS injection facility 

who could incur tens of millions of dollars in response costs under CERCLA. In 

order for this statutory defense to have any meaningful application in the 

context of GS, and to provide the shield Congress intended, EPA must 

resuscitate this provision by providing further clarification of where and how 

it should apply. There is precedent for the Agency providing clarification of 

the scope and extent of the "federally permitted release" exemption in the 

context of air emissions with respect to reporting requirements for releases. 

See Guidance on the CERCLA Section 101(10)(H) Federally Permitted Release 

Definition for Certain Air Emissions, 67 Fed. Reg. 18899 (April 17, 2002). As 

EPA acknowledged in this guidance, it is difficult to establish a "bright line" 

for when releases qualify for the release exemption. However, we believe the 

Agency needs to do just that - establish a bright line. 

EPA has the authority and discretion to interpret and further clarify the scope 

and extent of the "federally permitted release" exemption to GS injection. A 

review of the 11 enumerated releases under 101(10) reveals dissimilar text, 

wherein some of the exemptions include phrases like "in compliance with," 

"subject to," "identified in," or "authorized under." The language used for 

the UIC Exemption, does not specifically limit the exemption to compliance with 

or the terms identified in an enforceable permit; rather, the UIC Exemption 

uses a much broader phrase "authorized under." Herein, the UIC Exemption 

applies to the (i) injection of fluids (ii) authorized under (iii) federal or 

an approved state UIC program. The EPA Environmental Appeals Board had 

occasion to construe these 11 exemptions and their dissimilar language and 

reasoned that Congress' use of different phrases must be given due effect. See 

In re Mobil Oil Corporation, EPCRA Appeal No. 94-2, 5 EAD 490, 1994 WL 544260 

(EAB, Sept. 29, 1994) (construing the meaning of the phrase "subject to" and 

the statutory purposes of the Clean Air Act and CERCLA).[8] 

Under the plain language of this UIC Exemption, the Agency has the authority to 

define more broadly (whether pursuant to a permit or outside the context of a 

permit) what fluids and releases are authorized by either the federal or state 

27
UIC program. This issue is significant in that the Agency has stated in the GS 

Rule: "Class VI requirements and permits will need to be carefully structured 

to ensure that they do not ‘authorize’ inappropriate hazardous releases . . . 

include clarifying if there are potential release from the well which are 

outside the scope of the Class VI permit." GS Rule at 43504. 

First, it is clear that the Agency believes there are certain releases that are 

"inappropriate" and that, if occur, would give rise to CERCLA liability. This 

raises many concerns and more questions than answers. What releases are deemed 

outside the scope of the Class VI permit? Is any subsurface release not 

specifically identified in a UIC permit an inappropriate release? Is an 

unanticipated geochemical reaction an inappropriate release or outside the scope 

of the Class VI permit? Is the migration of a CO2 stream out of the injection 

zone or AoR a release whether or not it endangers a USDW? How would an 

appropriate v. inappropriate release be determined? As evidenced from these 

questions, it is critical that the Agency clarify what is meant by the term 

"inappropriate" hazardous release and in what context such releases may be 

outside the scope of the UIC program. 

Based on the case law, for an owner/operator to maximize its shield under the 

exemption, all potential releases should be identified and authorized under the 

permit, including appropriate and inappropriate ones. Thus, there is clear 

tension between EPA’s statement that no inappropriate release be authorized by 

permit and the current state of the law which requires all releases be 

identified in a permit to benefit from the exemption. 

It is unambiguous from the plain text of the statute that Congress intended 

that releases authorized under the SDWA UIC program not be subject to CERCLA 

liability. It is also clear that the Agency has broad authority to clarify 

what releases should be covered under the GS Rule. Therefore, the Agency need 

not wait for the issuance of permits to decide on a case-by-case basis what is 

an appropriate or inappropriate release. EPA should make clear that all 

fluids injected pursuant to an authorized program or an approved permit will 

not give rise to CERCLA liability where the release occurs in and effects only 

subsurface formations and is geologically contained. The Agency could 

authorize, for example, the migration of the CO2 stream outside the injection 

zone or any other release that does threaten ambient air. 

The extension of the UIC Exemption to subsurface or geologically contained 

releases is appropriate in that subsurface releases of CO2 are fundamentally 

different than releases of CO2 to ambient air. Releases of sufficient 

quantities of CO2 to ambient conditions can pose serious health risks and even 

death. Whereas, the slow movement of a CO2 plume in confined subsurface strata 

ordinarily presents little, if any, imminent or substantial risk to human 

health or the environment. EPA has recognized the distinction in the nature 

and risks of subsurface and ambient releases of CO2. See GS Rule at 43498 

28
("geologic confining systems do not experience . . . rapid and complete 

turnover [of CO2]"). Thus, while the application of CERCLA may still be 

appropriate in the event of releases of CO2 to the ambient air, the statute is 

not necessary to address releases that involve only subsurface locations. 

Unlike the decision in In re Mobil, where the broad interpretation of the 

CERCLA air exemption would leave a gap in the government’s ability to respond 

to a release, in the case of a subsurface release from a GS injection well, no 

such gap would exist, as the Agency has broad authority under SDWA to respond 

appropriately. In addition to civil, criminal and administrative enforcement 

authorities under the UIC program, 42 U.S.C. § 300h-2, and the potential to 

levy substantial monetary penalties, the EPA Administrator has broad emergency 

powers under SDWA to respond to a threat to any source of underground drinking 

water. Specifically, Section 300i says: 

[T]he Administrator, upon receipt of information that a contaminant which is 

present in or is likely to enter a public water system or an underground source 

of drinking water . . . which may present an imminent and substantial 

endangerment to the health of persons, and that appropriate State and local 

authorities have not acted to protect the health of such persons, may take such 

actions as he may deem necessary in order to protect the health of such persons. 

42 U.S.C. § 300i 

Under this emergency authority, the Administrator make take whatever measures 

necessary to protect human health, including ordering any corrective action or 

replacement of drinking water supplies or commencing a civil action for 

appropriate relief, including a restraining order or permanent or temporary 

injunction. Thus, the Agency has adequate authority under SDWA to address any 

release or contamination that presents an endangerment. 

4 The term "release" is broadly defined to mean"any spilling, leaking, pumping, 

pouring, emitting, emptying, discharging, injecting, escaping, leaching, 

dumping, or disposing into the environment (including the abandonment or 

discarding of barrels, containers, and other closed receptacles containing any 

hazardous substance or pollutant or contaminant)." 42 U.S.C. § 9601(22). The 

term "release" specifically excludes "emissions from engine exhaust of a motor 

vehicle, rolling stock, aircraft, vessel, or pipeline pumping station engine." 

Although this exemption has not been interpreted by many courts, it does 

represent Congress’ clear intent to exempt CO2 emissions (and other impurities) 

from vehicles or vessels that might otherwise constitute a release under 

CERCLA. Arguably, it also denotes a qualitative distinction between CO2 and 

other hazardous substances for which Congress saw fit to apply CERCLA. 

5 If a catastrophic release of CO2 occurred, it would be the release of CO2 

itself, and not the minute constituents of other impurities contained in the 

CO2, that would arguably threaten human health and the environment. However, 

CO2 is not a hazardous substance and therefore would not trigger release 

29
reporting requirements under CERCLA or the Emergency Planning And Community 

Right-to-Know Act (EPCRA). Another regulatory regime may be more appropriate 

to deal with this potential scenario. 

6 Section 107(j) says "recovery by any person . . .for response costs or 

damages resulting from a federally permitted release shall be pursuant to 

existing laws in lieu of this section." 

7 See also Kurt Ryland, Saving A Disappearing Exemption To CERCLA Liability, 

N.Y.U. ENV. L.J. (1995). According to the author, federal courts have 

threatened the utility of the exemption through holdings that have weakened the 

protective shield provided by a permit. The author explores these decisions 

and how they leave many unanswered questions concerning the exemption's 

coverage. 

8 In the In re Mobil case, the defendant violated its Clean Air Act permit and 

EPA initiated an enforcement action for the defendant’s failure to provide 

notice of a release under EPCRA. Mobil argued that even if its emissions 

violated any specific permit limit, its emissions were subject to the federal 

permitting release exemption because the emissions were "subject to" a state 

issued implementation plan. Ultimately, the EAB rejected Mobil’s argument 

after concluding that Mobil’s argument would create a gap in the government’s 

ability to respond adequately to air releases of hazardous substances. 

Individual Response: EPA thanks the commenter for their detailed comments and 

recommendations regarding the applicability of CERCLA and the scope of the exemption for 

federally permitted releases, in response to the Agency’s request. CERCLA exempts from 

liability, under CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted releases” 

(FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Therefore, Class VI requirements and 

permits will need to be carefully structured to ensure that they do not “authorize” inappropriate 

releases, and would need to prevent potential releases from the well which are outside the scope 

of the Class VI permit. EPA reiterates that the GS rule is not promulgated under CERCLA, 

therefore the applicability of that statute will not be determined under the SDWA or the terms of 

the GS rule, but rather according to the CERCLA statute itself and any implementing regulations 

that may apply. To the extent the commenter is seeking interpretations of CERCLA and its 

related provisions, such as the definition of a federally permitted release, such interpretations are 

beyond the scope of this rulemaking. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

30
Regarding long term liability, once an owner or operator has met all regulatory requirements 

under Part 146 for Class VI wells and the Director has approved site closure pursuant to 

requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does 

not have authority to transfer SDWA or other legal liability for Class VI wells to the State or 

federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Letter ID: 0151 Comment ID: 21855 Letter Lines: 805 to 976 ; 1579 to 1594 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: C. RCRA Should Not Apply To GS Or, Alternatively, EPA Must Clarify And 

Minimize 

The Potential Applicability And Scope Of RCRA. 

We begin this section by noting that CO2 re-injection from gas processing is 

currently exempt from Subtitle C requirements of RCRA. Therefore, the 

following comments regarding the potential application of RCRA pertains to 

injection of CO2 from non-exempt processes and industries. 

Under the proposed rule, EPA has stated that it "cannot make a categorical 

determination as to whether injected CO2 is hazardous under RCRA." See Rule at 

43503. The Agency goes on to say that if the CO2 stream is considered 

hazardous under RCRA, then the more stringent UIC Class I requirements for 

31
injection of hazardous waste apply. Consequently, the Agency has defined 

"carbon dioxide stream" to exclude hazardous wastes as defined in 40 C.F.R. 

Part 261 (e.g., wastes that are characteristically hazardous due to pH or 

toxicity). 

For many of the same reasons set forth above for CERCLA, Spectra likewise 

believes that RCRA’s waste regulatory regime is completely unnecessary and 

inappropriate for geologic sequestration of CO2. First, CO2 is neither a 

pollutant, a solid waste,[9] nor a hazardous waste. Second, CO2 has been 

properly and safely injected for decades in the context of enhanced oil 

recovery (EoR), without the regulatory overlay of Subtitle C of RCRA. Third, 

there are other regulatory regimes that can apply to CO2 injection that make 

the application of RCRA unnecessary. 

1. RCRA Hazardous Waste Requirements Would Be Costly And Burdensome. 

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

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

apply. EPA initiated a rulemaking in 2002 to reduce the burdens associated 

with the RCRA hazardous waste program. 68 Fed. Reg. 61662, 61664 (Oct. 29, 

2003). The agency noted, "[t]he existing hazardous waste regulations require 

the submittal of 334 notifications, reports, certifications, demonstrations, 

and plans from generators and [treatment, storage, and disposal facilities] to 

demonstrate compliance with the RCRA regulations." Id. at 61664. Reporting 

requirements are just one example of RCRA’s burdens. Others include treatment, 

storage, and disposal facility requirements generally, waste manifesting, 

training requirements for transporters and handlers, citizen suit provisions, 

and the fact that hazardous waste regulation often increases one’s exposure to 

Superfund liability. 

While EPA seeks to downplay the potential applicability of RCRA, by opining 

that concentrations of impurities in a CO2 stream are "expected to be very low" 

there is no clear assurance that RCRA does not apply. As currently proposed, 

the EPA has shifted the burden to the owner/operator to determine whether its 

CO2 stream is not a hazardous waste under RCRA. The only way for an 

owner/operator to determine whether its stream is not a hazardous waste is to 

test the CO2 stream or apply "generator knowledge." To require testing for CO2 

streams would be overly burdensome and expensive, particularly given the 

diverse sources of CO2 streams and their varied composition. As well, the high 

variability of CO2 stream composition makes reliance upon "generator knowledge" 

risky if not entirely unworkable. 

2. EPA Has Authority To Exempt CO2 Under Its Contingent Management Approach. 

The Agency has authority under Subtitle C of RCRA to determine which wastes are 

subject to federal hazardous waste regulations. Section 3001 directs the 

32
Administrator of EPA to 

develop and promulgate criteria for identifying the characteristics of hazardous 

waste, and for listing hazardous waste, which should be subject to the 

provisions of this subchapter, taking into account toxicity, persistence, and 

degradability in nature, potential for accumulation in tissue, and other related 

factors such as flammability, corrosiveness, and other hazardous 

characteristics. Such criteria shall be revised from time to time as may be 

appropriate. 42 U.S.C. § 6921(a). 

It is clear from the language of Section 3001, that Congress left to the EPA the 

discretion to determine which hazardous wastes would be subject to federal 

regulations and which ones would be exempt therefrom. See Military Toxics 

Project v. EPA, 146 F.3d 948, 958 (D.C. Cir. 1998) ("Congress’ broad delegation 

to EPA to develop criteria for listing hazardous wastes . . . indicates that 

Congress intended the agency to have substantial room to exercise its 

expertise"). The criteria set forth above enable EPA to take into consideration 

the relative risks posed by different wastes (i.e., some wastes are by nature 

more toxic than others), the capacity for a waste to breakdown and thus become 

less toxic in the environment (i.e., some wastes degrade faster than others), 

how long it takes a waste to degrade, and the potential for human exposure and 

accumulation in tissue. The application of these criteria to CO2 weigh in the 

favor of exempting CO2 injection and disposal from hazardous waste regulations. 

EPA considers the risk of chronic and acute health effects from airborne 

exposure from properly operated CO2 injection as minimal. GS Rule at 43498. It 

likewise considers the risk of adverse impacts to ecosystems from properly 

managed GS injection activities as minimal. Id. Overall, the Agency believes 

that the risks to human health and the environmental from properly managed CO2 

injection activities are minimal. These risks EPA believes will be properly 

addressed and managed through the new Class VI UIC well program. 

Given the minimal risks from properly managed CO2 pursuant to SDWA’s authority, 

EPA should exempt CO2 streams entirely from RCRA hazardous waste regulations 

or, alternatively, establish a "safe harbor" for the injection of CO2, 

including impurities, by clarifying minimum performance standards or testing 

requirements. The concept of a blanket exemption is fully consistent with the 

Agency’s "contingent management" approach under RCRA, whereby certain low-risk 

wastes are exempted entirely from RCRA Subtitle C regulations. See EPA’s 

Contingent Management Technical Background Document, October 29, 1999. 

According to the Agency, 

EPA's longstanding regulatory criteria for determining whether wastes pose 

hazards that require regulatory control incorporate the idea that a waste that 

is otherwise hazardous may not present a hazard if already subject to adequate 

regulation. See, e.g., 40 CFR 261.11(a)(3)(x), which requires EPA to consider 

33
action taken by other governmental agencies or regulatory programs based on the 

health or environmental hazard posed by the waste.) Thus, where a waste might 

pose a hazard only under limited management scenarios, and other regulatory 

programs already address such scenarios, EPA is not required to classify a waste 

as hazardous waste subject to regulation under Subtitle C. 62 Fed. Reg. 6622, 

6636 (Feb. 12, 1997). The D.C. Circuit Court of Appeals has upheld EPA’s 

contingent management approach on at least three occasions. Edison Electric 

Institute v. EPA, 2 F.3d 438 (D.C. Cir. 1993) (court upheld a temporary 

exemption from Subtitle C for petroleum-contaminated media based on the fact 

that the potential hazards of such materials are already controlled under the 

underground storage tank regulations); NRDC v. EPA, 25 F.3d 1063 (D.C. Cir. 

1994) (court upheld EPA's finding that alternative management standards for used 

oil promulgated under RCRA section 3014 reduced the risks of mismanagement and 

eliminated the need to list as a hazardous waste); Military Toxics Project v. 

EPA, 146 F.3d 948, 958 (D.C. Cir. 1998) (court upheld EPA’s military munitions 

rule as obviating the need to apply RCRA’s hazardous waste regulations). 

As EPA has emphasized before, even the legislative history of Subtitle C 

supports the Agency’s contingent management concept. In a House Report, 

Congress stated that "the basic thrust of this hazardous waste title is to 

identify what wastes are hazardous in what quantities, qualities, and 

concentrations, and the methods of disposal which may make such wastes 

hazardous." 62 Fed. Reg. 6622, 6636 (citing H. Rep. No. 94-1491, 94th Cong., 

2d Sess.6 (1976), reprinted in A Legislative History of the Solid Waste 

Disposal Act, as Amended, Congressional Research Service, Vol.1, 567 (1991)). 

3. CO2 Geologic Sequestration Should Be Subject To Bevill Exemptions. 

Further argument for a RCRA exemption, and consistent with the concept of 

contingent management, is the fact that Congress exempted certain wastes from 

regulation under Subtitle C of RCRA. In 1980, when Congress amended the Solid 

Waste Management Act, it opted to temporarily exempt certain high-volume low 

toxicity wastes from the Subtitle C hazardous waste regulatory scheme, 

including, among others, "fly ash waste, bottom ash waste, slag waste and flue 

gas emission control waste generated primarily from the combustion of coal or 

other fossil fuels" (hereafter referred to as "FFC" wastes) 42 U.S.C. § 

6921(b)(3)(A)(i) (emphasis added). This amendment (a/k/a the Bevill 

Amendment), was prompted in large measure by Congress’ concern regarding the 

potential added recycling costs (estimated at $3B annual increase) of 

subjecting fossil-fuel combustion wastes to hazardous waste requirements. 58 

Fed. Reg. 42466, 42468 (Aug. 9, 1993). Under the Bevill Amendment, Congress 

directed EPA to make a regulatory determination on whether or not FFC needed to 

be regulated under Subtitle C. 

As part of the Agency’s regulatory determination, EPA conducted a three-part 

technical analysis evaluating whether (1) the FFC wastes posed human health or 

34
environmental problems, (2) whether the wastes could pose significant risks at 

any site under current or plausible management scenarios, and (3) whether the 

wastes exhibited any of the characteristics of hazardous waste. EPA’s 

rationale for the iterative analysis was to determine, first, whether the 

wastes posed serious risks, second, whether current management practices and 

federal and state regulatory controls were adequate to manage the risks and, 

third, the economic impact on the industry before regulating the waste as 

hazardous. EPA identified a number of sites with unlined lagoons and ponds 

where FFC wastes clearly had resulted in extensive ground water impacts from 

arsenic, barium, cadmium, chromium, fluoride, lead, mercury, nickel and 

selenium that had leached into the water. Id. at 42475. EPA concluded, 

however, that such sites were ordinarily not located near populations and 

drinking water systems. EPA also concluded that up to 7% of the FFC wastes 

exhibited the characteristics of hazardous waste based on toxicity. Despite 

these negative findings, EPA ultimately made the determination that more 

stringent regulations were not necessary or desirable. 

Based on a plain language reading of the Bevill Amendment, it appears that CO2 

falls within the scope of the exemption as a flue gas emission control waste. 

Similar to FFC wastes, CO2 are a high-volume low toxicity waste when properly 

managed in underground formations. Therefore, we believe the Bevill Amendment 

presents the Agency with another viable option for exempting CO2 from Subtitle 

9 For a waste to be a hazardous waste, it must first be a solid waste. There 

is a legitimate question whether CO2 is even a solid waste based on the 

statutory definition of "solid waste" expressly including "contained gaseous 

material." 42 U.S.C. § 1004(27). EPA has consistently interpreted this 

provision as excluding uncontained gases from the definition of solid waste. 

See, e.g., 47 Fed. Reg. 27530 (June 24, 1982) (gases from fume incinerators not 

subject to RCRA, because fumes are not a solid waste); 54 Fed. Reg. 50973 (Dec. 

11, 1989) (uncontainerized gases are excluded from RCRA); In re BP Chemicals 

America, Inc., RCRA Appeal No. 89-4, 1991 WL 208971, at *2 (Admin., Aug. 20, 

1991) (Administrator rejected the argument that otherwise uncontained gas 

passing through piping or the facility made it "contained" and subject to 

RCRA). While CO2 emissions would clearly fit into the "uncontained" gas 

classification, what is unclear is whether the Agency’s interpretation would 

extend to CO2 subsequently captured and injected into an underground formation. 

We believe this merits further clarification by the Agency on what constitutes 

an uncontained vs. contained gas. 

Individual Response: EPA agrees that any requirements for the CO2 stream should be clearly 

identified. EPA received many comments regarding the applicability of the RCRA regulations 

and statute to CO2 streams that are geologically sequestered under the final Class VI UIC well 

requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

35
requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

Letter ID: 0151 Comment ID: 21856 Letter Lines: 977 to 1110 ; 1596 to 1616 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: C. 

D. EPA Should Create A Subclass Of Class II Or Class VI UIC Wells For Sour CO2 

Injection Operations Irrespective Of Whether Such Gas Is From Hydrocarbon 

Production. 

Raw natural gas often contains significant impurities such as CO2, H2S, and N2. 

Sour CO2 is also generated as a by-product from the gas sweetening process used 

to produce natural gas suitable for transmission and sale. The composition of 

the sour CO2 mixture is highly variable based on geological conditions, the 

composition of the raw natural gas, and the processing technology. Raw gas 

that is naturally higher in H2S results in higher concentrations of H2S as a 

percentage composition of the sour CO2. Although, in Western Canada, CO2 often 

accounts for most of the sour CO2 composition (i.e., as much as 80%), at some 

facilities, such as our Kwoen plant, the CO2 composition of the gas waste is 

only around 20%. 

Historically, most of the waste gases from natural gas processing were disposed 

of by flaring, but more recently, great strides have been made toward injecting 

the gas wastes into deep geologic formations. Thus, the injection and longterm storage of sour CO2 is an appropriate analog to CO2 geological 

sequestration. Sour CO2 disposal is not only an integral part of natural gas 

production, but the management and disposal of such gases will be an integral 

part of making GS technologies viable as well. The IPCC noted that it will be 

important to reduce the acidic gas components of flue gas from coal-fired power 

plants before CO2 removal, because the acidic gas reduces the absorption 

capacity of the solvent used to remove CO2. Thus, power plants that seek to 

employ GS technologies will be required to eliminate and dispose of these gases 

along with the CO2. It is unclear whether or not the acidic qualities of flue 

gases would constitute a characteristic hazardous waste based on low pH or 

toxicity. Notwithstanding, UIC injection requirements that govern CO2 disposal 

must govern acidic gases of all kinds as part-and-parcel to the GS Rule. These 

requirements must be flexible and workable, similar to those of Class II 

requirements. 

36
Despite the potentially hazardous characteristics of sour CO2, Section 3001(b) 

(2)(A) of RCRA currently exempts sour CO2 from Subtitle C hazardous waste 

regulations provided the gas is related to oil or natural gas exploration or 

production and processing.[10] Although not regulated under RCRA, sour gas 

injection for purposes of disposal is regulated under the UIC Class II well 

program. EPA has raised some concern regarding the toxicity and potential 

safety of sour CO2 in the context of the UIC program.[11] However, the 

management and injection of such gases has been performed safely over the last 

two decades. And, in fact, the IPCC has equated the health, safety and 

environmental risks of sour CO2 disposal with that of GS operations, if 

properly managed.[12] The history and strong safety record of sour CO2 

operations in North America provides a compelling argument to exempt CO2 

injection from other non-exempt sources and activities. 

In the U.S., the management and disposal of sour CO2 has largely been 

implemented at the state level pursuant to both federal UIC and state 

underground injection laws. Some states like Wyoming regulate sour CO2 

injection solely pursuant to the UIC Class II requirements. Whereas, other 

states, such as Texas, overlay the UIC program requirements with additional 

state law requirements. For example, Texas law governs injection where the 

H2S content is at least 100 parts per million. See 16 TEX. ADMIN. CODE § 

3.36(a)(2)(C) (2008). In addition to the baseline UIC Class II requirements, 

operators are required to assess the potential impact of releases by 

determining a "radius of exposure" based on concentrations of 100 ppm and 500 

ppm. They are also required to post warning signs in public areas, provide 

wellhead security, and use corrosion-resistant materials. Contingency planning 

to prepare for and respond to potentially dangerous releases is major component 

of sour gas injection operations. 

Canada has far more experience with sour CO2 disposal than the U.S. As noted 

earlier, in Western Canada, as of 2007, there were 44 sour CO2 injection 

projects operational, injecting into 51 different formations. A total of 27 of 

these operations inject sour CO2 into deep saline formations, while 19 sites 

inject into depleted oil and gas reservoirs, and the remaining sites inject 

into the water leg of depleted oil and gas reservoirs. See Carbon Dioxide 

Capture and Storage, IPCC, Annex I, Properties of CO2 and Carbon-Based Fuels, 

November 2005. Carbonates form the reservoir at 29 sites and quartz-rich 

sandstone at 21 sites. The overlying unit in most formations is shale, and the 

others consist of tight limestone, evaporites, and anhydrites. Since the early 

1990s, when injection first commenced, 2.5 Mt of CO2 and 2.0 Mt of H2S have 

been safely injected without any detectable leaks. 

Similar to the U.S., Alberta has a program to regulate activities related to 

the injection and disposal of fluids, although there are differences between 

the two programs. The Energy Resources Conservation Board (ERCB), an 

37
independent quasi-judicial agency of the Government of Alberta, is responsible 

for regulating Alberta’s energy resources (oil, natural gas, oil sands, coal) 

and pipelines, as well as approving applications for oil and gas operations 

including underground injection.[13] 

The ERCB is responsible for reviewing and approving all injection wells 

consistent with specific technical requirements pertaining to cementing and 

casing, logging to evaluate hydraulic isolation and casing integrity, and other 

testing for initial pressure, monitoring, area of review, and operating 

parameters. The ERCB has the authority to require a well to be abandoned where 

the location or condition of that well may become a source of water pollution. 

Alberta’s philosophy for deepwell disposal of oilfield and industrial wastes is 

a safe and viable disposal option where wells are properly constructed, 

operated, and monitored. Regulatory activities for sour gas focus on the 

following: 

. wellbore integrity to ensure initial and ongoing containment of the disposal 

fluid to protect groundwater; . formation suitability and hydraulic containment 

to ensure initial and ongoing confinement of the disposal fluid to protect 

groundwater; . suitability of the waste stream for deepwell disposal 

considering the nature of the fluid, the integrity of the well, and alternative 

waste management options; . maximum H2S fraction, maximum wellhead injection 

pressure, and rate and maximum injection volume; and . reporting and 

manifesting of disposed wastes. 

In addition, operators of sour gas processing facilities must submit monthly 

reports which provide detailed information regarding the nature of the 

operations, including the amount and quality of the sour CO2 injection. 

Sour CO2 disposal, storage or cycling operations in Alberta are regulated as a 

Class III well (different than UIC Class III), which under Alberta’s laws are 

wells primarily used for the injection of hydrocarbons or inert or other gases. 

On balance, the injection of sour CO2 is regulated no differently than 

hydrocarbons. Similar to the U.S., sour CO2 disposal is not managed as a 

hazardous waste, which is regulated under Alberta’s Class Ia well requirements 

that are the most stringent. 

Under Alberta’s regulations, matters of fluid-fluid, fluid-equipment, and 

fluid-formation compatibility are left primarily to the disposal well operator, 

with provincial regulators relying on operating and monitoring requirements to 

provide for early detection and mitigation of potential problems. Alberta 

prohibits the subsurface injection of numerous wastes, including municipal or 

industrial sewage, lube oils, spent solvents, diesel invert drilling fluids, 

and surface run-off water that meets surface discharge criteria (some of these 

prohibited because they are treated as recyclable). All other waste fluids, 

including sour CO2, are suitable for deepwell disposal if they have a pH 

38
between 4.5 and 12.5. 

Based on the collective experience of U.S. and Canadian operators involving the 

safe disposal of many metric tons of sour CO2 over the last two decades, EPA 

should consider developing a subclass of wells under Class II or Class IV for 

the injection of sour CO2. There is simply no compelling basis for the EPA to 

regulate any acidic gases as hazardous waste under the burdensome Class I 

requirements. 

10 See U.S. EPA, Regulatory Determination for Oil and Gas Geothermal, 

Development and Production Wastes, 53 Fed. Reg. 254476, 25454 (July 6, 1988). 

EPA made the regulatory determination in 1988 to exempt sour CO2 from hazardous 

waste requirements. Presumably, sour CO2 would be subject to RCRA’s hazardous 

waste requirements if they were not generated during oil and gas production. 

11 See Vulnerability Evaluation Framework for Geologic Sequestration of Carbon 

Dioxide, U.S. EPA Technical Support Document, Report No. EPA430-R-08-009, July 

10, 2008. 

12 According to the IPCC, "[w]ith appropriate site selection based on available 

subsurface information, a monitoring program to detect problems, a regulatory 

system, and the appropriate use of remediation methods to stop or control CO2 

releases if they arise, the local health, safety and environment risks of 

geologic storage would be comparable to risks of current activities such as 

natural gas storage, [enhanced oil recovery], and deep underground disposal of 

acid gas." IPCC 2005. 

13 See Injection and Disposal Wells, Well Classifications, Completions, Logging 

and Testing Requirements, ERCB, March 1994. Available at 

http://www.ercb.ca/docs/ Documents/directives/Directive051.pdf. 

Individual Response: The Agency believes that the nature and risks of CO2 injection for the 

primary purpose of long-term storage poses different risks than those associated with injection 

for the primary purpose of EOR, and therefore has developed new Class VI regulations to 

address these unique risks. For example, the volume of CO2 anticipated to be injected for longterm storage is significantly greater than for EOR operations. Reservoir pressure conditions will 

also be different, for example, Class VI injection operations involve larger volumes of CO2 that 

will likely have higher pressures within their storage formations than Class II ER projects. EPA 

adds that most sour gas (acid gas) injection in the U.S. is permitted as Class II as defined under 

40 CFR §144.6 of the UIC regulations because the sour CO2 is typically injected associated with 

oil and gas exploration. The GS requirements are not overly burdensome and EPA expects the 

tailored permitting, siting, construction, operation, monitoring, and post-injection site care 

requirements in the GS rule to prevent leakage from injection formations and protect USDWs. 

EPA has taken the position that injection of CO2 for the primary purpose of enhancing oil and 

gas recovery should remain under the Class II Program because of the differences in risk profiles 

39
between EOR and long-term storage of CO2. The Agency disagrees that wells injecting CO2 for 

the primary purpose of long-term storage should be regulated under Class II requirements. EPA 

recognizes that the oil and gas industry has decades of experience injecting CO2 for the purpose 

of EOR, and that sites used for EOR may be suitable for GS and may be among the first Class VI 

permitted sites. EPA also recognizes that a by-product of EOR activities is that a certain 

percentage of the CO2 is trapped in the receiving formation. 

Letter ID: 0151 Comment ID: 21877 Letter Lines: 1112 to 1166 ; 1618 to 1629 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment Code: 5000 2.8 Proposed Well Plugging and Post-Injection Site Care Requirements 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: IV. EPA MUST DEVELOP A FLEXIBLE FRAMEWORK TO ADDRESS POSTINJECTION SITE CARE, 

FINANCIAL ASSURANCE, AND LONG TERM LIABILITY THAT ELIMINATES 

OBSTACLES TO 

COMMERCIAL-SCALE DEPLOYMENT OF CCS. 

Numerous studies and commentators have recognized that the principle obstacle 

to commercial-scale deployment of CCS is regulatory uncertainty over the 

capture, transport, injection, and storage of CO2. As stated by a recent GAO 

report: 

The IPCC, two federal advisory committee reports, and many stakeholders we 

contacted agreed that key regulatory and legal issues will need to be addressed 

if CCS is to be deployed at commercial scale. Among these issues are (1) 

confusion over the rules for injecting large volumes of CO2, (2) long-term 

liability issues concerning CO2 storage and potential leakage, (3) how property 

ownership patterns may affect CO2 storage, and (4) how the Clean Air Act will 

apply to facilities that capture CO2. - EPA’s 2007 UIC workshop, attended by 

more than 200 stakeholders, revealed liability associated with unintended 

migration of injected CO2 to be a critical concern. Similarly, 19 of the 20 

stakeholders we interviewed told us that liability related to CO2 storage was a 

large or very large barrier to deployment of CCS at a commercial scale, with 

some noting that liability concerns have already negatively impacted companies’ 

ability to initiate CCS projects. For example, two stakeholders reported that 

these concerns had already made it difficult to obtain insurance for CCS 

projects. They noted specifically that insurers have difficulty writing 

insurance policies because of uncertainties associated with and limited data 

available for CCS, while another added that investors will not support projects 

like CCS if they expose them to unlimited and undefined long-term liabilities, 

especially when future revenue streams are uncertain.[14] 

The promise of CCS as a strategy to address climate change and promote national 

40
energy security hinges on resolving this regulatory uncertainty in a way that 

does not place an unreasonable burden on site owners and operators that would 

effectively prevent the development of commercial-scale CCS projects in the 

United States. The EPA has the authority under SDWA and the UIC Program to 

create a flexible framework to address issues such as post-injection site care, 

financial assurance, and long-term liability in a manner that places enough 

responsibility on owners and operators to ensure that all applicable best 

practices are followed, but not so much that it becomes virtually impossible to 

secure the requisite financing and insurance needed for CCS projects to be 

commercially viable. 

The potentially unique challenge of resolving the regulatory uncertainty 

currently inhibiting the development of CCS projects, if done with inadequate 

attention to existing market dynamics and economic realities, likely will 

preclude any commercial-scale deployment of CCS and undermine its effectiveness 

as a strategy to reduce greenhouse gas emissions. Addressing the regulatory 

uncertainty surrounding post-injection site care, financial assurance, and 

long-term liability effectively boils down to four overarching questions 

confronting entities involved in the capture, transport, injection, and storage 

of CO2: (1) length of the post-injection site care time period; (2) aspects of 

post-injection site care for which entities will be responsible; (3) 

availability and suitability of different risk management instruments for 

meeting financial assurance requirements; and (4) permanent transfer of all 

liability to the State. Spectra’s comments on post-injection site care, 

financial assurance, and long-term liability focus broadly on these issues. 

14 GAO Report, Climate Change, Federal Actions Will Greatly Affect the 

Viability of Carbon Capture and Storage As a Key Mitigation Option, Report to 

the Chairman on the Select Committee on Energy Independence and Global Warming, 

House of Representatives, GAO-08-1080, September 2008, at 23, 25. See also 

Capturing King Coal: Deploying Carbon Capture and Storage Systems in the US at 

Scale, WORLD RESOURCES INSTITUTE (2008) at 24 ("In the event of an accident or 

damage years after the well is closed, who is financially and legally 

responsible? Current law and policy is unclear on this matter, and more 

generally on the matter of responsibility for long-term measuring and 

monitoring of the site. In particular, the degree to which private parties 

remain responsible, or the government assumes a measure of responsibility, is 

important."). 

Individual Response: EPA acknowledges the commenter¿s request for certainty regarding postinjection site care (PISC) requirements for GS wells. However, EPA believes that a certain 

amount of flexibility is appropriate for setting the PISC timeframe, given the variety of 

circumstances that may occur at GS sites. The PISC requirements in the final GS rule, as 

specified in §146.93(b), incorporate a combination of a fixed timeframe and a performance 

standard approach. The GS rule offers owners or operators flexibility regarding the duration of 

the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

41
timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters¿ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA recognizes that there are challenges associated with financial responsibility for GS projects. 

However, the Agency believes that in order to protect USDWs from endangerment under the 

SDWA operators must demonstrate under §146.85 that financial resources are available to plug 

the injection well and provide PISC when injection begins. 

Under the final GS rule owners or operators may choose from a variety of financial instruments 

to demonstrate that they meet the financial responsibility requirements under §146.85, provided 

the Director determines that the demonstration is adequate to pay for each activity for which 

financial responsibility is required. EPA is developing guidance (available on EPA¿s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) to help owners or operators, 

permitting authorities, and third parties choose and evaluate appropriate financial methods. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. The final 

rule requires an owner or operator to conduct monitoring as specified in the Director-approved 

PISC and site closure plan following the cessation of injection until he or she can demonstrate 

that the GS project no longer poses an endangerment to USDWs. 

Once an owner or operator has met all requirements under Part 146 for Class VI wells and the 

Director has approved site closure pursuant to §146.93, the owner or operator will generally no 

longer be subject to enforcement for regulatory noncompliance. Furthermore, the financial 

instrument required under §146.85 will be released if it was not used. However, even if site 

closure is approved, an owner or operator may be held liable for regulatory noncompliance (e.g., 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for noncompliance even after site closure if the Director relied on erroneous 

information (e.g., erroneous modeling data) provided by the owner or operator when approving 

site closure. 

Additionally, an owner or operator may always be subject to any action, such as administrative 

orders or civil actions, the Administrator deems necessary under §1431 of the SDWA after site 

closure if there is unanticipated migration towards or into a USDW that causes or threatens 

42
imminent and substantial endangerment to public health. If the owner or operator fails to comply 

with the order, he or she may be subject to a civil penalty for each day such violation occurs or 

failure to comply continues. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

pursuant to §144.38 whereby all potential liabilities associated with meeting the requirements of 

that permit are transferred to that new owner or operator. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, the Clean Air Act, 42 

U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. 

EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the 

State or federal government or a third-party fund. See the final rule preamble for further 

discussion of EPA's final approach. 

Letter ID: 0151 Comment ID: 21878 Letter Lines: 1168 to 1216 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: A. The Director Should Have the Discretion To Shorten The Post-Injection Site 

Care Period, But Not Extend It. 

EPA is proposing a post-injection site care period of 50 years. The Director 

would have discretion to extend this period if after 50 years USDWs still face 

potential endangerment or modeling and monitoring results demonstrate that the 

CO2 plume and pressure front have not yet stabilized. The Director also could 

reduce this period if data on pressure, fluid movement, mineralization, and/or 

dissolution reactions indicate that the plume and pressure front have ceased 

and the injectate does not pose a risk to USDWs. EPA requested comment on the 

proposed use of a tentative 50-year fixed timeframe that could be modified at 

the Director’s discretion based on monitoring and modeling data. 

Spectra supports EPA’s approach granting the Director discretion to adjust the 

timeframe based on the risk posed to USDWs. This approach takes into account 

the site-specific nature of CCS projects and recognizes the importance of 

creating a rule that does not place unnecessary regulatory, financial, or 

technical burdens on site owners and operators. However, Spectra proposes 

limiting Director discretion to the ability to shorten the post-injection site 

care period, upon meeting certain performance-based criteria that indicate the 

CO2 plume has stabilized and poses no recognizable risk to USDWs. This creates 

an incentive for project operators to adhere to best practices and could 

potentially encourage CCS project development. 

Spectra respectfully disagrees with granting the Director the discretion to 

extend the post-injection site care period beyond the fixed, pre-determined 

time period, on grounds that this places an unreasonable and potentially 

43
prohibitive financial risk on site operators. Specifically, owners or 

operators whose post-injection site care period is extended may be unable to 

secure additional financial assurance to cover the additional period of time. 

EPA cannot assume that owners or operators would be able to renew or extend the 

risk management instrument it procured prior to commencing injection and 

storage operations, nor can it assume that an owner or operator would be able 

to secure a new risk management instrument in the market. The possibility of 

an extension creates a risk for owners or operators that they may have to 

finance post-injection site care well beyond the default period, which would 

increase project costs and potentially inhibit CCS project development 

altogether. Furthermore, the extension of a post-injection site care period 

for an owner or operator that is no longer solvent exposes the public to 

unnecessary risk and would require governmental intervention. Rather than the 

possibility of an extension at the Director’s discretion, Spectra believes that 

a fixed post-injection site care period with the possibility of it being 

shortened upon meeting certain performance criteria that are evaluated on a 

site-by-site basis creates an incentive for operators to adhere to best 

practices and removes what would be a major deterrent from CCS project 

development. Spectra further believes that EPA should develop such performance 

criteria as soon as possible and in a manner that provides a realistic 

possibility that sites with stabilized CO2 plumes would qualify for a shorter 

post-injection site care period. 

Individual Response: EPA disagrees that the Director should not have discretion to lengthen the 

post-injection site care monitoring period. EPA believes that 50 years is an appropriate default 

post-injection site care timeframe in most cases. However, EPA recognizes that, in some cases, 

the post-injection site care timeframe may need to be lengthened based on site-specific 

circumstances. For instance, if after 50 years, monitoring data indicates that the CO2 plume is 

still moving and may endanger a USDW, monitoring should continue on a regular basis, as 

specified in §146.93(b)(2). 

Because of the variety of site-specific circumstances at GS sites, EPA believes that Directors, in 

consultation with operators, will be in the best position to determine whether additional postinjection site care monitoring is needed (or whether the timeframe may be shortened), based on 

the circumstances of a particular project. EPA expects this decision to be made based on relevant 

site data and in consultation with all potentially impacted parties. 

Letter ID: 0151 Comment ID: 21879 Letter Lines: 1218 to 1293 ; 1631 to 1634 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: B. EPA’s Selection Of A 50-Year Post-Injection Site Care Period Is Arbitrary. 

Spectra respectfully disagrees with EPA’s selection of a 50-year default 

timeframe. As an alternative, Spectra recommends that EPA adopt a postinjection site care period of 30 years, similar to that used under RCRA for 

44
post-closure care for hazardous waste management units, 40 C.F.R. § 264.117, 

after which time all responsibility and liability would transfer to the State. 

The Director should be granted discretion to shorten this timeframe upon a 

showing that certain performance criteria are met that indicate USDWs are not 

at any recognizable risk, as discussed more fully above.[15] 

A 30-year timeframe with Director discretion to shorten represents a better 

approach because it provides greater regulatory certainty for owners and 

operators, financiers, insurers, and other entities involved in CCS projects.[16] 

By contrast, a 50-year period that could be extended or reduced depending upon 

periodic assessments of the CO2 plume creates significant uncertainty, 

subjecting owners and operators to a post-injection site care period that 

either could end at any time after approximately 10 years or continue 

indefinitely up to and beyond 100 years. In practice, it is far easier for 

owners and operators to plan for a 10-year period with the possibility of an 

extension than a 50-year period that could fluctuate in either direction at the 

Agency’s discretion, as discussed more fully above. 

Furthermore, with respect to USDW endangerment, projects with plumes likely to 

stabilize within 10 years represent the safest types of projects. A 50-year 

post-injection site care period would place an undue regulatory and financial 

burden on these safest of projects. Even with Director discretion to shorten 

this time period, owners and operators nevertheless would have to plan for a 

post-injection site care period of at least 50 years, significantly affecting 

the prospective costs of the project. By comparison, a 30-year timeframe with 

Director discretion to shorten would seem to favor the development of projects 

likely to have CO2 plumes that stabilize early and avoid an unnecessarily long 

post-injection site care period. Similarly, the potential of reduced 

regulatory and financial burdens that would accompany a 30-year period with 

Director discretion to shorten creates incentives for project owners and 

operators to develop and manage projects in a way that maximizes the likelihood 

of the CO2 plume stabilizing early. 

For the foregoing reasons, the EPA’s 50-year post-injection site care period is 

arbitrary and risks adding to the barriers and obstacles that are currently 

preventing commercial-scale deployment of CCS. A 30-year period with Director 

discretion to shorten would provide the same level of protection for USDWs 

while minimizing regulatory and financial burdens on site owners and operators. 

C. After The Post-Injection Site Care Period And Determination That The CO2 

Plume Has Stabilized, Owners And Operators Should Be Released From All Site Care 

Responsibility, Such As Monitoring And Verification Requirements, And Any 

Financial Assurance Instruments Should Be Released. 

The GS Rule provides that owners or operators must demonstrate and maintain 

financial responsibility for certain corrective actions described in 40 C.F.R. 

45
§ 146.84 of the Rule. The GS Rule releases owners and operators from financial 

responsibility requirements at the conclusion of the post-injection site care 

period once the Director has determined that the injected fluid no longer poses 

a threat of endangerment to USDWs. 

Spectra supports EPA’s approach to releasing owners and operators from any 

further financial responsibility requirement at the conclusion of the postinjection site care period and upon a determination by the Director that the 

CO2 plume poses no further risk to USDWs. Establishing firm and discrete 

limits for post-injection obligations on behalf of owners and operators is 

essential to the viability of commercial-scale CCS. Open-ended requirements 

that could continue indefinitely, even after a showing that the CO2 plume has 

stabilized, would impose an unreasonable burden and likely inhibit project 

development. 

Spectra also proposes that owners and operators be released from any monitoring 

or verification requirements at the conclusion of the post-injection site-care 

period and upon a showing that the CO2 plume has stabilized. This approach 

would have the effect of dovetailing the responsibilities of owners and 

operators in the post-injection site care period with the transfer of long-term 

liability to the State. As discussed more fully below, Spectra believes that 

the eventual transfer of long-term liability to the State should encompass all 

potential liability - both anticipated site care responsibilities, such as 

monitoring and verification requirements, as well as any unanticipated 

migration of the CO2 plume and potential endangerment of USDWs. 

15 Modeling results indicate that a CO2 plume will stabilize within 10 to 100 

years after the cessation of injection. See Computational Modeling of 

Underground Injection of Carbon Dioxide for Determine of Are-of-Review and 

Potential Risk to Underground Sources of Drinking Water, U.S. EPA (2008). 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive in most cases or arbitrary. EPA proposed a default timeframe of 50 years based on a 

review of research studies, industry reports, and existing environmental programs. This analysis 

was included in an EPA background document available in the federal docket, "Computational 

Modeling of Underground Injection of Carbon Dioxide for Determination of Area-of-Review 

and Potential Risk to Underground Sources of Drinking Water." EPA assessed various default 

timeframes based on additional review of research studies and evaluation of public comments. 

While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the 

commenters provided sufficient data to warrant a change in the proposed timeframe. While the 

10- or 30-year timeframe suggested by some of these commenters may be within the timeframe 

suggested in some studies, EPA believes that the potential risks of endangering USDWs will 

likely not decline within these timeframes and available data, including data submitted by 

commenters, do not support a different default timeframe. However, EPA recognizes that 

alternative timeframes may be appropriate under limited, specific circumstances, which is why 

EPA is providing the Director discretion to approve an alternative post-injection site care 

46
timeframe as long as the owner or operator can meet the requirements provided at §146.93(c). 

The GS rule offers owners or operators flexibility regarding the duration of the PISC timeframe 

by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the 

PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording 

the Director discretion to allow a Class VI well owner or operator to demonstrate, based on 

substantial data during the permitting process, that an alternative PISC timeframe may be 

appropriate if it ensures non-endangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA agrees that owners or operators should not be subject to additional monitoring or financial 

responsibility requirements following site closure. The final rule releases owners or operators 

from these requirements once closure has occurred. 

Letter ID: 0151 Comment ID: 21880 Letter Lines: 1295 to 1401 ; 1636 to 1661 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: D. After The Post-Injection Site Care Period And Determination That The CO2 

Plume Has Stabilized, Owners And Operators Should Not Be Liable For 

Unanticipated Migration Of CO2 Plume And Any Potential Endangerment Of USDWs Or 

Other Environmental Impacts. 

The successful completion of the post-injection site care period and a showing 

that the CO2 plume has stabilized and poses no further risk to USDWs should 

mark the end of any and all liability for owners and operators, absent a 

showing of gross negligence, willful misconduct, or a violation of one or more 

applicable federal laws. Such an approach would provide clarity and certainty 

to owners and operators with respect to liability exposure, as well as to 

investors, lenders, insurers, and others. Given the multiple benefits 

conferred to the public by the successful capture, transport, injection and 

underground storage of CO2, the end of the post-injection site care period 

represents a fair and reasonable point to demarcate the end of private 

liability and the beginning of State responsibility, even in cases of 

unanticipated migration of the CO2 plume. And such an approach is fully 

consistent with the Interstate Oil and Gas Compact Commission’s (IOGCC) 

position, as discussed below.[17] Placing a strict limit on owner/operator 

liability also offers among the best available incentives for owners and 

operators to adhere to best practices in managing the project. 

47
This type of limit on liability is of critical importance, since commercial 

viability of CCS depends on the ability of owners and operators to transfer any 

and all long-term liability, either by contract to another party, or to the 

State upon completion of the post-injection site care period and a showing that 

the CO2 plume has stabilized. The World Resources Institute has recognized the 

importance of the ability to transfer long-term liability, stating that "[i]t 

is unlikely that any commercial operation would agree to assume 

responsibilities indefinitely."[18] The GAO report also noted that "[s] 

takeholders told us that they were concerned by the unspecified period of time 

for which they may be liable for stored CO2."[19] 

Where owners and operators face uncertainty as to the limits of their 

liability, or if these limits are not reasonable, then prospective investors 

and lenders will lack any assurance of a return on their investment and the 

financing essential to commercial-scale deployment will not materialize. 

Furthermore, private insurers will similarly be deterred in the face of 

uncertain or unreasonable liability from providing sufficient insurance 

coverage. 

A useful approach to limiting liability for activities that provide valuable 

public benefits is the Oil Pollution Act (OPA) of 1990.[20] Under the OPA, a 

responsible party’s liability is limited except in cases of gross negligence or 

willful misconduct or where there are violations of applicable federal laws. 

Where the costs or damages arising from an accident exceed the applicable 

liability limit, responsible parties may seek compensation from the Oil Spill 

Liability Trust Fund (OSLTF). 

The OPA establishes liability limits for permit holders or pipeline right of 

way holders, vessel owners, and owners or operators of onshore facilities, 

offshore facilities, and deepwater ports. When a party pays or incurs costs or 

damages in excess of an applicable liability limit, the responsible party may 

present a claim to the OSLTF for compensation. The Fund will compensate 

parties for any one oil pollution incident up to $1 billion or the balance of 

the Fund, whichever is less. Natural resource damage assessments and claims in 

connection with any one incident are limited to $500 million of the $1 billion 

per incident limit. The OSLTF is funded by an oil tax, interest on fund 

principal, cost recovery from responsible parties, and penalties (which include 

civil penalties assessed to the responsible party). The OSLTF also can borrow 

from the U.S. Treasury to cover potential shortfalls. 

A concept similar to the OSLTF for geologic storage of CO2 has been proposed 

by, among others, the IOGCC Task Force.[21] Specifically, the IOGCC has proposed 

a multi-state Carbon Mutual Account that would cover damages or remediation 

costs that exceed what is already covered by private insurers. This "trust" 

would be funded by industry and administered by the States and could draw upon 

a variety of funding mechanisms, including pooled contributions by multiple 

48
projects, royalty revenues from coal, wire charges or carbon levy applied to 

regulated transmission entities, carbon credits from verified carbon emission 

reductions, tax rebates from property taxes paid by storage projects, or an 

extension fee applied to rates approved by state public service commission and 

charged by the storage facility and/or coal-burning power plant. 

Other regulatory models have been suggested as a way to manage long-term 

liability associated with CCS, including the Price-Anderson Nuclear Industries 

Indemnity Act and the National Flood Insurance Act of 1968, both of which 

appear to be poor fits for CCS and raise numerous concerns.[22] Based on the 

collective experience using these other regulatory constructs, it is important 

to underscore the significance of creating certainty with respect to liability 

transfers to the State. Given the clear advantages of placing strict limits on 

owner/operator liability and covering the balance of any further damages or 

remediation costs with a trust fund-type of approach, Spectra recommends that 

the EPA Office of General Counsel analyze the legal issues arising from the 

creation of a state-administered fund as discussed above, including in 

particular whether EPA believes it has the authority to do so under existing 

law. If EPA concludes it does not have the authority, then it should 

communicate to Congress so that it may act if so desired. 

E. SDWA Does Not Preclude EPA From Establishing A Framework That Allows The 

Transfer Of Long-Term Liability. 

In the GS Rule, EPA has taken the position that "SDWA does not provide EPA with 

the authority to transfer liability from one entity to another." GS Rule at 

43522. Contrary to EPA’s position, Spectra believes that allowing the transfer 

of liability does not violate SDWA. Specifically, Spectra believes that EPA can 

proceed in the GS Rule to allow the full and complete transfer of liability 

from one entity to another without running afoul of SDWA on grounds that there 

is no express prohibition in SDWA. 

Recently, EPA has said that SDWA does not "explicitly provide EPA the authority 

to transfer liability from the owner/operator to another entity."[23] In 

addition, current UIC regulations allow the transfer of permits to new owners 

or operators, although EPA has taken the position that trust responsibilities 

to the owner are in perpetuity. We respectfully request further clarification 

from the Agency as to why it believes that SDWA precludes the transfer of 

liability. 

17 See CO2 Storage: A Legal and Regulatory Guide for States, INTERSTATE OIL & 

GAS COMPACT COMMISSION (December 2007). 

18 See also Capturing King Coal:Deploying Carbon Capture and Storage Systems in 

the US at Scale, WORLD RESOURCES INSTITUTE (2008) at 24. 

49
19 GAO Report, Climate Change, Federal Actions Will Greatly Affect the 

Viability of Carbon Capture and Storage As a Key Mitigation Option, REPORT TO 

THE CHAIRMAN ON THE SELECT COMMITTEE ON ENERGY INDEPENDENCE AND 

GLOBAL WARMING, 

HOUSE OF REPRESENTATIVES, GAO-08-1080 (September 2008) at 39. 

20 33 U.S.C. 2701 et seq. The OPA generally consolidated the liability and 

compensation provisions of the Trans-Alaska Pipeline Authorization Act (TAPPA) 

of 1973. For an additional discussion of OPA as a suitable model for managing 

CCS long-term liability, see Approaches To Geologic Sequestration Site 

Stewardship After Site Closure, U.S. EPA (July 2008). 

21 See CO2 Storage: A Legal and Regulatory Guide for States, INTERSTATE OIL & 

GAS COMPACT COMMISSION (December 2007). 

22 See generally Chiara Trabucchi and Lindene Patton, Storing Carbon: Options 

for Liability Risk Management, Financial Responsibility, BNA DAILY ENVIRONMENT 

REPORT (Sept. 3, 2008). 

23 Approaches To Geologic Sequestration Site Stewardship After Site Closure, 

U.S. EPA (July 2008). 

Individual Response: Under the final GS rule, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

50
§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. 

EPA disagrees with the commenter that the Agency has the authority to transfer liability under 

SDWA because it is not expressly prohibited. EPA maintains that the Agency 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, if an owner or operator were to transfer their 

Class VI permit pursuant to §144.38 then generally all other regulatory responsibilities are 

transferred to the new owner and operator, which includes all potential liabilities associated with 

meeting the requirements of that permit. For additional clarification on the issue of long term 

liability, please see the preamble to the final rule. 

Letter ID: 0151 Comment ID: 21881 Letter Lines: 1403 to 1438 ; 1663 to 1669 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: V. EPA MUST PROVIDE FLEXIBILITY IN DEMONSTRATING FINANCIAL 

ASSURANCE. 

In its July 2008 paper Approaches to Geologic Sequestration Site Stewardship 

After Site Closure, EPA stated that the purpose of financial assurance is "to 

minimize the number of facilities that are orphaned and abandoned; thereby, 

reducing the potential that these costs will be borne by the public."[24] With 

respect to the injection and storage of CO2, abandoned or orphaned sites would 

place the public and surrounding environment at risk and potentially undermine 

the primary purpose of CCS - to reduce emissions of CO2. Financial assurance 

requirements are justified to ensure projects operate in accordance with 

applicable best practices and appropriate steps are taken to minimize risks in 

the post-closure period. 

EPA notes repeatedly in the GS Rule that the risks of geologic storage of CO2 

decrease substantially over time. However, no private market to manage the 

risks associated with CCS during a virtually indefinite post-closure time 

period exists or is likely to exist in the future.[25] As a result, ensuring the 

commercial-scale deployment will depend on the eventual transfer of any and all 

risk to the State. Given the promise of CCS as a key tool to address global 

climate change and to promote domestic energy security, shifting long-term risk 

to the State is justified and, in certain respects, highly desirable given 

potential public benefits CCS could deliver. 

In apportioning the risk, it is clear that owners and operators of CCS projects 

should bear responsibility for harms and risks of harms caused during the 

period an injection site is operating, and for a reasonable closure period 

afterwards, e.g., 30 years with Director discretion to shorten, as discussed 

more fully above. Among other things, this approach encourages the development 

and implementation of best practices. 

51
Accordingly, Spectra supports EPA’s approach to releasing owners and operators 

from any further financial assurance requirement at the conclusion of the postinjection site care period and upon a determination by the Director that the 

CO2 plume poses no further risk to USDWs. With respect to specific aspects of 

financial assurance requirements, Spectra offers the following additional 

comments. 

24 Id.,n.2. 

25 Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for Liability 

Risk Management, Financial Responsibility, BNA DAILY ENVIRONMENT REPORT at 9 

(Sept. 3, 2008) ("Because CCS is what the financial services sector would call 

a specialty risk, only a small part of the sector would be equipped and 

qualified to analyze the risks and place capital thereon."). 

Individual Response: As described above, EPA agrees that it is appropriate to allow a flexible 

approach for financial responsibility. Under the final GS rule owners or operators may choose 

from a variety of financial instruments to demonstrate that they meet the financial responsibility 

requirements under §146.85, provided the Director determines that the owner or operator's 

proposed financial responsibility demonstration is adequate to pay for each activity, including 

corrective action on wells in the AoR, injection well plugging, PISC and site closure, and 

emergency and remedial response. EPA is developing guidance (available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) to help owners or operators, 

permitting authorities, and third parties choose and evaluate appropriate financial methods and 

states may set more specific financial responsibility requirements if they so choose. 

Regarding the concern about a private market to manage risks, EPA anticipates that as GS is 

deployed, particularly if there are early successful uses of these instruments, owners or operators 

will demand and carriers will offer third-party GS financial instruments in greater numbers. 

Regarding transfer of liability, EPA does not have authority to transfer or shift liability from one 

party to another party. See the final rule and preamble for further discussion of the EFAB's 

findings and EPA's final approach. 

Letter ID: 0151 Comment ID: 21893 Letter Lines: 1440 to 1463 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: A. EPA’s Requirement To Include A ‘General Duty’ To Obtain Financial 

Responsibility Is Reasonable. 

Spectra believes that the "general duty" in the GS Rule to obtain financial 

assurance is reasonable. However, Spectra further believes that EPA should 

seek to provide detailed guidance describing recommended types of risk 

52
management instruments that would satisfy this requirement as soon as possible. 

A lengthy delay in clarifying what is meant by a "general duty" risks 

inhibiting project development and technology demonstrations. 

Spectra also believes that this duty should be broadly construed and include 

not only traditional instruments such as letters of credit, insurance bonds, 

and owner/operator ratings but also other potentially more innovative 

instruments as well. For example, in the GS Rule, EPA indicates that its 

guidance will be similar to the requirements for financial assurance currently 

applicable to Class II owners and operators, which is generally limited to the 

provision of financial assurance by third party instruments, such as surety 

bonds, financial guarantee or performance bonds, letters of credit, or an 

irrevocable trust fund. Alternatively, Class II owners and operators can rely 

on self-insurance instruments. However, modeling financial assurance guidance 

on what is currently provided for Class II wells overlooks the potential of 

allowing insurance products, which are permitted for Class I injections. 

Spectra believes that insurance products should be considered in EPA’s 

guidance. 

Individual Response: The owners or operators general duty is to ensure protection of USDWs 

from endangerment, which includes the requirement to demonstrate financial responsibility. 

Owners or operators may choose from a variety of financial instruments to meet their financial 

responsibility obligations under the rule, provided the Director determines that the operator's 

proposed financial responsibility demonstration is adequate to protect USDWs from 

endangerment, which means the ability of the owner or operator to have the ability to pay for 

each activity for which financial responsibility must be demonstrated, including corrective action 

on wells in the AoR, injection well plugging, PISC and site closure, and emergency and remedial 

response throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the 

permitted types of financial responsibility instruments. See the final rule and preamble for further 

discussion of EPA's final approach to financial responsibility. 

EPA will retain the use of self-insurance as an instrument for financial responsibility for Class 

VI wells. EPA is developing guidance that describes the types of financial instruments, including 

self insurance, which owners or operators can use to meet financial responsibility requirements 

for GS wells. The financial responsibility guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) will include considerations 

for Directors regarding how best to evaluate the appropriateness of a specific financial 

responsibility instrument for a specific project. EPA notes that directors may disallow certain 

instruments. 

EPA anticipates that as GS is deployed, particularly if there are early successful uses of these 

instruments, owners or operators will demand and carriers will offer third-party GS financial 

instruments, including insurance, in greater numbers. 

EPA acknowledges that states may not be authorized under state law to allow for self insurance 

or other financial instruments. Therefore, states may prohibit the use of any financial instruments 

53
included in the rule, including self insurance, for Class VI wells. See the final rule and preamble 

for further discussion of EPA's final approach to financial responsibility. 

Letter ID: 0151 Comment ID: 21894 Letter Lines: 1465 to 1483 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: B. EPA Should Require Separate Financial Demonstrations For Well Plugging And 

Post-Injection Site Care Requirements. 

Spectra believes the financial assurance requirements for post-injection site 

care should be separate from the financial assurance requirements for well 

plugging in the GS Rule. The high likelihood that the need for well plugging 

will vary greatly from site to site raises concern over the extent to which it 

could distort a given owner or operator’s needs for financial assurance at a 

particular site. Allowing for a separate well plugging financial assurance 

requirement would allow owners and operators to acquire the appropriate risk 

management instrument that takes into account a particular site’s unique 

character and well plugging needs, thereby making overall financial assurance 

requirements more cost effective and efficient. In addition, post-injection 

site care requirements will similarly vary from site to site, and maximum 

flexibility in selecting risk management instruments to meet financial 

assurance requirements will encourage CCS project development. In neither case 

would separate requirements result in diminished coverage or in any way 

jeopardize USDWs. Accordingly, EPA should revise the GS Rule to reflect 

Spectra’s comments on this point. 

Individual Response: EPA will allow owners or operators to use separate financial 

responsibility instruments for well plugging and site closure. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities with their permit 

applications per §146.85(a), and financial responsibility will need to be reevaluated prior to well 

plugging or site closure, or at any other time deemed appropriate by the Director. EPA believes 

this is necessary to assure that resources are available to prevent the endangerment of USDWs in 

the event that the owner or operator experiences financial difficulties at any time during the life 

of the GS project. 

In order to assist owners or operators and financial institutions in achieving accurate cost 

estimates for all GS activities, EPA plans to include a discussion of how to estimate costs, 

including how to adjust cost estimates for inflation to account for the long-term nature of GS 

projects, in its guidance on meeting financial responsibility requirements for GS wells. The 

guidance will be available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA acknowledges that GS technologies and cost estimating methods are likely to change and 

improve as GS is deployed nationwide. However, EPA believes that past injection practices 

54
provide a good foundation for estimating the necessary costs and demonstrating financial 

responsibility. EPA envisions that financial responsibility updates required at the time of AoR 

reevaluation or at other frequencies specified by the Director, will provide opportunities to refine 

the cost estimates and adjust the financial responsibility instruments as appropriate. 

Letter ID: 0151 Comment ID: 21895 Letter Lines: 1485 to 1503 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: C. EPA’s Three Year Pay-In Period For A Trust Fund Is Not Reasonable. 

In the GS Rule, EPA notes that current UIC guidance describes trust funds as a 

form of financial assurance, whereby owners and operators can deposit funds 

into the trust fund in phases, e.g., either over the term of the initial permit 

or over the remaining operational life of the injection well, whichever is 

shorter. EPA raised concern over the possibility that the owner or operator 

may face financial distress prior to the trust being fully funded and stated 

that it is considering a guidance approach that would recommend adopting a payin period of three years for GS projects. Spectra respectfully disagrees with 

this approach, on grounds that it will create an unreasonable and unnecessary 

barrier to the use of trust funds. A three year pay-in period has the potential 

to increase upfront costs significantly and discourage use of trusts solely for 

the purpose of avoiding the unlikely scenario of an owner or operator becoming 

insolvent prior to the end of the project’s operation or the end of the permit 

term. While Spectra recognizes that a three year pay-in period would address 

the Agency’s concerns, the risk that this approach would create a drag on the 

use of trusts far outweighs any benefit it might afford. Accordingly, Spectra 

opposes a three year pay-in period for the foregoing reasons. 

Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds. The final rule requires that the Director approve the use 

and length of pay-in periods. EPA adds that owners or operators may choose from a variety of 

financial instruments to meet their financial responsibility obligations under the GS rule. This 

includes using other financial instruments other than trust funds. Additionally, EPA is 

developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that will discuss pay-in 

periods and provide guidance for Directors to use in determining an appropriate pay-in period. 

55