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 Wa ter UIC Geologic Sequestration Rule, Docket No. EPA-HQ-OW-2008-0390

Dear Assistant Administrator Grumbles:

Spectra Energy Corp (“Spectra” or “Spect ra Energy”) appreciates this opportunity to submit for the U.S. EPA’s (“EPA” or “Agency”) consideration the following comments regarding the Agency’s proposed de velopment 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 im portance of the GS Rule in the larger context of carbon, capture and sequestra tion (“CCS”) and we acknowledge the Agency’s trem endous 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 th e proposed technical requirements and potential liabilities, we believe that the Proposed Rule provides a so lid 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 extens ive knowledge and experi ence with injection

of CO 2 

### and sour CO 2 

### from natural gas processing. Spectra also has extensive knowledge and experience with constructi ng and operating natu ral gas storage facilities. Therefore, we offer working kn owledge of how CO 2 

### 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 en courage carbon capture and sequestration as an integral part of any na tional climate change policy. Second, whileSpectra Energy UIC Comments Page 2 December 18, 2008



### Spectra appreciates many of th e unknowns that curre ntly exist with re spect to commercial scale GS operations, sour CO 2 1 

### from natural gas operations ha s been safely injected for nearly two decades and such operations present significa nt opportunities for further reductions in atmospheric CO 2 

### 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 concer ned that, should EPA impose excessive or unreasonable requirements as part of the GS Rule, this could have negative implications for GS activities in other jurisd ictions such as Canada – wher e 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 operatio ns and broad experi ence with geologic sequestration. Section II (Page 6) offers an overview of some of the more technical provisions of the Proposed Rule and our re commendations regarding those requirements. Section III (Page 16) presents a review of the continuing liability impediments to CCS and our recommendations regardi ng how best to remove thos e barriers. Sections IV (Page 31) and V (Page 39) pr ovide an evaluation of the long-term care and financial assurance requirements, respectively, associ ated with CCS and our recommendations.

1 The term sour CO 2 (a/k/a “acid gas”) is used to describe the by-product generated from natural gas processing and is primarily a mixture of CO 2 and H 2 S 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 th an 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 pi pe into the Gulf of Mexico.

• East Tennessee Natural Gas which transports up to 1.3 Bcf per day mainly through Tennessee and Virginia ac ross 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 pipe line 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 natu ral 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 na tural gas from northeast Louisiana to

southwest Alabama.

• Market Hub Partners a nd 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 mark et 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 join t venture between Spectra Energy andSpectra Energy UIC Comments Page 4 December 18, 2008



### ConocoPhillips. DCP operates processing pl ants, 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 mi d 1990s, Spectra Energy’s Western Canadian business unit (SET West) has incorporated CC S/acid gas re-injection (AGR) into our natural gas processing facilities in British Co lumbia and Alberta. For example, our Kwoen facility is the largest CCS/AGR op eration in North Am erica, re-injecting approximately 100 Kt per year. An expa nsion currently underway at Kwoen will increase the reinjection and storage cap acity of the project to 130 Kt CO 2 

### /year. Kwoen and SET West have been recognized by th e 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

CO 2 

### per year.

 

### The AGR/CCS at Sikanni injects 5Kt CO 2 

### /year.

 

### The AGR/CCS at Jedney 1 injects 39 Kt CO 2 

### /year.

 

### A partner project at the same loca tion - Jedney 2 - injects 30 Kt CO 2 

### /year.

 

### The Kwoen facility curr ently injects 100 Kt CO 2 

### /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 CO 2 

### /year, once fully operational. Today, Spectra Energy’s eight CCS/AGR projects safe ly capture and store more than 229 Kt

CO 2 

### per year.

The evolution and commercialization of thes e 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 proc essing and release of sulfur.

It has also accrued benefits to SET’s customers by moving more natural gas from exploration and produc tion fields in northeast British Columbia to the Lower Mainland

and U.S. Pacific Northwest markets.

 

### Key CCS/AGR projects (Jedney and Kwoe n) 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 CO 2 

### -rich gas re-injection projec ts in operation in Western Canada, eight of which are managed by SET West.

The exceptional scale and relative impact of th ese projects are depicted in the following graph of CO 2 

### 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_me dia/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 REQU IREMENTS 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 CO 2 

### deepwell injection. While we generally support the Agency’s decision not to be overly pres criptive in the development of the GS requirements, certain portions of the technica l requirements appear to be excessive and unreasonable and will result in higher operationa l 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 CO 2 

### Movement and Reservoir Pressure.

EPA correctly acknowledges that some co mpanies use proprietary models for their current GS operations, and ha s requested comment on allowing the use of such models for GS sites. Spectra strong ly agrees with the continued use of proprietary models. While Spectra would be willing to provide information pertaining to the underlying assumptions and scientific basis, subjec t to protection as confidential business information (“CBI”), we would object to any effort by the Agency to co mpel further disclosure regarding such models. Although we recognize that the Ag ency 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 infra structure we operate or may op erate in the future could be extremely detrimental and costly.

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

Fluid Flow Models And Reevalua tion Should Occur At A Fixed Frequency Not To Exceed 10 Years.

We agree with the Agency’s current position that the a pplication of computational fluid flow models to predict the co mplex multi-phase buoyant flow of CO 2 

### , co-injectates, and compounds is an acceptable and appropri ate approach to mapping out the Area of Review (AoR). Such computational models ar e 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 th at 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 freque nt reevaluation, as appropriate, if the monitoring or modeling suggests that the CO 2 

### plume is not behaving as originally predicted and could result in endangerment to underground sources of drinking water (USDWs). Based on our experi ence with AGR, we believe that a frequency of between 3-5 years may be more re asonable and appropriate a nd would support such a determination; but in any event, we agree th at such reevaluation s hould not exceed 10

years.

C. Phased Corrective Action Is An Appropriate Approach.

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

action. We believe this is a reasonable approach, given the potential size of the CO 2 

### plume for commercial-scale operations (50 square miles or larger). Requiring corrective action for the entire AoR prior to injection would likely resu lt in substantial delays in permitting and project impl ementation. 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 clarifica tion by EPA, however, is the ab ility to gain access to third party wells that may over time require correc tive action. Most states require corrective action to be performed prior to injection and the “right of access” is taken into consideration during the adequacy determin ation of the corrective action plan. Some states, such as Texas, require correc tive 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 T EX



### . A DMIN



### . C ODE 

### § 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 be lieve it is important for the Agency in the Final GS Rule to discuss and clarify how owne r/operators and states will be expected to implement corrective action base d on an iterative approach.

D. EPA Should Not Arbitrarily Pr eclude Injection Into Certain

Formations Located Above The Lowermost USDW.

Under the Proposed Rule, EPA has proposed limiting the injection of CO 2 

### to below the lowermost USDW. Spectra believe s that it is premature for the Agency to preclude the injection of CO 2 

### into formations such as unmine able coal seams, depleted oil and gas reservoirs, zones in between or a bove 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 Wyom ing 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 s till be appropriate and, therefor e, the Director should haveSpectra 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 Permitti ng Process Overly Burdensome By Requiring Unnecessary Or Unavailable Data.

Under the proposal, EPA is requiri ng the collection and submission of a significant amount of informa tion 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. Ther efore, 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, includi ng all USDWs in the area of review.” 40 C.F.R. § 146.82(g). It is not clear how much baselin e 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 throu gh multiple strata, this could involve tens (and possi bly hundreds) of different fo rmations 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 applic ant may rely upon secondary sources (such as other drilling or geologic records) that relate to and s upport the data requirement. EPA should also clarify whether the Agency expects applicants to test private wells, where permission is granted, within the AoR for pu rposes of establishing baseline data. As a general matter, Spectra believes that EPA should not requir e testing of private wells because sampling results could be affected by flawed well cons truction 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 confini ng zone. 40 C.F.R. § 146.82(j). A permit applicant is already required to submit th e underlying data as part of the permit application process, and it appears that this requirement is unnecessary and duplicative. Therefore, we request further clarificati on regarding the intent and scope of this formation testing program.

Spectra generally supports the requi rement for the “proposed stimulation program” to ensure that stimulation activities will not interfere with containment. 40Spectra Energy UIC Comments Page 9 December 18, 2008



### C.F.R. § 146.82(k). We believe it is importa nt that EPA monitor s timulation 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 applican t 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 w ithin the AoR located

hundreds or thousands of feet above the CO 2 

### 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 ro ck, and possibly the porous strata directly above the injection zone, or wells that penetrat e or are in close proximity to a gas storage

reservoir.

The Agency has stated that only informa tion of public record pertaining to all types of wells (injection, producing, aba ndoned) be included on the AoR. Data availability and use raises a que stion regarding the possible ex istence of other data which might be private, proprietary and/or not publ icly 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 woul d 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 mechan ical integrity of injection wells to ensure against any “signifi cant 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 ab sence of significant fl uid movement by using tracers, temperature or noise logs, or casing in spections, or any other tests as required by the Director. 40 CFR § 146.89(c). While Sp ectra fully supports th e need for integrity testing, we believe that some of the requi rements 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 gene ral approach here, we are concerned that the absence of a definition regarding what constitutes “significant” could createSpectra 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, alternativel y, clarify under what conditions significant leakage might be construed. Toward this e nd, 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’ esta blished no specific metric for measuring endangerment and thus the Agency has the di scretion to develop UI C requirements based on varied geology, Miami-Dade County v. EPA , 529 F.3d 1049 (11 th 

### Cir. 2008) (court upheld EPA’s rule elimina ting the non-endangerment finding requirement for Class I municipal injection wells). Th e amount of leakage and what constitutes significant may vary depending upon the geologic form ations and proximity to USDWs.

2. Annual Mechanical Integrity Te sting And Quarterly Corrosion Monitoring Are Excessive.

We do not believe there is any compe lling reason to require annual integrity testing. 40 C.F.R. § 146.8 9(c). First, our experience in Canada with sour CO 2 

### injection wells is that integrity testing every five years is more than sufficient. Alberta regulations require all operators to verify every fi ve years the down hole condition to confirm hydraulic isolation. Many of ou r injection wells are reused pr oducer wells that have been

in corrosive environments for over 15 years. Even after 15 ye ars, these wells are in good condition, based on the good de sign and the use of proper ma terials, and we have never experienced a leak. Annual testing and quar terly corrosion testing could also result in significant costs from plant shut downs 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 an d equipment for corrosion and make any necessary equipment upgrades. These shut downs, which ordinarily occur once every three to five years, are also used to in spect 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 th e 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 maki ng certain that the cement and casing materials used are resistant to corrosion. We use ni ckel steel in some of our wells, which is even stronger and more corrosion resistant than stainless steel.

Section 146.89(d) currently gives the Dire ctor discretion to re quire any other test to evaluate mechanical integrity, provided such alternative test s are approved and published in the Federal Register. We woul d recommend that EPA re vise 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 quart erly basis is excessive a nd 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 CO 2 

### plume, unless it is suspected that leak age is occurring, and then they are only used to trace the leakage. The use of tracers can be very expe nsive 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 neighbo ring operators, could produce conflicting and indeterminate results. Due to the potential for groundwater contamination, the use of radioactive materi als 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 downho le 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 CO 2 

### mixture that is 80% H 2 

### S and 20% CO 2 

### , we use primarily three forms of ESD: (1) a valv e at the wellhead, (2) a subsurface safety valve, and (3) a check valve at the packer. This ESD configur ation enables us to plan for and respond to a number of contingencies, including (1) shutting down the wellhead (2) shutting the subsurface safety va lve 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) clos ing the packer check valve, which enables us to conduct any uphole work. For gas storage involving only the in jection 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 expe rience 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 pr oblems with flow rate. In addition, coupons do not identify where corro sion may or may not be taking pl ace, 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 pro duce representative results and the data will generally not be helpful. Similarly, the concept of a “c onstructed loop” at the surface to monitor and test material integrity is also not recommende d, 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, wh ich allow an operator to identify specific zones where corrosion may be occurring.

EPA is also proposing “p eriodic monitoring of th e 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 CO 2 

### plume and the number of c onfining zones, this could potentially require many monitoring wells, wh ich could be extrem ely expensive and unlikely to produce useful data. It is our strong recommendation that EPA minimize the amount of monitoring to the zone immediatel y above the confining zone, and only to the

extent that the CO 2 

### plume is within close proximity. For example, there may be regional conditions where ground water is separated by hundred or thous ands of feet of confining strata, and where such monitoring is unne cessary. We would recommend that the Director be given discretion to limit or ta ilor ground water monito ring, 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. 1 46.90(e). External mechanical integrity is not defined. Theref ore, we would ask EPA to clarify what is meant by this term.

H. The Requirement To Perform Am bient 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 dete ct 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 coul d prompt unnecessary and costly response actions and needlessly alarm the public. We believe that targeted ground water monitoring and other wellhead testing and mo nitoring requirements are sufficient to detect any movement of CO 2 

### that could endanger a USDW. Given the narrow scope of SDWA authority, we question th e 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 pursuan t 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) (s tate 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 th e 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 injecti on activities. Spectra is concerned about the potential implications and impacts on un derground gas storage from the Proposed Rule. Natural gas storage is regulated by Stat e 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 poten tial 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 su bsurface activities. Many State oil and gas regulations specify well siting or construction requirements for any wells that are drilled within a gasSpectra Energy UIC Comments Page 14 December 18, 2008



### storage area or penetrate the storage hori zon. Spectra suggests that appropriate regulatory agencies in individu al States be active participan ts with the EPA in the GS permitting process, to ensure appropriate State knowledge of local ge ology 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 St ates 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 an d GS permit application process, all natural gas storage projects within the AoR sh ould be identified on the AoR map and assessments performed to determine the potential impact from CO 2 

### or fluid migration to the gas reservoir. Such an asse ssment should also include analysis of potential leak paths through faulting, fractur ing, or other migratio n paths from injected CO 2 

### 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 requ ired. 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 co nducted based on the proximity (laterally and vertically) of the GS zone to existing gas storage reservoi rs and the potential for communication with a gas storage reservoir. For this reason, we be lieve it is important that all records relating to well logs, cementing records, and casing st rings and cementing ope rations 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 CO 2 

### injection operation.

J. The Use Of Horizontal Drilling Sh ould Be Allowed And Encouraged.

As the EPA has noted in the Proposed Ru le, 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 poros ity and permeability

than one can achieve in a vertical well as th e operator is capable of extending the length to be many times the horizontal thickness of th e reservoir. This allows the operator to produce or inject over a greater length of rese rvoir 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 theSpectra Energy UIC Comments Page 15 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 a nd 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 ar eas of the reservoir that an operator may not otherwise be able to reach using vertical drilling. As more porosity and perm eability are opened up, the pressure differential across the injection face is reduced and th erefore the ability to inject a given volume of gas in a single we ll 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 st orage reservoir are reduced. Under this concept, fewer penetrations of the cap rock result in less potential fo r a breach to occur.

Horizontal drilling is only one of a num ber of new technologies that are being developed for better management of a reservoi r, whether it be for oil and gas production, gas storage, coal bed methane production or in jection for disposal of waste fluids. EPA should support the use of all new technolog ies which contribute to better methods of

CCS.Spectra Energy UIC Comments Page 16 December 18, 2008



### III. EPA MUST ADDRESS THE LEGAL UNCERTAINTIES AND

IMPEDIMENTS TO CCS.

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

### the legal

uncertainties related to un derground injection of CO 2 

### , including the possible application of CERCLA and RCRA, are a very real lega l impediment to the viability of carbon capture and geologic sequestration. We agree with the GAO’s recommendation that EPA more comprehensively examin e CERCLA and RCRA as a potential barrier to CCS. As discussed in greater detail below, we belie ve the Agency has su fficient authority to develop responsible policies a nd 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 as k 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 Agen cy 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 sw eeping liability regime under the Comprehensive, Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”) will have an ab solute chilling effect on the underground injection of CO 2



### . The threat of CERCLA litigation and the potential liability to a GS owner or operator is alone significant and could seriously discour age the siting and construction of a GS operation. Under CERCLA’s strict liability re gime, an owner or operator may be held jointly and severally liab le for response costs related to a ny release or potential release of

a hazardous substance from a facility. In addition to fe deral and state enforcement actions, CERCLA also authorizes private pa rties to seek remediation costs from an owner/operator who is alleged to have ca used an actionable release under CERCLA. Therefore, given the extensive size of the CO 2 

### plume, covering tens of square miles, a private landowner within the AoR and w hose property is situated above the CO 2 

### plume

3 GAO Report

, Climate Change, Federal Actions Will Greatly Affect the Viability of Carbon Capture and Storage As a Key Mitigation Option , R EPORT TO THE C HAIRMAN ON THE

S ELECT C OMMITTEE ON E NERGY I NDEPENDENCE AND G LOBAL W ARMING

, H OUSE OF

R EPRESENTATIVES , GAO-08-1080 (September 2008).Spectra Energy UIC Comments Page 17 December 18, 2008



### could potentially assert a CERCLA claim agains t an owner/operator of a GS operation. In its proposed GS Rule , EPA states as follows:

[W]hether or not there is a hazard ous substance that may result in CERCLA liability from a sequestra tion facility depends entirely on the make-up of the specific CO 2 

### stream and of the environmental media (e.g., soil, groundwate r) in which it is stored.

Unfortunately, the Proposed Rule leaves considerable un certainty regarding potential CERCLA liability. See GAO Report, Climate Change: fe deral actions will greatly affect the viability of carbon capture an d 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/opera tors may have very little control, if any, over the migration of the CO 2 

### plume or geochemical reactions post-injection. As the Agency has acknowledged, de spite all the geologic and geochemical data that is developed as part of th e UIC permitting process, th ere may be unknown and unanticipated geochemi cal reactions that occur underg round post-injection that could

constitute a “release” 4 

### under CERCLA, thereby triggering liability. Scenarios that could potentially constitute a release under CE RCLA include: (1) migration of CO 2 

### from the injection zone into another z one or outside the AoR; (2) mi gration of displaced brine or fluids outside the injection zone, (3) geoche mical reactions within or outside of the injection zone, and (4) atmospheric releases of CO 2 

### . Subsurface releases that are geologically contained (releases (1) – (3) above ), even if they migrat e beyond the AoR or out of the injection zone, ordinarily will not re sult in a type of rel ease that threatens the ambient environment or presents an immine nt and substantial endangerment to human health and the environment, unl ess a USDW is endangered.

4 The term “release” is broadly defined to mean “any spilling, leaking, pumping, pouring, emitting, emptying, discharging, inje cting, escaping, leaching, dumping, or disposing into the environment (including the abandonment or discar ding of barrels, containe rs, and other closed receptacles containing any hazardous subs tance or pollutant or contaminant).” 42 U.S.C. § 9601(22). The term “release” specifically exclud es “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 

### CO 2 emissions (and other impurities) from vehi cles or vessels that might otherwise

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



### CO 2 and other hazardous substances for wh ich Congress saw fit to apply CERCLA.Spectra Energy UIC Comments Page 18 December 18, 2008



### It is important to emphasize that CO 2 

### is itself not a “hazar dous substance” under CERCLA nor under any other federal enviro nmental law. However, as EPA points out, some of the impurities poten tially contained in a CO 2 

### 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 owne r/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 CO 2 

### 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 deployme nt 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 CO 2 

### and any impurities by clar ifying minimum performance standards, employed technologies, or testi ng requirements, which if used, will exempt subsurface releases from CERCLA liability. To ward this end, the Agency has suggested

that several enumerated defenses under CE RCLA, such as the “f ederally permitted release” provision, may provide sufficient sa fe harbor. However, as discussed below, Spectra is concerned that this de fense 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 rele ase” exemption. Among the list of 11 enumerated federally permitted releases is “any injection of flui ds authorized under Federal underground injection control progra ms or State programs submitted for Federal approval . . . pursuant to part C of the Safe Drinking Water Act” (her eafter referred to as

5 If a catastrophic release of CO 2 occurred, it would be the release of CO 2 itself, and not the minute constituents of other impurities contained in the CO 2 , that would arguably threaten human health and the environment. However, CO 2 is not a hazardous substance and therefore would not trigger release reporting requireme nts 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 sh all be pursuant to existing laws in lieu of this section.”Spectra Energy UIC Comments Page 19 December 18, 2008



### the “UIC Exemption”). 42 U.S.C. § 9601(10) (G). Although the EP A 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 expr essly identified in a permit). 7



### Given that subsurface plumes from co mmercial GS operations may encompass 50 square miles or more (roughly the size of the District of Co lumbia), 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 CE RCLA. 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 re suscitate this provision by prov iding 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 rele ase” 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 Ag ency needs to do just that – establish a bright line.

EPA has the authority and discretion to in terpret and further clarify the scope and extent of the “federally permitted release” exemp tion 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 complianc e with,” “subject to,” “identified in,” or “authorized under.” The language used fo r the UIC Exemption, does not specifically limit the exemption to compliance with or th e terms identified in an enforceable permit; rather, the UIC Exemption uses a much broade r phrase “authorized under.” Herein, the UIC Exemption applies to the (i) injection of fl uids (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 dissi milar language and reasoned that Congress'

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

E NV

. L.J. (1995). According to the author, federal c ourts have threatened the utility of the exemption through holdings that have weakened th e 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 Page 20 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, 19 94 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 Ex emption, 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 eith er the federal or state UIC program. This issue is significant in that the Ag ency 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 out side the scope of the Class VI permit.” GS Rule at 43504.

First, it is clear that the Agen cy believes there are certain releases that are “inappropriate” and that, if occur, would give rise to CERC LA liability. This rais es many conc erns and more questions than answers. What releases are deemed outside the scope of the Class VI permit? Is any subsurfa ce release not specifically identified in a UIC permit an inappropriate release? Is an unanticipated geochemical reac tion an inappropriate release or outside the scope of the Class VI permit? Is the migration of a CO 2 

### 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 dete rmined? As evidence d from these questions, it is critical that the Agency clarify what is meant by the term “inappropriate” hazardous

release and in what context su ch releases may be outside th e scope of the UIC program.

Based on the case law, for an owner/ope rator to maximize its shield under the exemption, all potential releas es 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 au thorized 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 Page 21 December 18, 2008



### the law which requires all releases be id entified in a permit to benefit from the exemption.

It is unambiguous from the plain text of the statute that C ongress intended that

releases authorized under th e SDWA UIC program not be s ubject to CERCLA liability. It is also clear that the Agency has broad authority to clarify wh at releases should be

covered under the GS Rule. Therefore, the Agen cy need not wait fo r 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 wh ere the release occurs in and effects only subsurface formations and is ge ologically contained. The Agency could authorize, for example, the migration of the CO 2 

### 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 appropria te in that subsurface releases of CO 2 

### are fundamentally different than

releases of CO 2 

### to ambient air. Releases of sufficient quantities of CO 2 

### to ambient conditions can pose serious health risks and ev en death. Whereas, the slow movement of

a CO 2 

### plume in confined subsurface strata ordi narily presents little, if any, imminent or

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

in the nature and risks of subsurface and ambient releases of CO 2



### . See GS Rule at 43498 (“geologic confining systems do not experien ce . . . rapid and complete turnover [of

CO 2 

### ]”). Thus, while the appli cation of CERCLA may still be appropriate in the event of

releases of CO 2 

### to the ambient air, the statute is not necessary to address releases that involve only subsurface locati ons. 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 Ag ency has broad authority under SDWA to respond appropriately. In addition to civ il, criminal and admi nistrative enforcement authorities under the UIC program, 42 U.S. C. § 300h-2, and the potential to levy substantial monetary penalties, the EPA Ad ministrator has broa d emergency powers under SDWA to respond to a threat to a ny source of underground drinking water. Specifically, Section 300i says:

[T]he Administrator, upon re ceipt 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 su ch actions as he may deemSpectra Energy UIC Comments Page 22 December 18, 2008



### necessary in order to protect th e health of such persons. 42 U.S.C. § 300i

Under this emergency authority, the Admini strator make take whatever measures necessary to protect human health, includ ing ordering any corrective action or replacement of drinking water supplies or commencing a civil action for appropriate relief, including a restraining order or perm anent or temporary injunction. Thus, the Agency has adequate au thority under SDWA to address a ny release or contamination that presents an endangerment.

C. RCRA Should Not Apply To GS Or, Alternatively, EPA Must Clarify And Minimize The Potential App licability And Scope Of RCRA.

We begin this section by noting that CO 2 

### re-injection from gas processing is currently exempt from Subtitle C requireme nts of RCRA. Therefore, the following comments regarding the potential application of RCRA pertains to injection of CO 2 

### from non-exempt processes and industries.

Under the proposed rule, EPA has stated that it “cannot make a categorical determination as to whether injected CO 2 

### is hazardous under RCRA.” See Rule at 43503. The Agency goes on to say that if the CO 2 

### stream is considered hazardous under RCRA, then the more stringent UIC Class I requirement s for injection of hazardous waste apply. Consequently, the Agency has defined “car bon dioxide stream” to exclude hazardous

wastes as defined in 40 C.F.R. Part 261 ( e.g ., wastes that are char acteristically hazardous due to pH or toxicity).

For many of the same reasons set fo rth above for CERCLA, Spectra likewise believes that RCRA’s waste regulatory re gime is completely unnecessary and inappropriate for geologic sequestration of CO 2 

### . First, CO 2 

### is neither a pollutant, a solid

waste, 9 

### nor a hazardous waste. Second, CO 2 

### has been properly and safely injected for

9 For a waste to be a hazardous waste, it must fi rst be a solid waste. There is a legitimate question whether CO 2 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 uncontai ned gases from the definition of solid waste. See,

e.g., 47 Fed. Reg. 27530 (June 24, 1982) (gases from fu me incinerators not subject to RCRA, because fumes are not a solid waste); 54 Fe d. 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) (Administrat or rejected the argument that otherwise uncontained gas passing th rough piping or the facility made it “contained” and subject to RCRA). While CO2 emissions woul d clearly fit into the “uncontai ned” gas classification, what is unclear is whether the Agency’s interpretation would extend to CO 2 subsequently captured andSpectra Energy UIC Comments Page 23 December 18, 2008



### decades in the context of enha nced oil recovery (EoR), without the regulatory overlay of Subtitle C of RCRA. Third, there are othe r regulatory regimes that can apply to CO 2 

### injection that make the appli cation 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 bu rdens associated with the RCRA hazardous waste program. 68 Fed. Reg. 61 662, 61664 (Oct. 29, 2003). The agency noted, “[t]he existing hazardous waste re gulations require the submittal of 334 notifications, reports, certifications, dem onstrations, 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 pot ential applicability of RCRA, by opining that concentrations of impurities in a CO 2 

### 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/oper ator to determine whether its CO 2 

### stream is not a hazardous waste under RCRA. The only wa y for an owner/operator to determine

whether its stream is not a haza rdous waste is to test the CO 2 

### stream or apply “generator knowledge.” To require testing for CO 2 

### streams would be ove rly burdensome and expensive, particularly give n the diverse sources of CO 2 

### streams and their varied composition. As well, the high variability of CO 2 

### stream composition makes reliance upon “generator knowledge” risk y if not entirely unworkable.

2. EPA Has Authority To Exempt CO 2 

### Under Its Contingent Management Approach.

The Agency has au thority under Subtitle C of RCR A to determine which wastes are subject to federal hazardous waste re gulations. Section 3001 directs the

Administrator of EPA to

injected into an underground form ation. We believe this merits further clarification by the Agency on what constitutes an uncontained vs. contained gas.Spectra Energy UIC Comments Page 24 December 18, 2008



### develop and promulgate crit eria for identifying the

characteristics of hazardous wa ste, and for listing hazardous waste, which should be subject to the provisions of this subchapter, taking into account toxicity, persistence, and degradability in nature, potentia l for accumulation in tissue,

and other related factors such as flammability, corrosiveness,

and other hazardous characterist ics. 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 delegati on to EPA to develop criteria for listing

hazardous wastes . . . indica tes that Congress intended the agency to have substantial room to exercise its expertise”). The criteri a set forth above enable EPA to take into

consideration the relative risk s posed by different wastes ( i.e. , some wastes are by nature more toxic than others), the capacity for a wa ste 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 accumula tion in tissue. The application of these criteria to CO 2 

### weigh in the favor of exempting CO 2 

### injection and disposal from hazardous waste regulations.

EPA considers the risk of chronic and ac ute health effects from airborne exposure from properly operated CO 2 

### injection as minimal. GS Rule at 43498. It likewise considers the risk of adverse impacts to ec osystems from properly managed GS injection

activities as minimal. Id . Overall, the Agency believes th at the risks to human health and the environmental from properly managed CO 2 

### injection activities are minimal. These risks EPA believes will be properly addre ssed and managed throug h the new Class VI UIC well program.

Given the minimal risks from properly managed CO 2 

### pursuant to SDWA’s authority, EPA should exempt CO 2 

### streams entirely from RCRA hazardous waste regulations or, alternatively, establish a “safe harbor” for the injection of CO 2 

### , including impurities, by clarifying minimum performance standards or testing requirements. The concept of a blanket exemption is fully co nsistent 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. Acco rding 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 wast e that is otherwise hazardous may not present a hazard if al ready 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.) T hus, where a waste might pose a hazard only under limited manage ment 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 uphe ld 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 po tential hazards of such materi als 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 alternativ e management standards for used oil promulgated under RCRA section 3014 re duced the risks of mismanagement and

eliminated the n eed 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 h azardous waste regulations).

As EPA has emphasized before, even the le gislative history of Subtitle C supports the Agency’s contingent management concept. In a House Report, Congress stated that

“the basic thrust of this haza rdous 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 Re search Service, Vol.1, 567 (1991)).

3. CO 2 

### 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 exem pt certain high-volume low toxicity wastes from the Subtitle C hazardous waste regulatory scheme, including, am ong others, “fly ashSpectra Energy UIC Comments Page 26 December 18, 2008



### waste, bottom ash waste, slag waste and flue gas emission control waste generated primarily from the combustion of coal or ot her fossil fuels” (hereafter referred to as “FFC” wastes) 42 U.S.C. § 6921(b)(3)(A)(i) (e mphasis added). This amendment (a/k/a the Bevill Amendment), was prompted in large measure by Congress’ concern regarding the potential added recycling costs (estimat ed 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 Ame ndment, 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 de termination, EPA condu cted 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 re gulatory 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 site s with unlined lagoons and ponds where FFC wastes clearly had resulted in extensive gr ound water impacts from arsenic, barium, cadmium, chromium, fluoride, lead, mercury, ni ckel and selenium that had leached into

the water. Id. at 42475. EP A concluded, however, that such sites were ordinarily not located near populations and dr inking water systems. EPA al so concluded that up to 7%

of the FFC wastes exhibited the characteris tics of hazardous waste based on toxicity. Despite these negative findings, EPA ultimat ely 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 CO 2 

### falls within the scope of the exemption as a flue gas emissi on control waste. Similar to FFC wastes, CO 2 

### are a high-volume low toxicity wa ste when properly managed in underground formations. Therefore, we believe the Bevill Amendment presents the Agency with another viab le option for exempting CO 2 

### from Subtitle C.

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

Sour CO 2 

### Injection Operations Irrespect ive Of Whether Such Gas Is From Hydrocarbon Production.

Raw natural gas often contains significant impurities such as CO 2 

### , H 2 

### S, and N 2



### . Sour CO 2 

### is also generated as a by-product fr om the gas sweetening process used to produce natural gas suitable for transmission and sale. The composition of the sour CO 2 

### 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 H 2 

### SSpectra Energy UIC Comments Page 27 December 18, 2008



### results in higher concentrations of H 2 

### S as a percentage composition of the sour CO 2



### . Although, in Western Canada, CO 2 

### often accounts for most of the sour CO 2 

### composition ( i.e. , as much as 80%), at some facilitie s, such as our Kwoen plant, the CO 2 

### composition of the gas waste is only around 20%.

Historically, most of the waste gases fro m natural gas processi ng were disposed of by flaring, but more recently, great strides have been made toward injecting the gas wastes into deep geologic fo rmations. Thus, the injection and long-term storage of sour

CO 2 

### is an appropriate analog to CO 2 

### geological sequestration. Sour CO 2 

### disposal is not only an integral part of natural gas producti on, 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 fl ue gas from coal-fired power plants before CO 2 

### removal, because the acidic gas reduces the absorption capacity

of the solvent used to remove CO 2 

### . Thus, power plants th at seek to employ GS technologies will be required to eliminate a nd dispose of these ga ses along with the CO 2



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

characteristic hazardous waste based on lo w pH or toxicity. Notwithstanding, UIC injection requirements that govern CO 2 

### disposal must govern acidic gases of all kinds as part-and-parcel to the GS Rule. These requ irements must be fl exible and workable, similar to those of Class II requirements.

Despite the potentially hazardou s characteristics of sour CO 2 

### , Section 3001(b)(2)(A) of RCRA cu rrently exempts sour CO 2 

### from Subtitle C hazardous waste regulations provided the gas is related to o il or natural gas explor ation 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 CO 2 

### in the context of the UIC

program. 11 

### However, the management and injecti on 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 CO 2 

### disposal with that of GS operations, if properly

10 See U.S. EPA, Regulatory Determination fo r Oil and Gas Geothermal, Development and Production Wastes, 53 Fed. Reg. 254476, 25454 (J uly 6, 1988). EPA made the regulatory determination in 1988 to exempt sour CO 2 from hazardous waste requirements. Presumably,

sour CO 2 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 Docu ment, Report No. EPA430-R-08-009, July 10, 2008.Spectra Energy UIC Comments Page 28 December 18, 2008



### managed. 12 

### The history and strong sa fety record of sour CO 2 

### operations in North America provides a compelling argument to exempt CO 2 

### injection from other nonexempt sources and activities.

In the U.S., the management and disposal of sour CO 2 

### has largely been implemented at the state level pursuant to both federal UIC a nd state underground injection laws. Some states like Wyoming regulate sour CO 2 

### injection solely pursuant to the UIC Class II requirements. Whereas, other states, such as Texas, overlay the UIC program requirements with additional state la w requirements. Fo r example, Texas law governs injection where the H 2 

### S content is at least 100 parts per million. See 16 T EX



### . A DMIN



### . C ODE 

### § 3.36(a)(2)(C) (2008). In add ition to the baseline UIC Class II requirements, operators are required to a ssess the potential impact of releases by determining a “radius of exposure” based on concentrations of 1 00 ppm and 500 ppm. They are also required to post warning signs in public areas, provide wellhead security,

and use corrosion-resistant mate rials. Contingency planning to prepare for and respond to potentially dangerous releas es is major component of sour gas injection operations.

Canada has far more experience with sour CO 2 

### disposal than the U.S. As noted earlier, in Western Canada, as of 2007, there were 44 sour CO 2 

### injection projects operational, injecting into 51 di fferent formations. A total of 27 of these operations inject

sour CO 2 

### into deep saline formations , while 19 sites inject in to depleted oil and gas reservoirs, and the remaining sites inject in to 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 site s. 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 CO 2 

### and 2.0 Mt of H 2 

### S have been safely injected without any detectable leaks.

Similar to the U.S., Alberta has a prog ram to regulate activities related to the injection and disposal of fluids, although th ere are differences between the two programs. The Energy Resources Cons ervation 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 prob lems, a regulatory system, and the appropriate

use of remediation methods to stop or control 

### CO 2 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 underg round disposal of acid gas.”

IPCC 2005.Spectra Energy UIC Comments Page 29 December 18, 2008



### resources (oil, natural gas, oil sands, co al) and pipelines, as well as approving applications for oil and gas opera tions including underground injection. 13



### The ERCB is responsible for reviewin g and approving all injection wells consistent with specific technical require ments 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. Re gulatory 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 c ontainment to ensure initial and ongoing confinement of the disposal fl uid to protect groundwater;

● suitability of the waste stream for deep well disposal considering the nature of the fluid, the integrity of the well, a nd alternative waste management options;

● maximum H 2 

### S fraction, maximum wellhead inj ection pressure, and rate and maximum injection volume; and

● reporting and manifesting of disposed wastes.

In addition, operators of sour gas processi ng facilities must submit monthly reports which provide detailed information regarding the na ture of the operations, including the amount and quality of the sour CO 2 

### injection.

Sour CO 2 

### disposal, storage or cycling operati ons in Alberta are regulated as a Class III well (different than UIC Class III) , which under Albert a’s laws are wells primarily used for the injection of hydrocarbons or inert or other gases. On balance, the injection of sour CO 2 

### is regulated no differently than h ydrocarbons. Similar to the U.S.,

13 See Injection and DisposalWells, Well Classificati ons, Completions, Logging and Testing Requirements , ERCB, March 1994. Available at http://www.ercb.ca/docs/

Documents/directiv es/Directive051.pdf.Spectra Energy UIC Comments Page 30 December 18, 2008



### sour CO 2 

### disposal is not managed as a hazar dous waste, which is regulated under Alberta’s Class Ia well requirement s 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 monito ring requirements to provide for early detection and mitigation of potential problems. Alberta pr ohibits the subsurface injection of numerous wastes, including municipal or in dustrial sewage, lube oils, spent solvents, diesel invert drilling fluids, an d surface run-off water that meets surface discharge criteria (some of these prohibited becaus e they are treated as recyclable). All other waste fluids, including sour CO 2 

### , 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 me tric tons of sour CO 2 

### over the last two decades, EPA should consider developing a subclass of wells under Class II or Class IV for the injection of

sour CO 2 

### . There is simply no compelling basis for the EPA to regulate any acidic gases as hazardous waste under the burdensome Class I requirements.Spectra Energy UIC Comments Page 31 December 18, 2008



### IV. EPA MUST DEVELOP A F LEXIBLE FRAMEWORK TO ADDRESS POST-INJECTION SITE CARE, FI NANCIAL ASSURANCE, AND LONG

TERM LIABILITY THAT ELI MINATES OBSTACLES TO

COMMERCIAL-SCALE DE PLOYMENT OF CCS.

Numerous studies and commentators have re cognized that the principle obstacle to commercial-scale deployment of CCS is regu latory uncertainty over the capture, transport, injection, and storage of CO 2 

### . As stated by a recent GAO report:

The IPCC, two federal advisory comm ittee reports, and many stakeholders we contacted agreed that key regulatory an d legal issues will need to be addressed if CCS is to be deployed at commercial scale. Among these issues are (1) confusion over the ru les for injecting large volumes of CO 2 

### , (2) long-term liability issues concerning CO 2 

### storage and potential leakage, (3) how property ownership patterns may affect CO 2 

### storage, and (4) how the Clean Air Act will apply to facilities that capture CO 2 

### . ... EPA’s 2007 UIC workshop, attended by more than 200 stakeholders, revealed liability associated with unintended migration of injected CO 2 

### to be a critical concern. Similarly, 19 of the 20 stak eholders we interviewed told us that liability related to CO 2 

### storage was a large or very large barrier to deployment of CCS at a commercial sc ale, with some not ing that liability concerns have already ne gatively impacted compan ies’ ability to initiate CCS projects. For example, two stake holders 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 a ssociated with and limited data available for CCS,

while another added that investors will not suppor t projects like CCS if they expose them to unlimited and undefi ned 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 Wa rming, 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 , W ORLD R ESOURCES I NSTITUTE (2008) at 24 (“In the event of an accident or damage years after the well is cl osed, who is financially and legally responsible? Current law and policy is unclear on this ma tter, and more generally on the matter of responsibility for long-te rm measuring and monitoring of the site. In particular, the degree to which private parties remain responsible, or th e government assumes a m easure of responsibility, is important.”).Spectra Energy UIC Comments Page 32 December 18, 2008



### The promise of CCS as a strategy to a ddress climate change and promote national energy security hinges on resolving this regu latory uncertainty in a way that does not place an unreasonable burden on s ite owners and operators that would effectively prevent the development of commercial-scale CCS proj ects in the United States. The EPA has the authority under SDWA and the UIC Progr am to create a flex ible framework to address issues such as post-injection site ca re, financial assurance, and long-term liability in a manner that places enough responsibility on owners and ope rators to ensure that all applicable best practices are followed, bu t not so much that it becomes virtually impossible to secure the requisite financing an d insurance needed for CCS projects to be commercially viable.

The potentially unique challenge of resolv ing 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 effectiv eness 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 involve d in the capture, transport, injection, and storage of CO 2 

### : (1) length of the post-injection site care time period; (2) aspects of post-injection site care for which entities w ill be responsible; (3) availability and suitability of different risk management in struments for meeting financial assurance requirements; and (4) permanent transfer of a ll liability to the State. Spectra’s comments on post-injection site care, fina ncial assurance, and long-ter m liability focus broadly on

these issues.

A. The Director Should Have the Di scretion To Shorten The PostInjection Site Care Peri od, But Not Extend It.

EPA is proposing a post-inje ction 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 monitori ng results demonstrate that the CO 2 

### plume and pressure front have not yet stab ilized. The Director also coul d reduce this period if data on pressure, fluid movement, mineralization, a nd/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 disc retion based on monitori ng and modeling data.

Spectra supports EPA’s approach grantin g 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 andSpectra Energy UIC Comments Page 33 December 18, 2008



### operators. However, Spectra proposes limiti ng Director discretion to the ability to

shorten the post-injection site care period, upon meeting certain performance-based

criteria that indicate the CO 2 

### plume has stabilized and pose s no recognizable risk to

USDWs. This creates an incen tive for project operators to adhere to best practices and could potentially encourage CCS project development.

Spectra respectfully disagrees with gr anting 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 po tentially 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 owne rs or operators would be able to renew or extend the risk management instrument it pr ocured prior to commencing injection and storage operations, nor can it assume that an ow ner 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-in jection site care well beyond the default period, whic h 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 expo ses the public to unnecessary risk and would require governme ntal 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 furthe r believes that EPA should develop such performance criteria as soon as possible a nd in a manner that provides a realistic possibility that site s with stabilized CO 2 

### plumes would qualify for a shorter post-injection site care period.

B. EPA’s Selection Of A 50-Year Pos t-Injection Site Care Period Is Arbitrary.

Spectra respectfully disagrees with EPA’s selection of a 50-year default timeframe. As an alternative, Spectra reco mmends that EPA adopt a post-injection site care period of 30 years, similar to that used under RC RA 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 th e State. The Director should be granted discretion to shorten this timeframe upon a sh owing that certain performance criteria areSpectra Energy UIC Comments Page 34 December 18, 2008



### met that indicate USDWs are not at any r ecognizable risk, as discussed more fully

above. 15



### A 30-year timeframe with Director di scretion 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 extende d or reduced depending upon pe riodic assessments of the

CO 2 

### plume creates significant uncertainty, su bjecting owners and operators to a postinjection site care period that either could en d at any time after approximately 10 years or continue indefinitely up to an d 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 dir ection at the Agency’s discretion, as discussed more fully above.

Furthermore, with respect to USDW enda ngerment, 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 regulato ry and financial burden on these safest of projects. Even with Director discretion to s horten 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 shorte n would seem to favor the development of projects likely to have CO 2 

### plumes that stabilize early a nd avoid an unnecessarily long post-injection site care period. Similarl y, the potential of reduced regulatory and financial burdens that would accompany a 30-y ear period with Director discretion to shorten creates incentives for project owne rs and operators to develop and manage projects in a way that maximi zes the likelihood of the CO 2 

### plume stabilizing early.

For the foregoing reasons, the EPA’s 50-ye ar post-injection site care period is arbitrary and risks adding to the barriers a nd obstacles that are currently preventing commercial-scale deployment of CCS. A 30-ye ar period with Director discretion to shorten would provide the same level of protection for USDWs while minimizing regulatory and financia l burdens on site owners and operators.

15 Modeling results indicate that a CO 2 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 Pote ntial Risk to Underground Sources of Drinking

Water , U.S. EPA (2008).Spectra Energy UIC Comments Page 35 December 18, 2008



### C. After The Post-Injection Site Care Period And Determination That

The CO 2 

### Plume Has Stabilized, Owners And Operators Should Be Released From All Site Care Respon sibility, Such As Monitoring And Verification Requirements, And An y 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 determinati on by the Director that the CO 2 

### plume poses no further risk to USDWs. Establishing firm and disc rete limits for post-i njection obligations on behalf of owners and operators is essentia l to the viability of commercial-scale CCS. Open-ended requirements that could continue indefinitely, even after a showing that the

CO 2 

### 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-injecti on site-care period and upon a showing that the CO 2 

### plume has stabilized. This a pproach would have the effect of dovetailing the responsibilities of owners and operators in the post-injection site care period with the transfer of lo ng-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 ca re responsibilities, such as monitoring and verification requirements, as well as any unanticipated migration of the

CO 2 

### plume and potential endangerment of USDWs.

D. After The Post-Injection Site Care Period And Determination That

The CO 2 

### Plume Has Stabilized, Owners And Operators Should Not Be Liable For Unanticipated Migration Of CO 2 

### Plume And Any Potential Endangerment Of USDWs Or Other Environmental Impacts.

The successful completion of the post-injec tion site care period and a showing that

the CO 2 

### 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 s howing of gross negligence, willful misconduct, or a violation of one or more applicable fede ral laws. Such an approach would provide clarity and certainty to owners and operat ors with respect toSpectra Energy UIC Comments Page 36 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 CO 2 

### , 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 CO 2 

### plume. And such an approach is fully consistent with th e 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 cr itical importance, sin ce 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 CO 2 

### plume has stabilized. The World Resources Institute has recognized the importa nce of the ability to transfer long-term liability, stating that “[i]t is unlikely th at any commercial opera tion would agree to assume responsib ilities indefinitely.” 18 

### The GAO report also not ed that “[s]takeholders told us that they were conc erned by the unspecified period of time for which they may be

liable for stored CO 2 

### .” 19



### Where owners and operators face uncertainty as to the limits of their liability, or if these limits are not reasonable, then prospective investor s and lenders will lack any

assurance of a return on their investment a nd the financing essential to commercial-scale deployment will not materialize. Furthermore, private insure rs will similarly be deterred

in the face of uncertain or unreasonable lia bility from providing su fficient insurance

coverage.

17 See CO 2 Storage: A Legal and Regulatory Guide for States , I NTERSTATE O IL & G AS

C OMPACT C OMMISSION (December 2007).

18 See also Capturing King Coal: Deploying Carb on Capture and Storage Systems in the

US at Scale , W ORLD R ESOURCES I NSTITUTE (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 , R EPORT TO THE C HAIRMAN ON THE

S ELECT C OMMITTEE ON E NERGY I NDEPENDENCE AND G LOBAL W ARMING

, H OUSE OF

R EPRESENTATIVES , GAO-08-1080 (September 2008) at 39.Spectra Energy UIC Comments Page 37 December 18, 2008



### A useful approach to limiting liability fo r 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 la ws. 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 owne rs 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 pa rty may present a clai m to the OSLTF for compensation. The Fund will co mpensate 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 a ny one incident are lim ited 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 CO 2 

### has been proposed by, among others, the IOGCC Task Force. 21 

### Specifically, the IOGCC has proposed a

multi-state Carbon Mutual Accoun t that would cover damages or remediation costs that exceed what is already covere d 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 applie d to regulated transmission entities, carbon

credits from verified carbon emission reductions , tax rebates from property taxes paid by storage projects, or an extension fee applie d to rates approved by state public service commission and charged by the storage fac ility and/or coal-bur ning power plant.

Other regulatory models have been su ggested as a way to manage long-term liability associated with CCS, including the Price- Anderson Nuclear Indu stries 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 Aut horization 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 Stew ardship After Site Closure , U.S. EPA (July 2008).

21 See CO 2 Storage: A Legal and Regulatory Guide for States , I NTERSTATE O IL & G AS

C OMPACT C OMMISSION (December 2007).Spectra Energy UIC Comments Page 38 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 liab ility 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 EP A Office of General Counsel analyze the legal issues arising from the creation of a st ate-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 th e 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 po sition that “SDWA does not provide EPA with the authority to transfer lia bility from one entity to another.” GS Rule at 43522. 

### Contrary to EPA’s position, Spectra believes th at 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 ow ner/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 responsibilitie s to the owner are in perpetuity. We respectfully request further clarification fro m the Agency as to why it believes that SDWA precludes the tran sfer of liability.

22 See generally Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for Liability Risk Management, Financial Responsibility , BNA D AILY E NVIRONMENT R EPORT (Sept. 3, 2008).

23 Approaches To Geologic Sequestration Si te Stewardship After Site Closure , U.S. EPA (July 2008).Spectra Energy UIC Comments Page 39 December 18, 2008



### V. EPA MUST PROVIDE FLEX IBILITY IN DEMONSTRATING

FINANCIAL ASSURANCE.

In its July 2008 paper Approaches to Geologic Seque stration Site Stewardship After Site Closure , EPA stated that the purpose of fina ncial assurance is “to minimize the

number of facilities that are or phaned and abandoned; thereby, reducing the potential that

these costs will be bor ne by the public.” 24 

### With respect to the injection and storage of

CO 2 

### , abandoned or orphaned s ites would place the public and surrounding environment at risk and potentially undermine the primar y purpose of CCS — to reduce emissions of

CO 2 

### . Financial assurance requirements are ju stified 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 CO 2 

### decrease substantially over time. However, no private market to manage the risks

associated with CCS du ring a virtually indefinite post-cl osure time period exists or is likely to exist in the future. 25 

### As a result, ensuring the co mmercial-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 cha nge and to promote domestic energy security, shifting long-term risk to the State is justified and, in ce rtain respects, highly desirable given potential public bene fits 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 disc ussed more fully above. Among other things, this approach encourages the developmen t and implementation of best practices.

Accordingly, Spectra supports EPA’s appr oach to releasing ow ners and operators from any further financial assurance requireme nt at the conclusion of the post-injection site care period and up on a determination by the Director that the CO 2 

### plume poses no further risk to USDWs. With respect to specific aspects of financial assurance requirements, Spectra offers th e following additional comments.

24 Id ., n.2.

25 Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for Liability Risk Management, Financial Responsibility , BNA D AILY E NVIRONMENT R EPORT at 9 (Sept. 3, 2008) (“Because CCS is what the financ ial services sector w ould call a specialty risk, only a small part of the sector would be equipped and qualified to analyze the risks and pl ace capital thereon.”).Spectra Energy UIC Comments Page 40 December 18, 2008



### A. EPA’s Requirement To Include A ‘Gen eral Duty’ To Ob tain 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 reco mmended 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 sh ould be broadly constr ued and include not only traditional instruments such as letters of credit, insurance bonds, and owner/operator ratings but also other potentia lly more innovative in struments as well. For example, in the GS Rule, EPA indicates th at 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 provisi on of financial assurance by th ird party instruments, such as surety bonds, financial guarantee or perfo rmance 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 overloo ks the potential of allowing insurance products, which are permitted for Class I inje ctions. Spectra believes that insurance products should be considered in EPA’s guidance.

B. EPA Should Require Separate Fi nancial 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 w ill vary greatly from site to

site raises concern over the extent to which it could distor t a given owner or operator’s needs for financial assurance at a particular site. Allowing for a separate well plugging financial assurance requirement would allo w owners and operators to acquire the appropriate risk management instrument that takes into account a particular site’s unique character and well plugging needs, ther eby making overall financial assurance requirements more cost effective and efficien t. In addition, post-injection site care requirements will similarly vary from site to site, and maximum flexibility in selecting risk management instruments to meet fina ncial assurance requirements will encourage CCS project development. In neither case would separate requirements result in diminished coverage or in any way jeopardize USDWs. Acco rdingly, EPA should revise the GS Rule to reflect Spect ra’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 describe s trust funds as a form of financial assurance, whereby owners and operators can de posit funds into the trust fund in phases, e.g ., either over the term of the initia l permit or over the remaining operational life of the injection well, whicheve r 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 cr eate an unreasonable and unnecessary barrier to the use of trust funds. A three year pay-in period has the potentia l 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 prio r to the end of the project’s operation or the end of the permit term. While Spectra reco gnizes 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 s uggestions 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 26333560v9Letter 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 "S pectra 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 Injec tion Control Program for Carbon Dioxide Geologic Sequestration Wells (h ereafter 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 Ru le 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, es pecially 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 Propos ed 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 fram ework for regulating injection of CO2 for GS and adds that the GS regulati on 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 potenti al 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 (p erformance-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 significantopportunities for further reductions in atmospheric CO2 emission through longterm geologic sequestration. Lastly, Sp ectra and many others within the industry have ongoing operati ons in North America and elsewhere, and we are concerned that, should EPA impose excessive or unreasonable requirements as part

1of 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 prot ects 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 broade r context of CCS and the need for regulatory clarity to ensure that USDWs are protected from endangerment. In develo ping the final GS rule,

the Office of Water coordinated with other Agency program offices and across federal agencies (e.g., with the Department of Energy; United Stat es Geological Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the Minerals Management Service; and the Bureau of Land Management). The Agency continue s to evaluate areas of potential applicability

of other Federal environmental statutes incl uding, but not limited to: the Clean Air Act; the Resource Conservation and Recovery Act; th e Comprehensive Environmental Response, Compensation, and Liability Act; and the Marine Protection, Res earch, 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 efficien cies for owners or ope rators. 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 re gulating GS under the UIC Program. Even after finalization of the GS regulation, the Agency plan s to collect and review data every six years on GS projects to determine whether the appropr iate amount and types of information and appropriate documentation are being collected, and to determine if modifications to the requirements are approp riate or necessary.

Letter ID: 0151 Comment ID: 21817 Letter Lines: 175 to 187

Comment Code: 1250 1.1.1.4 Flexibility is needed (p erformance-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 deep well injection. While we generally support the Agency’s decision not to be overly prescrip tive 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

2without meaningful benefits. In the prom ulgation of the Final Rule, we would encourage EPA to continue to build upon the concept of flex ibility, reduce the amount of unnecessary and co stly requirements, and, in certain cases, provide greater discretion to the States in deciding the technical specifications applicable to siting, well c onstruction, and monitoring.

Individual Response: EPA agrees that permitting decisions for GS wells should be based on site-specific factors. The GS ru le requires owners or operators to submit, and Directors to consider, extensive site-specific data, specified at §146.82, to demons trate that a site is suitable for GS. Additionally, many of the permit require ments for GS wells are established through individualized site-specific pl ans for AoR and corrective actio n, 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 speci fic criteria to be met by the owner or operator and areas of

Directorial discretion and consider ations 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 prov iding consistency in permitting across the U.S.

EPA disagrees that the Class VI requirements ar e overly stringent; instead, the GS requirements are tailored to the unique nature of GS, incl uding 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 regula tory 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 Pr oprietary Models For Modeling CO2

Movement and

Reservoir Pressure.

EPA correctly acknowledges that some compan ies 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 inform ation ("CBI"), we w ould 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 di sclosures in the

case of the critical infrastructure we operate or may operate in the future could be extremely detrimental and costly.

3Individual Response: EPA agrees that some of the availa ble 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 sa tisfaction, the code assumptions, re levant equations, and scientific basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir engineering professionals as we ll as in peer-reviewed studies to model CO2 sequestration. EPA

adds that its Confidential Business Informati on requirements at 40 CFR 144.5 will apply to the use of proprietary models. Information includin g model assumptions and equations are used by

the Director to inform his/her decision to issu e 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 Determin ed 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 appr opriate approach to mapping out the Area of Review (AoR). Such computational models are currently being used by industry with su ccess. Further, industry continues to refine the accuracy of these models as the data and science are improved.

Individual Response: EPA acknowledges the commenter’s suppor t and believes th at predicting the complex multiphase, buoyant flow of the CO 2, co-injectates, and compounds that may be mobilized due to injection requires the sophistica tion of computational models, as required at 146.84(c)(1). Models can predict CO2 fate and tr ansport, as well as changes in formation pressure, in three dimensions, as a function of ti me 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 a nd potential migration through fau lts, fractures, and artificial penetrations.

Letter ID: 0151 Comment ID: 21820 Letter Lines: 216 to 224

Comment Code: 3530 2.2.3.1 AoR reevaluation fre quency (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 disc retion to require more fr equent reevaluation, as appropriate, if the monitoring or modeling suggests that the CO2 plume is not

4behaving as originally predicted a nd could result in endangerment to underground sources of drinking water (USD Ws). Based on our experience with AGR, we believe that a fre quency of between 3-5 years may be more reasonable and appropriate and would support such a de termination; 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 pre ssure front movement, establish conditions for corrective action, and ensure pr otection of USDWs from endange rment. 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 believe s that this revised frequency

addresses commenters' concerns about the inhe rent uncertainties in modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of monitori ng 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 opera tions (50 square miles or larger). Requiring corrective action for the entire AoR prior to inject ion would likely result in substantial delays in perm itting and project implementation. We agree that at a minimum, as part of th e 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 corr ective action. Most states require corrective action to be performed prior to injection and the “right of access” is taken into consideration during the ad equacy determination of the corrective action plan. Some states, such as Texa s, require correctiv e action prior to injection unless the owner/ operator, after best effo rts, is unable to get permission to access the property of a th ird party. 30 TEX. ADMIN. CODE § 305.151 (2008). Since SDWA does not provide EP A 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 s upport 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, avoi ding delays in project start-up, allowing for use of future, improved corrective act ion techniques and addressing unanticipated changes in the movement of the CO2 plume or pressure front . EPA believes that the phased corrective action

5approach 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 th at 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 ac tion, and demonstrate they have done this in their proposed Ao R and corrective action plan. In the AoR and corrective action plan, the owner or operator must describe how s ite access will be guaranteed for future corrective action, as specified in §1 46.84(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 Inje ction 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 in to formations such as unmineable coal seams, depleted oil and gas reservoirs, zones in between or above USDWs, or other formations. As EPA points out, im posing such a limit may preclude the application of GS in areas such as th e Williston and Powder River Basins in Wyoming and North and South Dakota, wh ere the lowermost USDW is located

thousands of feet below the surface. In th ese cases, we agree with EPA that GS may still be appropriate and, therefor e, 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 lim ited circumstances where injection above the lowermost USDW can be performe d 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 owne rs or operators can seek a waiv er of the Class VI injection depth requirements for injecti on into non-USDW formations a bove and/or between USDWs.

EPA believes that these requirements will ensure USDW protection while providing flexibility to UIC program Directors and owne rs or operators who undertak e CO2 injection for GS. The Agency believes this approach: 1) responds to co ncerns about local and re gional geologic storage capacity limitations imposed by th e proposed injection depth require ments; 2) allows for a more site-specific assessment of injection depth for GS projects; 3) accommodates injection into different formation types; 4) a llows 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 aqui fer exemptions for GS. Finally,

6EPA’s approach to addressing injection depth va riability through a waiver process responds to concerns about future drinking wa ter resource availability and the need to ensure that high quality water remains available in sufficient qua ntities to supply drinking water needs. For additional information on the waiver approach, pleas e see the final rule and preamble, as well as EPA's responses to comments on the Notice of Data Availability and Request for Comment.

Letter ID: 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, ex cessive, or may even be unavailable. Therefore, we would recommend that the Ag ency include a provision in the Final GS Rule that would provide a waiver pro cess and criteria, whereby the Director could waive certain data requirements, wh ere such requirements are unnecessary.

Individual Response: EPA disagrees that any of these pr otective 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 Direct or's discretion (§146.83(b)), based on his or her understanding of a particular site.

EPA believes that a detailed ge ologic site characterization (required under §146.82) is essential to evaluating the presence and adequacy of the va rious geologic features n ecessary to receive and confine injected CO2 for GS. The requirements fo r geologic site charac terization are based on a long-standing UIC regulatory fr amework developed to address specific risks to USDWs posed by injection. The Class VI GS re quirements 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, a nd data quality. For instance, in me eting the requirement to tabulate information on wells in the AoR, the Director ha s 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.

7Letter ID: 0151 Comment ID: 21824 Letter Lines: 275 to 290

Comment Code: 3130 2.1.3 Comments that operators s hould submit more (or different) geologic data than proposed

Comment: EPA is proposing that an applicant in clude "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 baseli ne data EPA is expecting the permit applicant to generate and collect from additional drilling or testing of the injection zone and all other zones. Give n the likely depth of many of the GS wells through multiple strata, this coul d involve tens (and possibly hundreds)

of different formations above the in jection zone. Therefore, we would recommend that EPA limit the baseline geoc hemical 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 ap plicants to test private wells, where permission is granted, within the AoR fo r purposes of establishing baseline data. As a general matter, Spectra be lieves 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 su bmitted 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 th e 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 requir e such sampling if it is believed to be necessary to ensure USDW protection.

While each monitoring plan will be site-specific based on data co llected during the initial site characterization and baseline geoc hemical 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 meta ls. 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 th at the permit applicant include a "proposed formation testing program to obt ain an analysis of the chemical and

8physical characteristics" of the injecti on 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 applicatio n process, and it appears that this requirement is unnecessary and duplicativ e. Therefore, we request further clarification regarding the intent and scope of this formation testing program.

Spectra generally supports the requirem ent 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 pa rties to ensure that such activities not interfere with or damage the contai nment 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 require ments, 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 we ll is authorized (at §146.82(c)).

Additionally, EPA agrees that it is important th at 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 we ll stimulation activitie s are not endangering USDWs. EPA plans to, every six years, collect and review project data on early GS projects, including site characterization, operational, mon itoring, 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 a ppropriate 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 hundr eds 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, a nd possibly the porous strata directly above the injection zone, or wells that penetrate or ar e in close proximity to a gas storage reservoir.

9The Agency has stated that only informati on of public record pertaining to all types of wells (injection, producing, aba ndoned) be included on the AoR. Data availability and use rais es a question regarding th e possible existence of other data which might be private, proprietary and/or not pub licly available. Such non-publicly available data may or ma y 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 inform ation that is not contained in the public record.

Individual Response: EPA clarifies that, under 146.84(c)(2), operators ar e required to identify all penetrations in the AoR that penetrate the co nfining zone, but that corrective action is needed only for those wells that are determined to need corrective action in orde r to prevent movement

of fluid into or between USDW s. 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 Leak age" Should Be Clarified.

A significant component of the GS Rule is focused on mechani cal integrity of injection wells to ensure against any "si gnificant leakage" th at would endanger USDWs. As part of the integrity tes ting requirements, EPA is proposing to require owner/operators to at least once per year determine the absence of significant fluid movement by using trace rs, 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 th e 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 requi rements 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 injec tion 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 impact s to well integrity due to CO2 phase changes, the temperature and pressure eff ects 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 determin ing the presence or absence of

10corrosion of the long-string casing, and is required if the Director determin es that it is necessary based on site-specific information. EPA has revi sed the final GS rule to require that the frequency of the casing inspection log must be specified in the approve d testing and monitoring plan. See §146.89(d).

In addition, EPA is using an adaptive approach to regulating GS. The Ag ency plans to collect and review data every six years on GS projects to determine whether the appropriate amount and types of information and appropriate documenta tion 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 th at could be construed against the owner/operator and beyond authority grante d under SDWA. Therefore, we would strongly recommend that the Agency define what consti tutes "significant" or, alternatively, clarify under what cond itions significant leakage might be construed. Toward this end, we believe that the term should be defined and construed within the statutorily defined c oncept of "endangerment" [2] under SDWA, i.e., significant leakage would be defined as a ny leakage that could potentially endanger a USDW. As one cour t has held, Congress’ established no specific metric for measuring endanger ment 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 c onstitutes significant may vary depending upon the geologic forma tions and proximity to USDWs.

2 Endangerment is defined as follows: U nderground injection endangers drinking water sources if such injection may resu lt in the presence in underground water which supplies or can reasonably be expect ed 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 nationa l primary drinking water regulation or may otherwise adversely affect the h ealth of persons. 42 U.S.C. § 300h(d).

Individual Response: A properly designed and operated we ll should have no leakage in the casing, tubing, or packer and no fluid movement into a USDW th rough channels adjacent to the

11wellbore. While the intent of MITs is to detect these types of pr oblems as early as possible, the goal of the well design and constr uction requirements at §146.86 is th e 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 c ontext 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 appro ach allows states flexib ility, will not interfere with the implementation of existing UIC program s, and maintains protection of USDWs from endangerment.

In keeping with its adaptive rule making approach, the Agency plan s to collect and review data every six years on early GS proj ects, including MIT da ta, to determine whether the appropriate amount and types of information and appropria te documentation are being collected, and to determine if modifications to the requ irements 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 compelli ng 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 conf irm hydraulic isolation. Many of our injection wells are reused producer we lls that have been in corrosive environments for over 15 years. Even af ter 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 te sting and quarterly corrosion testing could also result in significant costs from plant shutdowns and downtime with very little benefit, if any, from the data gene rated. Many companies, including Spectra, conduct periodic plant- wide shutdowns to thoroughly inspect piping and equipment for corrosion and ma ke any necessary equipment upgrades. These shutdowns, which ordinarily occur once every three to five years, are also used to inspect our injection we lls, including pulling tubing and running cement bond logs and well casing integrity l ogs 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, wh ich provide the primary "isolation"

mechanism from the reservoir fluids. We can and often do run noise logs that

12can assess for "channeling" behind th e 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 corros ion resistant than stainless steel.

Individual Response: EPA disagrees that a five-year extern al MIT is appropriate. The final GS regulation retains the requirement that owners or operators of Class VI wells must demonstrate injection well external mech anical integrity at least once annually under §146.89(c). EPA believes this is justifiable for the protecti on of USDWs from endangerment given the unique nature of CO2 GS relative to other inject ion operations. Because of the unknown long-term effects of CO2 GS, EPA chose a more conservativ e initial approach in the early stages of deployment for GS.

While EPA acknowledges the successful histor y of the Class II injection program, including injection of sour (acid) gas, the Agency believ es that CO2 injection for GS is substantially different from Class II ER operations in tha t: 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 afte r injection, 2) typically there is minimal formation pressure build-up during ER operations because withdrawal s from oil recovery wells reduce reservoir pressure, which is not the case in GS reservoi rs, 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 belie ves that continuous pressure monitoring to demonstrate internal mechanical integrity of GS wells, instead of periodic testing, which is required for most other types of d eep injection wells, is important.

In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate. Regarding concer ns about disruptions of plan t 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 we ll can be timed to avoid complete interruption of the project.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd 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)

13Comment: Section 146.89(d) currently gives the Director discretion to require any other test to evaluate mechanical integrity , provided such alte rnative tests are approved and published in the Federal Regi ster. 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 describe d in §146.89(c) of the rule (e.g., an approved tracer log or temperatur e or noise logs) are effective me thods to demonstrate external MI, provide an important early warning of potenti al 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 th e use of alternative MIT methods.

The final GS regulation retains th e 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 annua l mechanical integrity testing is appropriate for Class VI wells and is justifiable for the protection of US DWs from endangerment given the unique nature of CO2 GS relative to other injection operations, including the potential co rrosive impact of CO2 in the presence of water and impurities on well mate rials, the potential geomechanical impacts to well integrity due to CO2 phase ch anges, the temperature and pre ssure effects associated with injecting supercritical CO2, and the buoyant natu re of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a more cons ervative initial approach in the early stages of deployment for GS.

In addition, a comprehensive review conducte d by EPA of MIT results from 1993 to 1998 found that Class I wells injecting corrosi ve fluids fail MITs at rates two to three times higher than those that inject non-corrosive fluids (USEPA 1999). Given the potentia l for CO2 to be corrosive (e.g., in the presence of water or aqueous formation flui ds), there is a potential risk factor for MIT failure and, for this reason, EPA be lieves that the tailored MIT requi rements in the final GS rule are appropriate.

EPA adds that it is using an ad aptive approach to regulating GS. The Agency plans to collect and review data every six years on GS projects, including MIT da ta, to determine whether the appropriate amount and types of information a nd 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 be lieve that the requirement to conduct corrosion monitoring on a quarterly basi s is excessive and unnecessary. To require quarterly monitoring could nega tively impact the flow rate, thus

14requiring operators to add more well s. This could limit the overall effectiveness of the project. In a ddition, quarterly corrosion monitoring would require the operator to remove th e 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 corros ion monitoring is reasonable and appropriate given the potentially corrosive natu re of the CO2 stream. CO2 in the presence of water becomes acidic, potentially accelerating co rrosion 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 corrosi on 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 im pact 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 l eakage is occurring, a nd 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 lo ng shelf lives (e.g., 50 or 100 years) and, if used too frequently by neighbor ing 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 circumst ances, tracers can be an important component of a multifaceted approach to mon itoring GS projects. However, the Agency recognizes that tracers may not be appropriate in all GS project s. For this reason, EPA does not require the use of tracers at all GS sites; however, the Director ha s discretion to require their use

if he/she determines that the use of tracers could improve mon itoring 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, includin g a comprehensive monitoring program per §146.90 (which includes testing of th e 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., Phel ps and Cole, 2008; Hovorka et al., 2004; McCallum et al., 2005) found that tracers can pr ovide useful CO2 monitoring information at injection wells both at depth and at near-surface locations. At Fr io, tracers enabled quantification of CO2 plume behavior and provided a techniqu e for model validity tes ting (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

15types of information and appropriate documenta tion 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 m onitoring 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 ES D: (1) a valve at the wellhead, (2) a subsurface safety valve, and (3) a ch eck valve at the packer. This ESD configuration enables us to plan for a nd respond to a number of contingencies, including (1) shutting down the wellhead (2) shutting the subsurface safety

valve in the event the wellhead is shea red 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 i nvolving only the inj ection of sweet gas, typically only wellhead ESD is used.

Individual Response: After evaluating the risks and benefi ts of down-hole shut-off systems and considering additional research, EPA will not re quire 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 owne rs 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 believ es that offshore Class VI wells present unique construction and operational conditi ons, 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. Th e 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 expe rience 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

16ambient 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 resu lts 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 th e casing evaluation logs, which allow an operator to identif y specific zones where corrosion may be occurring.

Individual Response: EPA believes that the use of coupons fo r corrosion monitoring is feasible and appropriate for GS wells. Corrosion monitori ng by various techniques, including the use of coupons, has been performed by operators of Cla ss I hazardous waste in jection wells for many years. Use of coupons can help provide early warn ing of corrosion of well materials that could compromise the well's integrity.

The use of well coupons for testing with CO2 for co mpatibility is one of three options outlined in §146.90(c). Operators also have the option of routing the CO2 str eam through a loop constructed with the material used in the well or using an alternative method a pproved by the Director.

EPA is developing guidance on testing and mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/uic/wells_se questration.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 monito ring of the ground water quality and geochemical changes above the confini ng zone(s)." § 146.90(d). It is unclear how many wells would be required, and whet her EPA expects all zones would be monitored. Given the potential size of the CO2 plume and the number of confining zones, this co uld potentially require many monitoring wells, which could be extremely expensive and unlikely to produce useful data. It is our strong recommendation that EPA minimize th e 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 thous ands 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,

17based 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 re view evaluation, as described in §146.90(d)(2). The details of the geochemical m onitoring 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 th e 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 te sted 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 mon itoring to assist owne rs or operators and Directors in evaluating requi rements under §146.90, including pr oposed monitoring plans. The guidance describes available technologies a nd recommended approaches for implementing a testing and monitoring plan, including pre-ope rational geophysical l ogging and testing of injection wells, MITs, injecti on well testing during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, a nd soil gas and surface air monitoring which may be required by the UIC Director for specific GS projects. Th e guidance can be found on EPA’s website at http://water.epa.gov/type/gr oundwater/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 monitori ng wells sited based on site-speci fic information will provide

direct information that is not otherwise obtai nable and, along with othe r monitoring data, will support a broader understanding of fl uid behavior at the site.

EPA acknowledges the commenters' concern abou t the cost of monitoring. However, EPA believes that monitoring is essential for protecti on of USDWs at GS sites. Although a significant cost in absolute terms, monito ring costs are expected to be a small fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is av ailable 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/opera tor demonstrate "external mechanical integrity pursuant to § 146.89(c) at l east once per year." 40 C.F.R. 146.90(e). External mechanical integrity is not de fined. Therefore, we would ask EPA to clarify what is meant by this term.

Individual Response: EPA clarifies that mechanical integr ity refers to the absence (1) of

18significant leak in the casing, tubi ng, or packer and (2) of sign ificant fluid movement into a USDW through channels adjacent to the injectio n wellbore. The second half of this definition refers to external mechanical integrity.

EPA adds that a properly designed and opera ted 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 pr oblems as early as possible, the goal of the well design and constr uction requirements at §146.86 is th e 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 woul d recommend that this provision be deleted. It is not clear how am bient air or soil gas monitoring is related to or supports th e protection of USDWs. Based on our experience, the use of surface air monito ring 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 Agen cy’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 provisi on 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 progr am, 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 su rvey for UIC injection not federally enforceable).

Individual Response: The final rule at §146.90(h) retains th e 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 notifica tion of a Class VI owner or operator and UIC Director in the event of a USDW endangermen t, pursuant to requirements at §146.91(c). EPA clarifies that the decision to use surface monitoring and the se lection of monitoring methods will

19be site-specific (e.g., may be influenced by ge ology, injection depth, a nd operational conditions) and must be based on potential risk s to USDWs within the AoR.

EPA believes that surface air and soil gas monitoring are within th e scope of the SDWA in that they can provide additional data to pinpoint the lo cation and magnitude (or ab sence) 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 m onitoring are within the scope of SDWA’s general authority (SDWA sections 1421 et al).

The Agency believes that surface air and soil ga s monitoring, when coupled with subsurface monitoring, may be appropriate at some GS projects to ensu re USDW protection. EPA also acknowledges that surface air a nd soil gas measurements are subj ect to variabili ty 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 thei r use. The decision to use surface monitoring and

the selection of monito ring methods will be site-specific (e.g., may be influenced by geology, injection depth, and operational conditions) and must be based on poten tial 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 Im pact The Storage Of Hydrocarbon Natural

Gases.

One concern with GS is the potential imp lications for and impact on large-scale natural gas storage operations. Under SD WA, hydrocarbon natural gas storage is exempt from current UIC regulations governing injection activ ities. Spectra is concerned about the potential implic ations 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 reservoi rs and salt caverns. Generally, the types of storage fields th at will potentially be imp acted by the Proposed Rule are porous rock reservoirs. Because many of the areas and geologic formations

considered for GS will be in the same ba sins and may occur within or in close proximity to the same geologic strata, th ere 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 critic al role in protec ting and regulating

20the competing economic interests involved in utilizing the su bsurface, not only for natural gas storage but also oil a nd gas production or other subsurface activities. Many State oil and gas re gulations specify well siting or construction requirements for any wells th at 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 protec tion of gas storage and other economic

interests. We believe the EPA should affi rm the authority of the States to require the GS operator to comply with all well construction and monitoring requirements to protect the integr ity of gas storage reservoirs.

Second, as part of the site selection a nd GS permit application process, all natural gas storage projects within the AoR should be identified on the AoR map and assessments performed to determine th e potential impact fr om CO2 or fluid migration to the gas reservoir. Such an assessment should also include analysis of potential leak paths th rough faulting, fracturing, or other migration paths from injected CO2 in fo rmations in close proximity to gas storage reservoirs.

Third, we would recommend that where GS a nd gas storage reservoirs are in close proximity that additional monitoring be required. We are also concerned about the potential impact of hydraulic frac turing of GS wells on natural gas storage. We believe that an analys is should be conducted based on the proximity (laterally and ve rtically) of the GS zone to existing gas storage reservoirs and the potentia l 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 ac cessible to the public. Conversely, and for the same reasons, we believe inform ation regarding the proximity of gas storage reservoirs to GS wells is eq ually 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 (§1 46.84), 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 owne r or operator to ensure that th e project is being operated in a manner that protects USDWs from endangerment.

Under §146.82(a)(2) owners or operators must id entify all injection a nd production wells, which will most likely include evidence of and informa tion about the location of natural gas storage

21sites. The Director must evaluate this informa tion 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 Di rector 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 he lp 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 owne rs or operators regarding char acterizing the regional geology and hydrogeology of a proposed GS site as we ll as performing the n ecessary geochemical, geomechanical, and geophysical analyses of the injection and confining zone. Additionally, EPA expects that this guidance will s upport permitting authorities as th ey evaluate initial permits for Class VI injection wells with technical assi stance as needed. The guidance can be found on EPA’s website at http://water.epa.gov/type /groundwater/uic/we lls_sequestration.cfm.

EPA expects permitting authorities to retain an ad ministrative record for the project, which at the discretion of the permitting authority might be ava ilable 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 pr ocess as possible.

In response to the comment that state gas agen cies should be involved in permitting decisions,

EPA clarifies that the de cision to issue a permit rests with th e agency implementing the Class VI Program, as identified in the state's approved prim acy application. If a state or tribe chooses not to seek primacy for Class VI program implemen tation, 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 regula ting mineral exploration and recovery must be notified when a draft Class VI permit is ava ilable 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 Ru le, horizontal drilli ng is not typical in deep injection wells in the UIC prog ram. However, horizontal wells have been used successfully for GS, such as the In Salah project in Algeria. Spectra supports the use of horizontal drillin g, 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 re servoir. This allows the operator to produce or inject over a greater length of reservoi r at lower wellbore pressures. Whereas, a horizontal well in a heterogeneous reservoir has a greater probability of

22intersecting 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 containmen t zone, either from leaks around the casing or from corrosion/erosion of wellbor e tubulars later in the life of the well. As an exploration tool, horizontal drilling in creases the ability to reach areas of the reservoir that an op erator may not otherwise be able to reach using vertical drilling. As more porosity and permeability are opened up, the pressure differential across th e injection face is reduced and therefore the ability to inject a give n 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, poten tials 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 t echnologies that are being developed for better management of a rese rvoir, 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 appr opriateness of horizontal drilling techniques for Class VI wells, and commenters representing energy companies, el ectric utilities, the oil and gas industry, CCS associations, states, and the public, unanimously suppo rted the concept and provided many reasons why horizonta l 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 ensu re the protection of USDW s 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 i ssues (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 underg round injection of CO2, including the possible application of CERCL A and RCRA, are a very real legal impediment to

23the viability of carbon capt ure and geologic sequestration. We agree with the GAO’s recommendation that EPA more comprehens ively examine CERCLA and RCRA as a potential barrier to CCS. As discussed in greater detail below, we believe the Agency has sufficient authority to devel op 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 ou ter 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 th e Agency work with Congress to enact legislation to bring about th e needed legal certainty.

3 GAO Report, Climate Change, Federal Acti ons Will Greatly Aff ect the Viability of Carbon Capture and Storage As a Ke y Mitigation Option, REPORT TO THE

CHAIRMAN ON THE SELECT COMMI TTEE 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 regardi ng the applicability of the RCRA regulations

and statute to CO2 streams that are geologically sequestered unde r 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 appl icability 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 pa rticular 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 comment ers who wish to submit comments on the RCRA proposal will need to do so during the comment pe riod for that rule. Finall y, EPA also notes that the final GS rule, which adds ne w 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 promulga ted 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 "flu id" is subject to the requireme nts of the UIC program. "Fluid"

is defined under 40 CFR 144.3 as a ny material or substance which flows or moves, whether in a semisolid, liquid, sludge, gas or other form or stat e, 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 out side 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

24Minimize To The Fullest Extent Of Its Au thority; Alternatively, Congress Must

Act.

The potential application of the sw eeping liability regime under the Comprehensive, Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA") will have an absolute chill ing effect on the underground injection of CO2. The threat of CERCLA litigation a nd the potential liability to a GS owner or operator is al one significant and could se riously discourage the siting and construction of a GS operati on. Under CERCLA’s st rict liability regime, an owner or operator may be he ld jointly and severally liable for response costs related to any release or potential releas e of a hazardous substance from a facility. In addition to federal and state enforcement actions, CERCLA also authorizes private pa rties to seek remediation costs from an owner/operator who is alleged to ha ve caused an actionable release under CERCLA. Therefore, given the extensive si ze 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 de pends entirely on the make-up of the specific CO2 stream and of the environm ental 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 CC S activities, however EPA notes that the GS rule is not promulgated under CE RCLA, 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 th at may apply. To the extent the commenter is seeking interpretations of RCRA or CERCLA, such interpretati ons 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 lia bility to owner/operators of GS facilities, particularly where the owne rs/operators may ha ve very little control, if any, over the mi gration of the CO2 plume or geochemical reactions post-injection. As the Agency has acknow ledged, despite all the geologic and

25geochemical data that is developed as pa rt of the UIC permitting process, there may be unknown and unanticipated geochemi cal reactions that occur underground post-injection that could constitute a "release" [4] under CERCLA, thereby triggering liability. Scenarios that co uld potentially const itute a release under CERCLA include: (1) migration of CO2 from the injection zone into another zone or outside the AoR; (2) mi gration of displaced brine or fluids outside the injection zone, (3) geochemical reactions within or outside of the injection zone, and (4) atmospheric releas es of CO2. Subsurface releases that are geologically contained (releases (1) - (3) above), even if they migrate beyond the AoR or out of the injection z one, ordinarily will not result in a type of release that threatens the ambien t environment or presents an imminent and substantial endangerment to human heal th and the environment, unless a USDW is endangered.

It is important to emphasize that CO2 is itself not a "haza rdous substance" under CERCLA nor under any other federal en vironmental law. However, as EPA points out, some of the impurities potentially contained in a CO2 stream, such as mercury and sulfuric acid, are h azardous substances even though their concentrations, according to EPA, are "expe cted to be very low." GS Rule at 43503. Thus, the presence and possible rel ease 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 matte r CERCLA liability is not necessary and serves as a major deterrent to la rge-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 performa nce standards, employed technologies, or testing requirements, which if used, will exempt subsurface releases from CERCLA liability. Toward this end, th e Agency has suggested that several enumerated defenses under CERCLA, such as the "federally permitted release" provision, may provide sufficient safe har bor. However, as discussed below, Spectra is concerned that this de fense 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 a ny 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 pe rmitted release" exemption. Among the list of 11 enumerated federally permitted releases is "any injection of fluids authorized under Federal underground in jection control programs or State programs submitted for Federal approval . . . pursuant to part C of the Safe

26Drinking Water Act" (hereafter referred to as the "UIC Exempti on"). 42 U.S.C. § 9601(10)(G). Although the EPA cites the federally permitted release defense as a way for an owner/operator to avoi d liability, this defe nse 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 pe rmitted release must be expressly identified in a permit). [7]

Given that subsurface plumes from comm ercial GS operations may encompass 50 square miles or more (roughly the size of the District of Columbia), this defense provides little comfort to an ow ner/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 fu rther 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 establis h a "bright line" for when releases qualify for the releas e exemption. However, we believe the Agency needs to do just that - establish a bright line.

EPA has the authority and di scretion 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 "aut horized under." The language used for the UIC Exemption, does not specifically limit the exemption to compliance with

or the terms identified in an enfor ceable permit; rather, the UIC Exemption uses a much broader phrase "authori zed under." Herein, the UIC Exemption applies to the (i) in jection of fluids (i i) authorized under (iii) federal or an approved state UIC program. The EP A Environmental Appeals Board had occasion to construe these 11 exempti ons 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 mean ing of the phrase "subject to" and the statutory purposes of the Cl ean Air Act and CERCLA).[8]

Under the plain language of this UIC Exem ption, 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 aut horized by either the federal or state

27UIC 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 poten tial 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 believ es 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 pe rmit? Is any subsurface release not specifically identified in a UIC permit an inappropriate release? Is an unanticipated geochemical reaction an ina ppropriate 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 rele ase and in what context such releases may be outside the scope of the UIC program.

Based on the case law, for an owner/opera tor to maximize its shield under the exemption, all potential releases should be identified and aut horized under the permit, including appropriate and inappr opriate ones. Thus, there is clear tension between EPA’s statement that no inappropriate release be authorized by permit and the current state of the la w 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 Ag ency 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 releas e. EPA should make clear that all fluids injected pursuant to an authori zed 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 subsu rface releases of CO2 are fundamentally

different than releases of CO2 to am bient 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 subs tantial risk to human

health or the environment. EPA has rec ognized the distinction in the nature

and risks of subsurface and ambient rel eases of CO2. See GS Rule at 43498

28("geologic confining systems do not e xperience . . . rapid and complete turnover [of CO2]"). Thus, while the a pplication of CERCL A 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 ha s broad authority under SDWA to respond appropriately. In addition to civil, cr iminal 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 r eceipt 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 pres ent 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 nece ssary in order to protect th e health of such persons. 42 U.S.C. § 300i

Under this emergency authority, the Admini strator make take whatever measures necessary to protect human health, including ordering a ny corrective action or replacement of drinking water supplie s or commencing a civil action for appropriate relief, includi ng 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, dischargi ng, injecting, escaping, leaching, dumping, or disposing into the enviro nment (including the abandonment or discarding of barrels, containers, and ot her closed receptacles containing any hazardous substance or pollutant or c ontaminant)." 42 U.S.C. § 9601(22). The term "release" specifically excludes "emissions from engine exhaust of a motor vehicle, rolling stock, airc raft, vessel, or pipeline pu mping station engine." Although this exemption has not been interpreted by many courts, it does represent Congress’ clear intent to exem pt 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 h ealth and the environment. However,

CO2 is not a hazardous substance and th erefore would not trigger release

29reporting requirements under CERCLA or th e Emergency Planning And Community Right-to-Know Act (EPCRA). Another regula tory regime may be more appropriate to deal with this potential scenario.

6 Section 107(j) says "recovery by a ny person . . .for response costs or damages resulting from a federally perm itted release shall be pursuant to existing laws in lieu of this section."

7 See also Kurt Ryland, Saving A Disappear ing Exemption To CERCLA Liability, N.Y.U. ENV. L.J. (1995). According to the author, federa l courts have threatened the utility of the exemption through holdings that have weakened the protective shield provided by a permit. Th e author explores these decisions and how they leave many unanswered que stions concerning the exemption's

coverage.

8 In the In re Mobil case, the defendan t 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 em issions 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 Mob il’s argument would create a gap in the government’s ability to respond adequate ly 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 prev ent 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 applicabilit y of that statute will not be determ ined under the SDWA or the terms of the GS rule, but rather accordi ng 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 remedi al response is necessary. Although EPA anticipates that the need for emergency or remedial actions at GS sites wi ll be rare, the GS rule requires, at §146.94, that emergency and remedial response plans be deve loped and updated to address such events and that owners or operators demonstr ate that financial resources are set aside to implement the plans if necessary, per §146.85.

30Regarding long term liability, once an owner or operator has met all regu latory requirements

under Part 146 for Class VI wells and the Dire ctor has approved site closure pursuant to requirements at §146.93, the owner or operato r will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, their financial instrument as required under §146.85 will be released if it was not used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA’s authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner or operator to take necessary response

measures if he or she receives information that a contaminant is present or is likely to enter a public water system or an USDW, which may pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner or operator of a Class VI well. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in

which such violation occurs or failure to comply continues.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, but not limited to, Clean Air Act, 42 U.S.C. §§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does not have authority to transfer SD WA 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 i ssues (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 requ irements of RCRA. Therefore, the following comments regarding the potentia l application of RCRA pertains to injection of CO2 from non-exem pt 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 stri ngent UIC Class I requirements for

31injection of hazardous waste apply. Cons equently, 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 characte ristically hazardous due to pH or toxicity).

For many of the same reasons set fort h above for CERCLA, Spectra likewise believes that RCRA’s waste regulatory re gime 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 W ould Be Costly And Burdensome.

EPA itself has acknowledged the burden of R CRA 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 notifica tions, reports, certifica tions, 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 require ments generally, waste manifesting, training requirements for transporters and handlers, citizen suit provisions, and the fact that hazardous waste regula tion often increases one’s exposure to Superfund liability.

While EPA seeks to downplay the potenti al applicability of RCRA, by opining that concentrations of impur ities in a CO2 stream are "e xpected 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 ow ner/operator to dete rmine whether its

CO2 stream is not a hazardous wast e under RCRA. The only way for an owner/operator to determine whether its st ream 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 thei r 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

32Administrator of EPA to

develop and promulgate criteria for iden tifying the characterist ics of hazardous waste, and for listing hazardous waste, which should be subject to the provisions of this subchapt er, taking into account toxi city, persistence, and degradability in nature, potential for accu mulation in tissue, and other related factors such as flammability, corro siveness, 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 Secti on 3001, that Congress left to the EPA the

discretion to determine which hazardous wa stes would be subject to federal regulations and which ones would be exem pt 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 wa stes (i.e., some wastes are by nature more toxic than others), the capacity fo r 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, a nd 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 dis posal from hazardous waste regulations.

EPA considers the risk of chronic and acute health effects from airborne exposure from properly operated CO2 injec tion as minimal. GS Rule at 43498. It

likewise considers the risk of adverse impacts to ecosystems from properly managed GS injection activities as minima l. Id. Overall, the Agency believes

that the risks to human health and the environmental from properly managed CO2 injection activities are minimal. Thes e risks EPA believes will be properly addressed and managed through the new Class VI UIC well program.

Given the minimal risks from properly mana ged 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 in jection of CO2, including impurities, by cl arifying minimum performance standards or testing requirements. The concept of a blanket ex emption 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 h azard if already subject to adequate regulation. See, e.g., 40 CFR 261.11(a)(3)(x), which requir es EPA to consider

33action 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, EP A is not required to classify a waste as hazardous waste subject to regula tion under Subtitle C. 62 Fed. Reg. 6622, 6636 (Feb. 12, 1997). The D.C. Circuit C ourt 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. Ci r. 1993) (court upheld a temporary exemption from Subtitle C for petroleum-c ontaminated media based on the fact that the potential hazards of such mate rials are already controlled under the underground storage tank re gulations); NRDC v. EPA, 25 F.3d 1063 (D.C. Cir. 1994) (court upheld EPA's finding that altern ative management standards for used oil promulgated under RCRA section 3014 reduced the risks of mismanagement and

eliminated the need to list as a hazar dous waste); Military Toxics Project v. EPA, 146 F.3d 948, 958 (D.C. Cir. 1998) (cour t 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 haza rdous waste title is to identify what wastes are hazardous in what quantities, qualities, and concentrations, and the methods of dis posal 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 Legisl ative 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 tem porarily exempt certain high-volume low toxicity wastes from the Subtitle C hazardous waste regulatory scheme, including, among others, "fly ash waste, bot tom ash waste, slag waste and flue gas emission control waste generated primar ily from the combustion of coal or other fossil fuels" (hereafter referre d to as "FFC" wastes) 42 U.S.C. § 6921(b)(3)(A)(i) (emphasis added). Th is amendment (a/k/a the Bevill Amendment), was prompted in large meas ure by Congress’ concern regarding the potential added recycling costs (estim ated 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 determin ation on whether or not FFC needed to be regulated under Subtitle C.

As part of the Agency’s regulatory de termination, EPA conducted a three-part technical analysis evaluating whether (1) the FFC wastes posed human health or

34environmental problems, (2) whether the wastes could pose si gnificant risks at any site under current or plausible mana gement scenarios, and (3) whether the wastes exhibited any of the character istics of hazardous waste. EPA’s rationale for the iterative analysis was to determine, first, whether the wastes posed serious risks, second, whet her current management practices and federal and state regulatory controls were adequate to manage the risks and, third, the economic impact on the industr y before regulating the waste as

hazardous. EPA identified a number of s ites with unlined lagoons and ponds where FFC wastes clearly had resulted in extensive ground water impacts from arsenic, barium, cadmium, chromium, fl uoride, lead, mercury, nickel and

selenium that had leached into the water. Id. at 42475. EPA concluded, however, that such sites were ordinar ily not located near populations and drinking water systems. EPA also conclude d that up to 7% of the FFC wastes

exhibited the characteris tics of hazardous waste ba sed 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-vol ume low toxicity waste when properly managed in underground formations. Theref ore, 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 uncontai ned gases from the defini tion of solid waste. See, e.g., 47 Fed. Reg. 27530 (June 24, 1982) (gas es 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 reject ed the argument that ot herwise uncontained gas passing through piping or the facility made it "conta ined" and subject to RCRA). While CO2 emissions would clearl y fit into the "uncontained" gas classification, what is unclear is whet her the Agency’s interpretation would extend to CO2 subsequently captured and injected into an underground formation.

We believe this merits further clarific ation 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 regardi ng the applicability of the RCRA regulations

and statute to CO2 streams that are geologically sequestered unde r 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 appl icability to CO2 streams being geologically sequestered, including the possible option of a conditional exemption from the RCRA

35requirements 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 pa rticular 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 comment ers who wish to submit comments on the RCRA proposal will need to do so during the comment pe riod for that rule. Finall y, EPA also notes that the final GS rule, which adds ne w regulations for Class VI wells under the Safe Drinking Water Act (SDWA), is not making any ch anges 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-produc t from the gas sweetening process used to produce natural gas suitable for tran smission and sale. The composition of the sour CO2 mixture is highly variable based on geological conditions, the composition of the raw natural gas, a nd 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 We stern Canada, CO2 often accounts for most of the sour CO2 compositi on (i.e., as much as 80%), at some facilities, such as our Kwoen plant, th e 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 stri des have been made toward injecting the gas wastes into deep geologic form ations. Thus, the injection and longterm storage of sour CO2 is an a ppropriate analog to CO2 geological sequestration. Sour CO2 dis posal is not only an integr al 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 component s of flue gas from coal-fired power plants before CO2 removal, because th e 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 th e GS Rule. These requirements must be flexible and work able, similar to those of Class II requirements.

36Despite the potentially hazardous characteri stics 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 re garding the toxicity and potential safety of sour CO2 in the context of the UIC program.[11] However, the management and injection of such gases ha s been performed safely over the last two decades. And, in fact, the IPCC ha s equated the health, safety and environmental risks of sour CO2 dispos al with that of GS operations, if properly managed.[12] The history and st rong safety record of sour CO2 operations in North America provides a compelling argument to exempt CO2 injection from other non-exe mpt sources and activities.

In the U.S., the management and dispos al of sour CO2 has largely been implemented at the state level pursua nt to both federal UIC and state underground injection laws. Some stat es like Wyoming regulate sour CO2 injection solely pursuant to the UIC Class II requirements. Whereas, other states, such as Texas, overlay the UI C program requirements with additional state law requirements. For example, Texas law governs injection where the H2S content is at least 100 parts pe r million. See 16 TEX. ADMIN. CODE § 3.36(a)(2)(C) (2008). In addition to the ba seline UIC Class II requirements, operators are required to assess the potential im pact of releases by determining a "radius of exposure" base d 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-resist ant 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, injec ting into 51 different formations. A total of 27 of these operations inject sour CO2 into d eep saline formations, while 19 sites inject into depleted oil and gas reser voirs, and the remaining sites inject into the water leg of depleted oil an d gas reservoirs. See Carbon Dioxide Capture and Storage, IPCC, Annex I, Prope rties of CO2 and Ca rbon-Based Fuels,

November 2005. Carbonates form the rese rvoir 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, eva porites, 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 prog ram 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

37independent quasi-judicial agency of the G overnment of Alberta, is responsible for regulating Alberta’s energy resources (oil, natural gas, oil sands, coal) and pipelines, as well as approving app lications for oil and gas operations including undergr ound injection.[13]

The ERCB is responsible for reviewi ng and approving all injection wells consistent with specific technical re quirements pertaining to cementing and casing, logging to evaluate hydraulic isol ation and casing inte grity, and other testing for initial pressure, monito ring, area of review, and operating parameters. The ERCB has the authority to require a we ll to be abandoned where

the location or condition of that well ma y become a source of water pollution. Alberta’s philosophy for deepwell disposal of oilfield and industrial wastes is a safe and viable disposal option wh ere wells are properly constructed, operated, and monitored. Regulatory ac tivities for sour gas focus on the following:

. wellbore integrity to ensu re initial and ongoing contai nment of the disposal fluid to protect groundwater; . formation suitability and hydraulic containment to ensure initial and ongoing confinemen t of the disposal fluid to protect groundwater; . suitability of the wast e stream for deepwell disposal considering the nature of the fluid, the integrity of the well, and alternative waste management options; . maximum H2 S fraction, maximum wellhead injection pressure, and rate and maximum inj ection volume; and . reporting and manifesting of disposed wastes.

In addition, operators of sour gas pro cessing facilities must submit monthly reports which provide detailed inform ation regarding the nature of the operations, including the amount and quali ty of the sour CO2 injection.

Sour CO2 disposal, storage or cycling ope rations in Alberta ar e 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 CO 2 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 pr imarily to the dispos al well operator, with provincial regulators relying on operating and mon itoring requirements to provide for early detection and mitiga tion of potential problems. Alberta prohibits the subsurface injection of nume rous 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 deep well disposal if they have a pH

38between 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 hazardou s 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 CO 2 would be subject to RCRA’s hazardous waste requirements if they were not generated during oil and gas production.

11 See Vulnerability Evaluation Framewor k for Geologic Sequestration of Carbon Dioxide, U.S. EPA Technical Support Do cument, Report No. EPA430-R-08-009, July 10, 2008.

12 According to the IPCC, "[ w]ith appropriate site sel ection based on available subsurface information, a monitoring program to detect problems, a regulatory system, and the appropriate use of remedi ation methods to stop or control CO2 releases if they arise, the local health, safety a nd environment risks of geologic storage would be comparable to risks of current ac tivities such as natural gas storage, [enhanced oil recove ry], and deep underground disposal of acid gas." IPCC 2005.

13 See Injection and Disposal Wells, We ll Classifications, Completions, Logging and Testing Requirements, ERCB, March 1994. Available at http://www.ercb.ca/docs/ Document s/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 asso ciated with injection for the primary purpose of EOR, and therefore has developed new Cla ss VI regulations to address these unique risks. For example, the volu me of CO2 anticipated to be injected for longterm storage is significantly greater than for EO R operations. Reservoir pre ssure conditions will also be different, for example, Class VI injecti on 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 ar e 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 leakag e from injection formati ons and protect USDWs.

EPA has taken the position that in jection of CO2 for the primar y purpose of enhancing oil and gas recovery should remain under the Class II Program because of the differences in risk profiles

39between EOR and long-term storage of CO2. The Ag ency disagrees that we lls 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 experien ce injecting CO2 for the purpose of EOR, and that sites used fo r 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 activitie s is that a certain percentage of the CO2 is trappe d 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 (p erformance-based standards)

Comment Code: 5000 2.8 Proposed Well Plugging and Post-In jection Site Care Requirements

Comment Code: 5400 2.9 Proposed Financial Respons ibility 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 comment ators have recognized that the principle obstacle to commercial-scale deployment of CC S is regulatory uncertainty over the capture, transport, injection, and storag e 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 commerci al scale. Among these issues are (1) confusion over the rules for injecting la rge 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 Cl ean 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 crit ical 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 commerci al scale, with some noting that liability concerns have already negatively impacted companies’ ability to initiate CCS projects. For ex ample, two stakeholders reported that these concerns had already made it di fficult to obtain insurance for CCS projects. They noted specifically th at insurers have difficulty writing insurance policies because of uncertainties associated with and limited data available for CCS, while another added th at 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 addr ess climate change and promote national

40energy security hinges on resolving this regulatory uncertainty in a way that does not place an unreasonable burden on si te owners and operators that would effectively prevent the development of co mmercial-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 i ssues such as post-injection site care, financial assurance, and long-term liabi lity in a manner that places enough responsibility on owners and operators to ensure that all applicable best practices are followed, but not so much th at it becomes virtually impossible to secure the requisite financing and insura nce needed for CCS projects to be commercially viable.

The potentially unique challenge of re solving the regulatory uncertainty currently inhibiting the deve lopment 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 capt ure, transport, inje ction, and storage of CO2: (1) length of the post-injection site care time period; (2) aspects of post-injection site care for which en tities will be responsible; (3) availability and suitability of differe nt risk management instruments for meeting financial assurance requirements ; and (4) permanent transfer of all liability to the State. Spectra’s co mments on post-injec tion site care, financial assurance, and long-term liabi lity 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 Captur e 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 responsib ility for long-term measuring and monitoring of the site. In particular, the degree to which private parties remain responsible, or the government a ssumes a measure of responsibility, is important.").

Individual Response: EPA acknowledges the commenter¿s reque st for certainty regarding postinjection site care (PISC) requirements for GS wells. However, EPA believes that a certain amount of flexibility is appropr iate for setting the PISC tim eframe, given the variety of circumstances that may occur at GS sites. Th e PISC requirements in the final GS rule, as specified in §146.93(b), incorporate a combinati on 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

41timeframe during the post-injecti on period based on site-specific da ta, 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 ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters¿ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts.

EPA recognizes that there are challe nges 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 ma y choose from a variety of financial instruments

to demonstrate that th ey meet the financial responsibil ity 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 de veloping guidance (available on EPA¿s website at http://water.epa.gov/type/groundwater /uic/wells_sequestra tion.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 well s must ensure protection of USDWs from endangerment and are subject to liab ility for enforcement under the Act. The final rule requires an owner or operator to conduct mo nitoring 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 pos es an endangerment to USDWs.

Once an owner or operator has met all requireme nts under Part 146 for Class VI wells and the Director has approved site clos ure pursuant to §146.93, the owne r or operator will generally no longer be subject to enforcement for regulator y 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 ce rtain circumstances. For example, an owner or operator may be held liable for noncompliance even after site closure if the Direct or relied on erroneous information (e.g., erroneous modeling data) provi ded by the owner or operator when approving

site closure.

Additionally, an owner or operator may always be subject to any action, such as administrative orders or civil actions, the Ad ministrator deems necessary unde r §1431 of the SDWA after site closure if there is unanticipated migration towa rds or into a USDW that causes or threatens

42imminent and substantial endangerm ent to public health. If the owner or operator fails to comply with the order, he or she may be subject to a ci vil 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 potentia l liabilities associated with meeting the requirements of that permit are transferred to that new owner or operator.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes incl uding, 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 tr ansfer SDWA or other legal liab ility for Class VI wells to the State or federal government or a third-party fund. See the final rule preamble for further discussion of EPA's final approach.

Letter ID: 0151 Comment ID: 21878 Letter Lines: 1168 to 1216

Comment Code: 5260 2.8.2.3 Adjusting the post-injecti on timeframe (seeking comment)

Comment: A. The Director Should Have the Discreti on To Shorten The Post-Injection Site Care Period, But Not Extend It.

EPA is proposing a post-injection site car e period of 50 years. The Director would have discretion to extend this pe riod if after 50 year s USDWs still face potential endangerment or modeling and m onitoring results demonstrate that the CO2 plume and pressure front have not ye t stabilized. The Director also could reduce this period if data on pressure, fluid movement, mineralization, and/or dissolution reactions indicate that the pl ume 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 USDW s. This approach takes into account the site-specific nature of CCS proj ects and recognizes the importance of creating a rule that does not place unnecessary regul atory, 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 rec ognizable risk to USDW s. This creates an incentive for project operators to a dhere to best practices and could potentially encourage CCS project development.

Spectra respectfully disagrees with gran ting the Director the discretion to extend the post-injection site care pe riod beyond the fixed, pre-determined time period, on grounds that this places an unreasonable and potentially

43prohibitive financial risk on site oper ators. Specifically, owners or operators whose post-injecti on 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 operator s 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 be yond 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 re quire governmental interven tion. Rather than the possibility of an extension at the Director’s discretion, Spectra believes that a fixed post-injection site care period with the possibili ty of it being shortened upon meeting certain performan ce criteria that ar e 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 th at 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 monitori ng period. EPA believes that 50 year s 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 ne ed 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, monitori ng should continue on a regular basis, as specified in §146.93(b)(2).

Because of the variety of site-specific circumstance s at GS sites, EPA believes that Directors, inconsultation with operators, will be in the best position to determine whether additional postinjection site care monitoring is needed (or wh ether the timeframe may be shortened), based on the circumstances of a particular project. EPA exp ects 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-Inje ction Site Care Pe riod Is Arbitrary.

Spectra respectfully disagrees with EP A’s selection of a 50-year default

timeframe. As an alterna tive, Spectra recommends that EPA adopt a postinjection site care period of 30 years, similar to that used under RCRA for

44post-closure care for hazardous waste ma nagement units, 40 C.F.R. § 264.117, after which time all responsibility and lia bility would transfer to the State. The Director should be gr anted discretion to shorte n this timeframe upon a showing that certain performance criteria are met that indica te USDWs are not at any recognizable risk, as di scussed more fully above.[15]

A 30-year timeframe with Director discre tion 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 peri od that could be extended or reduced depending upon periodic assessments of the CO2 pl ume creates significant uncertainty, subjecting owners and oper ators to a post-injection site care period that either could end at any time after ap proximately 10 years or continue indefinitely up to and beyond 100 years. In practice, it is far easier for owners and operators to pl an for a 10-year period with the possibility of an extension than a 50-year peri od that could fluctuate in either direction at the Agency’s discretion, as discussed more fully above.

Furthermore, with respect to USDW endange rment, projects with plumes likely to stabilize within 10 years represent the safest types of pr ojects. A 50-year post-injection site care period would pl ace an undue regulatory and financial burden on these safest of projects. Even with Director discretion to shorten this time period, owners and operators ne vertheless would have to plan for a post-injection site care period of at le ast 50 years, significantly affecting the prospective costs of the project. By comparison, a 30-year timeframe with

Director discretion to shor ten would seem to favor th e development of projects likely to have CO2 plumes that stabili ze early and avoid an unnecessarily long post-injection site care period. Simi larly, the potential of reduced regulatory and financial burdens that would accompany a 30-year period with

Director discretion to shorten create s 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-y ear post-injection site care period is arbitrary and risks adding to the barrie rs and obstacles th at are currently preventing commercial-scale deployment of CCS. A 30-year peri od with Director

discretion to shorten woul d 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 S hould Be Released From All Site Care Responsibility, Such As Monitoring And Verification Requirements, And Any

Financial Assurance Instrume nts Should Be Released.

The GS Rule provides that owners or ope rators 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 inject ed fluid no longer poses a threat of endangerment to USDWs.

Spectra supports EPA’s approach to rele asing owners and operators from any further financial responsib ility requirement at the conclusion of the postinjection site care period and upon a dete rmination by the Director that the CO2 plume poses no further risk to USDW s. Establishing firm and discrete limits for post-injection obligations on be half of owners a nd operators is essential to the viability of commerci al-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 re leased from any monitoring or verification requirements at the conc lusion of the post-injection site-care period and upon a showing that the CO2 pl ume has stabilized. This approach would have the effect of dovetailing the responsibilities of owners and operators in the post-injec tion site care period with th e transfer of long-term liability to the State. As discussed mo re fully below, Spectra believes that

the eventual transfer of l ong-term liability to the St ate should encompass all potential liability - both anticipated s ite care responsibilities, such as monitoring and verification requiremen ts, as well as any unanticipated migration of the CO2 plume and pot ential endangerment of USDWs.

15 Modeling results indicate that a CO2 plume will stabilize within 10 to 100 years after the cessation of injection. See Comput ational 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 si te care timeframe of 50 years is

excessive in most cases or ar bitrary. EPA proposed a default tim eframe of 50 years based on a review of research studies, indus try reports, and existing environm ental programs. This analysis was included in an EPA background document ava ilable 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 resear ch studies and evaluation of public comments. While numerous commenters suggested that EPA s horten 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 a nd available data, including data submitted by commenters, do not support a different defau lt timeframe. However, EPA recognizes that alternative timeframes may be appropriate unde r limited, specific circum stances, which is why EPA is providing the Director di scretion to approve an alternative post-injection site care

46timeframe as long as the owner or operator can meet the requirements provided at §146.93(c). The GS rule offers owners or operators flexibili ty 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 we ll 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-e ndangerment of USDWs pursuan t to requirements at §146.93(c). EPA believes that a default post-injection site car e timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where

substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts. EPA agrees that owners or opera tors should not be subject to a dditional 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 lia bility for long-term care

Comment: D. After The Post-Injection Site Care Period And Determination That The CO2 Plume Has Stabilized, Owners And Oper ators 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-inje ction 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 misc onduct, or a violation of one or more applicable federal laws. Such an appro ach would provide clar ity and certainty to owners and operators w ith respect to liability e xposure, as well as to investors, lenders, insurers, and others. Given the multiple benefits conferred to the public by the successf ul capture, transport, injection and underground storage of CO2, the end of th e post-injection site care period represents a fair and reasonable point to demarcate the end of private liability and the beginnin g 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] Plac ing a strict limit on owner/operator liability also offers among the best available incentives for owners and operators to adhere to best pr actices in managing the project.

47This 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 cont ract to another pa rty, or to the State upon completion of the post-injection site care period and a showing that the CO2 plume has stabilized. The World Re sources Institute has recognized the importance of the ability to transfer long-term liabili ty, stating that "[i]t is unlikely that any commercial ope ration would agree to assume responsibilities indefinitely."[18] Th e GAO report also noted that "[s] takeholders told us that they were co ncerned by the unspecified period of time for which they may be liable for stored CO2."[19]

Where owners and operators face uncerta inty as to the limits of their liability, or if these limits are not re asonable, then prospective investors and lenders will lack any assurance of a return on their investment and the financing essential to commercial-scal e deployment will not materialize. Furthermore, private insurers will sim ilarly be deterred in the face of uncertain or unreasonable liability fro m providing sufficient insurance

coverage.

A useful approach to limiting liability for activities that provide valuable public benefits is the Oil Pollution Ac t (OPA) of 1990.[20] Un der the OPA, a responsible party’s liability is limited ex cept in cases of gr oss negligence or

willful misconduct or where there are viol ations of applicable federal laws. Where the costs or damages arising from an accident exceed the applicable liability limit, responsible parties ma y seek compensation from the Oil Spill Liability Trust Fund (OSLTF).

The OPA establishes liability limits fo r permit holders or pipeline right of way holders, vessel owners, and owners or operators of ons hore facilities, offshore facilities, and deepwater ports. Wh en 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 co mpensation. 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 resour ce 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 fund ed by an oil tax, interest on fund principal, cost recovery from responsible parties, and penal ties (which include civil penalties assessed to the responsi ble party). The OSLTF also can borrow from the U.S. Treasury to c over potential shortfalls.

A concept similar to the OSLTF for geol ogic storage of CO2 has been proposed by, among others, the IOGCC Task Force.[21] Specifically, the I OGCC has proposed a multi-state Carbon Mutual Account that would cover damages or remediation costs that exceed what is already cove red by private insure rs. This "trust" would be funded by industry and administer ed by the States and could draw upon a variety of funding mechanisms, incl uding pooled contributions by multiple

48projects, royalty revenues from coal, wi re charges or carbon levy applied to regulated transmission entities, carbon credits from verifi ed 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 ra ise numerous concerns.[22] Based on the collective experience using these other regulatory constructs, it is important to underscore the significance of creating certainty with resp ect to liability

transfers to the State. Given the clear advantages of placing strict limits on owner/operator liability and covering th e balance of any further damages or

remediation costs with a tr ust fund-type of approach, Spectra recommends that the EPA Office of General Counsel analy ze the legal issues arising from the

creation of a state-administered f und 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 ha ve the authority, then it should communicate to Congress so that it may act if so desired.

E. SDWA Does Not Preclude EPA From Es tablishing A Framework That Allows The Transfer Of Long-Term Liability.

In the GS Rule, EPA has taken the positi on 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 be lieves that allowing the transfer of liability does not violate SDWA. Speci fically, Spectra believes that EPA can proceed in the GS Rule to allow the fu ll and complete transf er 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/op erator 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 resp ectfully request furt her clarification from the Agency as to why it believes that SDWA precludes the transfer of liability.

17 See CO2 Storage: A Legal and Regulator y 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 RESOUR CES INSTITUTE (2008) at 24.

4919 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-Alas ka Pipeline Authorization Act (TAPPA)

of 1973. For an additional discussion of OPA as a suitable model for managing CCS long-term liability, see Approach es To Geologic Sequestration Site Stewardship After Site Clos ure, U.S. EPA (July 2008).

21 See CO2 Storage: A Legal and Regulator y Guide for States, INTERSTATE OIL & GAS COMPACT COMMISSION (December 2007).

22 See generally Chiara Trabucchi and Li ndene Patton, Storing Carbon: Options for Liability Risk Management, Financial Responsibility, BNA DAILY ENVIRONMENT REPORT (Sept. 3, 2008).

23 Approaches To Geologic Sequestration S ite Stewardship After Site Closure, U.S. EPA (July 2008).

Individual Response: Under the final GS rule, once an owne r or operator has met all regulatory requirements under Part 146 for Class VI wells and the Director has approved site closure pursuant to requirements at §146.93, the owner or opera tor will generally no longer be subject to enforcement for regulatory noncompliance. Furtherm ore, their financial instrument as required under §146.85 will be released if it was not used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in ce rtain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even afte r site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provid ed by the owner or operator when approving site closure.

Separate from EPA’s authority to enforce regul atory compliance, an owner or operator may be subject to a §1431 response orde r even after proper site cl osure is approved under §146.93. Under §1431 the Administrator may require an ow ner or operator to take necessary response

measures if he or she receives information that a contaminant is present or is likely to enter a public water system or an USDW, which may pres ent an imminent and s ubstantial endangerment to the health of persons, and the appropriate Stat e and local authorities ha ve not acted to protect the health of such persons. Th e action may include issuing admi nistrative orders or commencing a civil action for appropriate relief against the ow ner or operator of a Class VI well. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in

which such violation occurs or failure to comply continues.

Furthermore, after site closure an owner or ope rator may remain liable under tort and other remedies, or under other federal statutes includi ng, but not limited to, Clean Air Act, 42 U.S.C.

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. EP A 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 we re to transfer their Class VI permit pursuant to §144.38 then generall y 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 Respons ibility and Long-Term Care Requirements

Comment: V. EPA MUST PROVIDE FLEXIBILITY IN DEMONSTRATING FINANCIAL

ASSURANCE.

In its July 2008 paper Approaches to Ge ologic Sequestration Site Stewardship After Site Closure, EPA stated that th e purpose of financial assurance is "to

minimize the number of facilities that are orphaned and abandoned; thereby, reducing the potential that these costs w ill be borne by the public."[24] With respect to the injection a nd 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 em issions 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 geologi c storage of CO2 decrease substantially over time. Howeve r, no private market to manage the risks associated with CCS during a virt ually 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 en ergy security, shifting long-term risk to the State is justified and, in certa in 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 a nd 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 shorte n, as discussed more fully above. Among other things, this approach encourages the development and implementation of best practices.

51Accordingly, Spectra supports EPA’s appro ach to releasing owners and operators from any further financial assurance requi rement at the conclusion of the postinjection site care period and upon a dete rmination by the Director that the CO2 plume poses no further risk to USDWs. With respect to specific aspects of financial assurance requirements, Spect ra offers the following additional

comments.

24 Id.,n.2.

25 Chiara Trabucchi and Lindene Patton, St oring Carbon: Options for Liability Risk Management, Financial Responsibilit y, BNA DAILY ENVIRONMENT REPORT at 9 (Sept. 3, 2008) ("Because CCS is what th e financial services sector would call a specialty risk, only a small part of the sector would be equipped and qualified to analyze the risks a nd 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 demons trate 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, injecti on well plugging, PISC a nd site closure, and emergency and remedial response. EPA is deve loping guidance (available on EPA’s website at http://water.epa.gov/type/groundwater /uic/wells_sequestra tion.cfm) to help owners or operators, permitting authorities, and third parties choose and evaluate appr opriate financial methods and states may set more specific financial respons ibility 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 au thority to transfer or shift liability from one party to another party. See the final rule and preamble for fu rther 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 financia l responsibility requirements (40 CFR 146.85)

Comment: A. EPA’s Requirement To Include A ‘G eneral Duty’ To Obtain Financial Responsibility Is Reasonable.

Spectra believes that the "general duty" in the GS Rule to obtain financial assurance is reasonable. However, Spect ra further believes that EPA should seek to provide detailed guidance de scribing recommended types of risk

52management 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 sh ould 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 requireme nts for financial a ssurance currently applicable to Class II owners and operator s, 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, Cla ss II owners and operators can rely on self-insurance instruments. However, modeling financial assurance guidance on what is currently provided for Cla ss II wells overlooks th e potential of allowing insurance products, which are permitted for Class I injections. Spectra believes that insurance produc ts 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 require ment 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 de termines that the operator's proposed financial responsibility demonstrat ion is adequate to protect USDWs from endangerment, which means the ability of the owne r or operator to have the ability to pay for each activity for which financial responsibility mu st 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 th e project. The final GS rule specifies at §146.85(a)(1) the permitted types of financial responsibility instrume nts. 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 describe s the types of financial instruments, including self insurance, which owners or operators can us e to meet financial responsibility requirements for GS wells. The financial responsibility guidance (available on EPA's website at http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm) will include considerations for Directors regarding how best to evaluate the appropriate ness of a specific financial responsibility instrument for a specific project. EPA notes that direct ors may disallow certain

instruments.

EPA anticipates that as GS is de ployed, particularly if there are early successful uses of these instruments, owners or operators will demand an d carriers will offer third-party GS financial instruments, including insu rance, in greater numbers.

EPA acknowledges that states may not be authorized under state law to allow for self insurance

or other financial instruments. Th erefore, states may prohibit the use of any financial instruments

53included in the rule, including self insurance, for Class VI wells. See the final rule and preamble

for further discussion of EPA's final a pproach 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 si te care (seeking comment)

Comment: B. EPA Should Require Separate Financ ial Demonstrations For Well Plugging And Post-Injection Site Ca re Requirements.

Spectra believes the financial assurance requirements for post-injection site care should be separate from the fina ncial assurance requirements for well plugging in the GS Rule. The high likeli hood 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 separa te well plugging financial assurance requirement would allow owners and operato rs to acquire the appropriate risk management instrument that takes into account a particular site’s unique character and well plugging needs, there by making overall financial assurance requirements more cost effective and e fficient. In addition, post-injection site care requirements will similarly va ry from site to site, and maximum flexibility in selecting risk manageme nt 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 shoul d 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. Howeve r, owners or operators must demonstrate adequate financial responsibility for all required activities with their permit applications per §146.85(a), and financ ial responsibility will need to be reevaluated prior to well plugging or site closure, or at any other time deemed appr opriate 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 opera tor experiences financial difficul ties at any time during the life of the GS project.

In order to assist owners or operators and financial instituti ons in achieving accurate cost estimates for all GS activities, EPA plans to in clude a discussion of how to estimate costs, including how to adjust cost estimates for infl ation to account for the l ong-term nature of GS projects, in its guidance on m eeting 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. Howeve r, EPA believes that past injection practices

54provide 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 provid e 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 ow ners 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 po ssibility 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 cr eate an unreasonable and unnecessary

barrier to the use of trus t 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 projec t’s operation or the end of the permit term. While Spectra recognizes that a th ree year pay-in pe riod would address the Agency’s concerns, the risk that this approach would create a drag on the use of trusts far outweighs any benefi t it might afford. Accordingly, Spectra opposes a three year pay-in peri od 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 Di rector approve the use and length of pay-in periods. EPA adds that owne rs or operators may choose from a variety of

financial instruments to meet their financial re sponsibility 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/groundwat er/uic/wells_sequestration.cfm ) that will discuss pay-in periods and provide guidance for Di rectors to use in determining an appropriate pay-in period.

55