3 ‐ 4

– Responses to Public Comments on Cost and Benefits of the Proposed Rule and

Statutory and Executive Orders

This file contains responses to public comments on the costs and benefits of the
proposed rule and compliance of the regulations with various statutory requirements

and executive orders (comment codes 6000 ‐ 8000).

The table below presents all of the EPA

‐ assigned comment code s that are included in

this section of the comment and response summary. Use the bookmarks in the PDF to

move among the comment codes.

Topics included in this summary and associated comment codes

3. Cost of the Proposed Rule 6000

3.1 Comments on the cost estimates 6100

3.2 Comments on costing methodology 6200

3.2.1 Comments on the timeframe of the costing analysis 6210

3.2.2 Assumptions about the number of monitoring wells 6220

3.3 Benefits of the proposed rule 6300

4. Statutory and Executive Order Reviews ( No comments were submitted for this topic.) 7000

4.1 Executive Order 12866: Regulatory Planning and Review 7100

4.2 Paperwork Reduction Act ( No comments were submitted for this topic.) 7200

4.3 Regulatory Flexibility Act 7300

4.4 Unfunded Mandates Reform Act ( No comments were submitted for this topic.) 7400

4.5 Executive Order 13132: Federalism ( No comments were submitted for this topic.) 7500

4.6 Executive Order 13175: Tribal Consultation and Coordination 7600

4.7 Executive Order 13045: Children's Health Protection 7700

4.8 Executive Order 13211: Energy Supply, Distribution, or Use ( No comments were
submitted for this topic.) 7800

4.9 National Technology Transfer and Advancement Act ( No comments were submitted for

this topic.) 7900

4.10 Executive Order 12898: Environmental Justice 8000

Every comment on these topic areas and the associated response is included in this

summary; there is some repetition where multiple commenters made the same

comment.

Responses to letters from individual commenters or organizations are also available in

the rulemaking docket.Comment Code: 6000 3. Cost of the Proposed Rule



### Individual Comments

Commenter Name: Karl R. Moor Letter ID: 0109 Commenter Organization: Southern Company, on behalf of Edison Electric Institute (EEI) Comment ID:

21996

Comment: Moreover, EPA should consider the effect of these regulations on securing critical financial backing for CCS projects. Misperceptions about risk will

also influence financial institutions. The recent turmoil in the financial markets highlights how challenging financing of new technologies may become. In a credit-constrained world, investors will be wary of putting their limited funds behind carbon capture and storage projects if they believe they are likely to endanger sources of drinking water or human health. As with public acceptance, EPA can shape carbon capture and storage as a tool for reducing carbon emissions by the messages that it sends the financial world with its regulations.

Response: EPA clarifies that promoting or incentivizing GS is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment. The GS rule contains tailored requirements to ensure that GS wells are appropriately permitted, sited, constructed, operated, monitored, and closed in a manner that protects USDWs from endangerment.

EPA disagrees that the requirements in the GS rule overstate the risk associated with GS. The requirements for Class VI wells are tailored to address the unique nature of full-scale CO2 GS, including the volumes of CO2 being anticipated for long-term storage, the buoyant and viscous nature of the injectate, and its corrosivity in the presence of water.

Commenter Name: Herbert Skolnick, Ph.D. Letter ID: 0110 Commenter Organization: Group Against Smog and Pollution, Inc. (GASP) Comment ID: 24958

Comment: A program with the dual mission of CO2 sequestration plus utilization of the gas in enhanced recovery of oil and gas has much more to offer in terms cost savings, time savings, and overall efficiency. Of equal significance is the increase in oil and gas production - particularly in light of concerns over US reliance on foreign oil and the present push for offshore drilling. The DOE estimates that given new CO2 technology existing oil fields can produce as much as an additional 500 thousand barrels per day by 2012 and as much as 2 million barrels per day by 2020.[FN 9: DOE supra note 6.]

Finally, given the lower costs of CO2 sequestration in existing oil fields and the attendant increased oil production, sequestration in existing oil fields is also more likely to provide storage site operators with the financial resourcesnecessary to ensure proper site closure and post-closure care, and to meet longterm financial assurance requirements.

Response: EPA recognizes that there may be benefits (including cost savings) associated with transitioning ER projects to GS. The final GS regulation requires at §146.81(c) that owners oroperators seeking to grandfather existing Class II wells for GS demonstrate that grandfathered wells were engineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §§146.86(b) and 146.87(a). EPA clarifies that promoting GS is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment. For additional information on EPA's final regulatory approach, including transitioning of EOR wells for GS, please see the final rule and preamble.

EPA is developing guidance on transitioning of EOR projects. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22528

Comment: CO2 SEQUESTRATION IS COSTLY

Xie and Economides (2008) discuss the uncertainties and risks of CO2 sequestration in oil and gas reservoirs (see Attachment 1, below) [SEE P. 11 OF PDF FOR ATTACHMENT 1]. The authors conclude the cost just to satisfy the United States Kyoto Protocol requirements will cost more than $1 Trillion per year. The paper gives a "realistic situation [view] on the potential impacts on commercial CO2 sequestration projects, environment and the global climate change."

Xie, X and M.J. Economides, 2009. "The Impact of Carbon Geological Sequestration". SPE 120333-P.

Response: EPA clarifies that the GS rule addresses costs associated with sequestration only, i.e., not capture or transportation. Any impacts on the cost of electricity are likely to be influenced by all aspects of CCS, including capture, transport, and sequestration. EPA adds that it does not establish or attempt to influence electric costs – they are set by factors the Agency does not control. Sequestration costs are expected to be a small component of total CCS project costs; EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs.

EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs. The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

EPA clarifies that addressing climate change is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24273 Other EPA Comment Codes and Descriptions: 6300 3.3 Benefits of the proposed rule

Comment: We are therefore concerned that the Proposed Rule, as presently drafted, will increase the cost of geologic storage [FN3] of CO2 without producing commensurate benefits in terms of protecting USDWs. In the case of some[3] Relative to "sequestration," the term "storage" has become the more common usage in the worldwide community addressing these issues. See, e.g., the European Union’s "Proposal for a Directive of the European Parliament and of the Council on the geological storage of carbon dioxide," (January 23, 2008) and the various reports and recommendations under the UNFCCC’s Clean Development Mechanism (available at http://cdm.unfccc.int/about/ccs/index.html) (last visited December 2, 2008). The terms "sequestration" and "storage" are used interchangeably in these comments.

Response: EPA disagrees that the GS rule does not provide commensurate benefits of protecting USDWs. The GS rule contains tailored requirements to ensure that wells are appropriately permitted, sited, constructed, operated, monitored, and closed in a manner that protects USDWs from endangerment. EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs, and believes these costs are necessary and appropriate to address the unique challenges posed by large-scale GS, including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24275 Other EPA Comment Codes and Descriptions: 1280 1.1.2.1 General comments on climate change/ global warming

Comment: We are also concerned that certain unnecessary and costly requirements in the Proposed Rule would discourage, or even foreclose, the conversion of existing Class II EOR wells to Class VI geologic sequestration wells. This would undercut the effectiveness of the Proposed Rule’s provisions for such conversion. Unnecessary or unduly costly requirements would preclude CCS from playing the role that many policy analysts and governments worldwide believe that it must play in any successful strategy for reducing atmospheric concentrations of CO2. This is important because it means that the EPA may - and indeed, must - balance objectives that pull at times in competing directions. In other words, if the EPA’s primary objective is to reduce CO2 emissions and if CCS is an essential component of a CO2 reduction strategy, then the rules governing CO2 injection and storage must be crafted in such a way as to advance the primary objective of reducing GHG emissions.

New rules for CO2 sequestration that are too risky or too costly for widespread use will work against this primary overall objective of reducing GHG emissions. Absent a broader legal foundation than the SDWA alone, however, the EPA could conceivably find itself required to impose conditions for sequestration that would foreclose (or unduly limit) the use of CCS as an emissions reduction tool. This, we fear, could defeat the very purpose of the rule in the first place. Accordingly, we suggest that EPA examine whether it may be appropriate to invoke other existing statutory authorities as part of the legal foundation for the new sequestration rules.

Response: EPA disagrees that certain requirements for the conversion of existing Class II EOR wells to Class VI wells are unnecessary. The final GS regulation requires at §146.81(c) that owners oroperators seeking to grandfather existing Class II wells for GS demonstrate that grandfathered wells were engineered and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements at §§146.86(b) and 146.87(a). These requirements do not impose additional stringency on conversion from Class II wells as compared to new construction. For additional information on EPA's final regulatory approach, including transitioning of EOR wells for GS, please see the final rule and preamble.

In regard to cost, the Agency clarifies that sequestration costs are expected to be a small component of total CCS project costs. EPA estimates that the GS rule requirements amount to approximately two percent of the total CCS project costs, according to the cost analysis for the final GS rule, which is in the rulemaking docket. EPA adds that promoting or incentivizing GS is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment.

EPA is developing guidance on transitioning of EOR projects. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: David L. Armstrong Letter ID: 0231 Commenter Organization: Kentucky Public Service Commission Comment ID: 21892

Comment: [FN2: 73 Fed. Reg. 43,496 (July 25, 2008)] [FN3: Id.]

KPSC urges EPA to act cooperatively with those regulated entities that will be directly affected by the implementation of the underground injection rule such that the total costs of the program can be kept to a minimum. KPSC encourages EPA to recognize that this is only one of many new regulations and rules related to carbon capture and sequestration that will have a substantial impact on utilities' costs of service. Under traditional rate-making principles and pursuant to specific statutory requirements, the utilities' ratepayers will ultimately bear the burden of those additional costs. At a time when the costs for all utilities are increasing -such as rising fuel, material, capital and labor costs -the additional impact of new environmental requirements may prove to be unbearably burdensome to many utility customers.

Response: EPA clarifies that the GS rule addresses costs associated with sequestration only, i.e., not capture or transportation. Any impacts on the cost of electricity are likely to be influenced by all aspects of CCS, including capture, transport, and sequestration. EPA adds that it does not establish or attempt to influence electric costs –they are set by factors the Agency does not control. Sequestration costs are expected to be a small component of total CCS project costs; EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs.

EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs. The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

Commenter Name: Steven B. Corneli Letter ID: 0234 Commenter Organization: NRG Energy, Inc. Comment ID: 23160Comment: regulations that are specifically tailored to CO2 injection for GS. However, we are concerned about several technical requirements of the proposed rules that would substantially increase the cost of GS without environmental benefits. It is essential that EPA develop a regulatory framework that encourages the commercial deployment of GS, otherwise efforts and investments to develop carbon capture technology will be discouraged.

Response: EPA believes that the GS rule requirements are necessary and appropriate to address the unique challenges posed by large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations. EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs, and believes these costs are necessary and appropriate to address the unique challenges posed by large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

The Agency clarifies that sequestration costs are expected to be a small component of total CCS project costs. EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs, according to the cost analysis for the final GS rule, which is in the rulemaking docket.

EPA also disagrees that the GS rule does not provide benefits of protecting USDWs. The GS rule contains tailored requirements to ensure that wells are appropriately permitted, sited, constructed, operated, monitored, and closed in a manner that protects USDWs from endangerment.

Commenter Name: Dave Bufalo Letter ID: 0522

Comment ID: 21469

Comment: and atmospheric relationship to, I would urge the EPA to look closely at the cost benefit ratios of what this is going to cost.

I am now a certified old guy, 66 years old. I have got gray hair, I wear trifocals and my income is fixed. Any type of environmental regulation without proven benefits to the benefit of mankind is going to cost all of us consumers money and that money could be better spent doing something else other than pure regulation. Thank you.

Response: EPA believes that the GS rule requirements are necessary and appropriate to address the unique challenges posed by large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations. EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs, and believes these costs are necessary and appropriate to address the unique challenges posed by large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

Commenter Name: Nancy LaPlaca Letter ID: 0529Comment ID: 21494

Comment: Every pound of coal burned creates three pounds of CO2. It is very unique in that way. And CO2 is a very stable molecule and so it is very difficult to capture and the theory behind this whole clean, so-called clean coal is that you can burn coal in such a way that you can capture the CO2 before it escapes into the atmosphere and then liquify it and then transport it somewhere and then pump it underground. Well, just to compress the CO2 I understand from a guy named Erin Coopman [phonetic] who is with a company called RamGen [phonetic] and they make the big huge machines that compress CO2 and so he gave me a price of $17 a ton to compress CO2 so if you take your average coal plant that maybe emits let's say a small one, or medium sized one 3 million tons a year, then that is going to cost three times 17 million dollars a ton for every year, so that is like $51 million dollars. That is just to compress the CO2. Then you are supposed to take this liquid CO2 and pump it underground. It is a very highly corrosive liquid and that really wants to become a gas again and when you cool the liquid, when you cool the gas I mean into a liquid, you have to bring it to a temperature of minus 240 Fahrenheit which is an extremely energy intensive process; takes a lot of power to do that and they estimate that it takes about 20% of the plants power just to capture the CO2. Now because no one in the United States has ever actually captured that CO2, liquified it and pumped it somewhere yet in combination with making electricity, we do not even know what the total parasitic load would be and some people estimate that that could be as high as maybe 25 or 30%.

Response: EPA clarifies that the GS rule addresses sequestration only, not capture, compression, or transportation. Any impacts on the cost of electricity are likely to be influenced by all aspects of CCS, including capture, transport, and sequestration. EPA adds that it does not establish or attempt to influence electricity costs – they are set by factors the Agency does not control. Sequestration costs are expected to be a small component of total CCS project costs; EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs.

Commenter Name: Nancy LaPlaca Letter ID: 0529

Comment ID: 21497 Other EPA Comment Codes and Descriptions: 1340 1.1.3.2 Oppose use of GS in general

Comment: Future Gen which some have dubbed Never Gen which is this prototype clean coal plant that was going to be built in South Illinois, but is now up in the air, that was going to cost a whopping $6,500 a kilowatt. To put that in, to compare that to other -- costs of other electric generation, wind is about even with escalated costs today about $2,000 a kilowatt to build a plant. Concentrating solar is about $3,000 or $4,000 a kilowatt, maybe $5,000 a kilowatt, but that includes storage, [indecipherable] salt storage. Nuclear power plants anywhere between $5,000 and $10,000 a kilowatt and incidentally in the energy bill right now, there is somewhere between 90 and 190 billion dollars in giveaways for nuclear industry and the energy policy act of 2008.

Response: EPA clarifies that the GS rule addresses sequestration only, not capture or transportation. Any impacts on the cost of electricity are likely to be influenced by all aspects of CCS, including capture, transport, and sequestration.Comment Code: 6100 3.1 Comments on the cost estimates



### Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22538

Comment: COST ESTIMATE FOR PLUGGING CLASS VI WELLS

EPA at 73 FR 43522 EPA discusses having funds available to plug Class VI wells. They question if the owner/operator will have sufficient funds to plug and abandon the injection well. We have expressed the same concern previously in these comments. EPA proposes to solve this problem by having a contractor make the cost estimate. Any cost estimate reflects the assumption used to develop the estimate. We recall when EPA instructed their cost estimating contractor to assume all existing SPCC Plans (67 FR 47140, July 17, 2002) were in compliance with the proposed unpublished SPCC rule. The resulting cost estimate was unethical, but reflected the given assumptions and showed the proposed revisions to 40 CFR Part 112 reduce regulatory costs. Is there a chance the same (unethical) approach is possible when estimating the plug and abandonment costs for Class VI by unethical speculators? Will the technically untrained EPA employee recognize the estimate is not correct or for that matter, how will untrained EPA employee recognize the estimate is correct?

Response: EPA is developing guidance on financial responsibility that describes the types of financial instruments that owners or operators can use to meet financial responsibility requirements for GS wells. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

For additional information on EPA's final regulatory approach, including the well plugging and financial responsibility requirements, please see the final rule and preamble.

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22541 Other EPA Comment Codes and Descriptions: 6210 3.2.1 Comments on the timeframe of the costing analysis (seeking comment)

Comment: COST ESTIMATE

EPA at 73 FR 43524 presents the results of an analysis of the cost to protect USDWs from a Class VI wells. EPA was very specific regarding what they did not include in the regulatory estimate. EPA based the cost estimate on a Class I well of unknown depth, unknown casing size, unknown location and type of reservoir. EPA, using this unspecified well information, calculated the incremental cost to convert the Class I well to a Class VI well. This approach excludes commenters from verifying the accuracy of the EPA estimate because of these omissions. This is reminiscent of the 2004 SPCC Plan cost estimate, where commenters were not privileged to the assumptions EPA provide to its contractor. Unethical instructions and unstated assumptions prevent commenters from testingthe accuracy of the cost estimate. We have no means of knowing if EPA provided unethical instructions to the contractor for development of the Class VI well costs, since EPA does not include the assumptions in the publication.

Apparently, EPA told the contractor to use a 25 year after closure monitoring time period (73 FR 43524). Then, EPA proposed a 50 years monitoring period at 40 CFR 146.91 (73 FR 43540). Either the Agency changed its mind after giving the go-ahead to the contractor , but did not revise the proposed rule or the Agency was attempting reduce cost of the rule.

*EPA at Table VII-2 (73 FR 43525) says the cost of baseline project plus Alternate 3 and Alternate 3 increment varies between $94.6 and $98.4 million for 22 sequestration projects or $4.3 million to $4.5 million per project. EPA at 73 FR 42504 provides a non-specific definition of Alterative 3. The definition is words without specificity! We have no inkling of want Alternative 3 entails.

On 28 August 2007, Dr. Holliday discussed these cost figures with the Chairman of the Society of Petroleum Engineers Sequestration Panel. The Chairman’s response was "there is no way in Hell we can conduct a sequestration project for that little money."

Response: EPA clarifies that due to the variation expected in individual project specifications, a pro forma (representative) project was used in the cost analysis to provide a reasonable estimate on a national basis for the purpose of selecting between regulatory options and development of the final regulation. This approach is consistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA. Detailed information on the pro forma assumptions and unit costs applied in the analysis are included in the appendix to the cost analysis, which is in the rulemaking docket.

EPA clarifies that cost estimates are presented in incremental terms, that is, the costs beyond those estimated to be incurred if the projects were operating under regulations in place prior to GS rule promulgation. (EPA determined that, absent the GS regulation, requirements similar to Class I industrial well requirements would apply to GS wells and therefore served as the baseline scenario.)

For this reason, costs may seem lower or less comprehensive than expected. This approach, the development of cost estimates that are incremental changes in cost relative to the baseline, is consistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA. As described in section 5.3 (Baseline) of that guidance, "An economic analysis of a policy or regulation compares 'the world with the policy or regulation' (the policy scenario) with 'the world absent the policy or regulation' (the baseline scenario)."

Commenter Name: Robert Bessette Letter ID: 0139 Commenter Organization: Council of Industrial Boiler Owners (CIBO) Comment ID: 23087 Other EPA Comment Codes and Descriptions: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 CFR 146.85)

Comment: D. Cost Prohibitive Requirements

Owners and operators will be responsible for numerous requirements under the proposed regulations. Specifically, they must provide financial assurances thatthey will be responsible for any corrective action, well plugging, emergency and remedial responses, and the postinjection site closure. These assurances will be cost-prohibitive for all but the most financially sound owners and operators. Moreover, the true cost of owning and operating an injection well is incalculable because the liability remains unknown and, consequently, insurers are unwilling to take the risk of backing the project. The probability that costs will balloon out of control make carbon capture and sequestration infeasible, even for the most dedicated of owners and operators. In January 2008, the Department of Energy cancelled its $1.8 billion in funding for the FutureGen CCS project because costs had soared to almost double the estimate provided in 2004. The proposed regulations place too high a financial burden on potential owners and operators and will actually discourage new projects.

Response: EPA notes that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

The goal of financial responsibility is to assure that resources are available to prevent endangerment of USDWs from improper plugging, remediation, and management of wells in the event that the owner or operator experiences financial difficulties. EPA believes that assuring financial responsibility for corrective action on wells in the AoR, injection well plugging, PISC and site closure, and emergency and remedial response at GS sites is an important component of ensuring that USDWs are protected. EPA has specified acceptable financial responsibility instruments in the final regulation.

EPA anticipates that the availability of third-party GS financial instruments will grow in response to demand for such instruments as deployment of GS technology increases in the future. In addition, EPA plans to allow owners or operators to choose from a variety of financial instruments to meet their financial responsibility needs, allowing them to select instruments they find easiest to obtain. See the final rule and preamble for further discussion of EPA's final approach to financial responsibility.

Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells and the Director has approved site closure pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to enforcement for regulatory noncompliance. Furthermore, the financial instrument required under §146.85 will be released if it was not used. However, even if a site closure is approved under §146.93, an owner or operator may be held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be held liable for regulatory noncompliance even after site closure was approved if the Director relied on erroneous information (e.g., erroneous modeling data) provided by the owner or operator when approving site closure.

Additionally, an owner or operator may always be subject to any action the Administrator deems necessary to protect the health of persons under §1431 of the SDWA after site closure if there is unanticipated migration towards or into a USDW that causes or threatens imminent and substantial endangerment to public health. The action may include issuing administrative orders or commencing a civil action for appropriate relief. If the owner or operator fails to comply with the order, they may be subject to a civil penalty for each day in which such violation occurs or failure to comply

continues.The Agency clarifies that Class VI well permits may be transferred to another owner or operator pursuant to §144.38, along with all potential liabilities associated with meeting the requirements of that permit. Please see further clarification on the issue of long term liability in the preamble of the

final rule.

Furthermore, after site closure an owner or operator may remain liable under tort and other remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the State or federal government or a third-party fund. See the final rule preamble for further discussion of EPA's final approach.

The Agency clarifies that sequestration costs are expected to be a small component of total CCS project costs. EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs, according to the cost analysis for the final GS rule, which is in the rulemaking docket.

Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 22475

Comment: Cost Analysis Technical Support Document

Table 2. Site Characterization Costs The allotment of labor hours seems unrealistically low (this comment applies to most cost tables). Some individual tasks are especially low (e.g., develop list of penetrations into injection zone = 12 hours).

In this table and others, labor rates appear to be low - perhaps underestimated by a factor of 1.5 to 2 depending on task/activity.

It appears that some important site characterization activities/tests have not been included - e.g., wireline logging, hydraulic testing, fluid sampling and analysis. These should be included.

3D seismic survey costs may be underestimated - recent quotes suggest ~$100 K per square mile. 2D seismic should be allowed because 3D may be impracticable to implement in many/most areas.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: EPA has considered each public comment on the assumed hours needed to perform each task and in few instances, such as hours required to perform reservoir simulation modeling, has made upward adjustments. Note that the cost algorithms apply to specific units of measure that need to be multiplied by one or more factors to produce the total hours or dollars required per site or per project. For example, the time needed to develop a list of penetrations into the injection zone using well history databases or maps is assumed to be 12 hours per square mile. A 25 square mile site would require 12 hours per square mile x 25 square miles per site = 300 hours per site. EPA assumes that four candidate sites must be evaluated to find a feasible saline aquifer site; therefore, the total time per project is 300 hours per site x 4 sites per project = 1,200 hours per project for well searches. Moreover, this cost item is just for searching well histories in databases and maps. There is aseparate cost item for physically looking for wells using air and ground magnetic surveys.

Using industry survey data from AAPG and SPE as presented in the cost analysis, EPA increased the estimated labor rates significantly from the BLS estimates used in the cost analysis for the proposed rule. The updated loaded hourly labor rates in the final rule cost analysis are $107.23 and $110.62 in 2008 dollars for engineering geologists and engineers, respectively. These correspond approximately to annual salaries of $139,400 and $143,800 and represent increases from the proposed rule analysis.

EPA clarifies that costs for wireline logging are included under the monitoring costs; these monitoring costs are estimated at $10,400 per monitoring well. Monitoring costs are assumed to include measurements of pressure, temperature, and resistivity above or into the injection zone. Fluid sampling costs for measuring salinity, CO2, tracers, etc., in or above the injection zone (a portion of equipment may be at surface, e.g., for periodic in situ sampling using U-tubes) are also included in monitoring costs. EPA notes that costs for analyzing water-CO2-rock geochemistry and mineral

interactions are accounted for under the site characterization costs.

To account for hydraulic and fluid testing, site characterization costs also include unit costs for obtaining geomechanical information on fractures, stress, rock strength, and in situ fluid pressures from existing data and literature and from new cores and tests.

EPA acknowledges that the seismic survey costs used in the proposed rule cost analysis (and associated documents) may have been underestimated. Based on several published reports that present a range of $40,000 to $160,000 per square mile, EPA's final cost analysis is based on an estimate of $104,000 per square mile. The Agency clarifies that site characterization requirements at §146.82 do not specify the use of 3D seismic. Instead, the requirements afford owners or operators the flexibility to select technologies that are appropriate to a given site provided the technologies produce sufficient information to demonstrate that a site is appropriate for GS. Using the cost of 3D provides for a more conservative estimate in cases where 2D may be appropriate.

Costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. The estimate of the costs for transporting CO2, for example, has been updated from the previous $3 to $4.60 per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA

Foundation.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29276

Comment: Table 3. Monitoring Costs Costs for FEED study should be higher. Monitoring a CCS site will require in-depth planning.

Monitoring wells will need to be of a large enough diameter to accommodate down-hole instrumentation (e.g., cross-well seismic); thus, costs for monitoring wells based on slim-hole prices may not be appropriate.Number of hours allocated for updating reservoir model based on monitoring data and conducting simulations, recalibrating etc. is grossly underestimated.

Costs need to be included for assimilating, evaluating, interpreting the enormous amount of diverse monitoring data that will be generated. The currently allocated amounts - 20 hrs for an annual report, 15 hrs for quarterly reports, and 8 hrs allocated for monthly reports - are unrealistically low.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: EPA believes that the cost estimate for front end engineering design (FEED) work specified under element B-3 is appropriate, as it only encompasses design work for monitoring and not other project components. FEED work for injection wells is covered under cost element C-1.

EPA acknowledges that slim-hole wells (deepest casing of 3.5 inches in diameter) may not accommodate the necessary monitoring equipment. Therefore, in its final rule cost analysis, EPA estimates drilling costs for monitoring wells that are 5.5 inches in diameter.

EPA notes that, in the cost analysis for the proposed rule, a less sophisticated reservoir model was assumed for the lower-cost regulatory options. However, for the selected regulatory option as presented in the proposed and final rules, unit cost B-18 applies. Unit cost B-18 accounts for updating the complex model every 5 years and applies to all projects under the GS rule. This includes 180 hours of engineer's time per site plus 64 hours of engineer's time per well, which EPA believes to be an appropriate estimate.

EPA agrees that interpretation and reconciliation of monitoring data is an important part of site monitoring and that considerable resources must be devoted to that task. This effort is captured under cost item B-18 for periodic calibration and running of complex reservoir simulation models to track past and future migration of the CO2 plume and other reservoir parameters such as pressure gradients. As described above, this effort is estimated to require 180 hours per site plus 64 hours per injection well. For example, a site with four injection wells would take 436 hours per model update. Much of the effort for the update would be a history matching exercise in which monitored data (injection volumes, injection pressures, reservoir pressures, plume location, etc.) are reconciled in the model to develop the best current picture of reservoir performance. Other cost items for compiling and submitting periodic reports are intended to cover the time needed to prepare the reports themselves. The modeling and report preparation efforts are expected to be higher at first, then are expected to decrease substantially over the learning curve for operators. The labor burden estimated in the cost model represents a long term average of the labor expected to be needed.

Costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. The estimate of the costs for transporting CO2, for example, has been updated from the previous $3 to $4.60 per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA

Foundation.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29277

Comment: Table 4. Well Construction Costs FEED cost seems high if this is intended to cover the design of the injection wells.

UIC permit costs are grossly underestimated ($10,000 per site plus $5,000 per injection well)

Rights of way costs should be based on area (e.g., acre) not well

Costs for wellhead and control equipment is underestimated. A wellhead (with Christmas Tree) alone can cost more than $100K. Controls can also be quite expensive if they include automated valves, real-time downhole sensors,

automatic shut-offs etc.

Pumps will not be required at all sites, i.e., if compression alone can achieve required injection pressures.

Pipeline costs are likely underestimated ($60K per inch mile all inclusive).

Surcharge for corrosion resistant casing ($1.75 per ft-inch diameter) and tubing ($1.10 per ft-inch diam) seems underestimated based on recent quotes

obtained from this reviewer.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: EPA clarifies that the front end engineering cost (FEED) estimated under unit cost itemC-1 includes the entire project FEED (including the costs of design and engineering as well as preoperational logging, sampling, and testing), with the exclusion of FEED for monitoring wells, which is covered by unit cost item B-3.

In the final rule, the costs for operators to compile and submit the necessary UIC permit applications for a given site are $10,400 per site plus $6,000 per well for the first five wells at a site and $2,000 per well for subsequent wells. EPA believes this cost is adequate based on the efficiencies realized in filing multiple well applications for a given site.

Effectively, the cost model does assign right-of-way costs on a per area basis; the cost model includes a pro forma case for each type of project (saline vs. ER and pilot vs. commercial scale) that is based on a fixed number of injection wells and a fixed square-mile area. For a representative saline commercial project, EPA assumes that the area is 23 square miles and there are 4 injection wells. Costs for surface rights of way are then equivalently expressed as $80,000 per project site (23 square miles) or $20,000 per injector.

The unit cost estimate for wellhead and control equipment used in the cost analyses for both the proposed and final rules is based on a 2008 Petroleum Services Association of Canada (PSAC) Well Cost Study and accounts for the maximum tons injected per well per day. EPA notes that in the cost analysis, wellhead and control equipment costs for pilot-scale saline projects are less than $100,000, but costs for commercial-scale saline projects are greater than $100,000; these cost estimates are consistent with the commenter's suggestion.For costing purposes, EPA adopts the conservative assumption that all project sites will need compressors/pumps. This costs $20,700 per injection well and $1,550 per pump horsepower.

EPA acknowledges that the pipeline cost estimate in the cost analysis for the proposed rule of $60,000 per inch-mile may be an underestimate. In the final rule cost analysis, EPA is using an estimate of $83,000 per inch-mile based on pipeline cost data reported to FERC and published annually in the Oil and Gas Journal.

The cost of corrosion-resistant casing ranges from $1.81 (low alloy) to $2.70 per foot length-inch diameter (higher alloy).

As described above, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final

rule docket.

Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29278

Comment: Table 5. Area of Review/Corrective Action Costs The amount of time allotted for fluid/reservoir modeling is too low to construct, calibrate and simulate CO2 fate and transport.

Labor rates of $53.52 per hour are unrealistically low.

Well remediation costs appear to be low - see TCEQ cost spreadsheet for estimating costs for plugging/abandoning wells.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: As noted previously, in the final GS Rule cost analysis, EPA assumes that all GS well owners or operators will perform complex fluid flow modeling, rather than less sophisticated modeling as assumed for some projects in the proposed rule. EPA estimates this modeling will require 180 hours per project, plus 64 hours of engineer labor per injection well.

EPA acknowledges that corrective action costs (presented in D-7 and D-8) will vary widely. However, EPA notes that the logging and plugging costs are based on the 2008 Petroleum Services Association of Canada (PSAC) Well Cost Study. The estimate in the cost analysis for both the proposed and final rules assumes 3 days of rig use at $10,400 per day (these costs are from the Land Rig newsletter, US Land Rig Rates, November 2007).

Regarding labor rates, as described above, EPA increased the estimated labor rates significantly from the BLS estimates used in the cost analysis for the proposed rule. Additionally, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29279

Comment: Table 6. Well Operation Unit Costs It isn’t clear how/why this is distinguished from Mechanical Integrity Testing.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: The costs for MITs were separated from operating costs to allow easier analysis and discussion by EPA of alternative regulatory options related to operations and testing and monitoring, including the frequency at which different MIT tests might be required.

As described above, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis.

Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29280

Comment: Table 7. Mechanical Integrity Tests Unit Costs Based on recent quotations obtained by this reviewer for these types of tests, the costs listed here are too low. In addition, there will be ancillary costs associated with conducting these tests such as the cost of a service rig.

Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.

Response: MIT costs were developed based on the following sources: Carbon Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner Field, Norway, S. Soloman, Bellona Foundation, May, 2007; UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage, Jonathan Koplos, Bruce Kobelski, Anhar Karimjee, and Chi Ho Sham, Fifth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May, 2006; Determination of the Mechanical Integrity of Injection Wells, EPA Region 5 website, www.epa.gov/region5/water/uic/r5guid/r5_05.htm; and Underground Injection Control Rules, Montana Board of Oil and Gas Conservation, www.bogc.dnrc.state.mt.us/uicrules.htm.

As described above, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final

rule docket.

Commenter Name: Michael Mudd Letter ID: 0167 Commenter Organization: FutureGen Alliance (FGIA) Comment ID: 29281

Comment: Table 8. Post Injection Well Plugging etc Cost for flushing wells is estimated at $500; this will not cover all the materials and services required to accomplish this. Costs that are identified as "initial estimates" or "ICF estimates" should be assigned very high uncertainty/low confidence.Well plugging/abandoning costs appear to be low - see TCEQ cost spreadsheet for estimating costs for plugging/abandoning wells.

Response: EPA acknowledges that the estimates in the proposed rule cost analysis for flushing wells with a buffer fluid were too low. In the final rule cost analysis, EPA increased the costs to $1,000 plus $0.085/inch-foot of casing diameter.

There are five cost items that relate to the per-well cost of abandoning injection wells. Those items and their values for a typical 4,000 foot deep well are as follows:

? G-3: Perform a mechanical integrity test prior to plugging to evaluate integrity of casing and cement to remain in ground ($18,670) ? G-1: Flush wells with a buffer fluid before closing ($1,340) ? G-2: Plug injection wells with cement and mud ($24,900) ? G-5: Remove surface equipment, structures, restore vegetation ($25,900) ? G-12: Operating G&A ($14,162)

The total cost of these items is $84,972 for a 4,000 foot deep injection well. EPA believes these costs to be conservative and in line with rule-of-thumb costs of $50,000 per well in most Texas counties (based on $10 per foot of abandoned well and oil/gas well bond requirements).

As described above, costs identified in the proposed rule as "initial" or "ICF" estimates have been reevaluated to confirm or refine them, based on either industry sources or EPA's best professional judgment, as shown in the appendix of the cost analysis. For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final

rule docket.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24270

Comment: In several significant areas, the assumptions for what is required to comply with the new requirements in the cost analyses seem far less comprehensive than what appears to be described in the proposed regulations.

Preliminary interpretation of the requirements set forth in the proposed rule appear, in some these cases, to be much more comprehensive than that assumed to be performed as part of the cost analyses. Several examples are provided below:

Geologic Siting Requirements

The costs assumed to be associated with the process of geologic site evaluation seems to be underestimated significantly relative to what the proposed GS rule requires. The rule contains over four pages worth of fairly detailed requirements for GS site selection and approval, including the following for owners or operators to prepare and submit:

“ Maps and cross sections of the USDWs near the proposed injection well.

“ Demonstration that the injection zone is: (1) sufficiently porous to receivethe CO2 without fracturing and (2) extensive enough to receive the anticipated total volumes of injected CO2. For this demonstration, owners or operators need to submit geologic core data, outcrop data, seismic survey data, cross sections, well logs, and other data that demonstrate the lateral extent and thickness, strength, capacity, porosity, and permeability of subsurface formations. They must demonstrate that the injection zone should be of a sufficient lateral extent that the CO2 can move a sufficient distance away from the well and still remain in the same zone, without displacing fluids into USDWs. His would require that structural features of a potential injection zone reservoir, such as the lateral extent, dip, or the presence of "pinchouts" (i.e., thinning or tapering out) can affect storage potential, would need to be examined.

“ Data on the local geologic structure, including information on the presence of any faults and fractures that transect the confining zone and a demonstration that they would not interfere with containment. These data are to support determinations about whether these features, if present, could potentially become conduits for movement of CO2 or other fluids to shallower layers, including USDWs.

“ Results of geomechanical studies of fault stability and rock stress, ductility, and strength.

“ Information on the seismic history of the area and the presence and depth of seismic sources to assess the potential for injection-induced earthquakes. Information on insitu fluid pressures is required to assess the potential for the pressures associated with injection to reactivate faults or to determine appropriate operating requirements.

“ Demonstration of the application one or more of a variety of techniques to characterize the receiving zones and confining zones of proposed GS sites. For example, geologic core data, test wells, and well logs can help determine rock formations’ strength and extent. Seismic and electrical methods can be used to reveal subsurface features. Gravity anomalies indicate density variations at depth, and gravity surveys can be used to locate voids, such as cavities and abandoned mines. Numerous geophysical logging tools can determine formation porosity. Large scale, regional pressure tests can also provide insight into the fluid flow field and the presence and properties of major faults and fractures that may affect flow and transport of CO2 and displaced brines.

“ Demonstration of the maximum sustainable injection pressures that will not cause unpermitted fluid movement, in order to assure that owners or operators not exceed an injection pressure that would initiate or propagate fractures in the confining zone. This should be based on geomechanical studies of fault stability and rock stresses and strength, along with an examination and interpretation of geological maps and cross sections, seismic and well surveys, determination of local stress fields, and modeling,

“ Information on the geochemistry of formation fluids that can affect whether a site is suitable for GS; to include what CO2 may act as a solvent, mix with native fluids to form carbonic acid, lead to the potential liberation of heavymetals into the formation fluids or break down the rock matrix or precipitate minerals and plug pore spaces, therefore reducing permeability (IPCC, 2005). Studies of rock samples and review of geochemical data from monitoring wells would be needed to evaluate the impact of these effects. Owners or operators are to submit geochemical data on 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.

According to the EPA cost analysis, the acquisition and interpretation of most or all of that described above, along with the reporting of this information according to the specifications set forth in the proposal, would amount to about 3.5 person-months of effort, or about $90,000. Recent Advanced Resources’ experience on the DOE SECARB GS demonstration project indicates, at least for this early project, costs are likely to be five to ten times or more than this for a small scale pilot project. Similar work Advanced Resources has done for the International Energy Agency Greenhouse Gas Program (IEA GHG) indicates that costs for site selection and project design for a commercial scale project could range from $5 to $20 million per site.[FN2]

[FN2: Advanced Resources International, Remediation of Leakage from CO2 Storage Reservoirs, IEA/CON/04/108, Report prepared for the IEA Greenhouse Gas R&D Programme, January 17, 2007]

In particular, meeting many of the requirements set forth in the proposed regulations for GS site selection will very likely require the drilling of stratigraphic and/or delineation wells. This will be especially true in deep saline aquifers. No costs associated with such wells appear to be considered in the EPA costs analyses for site selection (see discussion below).

Record Keeping and Reporting Requirements

EPA proposes that:

"...permit applications for GS sites include several plans not currently required under existing UIC regulations. These plans include a monitoring and testing plan, an AoR and corrective action plan, and a post-injection site care and site closure plan. The requirement for additional plans is intended to provide the Director the opportunity to assess proposed project operating procedures, and addresses GS requirements that are seen to be site-specific (e.g., what monitoring techniques will be used). In addition, these plans are intended to establish an ongoing dialogue between the operator and the permitting authority which is more substantial than that required for other classes of injection wells."

In EPA’s costs analyses, it appears that only costs associated with the incremental monitoring and testing plan were considered.

Response: EPA clarifies that all cost estimates are incremental and presented as an annualized present value. Incremental values are presented to capture only those costs directly attributable to theGS Rule, which take into account the costs that would be incurred under regulations already in place prior to GS rule promulgation (i.e., the baseline). Calculation of costs as an annualized present value is a typical economic costing methodology that accounts for the time preferences for expenditures (present value calculations) and allows for comparison of costs across rules that are incurred onvarious timelines. These factors result in the presentation of costs that are much lower than the nondiscounted costs of the regulation.

EPA has considered each comment on the assumed hours needed to perform each task and in a few instances, such as performing reservoir simulation modeling, has made upward adjustments. EPA also determined that in some cases multiple sites would be characterized before an owner would find a site that was a good candidate for a project. Therefore, EPA increased the site characterization costs by a factor of four for saline projects. Site characterization costs for ER projects were not increased, based on the assumption that ER sites would already have a significant amount of data available to preselect those sites that have a better chance of meeting requirements.

For the final rule, the estimated total (non-incremental) non-discounted cost for site characterization for a pilot saline project is $1.3 million. In incremental terms, this non-discounted estimate is $453,000, which translates to an annualized present value of $26,000. This approach (i.e., the development of cost estimates that are incremental changes in cost relative to the baseline), is consistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA.

EPA clarifies that it included costs of delineation wells under the category of stratigraphic testing (catalogued as cost element A-7). As presented in the Appendix A of the Cost Analysis, EPA assumes that a stratigraphic test well with a depth of 9,350 feet will need to be drilled for a

commercial-scale saline reservoir.

Regarding the cost and burden associated with the plans required with the permit application (i.e., the plans for AoR and corrective action, monitoring and testing, emergency and remedial response, injection well plugging, and post-injection site care and site closure), EPA clarifies that the burden for these plans has been addressed in the cost analysis for the final rule. EPA notes that the burden for permit applications under the baseline (based on Class I nonhazardous well requirements) includes burden for completing basic monitoring and testing plans, corrective action plans, and well failure contingency plans, as required at 40 CFR 146.14(a). A well plugging plan is also required under the baseline at §146.14(c). The incremental burden associated with writing these plans under the final rule is assumed to be negligible. Because post-injection site care and site closure plans are not required under the baseline, EPA added burden for such plans to section 5.4.7 of the cost analysis.

Burden incurred to obtain the additional information needed to complete the more detailed plans now required under the final rule and to compile this information into the plans is addressed in sections 5.4.3 (AoR and Corrective Action) and 5.4.7 (Monitoring).

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29282

Comment: Financial Responsibility RequirementsThe proposed rule states:

"Today’s proposal would require that owners or operators demonstrate and maintain financial responsibility, and have the resources for activities related to closing and remediating GS sites. EPA is proposing that the rule only specify a general duty to obtain financial responsibility acceptable to the Director, and will provide guidance to be developed at a later date that describes recommended types of financial mechanisms that owners or operators can use to meet this requirement."

Obviously, since these requirements are not specified in the rule, they were not explicitly and quantitatively considered in the EPA cost. These costs will be a very important factor in deciding whether GS projects are pursued. At least some discussion of the uncertainty associated with these costs, and the potential implications associated with this uncertainty on EPA’s conclusions, at a minimum, is warranted.

Response: Both the proposed and final GS Rule included a requirement for a demonstration of financial responsibility. The cost for demonstrating financial responsibility is distinct from the cost associated with the low probability of site failure and remediation of the site, which is included as a separate item and defined as a low percentage of capital expenditures on an annual basis. EPA included in the cost analysis for proposal and for the final rule the unit cost for demonstration of financial responsibility, which consists of the labor hours necessary to compile the firm’s financial information and project-related cost information to demonstrate financial capacity to address a problem, including the potential for complete failure and resulting closure of the site.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29283

Comment: Site characterization costs considered in the EPA cost analysis do not include any costs for delineation wells.

For any target formation for GS that has not been extensively characterized by a large number of wells (such as deep saline aquifers, in contrast to the generally relatively well defined depleted oil and gas fields), some wells will most likely need to be drilled to better understand the geology at or very near where the injection will take place. In many target formations, the information required for proper site characterization (cross sections, performing inter-well seismic, the acquisition of geochemical, geomechanical, and geophysical information, the relative location of the target injection zone and USDWs, characterization of the confining system, etc.) will require drilling additional some wells. In fact, this could often involve drilling several wells to understand both vertical and areal heterogeneity in the vicinity where injection will take place. EPA’s cost analysis appears to conclude that no well drilling will take place as part of the geologic characterization of the GS site.Perhaps it is EPA’s assumption that the monitoring wells assumed under their characterization of monitoring costs will serve that purpose. If that is the case, then that needs to be made clear.

Labor rate assumptions for engineers in the EPA cost analysis are much too low.

For most labor related activities assumed in the EPA cost analysis, it was assumed that tasks would be performed by either geologists or engineers. The geologist’s hourly labor rate was assumed to be $106.21 per hour, while the engineer’s hourly labor rate was assumed to be $53.52 per hour. Assuming 2,080 hours per year (including vacation), and a overhead markup ranging from 2.0 to 2.5, would result in a "representative" geologist’s salary of $88,000 to $111,000 per year, and a "representative" engineer’s salary of $44,000 to $56,000 per year.

The American Association of Petroleum Geologists (AAPG) performs an annual salary survey of its members.[FN3] Based on this survey, if one assumes that the geologists performing the assignments have five years of experience or less, the assumed labor rates or geologists are reasonable. However, it is important to note that in the last 3 years, these salaries have risen by 35%.

[FN3: http://www.aapg.org/explorer/salarysurvey.cfm]

Because of the similarities in the engineering tasks associated with GS and those associated with developing and producing oil and gas, it would be reasonable to assume that most engineering tasks associated with GS would be preformed by individuals trained as petroleum engineers. The EPA cost analyses assume that these would be performed by geologic or mining engineers.

The Society of Petroleum Engineers also performs an annual survey of its members, the last one conducted in September 2007.[FN4] The result of this survey shows that the mean annual salary of petroleum engineers in the U.S. was nearly $134,000. The average annual salaries for petroleum engineers with 0-10 years of experience were a little over $92,000. Of the various types of petroleum engineering categories considered in the survey, reservoir engineers (the most likely types to be involved in GS site characterization, reservoir modeling, and monitoring types of activities) where the second highest paid category (behind finance /administration), with average annual salaries for those 0-10 years of experience being a little less that $100,000.

[FN4: http://www.spe.org/spe-app/spe/career/salary_survey/index.htm]

Based on this, it seems that the labor rate assumptions for engineers in the EPA cost analysis were much too low, perhaps by a factor of two or more. (The assumed labor rate for engineers in EPA’s cost analyses are somewhat low even for mining engineers with some experience.[FN5],[FN6]) Since a large number of tasks are assumed to be performed by engineers in EPA’s assessment, this could have a substantial impact on their overall cost impact characterization, perhaps on the order of about $60,000 per GS site.[FN5: http://www.bls.gov/oco/ocos027.htm#projections_data] [FN6: http://www.payscale.com/research/US/Job=Mining_Engineer/Salary]

Response: For the final rule cost analysis, EPA updated labor costs using survey information from the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Engineers (SPE), resulting in an increase of 115% in the rate for engineers. EPA believes the updated labor rates are consistent with those in the field and representative of labor costs for GS projects.

Using industry survey data from AAPG and SPE as presented in the cost analysis, EPA increased the estimated labor rates significantly from the BLS estimates used in the cost analysis for the proposed rule. The updated loaded hourly labor rates in the final rule cost analysis are $107.23 and $110.62 in 2008$ for engineering geologists and engineers, respectively. These correspond approximately to annual salaries of $139,400 and $143,800 and represent increases from the proposed rule analysis.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29284

Comment: Injection well drilling cost assumptions in the EPA costs analysis are reasonable based on today’s conditions, but may not properly reflect recent increases in costs, as well as, importantly, the situation where demand for well drilling services in the GS industry expands dramatically, perhaps increasing costs correspondingly.

The most expensive activity likely to be associated with GS will be the costs associated with drilling injection wells, along with associated wells required for monitoring and site characterization. EPA assumes that the costs associated with just drilling injection wells can range from $210 to $280 per foot for wells typically drilled to a depth of on the order of 9,000 feet. Including all costs associated with well drilling and completion increases the range to from $280 to $320 per foot for a 9,000 foot well.

According to the latest drilling cost survey by the American Petroleum Institute (for 2006):[FN7]

“ The average costs of drilling and completing wells in the U.S. (not including sidetrack wells) was $378 per foot. The average well depth in the U.S. was 5,560

feet.

“ The average well cost for all onshore wells in the 7,500 to 10,000 foot depth category was $2,660,000. The average depth of wells in this category was 8,722 feet. This then equates to an average cost of about $305 per foot.

[FN7 American Petroleum Institute, 2006 Joint Association Survey on Drilling Costs, April 2008]

As another point of reference, Advanced Resources has drilled a GS wellassociated with a demonstration project in Mississippi, and is in the process of developing an AFE for a new well. Based on this experience:

“ A recent well drilled to 14,500 feet cost a little over $3,200,000, or about $215 per foot.

“ The drilling and completion costs estimated for a planned new injection well to be drilled to 10,000 feet would be on the order of $1,800,000, or about $175 per foot.

Based on all this, EPA’s assumed injection well costs, on average, are within the range associated with recent well drilling costs.

However, it is important to note that the 2006 API drilling cost survey shows that drilling costs, on average, nearly doubled between 2003 and 2006, and that trend has continued after 2006. Moreover, if demand for drilling wells associated with GS increases dramatically, causing competition for drilling rigs between oil and gas exploration and production and GS, drilling costs are likely to rise even more, perhaps substantially. This should be at least noted, if not accounted for, in EPA’s cost assessment.

Injection well cost assumptions in the EPA costs analysis appear not to reflect all of the additional requirements on well construction that the proposed regulations may require, in particular, the potential costs of .

As described above, while EPA’s drilling cost assumptions appear consistent with current well drilling and completion costs, the proposed regulations may require substantial enhancements to standard drilling requirements. For example, the proposed rule states:

"Due to the buoyancy of CO2, today’s proposal includes enhancements to typical deep well construction procedures to provide additional barriers to CO2 leakage outside of the injection zone. The proposal would require that surface casing for GS wells be set through the base of the lowermost USDW and cemented to the surface. The long-string casing would be cemented in place along its entire length. GS wells would also be constructed with a packer that is set opposite a cemented interval, at a location approved by the Director."

It is not clear that the costs of all of these additional requirements were

considered in EPA’s cost assessment.

Moreover, the proposed rule recognizes that under some circumstances, fracturing of the injection zone may be necessary to allow sufficient injectivity of CO2 (provided a specified set of conditions are met). This will be particularly true for very deep and low permeability aquifers. No consideration of such fracturing costs is apparent in EPA’s cost analyses.

EPA appears not to consider the costs of surface equipment associated with CO2 injection operationsIn addition to the Injection wells, additional surface equipment can often be associated with CO2 injection operations. These costs include CO2 storage vessels, high pressure pumps and vaporizers, distribution/production headers, and CO2 distribution lines when multiple injection wells are needed. It is not apparent that all of these costs are included in the EPA costs estimates. This would result in an underestimate of on the order of $60,000 - $70,000 per well. In addition, many sites would require additional compression, and perhaps, substantially more extensive piping infrastructure; costs also not apparently considered in EPA’s analyses. If this is the case, the cost underestimate could be substantially greater.

Response: With regard to injection well costs, EPA acknowledges that the proposal cost analysis underestimated the necessary surface casing lengths, which must be long enough to be set through the base of the lowermost USDW (to meet the requirements of the final GS regulation). The Cost Analysis for the final GS Rule assumes that surface casing will run from the wellhead to the base of

the lowermost USDW.

EPA acknowledges that hydraulic fracturing is a practice that may be employed at some GS project sites. However, it is a practice that is not required, entails additional permitting, and can only be undertaken with Director’s approval. Because of these factors, EPA believes it is a practice that will be minimally employed and did not include it in the cost analysis.

EPA did consider the cost of surface equipment associated with CO2 injection. The unit cost estimate for wellhead and control equipment used in the cost analyses for both the proposed and final rules is based on a 2008 Petroleum Services Association of Canada (PSAC) Well Cost Study and accounts for the maximum tons injected per well per day. For costing purposes, EPA adopts the conservative assumption that all project sites will need compressors/pumps. This costs $20,700 per injection well and $1,550 per pump horsepower.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 29285

Comment: EPA assumptions that the cost analyses be based on the assumption that there will be no new climate change regulations appears inconsistent with the rationale for the proposed GS rule.

EPA’s cost analyses are based on an anticipated level of GS activity in the United States under the existing regulatory conditions, as per EPA guidelines on economic analysis. In this baseline analysis, EPA assumes that there will be no new national climate change regulations. Based on this assumption, EPA assumed there will be only 22 projects that would be affected by the proposed GS rule. These projects include 12 anticipated DOE pilot projects, 3 projects proposed by DOE under the restructured FutureGen program, and 7 anticipated projects to be developed under state and regional incentive programs.[FN8]

[FN8: Environmental Protection Agency, "Cost Analysis for the Proposed Federal Requirements Under the Underground Injection Control Program for Carbon DioxideGeologic Sequestration Wells (Proposed GS Rule)" Office of Water (4606-M) July 2008 (pp. 3-4 to 3-5)]

EPA does recognize that alternative assumptions about the future deployment of projects could dramatically change the potential costs of the proposed rule, [FN9] and performed a sensitivity analysis on this assuming a 50% increase in the number of projects.

[FN9: Ibid, p 5-33]

Nonetheless, this appears to be somewhat inconsistent with the primary rationale for the rule. In the introductory discussion in the proposed GS rule, EPA describes the important role that GS can play in helping to mitigate global greenhouse gas emissions, and states that:

"CCS technologies could potentially represent a significant percentage of the cumulative effort for reducing CO2 emissions worldwide."

Moreover, the draft of the proposed GS rule goes on to say:

"Establishing a supporting regulatory framework for the future development and deployment of CCS technology can provide the regulatory certainty needed to foster industry adoption of CCS, which is crucial to supporting the goals of any proposed climate change legislation."

However, despite this rationale, the EPA cost analyses basically assume that no new GS projects other than those already proposed would result from the implementation of the proposed rule.

If this is in fact the case, it inevitably leads to the question: Why issue the proposed rule in the first place? All of the proposed projects assumed in the baseline are in the process of being pursued under existing regulatory authorities; and are not necessarily dependent on the promulgation of a new GS rule to be pursued.

Response: EPA clarifies that addressing climate change is outside the scope of the GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a manner that protects USDWs from endangerment.

Because EPA cannot predict the future deployment of projects not yet in the planning stages, EPA developed the GS Rule project baseline using a survey conducted with regional partners in 2010 from DOE and additional projects from industry knowledge and publicly available data. Using a costing baseline that is based on current legislation only, and that does not take into account predictions of future legislation, is also consistent with OMB guidance Circular A-4 on how to conduct economic analysis in support of rulemaking. However, EPA realizes the inherent uncertainty in the assumptions of baseline deployment, and did conduct a supplemental analysis that considered an alternative legislative scenario. The results of this supplemental analysis are provided in the Cost Analysis document (Chapter 5).

EPA notes that the baseline number of projects used in the proposal cost analysis is based on theassumption that if any project could possibly get approved under current regulations, that permit would most closely resemble a Class I Non-Hazardous well. In both the proposal and final rule cost analysis, the baseline scenario used for costing was then considered to be Class I non-hazardous regulations, and the changes in risk and costs incurred under each regulatory alternative were compared to that baseline to determine the relative risks and incremental costs of the GS Rule.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Edward Steadman Letter ID: 0220 Commenter Organization: The Energy and Environmental Research Center at the University of North Dakota Comment ID:

21629

Comment: Pages 43525 to 43526. Regarding cost of compliance. EPA compares the costs associated with standard Class I wells and the proposed Class VI wells and estimates that the proposed rules would increase the costs of complying with UIC regulations by 46%. The EPA also states that it they "believe[s] the proposed rule will not impede CO2 GS from happening...." First, a 46% increase in costs is significant. Second, to profess that such a large increase in costs will not impede the implementation of GS projects seems rather naïve.

Response: EPA clarifies that the GS rule addresses costs associated with sequestration only, i.e., not capture or transportation. Sequestration costs are expected to be a small component of total CCS project costs. Increasing this small component of the total CCS costs by 48 percent (i.e., based on final GS Rule costs) amounts to approximately a 2 percent increase in total CCS project costs.

EPA clarifies that the GS regulation does not promote or encourage the use of GS; rather it is designed to ensure consistency in permitting underground injection of CO2 at GS operations across the United States and provide requirements to prevent endangerment of USDWs in anticipation of

the eventual use of GS to reduce CO2 emissions.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23972 Other EPA Comment Codes and Descriptions: 3824 2.3.1.2 Cementing of long-string casing (seeking comment)

Comment: EPA Proposed §146.86 (b) Casing and Cementing of Class VI Wells. (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages.

*

*

* (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered.Additional proposed requirements affecting casing and cementing of Class VI wells is set forth in §§ 146.86 (b)(3) and (5) as quoted above. The requirement, to cement the casing to the surface is unnecessary, expensive and contrary to best practices. Under acceptable best practices, the long string casing would not be cemented to the surface so that the pressure between the surface casing and long string can be monitored to determine if there is migration between the long-string casing and the surface casing. The cementing requirement proposed above would limit the ability to monitor for migration of injected fluids, in this case CO2, behind the casing. Additionally, TxCCSA’s field data indicates that the proposed casing and cementing requirements are costly while providing limited, if any benefit. According to our findings, under existing Class II UIC rules, a conventional cementing program costs approximately $20,000 per well. Under the cementing program proposed for Class VI wells the cost could escalate to approximately $193,000 per well a potential $173,000 increase, representing a 10% increase in total per well costs.[FN1]

[FN1: For a typical well completed under Class II UIC rules, the total costs equals $1,700,000.]

TxCCSA suggests an alternative that protects USDWs, but at a reasonable cost. Rather than require cementing of the long string casing to the surface, the proposed rule should require cement and cement additives to be compatible with the carbon dioxide stream and formation fluids that cover the injection zone and the confining zone, and then require standard (API, ASTM International, or comparable standards) industry cements to a certain distance above the confining zone. This would place cements that may require special additives at the point where USDWs are most effectively protected from the mixture of carbon dioxide and formation fluids that could produce carbonic acid.

Response: EPA acknowledges that the Class VI requirements have associated costs beyond baseline costs assumed in the cost analysis for this rule (based on an assumption that Class I industrial wells are the baseline). The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.

The final cost analysis supporting the GS Rule includes cementing costs of $1.20 per foot lengthinch diameter plus 25% of total cementing costs for use of corrosion-resistant cement. For a representative deep saline injection well used in the cost analysis, this translates to a total cementing cost of $406,500 per injection well, representing an incremental cost of approximately 305,000 over baseline costs. This unit cost is in line with estimates provided by the commenter (actual costs are driven by well-specific characteristics). While the rule requirements necessitate these additional costs, the requirements are guided by the necessity to address the unique challenges posed by CO2 injection (including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations) as they protect USDWs from endangerment.

Commenter Name: Neeraj Gupta Letter ID: 0229 Commenter Organization: Battelle Energy Technology (BET) Comment ID: 21869Comment: Cost Estimates- In general most of the estimates for hours, hourly rates, and costs required for implementing the requirements appear to be too low compared to our experience and the complexity of proposed regulatory requirements. It is recommended that EPA obtain more realistic cost estimates for all aspects of the regulations, deep well drilling, monitoring, expert delivery of geosciences and engineering professionals.

Response: The Agency increased some unit costs (e.g., for labor rates, seismic analysis, pipeline, etc.) for the final rule, as described in the cost analysis, to address commenter concerns that they were underestimated. All unit costs were reviewed and updated commensurate with inflation, as explained in the Geologic CO2 Sequestration Technology and Cost Analysis document, which is in the rulemaking docket. In addition, EPA incorporated a site selection factor into the final cost analysis based on the assumption that site selection will be successful between 25 and 100 percent of the time, depending on project type; this factor increased costs for geologic site characterization.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Commenter Name: Lee Sprague Letter ID: 0505 Commenter Organization: Sierra Club Comment ID: 21240

Comment: MR. SPRAUGE: The additional comment I'd like to make seriously around, again around local participation for the processes.

Oftentimes, proposals for electro- generation need to, or incorporate the low cost, the low cost of electricity. And I think it is critical that the full cost of carbon sequestration, along with all of the, the elements that are comprised be storage transportation monitoring, and bonding, that the full cost of carbon sequestration you include in the economic analysis when computing the cost of electricity. The local communities have a measurement to measure alternativerenewables -- kinetic. They have a full way to analyze a complete cost of geosequestration associated with coal fire power facilities with other forms of electric generated unit.

I think that without this uniform analysis or way to cost out what the, how much it's going to actually cost over time for carbon sequestration, that -- out proper tools to make intelligent decisions as to whether the, the best or lowest price cost electricity when making determinations. Thank you very much.

Response: EPA clarifies that the GS rule addresses sequestration only, i.e., not capture or transportation. Any impacts on the cost of electricity are likely to be influenced by all aspects of CCS, including capture, transport, and sequestration. EPA adds that it does not establish or attempt to influence electric costs –they are set by factors the Agency does not control. Sequestration costs are expected to be a small component of total CCS project costs; EPA estimates that the GS rule requirements amount to approximately 2 percent of the total CCS project costs.

EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs. The Agency clarifies that the purpose of the GS regulation, promulgated under authority of the SDWA, is to ensure that, where GS is deployed, it is conducted in a manner that protects USDWs from endangerment.Comment Code: 6200 3.2 Comments on costing methodology



### Individual Comments

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory Comment ID:

22628

Comment: Costs of Compliance with Class VI Rule Seem Methodologically Problematic

On page 43524 EPA acknowledges that there is a need to revisit the Cost Analysis. EPA is commended for recognizing this need and is encouraged to consider fundamentally modifying large aspects of the Cost Analysis of this proposed class VI rule in subsequent revisions. The following is a selection of methodological issues in the economic analysis of this rule that argue in favor of rethinking the approach used here and making significant revisions for subsequent versions of the proposed Class VI rule. Suggestions to consider when revising the cost analysis include:

o Page 43525. I see no rigorous basis for asserting that 22 projects will deploy in 25 years. It would be far better to present costs for a range (high, medium and low) of CCS deployment scenarios and then explain the basis of these

scenarios.

o Page 43527. I also do not understand the rationale for assuming that a power plant would only capture half of its lifetime emissions. Why was that deemed to be an appropriate assumption to make?

o Page 43527. This page includes a reference to a research paper from my technical group as the basis for "we can use a long term average estimate of $3/tonCO2" for transportation costs. This research paper of ours does not speak to that specific monetary figure so I am not sure where that number comes from. There could be many instances where the cost of CO2 transport via a pipeline falls outside this $3/tonCO2 range.

o Page 43530. It is important to note that the determination as to whether this proposed rule will cost the public and or the private sectors more than $100 million in any given year is a function of the pace of CCS deployment which is something that will be driven by future climate policy. If there is no future national climate policy, then the cost of complying with this new rule should be close to $0. If there is a very tight / constraining climate policy, the cost could be significant. The USEPA is encouraged to model out a number of different climate policies and then assess what the incremental cost of complying with this rule is rather than basing the cost on assumptions about there only being 22 pilot projects over the next 25 years. Without doing this calculation, there is no way of knowing how robust the assertion is that the cost of complying with the proposed rule will not exceed $100 million in any given year.o Page 43527. The text here says that it is "unlikely that all coal plants would deploy CCS simultaneously." Not only is it "unlikely" it is simply impossible. There is no reason to hypothesize such a future deployment scenario and the computed results are meaningless for the purpose of public policy making. There is also no need to approach this particular calculation in this manner. My research group has completed a number of studies (as have other research groups) that could bound realistic CCS deployment rates. It is far better to use something within the realm of the possible as a basis for informing / justifying this important rule making. See for example:

o MA Wise and JJ Dooley. 2008. "The Value of Post-Combustion Carbon Dioxide Capture and Storage Technologies in a World with Uncertain Greenhouse Gas

Emissions Constraints." International Journal of Greenhouse Gas Control. In

press.

o Dooley JJ, RT Dahowski, and CL Davidson. 2008. "Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO2 Pipeline Networks." In the Proceedings of the 9th International Conference on Greenhouse Gas Technologies. PNNL-SA-62187, Pacific Northwest National Laboratory, Richland, WA.

o Wise MA, JJ Dooley, RT Dahowski, and CL Davidson (2007). "Modeling the impacts of climate policy on the deployment of carbon dioxide capture and geologic storage across electric power regions in the United States." International Journal of Greenhouse Gas Control. Volume 1, Issue 2, April 2007, Pages 261-270. doi:10.1016/S1750-5836(07)00017-5

o Dooley, James, J.; Davidson, Casie L.; Wise, Marshall A.; Dahowski, Robert T. "Accelerated Adoption of Carbon Dioxide Capture and Storage within the United States Electric Utility Industry: the Impact of Stabilizing at 450 ppmv and 550 ppmv." In, ES Rubin, DW Keith and CF Gilboy (Eds.), Greenhouse Gas Control Technologies, Volume I (pp. 891-899). Elsevier Science, 2005.

Response: In the cost analysis for the proposed rule, EPA used information from contacts in government and industry and its best professional judgment to develop the estimate of 22 baseline projects. The cost analysis also presented a sensitivity analysis that considered a 50-percent increase and a 50-percent decrease in this estimated baseline.

The cost analysis for the proposed rule assumed that each pro forma saline injection site would operate for 20 years and that two sites would be developed to cover the typical 40-year operating life of each power plant. The current cost estimate is based on one storage site operating for 40 years.

In updating the cost analysis baseline for the final rule, EPA consulted with DOE on the current number of planned or actual deployments because GS is in a nascent stage and there has been fluctuation in the number of planned projects. EPA also used publicly available data, e.g., from the Carbon Sequestration Leadership Forum's web site, to estimate the number of projects. Based on the information provided by DOE, the updated cost analysis uses an initial baseline of 29 projects, including 13 in saline formations and 16 at ER sites, as described in Chapter 3 of the Cost Analysis for the Final GS Rule. The final rule cost analysis also presents the alternative deployment scenarios of 50 percent more or 50 percent fewer projects.The estimate of the costs for transporting CO2 has been updated from the previous $3 to $4.60 per ton CO2 based on the following source: “Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges,” Feb. 2009, INGAA Foundation.

For additional information on the final costing approach, please see the final cost analysis and technology and cost document in the final rule docket.

Comment Code: 6210 3.2.1 Comments on the timeframe of the costing analysis (seeking comment)



### Individual Comments

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0114 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 22541 Other EPA Comment Codes and Descriptions: 6100 3.1 Comments on the cost estimates

Comment: COST ESTIMATE

EPA at 73 FR 43524 presents the results of an analysis of the cost to protect USDWs from a Class VI wells. EPA was very specific regarding what they did not include in the regulatory estimate. EPA based the cost estimate on a Class I well of unknown depth, unknown casing size, unknown location and type of reservoir. EPA, using this unspecified well information, calculated the incremental cost to convert the Class I well to a Class VI well. This approach excludes commenters from verifying the accuracy of the EPA estimate because of these omissions. This is reminiscent of the 2004 SPCC Plan cost estimate, where commenters were not privileged to the assumptions EPA provide to its contractor. Unethical instructions and unstated assumptions prevent commenters from testing the accuracy of the cost estimate. We have no means of knowing if EPA provided unethical instructions to the contractor for development of the Class VI well costs, since EPA does not include the assumptions in the publication.

Apparently, EPA told the contractor to use a 25 year after closure monitoring time period (73 FR 43524). Then, EPA proposed a 50 years monitoring period at 40 CFR 146.91 (73 FR 43540). Either the Agency changed its mind after giving the go-ahead to the contractor , but did not revise the proposed rule or the Agency was attempting reduce cost of the rule.

*EPA at Table VII-2 (73 FR 43525) says the cost of baseline project plus Alternate 3 and Alternate 3 increment varies between $94.6 and $98.4 million for 22 sequestration projects or $4.3 million to $4.5 million per project. EPA at 73 FR 42504 provides a non-specific definition of Alterative 3. The definition is words without specificity! We have no inkling of want Alternative 3 entails.

On 28 August 2007, Dr. Holliday discussed these cost figures with the Chairman of the Society of Petroleum Engineers Sequestration Panel. The Chairman’s response was "there is no way in Hell we can conduct a sequestration project for that little money."Response: EPA clarifies that due to the variation expected in individual project specifications, a pro forma (representative) project was used in the cost analysis to provide a reasonable estimate on a national basis for the purpose of selecting between regulatory options and development of the final regulation. This approach is consistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA. Detailed information on the pro forma assumptions and unit costs applied in the analysis are included in the appendix to the cost analysis, which is in the rulemaking docket.

EPA clarifies that cost estimates are presented in incremental terms, that is, the costs beyond those estimated to be incurred if the projects were operating under regulations in place prior to GS rule promulgation. (EPA determined that, absent the GS regulation, requirements similar to Class I industrial well requirements would apply to GS wells and therefore served as the baseline scenario.)

For this reason, costs may seem lower or less comprehensive than expected. This approach, the development of cost estimates that are incremental changes in cost relative to the baseline, is consistent with EPA Guidelines for Preparing Economic Analyses (September 2000) and with other major rulemakings under SDWA. As described in section 5.3 (Baseline) of that guidance, "An economic analysis of a policy or regulation compares 'the world with the policy or regulation' (the policy scenario) with 'the world absent the policy or regulation' (the baseline scenario)."

Commenter Name: George Holliday, PhD, PE, BCEE Letter ID: 0127 Commenter Organization: Holliday Environmental Services, Inc. Comment ID: 23056 Other EPA Comment Codes and Descriptions: 5240 2.8.2.2 Post injection timeframe (seeking comment)

Comment: C: WITHOUT TECHNICAL SUPPORT, EPA REQUIREs 50 YEARS OF

MONITORING EXECPT BY

SAYING MORE MONITORING IS EXPENSIVE.

1. Sequestration of CO2 is forever, or we don’t need capture the CO2 in the first place. If the CO2 escapes the Earth the World population is doomed, in accordance with the IPPC theory.

2. EPA provides no justification for selecting 50 years, in fact the proposed rule states the economic contractor was told to develop the cost on the basis of 25 years.

3. It is unclear if the cost is based on 25 or 50 years.

Response: EPA disagrees that the monitoring timeframe was selected based on cost. In determining the post-injection site care-timeframe for the proposed regulation, EPA reviewed industry reports, existing environmental programs, and initial GS research studies. EPA provided a synthesis of pertinent results from GS modeling studies in the preamble to the proposed regulation. Further explanation of this analysis was included in an EPA-prepared background document that is available in the federal docket for the GS rule, titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." Based on review of these studies, modeling results indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years after the cessation of injection. EPA believes that a 50-year default post-injection site care timeframe is a reasonable midpoint for most GS projects and available data, including data submitted by commenters, do not support a differentdefault timeframe, and has retained this in the final regulation. However, EPA recognizes that there may be sites where the 50 year post injection site care timeframe may be either not appropriate or more burdensome than necessary based on site-specific conditions. For this reason, the GS rule offers owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injection period based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to demonstrate, during the permitting process based on substantial data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to adjust the timeframe for a limited number of GS projects during the permitting process where substantial data exists to demonstrate that an alternative timeframe would be protective of USDWs, or based on data collected during the PISC period, is appropriate to address the range of sites where GS is anticipated to occur, to accommodate site-specific circumstances and various geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW impacts.

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking comment)



### Individual Comments

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory Comment ID:

22629

Comment: o Page 43528. The conclusion that "monitoring requirements account for 60 percent of the incremental regulatory costs, of which 70 percent is incurred for the construction, operation, and maintenance of monitoring wells" is likely heavily influenced by the assumption that there would be three monitoring wells for each injector well. The assumption that there are three monitoring wells per injector well is a significant cost driver. It is not clear that this would hold true in a field with multiple injector wells; for example a five spot injection pattern would require 15 monitoring wells, which could be excessive. For GS projects that have very large injection fields with numerous injector

wells there is no reason to believe that this 3:1 ratio would hold true. USEPA should consider modeling out a number of different deployment scenarios to see

how robust this assertion is. This seems to be a worthwhile effort as this is the largest cost component caused by this Class VI rule and therefore this estimated cost is one that could receive a good deal of attention. My sense is that adhering to this 3:1 ratio exaggerates the cost of the proposed Class VI

rule.

Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injectionwells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24268

Comment: Rule Provisions: 73 FR 43527 EPA Preamble Question: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption.

EPA Notice 43527.

API Response: It is difficult to select a realistic ratio since each site will have its own characteristics that would significantly affect the number of monitoring wells necessary.

The attached report prepared by ARI for API discusses the cost modeling in greater detail.

Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project sitecompared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

EPA acknowledges that, at this time, it is difficult to know how many monitoring wells will be used at GS sites. For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Commenter Name: Thomas Curtis Letter ID: 0181 Commenter Organization: American Water Works Association (AWWA) Comment ID: 23717

Comment: Category: Cost Analysis

EPA Request for Comment: The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption.

EPA Notice 43527.

AWWA Response: AWWA does not agree with the assumption to use three monitoring wells per injection well as the standard for the cost analysis. This number seems very low given the amount of area that would be covered by one injection well. Requiring three monitoring wells for an injection well that might be associated with a carbon dioxide plume stretching for over a mile seems like a drastic underestimate of the necessary monitoring. AWWA recommends that the requirement be based more on the projected plume performance and the potential interactions with USDWs or other important geologic formations.

Other cost estimates have indicated that, in the overall cost of the project, monitoring is a very small percentage of the total project cost as compared to those associated with the capture and transport processes. This conclusion is contrary to EPA’s cost estimate, and AWWA is concerned that the EPA’s high cost numbers for monitoring may be used to attempt to reduce the monitoring requirements and lower the overall project cost. AWWA recommends that the cost estimate be revised at a later date based upon data that becomes available fromthe DOE pilot projects. These projects might identify additional well construction costs, as well as be able to provide a better understanding of how the cost of monitoring compares to the rest of the project.

Response: EPA agrees that the number of monitoring wells associated with GS projects will be sitespecific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

In response to the concern that EPA will change its monitoring requirements to save costs, EPA clarifies that the number of monitoring wells in the cost analysis is an assumption developed for the purpose of the cost analysis only. The Agency is not specifying in the GS Rule the number of monitoring wells required at a GS site and clarifies that the exact number of monitoring wells at a particular GS project will be determined based on site-specific information and will be appropriate to ensure protection of USDWs from endangerment. For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

EPA is developing guidance on monitoring and testing to assist owners/operators and Directors in evaluating requirements under §146.90, including developing determining the appropriate number of monitoring wells for a GS site. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24561

Comment: Rule Provisions or Federal Register Cite: 73 FR 43527 EPA Preamble Question: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of theCost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption.

EPA Notice 43527.

CSC Response: It is difficult to select a realistic ratio since each site will have its own characteristics that would significantly affect the number of monitoring wells necessary. Moreover, the potential benefit of any monitoring well must be determined and weighed against countervailing considerations. The potential for using "three monitoring wells per injection wells" is completely out of proportion to any prior experience in the UIC program and, hence, unsupportable. For many sites, monitoring wells should be unnecessary.

Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

In response to the comment that monitoring wells will not be necessary for some GS projects, EPA clarifies that §146.90(d) requires monitoring of ground water quality and geochemical changes above the confining zone(s). In addition, direct monitoring for pressure changes in the injection zone, required at §146.90(g), will also necessitate the use of monitoring wells. EPA adds that projects operating under injection depth waivers will also monitor using monitoring wells below the injection zone (§146.95). For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24622

Comment: Rule Provisions: 73 FR 43527 EPA Rule Issue: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizesthat operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA

Notice 43527.

Anadarko Petroleum Corporation (APC) Response: It is difficult to select a

realistic ratio since each site will have its own characteristics that would significantly affect the number of monitoring wells necessary.

Please see the report submitted by API and prepared by ARI that discusses the cost modeling in greater detail.

Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Commenter Name: Darrick Eugene Letter ID: 0223 Commenter Organization: Texas Carbon Capture and Storage Association Comment ID: 23960

Comment: imperative. Also, in the Cost Analysis section of the Preamble, the suggested use of three monitoring wells per injection well [FN5] displays a theoretical approach and a lack of practical understanding in how geologic storage projects would be implemented.

5 ~ Id at 43524.Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis).

EPA acknowledges that, at this time, it is difficult to know how many monitoring wells will be used at GS sites. However, while assumptions are a necessary part of cost modeling, EPA disagrees that this approach is "theoretical." The current assumptions in the primary analysis are based on information gathered on the DOE pilot projects and EPA's experience with decades of injection regulated under the UIC Program.

For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23274

Comment: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA Notice 43527.

The number of monitoring wells required will be very site specific.

Response: EPA agrees that the number of monitoring wells associated with GS projects will be sitespecific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule CostAnalysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis). For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

EPA is developing guidance on monitoring and testing to assist owners or operators and Directors in evaluating requirements under §146.90, including developing determining the appropriate number of monitoring wells for a GS site. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24828

Comment: EPA Notice Questions: 73 FR 43527

EPA Rule Issue: 51. The Agency assumes three monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the Agency acknowledges that this factor may be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA

Notice 43527.

GWPC CO2 Committee Response: The group is unsure as to EPA’s methodology for deciding on the number of monitoring wells since each project could be vastly different requiring a wide variety in numbers and types of any necessary monitoring wells. Also, it was felt that the statement regarding the fact that monitoring wells are a significant portion of the costs has not been supported by independent analysis as yet. Therefore, the issue of numbers of monitoring wells is not yet ripe for a decision.Response: EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis). For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

EPA is developing guidance on monitoring and testing to assist owners/operators and Directors in evaluating requirements under §146.90, including developing determining the appropriate number of monitoring wells for a GS site. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Commenter Name: Mark Vickery Letter ID: 0280 Commenter Organization: Texas Commission on Environmental Quality Comment ID: 24103 Other EPA Comment Codes and Descriptions: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment)

Comment: (d) Concern exists on the practical implementation of the proposed requirements for monitoring the CO2 plume and pressure front. Noting that the actual monitoring plan would be left to director approval, EPA's cost analysis for a CO2-GS project assumes the presence of three monitor wells. This would not seem to be sufficient for identification/confirmation of the position of the plume or pressure front, and leads to speculation whether under the proposed rules, the cost of the geo sequestration portion of a carbon capture and sequestration project would be a significantly greater part of the overall cost of the project than represented. In this regard, monitor wells in any reasonable numbers could confirm or rule out the presence of CO2 or its pressure effects at the monitor well location, but would not be expected to identify or confirm the full extent of the plume or pressure front. Computer modeling informed by monitoring data should however be able to bound the reasonable extent of the plume and pressure

front.

Response: EPA clarifies that the specifics of monitoring, including the number of monitoring wells,must be described in the site-specific testing and monitoring plan, which must be approved by the

Director.

EPA recognizes that the number of monitoring wells associated with GS projects will be site-specific and vary based on many factors, including the local geologic characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to the number of injection wells; EPA clarifies that the number of injection wells was based on the size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly based on the size of the AoR. Because ER project sites have injection wells that are more clustered than those in saline formations, the AoR and the number of monitoring wells were anticipated to be smaller at an ER project site compared to a saline formation project. EPA retained this assumption regarding the density of injection wells for the final rule analysis, but it changed its assumption on the number of monitoring wells at each site. For the final rule, the Agency assumes one monitoring well above the injection zone per two square miles of AoR; for monitoring wells into the injection zone, the Agency assumes one monitoring well per four square miles. EPA assumes monitoring wells into the injection zone will also be used to sample above the injection zone. The number of monitoring wells assumed for each project type is presented in Exhibit 5.2 of the Cost Analysis.

Because the actual number of monitoring wells that will be necessary for a given project site is uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase in monitoring wells per project type to the original assumptions. This change results in annualized incremental rule costs approximately 16 percent less and 16 percent greater than costs estimated for the primary analysis (as shown in Exhibit 5.26 of the Cost Analysis). For additional information on EPA's final regulatory approach, including testing and monitoring requirements, please see the final rule and preamble.

EPA is developing guidance on monitoring and testing to assist owners/operators and Directors in evaluating requirements under §146.90, including developing determining the appropriate number of monitoring wells for a GS site. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.

Comment Code: 6300 3.3 Benefits of the proposed rule



### Individual Comments

Commenter Name: Ronald Evans Letter ID: 0215 Commenter Organization: Denbury Resources, Inc. (DRI) Comment ID: 24273 Other EPA Comment Codes and Descriptions: 6000 3. Cost of the Proposed Rule

Comment: We are therefore concerned that the Proposed Rule, as presently drafted, will increase the cost of geologic storage [FN3] of CO2 without producing commensurate benefits in terms of protecting USDWs. In the case of some

[3] Relative to "sequestration," the term "storage" has become the more common usage in the worldwide community addressing these issues. See, e.g., the European Union’s "Proposal for a Directive of the European Parliament and of the Council on the geological storage of carbon dioxide," (January 23, 2008) and thevarious reports and recommendations under the UNFCCC’s Clean Development Mechanism (available at http://cdm.unfccc.int/about/ccs/index.html) (last visited December 2, 2008). The terms "sequestration" and "storage" are used interchangeably in these comments.

Response: EPA disagrees that the GS rule does not provide commensurate benefits of protecting USDWs. The GS rule contains tailored requirements to ensure that wells are appropriately permitted, sited, constructed, operated, monitored, and closed in a manner that protects USDWs from endangerment. EPA acknowledges that the Class VI requirements have associated costs beyond baseline (Class I industrial wells) costs, and believes these costs are necessary and appropriate to address the unique challenges posed by large-scale GS, including large injection volumes, the relative buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in captured CO2, and its mobility within subsurface geologic formations.

Comment Code: 7100 4.1 Executive Order 12866: Regulatory Planning and Review



### Individual Comments

Commenter Name: Theresa Pugh Letter ID: 0169 Commenter Organization: American Public Power Association Comment ID: 23435

Comment: Executive Order 12866

APPA asks that the U.S. EPA consider APPA’s comments and NERC’s study under Executive Order 12866 and any future Executive Orders on energy expressed by President-Elect Obama which covers energy issues.

Response: EPA determined that the final GS rule is a "significant regulatory action,” under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), because GS will raise novel legal or policy issues. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866. Any changes made in response to OMB recommendations are documented and are provided in the rulemaking docket.

Comment Code: 7300 4.3 Regulatory Flexibility Act



### Individual Comments

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory Comment ID:

22667

Comment: o Page 43530. The draft rule correctly states "Sequestering CO2 via injection wells is a voluntary action that would only be undertaken by an entity if it were in its interest compared to other alternatives it may have." This point is worth repeating a number of times in this proposed rule. In particular, this might be worth repeating in discussions of what is required for Class VI wellsand the cost of meeting these requirements. At times, it seems as if the USEPA is apologizing for requiring compliance with measures designed to protect USDWs. The USEPA should ask for the public and other stakeholders to perform a thorough and rigorous review of any proposed requirements but there is no need to apologize. As the draft Class VI rule makes clear, no one is being required to use GS. That is important to remember and likely bears repeating.

Response: EPA acknowledges this comment. The GS rule does not require any facilities to sequester CO2. The purpose of the GS regulation is to ensure that, where deployed, GS is conducted in a manner that protects USDWs from endangerment. EPA discussed this in the preamble to the proposed rule (73 FR 43492), and further clarified this fact in the final rule preamble and the Cost Analysis, which is available in the docket for the rulemaking.

Commenter Name: Theresa Pugh Letter ID: 0169 Commenter Organization: American Public Power Association Comment ID: 23434

Comment: EPA to Consider SBREFA Impacts

APPA asks that the U.S. EPA consider APPA’s comments under Small Business Regulatory Enforcement and Fairness Act (SBREFA) since > 90% of APPA’s member

utilities meet the threshold for small entities.

Response: Based on a review of all of the Executive and Statutory Orders, EPA has determined that the GS rule is not subject to the requirements of Regulatory Flexibility Act and SBREFA. This conclusion is based on the scope of the GS Rule, which affects only those entities that choose to engage in GS.

EPA clarifies that the GS rule does not require any facilities to sequester CO2; nor does it create an economic incentive to do so. The purpose of the GS regulation is to ensure that, where deployed, GS is conducted in a manner that does not endanger USDWs.

Comment Code: 7600 4.6 Executive Order 13175: Tribal Consultation and Coordination



### Individual Comments

Commenter Name: Sam Kitto Letter ID: 0126 Commenter Organization: National Tribal Air Association Comment ID: 23050 Other EPA Comment Codes and Descriptions: 1930 1.4.4.2 Consultations with State, Tribal, and local Associations (e.g., GWPC, IOGCC)

Comment: According to the EPA, the GS rule does not have tribal implications as accorded by Executive Order 13175, largely because Indian tribes do not have primacy over an underground injection control (UIC) program (the Fort Peck Assiniboine and Sioux Tribes, and the Navajo Nation have received primacy since publication of the GS rule). This is a faulty rationale as Indian tribes could be placed in harm’s way as a result of geologic sequestration occurring on or near their lands. As already noted above, geologic sequestration could have significant environmental impacts on tribes, but their cultural practices could be affected as well. For example, a number of tribes depend upon certain plants for culturaland religious ceremonies, and with increased soil acidity due to CO2 leakage from geologic sequestration, the health and survival of these plants could be in jeopardy.

Although admitting that the GS rule will not impact tribes, the EPA claims that it did in fact consult with Indian tribes. What the NTAA can gather from the rule, however, is that the Agency simply contacted tribes about engaging in the rulemaking process and held one conference call; the EPA has also promised to "continue an ongoing dialogue with interested tribes on this rulemaking." Thisapproach taken by the Agency falls far short of what a true government-togovernment consultation between the federal government and tribes should look like. As inferred above, a tribal consultation plan could have helped overcome any concerns about Indian tribes not being properly consulted by the EPA with respect to the GS rule. The NTAA believes, however, that an opportunity for developing such a plan still exists, but requires at a minimum that the comment rule concerning the GS rule be extended no less than 90 days; the NTAA also gladly offers its resources to help develop such a plan.

Response: Throughout the GS rulemaking, EPA has promoted a transparent stakeholder process to ensure that all stakeholders understood the rulemaking elements and that viewpoints and suggestions for rule modifications were recorded. EPA, with support from the American Indian Environmental Office (AIEO), engaged Tribes early in the rulemaking process, and continued to update Tribal representatives as appropriate. Additionally, the Agency provided tribes with the contact information for EPA managers in order to facilitate ongoing communication throughout the rulemaking process.

In April 2008, prior to publication of the proposed GS rule, the Agency sent background information about the proposed rulemaking to all federally-recognized American Indian tribes. In addition, EPA communicated with the National Tribal Caucus of the National Operations Committee (NTC) and the National Tribal Water Council (NTWC) to encourage participation in a dedicated consultation on the rulemaking. On April 24, 2008, the Agency held the conference call with all interested tribal representatives. A summary of the call is included in the rulemaking docket. Additionally, an EPA representative presented information on GS and the GS regulatory framework at the National Tribal Council on Environmental Management (NTCEM) Meeting in Billings, Montana, in June 2008. In September 2008, during the proposed rule public comment period, EPA held two public hearings at which tribes were represented.

Throughout 2009 and 2010, more recent updates on the GS rulemaking were presented to tribal representatives through regularly scheduled calls with the NTWC, State and Tribal Climate Change Council (STC3), and the National Tribal Caucus. Representatives had the opportunity to ask EPA managers questions related to the rulemaking elements and finalization schedule. EPA believes that all of the actions undertaken were conducted to support an open and transparent rulemaking process in accordance with Executive Order 13175 and Agency recommendations.

EPA clarifies that following publication of the proposed rule in July of 2008, the Fort Peck Assiniboine and Sioux Tribes and the Navajo Nation received UIC Program primacy for the Class II program (under 1425 of the SDWA). EPA recognizes those tribes as co-regulators and remains committed to ensuring that co-regulators are informed on and have an opportunity to engage with EPA on the GS rule. To further ensure coordination and communication regarding the GS rule, EPA hosted a conference call specifically for the Fort Peck Assiniboine and Sioux Tribes, as well as the Navajo Nation, UIC Program Directors in February 2010. EPA representatives presented the historyof the rulemaking, the current schedule for finalization of the rule, and the statutory differences in applying for primacy for the proposed Class VI program versus applying for primacy for the Class II program. EPA received comments from the Navajo Nation UIC Director as a co-regulator for the program. A summary of the call is included in the docket for the GS rulemaking.

In response to the concern raised that tribes could be adversely affected by Class VI well projects because they may be sited on or near Indian country, EPA clarifies that the Federal UIC regulations are designed to ensure protection of USDWs from endangerment associated with injection activities. These regulations protect all populations from adverse health effects associated with endangerment to USDWs. EPA clarifies that regulating environmental impacts beyond impacts of endangerment to USDWs is beyond the scope of EPA’s authority under the Safe Drinking Water Act and this rulemaking.

The Agency is currently reviewing its tribal consultation policies and procedures in accordance with the President's directive of November 5, 2009. When that review is final, there will be more clarification from EPA on tribal consultation during program implementation.

Comment Code: 7700 4.7 Executive Order 13045: Children's Health Protection



### Individual Comments

Commenter Name: James Dooley Letter ID: 0156 Commenter Organization: Joint Global Change Research Institute, Pacific Northwest National Laboratory Comment ID:

22669

Comment: o Page 43531. The USEPA invites the public to identify peer reviewed studies that assess the effects on infants and toddlers who are exposed to drinking water that has been degraded "by geologic sequestration of carbon dioxide." The wording here seems to assume a number of key steps that I am not sure one can assert given where humanity is in terms of the commercial deployment of GS. This request for information would be better if it requested information on studies that speak to the impact of drinking contaminated water by infants and toddlers caused by processes that could result from a poorly functioning GS project at some point in the future. I do not see how there can be existing studies that show negative impacts on children from drinking water contaminated by a malfunctioning GS project. It is worth comparing the language here with the far more balanced and accurate language on page 43532 where the USEPA forcefully asserts that the proposed rule will not have a disproportionate impact on minority and low-income populations.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory(LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information such as the research described above and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Kyle Isakower Letter ID: 0170 Commenter Organization: American Petroleum Institute Comment ID: 24269

Comment: Rule Provisions: 73 FR 43531 EPA Preamble Question: 52. The public is invited to submit comments or identify peer-reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531.

API Response: API is not aware of anything unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking

water standards and MCLs can be used in this situation.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information, such as the research described above, and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Robert F. Van Voorhees Letter ID: 0190 Commenter Organization: Carbon Sequestration Council Comment ID: 24562

Comment: Rule Provisions or Federal Register Cite: 73 FR 43531 EPA Preamble Question: 52. The public is invited to submit comments or identify peer-reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531.

CSC Response: CSC is not aware of anything unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking

water standards and MCLs can be used in this situation.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potentialexceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information, such as the research described above, and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Craig R. Walters Letter ID: 0200 Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24623

Comment: Rule Provisions: 73 FR 43531EPA Rule Issue: 52. The public is invited to submit comments or identify peerreviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration

of carbon dioxide. EPA Notice 43531.

Anadarko Petroleum Corporation (APC) Response: APC is not aware of anything unique about CO2 injection or its potential impacts on drinking water quality that would not be addressed within the existing drinking water program. The data EPA has on developing drinking water standards and MCLs can be used in thissituation.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009 Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information such as the research described above and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Mark Bohrer Letter ID: 0241 Commenter Organization: North Dakota Industrial Commission Comment ID: 23275

Comment: 52. The public is invited to submit comments or identify peer-reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration of carbon dioxide.

EPA Notice 43531.

There are no known unique characteristics of carbon dioxide injection or itspotential impacts on USDWs that have not been addressed within existing UIC rules or found in current carbon dioxide injection projects.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information such as the research described above and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Commenter Name: Michel Paque Letter ID: 0259 Commenter Organization: Ground Water Protection Council Comment ID: 24830

Comment: EPA Notice Questions: 73 FR 43531

EPA Rule Issue: 52. The public is invited to submit comments or identify peerreviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestrationof carbon dioxide. EPA Notice 43531.

GWPC CO2 Committee Response: Studies already exist that address potential exposure issues, but there should be a recognition of the very low potential for exposure that exists for GS projects.

Response: EPA is funding research related to the potential for USDW contamination associated with GS projects. In addition, the Agency is tracking external research that focuses on potential exceedances of drinking water standards, which were developed by EPA and take into account impacts on children's health.

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory (LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL estimated the amount of trace elements from native mineral species that could potentially be mobilized by the intrusion of CO2 and the potential ground water concentrations that could result to determine the potential for drinking water standards to be exceeded. EPA has also examined potential methods for conducting treatment of water affected by a CO2 leak; this study is presented in the final rulemaking docket.

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University to investigate the potential for GS to affect USDWs. This research will involve laboratory experiments and modeling simulations to investigate the fate of dissolved CO2 in underground geologic formations and to determine possible risks associated with the dissolution of CO2 in underground aquifers. This STAR Grant is among six such grants awarded to major universities and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water."

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, therefore, minimize health risks to all populations, including children. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those environmental and human health impacts that are beyond the scope of the SDWA.

As part of its adaptive rulemaking approach, EPA plans to collect and review available information such as the research described above and data every six years on early GS projects, including impacts to USDWs and drinking water quality that may affect the health of children, to determine whether the appropriate amount and types of information and documentation are being collected, and to determine if modifications to the requirements are appropriate or necessary.

Comment Code: 8000 4.1 Executive Order 12898: Environmental Justice

### Individual Comments

Commenter Name: Anonymous2 Letter

ID: 0133 Commenter Organization: Sierra Club National Global Warming and Energy Committee and Sierra Club California-Nevada Regional Conservation Committee on Energy and Climate Change Comment

ID: 21597

Comment: Environmental Justice and the Siting of Injection Wells: Acknowledge the clear potential for environmental justice issues to be involved in the siting of Class VI injection wells, and formulate mandatory protocols for addressing those issues within the permitting process.

Response: EPA recognizes that some Class VI wells may be sited in areas with high percentages of minority, low-income, or tribal people. Furthermore, the Agency agrees that permit writers reviewing Class VI well permit applications should consider environmental justice issues when conducting

their review.

EPA clarifies that siting of GS projects is based on the presence of appropriate geologic formations that can receive and confine the total volume of CO2 anticipated to be injected under § 146.83(a)(2). The GS regulation at § 146.82 requires owners/operators to collect and submit extensive geological data on the proposed GS site, including an assessment of the geologic, hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that GS wells are located in suitable formations and that USDWs are protected from endangerment.

EPA also emphasizes that the purpose of the GS rule is to protect USDWs through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, in turn, minimize health risks to all populations, including minority, and low-income, and tribal populations. The "Risk and Occurrence Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, presents a broad discussion of risks to human health and the environment associated with GS, including those addressed under SDWA authority and those beyond the scope of the SDWA. The GS rule does not address risks outside the scope of the SDWA.

EPA is developing guidance for UIC Directors that places emphasis on considering the potential impact of any GS permits on communities (such as minority, and low-income and tribal populations) when evaluating Class VI injection well permit applications. The guidance also provides suggestions and tools for targeted outreach to ensure more meaningful public input and participation from the most affected communities during the permit evaluation and approval process. Additionally, as part of the permitting process pursuant to requirements at 40 CFR Part 124 the public has an opportunity to review public notices on GS permit applications, participate in hearings related to GS permit decisions, and inform permit writers of any environmental justice concerns associated with a specific GS project.

Commenter Name: Anonymous2 Letter

ID: 0133 Commenter Organization: Sierra Club National Global Warming and Energy Committee and Sierra Club California-Nevada Regional Conservation Committee on Energy and Climate Change Comment

ID: 21618

Comment: H. Environmental Justice and the Siting of Injection WellsRecommendation H: Acknowledge the clear potential for environmental justice issues to be involved in the siting of Class VI injection wells, and formulate mandatory protocols for addressing those issues within the permitting process.

California's Central Valley is a particularly valuable example for illustrating the importance of both technical and social considerations in establishing the permitting protocols for Class VI injection wells. The Central Valley has been consistently identified as a primary location for CCS projects by the DOE, the Lawrence Livermore National Laboratory, the Lawrence Berkeley National Laboratory, and British Petroleum -- among others. The DOE has entered into an agreement with Clean Energy Systems for a pilot CCS project at a natural gas power plant in Kern county, and BP has applied to the California Energy Commission for approval of a proposed project. Thus, employing certain technical considerations alone, the Central Valley is ideal for early CCS deployment. However, a history of economic and social issues in the region has served to heighten public resistance to such projects.

Due to previous identification as a region with economically disadvantaged populations, dangerously poor air quality, and degraded wildlife habitats, the Central Valley has become the focus of numerous governmental and nonprofit interventions, including ongoing EPA sanctions for violations of the Clean Air Act. Typically, when new industrial developments seek to become established in the region, they will be opposed unless they can be shown to carry greater benefits than costs to local communities. Because all three categories (health and safety, economic, and environmental) are interdependent in the Central Valley, the ability to ameliorate or solve any specific grievance becomes more

difficult.

In its comments to the proposed regulations, the EPA states: "Existing electric power generation plants that burn fossil fuels may be more prevalent in areas with high percentages of people who are minorities or have lower incomes on average, but it is hard to predict where new plants with CCS will be built." This statement fails to acknowledge the large prevalence of proposed geologic storage sites near existing oil and gas fields and/or currently operational power plants. Every study by industry and business consultants has concluded that CO2 storage is most economically feasible when sited as close to the source of emissions as possible. Whether CO2 is defined as an industrial commodity or a hazardous waste product, it is incompatible with storage in high income residential population centers. It is most likely that GS sites will be proposed in areas of similar populations to those communities, like California's Central Valley, that have histories of economic disadvantage, of environmental degradation from industrial developments, and of chronic health issues among the general populace, especially children. Therefore, it is of utmost importance for the EPA to mandate protocols for addressing environmental justice issues which will most likely be attendant to a large percentage of GS permit applications.

Response: EPA clarifies that siting of GS projects is based on the presence of appropriate geologic formations that can receive and confine the total volume of CO2 anticipated to be injected under §146.83(a)(2). The GS regulation at §146.82 requires owners/operators to collect and submit extensive geological data on the proposed GS site, including an assessment of the geologic,hydrogeologic, geochemical, and geomechanical properties of the proposed GS site to ensure that GS wells are located in suitable formations and that USDWs are protected from endangerment.

EPA also emphasizes that the purpose of the GS rule is to protect USDWs through permitting, siting, construction, operation, injection, and post-injection site care and site closure requirements that are tailored to address the unique nature of GS. The Class VI requirements, in turn, minimize health risks to all populations, including minority and low-income populations.

EPA is developing guidance for UIC Directors that places emphasis on considering the potential impact of any GS permits on communities such as minority and low income populations when evaluating Class VI injection well permit applications, as well as provides suggestions and tools for targeted outreach to ensure more meaningful public input and participation from the most affected communities during the permit evaluation and approval process. Additionally, as part of the permitting process pursuant to requirements at 40 CFR Part 124 the public has an opportunity to review public notices on GS permit applications, participate in hearings related to GS permit decisions, and inform permit writers of any environmental justice concerns associated with a specific GS project.