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 codes 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 resources 

necessary 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 or
operators 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 or
operators 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: 23160
Comment: 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: 0529
Comment 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 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: 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 that 
they 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 a
separate 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 item

C-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 receive 
the 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 heavy 
metals 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 the
GS 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 on

various 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 Requirements 
The 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 well 
associated 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 operations 
In 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 Dioxide 
Geologic 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 the
assumption 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: 21869
Comment: 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 alternative 

renewables -- 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 different
default 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 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: 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 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. 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 from 
the 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 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. 

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 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. 

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 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 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 geosequestration 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 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.

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 wells 
and 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 cultural 
and 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." This 

approach 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 history
of 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 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: Craig R. Walters Letter ID: 0200

Commenter Organization: Anadarko Petroleum Corporation Comment ID: 24623

Comment: Rule Provisions: 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 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 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: 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 its 
potential 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 sequestration 
of 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 Wells 
Recommendation 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.