1

American Public Power Association

1875 Connecticut Ave, NW 

Suite 1200

Washington, D.C. 20009 

202-467-2900; fax: 202-467-2910

www.APPAnet.org

Retrofitting Carbon Capture Systems on Existing Coal-fired Power Plants

A White Paper for the American Public Power Association (APPA)

L.D. Carter

November 2007

Summary: It will be necessary to reduce CO2 emissions from existing coal-fired power plants 

for the U.S. to reach the goals stated by some legislators for managing global climate change. 

The major technology choices for existing plants include post-combustion capture systems using 

chemical sorbents to isolate and concentrate CO2, and reconfiguring the unit to use pure oxygen 

rather than air as the combustion oxidant (yielding flue gas with a much higher concentration of 

CO2). Both existing technology approaches are costly, and both involve large parasitic power 

needs that can reduce the output of the existing unit by one-third. The changes introduced by 

retrofitting carbon capture and storage (CCS) on an existing power plant will raise variable costs, 

and could thereby lower the unit in the utility’s dispatch order.

Capture and storage concepts have been implemented on a small scale, but not on the scale 

necessary for large coal-fired power plants. Furthermore, most research on CCS is focused on 

new power plants and not issues that may be more relevant to existing power plants. In addition 

to overcoming technical issues, CCS retrofits will face as yet undefined regulatory challenges, as 

well as liability issues related to the underground migration of stored CO2 over a timescale that 

exceeds the scope of traditional risk mitigation instruments, like insurance. 

These challenges are daunting. Research and policy development are both proceeding, but 

whether current efforts will be sufficient to result in a solution set that enables the nation to 

continue to enjoy the benefits of low-cost electric power remains to be seen.
2

Introduction

Existing coal-fired power plants in the U.S. emitted 1.96 billion metric tons of CO2 in 2005, or 

about 27% of total U.S. emissions of greenhouse gases (GHGs).1 These power plants generate 

about one-half of the electricity in the U.S., and are in large part responsible for the U.S. enjoying 

power costs that are among the lowest in the world.2 Congress has not passed legislation to 

reduce GHG emissions, but many bills have been introduced and others are under development, 

with some seeking reductions in U.S. emissions as high as 30% in 2030 and 80% in 2050.3 The 

Chairman of the House Energy and Commerce Committee has identified a reduction goal for that 

committee’s legislation of “between 60 percent and 80 percent by 2050.”4Such large emission 

reduction goals will not be met without significantly reducing emissions from existing coal-fired 

power plants.

To date, most discussion of GHG emission mitigation related to coal-based power production has 

focused on new coal-based power production, and detailed engineering studies have evaluated the 

cost and performance of various options for those new units.5 With currently available 

technologies, CO2 capture and storage options (in saline formations) from these new units cost 

$30 – 70 per ton of CO2 avoided.6 7 The reader is referred to an earlier APPA White Paper for a 

general overview of carbon capture and storage (CCS) from coal-based power plants.8 This paper 

addresses those aspects of CCS that are of particular interest to retrofitting this technology on 

existing coal-fired power plants.

With respect to retrofitting existing coal units, a 2005 IPCC report concluded: “Retrofitting 

existing plants with CO2 capture is expected to lead to higher costs and significantly reduced 

overall efficiencies than for newly built power plants with capture. The cost disadvantages of 

retrofitting may be reduced in the case of some relatively new and highly efficient existing plants 

or where a plant is substantially upgraded or rebuilt.” 9

1

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1900 – 2005, U.S. EPA, EPA 430-R07-002, April 15, 2007. Note that the percentage includes non- CO2 greenhouse gases, and 

excludes sinks.

2 Electricity Prices for Industry, DOE/EIA, June 2007, 

http://www.eia.doe.gov/emeu/international/elecprii.html .

3 Climate Change: GHG Reduction Bills in the 110th Congress, Congressional Research Service, 

Rpt. #RL33846, January 31, 2007.

4 Memorandum from John Dingell, Chairman of Committee on Energy and Commerce, and Rick 

Boucher, Chairman of Subcommittee on Energy and Air Quality, to Members, Committee on 

Energy and Commerce, October 3, 2007.

5 See, for example, Cost and Performance Baseline for Fossil Energy Plants, U.S. DOE National 

Energy Technology Laboratory, DOE/NETL-2007/1281, May 2007.

6 Ibid. It should be noted, however, that most publicly available reports on CO2 capture and storage 

are based on markets that existing before 2005, and that since that time, power plant capital costs 

have escalated dramatically. The NETL report states (p.42) that it incorporated escalation through 

the 3rd Quarter of 2006, but the basic power system costs cited still appear below costs reported by 

utilities in the news media.

7 Carbon Dioxide Capture and Storage, UNEP/IPCC, 2005, avoided costs projected at 30-70 $/t 

CO2 for new pulverized coal units and 14-53 $/t CO2 for new IGCC units, p.347.

8 Carbon Capture and Storage From Coal-based Power Plants: A White Paper on Technology 

for the American Public Power Association (APPA), L.D. Carter, May 22, 2007 (available from 

APPA at http://www.appanet.org/files/PDFs/Attachment%20%233.pdf ).

9 Op.Cit., Carbon Dioxide Capture and Storage, p.10.
3

Technology Choices

The vast majority of existing coal-fired power plants are pulverized coal units. Pulverized coal 

units have two choices for CCS retrofit: post-combustion capture of CO2 using chemical 

sorbents, and replacing the existing air-combustion system with an oxygen-fired system, thereby 

creating a flue gas which is mostly CO2.

10

Post-combustion CO2 capture

Figure 1 depicts a post-combustion CO2 capture system. In this system, an acid gas sorbent 

vessel is placed downstream of conventional pollution capture systems. CO2 is absorbed into an 

appropriate chemical, such as an amine, which is heated in a separate vessel to release a high 

concentration stream of CO2 and the regenerated sorbent. The concentrated CO2 stream is then 

pressurized to about 2000 psia, for transport (as a supercritical fluid) via pipeline to an injection 

field. There it is injected into a stable formation as deep as one mile underground. The process 

requires large amounts of energy, both to strip the CO2 from the sorbent and to compress the 

concentrated CO2. In a study of capture technology at greenfield, or new, power plants, NETL11

concluded that whether the plant was subcritical or supercritical in design, the CCS system 

resulted in about a 12% absolute drop in efficiency (e.g., from 33% to 21%).12 Figure 2 shows 

the components responsible for the additional power needs in the CCS-equipped system, based on 

data in the NETL report for a subcritical power plant. As can be seen from the figure, about onehalf the power needs related to CO2 compression, about one-fourth was attributable to the CO2

amine system, and most of the rest derived from additional fans and pumps needed for the 

enlarged generation system (which burns more coal for the same power output) and the greatly 

enhanced cooling system. The CO2 capture system (alone) requires about twice as much cooling 

water as the original power plant.

An additional complexity of the CCS-equipped system is an SO2 polishing unit. For a high sulfur 

(IL #6) coal system, even a 98% efficient wet FGD system exhausts flue gas with about 40 ppm 

SO2. To suppress formation of heat stable salts in the sorbent, this must be lowered to about 10 

ppm. The NETL design accomplishes this at a new unit by using a serial combination of a 

traditional wet limestone FGD and a sodium hydroxide polishing scrubber.

The various pieces of hardware required for CO2 capture and compression require space. NETL 

reports that about one acre of land is needed for each 100 MW of generating capacity.13 A 

separate NETL report suggests that land requirements for capture and compression equipment at 

a 500 MW unit would be 60 acres, or 12 times the first estimate.14 In either case, this space 

requirement can be a major obstacle to retrofitting CO2 capture systems on existing units which 

are already space-limited due to previous retrofits for SO2, NOx, and mercury control systems.

10 An innovative multipollutant ammonia-based capture technology is currently being investigated 

by U.S. DOE, in collaboration with Powerspan Corporation. The lack of publicly available data on 

a commercial version of this technology preclude its inclusion in this analysis. Additional 

information is available at: http://www.netl.doe.gov/publications/factsheets/rd/R&D043.pdf .

11 NETL is the National Energy Technology Laboratory, which is owned and operated by the U.S. 

Department of Energy. See: http://www.netl.doe.gov/ .

12 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants, Exhibit ES-2.

13 Carbon Dioxide Capture from Existing Coal-Fired Power Plants, DOE/NETL-401/120106, 

p.xviii, December 2006.

14 Carbon Sequestration Program Environmental Reference Document, DOE/NETL DE-AT26-

04NT42070, August 2007, p.2-42.
4

Regarding technology readiness, the 2007 NETL report states: “The post-combustion CO2

removal technology for the PC and NGCC cases is immature technology. This technology 

remains unproven at commercial scale in power generation applications.”15

Oxy-combustion approaches

If a pulverized coal power plant is fired with nearly pure oxygen, instead of with air, the nitrogen 

in the traditional combustion air is eliminated from the flue gas, and the flue gas is composed 

primarily of CO2, water vapor, excess oxygen and trace gases like SO2, NOx, and HCl, although 

air infiltration can reintroduce nitrogen and more oxygen. After removal of water vapor, the flue 

gas is approximately 80-98% CO2.

16 As a result, the sorption/desorption equipment needed in the 

“Post-combustion” example above is unnecessary, although some purification may be needed 

prior to CO2 injection and storage. For purposes of this paper, this oxygen-based approach to 

CO2 capture will be termed “oxy-combustion”, even though it is actually another form of “postcombustion” CO2 capture. 

In the oxy-combustion system, some of the CO2 from the flue gas (about twice the volume of the 

oxygen supplied) must be recycled to reduce combustion gas temperatures from 3500 oC to a 

boiler tolerant 1900 oC. Oxy-combustion raises the possibility of reduced cost for downstream 

cleanup of traditional pollutants, either by storing them with the CO2 or by reducing the volume 

of the flue gas stream dramatically through elimination of nitrogen oxide and use of CO2

recycle.17 Additionally, the potentially higher combustion temperatures and the improved heat 

transfer properties of oxy-combustion gases mean that it may be possible to achieve higher 

thermal efficiencies than possible with other approaches to CO2 capture.

The major drawbacks to this approach for CO2 capture are large parasitic power requirements, 

primarily for oxygen production and CO2 compression, and the cost of the oxygen production 

facility. Ongoing research into improved techniques for oxygen production may mitigate these 

drawbacks to some degree. With current technology, cost and parasitic power needs for oxycombustion are about the same as for post-combustion CO2 capture. The potential advantages for 

oxy-combustion CO2 capture are speculative at this point. It may be easier to locate an oxygen 

plant than a CO2 sorption tower at an existing plant, where access to flue gas is already 

encumbered by retrofit SO2 scrubbers and other hardware installed after the plant was initially 

constructed. And the parasitic power needs for an oxy-combustion plant are more electrical than 

steam, so integration with the existing unit may be simpler.

A cross-platform comparison

A recently published report by DOE/NETL compares a basic new pulverized coal unit both to 

one with similar power output, but with post-combustion CO2 capture, and to a coal unit with 

oxy-combustion CO2 capture. NETL examined both supercritical and ultra-supercritical 

designs.18 Table 1 presents several outputs from the study for the supercritical designs. 

15 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants, p.40. “PC” refers to 

pulverized coal power plants, the traditional technology for burning coal to produce electricity. 

“NGCC” stands for natural gas combined cycle power generation. In a NGCC, natural gas is 

burned in a combustion turbine (much like a jet engine) that drives a generator to make electricity. 

Hot exhaust gases from the combustion turbine are used to convert water to steam, which 

expands through a steam turbine to drive a second generator.

16 Op.Cit., Carbon Dioxide Capture and Storage, p. 122.

17 Ibid., p.123.

18 Pulverized Coal Oxycombustion Power Plants, DOE/NETL-2007/1291, August 2007.
5

Note that both approaches to CO2 capture, with current technology applied to a new power 

plant, nearly doubled the power plant’s capital cost and the cost of electricity produced. 

Table 1. Comparison of cost and performance of capture systems (new plant).

Parameter Base Post-comb’n Oxy-comb’n

CO2 capture No 90% 100%

Gross capacity, MWe 584 667 793

Net capacity, MWe 554 549 546

Net plant heat rate, Btu/kwh 8,649 12,538 12,074

Net plant efficiency (HHV), % 39.5 27.2 28.3

Total Plant Cost, $/kw 1563 2857 2930

Levelized cost of electricity, $/MWh 62.9 114.4 113.0

Cost of capture, $/ton CO2 avoided n.a. 63 52

SO2 emissions, #SO2/mmBtu 0.085 Negligible 0.003

NOx emissions, #NOx/mmBtu 0.07 0.07 0.07

It should be repeated that the above table relates to new power plants. Traditional pollution 

control technologies designed for new power plants usually have a higher cost per unit of power 

output when applied to existing units. These cost “retrofit factors” have not been established for 

carbon capture technology, but for traditional pollutants like SO2 and NOx, they can be a 25-40% 

cost increase over the cost of a comparable system at a new facility. The other major distinction

for existing units is that they cannot easily be expanded to accommodate the very large amount of 

parasitic power needed to run the capture systems. Note that for the new units in Table 1, gross 

generating capacity was increased 15-35% to provide that power. At a retrofit unit with 33% 

energy conversion efficiency, a loss of 12% (absolute) efficiency means a loss of more than 

one-third of the output of the power plant. 

Replacement of this parasitic power, at today’s escalated prices for new power plants, will 

introduce a major cost barrier to retrofitting existing units for CO2 capture. It could also present 

limitations on how quickly regulations could be implemented. For example, recall that the 2005 

Clean Air Interstate Rule (CAIR) was by necessity introduced in phases (the necessity being that 

skilled labor limitations precluded a one-step regulatory process).19 Consider the comparative 

difficulty of retrofitting CO2 capture systems on the existing 320 GW coal-fired power plant fleet. 

The utility industry would need to install over 100 GW of additional new capacity for 

replacement power needs (above expected demand growth needs), and simultaneously 

install 320 GW of CO2 capture and compression systems, versus roughly 100 GW of SO2

scrubbers and NOx selective catalytic reduction systems under CAIR.

A final issue specific to existing units is that a different level of CO2 capture performance may be 

appropriate for those units. Most technical studies assume a high level, e.g., 90%, of CO2 capture 

for new units20. Under either a cap and trade or carbon tax approach to managing greenhouse gas 

reductions, the best strategy is usually considered to be the one that achieves the desired global 

emissions reduction at the lowest cost. For existing pulverized coal-fired power plants, it is too 

early to determine what the most cost-effective level of control will be, but it might be much 

lower than 90%.

19 Federal Register, 70FR25197, May 12, 2005.

20 This level of performance has yet to be demonstrated as either technically or economically 

feasible.
6

Operational issues related to CCS

Most generating unit-level analyses of the cost impacts of environmental requirements focus on 

the levelized cost of electricity (COE) implications of meeting the rules. It is also important to 

examine dispatching costs (or variable costs) under alternative compliance scenarios, because if 

variable costs increase significantly, the unit may become too expensive to dispatch, making the 

capacity factor assumptions in the COE projections (and the COE results) invalid.21 The costs for 

CCS retrofits are so large, and impacts on variable costs likewise large, that it is quite possible 

that a unit in which a large investment was made would not be used very much in an 

economically dispatched system. One only has to consider the significant amount of idle natural 

gas combined cycle (NGCC) units in the U.S. to recognize the reality that flawed assumptions 

with major economic ramifications are not just a theoretical possibility.

The large parasitic power requirements of CCS introduce additional analytical complexity 

regarding the use of systems equipped with CO2 capture, particularly retrofit units. Dispatching 

costs for these units will be much greater due to the higher fuel consumption, and purchase of 

replacement power. Moreover, if replacement power were purchased from another source, then 

all of the cost of replacement electricity could be considered a variable cost. Figure 4 compares 

dispatching costs (or variable costs) for several hypothetical systems, based on cost and 

performance data reported by DOE/NETL.22 The NETL costs were adjusted by assuming EIA 

AEO-2007 costs for natural gas and coal in 2020 (both the EIA reference price and “High Price” 

scenarios were used for natural gas). In addition, the NETL analysis was for a greenfield, or new 

power plant. A retrofit factor of 50% was applied to the capital and variable O&M costs for the 

new plant figures in the NETL report. Figure 4 presents dispatching costs for a range of carbon 

taxes (0-100 $/metric ton CO2), for coal and natural gas. Additionally, the costs in the figure 

reflect purchase of makeup power to replace the power required to run the CCS system, an issue 

further discussed below.

Note that the basic coal plant has a variable cost of about 20 $/MWh and a natural gas plant is 

about twice that amount, without any CO2 capture. At 90% capture, variable costs increase to

about 60-65 $/MWh for the coal system and for natural gas combined cycle systems equipped for 

capture, for a range of natural gas prices. The dashed lines in the figure represent an uncontrolled 

plant paying the relevant “tax”, rather than capturing the CO2, and a “hybrid” approach of 

controlling half the CO2 and paying the tax for the remainder.

These calculations are imprecise, but they indicate that until CO2 taxes or cap/trade costs exceed 

about $50/ton CO2, coal units without capture (and paying a CO2 tax) will be dispatched ahead of 

coal and natural gas units with capture. Other factors, such as subsidies paid to units that capture 

CO2 and improvements in the technology, could certainly impact these results dramatically. For 

perspective, S.1766 (Senator Bingaman’s climate change bill), which becomes progressively 

more stringent over time, begins with a “safety valve” price of 12 $/ton CO2 in 2012, and reaches 

$50/ton in about 2040. 

21 For example, most simplistic analyses of technology options assume a constant level of power 

generation (or capacity factor) across technology alternatives. In practice, however, utilities 

operate most those units with the least variable costs (which include fuel consumption and 

variable operation and maintenance costs). If these variable costs increase markedly for some 

technology options, then the assumption of constant generation across technology alternatives is 

incorrect, and the resulting COE calculations are likewise in error because fixed costs (such as 

capital costs) must now be paid with fewer kilowatt-hours of generation.

22 Op.Cit., Cost and Performance Baseline for Fossil Energy Plants. 
7

A key parameter in these cost comparisons is the cost of replacement power for the CCS system. 

Replacement power is estimated to be about 30% of the total plant generation for a pulverized 

coal system, and about one-half that for a natural gas combined cycle (NGCC) system. Who 

provides the replacement power is also important to dispatching costs. If the power is purchased 

from another utility, then its costs can be taken entirely as variable costs. If the replacement 

power is generated by the same utility that is retrofitting the CCS system, then only its variable 

costs are included in the dispatching costs for the retrofit system. Dispatching costs for this latter 

case (“self-generation” of replacement or parasitic power) are presented in Figure 5. This 

differential effect of who supplies the replacement power can be seen in comparing Figures 4 and 

5. 

The coal-based systems with CCS show a significant reduction in dispatching costs for the “selfgenerated” replacement power case (Figure 5), relative to the “purchased power” CCS case 

(Figure 4). Note that the break-even point for coal systems “paying the tax” versus retrofitting 

CCS has shifted from a tax level of $50/ton CO2, to $20/ton CO2 for the self-generated 

replacement power scenario. The NGCC systems are not as sensitive to the source of the 

replacement power, because most of the cost of NGCC power is the fuel cost, which is a variable 

cost in either scenario. For the self-generated replacement power scenario, the dispatching costs 

for a pulverized coal unit retrofit with CCS is about 40-50 $/MWh over a range of carbon taxes, 

which makes it comparable to NGCC systems without CCS retrofits. The take-home message 

here is not the absolute values of these projected costs, but rather the fact that analysts and 

decision-makers must be careful regarding how these costs are evaluated, and ensure that the 

assumptions used are appropriate for the system being evaluated, or they can be seriously misled. 

A related factor is the impact of parasitic power needs on bulk transmission of electric power to 

regions that are traditionally “net importers” of power. If a utility has generation capability that 

exceeds its local needs, it generally tries to sell that power to neighboring power consumers that 

have insufficient self-generation capacity. If local excess power is eliminated by retrofitting CCS 

systems on existing coal (and gas) power plants, then those utilities that previously purchased the 

excess power will quite likely lose that source of electricity. Hence, the sudden broad 

deployment of the current generation of CCS technology could be disruptive to power systems 

that do not even operate fossil fuel-fired generators. 

Carbon dioxide transport and storage

The cost and performance aspects of carbon dioxide transport and storage are well covered in the 

literature.23 The important factors related to transport and storage are:

1. The cost of transport and storage are believed to be a small fraction of the capture costs.

2. There is experience with pipeline transport and injection/storage at relatively small scale, 

but no experience with storage at the scale of commercial coal-fired power plants (e.g., 3 million 

metric tons per year for a single 500 MW unit). DOE is now beginning a program for evaluating 

“1 million TPY” demonstration projects, but results are years away.

3. There is no environmental regulatory framework for addressing the injection and storage 

of CO2 in the most likely resource for coal-fired power plants: saline geological formations 

perhaps one mile below the surface. EPA recently announced its intent to begin development of 

such a program under the Underground Injection Control program (UIC). See APPA paper on the 

current UIC program posted at http://www.appanet.org/files/HTM/ccs.html

4. There is likewise no framework for addressing financial liability associated with CO2

storage. Existing insurance mechanisms are not practical for a system that must maintain its 

23 Op.Cit., Carbon Dioxide Capture and Storage, Chapters 4 and 5.
8

integrity for hundreds of years. It is unlikely that electric utilities will embrace CCS technology 

until pragmatic frameworks are established.

Regulatory Issues for Retrofits

Clean Air Act Permits and Federal New Source Review Issues

Aside from the obvious regulatory issues associated with CO2 capture and storage that include 

permitting underground injection wells and obtaining rights to underground caverns for 

disposal,24 it also is likely that the retrofit of an existing electric generating unit will result in the 

retrofit being deemed a “major modification of a major Clean Air Act-regulated source.”25 This 

is because the CO2 capture system may lead to increases in other pollutants regulated under the 

Clean Air Act. Major modifications are subject to the federal new source review (NSR) program, 

which includes lengthy permitting, modeling of air quality impacts, and installation of state-ofthe-art pollution control equipment on the retrofitted boiler and ancillary emitting equipment. 

Under current federal law even environmentally beneficial projects can be subjected to lengthy 

regulatory processes, public scrutiny which can include legal challenges, and additional costs 

deriving from analytic requirements for permit preparation and additional pollution controls. It 

should be noted that NSR may be required for SO2 and NOx retrofits installed pursuant to the 

2005 Clean Air Interstate Rule (CAIR) because the SO2 and NOx pollution control equipment 

may lead to small increases of pollutants other than SO2 and NOx.26

However, even if the NSR exemption for “pollution control projects” still existed27, typical 

retrofits to existing power plants likely still would require NSR review. The large parasitic power 

requirements of CCS technology will very likely lead to increases in coal use at existing units.28

For some pollutants, like SO2, the additional reduction of that pollutant that occurs as part of the 

CO2 capture process will negate the increased amount of combustion. For others, like particulate 

matter, the situation is not as clear. In addition, some of the components of the CO2 capture

24 It is important to note that in some states, ownership of surface rights does not convey 

ownership of subsurface mineral or other rights needed for the disposal of carbon dioxide 

underground.

25 This term “major modification of a major source” has been the subject of extensive historical 

and ongoing regulatory and litigation controversy. This paper does not attempt to unscramble or 

recount these controversies, but instead calls to the reader’s attention that caution and additional 

costs associated with federal (and state) Clean Air Act permits will be associated with CCS 

retrofits. 

26 See, for example, Clean Air Report, Inside EPA, September 20, 2007, p.1; and New Source 

Review for CAIR and CAMR Projects, August 24, 2007 draft proposal by Indiana agency 

representatives to the Environmental Council of the States (not adopted by ECOS).

27 The D.C. Circuit Court of Appeals held that EPA could not exempt pollution control projects 

from New Source Review regulations, New York v. EPA, 413 F.3d 3 (D.C. Cir. 2006).

28 Consider the following simplistic example. An existing coal-fired power plant operates 60% of 

the year at full load, 30% at half-load, and is down for maintenance 10% of the year. After retrofit 

for CCS, the amount of coal used (and emissions) are unchanged for the full load and no load 

portions of the year. But for the 30% of the year historically run at half load, assuming demand 

remains the same and ignoring dispatching economics, to produce the same amount of 

megawatt-hours the unit will have to operate at approximately 70% capacity factor due to 

parasitic power loss. This higher operating level would lead to greater uncontrolled emissions. 

Increases in operating hours are not an exclusion from NSR if the increase is a direct result of a 

physical change at the unit. The ultimate determination of whether these circumstances 

constitute a “major modification” would depend on how State, EPA, and the courts interpret the 

regulations, as well as possible emission mitigating measures that the retrofit facility might 

undertake.
9

system may be sources of fugitive emissions of various pollutants regulated under the Clean Air 

Act.

NSR Review of CO2 and Other Green House Gases (GHG)

CO2 and other GHG also are likely to be regulated NSR pollutants for purposes of NSR review 

by the end of 2008 pursuant to a decision by the United States Supreme Court that these 

emissions were Clean Air Act “pollutants.”29 EPA officials announced at the September 2007 

meeting of the federal Clean Air Act Advisory Committee that the agency intended to complete 

regulations limiting CO2 and five other GHG from motor vehicles and possibly refineries by the 

end of 2008. The regulation of CO2 under Clean Air Act requirements (except as a “hazardous 

air pollutant”30) renders these substances a “regulated air pollutant” for purposes of New Source 

Review and Federal Operating Permits under 40 CFR subparts 51, 52 and 70 (the NSR and Part 

70 Operating Permit regulations). EPA officials also announced that they intend to undertake an 

NSR rulemaking by the time GHG are regulated to define what a “major source” of GHG is, and 

even more importantly, what “significant increases” of GHG are for purposes of defining the term 

“major modification.”31

Assuming CO2 and other GHG become regulated air pollutants, a significant net increase of any 

GHG within the facility will trigger NSR. This creates a situation analogous to the previously 

discussed paradox where environmentally beneficial hardware installed to reduce SO2 and NOx 

emissions under the CAIR rule could trigger NSR requirements due to small associated increases 

in particulate matter emissions. Similarly, the retrofit of traditional pollution control devices, like 

SO2 scrubbers, also could trigger “major modification” status for that facility for CO2, in the 

absence of the now-defunct “pollution control exemption”. This would lead to case-by-case Best 

Available Control Technology (BACT) reviews for CO2 emissions. 

Reconstruction and Clean Air Act New Source Performance Standards

If a facility retrofit constitutes a “reconstruction” of a facility under the Clean Air Act’s New 

Source Performance Standards (NSPS) regulations, the owner or operator must meet NSPS for 

the “affected source.” Thus, it is important to examine how EPA has interpreted the term,32

defined in the regulations as: 

40CRF60.15 (b) “Reconstruction” means the replacement of 

components of an existing facility to such an extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of 

29 In Massachusetts v. EPA U.S. 127 S.Ct.1438, 75 USLW 4149 (April 2, 2007), the Court 

addressed Massachusetts and other states’ petition challenging the agency for failing to regulate 

GHGs under the Clean Air Act’s mobile source program. The Court determined that these 

substances were “air pollutants” under the Act and essentially held that EPA must regulate 

vehicular emission of CO2 unless the Agency determines that CO2 does not endanger the 

public’s health and welfare. EPA is expected to regulate CO2 emissions from mobile sources, 

and that regulation will likely trigger requirements for new or modified major stationary sources 

such as power plants if they have more than de minimis increases in CO2 emissions.

30 Note that if CO2 were regulated as a hazardous air pollutant under Title III of the Clean Air Act, 

PSD would not apply pursuant to section 112(b)(6).

31 Until EPA defines what a “significant emission increase” is under 40 CFR §§51.166(b)(23) and 

52.21(b)(23 of the NSR regulations, “any” increase of pollutants will trigger NSR (and BACT) 

review.

32 EPA interpretations of NSPS for various affected industries can be searched on the Office of 

Enforcement and Compliance website on the “Applicability Determination Index” at 

http://cfpub.epa.gov/adi/.
10

the fixed capital cost that would be required to construct a comparable 

entirely new facility, and

(2) It is technologically and economically feasible to meet the applicable 

standards set forth in this part.

(c) “Fixed capital cost” means the capital needed to provide all the 

depreciable components.

Since the addition of a capture system does not fit neatly into the concept of “replacement of 

components,” the applicability of the NSPS ”reconstruction” test to CCS is unclear, in part 

because it is not clear whether the cost of a “pollution control” is included in determining the cost 

of a facility replacement.” Also, “pollution control projects” (PCPs) and “clean coal technology” 

continue to be exempt from the NSPS definition of “modification” under 40 CFR §60.14(e)(5), 

even following a Court’s ruling that the NSR exemption for PCPs was illegal because it might 

cause an increase in actual emissions.33 Nevertheless, even if all of these conditions are met, a 

regulatory obligation for reconstruction based on CO2 emissions can only exist after EPA adopts 

a CO2 NSPS, under 40 CFR Part 60. Note, that this future rulemaking could create a preference 

for an oxy-fueled system versus a post-combustion system, depending on how the rules are 

specified.

Storage Rules

There is general recognition that the current underground injection control (UIC) program for 

waste injection is not well designed to address issues associated with CO2 storage in deep saline 

reservoirs. The Interstate Oil and Gas Compact Commission (IOGCC) recently proposed that 

states take the lead on this type of regulation, given their extensive regulatory experience with 

CO2 -based enhanced oil recovery.34 Moreover, IOGCC expressed the view that CO2 should be 

treated as a resource, rather than as a waste, and that treatment of CO2 as a waste “would diminish 

significantly the potential to meaningfully mitigate the impact of CO2 emissions through geologic 

storage.” Shortly after IOGCC’s report and announcement calling for state primacy, U.S. EPA 

announced that it was beginning a federal rulemaking, under the authority of the Safe Drinking 

Water Act, to address underground injection of CO2.

35

Another local consideration that needs to be considered in the context of CCS is the ownership of 

surface and subsurface rights. In certain states (and most with significant mineral rights), 

ownership of underground caverns may be distinct from ownership of surface rights. Careful 

examination of deeds and other land records may be necessary to establish property ownership 

and rights of way for transport and sequestration of gases.

33 New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005).

34 Storage of CO2 in Geologic Structures – A Legal and Regulatory Guide for States and Provinces, 

IOGCC, September 25, 2007. “A key conclusion of that report [a 2005 IOGCC study] was that given the 

jurisdiction, experience, and expertise of states and provinces in the regulation of oil and natural gas production and 

natural gas storage in the United States and Canada, the states and provinces would be the most logical and 

experienced regulators of the geologic storage of carbon dioxide.”

35“EPA Rulemaking Plan May End States’ Bid for Lead Role On CO2 Storage”, Inside EPA, 

October 12, 2007, citing an Oct 11 announcement by EPA Administrator Stephen Johnson. 
11

Other liabilities 

Two additional areas of risk management related to CO2 storage are:

1. The potential for stored CO2 to migrate into areas of other valued resources, such as 

natural gas deposits, and diminish the value of those resources; and

2. The potential for CO2 migration after closure of the injection site. Injection of CO2

from an operating plant may last for decades, but for the storage to be effective, the CO2 must be 

contained for centuries. This timeframe is beyond the scope of available commercial risk 

management issues.

Effectively managing these risks may require government participation, and that may require 

additional legislative authority.

Looking to the future 

There is much ongoing activity related to CCS. The Department of Energy is focusing on both 

capture and storage, and several large storage projects are starting under the Regional 

Partnerships program. As noted earlier, EPA is beginning to develop rules for CO2 storage, and 

initial regulatory responses to Massachusetts versus EPA are likely by the end of 2007. Climate 

change mitigation legislation is receiving much attention in Congress.

Nevertheless, given the significant contribution of existing coal-fired power plants to both the 

nation’s electricity supply and to national greenhouse gas emission rates, and the high cost of 

currently available mitigation techniques, the resources focused specifically on developing 

pragmatic solutions for this CO2 emission group seem quite limited. Additional effort appears 

warranted to:

§ Significantly drive down the cost of CO2 capture, both through “learning by doing” using 

current technology, and through additional research.

§ Explore ways to modify the existing power plant itself, such as replacing turbines or

turbine components, or upgrading boilers, so that the existing plant becomes more efficient and 

productive. This would provide both a partial cost offset to the increased cost of electricity due to 

CCS retrofit, and (possibly) reduce the impact of parasitic power needs to drive the CCS 

hardware.

§ Gain experience with storing large quantities of CO2 in different types of geologic saline 

structures. The Regional Partnerships program may be a good start, but a few large projects are 

unlikely to be representative of the full range of geologies in the U.S. that are attractive for CO2

storage

§ Increase our knowledge base and simplify traditional preconstruction permitting 

procedures to expedite the permitting of CCS retrofit projects.
12

About the author – Doug Carter is an independent consultant on energy technology and 

related environmental issues. His current practice focuses on advising clients regarding 

advanced coal-based technologies and their potential role in mitigating global climate 

change. Mr. Carter’s resume includes 25 years with the U.S. Department of Energy, where 

he was Director of the Office of Planning and Environmental Analysis, within the Office of 

Fossil Energy. He had previously served with the Office of Enforcement and Office of Air 

Quality Planning and Standards at the U.S. Environmental Protection Agency. Mr. Carter 

holds degrees in Mechanical Engineering and Environmental Engineering. He can be 

reached at Carter2250@comcast.net .

The American Public Power Association is the national service organization representing the 

nation’s more than 2,000 community- and state-owned electric utilities. APPA’s website is 

www.appanet.org The dedicated website address for information on geologic sequestration 

and carbon capture and geologic sequestration or storage is:

http://www.appanet.org/files/HTM/ccs.html

APPA Contact: Theresa Pugh, Director, Environmental Services, 1875 Connecticut Ave, 

NW, Suite 1200, Washington, D.C. 20009-5715 or at (202) 467-2943

See page 13-16 for figures
13

Figures

Figure 1. Pulverized coal power plant with carbon capture.

Figure 2. Sources of parasitic power.

Additional Power Needs for CCS

Fans & pumps, 7%

Amine system Aux, 

24%

CO2 compression, 

53%

Other, 3%

Cooling system 

F&P, 13%

Boiler

PM removal

(FF or ESP)

Sulfur 

removal

(FGD) 

AH2

Flyash

Recycle

CO2

Scrubbers

Steam Turbine

Sulfur

By Products

Generator

Stack

Drying &

Comp.

Electric

Power

Coal

& 

Air

Sequestration

Ready CO2 

CO2 Capture

NOx

Removal

(SCR)

Condenser
14

Figure 3. An Oxy-combustion unit with CO2 capture.

Boiler

PM removal

(FF or ESP)

Sulfur

(FGD)

AH

Flyash

Recycle

Condenser

Coal

Steam Turbine

Sulfur

By Products

Solid

By Products

Generator

Flue Gas Recycling

Air 

Separatio

O

Air

Electric

Power

Sequestration

Ready CO2 

Drying &

Comp

CO2 Capture

NOx

Removal

(SCR)

Note: CO2 recirculation may be taken from before or after the FGD 

system, depending on SO2 concentration.
15

Figure 4. Dispatching costs assuming replacement power is purchased.

Dispatching Cost for Fossil Generating Options

-

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80 90 100

Carbon Tax, $/metric ton CO2

Variable costs, $/MWhr

PC, no capture but paying tax PC, w/50% capture * PC, w/90% capture

NGCC, no capture but paying tax NGCC w/90% capture, Ref. Price gas NGCC w/90% capture, $6.63 gas
16

Figure 5. Dispatching costs assuming self-generated replacement power.

Dispatching Cost for Fossil Generating Options

-

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80 90 100

Carbon Tax, $/metric ton CO2

Variable costs, $/MWhr

PC, no capture but paying tax PC, w/50% capture * PC, w/90% capture

NGCC, no capture but paying tax NGCC w/90% capture, Ref. Price gas NGCC w/90% capture, $6.63 gas
GEOLOGIC CO2

 SEQUESTRATION

ISSUE SPOTTING AND ANALYSIS WHITE PAPER

Timothy R Gablehouse1

Gablehouse Calkins & Granberg LLC

July 22, 2009

OBJECTIVE

This paper has been prepared for APPA’s electric utility members and water utilities for

the purpose of surveying the wide range of issues that will influence the implementation of

geologic carbon sequestration. As with many things, sequestration is not as simple as it seems. 

Injection of anything into the subsurface is regulated. Which agencies will act to regulate and

the criteria they will follow depends upon the answer to the questions raised in this paper –

questions that Congress and state legislatures will need to address if sequestration is to be

2

implemented on a scale remotely adequate to make a difference in the amount of CO reaching

the atmosphere.

Without a doubt sequestration projects will go forward. Many are already underway. 

Nothing in this White Paper should change anyone’s view on the technology available for

geologic sequestration. Nor should anyone read this paper to suggest that there are fatal legal

impediments to these projects. There are substantial legal issues and a prudent manager would

be well advised to factor these issues into the business plan for a sequestration project.

Much of this paper looks at the existing rules that apply to geologic sequestration. From

where we stand today it is these rules that will apply absent action by legislative bodies. For

example, if the CO2 being injected is a waste we next need to know if its hazardous waste and

Timothy Gablehouse is the managing partner of the environmental law firm of Gablehouse Calkins & Granberg

1

LLC in Denver Colorado. 410 17 St, Ste 1375 Denver CO 80202

th

tgablehouse@gcgllc.com

1
regulated under RCRA. If injection is limited to producing oil and gas operations for enhanced

recovery, then injection will be regulated by the state agencies that permit oil and gas

operations. The policies and procedures of these agencies and which permits might be required 2

are sometimes radically different state-by-state having the potential to drastically change the

regulatory burden and economics of any project. 

 Common law theories dealing with trespass, mineral rights and water rights all are

implicated as injection may result in trespass or harm to surface property rights, mineral rights or

water rights. Depending upon in which state injection operations occur, there are significant

questions regarding 2 the ownership and access to the subsurface spaces where the CO will be

placed. As the CO2 is intended to remain in the ground in perpetuity, then we also need to

examine who remains responsible in perpetuity. Regardless of whether these entities are private

corporations or public entities long-term liability issues will need to be address and understood. 

Absent new legislative action existing statutes such a CERCLA (“Superfund”) will play a role

which means that the landowner, mineral owner, injection operator and the entity that produced

2

the CO all may have some liability in perpetuity. 

It’s important to understand what this White Paper is not intended to accomplish. While

it will identify a broad range of property and liability issues associated with injection projects, it

will not suggest solutions to all of them. It will not address the range of liability issues

associated with the high-pressure pipeline infrastructure necessary to move acid gases from the

point of generation to the point of injection. For geolog 2ic CO sequestration to become broadly

viable there will need to be predictability on how these issues are handled. Many will have no

predictable solution until and unless we have federal and state legislation.

Acid gas injection for enhanced recovery of oil & gas is different from hydraulic fracturing which is also used to

2

enhance recovery by physically opening the subsurface formations using very high pressure, proprietary formulas

and particulates to hold the fractures open.

2
BACKGROUND

Much work ha 2s gone into the technical review of geologic CO sequestration. 

(Frequently this is referred to more generically as carbon capture and storage or “CCS” – the

remainder of this paper will utilize this nomenclature.) Some work has gone into potential

regulatory programs based upon extensions of the current EPA Underground Injection Control

(“UIC”) program. EPA has proposed a regulatory approach which is the topic of a September

10, 2008 White Paper available to readers. (As nothing has really changed on this front, this

White Paper will not cover that effort in any detail.)

Some states are adopting regulatory programs with various degrees of complexity. In

general they are based upon existing UIC programs or on injection of “acid gas” for production

enhancement in existing oil or gas operations. These can be radically different approaches and

the internal political situation along with the perceived importance of the oil and gas industry has

a large impact. 

It is critical to distinguish between production enhancement injection programs and

2

injection of CO solely for sequestration purposes as they are radically different in intent,

liability, risk and regulatory regime. A mineral owner typically has substantial rights to use

techniques such as fluid injection in order to produce the “minerals” like natural gas and

petroleum. Oil and gas production companies have substantial experience with this activity and

tend not to view it as very risky even though it’s currently benign regulatory posture is under

attack. 

As an example, the long-term liabilities associated with production enhancement versus

CCS scenarios have substantially different legal postures. For example, a land owner or even an

impacted neighbor may have products liability claims against the producer of the injected

3
enhancement fluid should it cause adverse impacts outside of the natural gas or petroleum

production pool. In a CCS project we would instead need to look to CERCLA or RCRA for 3

guidance 2 on long-term responsibility for the CO .

Not resolved to any satisfactory degree are the questions of legal access to property for

the purpose of CCS, whether it is waste disposal or something else, liability for the entire host of

things that people can imagine might go wrong, and long-term maintenance/monitoring. All one

need do is examine EPA’s 2008 Technical Support Document entitled “Vulnerability Evaluation

Framework for Geologic Sequestration of Carbon Dioxide” to get a sense of the complexity of

the problem and the difficulty of assessing potential risks. 

4

That these risks are a real concern when it comes to permitting and operation should be

obvious. Some examples may help to illuminate the risks that the public will fear:

- Fluid injection is suspected of causing Texas earthquakes. Wall Street Journal, June

12, 2009, Page A3.

- Earthquakes caused by deep well injection of wastes at Rocky Mountain Arsenal. 

http://earthquake.usgs.gov/regional/states/colorado/history.php

2

- Crystal Geyser UT – CO cold water eruptions through a manmade well. 

http://www.uweb.ucsb.edu/~glennon/crystalgeyser/

- 1986 Lake Nyos eruption and deaths.

- “CCS mobilization of hazardous, naturally occurring materials is a risk that must be

characterized.” “Injection into saline formations has the potential to disturb regional

ground-water flow systems and could contaminate drinking water.” Paraphrased

from the testimony of Dr. Burruss, USGS, Subcommittee on Environment and

Hazardous Materials, House Committee on Energy and Commerce, July 24, 2008

2

- Transportation infrastructure to transport CO to injection sites does not exist – USGS

projects that an infrastructure larger than the existing natural gas/petroleum industry

will be required to achieve meaningful levels of CCS. 

http://energy.er.usgs.gov/health_environment/CO2_sequestration/CO2_illustrations.html

See Modesto, City of v. The Dow Chemical Co., et al., No. 98-999345, Calif. Super., San Francisco Co. (liability

3

based on products liability theories found for dry cleaning fluid off-site impacts)

4

http://www.epa.gov/climatechange/emissions/downloads/VEF-Technical_Document_072408.pdf

4
ISSUES and DISCUSSION

I. Liability During Injection / Operational Liability

Operational liability includes the environmental, health, and safety risks associated with

CO2 capture, transport, and injection. Enhanced fluid recovery contractors are already subject to

a duty of care defined under tort law and are usually subject to standards of conduct under their

contractual arrangements. Companies providing these specific services have experience in their

industries, and are subject to liability for worker safety and property damage resulting from their

conduct. These companies are best positioned to manage the risks associated with their own

conduct and are able to obtain liability insurance for their conduct and workers. In surveys and 5

case studies, these companies were willing to provide services on a commercial basis and

generally willing to accept liability for their actions.6

However, it is foreseeable that large-scale CCS could make it less likely that companies

will be willing to accept liability for injection. For example, if there was contamination at the

surface during injection operations it could potentially affect drinking water. There is currently

no law protecting commercial or public operations from the full range of liabilities should they

cause contamination.

In theory government agencies could conduct the injection operations to limit liability

associated with injection. An example of this is Lawrence v. Buena Vista Sanitation District. 

7

Neighbors brought a trespass claim against the sanitation district, alleging contamination from

leakage at the district's wastewater treatment facility but did not argue that negligence was

M.A. de Figueiredo, D.M. Reiner, H.J. Herzog, Towards a Long-Term Liability Framework For Geologic Carbon

5

Sequestration, Presented at the Second Annual Conference on Carbon Sequestration, Alexandria, Va. May 2003.

Craig A. Hart, Advancing Carbon Sequestration Research in an Uncertain Legal and Regulatory Environment: A

6

Study of Phase II of the DOE Regional Carbon Sequestration Partnerships Program, Discussion Paper 2009-01,

Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009 (finding drilling companies

willing to participate in CCS and accept liability for their actions).

Lawrence v. Buena Vista Sanitation Dist., 989 P.2d 254 (Colo.App. 1999)

7

5
present. The court held that the district was immune from a trespass claim under Governmental

Immunity Act “unless negligence is proven”. Trespass is not a dangerous condition of a public

water facility or public sanitation facility; because the trespass claim did not require proof of

negligence it was barred by Governmental Immunity. Nobody should take this sort of outcome

as an indication that government agencies can conduct these operations with impunity – there are

many other available theories of liability. 

II. Post Injection Liability

A. Ownership of Pore Space

The surface owner usually owns pore space because mineral conveyances, including

leases, normally only pass title to the minerals, not the pore space itself. That does not, however,

end the conversation over who controls the pore space property right. The surface owner cannot

violate the mineral estate owner’s or lessees’ rights by doing something interfering with access

to the minerals, making the minerals more expensive to exploit or making the development of

the minerals economically impractical. Clearly injection into the pore space could cause this sort

of harm. The surface owner must also allow reasonable use of the property to give access to the

mineral estate. For CCS projects to proceed it is somewhat reckless to assume that agreement 8

with the surface owner is the only necessary step. It seems prudent to have agreements with

both surface and mineral owners even though it seems likely that the surface owner owns the

pore space. 

9

B. Risk of Leakage

Post-injection liability includes harm to human health, the environment, property, and the

climate liability related to leakage or migration of carbon dioxide from geological reservoirs and

Cassinos v. Union Oil, 14 Cal.App.4th 1785 (1993)

8

Geologic CO2 Sequestration: Who Owns the Pore Space?, 9 WY LR 98, 2009.

9

6
the effect on climate change. Potential pathways for carbon dioxide release include leakage

through the pores of low-permeability cap rocks if the carbon dioxide is injected at too high a

pressure, leakage through openings in the cap rock, leakage through abandoned or improperly

sealed wells, and migration via faults. 

10

Reportedly, there is a low risk of captured carbon leaking into the atmosphere in amounts

2

significant enough to pose a risk. CO and natural gas has been stored naturally in geologic 11

formations for millions of years and companies already store natural gas underground with a lot

of experience. The 2re are naturally occurring CO reservoirs in the western states that have held

gas for 2 millions of years. Furthermore, over 100 million tons of CO has been injected into oil

reservoirs for enhanced fluid recovery as well as into deep saline aquifers (over 80 projects have

been implemented worldwide). Commercial and experimental projects have shown the 12

potential for CCS across a wide range of geological settings. 

There are, however, reports suggesting that an exceptionally detailed analysis of geologic

conditions is critical to understanding 2 how the CO is being sequestered in each case. Whether

CO2 is being mineral trapped, in which case it may be stable on geologic time scales, versus

dissolution in groundwater is critical to an assessment of whether a potential for leakage is

present. Dissolution in groundwater is not preferred as it has the greatest potential for eventual

leakage to the atmosphere.13

The long 2-term liability associated with CO leakage that damages health or property is

difficult to establish because it is dissimilar to other regulatory schemes and has a timeframe of

thousands of years. We simply do not know what risks long-term geologic storage presents. 

IPCC, IPCC special report on carbon dioxide capture and storage; 2005.

10

Feidman, This work performed under the auspices of the U.S. Department of Energy by Lawrence Livermore

11

National Laboratory under Contract DE-AC52-07NA27344

Rocky Mountian Mineral Law Institute

12

Aeschbach-Hertig, Clean Coal and Sparkling Water, NATURE, Vol 458, Page 583, April 2009.

13

7
Exposure to CO2

 typically is not dangerous except in very high concentrations (> 15,000 ppm). 

For example, in Lake Nyos 1,500 people died when a lake over a magma pool released large

amounts of CO2. This is unlikely to occur at injection wells when properly monitored. 

Researcher 2s have successfully plugged and abandoned CO injection wells, even badly damaged

and fa 2iled wells. In wells that have failed and released CO , almost all were detected quickly and

stopped. 

14

EPA produced a July 2008 white paper entitled Approaches To Geologic Sequestration

Site Stewardship After Site Closure. They describe the advantages and disadvantages of 15

stakeholder developed models as well as models based upon existing federal laws ranging from

the Nuclear Industries Indemnity Act through CERCLA. If CCS is viewed as waste disposal the

“cradle-to-grave” model of the RCRA and perpetual nature of liability under CERCLA would be

2

inconsistent with any effort to limit responsibility for injected CO and especially any potentially

hazardous contaminants entrained in the injected materials. 

EPA’s ana 2lysis has been criticized as unrealistic given that geologic storage of CO is

intended to be indefinite and well beyond 50 years. The authors of a recent report view this as

the single greatest legal obstacle to commercial deployment of CCS. Quite obviously,

16

legislation will be required to address this issue if there is to be any time limit on liability.

C. Property Rights Issues Re 2lated to Migration of Injected CO

1. Natural Gas Storage Law May Provide Some Insight

S. Julio Friedmann, Carbon Management Program APL Global Security Principle Directorate, LLNL. .S.

14

Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344

15

http://www.epa.gov/OGWDW/uic/pdfs/support_uic_CO2_stewardshipforsiteclosure.pdf

World Climate Change Report, 87 WCCR, 05/08/2009, BNA.

16

8
Gas that is injected for storage remains the property of the injector. Injection of gas 17

into property that the injector does not own is a trespass. Pore space for such projects can be 18

purchased or leased from the landowner, and/or the mineral estate owner, so long as it does not

damage other persons. Agreement with the mineral estate owner or lessee will generally be 19

prudent in order to avoid later damage or trespass claims as there is ambiguity in some states

regarding whether a mineral owner owns the pore space previously occupied by the minerals,

natural gas or petroleum they have removed. Liability for negligent operation of storage

20

operations exists.21

Under many federal and state laws utility companies have eminent domain rights for

utility facilities. This begs the question of whether CCS operations represent a utility facility

under these statutes – if viewed as waste disposal, there is doubt. These statutes do not address

the ability to exercise eminent domain rights over buffer zones that may be desirable because of

the potential for gas migration. Buffer zones should be included because gas escape is a

trespass; however, how such a buffer might be valued in an eminent domain action is unknown.

With regards to carbon sequestration the concept of condemnation poses several

problems. CCS potentially involves large areas of land – hundreds of acres - depending upon the

subsurface conditions and resulting available storage volumes. The uncertainty over whether 22

statutory authority to exercise imminent domain applies suggests an initial effort to negotiate and

purchase rights. If injection requires approval from any landowner that could be affected, then it

Ellis v. Arkansas Louisiana Gas Co., 450 F. Supp. 412, 419 (D.C. OKL 1978) and many others

17

Kuntz, The Law of Oil and Gas s 2.6, p.71

18

Ellis, at 450 F. Supp. 412

19

Geologic CO2 Sequestration: Who Owns the Pore Space?, 9 WY LR 98, 2009.

20

In a recent case from Louisiana a jury awarded $9.2M to a petroleum company whose ability to exploit reserves

21

was adversely impacted by improper maintenance and operation of a neighboring salt dome storage facility.

Separation and capture of CO2 from large stationary sources and sequestration in geological formations--

22

coalbeds and deep saline aquifers. J Air Waste Manag Assoc. 2003 Jun;53(6):645-715

9
will be necessary to secure consent from a potentially large number of people. Negotiation and

condemnation will therefore impose high costs and long acquisition times. 

As it will not be the intent (in most cases) to later retrieve the gas, there are interesting

questions and serious unknowns regarding the rights and duties of the property owners later in

2

time. Establishing ownership of CO in perpetuity is a key part of this problem, especially given

the vast amounts of time it will be sequestered. If there is no intent to recover perhaps there is

no duty 2 to protect and preserve the CO or the associated surface facilities. If the entity that

owned the CO2 when it was injected disappears, then whether the CCS process is waste disposal

or something else will be critical to understanding the on-going duties of the landowner. Any

resolution of this issue will require legislation.

2. Enhanced Oil Recovery

Oil and gas leases typically contain the right to inject fluids to aid in the production of

gas or oil, but not for disposal of waste. Leases and state laws often give the producer the right

to “unitize” for secondary recovery allowing injection in various locations of a field. These

enhanced recovery 2 efforts are not necessarily designed to sequester CO even if “acid gas” is

used. Given the lease/contract rights these processes are probably not a good mechanism to

examine the broader liability issues associated with CCS projects unassociated with oil and gas

production. 

As noted before liability for the injected materials, such as hydraulic fracturing fluid or

acid gas, exists regardless of why these materials were injected. Contract or lease theories will

apply and may be of value in the short-term until the normal statute of limitations runs. Beyond

these theories liability is likely perpetual under federal environmental laws as these fluids will

10
typically contain hazardous substances. As noted earlier, products liability theories may apply to

the entity that produced the fluid if it harms third persons.

3. Waste Injection 

Wastewater wells are subject to permitting by EPA and/or states. Failure to obtain

permits or operate within the terms of a permit will make the operator subject to agency

enforcement and citizen suits. Obviously the party injecting must have the legal right to do so;

however, what those rights mean will be highly variable. In Chance v. BP Chemical, the

Supreme Court of Ohio determined that the defendant committed a trespass when chemicals

injected underground migrated under plaintiff’s property for which no rights had been acquired. 

Even so, the proper evaluation of damages is very uncertain. 

The court held that the surface owner’s rights were not absolute, but were contingent on

the reasonable and foreseeable use of their property. According to the court, subsurface rights 23

include the right to exclude invasions of the subsurface property that actually interfere with the

property owner’s reasonable and foreseeable use of the subsurface. This would most certainly 24

include harm to minerals or oil and gas resources leased by the landowner. 

This sort of analogy would work well for CCS because landowner’s that are not harmed

by 2 stored CO would have no cause of action. It seems to follow that there would only be a

cause 2 of action after CO specifically damages the health or property of a landowner – not for

speculation that gas could potentially leak from geologic formations or interfere with access to

minerals or oil and gas. Many courts would likely disagree and would find diminished value

simply due to the trespass. Legislation, rather than litigation, is by far the best way to establish

the rules in this arena.

Chance v. BP Chemical, 1995 WL 143827 (Ohio Ct. App 1995)

23

Id.

24

11
4. Wastewater

In Cassinos v. Union Oil Co., the owners of a mineral estate sued defendant for damages

when defendant injected wastewater into the mineral estate. The California Appeals Court

rejected the defendant’s claim that it should not be liable because the plaintiff did not establish

the extent of damage to the mineral estate. The court held that there was substantial evidence the

defendant’s actions interfered with and damaged the mineral estate. Therefore, the defendant

committed a trespass. The court also held that the plaintiff in the case could waive the tort claim

and collect on an alternative theory of contract implied in law to recover the value of the use

taken.25

From Chance (supra) and Cassinos, it is apparent that a cause of action is not likely to

occur if there is no damage done. Interference with mineral rights should be a concern because

CCS can displace subsurface gases and groundwater, which could damage mineral estates. The

holder of a mineral estate or lease would have a cause of action along with the surface owner.

If the activity is allowed by statute it does not necessarily mean that the injector will be

absolved of liability. In Tidewater Oil Co. v. Jackson, there were damages to plaintiffs' oil wells

as a result of water flooding operations conducted by defendant on adjoining property. The Court

of Appeals held that where defendant's water flooding activities were intentional and damage to

wells on adjoining land was foreseeable, defendant was liable under Kansas law for damage to

wells of adjoining leaseholders. 

These findings were inconsistent with the administrative findings to the effect that the

water flooding operations were carried on in a lawful manner. In the view the court took, it was

unnecessary to reconcile the findings. It was sufficient that the water flooding activities were

intentional and the consequences foreseeable. A legal claim was available, even though the

Cassinos v. Union Oil Co., 14 Cal.App.4th 1770, 18 C (Cal App 1993)

25

12
flooding was lawfully carried on, because it caused substantial injury to the claimants. This 26

case is important because it highlights that regulations that allow CCS may not absolve the

defendant of common law property law liability. 

4. Water Law

It most of the Western US surface and groundwater is a public resource dedicated to the

beneficial use of public agencies and private persons wherever they might make beneficial use of

the water. (Texas is a bit different in that groundwater belongs to the landowner and is not

subject to prior appropriation. That can result in significant fights between neighbors should one

pump so much groundwater that a neighbor’s well becomes dry. This law of the “biggest pump”

has been mitigated through administrative processes such as conservation districts regulating the

use of groundwater. ) Under the general western approach, including surface water in Texas, 27

water quality and quantity are property rights subject to statutory and common law protections. 

The biggest difference between water and real property is that the protections available for water

frequently exceed those available for real property. 

The right of water use includes the right to cross the lands of others to place water into,

occupy and convey water through, and withdraw water from the natural water bearing

formations within the state in the exercise of water use right. Natural water bearing formations

may also be used for the transport and retention of water. Water authorities can inject water for 28

later withdrawal with no payment for the pore space. The property rights of landowners or

mineral estate owners/lessees do not include the right to control the use of water in the ground

and cannot claim control of aquifers as part of their estate. Except for Texas, groundwater is part

of “waters of the state” and either by Constitution or statute, the general assembly of each state

Tidewater Oil Co. v. Jackson, 320 F.2d 157 (C.A. Kan. 1963)

26

Sipriano v. Great Spring Waters of America, et al., 1 SW3d 75 (Texas 1999)

27

Board of County Com’rs of County of Park v. Park County Sportsmen’s Ranch, 45 P.3d 693, 706 (Colo. 2002)

28

13
has control over the use and disposition of groundwater regardless of whether it is or is not

directly discharged to a natural stream. 

The law in most states prohibits the taking of private property for public or private use

without the property owner’s consent, but there are frequently exceptions which pertain to

constructed water facilities. For example many western state constitutions provide for access 29

to the water source across the lands of others and further recognize and address the private right

of condemnation for the construction of waterworks. There is a requirement for compensation 30

for use of another’s land, but that does not extend to employment of natural water bearing

subsurface formations on or within the landowner’s property for the movement of appropriated

water. An applicant for a conditional decree to utilize available aquifer storage space must 31

demonstrate that it will capture, possess, and control water lawfully available to it and without

injury to other water rights. 

32

Water storage under a landowner’s property is not a trespass if it does not inhibit the use,

benefit, or enjoyment of property. In Board of County Commissioners v. PCSR, LLP, PCSR 33

proposed to store water in underground aquifers underlying approximately 115 square miles. 

The landowners claimed that storage of water underground in aquifers underneath their land

would constitute a trespass. The Court held that it would not be a trespass and the project would

not require the Landowner’s consent or condemnation and the payment of just compensation

under the provisions of Article XVI. The court, in applying Causby, found that the project did 34

not include construction of any facilities on or in the Landowner’s properties and the

Colo. Const. art. XVI § 7

29

Colo. Const. art. II § 14

30

Sportsmen’s Ranch, at 45 P.3d 708

31

Id.

32

Sportsmens’s Ranch, 45 P.3d at 708

33

U.S. v. Causby, 328 U.S. 256 (1946) (ruled that property owner’s rights were not unlimited with respect to

34

airspace).

14
Landowner’s had not alleged that the use, benefit, and enjoyment of their properties would be

invaded or compromised in any way. Therefore, it was not a trespass. 

The court stated that the General Assembly, in authorizing the use of aquifers for storage

of artificially recharged projects further supplanted the Landowners’ common-law property

ownership theory. The court found it “particularly [significant]” that: 35

 (1) [F]ederal patents to land do not include water, (2) ground water is not a mineral

under the federal mining laws ..., (3) federal statutes as interpreted by the Supreme Court

recognize [a state’s] authority to adopt its own system for the use of all waters within the

state in accordance with the needs of its citizens, subject to the prohibitions against

interference with federal reserved rights, with interstate commerce, and with navigability

of any navigable waters, (4) the right of prior appropriation applies ... to waters of the

natural stream, including surface water and tributary ground water; (5) the property rights

of landowners do not include the right to control the use of water in the ground, whatever

the character of that water; and (6) the General Assembly has plenary control over the

use and disposition of ground water that is not part of the natural stream.36

In sum, the holders of water use rights may employ underground as well as surface water

bearing formations in the state for the placement of water into, occupation of water in,

conveyance of water through, and withdrawal of water from the natural water bearing formations

in the exercise of water use rights. Consent or just compensation was not required because the 37

plaintiffs did not have the right to restrict the defendant’s use of the water that was done within

regulations. 

CCS 2 presents a unique problem because the underground storage of CO could

potentially affect the flow and location of groundwater. This could occur because the process of

physical trapping may displace naturally occurring water and other gases. Any effect on water 38

resources could pose potential liability if it limits access to water that has already been

Id. at 703

35

Id.

36

Id. at 712

37

Statement of Dr. Robert Burrus, Research Geologist, Enerby Resources Team U.S. Geological Survey U.S. Dep.

38

Of the Interior Before the Subcommittee on Environement and Hazardous Materials House Committee on Energy

and Commerce Hearing on “Carbon Sequestration: Risks,

15
appropriated to beneficial use. Physical displacement of groundwater can also have adverse

practical impacts on private owners and utilities. As a result it will normally be prudent to

evaluate whether on-site groundwater wells, especially those used by public water systems, will

be disrupted by CCS operations.

In most places a water right includes the right to a particular quality as well as a

particular quantity of water. These cases are typically framed in the context of deprivation of

quantity but these water rights are also protected from activities of another that injure the quality

of a water right. Therefore, if water quality is affected by the precipitate that hopefully forms 39

from the geochemical reactions intended as part of CCS operations the owner of that water could

have a cause of action against the entity injecting and the owner of the gas injected. Historically

such interference involved the discharge of mine and other wastes into the stream but there is no

reason to believe the result would be different with CCS. 

40

III. Regulation

A. EPA UIC Rulemaking

The UIC Program regulates underground injection under five different classes of

injection wells, depending on the type of fluid being injected, the purpose for injection, and the

subsurface location where the fluid is to remain. States are allowed to assume primary

responsibility for implementing the UIC requirements in their borders, as long as the state

program is consistent with EPA regulations and has received regulatory approval. Injection

operators are required to provide financial assurance in case they cease operations, with the level

of assurance a function of the estimated cost of plugging and abandoning the injection well. If

there is a violation of a UIC permit, an enforcement action may be brought by the EPA

2A COPRAC § 76.11

39

Game & Fish Comm'n v. Farmers Irr. Co., 162 Colo. 301, 426 P.2d 562 (1967); Wilmore v. Chain O'Mines, 96

40

Colo. 319, 44 P.2d 1024 (1934).

16
Administrator or the applicable state agency. Violators may be subject to administrative orders,

civil penalties, and criminal penalties. The scope of the UIC statute is contamination of drinking

water 2, and under its current application to CO storage, the UIC Program gives more limited

treatment, if any, to other harms to human health, the environment, and property.

41

While there are requirements for constructing and monitoring injection well operation,

there are no federal requirements for monitoring actual movement of fluids within the injection

zones, nor are there requirements for monitoring in overlying zones to detect leakage with the

exception of specific class I hazardous wells, where this monitoring can be mandated.42

On July 15 2008, the EPA proposed a rulemaking package that would regulate geologic

sequestration of carbon dioxide under the UIC. The proposed rules would create a new category

of UIC well (Class VI) designed specifically for injection of CO2 into geologic formations. The

proposal includes detailed technical requirements for characterizing the scope and suitability of

the target formations, assuring that the injection zone will not affect any actual or potential

source of drinking water, monitoring and reporting on well conditions during and after the

sequestration is complete, and requiring as part of well permit applications plans for 50 years of

post-injection monitoring.43

The proposed rules do not direc 2tly address air quality issues. The Class VI CO injection

well requirements are designed to assure 2 that there are no significant releases of CO or

contaminants in the CO2 2 into the ambient atmosphere. The EPA declined to classify CO as a

hazardous wa 2ste but the proposed rules place a burden on the permittee to assure that the CO

does not contain impurities that would trigger RCRA hazardous waste management

Craig A. Hart, Advancing Carbon Sequestration Research in an Uncertain Legal and Regulatory Environment: A

41

Study of Phase II of the DOE Regional Carbon Sequestration Partnerships Program, Discussion Paper 2009-01,

Cambridge, Mass.: Belfer Center for Science and International Affairs, January 2009.

Regulating the ultimate sink: managing the risks of geologic CO2 storage. Page 3479

42

http://www.epa.gov/ogwdw/uic/wells_sequestration.html

43

17
requirements. The risks associated with this classification are manifest. Injection of hazardous

waste is highly regulated and would likely bring a CCS project to a screeching halt. 

None of this overrides the applicable provisions of CERCLA or RCRA. To the extent

there are hazardous substances released from the sequestration process liability under CERCLA

may be present. Likewise if materials injected are hazardous waste the daunting permitting and 44

corrective action provisions of RCRA and the state programs will apply. 

As an example, EPA issued orders under RCRA to require management of propane that

had leaked from an underground distribution system. In EPA’s view, the moment the propane

leaked from the distribution system it was a waste and presented a hazard. Depending upon the

factual setting, CCS operations could find themselves in the same situation. 

B. State Regulation

In the absence of federal action on the carbon sequestration issue, many states are in the

process of enacting their own regulations. Some examples follow:

1. Wyoming

House Bill 89 (created Wyoming Statute § 34-1-152 and amended Wyoming Statute §

34-1-202) addresses the ownership of Pore Space. The Bill establishes that the surface owner

owns pore space underneath the surface estate and that the pore space is conveyed upon the

conveyance of the surface, unless the space has been previously conveyed or is explicitly

excluded in the surface conveyance (in the same manner as a mineral interest). In addition, legal

requirements for notice to surface owners and/or mineral interest owners shall not be construed

to require notice to the pore space owner unless the law specifies that such notice to the pore

space owner is required. The statute expressly recognizes the dominance of the mineral estate

http://www.hhclimatechange.com/climate_change/2008/07/epa-releases-pr.html

44

18
and does not alter the common law as it relates to the rights of the mineral estate. The bill states

explicitly that it does not affect the common law regarding the dominance of the mineral estate.45

House Bill 90 (effective July 1, 2008; created Wyoming Statute §§ 30-5-501 and 35-11-

313 and amended Wyoming Statute § 35-11-103(c)) mandates UIC permit for GCS. It makes a

clear distinction from EOR. It instructs the Wyoming Department of Environmental Quality to

establish and issue permits to new “sub-classes of wells” within the UIC program and to regulate

well standards, bonding and monitoring. The bill requires the DEQ to create an advisory board

and rules to expand the UIC program to include carbon sequestration. Under the bill, a working

group including the supervisor of the oil and gas commission, the state geologist, and the

director of the DEQ will set bonding procedures. Jurisdiction subsequent extraction of

sequestered carbon dioxide rests with the Wyoming Oil and Gas Conservation Commission. The

bill does not impact the oil and other mineral interest owners’ right to drill or bore through

sequestration sites, nor does it include within its scope the regulation of enhanced oil recovery

operations using carbon dioxide.46

Like HB 89, Wyoming's carbon capture and sequestration legislation recognizes the

continuing dominance of the mineral estate. § 30-5-501 states specifically that the carbon

sequestration legislation enacted by § 35-11-313 shall not “affect the otherwise lawful right of a

surface or mineral owner to drill or bore through a geologic sequestration site” so long as the

drilling is conducted in conformity with rules for protecting the sequestration site against the

escape of CO2.

47

Id. at 143-45

45

Delissa Hayano, Guarding the Viability of Coal & Coal-Fired Power Plants: A Road Map For Wyoming’s Cradle

46

to Grave Regulation of Geologic CO2 Sequestration, 9 Wyo. L. Rev. 139, 145-49 (2009)

Id.

47

19
2. Oklahoma

Senate Bill 1765 (May 2008) was a proposal that required the development of GCS

permitting regime and transferred ownership of wells to state and released owners from liability

10 years after closure. The Bill that was passed, however, was relatively disappointing. It

mandated a task force to report to the Governor with GCS permitting recommendations by

December 2008 (extended to December 2009) and is modeled based on the IOGCC model

statute.48

3. Kansas 

Under HB 2419 (2007), GCS rules were supposed to be developed by July 2008 (draft in

progress). Under the Bill, a state GCS fund would pay long-term GCS related monitoring and

remedial activities. It also exempts GCS property and any electric unit utilizing GCS from taxes

for 5 years. Finally, it allows for accelerated depreciation of GCS equipment.49

4. Washington

ESSB 6001, passed April 17 2008. It codifies the emissions-reduction goals and policy

recommendations for the state. The bill also sets an Emissions Performance Standard (EPS) that

limits electric utilities’ ability to sign new or renewed long-term contracts with power plants

whose greenhouse-gas emissions exceed those of a modern natural gas-fueled power plant. The

bill essentially ends construction of pulverized coal plants to serve Washington loads, makes the

price of IGCC power reflect some of its emissions disposal costs, and jumpstarts the process

toward a comprehensive greenhouse-gas emissions reduction plan for the state.

50

de Figueiredo MA, Reiner DM, Herzog HJ. Framing the long-term in situ liability issue for geologic

48

carbon storage in the United States. Mitigation Adapt. Strat. Global Change 2005;10:647-57.

Melisa F. Pollak ,Humphrey Institute of Public Affairs, Big Sky Carbon Sequestration Partnership Annual Meetin.

49

Oct. 28, 2008

NW Energy Coalition, April 19, 2007. www.nwenergy.org/publications/fact-sheets/6001%20FINAL%2

50

20
1

American Public Power Association

2301 M Street, N.W.

Washington, D.C. 20037

202-467-2900; fax: 202-467-2910

www.APPAnet.org

Carbon Capture and Sequestration

Legal and Environmental Challenges Ahead

August, 2007 1

- A White Paper -

Prepared by Marianne Horinko, Executive Vice President, The Global Environment &

Technology Foundation for the American Public Power Association (APPA)

Carbon capture and sequestration or storage (CCS) is on the cutting edge of greenhouse 

gas reduction technology research. CCS is the process by which carbon dioxide (CO2) is 

separated and collected from large point sources such as coal power plants and retained in 

a manner that prevents immediate release into the atmosphere. This retention may be 

accomplished through a variety of means, such as large-scale botanical plantings or 

chemical adsorption treatment. This paper, however, is limited to the most common 

method, geological sequestration, which involves injection of CO2 into underground 

geological formations. While CCS could potentially be effective in reducing greenhouse 

gas emissions, there are still unanswered questions about its long-term effects on human 

health and the environment, as well as real property and liability considerations.

The scale of CCS necessary to impact greenhouse gas emissions vastly exceeds the 

historical use of carbon injection practices in enhanced oil recovery (EOR). The purpose 

of carbon injection in EOR has been to displace fossil fuel to allow recovery; carbon 

sequestration is merely a byproduct of that recovery process. Generally speaking, CO2

used in EOR is locally available from commercial, food grade CO2 sources and not from 

utility or manufacturing plants. Sometimes the CO2 used by the oil and gas recovery 

EOR operations is available locally through naturally occurring sources in the ground.

For example, to reduce the 2.5 billion tons of CO2 annually emitted by United States 

power plants by ten percent (250 megatons) would require extensive deployment of CO2 

emission capture technologies at 25 plants.

2 Commercial-level CCS deposits are likely to 

be extensive, intersecting with preexisting mineral, water, and private property rights. In 

addition, the environmental liability associated with such practices has not been widely 

litigated, adding a layer of business uncertainty to the use of CCS as a viable technique. 

The legal frameworks surrounding existing EOR practices are focused on injection and 

typically maintain only limited long-term storage and monitoring components due to their 

small scale. Commercial-level CCS projects would require a reliable and transparent 

1 This paper contains slight adaptations from the April 2007 version for APPA—primarily in the footnotes.

2 Based on Energy Information Administration statistics. Assuming that a one gigawatt power plant 

produces 10 million tons of CO2 annually. 
2

regulatory framework based on sound analysis of the unintended consequences to human 

health and environmental assets. The injection of CO2 from power plants into any 

appropriate geologic formation would also require, first, considerable breakthroughs in 

carbon separation technology at the power plant. This is a step that, generally speaking, 

EOR sites do not require. 3

The purpose of this white paper is to introduce environmental and legal issues that may 

require additional research before large-scale CCS can be implemented safely and 

effectively in the public power utility sector.

Human Health and the Environment

Despite the successes of EOR or tertiary recovery of oil and gas using CO2 injection, 

leakage from embedded CO2 deposits could result in the endangerment of ecological and 

human health given the scale of the utility sector’s emissions. A better understanding of 

these impacts is necessary in order to take precautionary steps to mitigate them or avoid 

them entirely.

§ Prolonged exposure to elevated concentrations of CO2 can be harmful to human 

respiratory and central nervous systems.

§ The release of large volumes of high concentrations of CO2 can result in the 

suffocation of humans, animals, or plants above ground. For instance, natural CO2

long-term seepage destroyed 40 hectares of trees on Mammoth Mountain in the 

Eastern Sierra Nevada mountain range in California.

4

§ Leakage from injected CO2 could migrate into Underground Sources of Drinking 

Water (USDWs). Migrating CO2 deposits may alter the pH of subsurface 

groundwater or displace potable water resources by forcing saline waters to merge 

with fresh water formations.

§ According to the U.S. EPA, 44 percent of all U.S. drinking water is from 

groundwater, a considerable increase from only 5 years ago when most U.S. drinking 

water was from surface water sources.

§ Current research suggests that injecting carbon into saline aquifers poses a threat to 

groundwater because of brine contamination.5Since it is not clear how large-scale 

CCS activities would address this concern, additional research is required considering 

the growing reliance on groundwater for use as drinking water.

§ CCS could potentially cause displacement of native fluids and chemical constituents, 

movement of possible hazardous substances, or potential leaching of naturally 

occurring metals and minerals mixed in the CO2 injection. 

3

Complete explanation of separation technology issues available. See L. D. (Doug) Carter, Carbon Capture 

and Storage From Coal-based Power Plants: A White Paper on Technology, American Public Power 

Association, 22 May 2007.

4 C.D. Farrar, M.L. Sorrey, W.C. Evans, J.F. Howle, B.D. Kerr, B.M. Kennedy, C.-Y. King, and J.R. 

Southron, “Forest-killing Diffuse CO2 Emission at Mammoth Mountain as a Sign of Magmatic Unrest,” 

Nature 376 (1995): 675-678.

5 Brian McPherson and Peter Lichter, CO2 Sequestration in Deep Aquifers, 

http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/7a2.pdf.
3

§ If the CCS process is responsible for discharge of a pollutant or hazardous substance 

(such as arsenic) into or upon navigable waters, this may incur administrative and/or 

civil penalties under the Clean Water Act (CWA).

6

Property Rights

The legal mechanism for securing property rights for large carbon sequestration sites may 

currently be ineffective in many states, leading to unforeseen costs and delays. It also 

may lead to tensions between large-scale CCS projects and individual property rights.

§ Since sub-surface land can be privately owned in the United States, CO2 injection into 

geologic formations may require permission from all private owners of intersected 

sub-surface property. A proposed deposit for a FutureGen zero-emissions plant site 

may require property rights from 69 individual property owners.

7

§ Compulsory unitization laws for oil and gas production operations, currently used in 

some states to compel private property owners to permit large oil and gas sub-surface

projects when a high percentage of affected property owners do accept, may be used

extensively for enhanced oil recovery-related CCS.

§ For non-oil and gas production projects, the use of eminent domain laws, currently 

used for sub-surface natural gas storage fields, may be necessary for CCS projects.

Widespread use of local and state eminent domain laws for CCS may be politically 

difficult, given the public backlash against eminent domain driven by the Supreme 

Court case Kelo v. New London.

8

§ There is currently a significant level of uncertainty in predicting migration and 

movement of large CO2 deposits in large geologic formations. Without further 

research, the scale of property right acquisition for CCS projects will remain high, as 

industry participants will seek to minimize liability from property trespass claims

related to sub-surface trespass, geological surveying, and deposit monitoring.

§ This scientific uncertainty may interfere with the availability of liability insurance for 

CCS project participants. If insurance companies cannot accurately calculate the risk 

of CO2 damages, or future potential environmental liability, they may decline to offer 

coverage to public power utilities. Some public power utilities may not have the 

insurance coverage thought to be sufficient to handle the perceived risks for geologic 

sequestration or storage of CO2.

§ The utilization of regional land use controls to ban large-scale CCS projects near 

valuable natural resources may be an obstacle to implementing projects in viable

locations.

General Regulatory Framework

The current federal and state regulatory framework may be insufficient for ensuring a fair

resolution in the event of leakage damage to human health or private property. 

§ Currently, CO2 has not yet been classified as a pollutant or a hazardous substance. If

embedded CO2 is not classified as such, then federal environmental statutes may lose 

6 CWA § 101 

7 Elizabeth Wilson and Mark de Figueiredo. “The Impact of Liability on the Adoption and Diffusion of 

Carbon Capture and Sequestration Technologies,” page 6.

8

545 U.S. 469 (2005).
4

protection from CO2 leakage damage, since these laws were created to assess and 

assign responsibility for damage from hazardous substances. However, CO2 could 

ultimately be classified as a pollutant, especially if large-scale implementation of 

CCS leads to negative impacts on environmental media. This classification would 

have a significant legal impact and would likely increase the costs associated with

CCS activities.

§ There is uncertainty in the governance of the Comprehensive Environmental 

Response, Compensation, and Liability Act (CERCLA) over private property damage 

cases that are caused by sequestered CO2. No carbon injection subsurface trespass 

legal precedents exist, and there is scientific uncertainty of embedded CO2 impacts.

§ If the CCS process causes a release or substantial threat of a release of any pollutant 

that may present an imminent and substantial danger to the public health or welfare, 

liability will likely attach under CERCLA.

9

§ If area-wide contamination is the result of CCS activities, potential parties could be 

held liable under CERCLA. To the extent that specific provisions of the CWA and 

the Safe Drinking Water Act (SDWA) are incorporated into the applicable or relevant 

and appropriate requirements (ARARs), those standards could then govern the 

remedial activities of a CERCLA cleanup. 

§ In the case that CCS results in collateral damage to natural resources, responsible 

parties could be made liable under the Natural Resources Damage Assessment 

(NRDA). 

§ The existence of citizen suit provisions, especially with respect to water laws in the 

Western U.S., introduces another level of uncertainty because any regulatory balance 

can be altered by a citizen bringing suit because of a lack of prosecutorial diligence, 

whether actual or perceived.

§ In nuisance tort cases or other grievances related to CO2 leakage, the potentially 

responsible parties under CERCLA are unclear. Federal and state government

regulators, carbon injection operators, and public power generators of CO2 may all be 

candidates for some portion of liability under the “joint and several liability” 

provision in the CERCLA statute’s “cradle to grave” liability scheme.

§ There may be legal difficulty in assigning responsibility for seismic disruption 

damages caused by carbon injection due to scientific uncertainty and lack of a legal 

precedent.

§ In the case of natural seismic action leading to future CO2 leakages, assigning liability 

based on fault may be impossible and lead to difficulty in handling the resultant 

damages.

Long-Term Stewardship and Liability

Assignment of liability associated with leakage and migration of CO2 deposits and 

resulting public health or environmental impact is further complicated by the extended

time frame of carbon storage, which may exceed the lifespan of industry participants.

For example, determining which party is responsible for the CO2 monitoring at a power 

plant after the plant is decommissioned or retired is difficult.

§ The existing legal framework for EOR carbon sequestration has insufficient 

long-term storage and monitoring controls for large-scale CCS projects. 

9 CERCLA § 104
5

§ The continuous existence of a viable entity is questionable under the current legal

framework. It is still an open question whether long-term liability should rest with a 

public or private entity. To ensure the future economic burden associated with the 

CCS site will not rest on the public as a whole, issues of long-term stewardship, land 

use controls, and data tracking will need to be addressed.

§ Assignment of liability in CO2 releases is especially difficult if the companies that 

managed the injection and monitoring no longer exist or if they utilize subsidiaries to 

limit liability.

§ Additional research is required to improve scientific knowledge of carbon storage, 

which would help to inform the liability debate.

§ Plugged CCS injection sites will require effective long-term stewardship performed 

by a government or private entity. A detailed framework must be firmly established 

in the U.S. Environmental Protection Agency’s (EPA) Underground Injection Control 

Program, which provides governance for CO2 injection under the SDWA.

10

§ Although geologic sequestration currently meets the statutory definition of 

“underground injection” in section 1421(d)(1) of the SDWA, EPA is currently 

evaluating Department of Energy (DOE) pilot projects to determine if changes to the 

regulations are required for long-term CCS.

§ Since EPA currently has the statutory mandate to protect underground sources of 

drinking water and aquifers, the unknown results of these DOE pilot projects leaves 

legal uncertainty with respect to the future of CCS activities.

Further Research

This white paper is intended as an overview of potential environmental and legal issues 

that could arise in a large-scale CCS operation. It is meant to promote further research

and discussion of these areas before large-scale CCS implementation can provide one of 

the many technological solutions to constraining carbon from existing or future power 

plants. A pressing need for reducing greenhouse gas emissions and halting their effect on 

climate change is driving the current political impetus to institute commercial-level CCS

on a short time frame. However, for commercial CCS to effectively reduce emissions

and mitigate the effects of climate change, a comprehensive plan and effective regulatory

framework that respect potential obstacles and adverse impacts are essential.

Technical and economic barriers to implementing commercial-level CCS are substantial,

but they are also currently under significant scrutiny. The legal and environmental 

challenges of CCS should be analyzed and addressed with similar vigor in order to 

promote effective and sustainable practices in the United States. Research on these 

aspects will inform cost-benefit analyses of CCS in relation to other methods being 

developed to mitigate climate change, allowing for optimal distribution of public and 

private resources.

10 Testimony of Acting Assistant Administrator William Wehrum and Assistant Administrator Ben 

Grumbles, U.S. Environmental Protection Agency. Subcommittee on Energy and Air Quality, United States 

House of Representatives, 6 March 2007.
6

Marianne L. Horinko is the Executive Vice President of the Global Environment & 

Technology Foundation (GETF). Prior to joining GETF, she served as Assistant 

Administrator for the Office of Solid Waste and Emergency Response (OSWER) at the 

U.S. Environmental Protection Agency from 2001 to 2004, and Acting EPA 

Administrator in 2003. She led the emergency responses to the 9/11 attacks, anthrax 

contamination, and the Columbia Space Shuttle disaster. She brought new approaches to 

environmental protection using partnerships, flexibility, and innovation. The 

Brownfields program, signed into law by President Bush in 2002, embodies these goals. 

During the first Bush Administration, Ms. Horinko was Attorney Advisor at EPA. 

Subsequently, she served as President of Clay Associates and practiced environmental

law at Morgan, Lewis & Bockius, a national environmental policy firm, where she 

assisted in the creation of the RCRA Policy Forum. She graduated from the University of 

Maryland (analytical chemistry) and Georgetown University Law School.

GETF is a 501(c) (3) not-for-profit foundation that works with government, industry, 

academia, and non-governmental organizations to advance sustainable solutions and 

practices that promote environmental stewardship. 
1

Carbon Capture and Storage From Coal-based Power Plants:

A White Paper on Technology

for the American Public Power Association (APPA)

L.D. Carter

May 22, 2007

Introduction

Technology for carbon capture and storage (CCS) from coal-based electric 

power plants is rapidly emerging. The component technologies for capture and 

transport exist, although they are relatively costly compared to other emission 

control systems (increasing the cost of electricity by over 60%). Technologies for 

injecting carbon dioxide (CO2) into partially depleted oil reservoirs have been 

used for enhanced oil recovery (EOR) in the U.S. for over 30 years. Similar 

techniques have been used since 1990 to inject CO2 into saline reservoirs in 

Canada, in association with oil and natural gas processing1. Additionally, a 

limited number of power plants have used chemical sorbents to capture CO2 for 

reuse at very small scale (a few hundred tons per day, or less).

2 However, there 

is no commercial experience with commercial scale power plants capturing and 

storing large quantities of CO2 in geologic formations. Additionally, there is no 

existing regulatory framework that adequately addresses one unique feature of 

carbon storage: it must be permanent to be effective. 

The challenge facing industry, and the regulatory community, is to address the 

technical gaps in integration of the technologies at hand, move aggressively with 

research and demonstration projects to significantly reduce the cost of more 

advanced carbon-controlled systems, build an improved understanding of the 

long-term behavior of CO2 stored underground, and craft a pragmatic risk 

management framework for conducting CO2 storage. Increasing the difficulty of 

this challenge is the fact that all of this must be done simultaneously, with limited 

resources, and at a time when continuous construction of new power plants is 

necessary to supply a healthy and growing economy.

1 Overview of Acid-Gas Injection Operations in Western Canada, S. Bachu, Alberta Energy and 

Utilities Board, Edmonton, Canada, http://uregina.ca/ghgt7/PDF/papers/peer/588.pdf .

2

For example: Kerr-McGee/ABB Lummus Crest Process using MEA (Mono-Ethanolamine), 

Fluor Daniel ECONAMINETM MEA process, Kansai Electric Power Co. / Mitsubishi Heavy 

Industries, Ltd. (KEPCO/MHI) process using KS-1, KS-2, and KS-3 solvents. Source: Carbon 

dioxide Capture and Storage, IPCC, 2005, p.116.
2

This paper will discuss the status of technology to capture CO2 both from

combustion-based and gasification-based power generation fueled by coal, and 

technologies to transport and store CO2 in underground (geologic) formations. 

This paper is not intended to be a technology treatise, but rather to draw from the 

work of others to present decision-makers in the utility sector and the regulatory 

sector with an overview of what is practical today and what is possible in the near 

future.

CO2 capture from combustion-based coal power plants

Two CO2 capture approaches are receiving strong interest for application with

combustion-based power plants. The first is based on absorption of flue gas CO2

by an aqueous solvent. CO2 concentrations in flue gas are modest, 12-15%, due 

primarily to presence of significant amounts of combustion-air nitrogen, and to 

“excess” air needed to ensure complete combustion of coal. For these 

concentrations, chemical sorbents have been shown to be effective at separating 

CO2 from the other flue gases, and releasing it in a concentrated stream for 

further processing. Figure 1 presents a diagram of a conventional pulverized 

coal power plant, equipped with such a CO2 “scrubber”. Possible solvents 

include a family of amine chemicals, which are molecular “cousins” to ammonia; 

proprietary solvents designed specifically to capture CO2, such as “KS-1” solvent 

from Mitsubishi Heavy Industries; and advanced solvent concepts, such as 

chilled ammonia. For these chemical solvent-based capture systems, the CO2 is 

captured in an absorption vessel (amines typically operate at 50 oC (120 oF)). 

The CO2-enriched sorbent is then pumped to a second vessel and heated to 

about 120 oC (250 oF) to drive off a concentrated stream of CO2 and regenerate 

the lean solvent. The concentrated CO2 is dried and compressed to about 2200 

psia for pipeline transport in a supercritical state to a site for use or storage. 

Parasitic power needs are substantial and include pumps, fans, solvent 

regeneration, and CO2 compression. In addition, the CO2 solvents tend to form 

“heat stable salts” with any remaining SO2 or NOx in the flue gas. These stable 

salts do not break down in the solvent regenerator, so there is loss of solvent 

unless SO2 and NOx are reduced to extremely low concentrations. These factors 

combine to lead to a 25% increase in fuel consumption per kilowatt-hour 

generated, and increase cost of electricity by over 60%.3

Looking to the future, an absorption process using ammonia is under 

development by Powerspan, and will be tested on a slipstream from First 

Energy’s 50 MW Burger plant in 2007 and 2008. Alstom and EPRI will test a 

chilled ammonia system at a 5 MW scale at WE-Energy’s Pleasant Prairie station

in 2007. AEP has signed a memorandum of understanding to test the 

technology at the Mountaineer Plant in West Virginia in 2008, and if successful, 

at the Northeastern Station in Oklahoma in 2011, for use with enhanced oil 

3 Carbon Dioxide Capture and Storage, IPCC, Chapter 3, 2005.
3

recovery.4 Ammonia is lower cost, has higher levels of CO2 absorption, and 

requires less energy for regeneration than currently used chemical solvents, so 

success in these technologies could reduce the cost and energy penalty of CO2

capture at conventional power plants.

Oxy-combustion is a second approach to capturing CO2 from pulverized coal 

power plants, and takes a radically different approach than CO2 absorption. With 

oxy-combustion, the coal is burned with pure oxygen, not air, so the products of 

combustion are primarily CO2, water vapor, and some excess oxygen (see Figure 

2). To moderate boiler temperatures to about 1900 oC (3450 oF), it is necessary 

to recirculate a portion of the flue gas CO2 (downstream of the particulate matter 

control system) back into the boiler. Particulate matter must be removed as 

usual, but nitrogen oxide formation is very low so the traditional selective catalytic 

reduction (SCR) system is unnecessary. The SO2 system can be significantly 

downsized because it does not process the flow of excess air or nitrogen 

normally encountered with air-based combustion. The CO2 capture system 

consists essentially of gas drying and compression, although some additional 

gas purification may be needed. This design approach can take advantage of 

higher temperatures and improved heat transfer from CO2/H2O mixtures to allow 

a more compact (cheaper) boiler. Parasitic energy demands are high (e.g., 

25%), because of the oxygen plant and CO2 compression. None of these 

systems has been operated at a commercial scale, although most of the 

component technology is commercially available.

Looking to the future, AEP has announced its intent to conduct a pilot 

demonstration of oxy-combustion in Summer 2007, followed by retrofit to an 

existing commercial coal-fired unit by 2015.5In addition, DOE is working with Air 

Products and Chemicals, Inc., to develop an Ion Transport Membrane approach

for producing oxygen, to replace the conventional cryogenic oxygen plant, 

thereby reducing the cost and energy required for oxygen production.6

CO2 capture from IGCC

A different approach to CO2 capture is associated with Integrated Gasification 

Combined Cycle (IGCC) power plants. In a conventional IGCC, coal is gasified 

to produce synthesis gas (primarily hydrogen, carbon monoxide, and carbon 

dioxide), which is then treated to remove contaminants and burned in a 

combustion turbine, which drives a generator to produce power. Hot exhaust 

gases from the combustion turbine are moved through a heat recovery steam 

generator to produce steam, which is expanded through a steam turbine and 

4 Corporate Citizenship, the role of technology, AEP news release, 

http://www.aep.com/citizenship/crreport/climatechange/theroleoftechnology.asp .

5

Ibid.

6 Development of Ion Transport Membrane Oxygen Technology for Integration in IGCC and Other 

Advanced Power Generation Systems, NETL project factsheet #136, May 2006, 

http://www.netl.doe.gov/publications/factsheets/project/Proj136.pdf .
4

generates additional power (hence, the term “combined cycle”). Rather than 

capture the CO2 at the end of this process, in an IGCC CO2 is captured prior to 

combustion of the synthesis gas. This is possible because the synthesis gas can 

be reacted with water in a catalytic “shift reactor” to convert most of the carbon 

monoxide to hydrogen and CO2. This leaves a modified synthesis gas consisting 

largely of hydrogen, water vapor, and CO2, still under the relatively high pressure 

created in the gasifier. CO2 is much easier to separate in this concentrated, 

pressurized state, than in normal flue gas. Following H2S removal, a physical 

solvent process, such as Selexol, can be used to separate the CO2 from the 

hydrogen. The CO2-rich solvent is then pumped to a separate vessel where 

concentrated CO2 and lean solvent are regenerated by a reduction in pressure, 

rather than by the addition of heat as with chemical sorbents (see Figure 3). The 

hydrogen (instead of CO-rich syngas) is burned in a combustion turbine, and 

waste heat is used to generate steam which generates additional power, similar 

to an IGCC without CO2 capture. The inherent advantage of this power 

generation approach is that the CO2 capture system uses much less parasitic 

power, and costs less than systems designed for pulverized coal power plants. 

The inherent disadvantage is that the basic IGCC system (without CO2 capture) 

remains a relatively immature technology, and costs more than comparably sized 

pulverized coal system without CO2 capture. For example, Duke Energy 

estimates the capital cost of its proposed Edwardsport, Indiana, IGCC to be 

$1.985 billion for the 630 MW facility, or over $3000/kw.7These costs are 

substantially higher than recent government reports which projected costs for 

such systems.8 Complicating this high capital cost is the fact that none of the 

four existing coal-based IGCCs has met its original design reliability goal with 

coal. In addition, high-efficiency combustion turbines fueled by hydrogen have 

not been commercially demonstrated.

It may be possible to reduce the cost of CO2 capture from IGCC systems, and 

use generation systems that do not require a hydrogen turbine, by capturing less 

than 90% of the plant’s CO2. For example, DOE’s most recent analysis of IGCC 

gasifiers indicates that the GE system converts about 30% of the coal carbon into 

CO2 in the synthesis gas (the rate for the ConocoPhillips design is about 25%, 

and the Shell system analyzed was much less).

9

This CO2 could be captured at 

lower cost and with much less disruption to the overall plant design that a system 

including a shift reactor. Alternatively, the gas could be partially shifted, lowering 

the cost of the shift reaction, and probably leaving enough CO in the syngas to 

enable use of demonstrated combustion turbines, at the sacrifice of high rates of 

CO2 capture. However, neither of these systems has been commercially 

demonstrated, or even well developed in published technical papers providing 

7 Edwardsport IGCC FEED Study Report, (Redacted Copy), Duke Energy, as filed with the 

Indiana Utility Regulatory Commission, 2April2007.

8 Cost and Performance Baseline for Fossil Energy Plants – Updated Technical Performance, 

DOE/NETL, 10April2007, http://www.netl.doe.gov/technologies/coalpower/refshelf.html .

9

Ibid.
5

detailed design or cost estimates. And neither would appear to overcome the 

basic cost and reliability issues associated with IGCCs without CO2 capture.

A number of developments that are underway are intended to make IGCC both 

more reliable and affordable. These include improved refractory, for 

refractory-lined gasifiers, which should reduce the outage time for rebricking, as 

well as allow higher gasifier temperatures, which will help carbon conversion; 

lower cost oxygen production processes (see above discussion of Ion Transport 

Membranes); warm gas H2S cleanup, which allows efficiency improvements; 

dry-feed coal “pumps” for gasifiers to replace lock-hopper approaches, and 

possibly, slurry feeds; and R&D on hydrogen fueled combustion turbines.

Several of these improved system components should be ready for commercialscale demonstration on the FutureGen system, which is scheduled to begin

operation in late 2012.

CO2 transport

Quantities of CO2 on the scale of a coal-fired power plant’s production (3 million

tons per year for a 500MW unit) will almost certainly be transported by pipeline

unless injection occurs at the plant site. For pipeline transport, CO2 is 

pressurized to a supercritical state that has the low viscosity of a gas, and yet 

can be efficiently pumped like a liquid. Because of the extensive use of CO2 for 

enhanced oil recovery, CO2 pipelines are a mature technology, and have been 

operating reliably in the U.S. for over 30 years. There are over 1500 miles of 

CO2 pipelines in the U.S., transporting over 50 million tons of CO2 per year. For 

example, the Weyburn pipeline carries 5000 tonnes per day of CO2 (96% CO2

and 0.9% H2S) for 200 miles between the Great Plains Synfuels plant in North 

Dakota and the Weyburn EOR project in Saskatchewan, Canada. Although CO2

is considered an “acid” gas, as long as the flow is kept moisture free, standard 

carbon-manganese steels can be used for pipelines.10 It should be noted that 

different states have different constraints on the concentrations of non-CO2

gases permitted in CO2 pipelines.

Pipeline transport cost is generally not a major component of overall capture, 

transport, and storage costs. However, pipeline costs vary by the size of the 

pipeline with significant economies of scale. For example, transport via a 150 

mile pipeline for CO2 from a 500 MW power plant (about 3 million TPY) is 

estimated to cost about $3.00 – 5.00/Tonne CO2, whereas transport for a 2,000 

MW facility would cost about $1.40 – 2.10/Tonne CO2.

11 An important issue 

related to pipelines is obtaining right-of-way for the pipeline. Additional 

legislation may be needed to ensure the ability to construct CO2 pipelines 

(eminent domain).

10 Op.Cit., IPCC 2005, p.182-3.

11 Op.Cit., IPCC 2005, p. 192; figures are in 2002 dollars.
6

CO2 storage

A number of options are available for CO2 storage. Figure 412 presents several 

of these options, including storage in depleted natural gas or oil reservoirs (which 

can involve EOR), storage in deep saline structures, and use for enhanced coalbed methane production. It appears that those storage options that provide a 

“rebate” on storage, such as EOR, will be insufficient to meet the storage 

requirements of a program requiring industry-wide capture and storage of CO2.

Additionally, power plants must compete with other, lower cost sources of CO2, 

such as CO2 produced from underground deposits, or CO2 from natural gas 

processing plants. Most CO2 currently used for EOR in the U.S. is from 

underground deposits, and most of the remainder is from natural gas processing 

plants. However, it also appears that, at least in the U.S., additional saline 

reservoirs will be adequate to handle storage needs for hundreds of years of 

emissions.

13 An important caveat on storage is that the needed geological 

storage formations are not evenly distributed throughout the U.S. Figure 5, taken 

from DOE’s Sequestration Atlas, shows the distribution of deep saline

formations.

14

In general, the process for injecting CO2 into geological formations is well 

understood, having been used for approximately 90 EOR projects worldwide, 

which cumulatively store about 40 million tonnes per year of CO2 (compared to 

about 3 million tons per year (TPY) of CO2 from a single 500 MW coal-based 

power plant).15 The key features separating CO2 injection for long-term storage 

versus CO2 injection for EOR are:

§ CO2 retention is not the primary goal for EOR operations. EOR operations 

focused on maximizing CO2 retention would likely follow different 

procedures.

§ With EOR operations, an impermeable caprock is likely associated with 

the oil deposit. In saline formations, the presence of caprock is presumed 

if the site is being considered for storage, but the integrity of the caprock 

has not been established by its ability to retain oil or natural gas over 

hundreds of thousands of years.

§ In EOR situations, the operator’s liability generally ends with the 

decommissioning of the injection well, as demonstrated by the return of 

surety bonds held by state agencies to assure remediation in the event of 

a leak.

Leakage of CO2 from a properly designed and operated storage facility is 

considered unlikely. The IPCC concluded that “it is considered likely that 99% or 

12 Op.Cit., IPCC 2005.

13 Carbon Sequestration Atlas of the U.S. and Canada, USDOE/NETL, March 2007.

14 Ibid.

15 Discussion Paper For 2nd IEA/CSLF Workshop on Legal Aspects of Storing CO2 (draft), 

International Energy Agency, 17October2006.
7

more of the injected CO2 will be retained for 1000 years.”16 However, if leakage 

occurs, it can be a serious matter. Figure 6 displays various pathways by which 

CO2 can escape storage.17 The most commonly stated concern is leakage via 

existing oil or gas wells that might penetrate the caprock near the CO2 injection 

site. It is commonplace in oil producing regions to “discover” wells long since 

abandoned and forgotten. Mitigation is straightforward: plug the well at a cost of 

$15,000 - $25,000. 

Although relatively low concentrations of CO2 are essential for the support of 

plant life, concentrations over 50,000 ppm have been shown to cause impairment 

of mental processing, and death is possible from exposure to concentrations 

exceeding about 10% CO2. Volcanic leaks leading to soil root concentrations of 

20-30% CO2 have killed trees at Mammoth Mountain, California.18 If CO2

escaped a deep saline reservoir, it might also migrate into a more shallow fresh 

water aquifer, and there is concern that the acidic nature of CO2 could mobilize 

metals that would harm such aquifers. It should be noted that no leakage or 

safety incident has been reported for the Canadian acid gas injection program, 

which has been operational since 1990.19

The FutureGen project implemented a comprehensive above ground and below 

ground site analysis for all sites being considered for the project.20 Three types 

of criteria were considered:

§ Qualifying criteria, which were required to be fully met.

§ Scoring criteria that involve a numerical evaluation, but did not have to be 

met 100%. There were 261 such criteria.

§ “Best value” criteria, which were non-quantitative, but important to the 

goals of the project.

This type of comprehensive analysis is a useful template for the next generation 

of CO2 storage projects. Site selection will follow an extremely cautious 

approach until much more experience has been gained with this technology.

In a report on regulatory needs related to carbon capture and storage (CCS), the 

Interstate Oil and Gas Compact Commission (IOGCC) concluded that most 

aspects of CCS were adequately addressed by existing regulatory frameworks, 

but that post-injection monitoring and risk management needed additional 

attention.21

16 Op.Cit., IPCC, p.197.

17 Op.Cit., IPCC, p. 243.

18 Lessons Learned from Natural and Industrial Analogues for Storage of CO2 in Deep Geological 

Formations, S. Benson, et.al., Lawrence Berkeley National Laboratory, March 2002.

19 Op.Cit., Bachu.

20 Results of Site Offeror Proposal Evaluation, FutureGen Alliance, 21July2006.

21 Carbon Capture and Storage: A Regulatory Framework for States, Interstate Oil and Gas 

Compact Commission, January 2005.
8

EPA has issued guidance applicable to pilot-scale CO2 injection projects, such as 

those being conducted by the DOE Regional Partnerships program. However, 

the guidance was clear in stating that it did not extend to commercial-scale 

projects, and implied that projects storing both CO2 and other materials like SO2

or H2S would face additional, unstated requirements.22 It is reasonable to expect 

that EPA will eventually adopt regulations governing CO2 injection for non-EOR 

purposes, probably under the Underground Injection Control (UIC) program. 

Until then, however, commercial scale projects will be regulated on a case-bycase basis, using current UIC regulatory authority. One can assume an 

abundance of caution will accompany early commercial projects, which could 

impact both the cost of the storage project and the time needed for obtaining 

necessary permits.

It should be noted, particularly in light of the IOGCC report, that there is no 

existing legal framework within which to address the long-term liabilities 

associated with CO2 storage. The timeframes for storage integrity exceed 

normal life cycles for corporations, and insurance instruments for such long 

periods have no “actuarial” basis for calculating appropriate fees. It seems likely

that this gap will have to be filled, probably by a system of sharing liability 

between the private and public sector, before most entities will be willing to 

embrace non-EOR CO2 storage projects.

Costs

We are in a period of rapid cost changes for major construction projects such as 

power plants. Therefore, any generic cost estimate must be taken as 

establishing an approximate value. The following capture cost estimates are 

taken from an April 2007 DOE/NETL report23; pipeline and injection costs are 

taken from an IPCC report24, and adjusted to 2007 dollars using the Chemical 

Engineering plant cost index.

§ Capture and compression, new IGCC: $30-40 $/tonne CO2 avoided.

§ Capture and compression, new SCPC w/ amine scrubber: 69 $/tonne 

CO2 avoided

§ 150 mile pipeline, 12 million tonne per year capacity (~ 2000 MW): 1.80 –

2.70 $/tonne CO2. Costs per tonne approximately double for a pipeline 

capacity of 3 million tonne per year.

§ Injection: Saline formation, 0.50 – 5.80 $/tonne CO2

§ Injection: Depleted oil field, 0.65 – 5.20 $/tonne CO2

§ Injection: Depleted gas field, 0.65 – 15.70 $/tonne CO2

22 Using the Class V Experimental Technology Well Classification for Pilot Geologic 

Sequestration Projects – UIC Program Guidance (UICPG #83), From C. Dougherty & B. McLean 

(EPA HQ), to Water management Division Directors and Air Division Directors, EPA Regions I-X, 

1March2007.

23 Op.Cit., DOE/NETL 2007, p.36.

24 Op.Cit., IPCC 2005, p.192, 260.
9

The approximate value of CO2 purchased for EOR might range from

1-2 $/thousand standard cubic feet, or about 18-36 $/tonne CO2, and varies

with the price of oil.

Several caveats are essential for proper interpretation of these cost estimates. 

1. It must be emphasized that they apply to a new facility, where there is 

freedom of design. Retrofitting would amplify costs not only due to space 

limitations, less likelihood of proximity to storage geology, and generally 

lower “beginning” plant efficiency (which exacerbates the impacts of 

parasitic power consumption), but also due to hardware issues such as 

the inability to easily extract steam for CO2 sorbent regeneration. 

2. The apparent lower cost of capture from IGCC, compared to SCPC, is 

significantly offset by the higher cost of the IGCC system without capture, 

compared to SCPC without capture. If both systems with capture are 

compared to a SCPC system without capture, the overall impact of 

capture and pressurization (without the transport and injection) is typically 

in the range of a 60-70% increase in the levelized cost of electricity. 

3. The DOE estimates are for bituminous coal-based systems. Most studies 

conclude that capital costs are higher for both IGCC and SCPC systems 

on subbituminous coals, but the increase is greater for IGCC units. 

4. One should not assume that power plants built near old oil or gas fields 

will enjoy a large “rebate” from CO2 sales for oil or gas recovery. A 

number of existing industrial processes produce voluminous supplies of 

relatively pure CO2 which are already separated from other gases.25

Probably most important, is the fact that no power plant in the world has 

demonstrated CO2 capture, transport, and storage in saline reservoirs. Such 

demonstrations are several years away. Pieces of the puzzle have been solved, 

but no one has yet assembled the entire puzzle. Moreover, it would seem very 

prudent to take the time to evaluate the technology at commercial scale before 

embarking on large scale deployment, regardless of how the costs look.

It is very likely that additional RD&D will reduce the cost of CO2 capture and 

compression, perhaps significantly. However, pipeline and injection systems use

relatively mature technologies and are not likely to enjoy such declines over time. 

25 Natural gas processing plants, for example, often process raw gas that is too high in CO2 for 

sale to pipelines, so the CO2 is separated and vented to the atmosphere. As noted earlier, this 

gas is available and much cheaper to capture than CO2 from power plants, and natural gas 

processing plants are usually in the vicinity of gas and oil fields. It is not coincidence that most of 

the CO2 now used for EOR that is not from natural deposits comes from natural gas processing 

plants. In a carbon constrained world, it is reasonable to assume that these processes will need 

to find storage for their emissions, and that the value of CO2 will drop as more emitters seek to 

sell their CO2.
10

Summary: Key issues requiring additional attention

With respect to CO2 capture from coal-based power plants, the major issues are 

technology integration and costs. CO2 capture from conventional power plants 

has occurred only at a very small scale (a few megawatts), and without 

integration with storage systems. Integration requires development of systems to 

address malfunctions in the carbon capture/compression/transport/or storage 

system. Cost barriers at new conventional pulverized coal power plants suggest 

that much cheaper sorbent systems, or lower cost oxygen production systems 

will be needed to avoid a major increase in power costs. Retrofit systems 

present additional issues that exceed the scope of this paper.

For gasification-based systems (IGCC), the major challenges are the relatively 

high cost of the IGCC itself, absent CO2 capture, and concerns regarding 

reliability. In addition, for 90% CO2 capture, the resulting fuel for the combustion 

turbine will be almost all hydrogen, and high efficiency combustion turbines 

fueled with hydrogen have not been commercially demonstrated.

Transport and injection of CO2 are relatively mature technologies. But we have 

very limited experience with the fate of CO2 injected in non-EOR applications at 

rates of 3 million TPY or more (comparable to a 500 MW coal-based power 

plant). We will need several multi-year research projects, at commercial scale, in 

which injected CO2 is carefully monitored, to gain the necessary understanding of 

what happens to such CO2 volumes over long periods of time. And it must be 

emphasized that not all areas of the U.S. are proximate to attractive storage 

formations.

As a final caveat, it should be noted that people often fear what is not well 

understood, and CO2 storage is not well understood by the general population, or 

by government bodies that regulate power plants. It would not be particularly 

challenging for groups opposed to coal use in general to generate public 

opposition to plants pursuing CCS technology, or unexpected for regulators to 

impose overly onerous requirements in an abundance of caution. The next few 

years will be a critical period during which we must both exercise due caution 

and yet embrace projects that will develop commercial scale knowledge about 

these technologies. Aggravating this situation is the lack of a system to manage 

CO2 storage sites decades after injection has been completed. The most 

obvious solution to this social/regulatory barrier is to immediately develop an 

interim regulatory plan, covering a limited set of pioneer plants that are injecting 

large volumes of CO2, to apply until we can generate the data needed to support

a permanent regulatory framework for broad deployment of this technology.
11

About the author – Doug Carter is an independent consultant on 

energy technology and related environmental issues. His current 

practice focuses on advising clients regarding advanced coal-based 

technologies and their potential role in mitigating global climate 

change. Mr. Carter’s resume includes 25 years with the U.S. 

Department of Energy, where he was Director of the Office of 

Planning and Environmental Analysis, within the Office of Fossil 

Energy. He had previously served with the Office of Enforcement 

and Office of Air Quality Planning and Standards at the U.S. 

Environmental Protection Agency. Mr. Carter holds degrees in 

Mechanical Engineering and Environmental Engineering. He can 

be reached at Carter2250@comcast.net .
12

Figures

Figure 1. Conventional PC with post-combustion capture.

Figure 2. Oxy-combustion system with CO2 capture.

Boiler

PM

removal

(FF or ESP)

Sulfur 

removal

(FGD) 

AH

2

Flyash

Recycle

CO2

Scrubbers

Steam 

Turbine

Sulfur

By Products

Generator

Stack

Drying &

Comp.

Electric

Power

Coal

& 

Air

Sequestration

Ready CO2 

CO2 Capture

NOx

Removal

(SCR)

Condenser

Boiler

PM removal

(FF or 

ESP)

Sulfur

(FGD)

AH

2

Flyash

Recycle

Condenser

Coal

Steam Turbine

Sulfur

By Products

Solid

By Products

Generator

Flue Gas 

Recycling

Air 

Separatio

O

Air

Electric

Power

Sequestration

Ready CO2 

Drying &

Comp

CO2 Capture

NOx

Removal

(SCR)
13

Figure 3. IGCC power plant with CO2 capture.

Figure 4. CO2 storage options.

Coal

Gasifier

Slag/Fines

Steam

Cryogenic 

Oxygen

Particulate 

Removal

Steam

Combustion Turbine & Gen

Air HRSG

Electricity

Stack

Water

Solids

Pure 

Sulfur

Compressor

CO2

Shift 

Reac

tor

H2

Steam Turbine & Gen

CO2 Capture

CO2

Rem

oval

Sulf

ur 

Rem

oval
14

Figure 5. Deep saline formations in the U.S. and Canada. (Formations are 

depicted in dark blue)

Figure 6. Potential pathways for CO2 leakage.
Will Water Issues/Regulatory Capacity

Allow or Prevent Geologic Sequestration

for New Power Plants?

A Review of the Underground Injection Control Program and 

Carbon Capture and Storage

Authors:

Jonathan Gledhill, Policy Navigation Group

James Rollins, Policy Navigation Group

Theresa Pugh, Director, Environmental Services, APPA

and

American Public Power Association

1875 Connecticut Ave, NW

Suite 1200

Washington, DC 20009-5715
and 1

Executive Summary

International concern over global climate change has spurred a search to identify ways to 

reduce greenhouse gas (GHG) emissions. Of the six gases comprising greenhouse emissions, 

carbon dioxide (CO2 – “carbon”) emissions far exceed the other five in the amount emitted.1

The U.S. is considering a number of voluntary options for an 18 percent reduction in CO2

emissions by the year 2012. One technology receiving serious consideration by the 

international agencies, Congress, states, and the Bush Administration is carbon capture and 

storage (CCS) or sequestration2

First the carbon dioxide from a power plant would have to be separated and removed from 

the power plant. Carbon sequestration really refers to the geologic storage in deep 

geological formations below the earth’s surface. Carbon dioxide injection has been used for 

several years in enhanced oil recovery operations. Through government and private 

partnerships, the U.S., through the Department of Energy (DOE), is evaluating the viability of 

long-term CCS by conducting demonstration and validation testing of CCS pilot projects.

APPA supports carbon storage demonstrations through the DOE and FutureGen to determine if 

the injection of CO2 is safe and effective as a mitigation measure. 

The CCS issue is of considerable import to the electricity/power plant sector which the U.S. 

DOE considers to be one of the largest emitters of CO2, accounting for 38 percent of CO2 

emissions among all energy sectors.3

While the U.S. DOE is pushing aggressively to deploy CCS for full-scale commercial use, there 

are a number of technical, regulatory, and policy issues related to long-term CO2 storage or 

geosequestration that remain to be studied and resolved. 

The U.S. Environmental Protection Agency (EPA) has regulatory authority over injection of 

wastes into wells through the Underground Injection Control program (UIC) created by 

Congress under the Safe Water Drinking Act. Congress specifically created the program out of 

concern for the protection of underground drinking water sources. Although the UIC program 

has established five classes to address various injection well activities, the Agency currently 

does not have a regulatory framework by which to regulate CCS activities. U.S. EPA has 

recently issued guidance to assist its regional offices and state regulators with permitting and 

operational decisions related to CCS pilot projects.

The U.S. EPA has classified CCS pilot projects as Class V experimental technology; however, 

the regulatory framework for Class V wells is insufficient to provide the necessary safeguards 

to ensure protection of groundwater sources. Therefore regulators have relied on the 

stringent requirements established for Class I hazardous waste wells, which includes the 

requirement that operators demonstrate no-migration of injection fluids (which would include 

CO2) for a period of 10,000 years.

1 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference 

Document (“NETL Reference Document”), Aug. 2007, at 1-2. See also, Electric Power Research Institute, 

Electricity Technologies in a Carbon-Constrained World, (“Electricity sector is responsible for 1/3 of U.S. CO2

emissions”).

2

Sometimes sequestration is also referred to as geosequestration.

3 NETL Reference Document, at 1-2.
and 2

In summary, there are major limitations in the technical, regulatory, and administrative 

requirements of the UIC program that appear to preclude, in the short term, commercialscale sequestration of carbon in non-oil and gas sites in large parts of the country. These 

limitations are important for utilities and policy officials to evaluate as they consider CCS 

projects. For electric utilities that wish to build additional generation to meet the needs of 

their communities, the challenges include very difficult issues.

APPA recommends that States and Public Utility Commissions consider and investigate the 

several limitations identified in this paper prior to mandating CCS as a part of permit 

approval. APPA also recommends working with the U.S. EPA on the cross-cutting and 

multimedia regulatory issues as the Agency moves forward towards determining the best 

regulatory framework for CCS.
and 3

Introduction

What is the Issue and Why does it Matter to Utilities and Municipal Government?

Policy officials and scientists alike, searching for viable ways to reduce carbon dioxide (CO2)

emissions, have identified carbon capture and storage (CCS) 4as a promising technology. This

technology separates CO2 from emissions of large stationary sources like power plants and 

injects the captured CO2 deep into the earth. Figure 1 gives a simple picture of this 

technology. The Intergovernmental Panel on Climate Change (IPCC) has identified CCS as a 

way of achieving overall reductions in greenhouse gas emissions.5This enthusiasm is shared 

by the U.S. government. The U.S. Department of Energy (DOE) is engaged in research and 

development of various CCS technologies to determine the viability of full scale deployment 

of CCS by the year 2012. The U.S. DOE is leading the Regional Carbon Sequestration 

Partnerships to conduct research and development of CCS and supporting small scale 

demonstration and validation pilot projects to determine the potential of this technology.

Figure 1: Diagram of a Carbon Capture and Storage Operation6

The benefits of reducing CO2 emissions through CCS must be balanced against the potential 

increased risks of groundwater pollution from CCS. Utilities provide water and power to their 

4 Carbon Capture and Storage is also referred to as Carbon Geologic Sequestration.

5

Intergovernmental Panel on Climate Change, Special Report: Carbon Dioxide Capture and Storage, Summary of 

Policymakers, 2005.

6 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Environmental Reference 

Document, Aug. 2007, at 3-53 Fig. 3-22.
and 4

communities and rely on available water supplies to produce power. Utilities are uniquely 

positioned and therefore must understand the potential promise and limitations of CCS. 

The potential trade-offs will tighten in the future as demand increases for power, water, and 

GHG reductions. According to EPA, ground water systems account for 91 percent of the total 

public drinking water systems in the U.S., serving 36 percent of the U.S. population.7 Demand 

for drinking water increases with population growth, number of households, and 

manufacturing. While conservation has reduced this need for some new sources, groundwater 

levels in many parts of the U.S. are declining due to increased pumping.8 Meanwhile, the 

demand for electric is expected to increase by 39 percent from 2005 to 2050,

9

requiring new 

capacity. If new power plants use CCS as some states are considering, underground drinking 

water sources will face pressure from both power and water needs.

The American Water Works Association (AWWA) and the American Public Power Association 

(APPA) commissioned this paper to consider the drinking water and groundwater issues with 

CCS and to identify the regulatory and technical hurdles that might minimize opportunities 

for CCS. More than 1,000 of the nation’s municipalities provide electricity to homes;

businesses and factories also manage many water utilities providing drinking water to 

residential, industrial, and commercial customers.

There are several cautions to assuming a seamless fit between current regulation and CCS. 

First, the existing regulations and regulatory program arose over 20 years ago, long before 

CCS was envisioned. Since CCS does not fit neatly into the existing program for power plants, 

the EPA is still in the process of crafting a regulatory approach. Second, for CCS to have a 

meaningful impact on U.S. emissions, the volume of CO2 to be injected underground will 

dwarf current amounts by 10 to 20 times. While the nation has the ingenuity to tackle this 

challenge, it will require investing in technical skills, data, research, and education both in 

the private sector and in regulatory agencies. Currently, regulatory agencies do not have the 

capacity to review and permit CCS at any significant level. To illustrate this issue, this paper 

reviews the current UIC program, its current implementation, the current regulatory 

framework for CCS, and the skill shortages states and EPA will face if CCS moves toward fullscale implementation. Finally, this paper highlights the major limitations for CCS that power 

plant and water utility managers should consider.

What is Underground Injection?

Underground injection involves the use of simple or complex technology to inject fluids into 

the earth most often for purposes of waste disposal or extraction of fossil fuels and minerals.

Wells regulated by the EPA include common shallow septic tank systems to highly-engineered, 

large volume systems that inject materials more than a mile underground. While shallow 

wells may only dispose of a few gallons per day, large disposal systems may each day pump 

the volume of an Olympic-sized swimming pool. 

7 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006.

8

Source: U.S. Geological Survey at http://ga.water.usgs.gov/edu/gwdepletion.html.

9

Energy Information Administration, Annual Energy Outlook 2007, Feb. 2007, at 82.
and 5

What is the Underground Injection Control (UIC) Program?

Congress and EPA established the legal framework for regulating underground disposal over 30 

years ago. Congress established the UIC program as part of the Safe Drinking Water Act 

(SDWA) of 1974 providing EPA with the authority to regulate underground injection activities 

to ensure the protection of the nation’s underground sources of drinking water. Almost all 

U.S. public water systems rely on some groundwater for drinking water.

10 Congress 

strengthened the regulatory requirements for hazardous waste UIC disposal in 1984. In the 

last 20 years, there have not been significant changes to the UIC program’s legal authority.

Congress intended for the UIC program to be administered by states due to the large number 

of wells and to the tradition of local control and regulation of drinking water. As such, the 

SDWA allows states to submit an application to EPA for primary enforcement or “primacy” for 

each part, or “class,” of the program. EPA can delegate primacy to a state, U.S. territory, or 

a federally recognized Native American tribe. The UIC program may be executed by the EPA, 

the state, or both under four separate scenarios:

1) EPA administers the program for all well classes within a state if the latter chooses not 

to apply for primacy;

2) a state is delegated primacy for all five classes;

3) a state has primacy for Class II (oil and gas) wells only; or,

4) a state has primacy for all classes except Class II oil and gas wells.

EPA has delegated primacy for the entire program to 34 states and three territories, shares 

responsibility with six states, and retains full responsibility in ten states. The ten states for 

which EPA has primacy are: Arizona, Hawaii, Iowa, Kentucky, Michigan, Minnesota, New York, 

Pennsylvania, Tennessee, and Virginia. These states have determined that committing state 

resources to run the program is not a high priority. 

How does EPA Regulate Underground Injection?

EPA established five classes of injection wells (Class I, II, III, IV, and V) under the UIC program 

based upon how the well is used, constructed, and operated.

11 The classes provide a 

consistent way for EPA to apply technical standards to similar activities to ensure the 

protection of underground drinking water and human health.

The classes are ranked by their potential hazard. Class I wells are for the largest volume and 

the most hazardous wastes. Class V wells are for shallow septic systems, dry wells, and low 

volume systems. Most UIC wells are either Class V, Class I, or Class II wells.

All underground injection wells must have a permit. For each class, EPA has established 

minimum technical standards, public participation, and a permitting process review that 

10 See EPA website, http://www.epa.gov/safewater/uic/whatis.html.

11 40 CFR Part 144.6.
and 6

states must include in their permitting process. With approximately 834,000 wells across the 

U.S.,

12 the UIC program is one of the largest environmental permitting programs.

12 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006; 

http://www.epa.gov/safewater/uic/classes.html.
and 7

What are the Five Classes of Injection Wells under the UIC Program?

Class I Injection Wells

Subject to the most stringent regulations, Class I wells include industrial hazardous, 

nonhazardous, and municipal sewage waste. Class I wells inject wastes deep into rock 

formations that are located beneath the lowest underground sources of drinking water13 and 

that are capped by an impermeable rock formation between the injection zone and drinking 

water sources above.

Figure 2: Diagram of Class I Well14

13 Class I hazardous wastes are injected to depths anywhere from 1,700 feet down to 10,000 feet below the earth’s 

surface.

14 U.S. EPA Office of Water, Class I Underground Injection Control Program: Study of the Risks Associated with 

Class I UIC Wells, Mar. 2001, at 11.
and 8

In 1984, Congress tightened Class I requirements by instituting a no-migration standard for 

disposal of hazardous waste via injection and creating a petition process by which operators 

must obtain approval to continue hazardous waste injection operations. Specifically, 

Congress prohibited injection of untreated hazardous wastes unless it is demonstrated that 

the waste has been treated to be non hazardous or unless the waste will not migrate out of 

the injection zone or contaminate drinking water for at least 10,000 years.

15 Because of the 

large volume of wastes injected, Class I injection is economical if it can show a “no 

migration” of the waste. Well operators, filing the petition to operate such wells, must 

accomplish this demonstration by modeling waste behavior underground.16

While there are a total of 529 Class I wells nationwide, there are only 163 Class I hazardous 

waste wells nationwide. Most Class I wells are found in Texas and Louisiana. Class I wells are 

banned in Missouri. The map below shows the location of Class I hazardous waste wells in the 

U.S.

17 As the map below shows, only 11 states have active Class I hazardous waste wells.

15 NRDC v. EPA, 907 F. 2d at 1158

16 RCRA, Section 3004, 40 CFR Part 148 (53 FR 28118). In the final regulations, EPA explained that 10,000 year 

requirement is based on ensuring for long term waste confinement. Specifically, demonstrations that can show nomigration over a 10,000 year period are likely to result in containment for an even longer period of time. 

Additionally, confinement for that period of time can result in waste immobilize due to geochemical 

transformation. 

17 See EPA website, http://www.epa.gov/safewater/uic/classi.html.
and 9

Figure 2: Hazardous Waste Wells in the U.S.
and 10

There are 366 nonhazardous Class I waste wells in 19 states. Nonhazardous Class I waste wells are required to comply with the 

same technical standards as hazardous waste wells. 

Class II Injection Wells

Oil and gas production facilities use Class II wells to inject fluids to pump hard-to-get oil and gas deposits to the surface. The 

recovered crude oil and natural gas comes to the surface mixed with salty water and other impurities. States require 

injection of this salty water underground so as not to pollute drinking water. Class II wells must comply with strict 

construction and operating standards and are often similar in construction to Class I deep wells. There are approximately 

167,000 Class II wells, predominantly found in the southwestern U.S. The map below shows the location of Class II wells in the 

U.S.

18 Twenty-two states do not have any Class II wells.

18 See EPA Website, http://www.epa.gov/safewater/uic/classii.html.
and 11

Figure 3: UIC Class II Oil & Gas Wells in the U.S.
and 12

Class III and Class IV Injection Wells

Class III wells typically involve using injection of fluids to extract minerals. Mining operations 

for salt, sulfur, and uranium rely heavily on injection using Class III wells. Class III wells have 

minimum standards for which operators must comply, including required casing and 

cementing of wells to prevent the migration of fluids into drinking water sources, a 

prohibition on injection of fluid between the outermost casing and well bore, and required 

integrity tests of well casings every five years.

In Class IV wells, hazardous waste is injected directly into or above underwater drinking 

water. Although Class IV wells, like Class V, generally involve shallow wells, EPA created a 

separate class for injection activities that present a heightened risk. Class IV wells have been

banned except in very narrow circumstances.

Class V Injection Wells

Most injection wells in the U.S. are Class V wells with an estimated 650,000 Class V wells in 

the nation.

19 Class V wells inject nonhazardous waste into or above underground drinking 

water and occur in a variety of residential and commercial settings including sewage disposal, 

aquifer recharge, and mineral recovery. Class V wells include advanced systems used by 

industry for wastewater disposal as well as less advanced types found in septic systems,

cesspools, and agriculture drainage wells. 

Injection activities that do not fit into the other classes - like CCS - are called Class V wells.

Experimental technologies that are in the demonstration phase are classified as Class V

injection.

20 Although there are no federal requirements that specifically address Class V 

experimental technology wells, over the years EPA has issued guidance to cover certain

experimental technologies. Notably, EPA issued guidance in 1983 clarifying that technologies 

in the experimental phase which would have otherwise fallen under another UIC programclass based upon well function, may be reclassified into one of the five classes once the 

technology has advanced for commercial use. However, the technology remains under Class V 

until proven for commercial use and it is shown that the technical standards of the other class 

would provide sufficient protection of underground drinking water and human health once the 

new technology is deployed for commercial use. If the technical standards of the other 

classes are unable to provide sufficient protection, the new technology remains under Class V 

until EPA adopts protective technical standards.21

EPA did not establish technical standards for Class V wells until the 1990s. Because of the 

diversity and sheer number of these wells, EPA did not set minimal technical standards for 

Class V wells. Since EPA finished the Class V rule over 10 years ago, EPA has not issued major 

policy changes to the program. 

19 U.S. EPA, Factoids: Drinking Water and Ground Water Statistics for 2005, Dec. 2006.

20 See, Underground Injection Control (UIC) Regulations as amended, 40 CFR Part 146.05(e), Aug. 27, 1981 (46 FR 

43156), and 40 CFR Part 146.03, Feb. 3, 1982 (47 FR 1416).

21 Victor J. Kimm, Memorandum: Appropriate Classification and Regulatory Treatment of Experimental 

Technologies. Ground-Water Program Guidance No. 28 (GWPG #28), May 31, 1983.
and 13

How Does CCS Fit into the UIC Program and Why Does this Matter to Electric Utilities?

Congress and EPA did not envision sequestration of carbon dioxide when they established the 

program for the chemical industry over 30 years ago so no federal regulatory framework exists 

to regulate CCS activities specifically. Yet, EPA has considered how CCS is regulated under 

the UIC program. In 2006 EPA determined that CCS activities are “underground injection” 

and that SDWA mechanisms are sufficient to regulate and to permit pilot projects. As a 

result, EPA issued a directive that CCS pilot projects are to be permitted as Class V 

experimental technology wells.22 This policy directive might be supplanted by an EPA 

rulemaking in 2008.

Since there are no federal requirements governing Class V experimental technology wells, 

there has been a lot of confusion and uncertainty. In March 2007 EPA issued guidance for 

permitting and operation of CCS pilot projects as a Class V experimental technology wells.23

This guidance for CCS pilot projects tries to straddle between the current legal framework 

and the environmental standards necessary to inject a large volume of carbon dioxide safely. 

Legally, EPA confirms that Class V is “the best mechanism for authorizing pilot GS project,”

24

and that Class V general permitting and public participation requirements apply. The permits 

can remain in effect as long as needed to cover the timetable of project goals and may be 

modified or extended to alter the goals or timetable, but cannot exceed state or federal 

permit limits.

As a counterpoint to the flexibility inherent in a Class V permit, the guidance then lays out 

why states should consider more stringent permit conditions in the CCS Class V permit. EPA 

emphasizes throughout the guidance that protection of underground drinking water and 

human health is the overriding concern. EPA lays out a number of considerations for regional 

and state directors to take into account for purposes of permitting and operation, including:

§ Siting considerations;

§ Consideration of the underground area affected by the injection;

§ Injection well construction;

§ Injection well operation and monitoring program considerations; and,

§ Site closure.

UIC program directors are also encouraged to consult with deep well experts including Class I 

and Class II directors to ensure appropriate standards are applied for CCS pilot projects.

However, EPA stops short of recommending CCS pilots have all the features of Class I permits, 

although UIC directors can opt for Class I requirements. The 2007 EPA guidance stresses that 

the primary goal of pilot projects is for EPA, the states, and well operators to collect and 

share data to better understand how CO2 reacts and moves underground, as well as

22 Cynthia C. Dougherty, Letter to State Regional UIC Contacts re: CCS pilot projects, U.S. EPA Office of Water, 

Jul. 5, 2006. http://www.epa.gov/safewater/uic/pdfs/memo_wells_sequestration_7-5-06.pdf

23 UICPG # 83. http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbonsequestration_final-03-07.pdf

24 UICPG # 83, at 6.
and 14

understanding what the risks are associated with CO2 injection. To determine how best to 

manage commercial scale CCS injection operations, the guidance suggests EPA regional and 

state directors adopt a more flexible approach in approving permits and identifying permit 

conditions to allow operators to “achieve project objectives.”25

How have States Regulated CCS Pilots?

EPA and the states have looked to Class I and II regulations for permit conditions for CCS

pilots because of the depth of injection and the larger volume of CO2 injected. Today CO2 is 

currently is being injected to recover oil and gas in wells subject to Class II well 

requirements. Some CCS pilots have occurred in oil and gas formations in Class II wells.26 In 

the few cases to date, states have granted Class V permits for CCS pilots sequestration with 

many – if not all – of the technical requirements for a Class I permit.

What are the Specific Class I and II Technical Requirements? 

The technical requirements for Class I and II wells include siting, well construction, operation, 

reporting, monitoring, permitting, financial assurance, and closure standards. The regulatory 

system is designed to minimize leaks into drinking water formations as waste and fluids are

pumped down through these layers and after they are put underground.

Siting

Class I permits require three separate hydrogeologic investigations to permit a deep injection 

well: reviewing the geology of the area, conducting an area of review study, and finally 

submitting a no migration petition. 

In the geologic study, permit applicants must show that the area is geologically stable; the 

area is not seismically active now and has not had earthquakes in recent geologic time. The 

formation must have suitable room to store the injected wastes and thick enough to dissipate 

the pressure without cracking the confining layer. The geologic study must also show the 

area around the well is free of vertical faults that could allow the injected fluids to migrate 

up to drinking water layers. Finally, the geologic study must also demonstrate that the 

injection layer’s rocks are chemically compatible with the waste. 27

The second study is the Area of Review. In this study, well operators must investigate all 

wells in the area that penetrate the injection or the confining layer. Operators must 

demonstrate that all of these wells are sufficiently capped and closed to prevent migration 

out of the injection layer. Under federal regulations for Class I hazardous waste wells, the 

Area of Review is defined as either a 2 mile radius from the well or to the zone of 

endangering influence on underground drinking water, whichever is a greater distance. 

States require larger Areas of Review; Texas, for example, uses a 2.5 radius for its Area of 

Review. For nonhazardous waste, the Area of Review can be a low as 1⁄4 of a mile.28

25 UICPG #83, at 3.

26 According to U.S. DOE, there are at 75 oil reserve carbon sequestration projects in the following states: 

Arkansas, Colorado, Louisiana, Oklahoma, and Texas. See, U.S. DOE National Energy Technology Laboratory, 

Carbon Sequestration Program Environmental Reference Document, Aug. 2007, at 3-60.

27 U.S. EPA Office of Water, Class I Underground Injection Control Program: Study of the Risks Associated with 

Class I Injection Wells, Mar. 2001, at 18.

28 Ibid, at 19.
and 15

One of the biggest challenges for Class I operators is to demonstrate no-migration of waste for 

at least ten thousand years. This demonstration requires computer modeling, knowledge of 

regional geology, and detailed geologic information of the area around the well. Small faults 

or buried channels can create a connection between deep formations and shallower drinking 

water sources. Injecting fluids also changes the volume and pressure underground, possibly 

activating dormant faults. Permit applicants must also search for abandoned wells that might 

connect the injection zone with upper layers.

Construction 

Operators prevent leaking by wrapping their wells in impermeable casing. Operators of 

enhanced recovery and hydrocarbon storage wells are required to case and cement the wells 

to prevent migration of fluids into underground drinking water. Specific casing and 

cementing requirements are determined by the state on a case-by-case basis; however, as 

part of that process they must take into account injection zone depth, depth of the bottom of 

all drinking water formations, injection pressures, and the nature of fluids to be injected.29

The well has essentially three walls so that breaching one still contains the waste. As shown 

in Figure 4, the injection tubing transports the waste to the injection zone. It is made of 

corrosion-resistant material and it is surrounded by the long string casing. This casing is 

sealed at the bottom by the packer and at the top by the well head. Operators must 

pressurize this space between the long string casing and the injection tubing to monitor for 

and to prevent leaks. Finally, the outermost wall, the well casing, supports the well 

structurally. Operators must maintain mechanical integrity of the well until plugged and 

abandoned.30

29 40 CFR Part 144.28(e)

30 40 CFR Part 144.28(f)
and 16

Figure 4: Diagram of Class I Well Technology31

Monitoring

Monitoring requirements include monitoring of the well and other formations. Class I well 

operators are required to analyze injection fluids to identify fluid characteristics, to use 

continuous recording devices to monitor injection pressure, flow rate, and volume, and to 

monitor for any leaks into drinking water with monitoring wells.32 Operators also minimize 

any leaks by carefully watching injection pressure. If there is a leak in a well, the pressure in 

the well will drop as the fluids escape out of the circumference. Regulations require well 

operators to use continuous recording devices to monitor injection pressure, flow rate, and 

volume.33 To demonstrate mechanical integrity, well operators must show that fluids will not 

31 Source: U.S. EPA website: http://www.epa.gov/safewater/uic/idealwel.html.

32 40 CFR Part 144.28(g)(1). 

33 40 CFR Part 144.26(g)(1). 
and 17

leak while traveling to the well, will not leak out of the well as it is injected, nor move into 

underground drinking water once injected into the deep rock.

34 The UIC program requires 

mechanical integrity demonstrations at least once every five years for both Class I and Class II 

wells.35

Class I operators are also required to develop approved ambient monitoring programs as 

determined by the Program Director to protect against fluid movement out of the injection 

zone. Monitoring programs are based upon a site-specific assessment and must include at a 

minimum annual monitoring for injection zone pressure.36 The Director may also require the 

following as part of the monitoring program:

1) Continuous monitoring for pressure in the aquifer located directly above the 

injection zone;

2) Other site specific data to include information on the position of the waste front 

within the injection zone or water quality;

3) Monitoring of ground water quality of the aquifer located directly above the injection 

zone;

4) Monitoring of ground water quality in the lowest underground source of drinking 

water; and, 

5) Any additional monitoring to determine if there is fluid movement into underground 

sources of drinking water.37

Class II well operators are required to monitor injected fluids to determine how it moves and 

changes while in the injection zone, and the frequency of which is determined in each permit 

based upon site specific criteria.

38 Operators are also required to monitor and record 

injection pressure, flow rate, and cumulative volume, the frequency of which can vary from 

daily to monthly, dependent upon the type of well operations.

39 Well operators must

demonstrate mechanical integrity at least every five years.40

Reporting

Reporting requirements also differ between Class I and Class II wells. Operators of Class I 

wells must submit quarterly reports with the following information: various characteristics of 

the injection fluid, monthly average and minimum and maximum values for injection 

pressure, flow rate/volume, well pressure monitoring well results, and the results of injection 

34 40 CFR Part 146.8

35 40 CFR Parts 146.13 and 146.23. 

36 40 CFR Part 146.13(d)(1).

37 40 CFR Part 146.13(d)(2).

38 40 CFR Part 146.23(b)(1).

39 40 CFR Part 144.28(g)(2); 40 CFR Part 146.23(b)(2).

40 40 CFR Part 144.28(g)(2)(iv); 40 CFR Part 146.23(b)(3).
and 18

well tests.41 Class II well operators are required to submit annual reports providing a 

summary of results from any required monitoring activities.42

Financial Assurance

For now, APPA is not aware of any additional financial assurance programs or systems 

envisioned for CCS. However, the existing law does require that financial responsibility is 

met. APPA has caution about embracing CCS technology and long-term storage or 

geosequestration for new power plants until this financial responsibility issue is better 

understood. To APPA’s knowledge, there has been nothing like this level of financial 

assurance required in the electric power sector for conventional pollution issues and liability 

concerns.

Currently, Class I operators must demonstrate and maintain financial responsibility for each 

well to ensure the operator is financially able to eventually close and abandon the well in 

accordance with an approved well abandonment plan.43 Class I operators have several options 

from which to choose in order to demonstrate financial responsibility.

1) Establish a trust fund in an amount equal to the estimated cost of plugging and 

abandonment;

2) Obtain a surety bond to guarantee payment into a standby trust fund;

3) Obtain a surety bond to guarantee well plugging and abandonment;

4) Obtain a letter of irrevocable plugging and abandonment letter of credit;

5) Plugging and abandonment insurance;

6) Meet financial criteria and obtain a corporate guarantee for plugging and 

abandonment; or,

7) Demonstrate financial responsibility using a combination of options 1, 2, 4, 5.44

Closure

Well operators must submit plans for plugging and abandonment as part of the permit 

approval process. 45 UIC program regulation requires Class I, II, III, and V wells to be plugged 

with cement sufficiently to prevent migration or leakage of the injection fluid. Class I permit 

holders must also monitor groundwater until they can demonstrate that the pressure in the 

injection zone decays to the point where there is no potential to influence underground 

drinking water sources.

46 Class V operators are also required to dispose of any waste, sludge, 

fluids, etc., that are found near the wells.47 Well operators are required to submit a report 

41 40 CFR Part 144.28(h)(1).

42 40 CFR Part 144.28(h)(2).

43 40 CFR Part 144.28(d).

44 40 CFR Part 144.63.

45 40 CFR Part 144.28(c).

46 40 CFR Part 14.28(g)(1)(iii).

47 40 CFR Part 146.10.
and 19

certified as accurate to the Director stating that well abandonment was conducted and 

completed in accordance with the abandonment plan. 

What are the Challenges for Permitting CCS Under the UIC Program for Electric Utilities 

Evaluating CCS Options?

With the international, federal, and state interest in CCS, academic, public interest groups,

and the federal government researchers are promoting the availability of sequestration sites. 

The Department of Energy estimates that North America has the capacity to store all of its 

annual power plant emissions underground. The APPA is very skeptical of DOE’s optimistic 

view because APPA does not believe that hydrological concerns and proximity to transmission 

lines, water issues and other infrastructure needs have been considered. Yet, new electric 

utilities are being asked to respond and to consider CCS as part of new plant design now. 

The APPA is concerned that these studies do not fully consider the technical, regulatory, and 

practical limitations of commercial-scale CCS. The current UIC regulatory program illustrates 

some of the major limitations utilities and policy officials must consider: 

Cost and Space Requirements for CCS at the Power Plant

The DOE estimates that a 300 MW power plan will require 60 acres of land to build and to 

operate the carbon capture technology.48 Constructing the pipeline terminus for C02

compression and transport via pipeline will require an additional 20 acres of land. DOE 

further estimates that carbon capture will consume 0.5 millions of gallons of water per day 

and over 15 megawatts of power or approximately 0.8 MGD per day for a 500 MW power 

plant. If utilities do not have readily available land and water, and can afford the costs of 

excess generating capacity, they will face limitations on their ability to construct CCS.49

Uncertainty Concerning Regulatory Requirements

Since EPA is formulating guidance or regulation on CCS and the UIC program, there is 

substantial uncertainty as to the ultimate siting, construction, and other permit 

requirements. If EPA embarks on a rulemaking, a final rule may not be promulgated until 

2012. Once EPA completes its policies, states may enact their own more stringent provisions. 

This uncertainty complicates commercial scale planning for new power plants with coal on 

the drawing board today.

Operators of Class I, II, or III wells are expected to take corrective measures when there is 

noncompliance or malfunction of the injection system, which may include temporary shut 

down and capping of the well. The operators are required to notify the UIC regulatory 

manager within 24 hours of when the operator becomes aware of the problem. Operators are 

also expected to include in their noncompliance report its cause, period of time it occurred, 

actions taken (or are taking) to correct the issue, and plans to prevent recurrence.50 Other 

specific requirements may be established as part of the operators UIC permit. However, the 

difficulty for well operators involved in CCS operations is finding an alternative means of 

disposing CO2 emissions if injection operations must temporarily cease. Operators may have 

to negotiate this issue as part of the well permitting process.

48 NETL report, at 2-44.

49 NETL report, at 2-44.

50 40 CFR Part 144.28(b)
and 20

Limitations on Class I Well Siting

If EPA and states draw upon the criteria for Class I wells for CCS wells, there are regulatory, 

technical, and transportation limitations for CCS that utilities must consider. On a technical 

basis, some areas of the U.S. would be unsuitable due to the relatively increased risk of 

earthquakes, for example. Many of the coal regions of the United States also correspond to 

areas that are relatively geologically active (e.g., areas of Wyoming51). Injection near 

population centers along the West Coast also might be ruled out due to seismic concerns. 

Until the siting criteria are defined, utilities may not be certain whether they can inject 

locally or be required to pipe CO2 hundreds of miles to areas with Class I wells such as the 

Gulf Coast. 

Sheer Size of CCS to Have Meaningful Impact on U.S. GHG Emissions

Another limitation is that the EPA and states may not have the human and financial resources 

to administer an expansion of the UIC program for CCS. Comparing the relative size of CO2

emissions and current underground injection gives some answer to this question. Power 

plants accounted for 2.4 billion metric tons of CO2 emissions in 200652 or approximately 86 

percent of point source CO2 emissions in the U.S.53

By way of comparison, EPA reported that 21.8 million tons were injected into hazardous 

waste wells in 2005,54 less than one percent of the amount of carbon dioxide released. 

Approximately 43 million metric tons of carbon dioxide is injected into wells today for 

enhanced oil and gas recovery.55

If perhaps 10-20 percent of carbon dioxide emissions were captured, the UIC programs would 

need to permit wells injecting masses 10 – 20 times the total mass currently injected for oil 

recovery or for all hazardous waste disposals. This expansion would pose a substantial 

challenge to the existing state permitting systems. APPA remains skeptical that more than a 

slip stream of CO2 can be separated and injected and remains doubtful that a new coal power 

plant (regardless of type) could separate and inject more than 50 percent of the CO2 from the 

plant.

51 http://ga.water.usgs.gov/edu/gwdepletion.html

52 Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World. 

53 Carbon Sequestration Atlas, at 11.

54 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based 

on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5.

55 Source: Advanced Resourced International, 2007.
and 21

Figure 5: Comparison of CCS Volumes to Current UIC Volumes

Injected Material Mass of Material

(mil. Metric tons/year)

CO2 emissions from power plants 2,40056

CO2 in Class II wells for oil recovery 4357

Class I hazardous waste 2258

Regional Carbon Sequestration Partnerships, total 2

Space Requirements for the Injection Well

DOE has estimated that injecting 0.9 million metric tons of CO2 will require a land area of 

over 2,750 acres. This carbon mass is only 40 percent of one year’s generation from a 300 

MW coal power plant with a 90 percent efficient CCS. Using DOE’s estimate, to hold 30 years 

of CO2 captured from a 300 MW boiler, the surface area requirement is over 200,000 acres, or 

312.5 square miles.59 This land choice must also consider load, transmission lines, coal or rail 

access, surface water (used to produce electricity) and conventional air pollution issues such 

as SO2 and NOX. The injection well, observational well and Area of Review (AoR) space issues 

will dictate where the future power plants can be built.

The U.S. DOE’s estimate may significantly underestimate the land area needed. As a gas, 

carbon dioxide is different then diluted wastewaters currently injected in Class I wells. It is 

more buoyant than the underwater fluids and will rise to the top of the injection layer. If the 

injection layer has dips and rises, CO2 will flow to fill in each rise first. In other words, unlike 

current injected fluids, it will migrate via diffusion on its own away from the injection well. 

Like natural gas, it will concentrate in traps miles away from the injection zone. In other 

words, applicants could have areas of review much greater than 2.5 miles currently thought

protective for liquid injection. A study in the saline formations of Texas where there are 

many Class I wells suggests that a formation large enough to store 30 years of CO2 from a 

single power plant could have traps over a 13 mile by 13 mile area.60

A further complication is the difference in property law traditions across the United States. 

In several Homestead laws, Congress gave away land to settlers who stayed upon and 

improved the land. However, the federal government retained the subsurface rights to the 

land, creating “split-estate” properties where the surface owner does not have title to the 

subsurface. Over 20 million acres of land in western U.S. states have split estates between 

private entities and the federal government.61 In other states, the mineral rights have been 

sold to private parties creating split estates between parties. In the eastern U.S., property 

titles typically include surface and subsurface rights. Depending on the state, utilities may 

56 Electric Power Research Institute, Electricity Technologies in a Carbon-Constrained World.

57 Source: Advanced Resourced International, 2007,

58 U.S. EPA Office of Solid Waste and Emergency Response, National Biennial RCRA Hazardous Waste Report: Based 

on 2005 Data, Dec. 2006, at 2-5, Exhibit 2-5.

59 NETL report, at 2-71

60 J.P. Nicot et al., Area of Review: How large is large enough for carbon storage?, Bureau of Economic Geology, 

Jackson School of Geosciences, The University of Texas at Austin, 2006.

61 NETL report, at 4-83.
and 22

face the limitation that it is impractical, impossible, or extremely costly to acquire title to 

hundreds of thousands of acres of land.

Unique Potential Hazards of Carbon Dioxide Injection

While deepwell injection of liquids has occurred safely for over 20 years, there is less 

experience with injecting gasses like CO2. While most CO2 injections for enhanced oil 

recovery have occurred safely, problems that have occurred illustrate the unique hazards that 

utilities and regulators must consider. A few of these potential hazards include the following.

Blowout

Well blowouts occur when gas escapes through old or unknown wells. In January 2001, a 

natural gas leak from a cracked gas well casing leading to salt caverns and used as a natural 

gas storage facility resulted in an initial gas explosion below two stores in downtown 

Hutchinson, KS. The initial gas explosion was followed by an eruption of natural gas and 

water geysers two miles east of the initial explosion later that day and for several days 

thereafter. Two people residing in a trailer home were killed as a result of one of the 

explosions. The gas leak originated from a cracked well casing at a depth close to 600 feet 

and proceeded to migrate horizontally, traveling along abandoned brine wells and ultimately 

reaching the surface some distance away from the initial explosion.62

In another case involving CO2, a blowout occurred during drilling at a production well in March 

1982 causing the free flow of CO2 at the well head and leakage from ground fractures directly 

above the site. The high rate of CO2 from the well caused containment not to occur until the 

following month.63

A report jointly funded by U.S. EPA and U.S. DOE looked at injection well accidents in both 

the U.S. and abroad and issued recommendations for protecting against future accidents.64

The report issued a number of recommendations including: determining the potential for CO2

migration along unsealed fault and fracture zones; the potential for magmatic or seismic 

activity to cause damage to sealing caps resulting in CO2 releases; the potential for wells to 

transport CO2 to the surface; and implementation of public education and CO2 monitoring 

programs to minimize impact to human health and the environment from releases.65

The risk of blowout is hard to quantify since there is little information on the number of 

abandoned wells in the United States. It is difficult to estimate the number of these wells 

since some do not have observable caps or metal casings that can be detected through 

sensors. Texas estimates that there are approximately 11,000 orphan abandoned wells that it 

is gradually closing through a state program.66 Operators of CCS injection wells will have to 

find, close, and cap abandoned wells within the Area of Review.

62 Lewicki et al., at 41-2.

63 Lewicki et al., at 39-40.

64 Jennifer L. Lewicki et al., Natural and Industrial Analogues for Release of CO2 from Storage Reservoirs: 

Identification of Features, Events, and Processes and Lessons Learned, Earnest Orlando Lawrence Berkeley 

National Laboratory, Feb. 2006.

65 Lewicki et al., at 48-9.

66 Source Texas Railroad Commission at: http://www.rrc.state.tx.us/news-releases/2006/100606.html..
and 23

The DOE has a method of finding abandoned wells under its SEQURE program, however this 

program is not set up for national application. The SEQURE program uses low flying airplanes 

to detect abandoned wells and, as discussed above, aerial methods may not detect wells 

which do not have metal cases or other markers.

Economic Damage

The saline formations in Texas produce some oil and gas in formations nearby or overlaying 

the potential injection formations. In addition to well blowout, less apparent seeps from the 

injection zone into oil and gas producing layers can dilute the value of these deposits and 

ultimately return the CO2 to the atmosphere.67

Corrosion

As CO2 rises to the top of the injection layer, it may contact closed wells or the cement 

casings of older wells. If the CO2 reacts with water to form acidic compounds, these acids 

could start to erode the concrete. As more is eroded, the process accelerates, creating a 

reinforcing-negative cycle that could allow the CO2 to rise up the abandoned well to drinking 

water layers. While this problem can be prevented through different well closure 

approaches, the potential problem will increase the cost of an applicant’s Area of Review 

study and demonstration.68

Permitting Costs

In 2001, EPA estimated the costs of the siting requirements – the geologic study, the Area of 

Review study, and the no migration petition – as at least $2 million for a Class I hazardous 

waste well.69 EPA based its estimate on applicant experience, including an Area of Review of 

2.5 miles. If, as discussed above, the zone of influence could stretch to a radius of 13 miles, 

the Area of Review would be 26 times larger than for a typical Class I well. The siting studies 

and corrective measures for closing abandoned wells could approach $20 to $50 million. 

Operators (presumably electric utilities) would still need to pay for the well construction 

costs (estimated to be well over $1 million), permitting fees, operating, and the other costs.

Regulatory Capacity

In all, a Class I permit application can fill a bookcase with the required plans, analyses, and 

reports. States may spend over a year reviewing a renewal permit and several years 

reviewing a new Class I well permit.70 Because of the regulatory burdens, APPA staff 

speculates that states will require considerable permit fees to pay for these new state 

employees as well as analyses of new and renewed71 permit applications. Class II permits can 

be approved more rapidly. However, and as the maps show, as the UIC program has matured, 

Class I and II wells primarily now only occur where there is ample experience and knowledge 

of local and regional geography.

67 Nicot, et al. 

68 Nicot, et al.

69 EPA, 2001, at 20.

70 Source: Texas Commission on Environmental Quality (TCEQ) at 

http://www.tceq.state.tx.us/assets/public/comm_exec/pubs/sfr/057_06.pdf.

71 Class I permits may remain in effect for up to ten years as determined by the Program Director. See, 40 CFR 

144.28.
and 24

Even moderate adoption of CCS by new electric utilities would be the biggest expansion of 

underground injection in U.S. history. From the volumes above, the U.S. must undertake a 

dramatic expansion in its technical infrastructure to support safe CCS. In the private sector, 

engineers and geologists must identify, map, and investigate many more UI sites. In the near 

term there may be a shortage of experienced investigators. For the public sector, the skill 

gap is even more critical. Regulatory agencies must have sufficient in-house experience to 

review all of the technical information provided and to evaluate permit applications against 

the regulatory standards.

The size of the current regulatory skill shortage is illustrated by the following:

§ Less than half of regulatory agencies across the states have experience reviewing 

Class I or Class II permits. As the charts show, only about 20 states have experience 

permitting deep, high-volume injection wells. For CCS to occur in geologic formations 

around the U.S., many states must hire and train permitting staff or rely on EPA 

regional offices.

§ Experience is concentrated in a few regions of the country. Current experience is 

not distributed throughout the country, but concentrated in Texas, Louisiana, Florida, 

and a few other states. Unless states accept deep well injection in their states, CCS 

may require special CCS pipelines or via surface shipping carbon dioxide gas hundreds 

or thousands of miles from a power plant to an injection well. Pipeline shipment and 

booster compressors along the CCS pipeline increase the cost and perhaps the 

perception of the hazards of CCS. 

§ EPA regions must also boost their technical capacity. It is not only states that will 

be deluged with CCS permit applications. EPA regions approve UIC permits in some of 

the nation’s largest states and in states with large coal-fired power plants. EPA 

regions must craft their own approaches and technical requirements for CCS Class V 

permit applications.

§ Even in states with experience, states would need a significant boost in resources 

to permit a larger number of CCS wells. In 2006, Texas had ten new and eight Class 

I hazardous waste permit renewals under review. The average processing time was 

over one year for these permits. If CCS increases by a factor of ten the effective 

number of Class I wells in Texas, the regulatory system must either grow rapidly or the 

time needed to gain approval will soar.

Another consideration is the increased regulatory burden faced by electrical utilities when 

partnering with enhanced oil recovery (EOR) operations. Electrical utilities partnering with 

Class II well operators for EOR presumably would be subject to current Class I regulatory 

provisions, and ultimately any new regulatory requirements or framework established by U.S. 

EPA specifically to address CCS injection activities. 

Conclusion

Although the concept of CCS sounds promising, regulatory agencies’ paramount responsibility 

will be to ensure current and future protection of the nation’s drinking water supplies. For 

CCS to have a meaningful impact on U.S. power plant emissions, the mass of CO2 to be 

injected underground will dwarf current amounts by 10 to 20 times. While the nation has the 

ingenuity to tackle this challenge, it will require investing in technical skills, data, research, 
and 25

and education both in the private sector and in regulatory agencies. At the same time, there 

are major limitations that appear to preclude commercial-scale CCS in many parts of the 

country. APPA commissioned this paper to demonstrate the necessary regulatory systems 

needed to properly permit CCS into non-oil and gas or EOR sites. 

This paper does not outline the necessity to deal with other issues such as amending state 

drinking water laws or amending federal environmental laws such as the Comprehensive 

Environmental Response, Compensation, and Liability Act (CERCLA); Endangered Species Act 

(ESA), Resource Conservation and Recovery Act (RCRA), and CERCLA’s Natural Resource 

Damage Assessment Act (NRDA). These issues have been addressed by other APPA papers 

located at www.appanet.org/files/HTM/ccs.html

Recommendations

APPA recognizes that controlling CO2 emissions can bring about reductions in greenhouse 

gases . While there is considerable support for CCS and its promise for achieving sizeable 

emissions reductions, it is not clear the current regulatory structure and framework 

adequately addresses the limitations and adverse impacts related to CCS that have been 

noted above. APPA wants to ensure that these issues receive consideration and are 

appropriately addressed prior to moving forward with commercial-scale use of CCS.

1. APPA recommends that establishment of a process to ensure states and Public Utility 

Commissions are made aware of the limitations of CCS as addressed in this paper and 

that the issues be fully investigated prior to mandating CCS as part of permit approval.

2. APPA looks forward to working with the U.S. EPA on the cross-cutting or multimedia 

regulatory issues such as water use, drinking water, and air issues as they move 

forward with determining the best regulatory framework through which to review, 

approve, monitor commercial-scale carbon capture and storage projects.

American Public Power Association

1875 Connecticut Ave, NW

Suite 1200

Washington, DC 20009-5715
Carbon Capture and Storage: Analysis of Potential Liabilities Associated with 

Groundwater Contamination Due to Geological Sequestration Operations 

September 10, 2008 

Prepared by Fredric P. Andes and Kari A. Evans, members of the Barnes & Thornburg 

LLP Water Team, for the American Public Power Association (APPA) 

Background 

Carbon capture and storage (CCS) has been identified as a key component of any 

strategy to address rising levels of greenhouse gasses in the atmosphere, which is widely 

believed to be contributing to climate change. CCS involves capturing carbon dioxide 

(CO2) from emission sources, and injecting it into deep underground geologic formations 

below the lowest source of drinking water. Figure 1 shows the locations of deep saline 

aquifers, which are considered suitable repositories for CO2. The concept is to trap the 

CO2 in a form and location such that it can be stored indefinitely, rather than being 

released to the atmosphere. 

Although the whole purpose of CCS is to store CO2 in a stable form and location 

so that it is not released to the atmosphere, there are concerns that migration of CO2 from 

the deep rock formations GS could occur, posing potential threats to underground sources 

of drinking water (referred to as “USDWs”). To address this concern, U.S. EPA issued a 

proposed regulation this year to establish permitting requirements for underground 

injection of CO2, which U.S. EPA is calling geological sequestration (GS).1

 U.S. EPA is 

 

1

 73 Fed. Reg. 43492 (Jul. 25, 2008); the comment period ends November 24, 2008. The notice can be 

found at http://edocket.access.gpo.gov/2008/pdf/E8-16626.pdf. U.S. EPA’s Advance Notice of Proposed 

Rulemaking on Regulating Greenhouse Gas Emissions Under the Clean Air Act 

(http://www.epa.gov/climatechange/anpr.html) also contains background information on CCS, including 

GS. 
proposing to use the existing framework of the Underground Injection Control (UIC) 

program of the Safe Drinking Water Act (SDWA) to regulate GS.2

 The UIC program is 

meant to protect USDWs from potential contamination by imposing requirements for 

siting, designing, constructing, monitoring, and maintaining underground injection wells. 

In the preamble to the proposed regulation, U.S. EPA acknowledges the following 

fundamental limitation: 

[I]t is recognized that some injection activities may raise 

cross-state boundary issues that are beyond the scope of 

this rulemaking.3

This admitted limitation raises questions concerning the impacts of existing state 

programs regulating water quality on GS. The American Public Power Association 

(APPA) is evaluating this issue because many questions have emerged regarding 

liabilities associated with water – particularly groundwater – contamination that could 

occur as a result of GS. No commercially demonstrated CCS power plants have been 

built to date, and only a few small scale demonstrations (1 – 2 megawatts) of carbon 

separation technology are underway.4 Thus, there is uncertainty regarding potential 

effectiveness of CCS technology, including long-term stability of GS. This paper 

provides an analysis of the potential liabilities associated with groundwater 

 

2

 42 U.S.C. 300h et. seq. 

3

 73 Fed. Reg. at 43497. 

4

 The Swedish power company Vattenfall AB commenced operations on September 9, 2008, at its pilot 

plant in Germany, a 30 megawatt test unit which cost about $100 million to build. This pilot project is 

located at Vattenfall’s existing power station in Schwarze Pumpe, Germany, a 600 megawatt plant fueled 

by lignite. The CO2 produced by the pilot plant will not be released into the atmosphere; instead, the CO2

will be almost completely separated, liquefied and further treated for long-term secure underground 

storage. This geologic sequestration or separation at a commercial scale is announced but not yet 

operational. The company hopes to have this first plant and other plants operational by 2015, with an 

ultimate goal of creating commercially viable carbon capture and storage technology by 2020. Vattenfall 

said its ultimate goal is to reduce CCS costs to approximately $30 per metric ton (tonne) of captured CO2, 

but it noted that the technology would be viable if it could cut the cost to a range of $35 to $42 per tonne by 

2020. 

2
contamination due to GS operations, including situations in which the geologic 

formations into which CO2 will be injected crosses state boundaries. 

1. How many states have listed or designated groundwater as “waters of the 

state,” and what is the significance for getting CCS permitting approval? 

The chart at the end of this paper provides a listing of the relevant regulatory 

definitions for each state and U.S. territory. All states and U.S. territories expressly 

include groundwater within their definitions of “waters of the state” and/or within their 

water quality regulatory framework. However, states generally segregate their surface 

water quality standards and Clean Water Act (CWA) permitting programs from their 

groundwater quality protection measures. 

The potential significance this existing state framework presents for obtaining 

CCS permitting approval cannot be fully understood at this time, because much will 

depend on whether states will decide to use their existing authorities or adopt new 

measures to impose requirements or liabilities that will be more stringent than the U.S. 

EPA UIC permitting program for GS. The federal UIC program allows states to adopt 

and implement programs that are more stringent than the federal program.5

Furthermore, there could be unintended consequences and associated potential 

liability relative to imprecise applicability of state clean water programs. For example, if 

a state includes groundwater in its definition of “waters of the state,” and has an 

antidegradation policy that covers all waters of the state, it is possible that even if the 

state does not do anything to implement the antidegradation policy as it concerns 

groundwater, one could raise a claim that the policy would apply to introduction of a new 

wastestream to a groundwater source, as would be the case with GS operations. 

 

5

 42 U.S.C. § 300h-2(d). 

3
2. If a nearby state has a groundwater determination of water of the state, what 

liability could attach to a utility in an adjacent state for having injected CO2, 

or produced briny water or any contaminant related to drilling and injection 

(i.e., muds, cement, salty produced water, mercury, arsenic, boron, NORM). 

U.S. EPA’s proposed regulation (including the preamble) addresses how the UIC 

program for GS would interact with the Resource Conservation and Recovery Act 

(RCRA) and the Comprehensive Environmental Response, Compensation and Liability 

Act (CERCLA or “Superfund”).6 While uncertainty remains regarding whether and how 

these federal remediation laws would apply to GS activities, it appears likely that 

Superfund liability could attach to those involved in GS operations if a UIC program 

regulating GS operations is incorporated into the applicable or relevant and appropriate 

requirements (ARARs) that govern Superfund remediation activities. Additional 

information about potential liabilities under RCRA and Superfund are explored in 

another APPA white paper on the legal and environmental challenges associated with 

CCS.7

As discussed in the previous section of this paper, what is less clear is how the 

proposed regulation would interact with existing state water quality and groundwater 

protection programs, particularly in cross-boundary situations. Although U.S. EPA has 

stated that the proposed regulation does not address cross-boundary water quality issues, 

such issues will undoubtedly arise. These issues have been clearly addressed in surface 

water situations regulated by the CWA. In Arkansas v. Oklahoma, the U.S. Supreme 

Court considered whether an NPDES permit issued by U.S. EPA to a sewage treatment 

plant in Arkansas was invalid due to claims that the discharge to a waterbody upstream of 

 

6

 73 Fed. Reg. at 43503-43504. 

7

 “Carbon Capture and Sequestration: Legal and Environmental Challenges Ahead,” prepared by Marianne 

Horinko, The Global Environment & Technology Foundation, for APPA (Aug. 2007). 

4
the Illinois River, which in turn flows into Oklahoma, could cause or contribute to a 

violation of Oklahoma water quality standards.8

 The Court ruled that the CWA preempts a neighboring state from bringing a common law action against discharges from 

NPDES-permitted facilities. In such situations, the permitting authority (U.S. EPA or a 

state with delegated permitting authority) must consider the downstream impacts to 

neighboring states when issuing the permit. 

The SDWA does not contain a similar provision respecting the IUC program. 

Also, as noted in the previous section of this paper, the SDWA does not pre-empt states 

from adopting or enforcing their own laws or regulations on underground injection as 

long as the UIC program requirements are met. Thus, the potential exists for states with 

sufficient state-based authority to take action concerning groundwater contamination 

associated with a GS operation in a neighboring state. 

Perhaps the greatest potential liability associated with GS is tort actions in which 

a party claims it has been injured by groundwater contamination due to CO2 storage. In 

particular, there is a concern about long-term liability once an injection well has been 

closed. Potential tort liability for GS is similar in nature but distinguishable from the 

liability that has been associated with MTBE, the fuel additive that reduced certain air 

emissions but also resulted in drinking water contamination due to leaking underground 

storage tanks and spills. MTBE contamination litigation has been filed by private 

citizens and states against companies that produced and used MTBE. Much of that 

litigation has been based upon product liability claims – i.e., that MTBE, as manufactured 

 

8

 503 U.S. 91 (1992). 

5
and used as fuel additive, was a defective commercial product that caused injury. In 

contrast, GS does not produce a “product,” but is a containment or disposal method. 

When questioned about this liability issue, U.S. EPA officials have stated that 

they do not believe the agency has the authority to address it by regulation, and that an 

act of Congress would be necessary. Congressional action would certainly be the best 

method to assure that tort liability is limited. Congress has taken such action in other 

situations in which it has been deemed necessary and in the public interest to enable 

important activities. For example, Congress has enacted the Price-Anderson Nuclear 

Industries Indemnity Act to address liability issues related to non-military nuclear 

facilities.9 The Price-Anderson Act provides partial indemnification against liability 

claims arising from nuclear incidents. It also creates an insurance system in which the 

nuclear industry funds claims up to a certain level, with any excess in claims being 

covered by the federal government. Such an approach was deemed necessary by 

Congress to overcome the concerns of potential nuclear energy investors about openended liability. The U.S. Supreme has upheld the constitutionality of the Price-Anderson 

Act with the following specific findings: 

(a) The record supports the need for the imposition of a 

statutory limit on liability to encourage private industry 

participation and hence bears a rational relationship to 

Congress’ concern for stimulating private industry’s 

involvement in the production of nuclear electric energy. 

(b) Assuming, arguendo, that the $560 million fund would 

not insure full recovery in all conceivable circumstances, it 

does not follow that the liability limitation is therefore 

irrational and violative of due process. When appraised in 

light of the extremely remote possibility of an accident in 

which liability would exceed the statutory limit and 

Congress’ commitment to “take whatever action is deemed 

 

9

 42 U.S.C. § 2210. 

6
necessary and appropriate to protect the public from the 

consequences of” a disaster of such proportions, the 

congressional decision to fix a $560 million ceiling is 

within permissible limits and not violative of due process. 

(c) The District Court’s finding that the Act tends to 

encourage irresponsibility in matters of safety and 

environmental protection cannot withstand careful scrutiny, 

since nothing in the liability-limitation provision 

undermines or alters the rigor and integrity of the process 

involved in the review of applications for a license to 

construct or operate a nuclear power plant, and since, in the 

event of a nuclear accident the utility itself would probably 

suffer the largest damages. 

(d) The Act provides a reasonably just substitute for the 

common law or state tort law remedies it replaces, and 

nothing more is required by the Due Process Clause. The 

congressional assurance of a $560 million fund for 

recovery, accompanied by the statutory commitment to 

“take whatever action is deemed necessary and appropriate 

to protect the public from the consequences of” a nuclear 

accident, is a fair and reasonable substitute for the uncertain 

recovery of damages of this magnitude from a utility or 

component manufacturer whose resources might well be 

exhausted at an early stage. And, at the minimum, the 

statutorily mandated waiver of defenses establishes at the 

threshold the right of injured parties to compensation 

without proof of fault and eliminates the burden of delay 

and uncertainty that would follow from the need to litigate 

the question of liability after an accident. 

(e) There is no equal protection violation, since the general 

rationality of the Act’s liability limitation, particularly with 

reference to the congressional purpose of encouraging 

private participation in the exploitation of nuclear energy, 

is ample justification for the difference in treatment 

between those injured in nuclear accidents and those whose 

injuries are derived from other causes.10

A similar situation exists with the potential for large-scale GS of CO2 in the 

United States. It is possible that through Congressional action on CO2 or through a stateby-state BACT determination that IGCC plus CCS technologies for CO2 sequestration 

 

10 Duke Power Co. v. Carolina Environmental Study Group, 438 U.S. 59, 60-61 (1978). 

7
would be the presumed required coal based generation technology to control CO2, in the 

near future—perhaps as early as 2009 or 2010. GS is often presumed to be a key strategy 

for reducing future CO2 emissions to the atmosphere. The federal government appears to 

expect that private industry will take the lead in financing, constructing, operating and 

maintaining GS sites. Therefore, in exchange for performing this “public good” (i.e., 

reducing the environmental impacts associated with production of a public commodity), 

Congress might opt to limit industry’s liability for unanticipated and unintended 

consequences of GS, including groundwater contamination. However, to date, none of 

the leading bills in Congress to address CO2 from power plants have included any 

revisions to existing Federal environmental laws to address liability. 

In the absence of a federal limitation on liability, individual states could adopt 

their own legislation to limit liability of GS operations. However, a state-by-state 

approach would not necessarily ensure liability limitations in cross-boundary situations, 

because the neighboring state may not have a corresponding law. States could also join 

together to adopt a multi-state compact on GS, including liability limitations. Interstate 

compacts are provided for in the U.S. Constitution, and are widely used by states to 

address issues that involve multiple states in situations where Congress has not acted (or 

in cases where the states have a preference for a Compact as opposed to a federal law). 

3. If a state’s groundwater is not classified as a water of the state now and a 

power plant gets permitted for operation, could it be affected say 5 or 10 

years from now if the nearby state designated the groundwater as a water of 

the state? 

As discussed in section 1 of this paper, it appears that all states and U.S. territories 

already include groundwater within their legal definitions of “waters of the state.” Thus, 

any potential liabilities associated with GS operations affecting groundwater in a 

8
neighboring state would be present at the time a GS operation is sited and permitted. In 

other words, potential liability would already exist, and thus would not arise only as the 

result of future changes in state laws. 

4. What are the legal actions available to citizens or private parties or states? 

Please explain if there are citizen suit actions available through only tort 

litigation for alleged CWA or SDWA violations or if permits could be either 

withheld or stopped. In other words could a utility get a permit and be 

operating a new CCS plant and say 8 years after operation find that its 

permit to operate was now under question by that state agency or by a 

nearby state which shares a deep saline aquifer? 

Both the SDWA and CWA contain citizen suit provisions, and many states have 

similar citizen suit laws regarding violations of state-based environmental laws. The 

CWA provision11 authorizes suits following notice against any person alleged to have 

violated a CWA effluent standard or limitation or an order issued by U.S. EPA or a state 

related to such a standard or limitation. A suit may also be filed against U.S. EPA for an 

alleged failure to perform any non-discretionary CWA act or duty. Suits are foreclosed if 

U.S. EPA or a state is diligently prosecuting the person alleged to have caused the 

violation. The SDWA provision12 contains a similar citizen suit provision. It is 

important to note that both statutes contain express statements that other statutory or 

common law rights are not restricted. For example, the CWA states: 

Statutory or common law rights not restricted. 

Nothing in this section shall restrict any right which any 

person (or class of persons) may have under any statute or 

common law to seek enforcement of any effluent standard 

or limitation or to seek any other relief (including relief 

against the Administrator or a State agency).13

 

11 33 U.S.C. § 1365. 

12 42 U.S.C. § 300j-8. 

13 33 U.S.C. § 1365(e). 

9
Thus, private parties would retain a private right of action to pursue suits based upon tort 

and other common law claims, even if a citizen would be foreclosed under the CWA or 

SDWA. 

About the American Public Power Association 

Public power is the term used to describe the more than 2,000 municipal and other state 

and local community-owned electric utilities that provide electricity for approximately 45 

million Americans. These public power systems are among the most diverse of the 

electric utility sectors, representing utilities in small, medium and large communities in 

49 states (all but Hawaii). Seventy-five percent of public power systems are located in 

cities with populations of 10,000 or less. The majority of public power systems do not 

generate electricity and serve as distribution utilities. Overall, public power accounts for 

about 16 percent of all kilowatt-hour sales to consumers. More than 80% of the cities 

with public power utilities also manage public water utilities. 

APPA was created in 1940 as a non-profit, nonpartisan organization. Its purposes are to 

advance the public policy interests of its members and their consumers, and to provide 

member services to ensure adequate, reliable electricity at a reasonable price with the 

proper protection of the environment. 

About the Authors 

Fredric P. Andes is a partner in the Chicago and Washington, D.C. offices of Barnes & 

Thornburg LLP, Chairman of the Environmental Department and the leader of the firm’s 

water team. He is also a member of the Firm’s Management Committee. Mr. Andes is 

involved in counseling and litigation on issues arising under various federal and state 

environmental laws, with a special emphasis on Clean Water Act matters. Mr. Andes is 

involved in clean water issues on the national and state levels. He was selected by the 

EPA to serve on the Federal Advisory Committee on the Total Maximum Daily Load 

(TMDL) Program. He serves as coordinator for the Federal Water Quality Coalition, 

which is a group of municipal and other regulated parties that participate in EPA 

rulemakings and policy regarding key Clean Water Act programs. Mr. Andes also 

advised trade associations, industries, and municipalities on TMDLs, permits, and other 

water quality matters on the state and federal levels, including development of water 

quality standards, listings, TMDLs, and permit conditions. Before coming to Barnes & 

Thornburg, Mr. Andes was a partner with the Chicago law firm of Sonnenschein Nath & 

Rosenthal. Prior to working in Chicago, he spent nine years practicing environmental law 

in Washington, D.C. Mr. Andes graduated cum laude from Harvard Law School in 1980. 

He obtained his undergraduate degree from Northwestern University in 1977. 

Kari A. Evans is of counsel in the Indianapolis, Indiana office of Barnes & Thornburg 

LLP where she is a member of the firm’s Environmental and Government Services 

Departments. In April of 2008 she returned to Barnes & Thornburg after serving as 

policy director for Environment and Natural Resources for Indiana Governor Mitch 

10
Daniels. Ms. Evans previously practiced at Barnes & Thornburg from 2000 to 2005. Ms. 

Evans represents businesses, local governments, and trade associations throughout the 

country on all aspects of environmental compliance, including legislative and regulatory 

development; permitting; and enforcement. She has litigated environmental cases in 

federal, state, and administrative courts, and has negotiated with federal, state, and local 

agencies to achieve resolutions to complex environmental issues. As Governor Daniels’ 

policy director for Environment and Natural Resources, Ms. Evans developed and 

advocated policy on significant national, regional, and state issues, including the Great 

Lakes Water Resources Compact, Great Lakes water discharge permitting, air quality 

standards and attainment designations, and mercury emission reduction requirements for 

electric utilities. Prior to joining Barnes & Thornburg in 2000, Ms. Evans was chief of 

the Water Rules Section at the Indiana Department of Environmental Management 

(IDEM. Ms. Evans earned her J.D. cum laude from the University of Minnesota Law 

School and received her B.S. in environmental science from Miami University in Oxford, 

Ohio. 

11
12

Figure 1: North American Deep Saline Aquifers 

Source: National Energy Technology Laboratory (NETL), U.S. Department of Energy 

For more information and other White Papers on CCS, please see APPA’s website at: 

http://www.appanet.org/files/HTM/ccs.html 

Appendix 1: “Waters of the State” Survey Chart is attached to this paper, which outlines 

the definition of “Waters of the State” for U.S. States and Territories. 

APPA Contact: 

Theresa Pugh 

Director, Environmental Services 

1875 Connecticut Ave, NW, 12th Floor 

Washington, DC 20009 

202-467-2956 

TPugh@APPAnet.org 
APPENDIX 1: “WATERS OF THE STATE” SURVEY CHART 

STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Alabama ADEM Admin. 

Code. R. 335-6-335-6-5-.02 

“Waters of the State” means all waters of any river, stream, watercourse, pond, lake, coastal, ground or surface water, wholly or partially within the state, natural or artificial. This does not include waters which are entirely confined and retained completely upon the property of a single individual, partnership or corporation unless such waters are used in interstate commerce. 

http://wns/Div

Alaska AS 46.030.900 “Waters” includes lakes, bays, sounds, ponds, impounding reservoirs, 

springs, wells, rivers, streams, creeks, estuaries, marshes, inlets, straits, passages, canals, the Pacific Ocean, Gulf of Alaska, Bering Sea, and Arctic Ocean, in the territorial limits of the state, and all other bodies of surface or underground water, natural or artificial, public or private, inland or coastal, fresh or salt, which are wholly or partially in or bordering the state or under the jurisdiction of the state. 

http://wats/Sta46/Cha

American Samoa 

ASC 24.0201 “Fresh surface waters” means all fresh territorial waters including perennial, 

intermittent, and ephemeral freshwater streams, all natural and artificial impoundments, springs, seeps and wetlands, including coastal wetlands not surface-connected to the ocean. This includes all surface territorial waters that are not embayments, open coastal waters, or ocean waters. 

“Ground water” means water in the part of the ground that includes all subsurface waters, basal and parabasal water, perched water, water percolating through the unsaturated zone, and all saline waters below and along the perimeter of the basal fresh water body. “Ocean waters” means those waters that extend from the 100-fathom (600-foot or 183-meter) depth contour seaward. “Open coastal waters” means those waters that begin at the shoreline and extend seaward to the 100-fathom (600-foot or 183-meter) depth contour from mean lower low water. This category includes small bays with good water movement which do not qualify as embayments. “Territorial waters” means waters of the United States as defined in 40 CFR 122.2, as well as those that are located within the jurisdiction of the territory. 

http://wdards/wsamoa_

1
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Arizona ARS Title 49-201 “Waters of the state” means all waters within the jurisdiction of this state 

including all perennial or intermittent streams, lakes, ponds, impounding reservoirs, marshes, watercourses, waterways, wells, aquifers, springs, irrigation systems, drainage systems and other bodies or accumulations of surface, underground, natural, artificial, public or private water situated wholly or partly in or bordering on the state. 

http://wocumeDoc=/aocType

Arkansas AR BLR 8-4-102 “Waters of the state” means all streams, lakes, marshes, ponds, watercourses, 

waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, which are contained within, flow through, or border upon this state or any portion of the state.

http://wteway.m&vid

California CA CODE 2-

13050 

“Waters of the state” means any surface water or groundwater, including saline waters, within the boundaries of the state. 

http://lwat/13

Colorado 5 CCR 1002-31 “State waters” means any and all surface and subsurface waters which are 

contained in or flow in or through this state, but does not include waters in sewage systems, waters in treatment works of disposal systems, waters in potable water distribution systems, and all water withdrawn for use until use and treatment have been completed. 

http://wons/wq

Connecticut CT Statutes 22a423 “Waters” means all tidal waters, harbors, estuaries, rivers, brooks, watercourses, waterways, wells, springs, lakes, ponds, marshes, drainage 

systems and all other surface or underground streams, bodies or accumulations of water, natural or artificial, public or private, which are contained within, flow through or border upon this state or any portion thereof 

http://chtm#S

2
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Delaware 7 DNREC 7202 “State Waters” or “Waters Of The State” means all water, on the surface and 

under the ground, wholly or partially within, or bordering the State, or within its jurisdiction including but not limited to: 

• Waters which are subject to the ebb and flow of the tide including, but not limited to, estuaries, bays and the Atlantic Ocean; • All interstate waters, including interstate wetlands; • All other waters of the State, such as lakes, rivers, streams (including intermittent and ephemeral streams), drainage ditches, tax ditches, creeks, mudflats, sandflats, wetlands, sloughs, or natural or impounded ponds; • All impoundments of waters otherwise defined as waters of the State under this definition; • Wetlands adjacent to waters (other than waters that are themselves wetlands) identified above. Waste and stormwater treatment systems including, but not limited to, treatment ponds or lagoons designed to meet the requirements of the Act (other than cooling ponds which otherwise meet the requirements of subsection (1) of this definition) are not “State waters” or “Waters of the State.” 

http://rnCode/opOfP

Florida FL Stat. 403.031 “Waters” include, but are not limited to, rivers, lakes, streams, springs, 

impoundments, wetlands, and all other waters or bodies of water, including fresh, brackish, saline, tidal, surface, or underground waters. Waters owned entirely by one person other than the state are included only in regard to possible discharge on other property or water. Underground waters include, but are not limited to, all underground waters passing through pores of rock or soils or flowing through in channels, whether manmade or natural. Solely for purposes of s. 403.0885, waters of the state also include navigable waters or waters of the contiguous zone as used in s. 502 of the Clean Water Act, as amended, 33 U.S.C. ss. 1251 et seq., as in existence on January 1, 1993, except for those navigable waters seaward of the boundaries of the state set forth in s. 1, Art. II of the State Constitution. Solely for purposes of this chapter, waters of the state also include the area bounded by the following: [specific boundaries omitted]

http://wex.cfmSearch31.HTM

3
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Georgia GA 391-3-6 “Water” or “waters of the State” means any and all rivers, streams, creeks, 

branches, lakes, reservoirs, ponds, drainage systems, springs, wells, wetlands, and all other bodies of surface or subsurface water, natural or artificial, lying within or forming a part of the boundaries of the State which are not entirely confined and retained completely upon the property of a single individual, partnership, or corporation. 

http://wes_exis

Guam Guam PL 26-32 “Groundwater”: all subsurface water and includes basal and parabasal water, 

perched water, all water below the groundwater table, water percolating through the unsaturated zone (vadose water), all saline waters below and along the permimeter of the basal fresh water body (freshwater lens), and water on the surface that has been collected with the specific intent of recharging or disposing of that water to the subsurface by means of injection, infiltration, percolation, etc. 

“Marine Waters”: all coastal waters off-shore from the mean high water mark, including estuarine waters, lagoons and bays, brackish areas, wetlands and other special aquatic sites, and other inland waters that are subject to ebb and flow of the tides. “Surface Waters”: all of surface freshwater and includes: (1) waters that flow continuously over land surfaces in a defined channel or bed, such as streams and rivers; (2) standing water in basins, such as lakes, wetlands, marshes, swamps, ponds, sinkholes, ponding basins, impoundments, and reservoirs, either natural or man-made; and (3) all waters flowing over the land as runoff, or as runoff confined to channels with intermittent flow. 

http://wdards/wwqs.pd

Hawaii H.R.S. 342D-1 “State waters”, as defined by section 342D-1, HRS, means all waters, fresh, 

brackish, or salt around and within the State, including, but not limited to, coastal waters, streams, rivers, drainage ditches, ponds, reservoirs, canals, ground waters, and lakes; provided that drainage ditches, ponds, and reservoirs required as part of a water pollution control system are excluded. 

“State waters” means all waters, fresh, brackish, or salt, around and within the State, including, but not limited to, coastal waters, streams, rivers, drainage ditches, ponds, reservoirs, canals, ground waters, and lakes; provided that drainage ditches, ponds, and reservoirs required as a part of a water pollution control system are excluded. 

http://went/Vo0344/H0001.h

4
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Idaho IDAPA 58.01.02 “Waters And Waters Of The State”: All the accumulations of water, surface 

and underground, natural and artificial, public and private, or parts thereof 

which are wholly or partially within, which flow through or border upon the state. 

http://a/idapa5

Illinois 35 IAC 301 “Waters” means all accumulations of water, surface and underground, 

natural, and artificial, public and private, or parts thereof, which are wholly or partially within, flow through, or border upon the State of Illinois, except that sewers and treatment works are not included except as specially mentioned; provided, that nothing herein contained shall authorize the use of natural or otherwise protected waters as sewers or treatment works except that in-stream aeration under Agency permit is allowable. 

http://w/dsweb

Indiana IC 13-11-2-265 “Waters”, for purposes of water pollution control laws and environmental 

management laws, means: (1) the accumulations of water, surface and underground, natural and artificial, public and private; or (2) a part of the accumulations of water; that are wholly or partially within, flow through, or border upon Indiana. 

(b) The term “waters” does not include: (1) an exempt isolated wetland; (2) a private pond; or (3) an off-stream pond, reservoir, wetland, or other facility built for reduction or control of pollution or cooling of water before discharge. (c) The term includes all waters of the United States, as defined in Section 502(7) of the federal Clean Water Act (33 U.S.C. 1362(7)), that are located in Indiana. 

http://wtitle13/

Iowa IA Code 455B.171 “Water of the state” means any stream, lake, pond, marsh, watercourse, 

waterway, well, spring, reservoir, aquifer, irrigation system, drainage system, and any other body or accumulation of water, surface or underground, natural or artificial, public or private, which are contained 

within, flow through or border upon the state or any portion thereof. 

http://w2003SU

Kansas KS65-161 “Waters of the state” means all streams and springs, and all bodies of surface 

and subsurface waters within the boundaries of the state. 

http://wstatute5-161.h

5
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Kentucky KRS 224A.011 “Waters of the state” means all streams, lakes, watercourses, waterways, 

ponds, marshes, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, which are situated wholly or partly within, or border upon, this state, or are within its jurisdiction, except those private waters which do not combine or effect a junction with natural, surface, or underground waters. 

http://w.pdf

Louisiana LAC 33, part IX, 

Subpart 1, Section 107 

“Waters of the State”: both the surface and underground waters within the state of Louisiana including all rivers, streams, lakes, estuaries, ground waters and all other water courses and waters within the confines of the state, and all bordering waters and the Gulf of Mexico. 

http://wortals/0200806

Maine ME Title 38, 

Section 361 A 

“Waters of the State” means any and all surface and subsurface waters that are contained within, flow through, or under or border upon this State or any portion of the State, including the marginal and high seas, except such waters as are confined and retained completely upon the property of one person and do not drain into or connect with any other waters of the State, but not excluding waters susceptible to use in interstate or foreign commerce, or whose use, degradation or destruction would affect interstate or foreign commerce. 

http://j38/title

Maryland MD Code 

26.08.01.01 

“Waters of this State” includes: (a) Both surface and underground waters within the boundaries of this State subject to its jurisdiction, including that part of the Atlantic Ocean within the boundaries of this State, the Chesapeake Bay and its tributaries, and all ponds, lake, rivers, streams, tidal and nontidal wetlands, public ditches, tax ditches, and public drainage systems within this State, other those designed and used to collect, convey, or dispose of sanitary sewage; (b) The flood plain of free-flowing waters determined by the Department of Natural Resources on the basis of the 100-year flood frequency. 

http://wCenter

Massachusetts 314 CMR 4.03 “Waters of the Commonwealth”: All waters within the jurisdiction of the 

Commonwealth, including, without limitation, rivers, streams, lakes, ponds, springs, impoundments, estuaries, wetlands, coastal waters, groundwaters, and vernal pools. 

http://wulation

Michigan MCL 324.30101 “Waters of the state” means groundwaters, lakes, rivers, and streams and all 

other watercourses and waters, including the Great Lakes, within the jurisdiction of this state. 

http://w1fprfohpage=g324-31

6
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Minnesota MAR 115.01 “Waters of the state” means all streams, lakes, ponds, marshes, watercourses, 

waterways, wells, springs, reservoirs, aquifers, irrigation systems, drainage 

systems and all other bodies or accumulations of water, surface or underground, natural or artificial, public or private, which are contained within, flow through, or border upon the state or any portion thereof. 

https://atutes/

Mississippi MS WPC-1 “Waters of the State” means all waters within the jurisdiction of this State, 

including all streams, lakes, ponds, wetlands, impounding reservoirs, marshes, watercourses, waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, situated wholly or partly within or bordering upon the State, and such coastal waters as are within the jurisdiction of the State, except lakes, ponds, or other surface waters which are wholly landlocked and privately owned, and which are not regulated under the Federal Clean Water Act (33 U.S.C.1251 et seq.). 

http://wMDEQe

Missouri MRS 644.016 “Waters of the state”: all rivers, streams, lakes and other bodies of surface 

and subsurface water lying within or forming a part of the boundaries of the state which are not entirely confined and located completely upon lands owned, leased or otherwise controlled by a single person or by two or more persons jointly or as tenants in common and includes waters of the United States lying within the state. 

http://w00-699

Montana 75-5-103 “State waters” means a body of water, irrigation system, or drainage system, 

either surface or underground. 

(b) The term does not apply to: 

(i) ponds or lagoons used solely for treating, transporting, or impounding pollutants; or (ii) irrigation waters or land application disposal waters when the waters are used up within the irrigation or land application disposal system and the waters are not returned to state waters. 

http://wdards/wdf

Nebraska Title 118, Chap. 1 “Waters of the State” shall mean all waters within the jurisdiction of this 

State including all streams, lakes, ponds, impounding reservoirs, marshes, wetlands, watercourses, waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface or underground, natural or artificial, public or private, situated wholly or partly within or bordering upon the State. 

http://w

7
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Nevada: NRS 445A.415 “Waters of the State” means all waters situated wholly or partly within or 

bordering upon this State, including but not limited to: 

1. All streams, lakes, ponds, impounding reservoirs, marshes, water courses, waterways, wells, springs, irrigation systems and drainage systems; and 2. All bodies or accumulations of water, surface and underground, natural or artificial. 

http://w445A.h

New Hampshire 

NH RSA 485-A NH RSA 485-C (Groundwater Protection Act) 

The purpose of this chapter is to protect water supplies, to prevent pollution in the surface and groundwaters of the state and to prevent nuisances and potential health hazards. In exercising any and all powers conferred upon the department of environmental services under this chapter, the department shall be governed solely by criteria relevant to the declaration of purpose set forth in this section. “Surface waters of the state” means perennial and seasonal streams, lakes, ponds, and tidal waters within the jurisdiction of the state, including all streams, lakes, or ponds bordering on the state, marshes, water courses, and other bodies of water, natural or artificial. “Groundwaters” shall mean all areas below the top of the water table, including aquifers, wells and other sources of groundwater. 

http://wml/NH

New Jersey NJAC 7:9B “Waters of the State” means the ocean and its estuaries, all springs, streams, 

wetlands, and bodies of surface or ground water, whether natural or artificial, within the boundaries of the State of New Jersey or subject to its jurisdiction. 

http://wa/docs/

New Mexico NMAC 20.8 “Water” means all water including water situated wholly or partly within or 

bordering upon the state, whether surface or subsurface, public or private, except private waters that do not combine with other surface or subsurface water. 

http://won/regs

8
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

New York NYECL 17-0105 “Waters” or “waters of the state” shall be construed to include lakes, bays, 

sounds, ponds, impounding reservoirs, springs, wells, rivers, streams, creeks, estuaries, marshes, inlets, canals, the Atlantic ocean within the territorial limits of the state of New York and all other bodies of surface or underground water, natural or artificial, inland or coastal, fresh or salt, public or private (except those private waters which do not combine or effect a junction with natural surface or underground waters), which are wholly or partially within or bordering the state or within its jurisdiction. 

http://lyork/enconser0105.h

North Carolina NC G.S. 143-212 “Waters” means any stream, river, brook, swamp, lake, sound, tidal estuary, 

bay, creek, reservoir, waterway, or other body or accumulation of water, whether surface or underground, public or private, or natural or artificial, that is contained in, flows through, or borders upon any portion of this State, including any portion of the Atlantic Ocean over which the State has jurisdiction. 

http://wion/Star_143/

North Dakota ND Century Code 

33-16-02.1 

“Waters of the state” means all waters within the jurisdiction of this state including all streams, lakes, ponds, impounding reservoirs, marshes, watercourses, waterways, and all other bodies or accumulations of water on or under the surface of the earth, natural or artificial, public or private, situated wholly or partly within or bordering upon the state, except those private waters that do not combine or effect a junction with natural surface or underground waters just defined. 

http://wW/Z7_pdf

9
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Northern Mariana Islands 

2 CMC 3101 “Commonwealth Waters” means all waters, fresh, brackish, or marine, 

including wetlands, surrounding or within the Commonwealth, as provided for by Federal and Commonwealth law. 

Whereas the Commonwealth is almost entirely dependent on ground water for its drinking water supplies, these regulations set water quality standards for surface waters and land disposal activities to ensure the protection of this natural resource. Requirements for land disposal activities will be determined according to groundwater management zones promulgated under the CNMI Well Drilling and Well Operation Regulations for Saipan; for Tinian and Rota these requirements will be dependent on known geological and aquifer characteristics, lateral distances to nearby water wells, and general quality and vulnerability of existing ground water until specific groundwater quality management zones are developed. 

http://wdards/wmarian

Ohio ORC Chapter 6111 “Waters of the state” means all streams, lakes, ponds, marshes, watercourses, 

waterways, wells, springs, irrigation systems, drainage systems, and other 

bodies or accumulations of water, surface and underground, natural or artificial, regardless of the depth of the strata in which underground water is located, that are situated wholly or partly within, or border upon, this state, or are within its jurisdiction, except those private waters that do not combine or effect a junction with natural surface or underground waters. 

http://c

Oklahoma OAR 785:45-1-2 “Waters of the state” means all streams, lakes, ponds, marshes, watercourses, 

waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, which are contained within, flow through, or border upon this State or any portion thereof. 

http://wc02.nsfme=M4dthj0ccln50o

Oregon OAR 340-041-

0001 

“Waters of the State” means lakes, bays, ponds, impounding reservoirs, springs, wells, rivers, streams, creeks, estuaries, marshes, inlets, canals, the Pacific Ocean within the territorial limits of the State of Oregon, and all other bodies of surface or underground waters, natural or artificial, inland or coastal, fresh or salt, public or private (except those private waters that do not combine or effect a junction with natural surface or underground waters) that are located wholly or partially within or bordering the state or within its jurisdiction. 

http://aRs_300

10
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Pennsylvania 35 P.S. 961.1 “Waters of the Commonwealth” shall be construed to include any and all 

rivers, streams, creeks, rivulets, impoundments, ditches, water courses, storm sewers, lakes, dammed water, ponds, springs and all other bodies or channels of conveyance of surface and underground water, or parts thereof, whether natural or artificial, within or on the boundaries of this Commonwealth. 

http://wault.wl1000&ype=V.0&rp=C9107F4EEC

Puerto Rico PR Water Quality 

Standards 

“Waters of Puerto Rico”: All coastal waters, surface waters, estuarine waters, ground waters and wetlands as defined in this Regulation. 

http://wdards/w

Rhode Island RI GA 46-15 “Waters of the State” or “The Waters” means all surface water and 

groundwater of the State of Rhode Island, including all tidewaters, territorial seas, wetlands, and land masses partially or wholly submerged in water; and both inter- and intra-state bodies of water which are, have been or will be used in commerce, by industry, for the harvesting of fish and shellfish or for recreational purposes. 

http://w

South Carolina SC Code 48-1-10 “Waters” means lakes, bays, sounds, ponds, impounding reservoirs, springs, 

wells, rivers, streams, creeks, estuaries, marshes, inlets, canals, the Atlantic Ocean within the territorial limits of the State and all other bodies of surface or underground water, natural or artificial, public or private, inland or coastal, fresh or salt, which are wholly or partially within or bordering the State or within its jurisdiction. 

http://w8c001.

South Dakota SDAR 74:51:01:01 “Waters of the state,” all waters within the jurisdiction of this state, 

including streams, lakes, ponds, impounding reservoirs, marshes, watercourses, waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, situated wholly or partly 

within or bordering on the state, but not waste treatment systems, including treatment ponds or lagoons designed to meet the requirements of the CWA other than cooling ponds as defined in 40 C.F.R. § 423.11(m) (July 1, 1991). 

http://lule.asp

Tennessee TN Water Control 

Act of 1977 

“Waters of the state”: any and all water, public or private, on or beneath the surface of the ground, which are contained within, flow through, or border upon Tennessee or any portion thereof except those bodies of water confined to and retained within the limits of private property in single ownership which do not combine or effect a junction with natural surface or underground waters. 

http://w.htm

11
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Texas TX WATER 

CODE 26 

“Water” or “water in the state” means groundwater, percolating or otherwise, lakes, bays, ponds, impounding reservoirs, springs, rivers, streams, creeks, estuaries, wetlands, marshes, inlets, canals, the Gulf of Mexico, inside the territorial limits of the state, and all other bodies of surface water, natural or artificial, inland or coastal, fresh or salt, navigable or nonnavigable, and including the beds and banks of all watercourses and bodies of surface water, that are wholly or partially inside or bordering the state or inside the jurisdiction of the state. 

http://tWA/co0.pdf

Utah UT Admin. Code 

R317-1 

“Waters of the state” means all streams, lakes, ponds, marshes, watercourses, waterways, wells, springs, irrigation systems, drainage systems, and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, which are contained within, flow through, or border upon this state or any portion thereof, except that bodies of water confined to and retained within the limits of private property, and which do not develop into or constitute a nuisance, or a public health hazard, or a menace to fish and wildlife, shall not be considered to be “waters of the state” under this definition (Section 19-5-102). 

http://wde/r317

Vermont 10 V.S.A. 1390, 

1391 “Groundwater” means water below the land surface, but does not include surface waters within the meaning of 10 V.S.A. § 1251(13). 

It is the policy of the state of Vermont that it shall protect its groundwater resources to maintain high quality drinking water and shall manage its groundwater resources to minimize the risks of groundwater quality deterioration by limiting human activities that present unreasonable risks to the use classifications of groundwater in the vicinities of such activities while balancing the state's groundwater policy with the need to maintain and promote a healthy and prosperous agricultural community. 

http://wtions.c

Virgin Islands 12 VIC 7.182(f) “Waters of the United States Virgin Islands” means all waters within the 

jurisdiction of the United States Virgin Islands including all harbors, streams, lakes, ponds, impounding reservoirs, marshes, water-courses, waterways, wells, springs, irrigation systems, drainage systems and all other bodies or accumulations of water, surface and underground, natural or artificial, public or private, situated wholly or partly within or bordering upon the United States Virgin Islands, including the territorial seas, contiguous zones, and oceans. 

http://wlpext.dh.htm&

12
STATE LAW DEFINITION OF “WATERS OF THE STATE” 

Virginia VA Code 62.1-44-2 “Water” includes all waters, on the surface and under the ground, wholly or 

partially within or bordering the Commonwealth or within its jurisdiction and which affect the public welfare. 

http://lbin/leg

Washington RCW 90.48.020 Wherever the words “waters of the state” shall be used in this chapter, they 

shall be construed to include lakes, rivers, ponds, streams, inland waters, underground waters, salt waters and all other surface waters and watercourses within the jurisdiction of the state of Washington. 

http://aspx?cit

Washington, D.C. 

DCMR Title 21, Chapter 11 

Waters of the District or District waters - flowing and still bodies of water, whether artificial or natural, whether underground or on land, so long as in the District of Columbia, but excludes water on private property prevented from reaching underground or land watercourses, and also excludes water in closed collection or distribution systems. 

http://o,63926

West Virginia WVC 22-11-3 “Water resources”, “water” or “waters” means any and all water on or 

beneath the surface of the ground, whether percolating, standing, diffused or flowing, wholly or partially within this state, or bordering this state and within its jurisdiction, and includes, without limiting the generality of the foregoing, natural or artificial lakes, rivers, streams, creeks, branches, brooks, ponds (except farm ponds, industrial settling basins and ponds and water treatment facilities), impounding reservoirs, springs, wells, watercourses and wetlands. 

http://les/22/w

Wisconsin WI NR 103.03 “Waters of the state” includes those portions of Lake Michigan and Lake 

Superior within the boundaries of Wisconsin, and all lakes, bays, rivers, streams, springs, ponds, wells, impounding reservoirs, marshes, watercourses, drainage systems and other surface or ground water, natural or artificial, public or private, within the state or its jurisdiction. 

http://wnr/nr10

Wyoming W.S. 35-11 “Waters of the state” means all surface and groundwater, including waters 

associated with wetlands, within Wyoming. 

http://sS/6547

13