1 American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washingto

n, D.C. 20009 202

- 467

- 2900; fax: 202

- 467

- 2910 www.APPAnet.org

Retrofitting Carbon Capture System s 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 CO 2 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 m ajor technology choices for existing plants include post

- com bustion capture systems using chemical sorbents to isolate and concentrate CO 2 , and reconfiguring the unit to use pure oxygen rather than air as the combustion oxidant (yielding flue gas with a mu ch higher concentration of CO 2 ). 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 re trofitting 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 pl ants. 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 CO 2 over a timescale that ex ceeds the scope of traditional risk mitigation instruments, like insurance. These challenges are daunting. Research and policy development are both proceedin g, 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 CO 2 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 co sts 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% i n 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.” 4 Such large emission reduction goals will not be met without significantly r educing 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 an d performance of various options for those new units. 5 With currently available technologies, CO 2 capture and storage options (in saline formations) from these new units cost $30

– 70 per ton of CO 2 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 addr esses those aspects of CCS that are of particular interest to retrofitting this technology on ex isting coal

- fired power plants. With resp ect to retrofitting existing coal units, a 2005 IPCC report concluded: “ Retrofitting existing plants with CO 2 capture is expected to lead to higher costs and significantly reduced overall efficiencies than for newly built power plants with capture. The c ost 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

- R

07

- 002, April 15, 2007. Note that the percentage includes non

- CO 2 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 110 th Congress , Congressional Resear ch 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 CO 2 capture and storage a re 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 3 rd 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, av oi ded costs projected at 30

- 70 $/t CO 2 for new pulv erized coal units and 14

- 53 $/t CO 2 for new IGCC units, p.347. 8 Carbon Cap ture 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://w

ww.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

- fir ed power plants are pulverized coal units. Pulverized coal units have two choices for CCS retrofit: post

- combustion capture of CO 2 using chemical sorbents, and replacing the existing air

- combustion system with an oxygen

- fir ed system, ther eb y creating a flue gas which is mostly CO 2 . 10
Post

- combustion CO 2 capture Figur e 1 depicts a post

- combustion CO 2 capture system. In this system, an acid gas sorbent vessel is placed downstream of conventional pollution capture systems. CO 2 is absorbed into an appropriate chemical, su ch as an amine, which is heated in a separate vessel to release a high concentration stream of CO 2 and the regenerated sorbent. The concentrated CO 2 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 CO 2 from the sorbent and to compress the concentrated CO 2 . In a study of capture technology a t gr eenfield, or new, power plants, NETL 11 concluded that whether the plant was subcritical or supercritical in design, the CCS system re sulted 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 one

half the power needs related to CO 2 compression, about one

- fourth was attributable to the CO 2 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 CO 2 capture system (alone) requires abou t twice as much cooling water as the original power plant. An additional complexity of the CCS

- equipped system is an SO 2 polishing unit. For a high sulfur (IL #6) coal system, even a 98% efficient wet FGD system exhausts flue gas with about 40 ppm SO 2 . 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.
T he various pieces of hardware required for CO 2 capture and compression require space. NETL re ports 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 comp re ssion 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 CO 2 capture systems on existing units which are already space

- limited due to previous ret rofits for SO 2 , NOx, and mercury control systems.

10 An innov ative multipollutant ammonia

- based capture technology is currently being investigated by U.S. DOE, in collaboration with Powerspan Corporatio n. The lack of publicly available data on a commercial version of this technology preclude its inclusion in this analysis. Additional in formation is available at: http://www.n etl.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. , Co st 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

- AT 26

- 04NT42070, August 2007, p.2

- 42.4

Regarding technology readines s, the 2007 NETL report states: “The post

- combustion CO 2 removal technology for the PC and NGCC cases is immature technology. This technology remains unproven at commercial sc ale 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 i s composed prim arily of CO 2 , 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% CO 2 . 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 CO 2 injection and storage. For purposes of this paper, this oxygen

- based approach to CO 2 capture will be termed “ oxy - com bustion”, even though it is actually another form of “post

combustion” CO 2 capture. In the oxy

- combustion system, some of the CO 2 from the flue gas (about twice the volume of the oxygen supplied) must be recycled to reduce combustion gas temperat ures from 3500 oC to a boiler tolerant 1900 oC. Oxy

- combustion raises the possibility of reduced cost for downstream clea nup of traditional pollutants, either by storing them with the CO 2 or by reducing the volume of the flue gas stream dramatically throu gh elimination of nitrogen oxide and use of CO 2 re cycle. 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 ther ma l efficiencies tha n possible with other approaches to CO 2 capture. The major drawbacks to this approach for CO 2 capture are large parasitic power requirements, prim arily for oxygen production and CO 2 com pre ssion, and the cost of the oxygen production facility. Ongoing res earch into improved techniques for oxygen production may mitigate these drawbacks to some degree. With current technology, cost and parasitic power needs for oxy

combustion are about the same as for post

- combustion CO 2 capture. The potential advantages f or oxy - combustion CO 2 capture are speculative at this point. It may be easier to locate an oxygen plant than a CO 2 sorption tower at an existing plant, where access to flue gas is already encumbered by retrofit SO2 scrubbers and other hardware installed a fter 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 CO 2 capture, and to a coal unit with oxy - combustion CO 2 capture. NETL examined both supercritical and ultra

- supercritical designs. 18 Table 1 present s 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 pulv erized coal power plants, the traditional technology for burning coal to produce electricity. “NGCC” stands for natural gas com bi ned 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 t hrough 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 CO 2 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 pla nt heat rate, Btu/kwh 8,649 12,538 12,074 Net pla n t 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 CO 2 avoided n.a. 63 52 SO2 emissions, #SO2/mmBtu 0.085 Negligible 0.003 NOx emissions, #NOx/mm Btu 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 SO 2 and NOx, they can be a 25

- 40% cost incr ease 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 po wer. At a retrofit unit with 33% en ergy conversion efficiency, a loss of 12% (absolute) efficiency m eans 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 plan ts, will introduce a major cost barrier to retrofitting existing units for CO 2 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

- ste p regulatory process). 19 Consider the comparative difficulty of retrofitting CO 2 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 CO 2 capture and compression systems, versus roughly 100 GW of SO 2 scrubbers and NOx selective catalytic reduction system s under CAIR. A fina l issue specific to existing units is that a different level of CO 2 capture performance may be appropriate for those units. Most technical studies assume a high level, e.g., 90%, of CO 2 capture for new units 20 . 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 le vel 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 exa mine 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 possibl e 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 ma jor 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 CO 2 capture, particularly retr ofit units. Dispatching costs for these units will be much greater due to the higher fuel consumption, and purchase of re placement 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 natur al 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 cos ts for the new pla nt figures in the NETL report. Figure 4 presents dispatching costs for a range of carbon taxes (0

- 100 $/metric ton CO 2 ), for coal and natural gas. Additionally, the costs in the figure re flect purchase of makeup power to replace the pow er 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 CO 2 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 t he CO 2 , and a “hybrid” approach of controlling half the CO 2 and paying the tax for the remainder. These calculations are imprecise, but they indicate that until CO 2 taxes or cap/trade costs exceed about $50/ton CO 2 , coal units without capture (and paying a CO 2 tax) will be dispatched ahead of coal and natural gas units with capture. Other factors, such as subsidies paid to units that capture CO 2 and improvements in the technology, could certainly impact these results dramatically. For perspective, S.1766 (Senator Bingaman’s climate change bill), which becomes progressively mor e stringent over time, begins with a “safety valve” price of 12 $/ton CO 2 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, howev er, utilities operate most those units with the least v ariable costs (which include fuel consumption and variable operation and maintenance costs). If these v ariable 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 Performan ce Baseline for Fossil Energy Plants

.7

A key parameter in these cost comparisons is the cost of repl acement 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 als o 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 variabl e 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 differ entia l effect of who supplies the replacement power c an be seen in comparing Figures 4 and 5. The coal

- based systems with CCS show a significant reduction in dispatching costs for the “self

generated” replacement power case (Figure 5), relative to the “purchased power” CCS case (Figur e 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 CO 2 , to $20/ton CO 2 for the self

- generated re placement power scenario. The NGCC systems are not as sensitive to the source of the re placement 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 her e is not the absolute values of these projected costs, but rather the fact that analysts and decision

- ma kers must be careful regarding how th es e 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 ex ceeds 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 ex cess power will quite likely lose that source of electricity. Hence, the sudden broad deployment of the current generat ion 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 liter ature. 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. Ther e is experience with pipeline transport and injection/storage at relatively small scale, b ut 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 m illion TPY” demonstration projects, but results are years a way. 3. Ther e is no environmental regulatory framework for addressing the injection and storage of CO 2 in the most likely resource for coal

- fir ed power plants: saline geological formations perhaps one mile below the surface. EPA recently announced its inten t 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. Ther e is likewise no framework for addressing financial liability associated with CO 2 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 embr ace CCS technology until pragmatic frameworks are established. Regulatory Issues for Retrofits Clean Air Act Permits and Federal New Source Review Issues As ide from the obvious regulatory issues associated with CO 2 capture and storage that include per mi tting 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 re trofit being deemed a “major modification of a major Clean Air Act

- re gulated source.” 25 This is because the CO 2 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, mo deling of air quality impacts, and installation of state

- of

the

- 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 regu latory 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 SO 2 and NOx retrofits installed pursuant to the 2005 Clean Air Interstate Rule (CAIR) because the SO 2 and NOx pollution control equipment ma y lea d to small incr eases of pollutants other than SO 2 and NOx. 26 However, even if the NSR exemption for “pollution control projects” st ill existed 27 , typical re trofits 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 SO 2 , the additional reduction of that pollutant that occurs as part of the CO 2 capture process will negate the increased amount of combustion. For others, like particulate ma tte r, the situation is not as clear. In addition, some of the components of the CO 2 captu re

24 It is important to note that in some states, ownership of surface rights does not conv ey ownership of subsurface mineral or other rights needed for th e 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 contro ve rsies, but instead call s 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 representativ es 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 pol lu tion 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. In creases 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 t he courts interpret the regulations, as well as possible emission mitigating measures that the retrofit facility might undertake.9

system ma y be sources of fugitive emissions of various pollutants regulated under the Clean Air Act. NSR Review of CO 2 and Other Green House Gases (GHG)
CO 2 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 CO 2 and five other GHG from motor vehicles and possibly refineries by the end of 2008. The regulation of CO 2 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 GH G are regulated to define what a “major source” of GHG is, and even mor e importantly, what “significant increases” of GHG are for purposes of defining the term “m ajor modification.” 31 Assuming CO 2 and other GHG become r egu lated air pollutants, a signific ant 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 SO 2 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 SO 2 scrubbers, also could trigger “major modification” status for that facility for CO 2 , in the abse nce of the now

- defunct “pollution control exemption”. This would lead to case

- by

- case Best Available Control Technology (BACT) reviews for CO 2 emissions. Reconstruction and Clean Air Act New Source Performance Standards If a facility retrofit constitu te s 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 stat es’ 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 CO 2 emissions from mobile sources, and that regulation will likely trigger requirements for new or modified major stationary sourc es such as power plants if they have more than de minimis increases in CO 2 em issions. 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 def ines 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 v arious affected industries can be search ed 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 requi re d t o 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 depr eciable component s. 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 contro l” 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 r uling 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 CO 2 emissions can only exist after EPA adopts a CO 2 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 Ther e is general recognition that the current underground injection control (UIC) program for waste injection is not well designed to address issues associated with CO 2 storage in deep saline re se rvoirs. The Interstate Oil and Gas Compact Commission (IOGCC) recently proposed that states take the lea d on this type of regulation, given their extensive regulatory experience with CO 2 - based enhanced oil recovery. 34 Moreover, IOGCC expressed the view that CO 2 should be treated as a resource, rather than as a waste, and that treatment of CO 2 as a wa ste “would diminish significantly the potential to meaningfully mitigate the impact of CO 2 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 rul ema king, under the authority of the Safe Drinking Water Act, to address underground injection of CO 2 . 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 exa mination 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 CO 2 in Geologic Structures

– A Legal and Regulatory Guide for State s 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 storag e 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 CO 2 Storage ” , Inside EPA , October 12, 2 007, citing an Oct 11 announcement by EPA Administrator Stephen Johnson.11

Other liabilities Tw o additional areas of risk management related to CO 2 storage are: 1. The potential for stored CO 2 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 CO 2 migration after closure of the injection site. Injection of CO 2 from an operating plant may last for decades, but for the storage to be effective, the CO 2 must be contained for centuries. This timeframe is beyon d the scope of available commercial risk ma nagement issues. Effectively managing these risks may require government participation, and that may require additional legislative authority. Looking to the future Ther e is much ongoing activity related to CC S. 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 CO 2 storage, and initial regulatory resp onses to Massachusetts versus EPA are likely by the end of 2007. Climate cha nge mit igation legislation is receiving much attention in Congress. Nevertheless, given the significant contribution of existing coal

- fired power plants to both the nation’s elec tricity 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 CO 2 emission group seem quite limited. Additional e ffort appears warranted to:

§ Significantly drive down the cost of CO 2 capture, both through “learning by doing” using current technology, and through additional research.

§ Explor e 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 parasi tic power needs to drive the CCS hardware.

§ Gain experience with storing large quantities of CO 2 in differ ent types of geologic saline structures. The Regional Partnerships program may be a good start, but a few large projects are unlikely to be representa tive of the full range of geologies in the U.S. that are attractive for CO 2 storage

§ Increase our knowledge base and simplify traditional preconstruction permitting procedures to expedite the permitting of CCS retrofit projects.12

Ab out the aut hor

– Doug Carter is an independent consultant on energy technology and re lated environmental issues. His current practice focuses on advising clients regarding advanced coal

- based technologies and their potential role in mitigating global climate cha nge. 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 degr ees in Mechanical Engineering and Environmental Engineering. He can be re ached at Carter2250@comcast.n et

. The Amer ican 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 dedica ted 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, Dir ector, Environmental Services, 1875 Connecticut Ave, NW, Suite 1200, Washington, D.C. 20009

- 5715 or at (202) 467

- 2943

See pag e 13

- 1 6 for figures13

Figures Figur e 1. Pulverized coal power plant with carbon capture.

Figur e 2. Sour ces 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 CO 2 Scrubbers

Steam Turbine Sulfur By Products

Generator Stack

Drying & Comp

.

Electric

Power Coal & Air Sequestration Ready CO 2 CO 2 Capture

NOx Removal (SCR)

Condenser14

Figur e 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 CO 2 Drying & Comp

CO 2 Capture NOx Removal (SCR)

Note: CO 2 recirculation may be taken from before or after the FGD system, depending on SO 2 concentrat ion.15

Figur e 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 CO2Variable 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 gas16

Figur e 5. Dispatching costs as suming 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 CO2Variable costs, $/MWhr

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

ing tax NGCC w/90% capture, Ref. Price gas NGCC w/90% capture, $6.63 gas2 

### GEOLOGIC C O SEQ UESTRATIO N ISS UE SPOTTING A ND ANA LYSIS WHITE P AP ER

Timot hy R Gablehouse 1 

### Gablehouse Calkin s & G ranberg LLC

July 22, 2009 OBJECT IVE This paper

has bee n prepa

red f or APPA’s elec tric utility members a

nd water utilit ies for the purpose of

survey ing the wide ra

ng e of issues that will influenc e the implementation of
g eolog ic ca

rbon seque stration. As with many things, seque stration is not as simpl e as it see ms. I njection of a

ny thing into the subsurfa ce is re g ulated. Which ag encie s will act to reg ulate and the cr iteria they

will follow depends upon the a nswer to the que stions raised in this paper – questions that Congre ss and state leg islatures will need to a ddress if se questration is to be

2 

### implemented on a sc ale r emotely adequate to make a

differ ence in the amount of CO rea ching the atmosphere

. Wit hout a doubt sequestra tion projects will go f orwa rd. Many are alre ady

underw ay
. Nothing in this Whit e Paper should chang e any one’s view on the technolog y

available for
g eolog ic seque stration. Nor should any one re ad this paper to sugg est that there are fata l leg al impediments to these projec ts. There are substantial leg al issues and a prudent mana g er w ould be we ll advised to fac tor these issues into the business plan for a seque stration projec t. Much of this pape r looks at the existi ng rules that apply to ge ologic sequestra tion. From wher e we stand today

it is t hese r

ules that will apply

absent a ction by

leg islative bodies. For

2 

### example, if the CO being injected is a w aste we next need to know if its hazardous waste a nd

T i m o t h y G a b l e h o u s e i s t h e m a n a g i n g p a r t n e r o f t h e e n v i r o n m e n t a l l a w f i r m o f G a b l e h o u s e C a l k i n s & G r a n b e r g 1 L L C i n D e n v e r C o l o r a d o
. 4 1 0 1 7 S t , S t e 1 3 7 5 D e n v e r C O 8 0 2 0 2 t h t g a b l e h o u s e @ g c g l l c
. c o m 

### 1

### reg ulated under RCR A. I f injection is limit ed to produc ing oil and g as oper ations for e nhance d

rec overy , then injection will be re g ulated by the state a g encie s that permit oil and g as
opera tions. The policies a nd proce dures of

these a g encie s and which pe rmits might be re quired 2



### are sometimes radica lly

differ ent state-by -state ha ving the potential to drastically chang e the
reg ulatory

burden a nd economics of

any projec t. Common l aw theor ies dea ling with tre spass, mineral r ights a nd water rig hts all are implicated as injec tion may result in trespass or

harm to surfa ce pr operty rig hts, mineral rig hts or
water rig hts. Depending upon in which state injec tion operations occ ur, there are signific ant

2 

### questions reg arding the owner ship and ac cess to the subsurf ace space s where the CO will be

2 

### place d. As the CO is intended to remain in the g round in perpe tuity , then we a lso need to examine who rema ins responsible in perpe tuity . Reg ardle ss of whethe r these e ntities are pr ivate
corpor ations or public entities long -term liability issues will need to be a ddress a nd understood. Absent newleg islative action existi ng statutes such a CERCL A (“ Superfund” ) will play a role which mea

ns that the landowne r, minera l owner, injec tion operator a nd the entity

that produce d

2 

### the CO all may

have some liability

in perpe tuity

. I t’s important to understand wha t this W hite Paper is not intended to ac complish. W hile it will i dentify

a broa d rang e of pr operty and liability

issues associate d with injection projects, it will not sugg est solutions t o all of them. I t will not address the ra ng e of liability

issues associate d with the high- pressure pipeline infra structure nece ssary to move acid g ases f

rom the

2 

### point of g ener ation to the point of injection. For g eolog ic CO sequestra tion to become broa dly viable ther e will need to be predic tability on how these issues a

re ha ndled. Many

will have no predic table solution until and unless we have f eder al and state leg islation.

A c i d g a s i n

j e c t i o n f o r e n h a n c e d r e c o v e r y o f o i l & g a s i s d i f f e r e n t f r o m h y d r a u l i c f

r a c t u r i n g w h i c h i s a l s o u s e d t o 2
e n h a n c e r e c o v e r y b y p h y s i c a l l y o p e n i n g t h e s u b s u r f a c e f o r m a t i o n s u s i n g v e r y h i g h p r e s s u r e , p r o p r i e t a r y f o r m u l a s a n d p a r t i c u l a t e s t o h o l d t h e f r a c t u r e s o p e n
. 

### 2

### BACK GR OUND

2



### Much work ha s g one into the technic al re view of g eolog ic CO sequestra tion. (F reque ntly

this is refer

red to more g ener ically

as ca rbon ca pture a nd storag e or “ CCS ” – the

rema inder of this pape r will utili ze this nom encla ture.) Some wor k has g one into potential
reg ulatory

prog rams base d upon extensions of the curre nt EPA Underg round I njection Control (“U I C”) prog ram. EPA has pr oposed a r eg ulatory approa ch which is the topic of a September 10, 2008 Whit e Paper

available to rea ders. ( As nothing ha s rea lly chang ed on this front, this Whit e Paper

will not cover that e ffor

t in any detail.)
Some states are adopting reg ulatory prog rams with var ious deg ree s of complexity . I n
g ener al they

are based upon e x isting UI C prog rams or on injec tion of “ac id ga s” for production enhanc ement in exist ing oil or g as oper ations. These c an be r adica lly differ ent appr oache s and the interna l politi cal situation along with the perc eived importanc e of the oil and g as industry has a lar g e impact.
I t is critical to distinguish betwee n production enha nceme nt injection prog rams and

2 

### injection of CO solely

for se questration purpose s as they are radic ally

differ ent in intent, liability , risk and re g ulatory reg ime. A minera l owner ty pically has substantial rig hts to use techniques suc h as fluid injection in order to produce the “miner als” like na tural g as and petroleum. Oil and g as produc tion companies have substantial experience with this activity and tend not to view it as very risky even thoug h it’s curre ntly benig n reg ulatory

posture is under attack.
As an e x ample, the long -term liabilities associate d with production enha nceme nt versus CCS scena

rios have substantially

differ ent leg al postures. F or example, a land ow ner or even a n impacted ne ighbor

may have pr oducts liability

claims ag ainst the produce r of the injec ted

3

### enhanc ement fluid should it cause a dverse impacts outside of the na tural g as or pe troleum

production pool. I n a CCS project we w ould instead nee d to look to C ERCL A or RCRA for 3

2 

### g uidance on long- term re sponsibili ty for the CO

. Not resolved to a

ny satisfac tory

deg ree are the questions of leg al ac cess to prope rty for the purpose of

CCS , whether

it is waste disposal or something e lse, liability for the e ntire host of things that pe ople ca

n imag ine might g o wrong , and long -term maintena nce/monitoring . All one need do is e x amine EPA’s 2008 Te chnica l Support Document entitled “Vulne rability Evaluation
Fr amewor

k for Ge ologic Sequestration of Car bon Diox ide” to g et a se nse of the c omplex ity of the problem a

nd the difficulty

of asse ssing potential r isks. 4


### That these r isks are a

rea l conce rn whe n it comes to permitting a nd opera tion should be obvious. Som e examples may help to illumi nate the r isks that the public will fear:

- Fluid injection is suspected of causing Texas ear

thquakes. W

all Street Journal , J une 12, 2009, Pag e A3.

- Earthqua

kes ca used by deep w ell injection of wa stes at Rocky Mountain Arsena l. http:// ear thquake.usg s.g ov/reg ional/states/colorado/history .php

2 

### - Cry stal Gey ser UT – CO cold wate r er uptions through a

manmade w ell. http:// www.uwe b.ucsb.edu/~g lennon/cry stalg ey ser/

- 1986 L ake N y os eruption and de aths.

- “CCS mobi liz ation of hazardous, na turally occur ring materia ls is a risk that must be char acte rized.” “I njection into saline forma tions has the potential to disturb reg ional g round-water flow sy stems and could contaminate drinking water .” Para phrase d from the testimony

of Dr. B urruss, USGS, Subcommitt ee on E nvironment and Hazardous Ma terials, House Commi ttee on Ene rg y and Commerce , J uly

24, 2008

2 - 

### Transpor

tation infrastruc ture to transpor t CO to injection sites does not ex ist – USGS projec ts that an infra structure larg er tha n the exist ing natural g as/petroleum industry will be require d to achieve meaning ful levels of CCS. h t t p : / / e n e r g y . e r
. u s g s
. g o v / h e a l t h

_ e n v i r o n m e n t / C O 2

_ s e q u e s t r a t i o n / C O 2

_ i l l u s t r a t i o n s . h t m l

S e e M o d e s t o , C i t y o f v . T h e D o w C h e m i c a l C o
. , e t a l

. , N o
. 9 8

- 9 9 9 3 4 5 , C a l i f

. S u p e r
. , S a n F r a n c i s c o C o
. ( l i a b i l i t y 3 b a s e d o n p r o d u c t s l i a b i l i t y t h e o r i e s f o u n d f o r d r y c l e a n i n g f

l u i d o f f

- s i t e i m p a c t s ) 4 h t t p : / / w w w . e p a
. g o v / c l i m a t e c h a n g e / e m i s s i o n s / d o w n l o a d s / V E F

- T e c h n i c a l

_ D o c u m e n t

_ 0 7 2 4 0 8

. p d f 

### 4

### ISS UES an d DISCUSS ION

I. Liab ility During In jec tion / Op erat ional L iabil ity Oper ational liability

includes the e nvironmental, hea lth, and safe ty risks associate d with

2 

### CO captur e, tra

nsport, and injection. Enha nced f luid recove ry

contra ctors ar e alr eady

subject to a duty of ca re de fined unde r tort law a nd are usually

subject to standar ds of conduc t under their
contra ctual ar

rang ements. Companies providing these spec ific ser vices ha ve experienc e in their industries, and ar e subjec t to liabili ty for wor ker sa fety and prope rty

damag e re sulting fr om their conduct. The se compa

nies are best positioned to manag e the r isks associated with their ow n conduct a nd are able to obtain liability insurance for their

conduct a

nd worke rs. I n survey s and

5



### case studies, these compa nies wer e willing to pr ovide servic es on a c ommercia l basis and
g ener ally willing to ac cept liability for their actions. 6


### Howeve r, it is forese eable that larg e-sc ale CCS could make it less likely that companies will be willing to ac cept liability for injec tion. For e x ample, if ther e wa s contamination at the surfa ce dur ing injec tion operations it could potentially aff ect dr inking wa

ter. The re is cur

rently no law prote cting commerc ial or public oper ations from the full ra ng e of liabilities should they

cause contamination.
I n theory g overnme nt ag encie s could conduc t the injection opera tions to l imit l iability associate d with injection. An example of this is L awr ence v. Bue na Vista Sanitation District. 7 

### Neig hbors broug ht a trespa ss claim ag ainst the sanitation district, alleg ing c ontamination from leaka g e at the district' s wastewa ter tre atment fa cility

but did not arg ue that neg lige nce w as

M

. A

. d e F i g u e i r e d o , D

. M

. R e i n e r , H

. J

. H e r z o g , T o w a r d s a L o n g - T

e r m L i a b i l i t

y F r a m e w o r k F o r G e o l o g i c C a r b o n 5 S e q u e s t r a t i o n , P r e s e n t e d a t t h e S e c o n d A n n u a l C o n f e r e n c e o n C a r b o n S e q u e s t r a t i o n , A l e x a n d r i a , V a
. M a y 2 0 0 3

. C r a i g A

. H a r t , A d v a n c i n g C a r b o n S e q u e s t r a t i o n R e s e a r c h i n a n U n c e r t a i n L e g a l a n d R e g u l a t o r y E n v i r o n m e n t : A 6 S t u d y o f P h a s e I

I o f t h e D O E R e g i o n a l C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p s P r o g r a m , D i s c u s s i o n P a p e r 2 0 0 9

- 0 1 , C a m b r i d g e , M a s s
. : B e l f e r C e n t e r f

o r S c i e n c e a n d I n t e r n a t i o n a l A f f a i r s , J a n u a r y 2 0 0 9 ( f

i n d i n g d r i l l i n g c o m p a n i e s w i l l i n g t o p a r t i c i p a t e i n C C S a n d a c c e p t l i a b i l i t y f o r t h e i r a c t i o n s )

. L a w r e n c e v . B u e n a V i s t a S a n i t a t i o n D i s t

. , 9 8 9 P

. 2 d 2 5 4 ( C o l o
. A p p
. 1 9 9 9 ) 7 

### 5

### prese nt. The cour t held that the district was immune fr om a trespa ss claim under G overnme ntal
I mmunity Act “unle ss neg lige nce is prove n”. Tre spass is not a dang erous c ondition of a public
water fac ility or public sanitation fa cility ; beca use the tre spass claim did not require proof of
neg lige nce it wa s barr ed by Gover nmental I mmunity . Nobody should take this sort of outcome as an indica tion that gove rnment ag encie s can c onduct these ope rations with impunity – there are
many other a vailable theor ies of liability

. II. P ost Inject ion L iabil ity
A. Own ership of

P ore Space The surf ace owner

usually owns pore spa ce be cause mineral c onvey ance s, including lease s, normally

only pass title to the minerals, not the pore space itself. That does not, howe ver, end the c onversa tion over who c ontrols the pore spa ce pr operty rig ht. The surfa ce ow ner c annot violate the minera l estate owne r’s or le ssees’ r ights by doing some thing inter fer ing w ith acce ss to the minerals, making the minera ls more expensive to expl oit or making the deve lopment of the minera ls economica lly impractica l. Clearly

injection into the pore spac e could c ause this sort of har m. The surfa ce ow ner must also allow re asonable use of the pr operty to give acc ess to the mineral e state. For

CCS projec ts to procee d it is som ewha t rec kless to assume that ag ree ment 8


### with the surfa ce ow ner is the only nece ssary

step. I t seems prude nt to have ag ree ments with both surfac e and miner al owner s even thoug h it seems likely that the surfa ce ow ner ow ns the
pore spa ce. 9


### B. Risk of

Leakage Post-injection liabili ty

includes har

m to human health, the envir onment, proper ty , and the climate liability

rela ted to leaka g e or mig ration of c arbon dioxide from g eolog ical re servoirs a nd

C a s s i n o s v . U n i o n O i l , 1 4 C a l

. A p p
. 4 t h 1 7 8 5 ( 1 9 9 3 ) 8 G e o l o g i c C O 2 S e q u e s t r a t i o n : W h o O w n s t h e P o r e S

p a c e ? , 9 W Y L R 9 8 , 2 0 0 9

. 9 

### 6

### the ef

fec t on climate cha

ng e. Potential pathway s for c arbon dioxide relea se include le akag e throug h the pore s of low-pe rmea bility cap r ocks if the c arbon dioxide is inj ecte d at too high a
pressure , leaka g e throug h opening s in the cap r ock, lea kag e throug h abandone d or improper ly seale d wells, and mig ration via fa ults. 1 0 

### Reportedly , there is a low risk of ca ptured c arbon le aking into the atmosphere in amounts

2 

### signific ant enoug h to pose a risk. CO and natur al g as has be en stored naturally in ge ologic 1 1


### formations for

milli ons of y ear s and compa nies alre ady

store natur al g as under g round with a lot

2 

### of experienc e. The re a

re na turally

occur ring CO rese rvoirs in the we stern states that have held

2 

### g as for milli ons of y ear s. Furthe rmore, ove r 100 million t ons of CO has bee n injected into oil

rese rvoirs for

enhanc ed fluid re cover

y as we ll as into deep saline a quifers ( over 80 pr ojects have been implemente d worldwide)

. Commercial and e x perimenta l projects have shown the 1 2 

### potential for CCS across a wide ra ng e of g eolog ical setting s. There are , howeve r, re ports sug g esting that an exceptionally detailed a

naly sis of g eolog ic

2 

### conditions is critical to understanding how the CO is being sequester ed in ea ch ca se. Whether

2 

### CO is being mineral tra

pped, in which c ase it may be stable on g eolog ic time scale s, versus dissoluti on in gr oundwater is critical to an a ssessment of whe ther a potential for lea

kag e is
prese nt. Dissoluti on in gr oundwater is not prefe rre d as it has the g rea test potential for e ventual leaka g e to the atmospher e. 1 3

2 

### The long -term liability

associate d with CO leaka g e that dama g es hea lth or proper ty is difficult to establish beca use it is dissi milar to other re g ulatory scheme s and has a

timeframe of thousands of y ear s. We simpl y do not know what risks long -term g eolog ic storag e pre sents.

I P C C , I P C C s p e c i a l r e p o r t o n c a r b o n d i o x i d e c a p t u r e a n d s t o r a g e ; 2 0 0 5

. 1 0 F e i d m a n , T h i s w o r k p e r f o r m e d u n d e r t h e a u s p i c e s o f t h e U

. S

. D e p a r t m e n t o f E n e r g y b y L a w r e n c e L i v e r m o r e 1 1 N a t i o n a l L a b o r a t o r y u n d e r C o n t r a c t D E

- A C 5 2

- 0 7 N A 2 7 3 4 4 R o c k y M o u n t i a n M i n e r a l L a w I n s t i t u t e 1 2 A e s c h b a c h

- H e r t i g 

### , C l e a n C o a l a n d S p a r k l i n g W a t e r , N A T U R E , V o l 4 5 8 , P a g e 5 8 3 , A p r i l 2 0 0 9

. 1 3 

### 72



### Ex posure to CO ty

pically is not dang erous e x cept in ver y high c oncentr ations (> 15,000 ppm).
For example, in L ake N y os 1,500 people died w hen a la ke over a mag ma pool rele ased la rg e

2 

### amounts of CO . This is unli kely to occur at injection wells whe n proper ly monitored.

2 

### Resear cher s have suc cessf ully plugg ed and a

bandoned CO injection wells, eve n badly damag ed

2 

### and fa iled wells. I n wells that have failed a nd rele ased CO , almost all were detec ted quickly and stopped. 1 4 

### EPA produce d a Jul y

2008 white pape r entitled Approaches To Ge ologic Sequestration Site Stewardship After Sit e Closure

. They descr ibe the adva

ntag es and disadva

ntag es of 1 5


### stakeholder

develope d models as well as mode ls based upon existi ng fede ral law s rang ing f rom the Nucle ar I ndustries I ndemnity Act throug h CERCL A. I f CCS i s viewed a s waste disposal the
“cr adle- to-g rave ” model of the RCR A and pe rpetua l nature of liability under CERCL A would be

2 

### inconsistent with any

eff ort to limi t responsibility

for injec ted CO and espe cially any potentially hazardous conta

minants entrained in the injec ted mater ials.

2 

### EPA’s ana ly sis has been c riticized as unrea listi c g iven that g eolog ic storag e of CO is intended to be indef

inite and well bey ond 50 y ear s. The author s of a r ece nt report view this as the sing le g rea test leg al obstacle to commerc ial deploy ment of CCS. Quite obviously ,

1 6 

### leg islation will be re quired to addr ess this issue if there is to be a ny time limi t on liabilit y .

2 

### C. P ropert y Rights Issu es Re lated to Migr ation of Inject ed CO 1. Natural G as Storage Law May P rovide Som e Insight

S

. J u l i o F r i e d m a n n , C a r b o n M a n a g e m e n t P r o g r a m A P L G l o b a l S e c u r i t y P r i n c i p l e D i r e c t o r a t e , L L N L

. . S

. 1 4 D e p a r t m e n t o f E n e r g y b y L a w r e n c e L i v e r m o r e N a t i o n a l L a b o r a t o r y u n d e r C o n t r a c t D E

- A C 5 2

- 0 7 N A 2 7 3 4 4 1 5 h t t p : / / w w w . e p a
. g o v / O G W D W / u i c / p d f s / s u p p o r t

_ u i c

_ C O 2

_ s t e w a r d s h i p f o r s i t e c l o s u r e . p d f W o r l d C l i m a t e C h a n g e R e p o r t , 8 7 W C C R , 0 5 / 0 8 / 2 0 0 9 , B N A

. 1 6 

### 8

### Gas that is injected f or storag e re mains the proper ty of the injec tor. I njection of g as 1 7 

### into property

that the injector doe s not own is a trespass. Pore spac e for such projec ts can be 1 8 

### purcha sed or lea sed fr om the landowner , and/or the miner al estate owner , so long a s it does not damag e other

persons. Ag ree ment with the mineral e state owne r or lesse e will g ener ally be 1 9 

### prudent in orde r to avoid later damag e or tre spass claims as ther e is ambig uity in some states
reg arding whether

a minera l owner ow ns the pore spa ce pr eviously occupie d by

the minera ls,
natura l ga s or petrole um they have r emoved. L iability for ne g lige nt opera tion of storag e 2 0


### opera tions ex ists. 2 1


### Under many fede ral a nd state laws utility

companies ha

ve eminent domain r ights for utilit y fac iliti es. This beg s the question of whe ther CCS operations repr esent a utilit y fac ility under the se statutes – if viewe d as wa ste disposal, there is doubt. These statutes do not addre ss the ability to exercise eminent domain r ights ove r buff er zones that may

be desira ble bec ause of the potential for g as mig ration. B uffe r zones should be included be cause g as esc ape is a trespass; howe ver, howsuch a buf fer might be va lued in an eminent domain a ction is unknown. Wit h reg ards to ca

rbon seque stration the conc ept of c ondemnation poses seve ral problems. CCS pot entially involves larg e ar eas of

land – hundre ds of ac res - depending upon the subsurfac e conditions and re sulting ava ilable storag e volumes. The unc erta inty over w hether 2 2 

### statutory authority to exercise imminent domain applies sug g ests an initial effor t to neg otiate and purcha se rig hts. I f injection re quires appr oval from a ny landowner

that could be a ffe cted, then it

E l l i s v . A r k a n s a s L o u i s i a n a G a s C o
. , 4 5 0 F

. S u p p
. 4 1 2 , 4 1 9 ( D

. C

. O K L 1 9 7 8 ) a n d m a n y o t h e r s 1 7 K u n t z , T h e L a w o f O i l a n d G a s s 2

. 6 , p
. 7 1 1 8 E l l i s , a t 4 5 0 F

. S u p p
. 4 1 2 1 9 G e o l o g i c C O 2 S e q u e s t r a t i o n : W h o O w n s t h e P o r e S

p a c e ? , 9 W Y L R 9 8 , 2 0 0 9

. 2 0 I n a r e c e n t c a s e f

r o m L o u i s i a n a a j u r y a w a r d e d $ 9

. 2 M t o a p e t r o l e u m c o m p a n y w h o s e a b i l i t y t o e x p l o i t r e s e r v e s 2 1

w a s a d v e r s e l y i m p a c t e d b y i m p r o p e r m a i n t e n a n c e a n d o p e r a t i o n o f a n e i g h b o r i n g s a l t d o m e s t o r a g e f a c i l i t y . S e p a r a t i o n a n d c a

p t u r e o f C O 2 f r o m l a r g e s t a t i o n a r

y s o u r c e s a n d s e q u e s t r a t i o n i n g e o l o g i c a l f o r m a t i o n s - - 2 2

c o a l b e d s a n d d e e

p s a l i n e a q u i

f e r s
. J A i r W

a s t e M a n a g A s s o c
. 2 0 0 3 J u n ; 5 3 ( 6 ) : 6 4 5

- 7 1 5 

### 9

### will be nece ssary to secure consent fr om a potentially larg e number

of people . Neg otiation and condemna tion will t here fore impose high c osts and long a cquisition ti mes. As it will not be the intent (in most case s) to later r etrieve the g as, there are interesting questions and serious unknowns r eg arding the rig hts and duties of the prope rty owner s later in

2 

### time. Establishing owne rship of CO in perpe tuity is a key part of this problem, e specia lly g iven the vast amounts of time it will be sequester ed. I f there is no intent to recover perha ps there is

2 

### no duty to protect a

nd prese rve the CO or the a ssociated surf ace fac iliti es. I f the e ntity that

2 

### owned the CO when it was injec ted disappea rs, then whe ther the CCS process is wa ste disposal or something else will be c ritical to understa nding the on-g oing duties of the landowne r. Any resolution of this issue will require leg islation.
2. Enh anced Oil Recover y Oil and g as lea ses ty

pically contain the r ight to inject f luids to aid in t he produc tion of
g as or oil, but not for disposal of wa ste. L ease s and state law s often g ive the produc er the rig ht to “unitiz e” f

or sec ondary

rec overy allowing injection in various locations of a field. These

2 

### enhanc ed re cover

y eff orts are not nece ssarily

desig ned to seque ster CO even if “ac id ga s” is used. Given the lease /contrac t rig hts these proc esses a re pr obably

not a g ood mecha

nism to examine the broade r liability issues associate d with CCS projec ts unassociated w ith oil and ga s production. As noted bef

ore liability

for the injec ted mater ials, such as hy draulic f rac turing fluid or acid g as, exists reg ardle ss of why these mate rials wer e injecte d. Contract or le ase the ories will apply and may be of va lue in the short-ter m until t he norma l statute of limitations runs. B ey ond these theor ies liability

is likely perpe tual under f

eder al environme ntal laws as these fluids will

10

### ty

pically contain hazar dous substances. As note d ear lier, produc ts liabili ty theories may

apply to the entity that produce d the fluid if it harms third persons. 3. Waste Injec tion
Wastewater

wells are subject to permitting by EPA and/or states. F ailure to obtain permits or oper ate within the ter ms of a per

mit will make the ope rator subje ct to ag ency enfor ceme nt and citizen suits. Obvious ly the par ty injecting must have the leg al rig ht to do so; howeve r, wha t those rig hts mean will be hig hly varia ble. I n Chance v. BP Chemical, the Supreme Court of Ohio de termined that the de fenda nt committed a trespass whe n chemica ls injected unde rg round mig rate d under pla intiff’s prope rty for whic h no rig hts had bee n acquir ed. Even so, the pr oper e valuation of da mag es is very uncer tain. The c ourt held that the surf ace owner ’s rig hts were not absolute, but were conting ent on the re asonable and for esee able use of their pr operty

. Acc ording to the court, subsurf ace rig hts 2 3


### include the r ight to exclude invasions of the subsurf ace proper

ty that actua lly

interfe re w ith the
proper ty owner ’s re asonable and for esee able use of the subsurf ace
. This would most certainly 2 4


### include har

m to minerals or oil and g as re source s leased by the landowne r. This sort of ana logy

would work we ll for CCS because la ndowner ’s that ar e not har med

2 

### by stored CO would have no c ause of action. I t seems to follow that there would only be a

2 

### cause of ac tion after CO specific ally damag es the he alth or prope rty of a la ndowner – not for specula tion that ga s could potentially leak f rom g eolog ic forma tions or interfer e with ac cess to minerals or oil and g as. Many courts would likely

disag ree and would find diminished value simply due to the tre spass. L eg islation, rather tha n litigation, is by

far the best wa

y to establish the rules in this are na.

C h a n c e v . B P C h e m i c a l , 1 9 9 5 W L 1 4 3 8 2 7 ( O h i o C t

. A p p 1 9 9 5 ) 2 3 I d

. 2 4 

### 11

### 4. Wastewater

I n Cassinos v. Union Oil C o., the owner s of a miner al estate sued def endant f or dama g es when de fenda

nt injected wa stewate r into the mineral e state. The Ca lifornia Appe als Court reje cted the de fenda

nt’s claim that it should not be liable beca use the plaintiff did not establish the extent of damag e to the minera l estate. The court he ld that there w as substantial evidenc e the defe ndant’s ac tions int erf ere d with and damag ed the miner al estate . There fore , the def endant committed a trespa ss. The cour t also held that the plaintiff in the c ase c ould waive the tor t claim and collec t on an alter

native theor

y of contra ct implied in law to rec over the value of the use taken. 2 5


### Fr om Chance ( supra) and Cassinos, it is apparent that a cause of ac tion is not likely to

occur if there is no damag e done. I nterfe renc e with minera l rig hts should be a conc ern be cause CCS can displac e subsurfa ce g ases a nd g roundwa ter, whic h could damag e minera l estates. The holder of a

mineral e state or lea se would have a ca use of a ction along with the surfa ce ow ner. I f the a ctivity

is allowed by

statute it does not nece ssarily mean that the injec tor will be absolved of liability . I n Tidewa ter Oil Co. v. J ackson, the re w ere damag es to plaintiffs' oil wells

as a r esult of wate r flooding opera tions conducted by defe ndant on adjoining proper ty . The Court of Appe als held that whe re de fenda nt's w ater flooding activities wer e intentional and da mag e to wells on adjoining land was f orese eable , defe ndant was liable under K ansas law for da mag e to wells of adjoining lease holders. These f indings we re inc onsistent with the administ rative f indings to the e ffe ct that the
water flooding opera

tions were c arr ied on in a lawf ul manner. I

n the view the c ourt took, it was

unnece ssary

to rec oncile the f

indings. I t was suffic ient that the wate r flooding activities wer e intentional and the conse quence s fore seea ble. A leg al claim wa s available , even thoug h the

C a s s i n o s v . U n i o n O i l C o
. , 1 4 C a l

. A p p
. 4 t h 1 7 7 0 , 1 8 C ( C a l A p p 1 9 9 3 

### ) 2 5 

### 12

### flooding was law fully car ried on, be cause it caused substantial injury to the claimants. This 2 6



### case is important because it highlig hts that reg ulations that allow CCS may not absolve the defe ndant of c ommon law proper ty law liability

. 4. Water Law
I t most of the Western US surfac e and g roundwa ter is a public r esourc e dedic ated to the benef icial use of public a g encie s and private persons whe reve r they might make benef

icial use of the wate r. (Te x as is a bit differ ent in that g roundwa ter be longs to the la ndowner and is not subject to prior a

ppropriation. Tha t can r esult in significa nt fig hts betwee n neig hbors should one pump so much g roundwa ter that a neig hbor’s we ll becomes dry . This law of the “ bigg est pump” has bee n mitigated thr oug h administrative proc esses such a s conser vation districts regulating the use of g roundwa ter. ) Unde r the g ener al weste rn appr oach, inc luding surf ace water in Texas, 2 7


### water quality and quantity

are proper

ty rig hts subject to statutory and common law pr otections. The big g est diffe renc e betwe en wa ter a nd rea l property

is that the protections ava ilable for w ater fre quently

exceed those a

vailable f or re al prope rty

. The rig ht of wate r use include s the rig ht to cross the lands of othe rs to place water into,
occupy and conve y

water throug h, and withdra

w wate r fr om the natura l water bear ing formations within the state in the exerc ise of wa ter use r ight. Natural wa ter be aring formations
may also be used f

or the tra nsport and re tention of wate r. Water authorities c an inject water for 2 8


### later w ithdrawa l with no pay ment for the por e spac e. The proper ty rig hts of landowner s or mineral e state owne rs/lessees do not include the rig ht to control the use of w ater in the g round and ca nnot claim control of a quifers a s part of the ir estate. E x cept f or Texas, g roundwa ter is par t of “w ater s of the state” and either by Constit ution or statute, the g ener al assembly of ea ch state

T i d e w a t e r O i l C o
. v . J a c k s o n , 3 2 0 F

. 2 d 1 5 7 ( C

. A

. K a n
. 1 9 6 3 ) 2 6 S i p r i a n o v
. G r e a t S

p r i n g W a t e r s o f A m e r i c a , e t a l

. , 1 S W 3 d 7 5 ( T e x a s 1 9 9 9 ) 2 7 B o a r d o f C o u n t y C o m ’ r s o f C o u n t y o f P a r k v . P a r k C o u n t y S p o r t s m e n ’ s R a n c h , 4 5 P

. 3 d 6 9 3 , 7 0 6 ( C o l o
. 2 0 0 2 ) 2 8 

### 13

### has control ove r the use a nd dispositi on of g roundwa ter re g ardle ss of whethe r it is or is not direc tly discharg ed to a na

tural strea m. The lawin most st ates prohibits the taking of private proper ty for public or

private use without the property

owner ’s conse nt, but there a re f reque ntly exceptions which perta in to
constructe d water

fac iliti es. For

example many

wester n state constitutions provide for a cce ss 2 9


### to the water

source acr oss the lands of other s and fur ther re cog nize and addre ss the private r ight of conde mnation for the c onstruction of wa terwor ks. There is a requir ement for compensa

tion 3 0


### for use of anothe r’s land, but that doe s not ex tend to employ ment of natura l water

bear ing subsurfac e for

mations on or within the landowner ’s prope rty for the move ment of appr opriated
water

. An applica

nt for a c onditional decre e to utiliz e ava ilable aquife r storag e spac e must 3 1


### demonstrate tha t it will captur e, possess, and c ontrol water lawfully available to it and without injury to other wa ter rig hts. 3 2 

### Water storag e under

a landowne r’s prope rty

is not a trespass if it does not inhibit the use, benef it, or enjoy

ment of prope rty

. I n Boa rd of County

Commi ssioners v. PCS R, L L P, PC SR 3 3 

### proposed to store w ater

in underg round aquife rs under ly ing a pproxi mately

115 square miles. The landow ners c laimed that storag e of w ater underg round in aquife rs under neath their

land would constitute a trespa ss. The Court held that it would not be a tre spass and the pr oject would not require the L andowne r’s c onsent or conde mnation and the pay ment of just compensation under the provisions of Article X VI . The c ourt, in apply ing Ca usby , found that the proje ct did 3 4


### not include construc tion of any fac iliti es on or in the L andowne r’s prope rties and the

C o l o
. C o n s t

. a r t

. X V I § 7 2 9 C o l o
. C o n s t

. a r t

. I I § 1 4 3 0 S p o r t s m e n ’ s R a n c h , a t 4 5 P

. 3 d 7 0 8 3 1 I d

. 3 2 S p o r t s m e n s ’ s R a n c h , 4 5 P

. 3 d a t 7 0 8 3 3 U

. S

. v . C a u s b y , 3 2 8 U

. S

. 2 5 6 ( 1 9 4 6 ) ( r u l e d t h a t p r o p e r t y o w n e r ’ s r i g h t s w e r e n o t u n l i m i t e d w i t h r e s p e c t t o 3 4
a i r s p a c e )

. 

### 14

### L andowne r’s ha d not alleg ed that the use , benef it, and enjoy

ment of their pr operties would be invaded or

compromised in any

way . There fore , it was not a trespa ss. The c ourt stated that the Ge nera l Assembly , in authorizing the use of aquife rs for stora g e of ar tificially rec harg ed proje cts furthe r supplanted the L andowne rs’ c ommon-law prope rty

owner ship theory

. The c ourt found it “par ticularly [si g nificant]” that: 3 5 

### (1) [F]eder al patents to land do not include w ater , (2) g round wa ter is not a minera l under the fede ral mining laws ..., (3) fede ral statutes a s interpre ted by the Supreme Court rec og nize [ a state’ s] authority to adopt its own sy stem for the use of all wa ters within the state in ac corda

nce w ith the needs of its citizens, subject to the prohibitions ag ainst interfe renc e with fe dera l reser ved rig hts, with int erstate commerc e, and w ith naviga bility of any navig able wa

ters, (4) the rig ht of prior a ppropriation applies ... to wa ters of the natura l stream, including surfa ce w ater and tributary

g round wa ter; (5) the prope rty rig hts of landowne rs do not include the r ight to contr ol the use of water in the g round, wha tever the cha rac ter of tha t water ; and (6) the Gene ral Asse mbly has plena ry control over

the use and disposition of g round wa ter that is not part of the natura l stream. 3 6



### I n sum, the holders of wa ter use r ights may

employ underg round as we ll as surfac e wa ter bear ing f ormations in the state for

the place ment of wa ter into, occ upation of wa ter in,
convey ance of wa ter throug h, and withdra wal of w ater

from the na tural wa ter be aring formations in the exercise of

water use rig hts. Consent or just compensation was not re quired be cause the

3 7 

### plaintiffs did not have the r ight to re strict the def endant’ s use of the w ater

that was done within
reg ulations.

2 

### CCS prese nts a unique problem be cause the under g round storag e of CO could potentially

aff ect the f low and loca tion of g roundwa ter. This could oc cur be cause the proc ess of phy sical trapping

may displace na turally

occur ring water

and other g ases. Any

eff ect on water 3 8



### resour ces c ould pose potential liability if it lim its acce ss to water tha t has alre ady been

I d

. a t 7 0 3 3 5 I d

. 3 6 I d

. a t 7 1 2 3 7 S t a t e m e n t o f D r
. R o b e r t B u r r u s , R e s e a r c h G e o l o g i s t , E n e r b y R e s o u r c e s T e a m U

. S

. G e o l o g i c a l S u r v e y U

. S

. D e p
. 3 8 O f t h e I n t e r i o r B e f

o r e t h e S u b c o m m i t t e e o n E n v i r o n e m e n t a n d H a z a r d o u s M a t e r i a l s H o u s e C o m m i t t e e o n E n e r g y a n d C o m m e r c e H e a r i n g o n “ C a r b o n S e q u e s t r a t i o n : R i s k s , 

### 15

### appropr iated to bene ficial use. Phy sical displace ment of g roundwa ter c an also ha ve adve rse

prac tical impacts on private owner s and utiliti es. As a r esult it will normally be prude nt to evalua te whethe r on-site g roundwa ter we lls, especially those used by

public water

sy stems, will be disrupted by

CCS opera

tions.
I n most places a w ater

rig ht includes the rig ht to a particula r quality as we ll as a particula r quantity of wa ter. The se ca ses ar e ty

pically fra med in the context of deprivation of quantity but these wa ter rig hts are a lso protected f rom ac tiviti es of a

nother that injure the quality of a w ater rig ht. There fore , if wate r quality is affe cted by

the pre cipitate that hopef ully forms 3 9 

### from the g eoche mical re actions intended a s part of CCS operations the owne r of that wa ter c ould have a cause of ac tion ag ainst the entity injecting and the owne r of the g as injecte d. Historically such interf

ere nce involved the discharg e of mine a nd other wa stes into the stream but there is no

rea son to believe the r esult would be diffe rent with CCS. 4 0 

### III. Regulation
A. EP A UIC Rulem akin g The UI C Progr am re g ulates under g round injection under five diff ere nt classes of injection wells, depe nding on the ty pe of f luid being injec ted, the purpose for injec tion, and the subsurfac e loca tion where the fluid is to remain. States ar e allowe d to assume primary responsibility

for implementing the UI C require ments in their border s, as long as the state
prog ram is consistent with EPA reg ulations and has re ceive d reg ulatory approva l. I njection
opera tors are require d to provide financ ial assura nce in c ase the y

cea se oper ations, with the level of assura nce a function of the e stimated cost of plug g ing a nd abandoning the injection well. I f there is a violation of a UI C permit, an enf orce ment action may

be broug ht by

the EPA

2 A C O P R A C § 7 6

. 1 1 3 9 G a m e & F i s h C o m m 'n v . F a r m e r s I r r
. C o
. , 1 6 2 C o l o
. 3 0 1 , 4 2 6 P

. 2 d 5 6 2 ( 1 9 6 7 ) ; W i l m o r e v . C h a i n O 'M i n e s , 9 6 4 0 C o l o
. 3 1 9 , 4 4 P

. 2 d 1 0 2 4 ( 1 9 3 4 )

. 

### 16

### Administrator or the a pplicable state ag ency . Violators may be subjec t to administ rative or ders, civil penalties, and c riminal penalties. The scope of the UI C statute is contamination of drinking

2 

### water , and under

its curre nt application to CO storag e, the UI C Progr am g ives more limited
trea tment, if any , to other har ms to human health, the environme nt, and prope rty

. 4 1


### Whil e ther e ar e re quirements for constructing and monitoring injection well oper ation, there are no fede ral re quirements for monitoring a ctual movement of fluids within the injection
zones, nor are there require ments for monitoring in overly ing zones to dete ct leaka g e with the exception of specif

ic class I hazardous we lls, where this monitoring c an be ma ndated. 4 2


### On J uly 15 2008, the EPA proposed a rulemaking packa g e that would re g ulate g eolog ic sequestra tion of car

bon diox ide under

the UI C. The proposed r

ules would cre ate a

new c ateg ory of UI C well (Class VI ) desig ned spec ifically for injec tion of CO2 into geolog ic forma tions. The proposal includes de tailed technic al re quirements for char acte rizing the scope and suitability of the targ et forma tions, assuring tha t the injection zone will not affec t any actua l or potential

source of drinking water , monitoring a nd repor ting on we ll conditions during and a fter the sequestra tion is complete, and re quiring as par t of well per

mit applications plans for 50 y ear s of post-injection monitoring. 4 3

2 

### The propose d rules do not direc tly addre ss air quality

issues. The Class VI

CO injection

2 

### well re quirements ar e desig ned to assure that there are no signific ant re lease s of CO or

2 2 

### contaminants in the CO into the ambient atmosphere . The EPA dec lined to classify CO as a

2 

### hazardous wa ste but the proposed r ules place a burde n on the per mittee to assure tha t the CO does not contain impurities that would trig g er RCRA hazardous wa ste manag ement

C r a i g A

. H a r t , A d v a n c i n g C a r b o n S e q u e s t r a t i o n R e s e a r c h i n a n U n c e r t a i n L e g a l a n d R e g u l a t o r y E n v i r o n m e n t : A 4 1 S t u d y o f P h a s e I

I o f t h e D O E R e g i o n a l C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p s P r o g r a m , D i s c u s s i o n P a p e r 2 0 0 9

- 0 1 , C a m b r i d g e , M a s s
. : B e l f e r C e n t e r f

o r S c i e n c e a n d I n t e r n a t i o n a l A f f a i r s , J a n u a r y 2 0 0 9

. R e g u l a t i n g t h e u l t i m a t e s i n k : m a n a g i n g t h e r i s k s o f g e o l o g i c C O 2 s t o r a g e
. P a g e 3 4 7 9 4 2 h t t p : / / w w w . e p a
. g o v / o g w d w / u i c / w e l l s

_ s e q u e s t r a t i o n
. h t m l 4 3 

### 17

### require ments. The risks assoc iated with this classification ar e manife st. I njection of ha zardous

waste is hig hly

reg ulated and w ould likely bring a CCS project to a scr eec hing ha lt. None of this overrides the a

pplicable pr ovisions of CERC L A or RCRA. To the extent there are hazardous substance s relea sed fr om the sequestra tion process liability under CERCL A
may be pre sent. L ikewise if mate rials injected a re ha zardous waste the daunting permitting a nd 4 4



### corr ective a ction provisions of RCR A and the sta te prog rams will apply

. As an e x ample, EPA issued orde rs under RCR A to require manag ement of pr opane tha t had lea ked fr om an under g round distribution sy stem. I n EPA’s view, the moment the pr opane leake d from the distribution sy stem it was a wa ste and pre sented a hazard. De pending upon the fac tual setting, CCS operations could find themse lves in the same situation.
B. State Re gulation
I n the abse nce of

fede ral a ction on the ca

rbon seque stration issue, many states ar e in the
proce ss of ena cting their own re g ulations. Som e examples follow: 1. Wyom ing
House B ill 89 (created Wy oming Statute § 34-1- 152 and ame nded Wy oming Statute § 34-1-202) addre sses the owne rship of Pore Spac e. The Bill establishes that the surf ace owner
owns pore spa ce unde rnea th the surfa ce e state and tha t the pore spa ce is c onvey ed upon the
convey ance of the surf

ace , unless the spac e has be en pre viously convey ed or is explicitly excluded in the surfa ce c onvey ance (in the same ma nner a s a minera l interest). I n addition, leg al require ments for notice to surfac e owne rs and/or miner al intere st owners shall not be c onstrued to require notice to the pore space owner unless the law spe cifies that suc h notice to the pore
space owner

is require d. The statute e x pressly rec og nizes the dominance of the mineral e state

h t t p : / / w w w . h h c l i m a t e c h a n g e
. c o m / c l i m a t e

_ c h a n g e / 2 0 0 8 / 0 7 / e p a - r e l e a s e s - p r
. h t m l 4 4 

### 18

### and does not a lter the c ommon law as it relate s to the rig hts of the minera l estate. The bill st ates

expli citly that it does not affe ct the common law r eg arding the dominance of the minera l estate. 4 5


### House B ill 90 (effe ctive Jul y 1, 2008; cre ated Wy oming Statute §§ 30-5- 501 and 35-11- 313 and ame nded Wy oming Statute § 35-11- 103(c) ) manda tes UI C permit for GCS. I t makes a clea r distinction from EOR. I t instructs the Wy oming De partment of E nvironmental Qua lity to establish and issue per

mits t o new “ sub-classe s of wells” w ithin the UI C prog ram a nd to reg ulate well standar ds, bonding a nd monitoring. The bill requires the D EQ to cre ate a n advisory

board and rule s to ex pand the UI C prog ram to include c arbon se questration. Unde r the bill, a working
g roup including the supervisor of the oil and g as commission, the state g eolog ist, and the direc tor of the DE Q will set bonding pr ocedur es. Jurisdi ction subsequent extraction of sequester ed ca

rbon diox ide re sts with the W y oming Oil and G as Conserva tion Com mission. The bill does not im pact the oil and othe r minera l interest owner s’ rig ht to drill or bore throug h sequestra tion sit es, nor doe s it include within it s scope the r eg ulation of enha nced oil re cover

y
opera tions using ca

rbon diox ide. 4 6


### L ike HB 89, Wy oming' s car bon captur e and se questration leg islation recog nizes the continuing dominanc e of the mineral e state. § 30-5- 501 states spec ifically that the ca

rbon sequestra tion legislation ena cted by § 35-11-313 sha ll not “affe ct the other wise lawf ul rig ht of a surfa ce or mineral owne r to drill or bore thr oug h a g eolog ic seque stration site” so long as the drilling is conduc ted in confor mity with rules for pr otecting the seque stration site ag ainst the

2 

### esca pe of CO

. 4 7

I d

. a t 1 4 3

- 4 5 4 5 D e l i s s a H a y a n o , G u a r d i n g t h e V i a b i l i t y o f C o a l & C o a l

- F i r e d P o w e r P l a n t s : A R o a d M a p F o r W y o m i n g ’ s C r a d l e 4 6 t o G r a v e R e g u l a t i o n o

f G e o l o g i c C O 2 S e q u e s t r a t i o n , 9 W y o
. L

. R e v . 1 3 9 , 1 4 5

- 4 9 ( 2 0 0 9 ) I d

. 4 7 

### 19

### 2. Oklah om a

Senate B ill 1765 (May

2008) wa s a proposa l that require d the deve lopment of GCS permitting r eg ime and tra nsfer red ow nership of w ells to state and re lease d owner s from liability 10 y ear s after

closure. T he B ill that was passed, howe ver, w as re latively disappointing. I t mandated a

task forc e to re port to the Gover nor with GCS permitting re commendations by
Dec ember

2008 (extended to Dec ember 2009) and is modeled ba sed on the I OGCC model
statute. 4 8


### 3. Kansas Under HB 2419 (2007), GCS rules we re suppose d to be deve loped by J uly 2008 (dra ft in
prog ress). U nder the Bill, a state G CS fund would pay long- term GCS relate d monitoring a nd

reme dial activities. I t also exempts GC S property and any elec tric unit utili zing GCS from taxes for 5 y ear s. Finally , it allows for ac cele rate d depre ciation of GCS equipment. 4 9


### 4. Washin gton ESSB 6001, passed Apr il 17 2008. I t codifies the e missions -re duction g oals and policy

rec ommendations for the state . The bill also sets an Emissions Performanc e Standar d (EPS) that limit s elec tric utiliti es’ a

bility to sign ne w or re newe d long- term contra cts with power pla nts whose g ree nhouse-g as emissions exceed those of a modern na tural g as-f

ueled powe r plant. The bill essentially

ends construc tion of pulverized coal plants to ser ve Washing ton loads, makes the price of I GCC power re flec t some of its emissions di sposal costs, and jumpstarts the proc ess toward a compre hensive g ree nhouse-g as emissions reduc tion plan for the state

. 5 0

d e F i g u e i r e d o M A , R e i n e r D M , H e r z o g H J

. F r a m i n g t h e l o n g - t e r m i n s i t u l i a b i l i t y i s s u e f o r g e o l o g i c 4 8
c a r b o n s t o r a g e i n t h e U n i t e d S t a t e s
. M i t i g a t i o n A d a p t

. S t r a t

. G l o b a l C h a n g e 2 0 0 5 ; 1 0 : 6 4 7

- 5 7

. M e l i s a F

. P o l l a k , H u m p h r e y I n s t i t u t e o f P u b l i c A f f a i r s , B i g S k y C a r b o n S e q u e s t r a t i o n P a r t n e r s h i p A n n u a l M e e t i n
. 4 9 O c t

. 2 8 , 2 0 0 8 N W E n e r g y C o a l i t i o n , A p r i l 1 9 , 2 0 0 7

. w w w . n w e n e r g y . o r g / p u b l i c a t i o n s / f a c t

- s h e e t s / 6 0 0 1 % 2 0 F I N A L % 2 5 0 

### 20

### 1 Am erican Public Power Association 2301 M Street, N.W. Wa shington, 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

- Prepar ed by Marianne Horinko, Executive Vice President, The Global Environment & Technology Foundation for the American Public Power Association (APPA)
C arbon capture and sequestration or storage ( CCS) is on the cutting edge of gre enhouse gas reduction tech no l ogy research

. CCS is t he process by which carbon dioxide (CO 2 

### ) is separated and collected fro m large point sources such as coal power pl ant s and retained in a manner that prevents immediate release in to the atm osphere. This retention may be accomplished th

rough a variet y o f means, such as large

- scale botani cal plant ings or chemical adsorption treatment. This paper, however, is limited to the most common method, geological sequestration, which invo lves inject io n of CO 2 

### int o underground geol ogi cal f

orm at io ns
. While CCS could potentially be effect ive in reducing greenhouse gas emissio ns , there are still unanswered questions about its long

- term effects on hu man healt h and the environment , as well as real property and liabilit y co nsiderat io ns
. T he scale o f CCS necessary to impact greenhouse gas emissio ns vast ly exceeds the histo ri cal use of carbon inject io n pract ices in enhanced oil recovery ( EOR )

. The purpose of carbon inject io n in EOR has been to displace fossil fuel to allow recovery; carbon sequestrat io n is merely a byproduct of that recovery process. Generally speaking, CO 2 

### used in EOR is locally available from co mmercial, food grade CO 2 

### so u rces and not from utilit y or m anufacturing plants. Somet imes th e CO 2 

### used by the oil and gas recovery EOR oper at io ns is available locally through naturally occurring sources in the ground. For example, to reduce th e 2.5 bil lio n t ons of CO 2 

### annually emi tted by Uni

ted States power plants by t en percent (250 megatons) woul d requi re extensive deplo yment of CO 2 

### emissi on capture techno lo gi es at 25 plants

. 2 

### Co mmercial

- level CCS deposi ts are likely to be extensive, intersect ing wi th preexist ing mineral , wate r , and private property rights

. In addi ti on, the environmental liabilit y associ ated wi th such practices has not be en wi dely lit igated, adding a layer of business uncertainty to the use of CCS as a viable technique. The legal framework s surrounding exist ing EOR p racti ces are focused on inject io n and ty pically maintain only limited long

- term storage and monitoring comp onents due to their small scale

. Commercial

- level CCS project s wo u ld require a reliable and transparent

1 This paper contains slight adaptations from the April 2007 version for APPA

— pr imarily in the footnotes. 2 Based on Energy Informatio n Administration statistics. Assuming that a o ne g iga watt power plant produces 10 million tons of CO 2 annually.

### 2

regul atory framework based on sound analysis o f the unintended consequences to human healt h and environmental assets. The inject io n of CO 2 

### fro m power plants into any appropriate geologic format io n would also require, first, considerable breakthroughs in carbon separat io n t echno lo gy at the power plant. This is a step that, generally speaking, EOR si tes do not require. 3 

### The purpose of this white paper is t o introduce environmental and legal issues th at ma y requi re addi ti onal research before large

- scale CCS can be implemented safely and effect ively in the public power utilit y s ector

. Human Health and the E nvironment Despite the su ccesses of EOR or te rti ary recovery of oil and gas using CO 2 

### inject io n, l eakage from embedded CO 2 

### deposi ts coul d resul

t in th e endangerm ent of ecol ogi cal and human healt h given the scale of the utilit y sector’s emissio ns
. A better understanding of th ese impacts is necessary in order to take precautionary steps to mit igate th em or avoid th em enti rely.

§ Prol onged exposure to e levated concentrations of CO 2 

### can be harmful to human respi ratory and central nervous systems.

§ The r el ease of large vo lu mes o f high concentrations of CO 2 

### can resul t in th e s uffocat io n of humans , animals , or pl ants above ground

. For instance, natural CO 2 

### lo ng - term seepage destroy ed 40 hectares of trees on Mammoth Mountain in th e Eastern Si erra Nevada mo untain range in California

. 4



### § L eakage fro m injected CO 2 

### c oul d migrate into Underground Sources of Drinking Water (USDWs)

. Migrat ing CO 2 

### deposi ts m ay al te r the pH of subsurface groundwater or displace potable water resources by fo rcing saline waters to merge wi th fresh water formations.

§ According to the U.S. EPA , 44 percent of all U. S. drinking water is from groundwater, a considerable increase fro m o nly 5 years ago when most U. S. drinking water was from surface water sources.

§ Current research suggests that inject ing carbon into saline aquifers poses a threat to groundwater because of brine contaminat io n. 5 

### Since it is not clear how large

- scale CCS activit ies would address this concern, addit io nal research is required considering th e growing reliance on groundwater for use as drinking water.

§ CCS coul d potentiall y cause d isplacement of nat ive fluids and chemical const it uents, mo vement of possible hazardous substances , or potential leaching of naturally occurring metals and minerals mixed in the CO 2 

### inject io n
.

3 Complete explanation of separation technology issues a vailable. 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 CO 2 Emission at Mammoth Mountain as a Sign of Magmatic Unrest,” Nature 376 (1995): 675

- 678. 5 Br ian McPherson and Peter Lichter, CO 2 Sequestration in Deep Aquifers , http://www.netl.doe.gov/publications/proceedi ngs/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 penalt ies under the Clean Water Act (CWA)

. 6 

### Property Rights The legal mechanism fo r securing property ri ghts for large carbon sequ estrati on si tes may currently be in effect ive in many state s , l eading to unforeseen costs and delays

. It also may lead to tension s between large

- scale CCS projects and individual property rights.

§ Si nce sub

- surface land can be privately owned in the Unite d States, CO 2 

### inject io n int o geol ogi c form at io ns may require permissio n from all private owners of intersected sub

- surface property

. A proposed deposit fo r a FutureGen zero

- emissio ns plant site may requi re property ri ghts fro m 69 individual property owner s
. 7



### § Com pulsory u nit izat io n laws fo r oil and gas production operations , currently used in some states to co mpel private property owners to permit large oil and gas sub

- surface proj ects when a high percentage of affected property owners do accept, ma y be use d extensively fo r enhanced oil recovery

- related CCS

. § For non

- oil and gas production projects, the use of eminent d om ain laws , currently used for sub

- surface natural gas storage fields , ma y be necessary fo r CCS proj ects

. Widespread use of local and state e minent d omain laws for CCS ma y be polit ically difficult, given the public backlash again st eminent d omain driven by the Suprem e Court case Kelo v . New London

. 8



### § There is currently a significant level of uncertaint y in predict ing migration and mo vement of large CO 2 

### deposits in large geologic format io ns
. Wit hout further research , t he scale of property right acquisit io n fo r CCS proj ects will remain high , as industry parti cipants will seek to minimize liabilit y fro m property trespass claims rel ated to sub

- su rf

ace trespass, geological surveying, and deposit monitoring

. § This scient ific uncertaint y ma y int erf ere wi th th e availabilit y o f liabilit y insurance for CCS proj ect parti cipants

. If insurance co mpanies cannot accurately calculate th e ri sk of CO 2 

### dam ages , or future potential environmental liabilit y, th ey may decline to offer coverage to public power utilit ies

. Some public power utilit ies may not have the insurance coverage thought to be sufficient to handle the perceived risks for geologic sequestration or storage of CO 2 

### . § The u tilizat io n of regi onal land use c ontrols to ban large

- scale CCS projects near valuable natural resources may be an obstacle to implement ing proj ects in viable lo cat io ns. General Regulatory Framework The current federal and state re gulatory framework may be insufficient for ensuring a fa ir resol u ti on in th e event of leakage damage to human healt h or private property

.

§ Current ly, CO 2 

### has not y et been classified as a pollutant or a hazardous substance. If embedded CO 2 

### i s not cl assif ied as such , then federal envi ronmental statutes ma y lo se

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 protecti on from CO 2 

### leakage damage , since these laws were created to assess and assign responsibilit y fo r dam age fro m hazardous substances. However, CO 2 

### coul d ul ti mately be classified as a pollutan t, especi ally if large

- scale implementation of CCS leads to negative impacts on environmental media. This classificat io n would have a significant legal impact and would likely increase the costs associ ated wi th CCS activit ies.

§ There is uncertaint y in th e governance of th e Comprehensive Environmental Response, Compensation, and Liabilit y Act ( CER C L A ) over private property damage cases t hat are caused by sequestered CO 2 

### . No carbon injection subsurface trespass legal precedents exist , and there is s cient ific uncertaint y o f embedded CO 2 

### impacts.

§ If th e CCS process causes a rel ease or substant ia l t hreat of a rel ease of any pollutant th at may present an imminent and substant ia l danger to the public healt h or welfare, liabilit y will likely attach under CERCLA

. 9



### § I f area

- wide contaminat io n is the result of CCS activit ies, potential parties coul d be held liable under CERCLA

. To the extent that specific provisio ns of the CWA and th e Safe Drinking Water Act ( SDWA ) are incorporated into the applicable or relevant and a ppropri ate requi

rem ents (ARARs), those standards could then govern the rem edial act ivit ie s of a CERCLA cleanup.

§ In the case that CCS results in collateral damage to natural resources, responsible parti es coul d be made liable under the Natural Resources D amage Assessment (NRDA).

§ The existence of cit izen suit provisio ns, especially with respect to water laws in the Western U.S. , introduces another level of uncertaint y because any regulatory balance can be altered by a cit izen bringing suit because of a la ck o f prosecutorial diligence, whether actual or perceived.

§ In nuisance tort cases or other grievances related to CO 2 

### leakage, t he potentially resp onsible parties under CERCLA are unclear. F ederal and state government regul ators , carbon injection operat ors, and public power generator s of CO 2 

### ma y a ll be candidates for some porti on of liabilit y under th e “jo int and several liabilit y” provi si on in th e CERCLA statute ’s “cradle to grave” liabilit y s cheme

. § There ma y be leg al difficult y in assigning responsibil it y fo r seismic disruption dam ages caused by carbon inject io n due to scient ific uncertainty and lack of a legal preceden t.

§ In the case of natural seismic act io n leading to future CO 2 

### leakages, assigning liabilit y based on fault may be impossible and lead to difficult y in ha ndling the resultant dam ages. Long
- Term Stewardship and Liability Assignment of l iabilit y associ ated wi th leakage and migrat io n of CO 2 

### deposi ts and resul ti ng public healt h or environmental impact is further com plicated by th e extended t ime frame of carbon storage , which may exceed the lifespan of industry part ic ipants. For example, determining which part y is responsible for the CO 2 

### mo nit ori ng at a power pl ant after the pla nt is deco mmissio ned or retired is difficult.

§ The exist ing legal framework for EOR carbon sequestration has insufficient lo ng - term storage and monitoring controls for large

- scale CCS projects.

9 CERCLA § 104

### 5

§ T he continuo us existenc e of a viable ent it y is questio nable under th e current legal framework

. It i s st ill an open q uest io n whether long

- te rm liabilit y should rest with a public or private ent it y. To ensure the future economic burden associated with the CCS site will not rest on the public as a who le, issues of long

- term stewardship, land use controls, and data trackin g will need to be addressed

. § Assignment of liabilit y in CO 2 

### rel eases is especially difficult if the co mpanies that managed the injection and monitoring no longer exist or if they ut ilize subsidiaries to limit liabilit y.
§ A ddi ti on al research is requi

re d to improve scient ific knowledge of carbon storage , which would help to inform the liabilit y debate

. § Pl ugged CCS injection sites will require effect ive long

- te rm stewardship perf orm ed by a government or private ent it y . A detailed framework mu st be fir mly established in th e U.S. Environmental Protection Agency’s (EPA) Underground Inject io n Control Program , which provi de s governance for CO 2 

### injection under the SDWA

. 10



### § Alt hough geologic sequestration current ly meets the statutory definit io n of “u nderground i nject io n” in sect io n 1421(d)(1) of the SDWA, EPA is current ly evaluat ing D epart me nt of Energy (DOE) pilot projects to determine if changes to the re gul at io ns are required for long

- term CCS.

§ Si nce EPA current ly has the statutory mandate to protect undergrou nd sources of drinking water and aquifers, the unknown results of these DOE pilot projects leaves legal uncertaint y w it h respect to the future of CCS activit ies.
Further Research This white paper is intended as an overview of potent ia l environmental and l egal issues th at coul d ari se in a large

- scale CCS operati on. It is meant to promote further research and discussio n of th ese areas before large

- scale CCS imp lementation can provi de one of th e many techno lo gi cal so lut io ns to constraining carbon fro m exist i ng or future power pl ants

. A pressing need for reducing greenhouse gas emissio ns and halt ing their effect on climate change is driving the current polit ical impetus to institute co mmercial

- level CCS on a short time frame . H owever, for commercial CCS to e ffect ively reduce emissio n s and mit igate the effects of climate change , a co mpr ehensive pl an and effective regulatory framework th at respect potential obstacles and adverse impacts are essent ia l. Technical and e conomic barriers to imp lement ing commercial

- level CCS are substant ia l , but th ey are also currently under significant scrutiny

. The legal and environmental challenges of CCS should be analyzed and addressed wi th similar vigor in order to prom ote effect ive and sustainable pract ice s in t he United Stat es. R esearch on these aspects will inform cost

- benefit analyse s of CCS in relat io n t o other methods being developed to mit igate climate change , all owing for optimal distribut io n of public and private resources
.

10 Testimony of Actin g 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 th e Execut ive Vice President of the Global Environment & Techno lo gy Foundat io n (GETF). Prior to jo ining GETF, she served as Assistant Ad ministrator for the Office of Solid Waste and Emergency Response (OSWER) at the U.S. Environmental Protection Agency fro m 2001 to 2004, a nd Act ing EPA Ad ministrator in 2003

. She led the emergency responses to the 9/11 attacks, anthrax contaminat io n, and the Columbia Space Shuttle disaster. She brought new approaches to environmental protection using partnerships, flexibilit y, and innovat i on. 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 pract iced environmen tal law at Morgan, Lewis & Bockius, a nat io nal environmental policy firm, where she assisted in the creation of the RCRA Policy Forum. She graduated from the Universit y o f Maryland (analyt ical chemistry) and Georgetown Universit y Law School.
GETF is a 50 1(c ) ( 3) not

- fo r - profit foundation that works with government, industry, academia, and non

- governmental organi zat io ns to advance sustainable so lut i ons and practi ces that promote environmental stewardship.

### 1



## Carbon Capture and Storage From Coal - based Power Plants :

A W hite Paper on Technology for th e American Public Power Associa tion (APPA) L.D. Carter May 22 , 2007

Int roduction Technology for carbon capture and storage (CCS) from c oal

- 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 co st of electricity by over 60%). Technologies for injecting carbon dioxide ( CO 2 

### ) 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 CO 2 

### in to saline reservoirs in Canada, in associ ation with oil and natural gas processing 1



### . Additionally, a lim ited number of power plants have used chemical sorbents to capture CO 2 

### for reuse at very small scale (a few hundred tons per day, or less)

. 2 

### However, there is no commercial experience with co mmercial scale power plants capturing and storing large quantities of CO 2 

### 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 carb on - controlled systems, build an im proved understanding of the long

- term behavior of CO 2 

### stored underground, and craft a pragmatic risk management framework for conducting CO 2 

### storage. Increasing the difficulty of this challenge is the fact that all of thi s 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 W estern Canada , S. Bachu, Alberta Energy and Utilities Board, Edmonton, Canada, ht tp://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 usin g 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 CO 2 

### both from combustio n - based and gasification

- based power generation fueled by coal, and technologies to transport and store CO 2 

### 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. CO 2 

### capture from combustion - based coal power plants Two CO 2 

### capture approaches are receiving strong inte rest for application with combustion

- based power plants . The first is based on absorption of flue gas CO 2 

### by an aqueous solvent. CO 2 

### concentrations in flue gas are modest, 12

- 15%, due prim arily to presence of significant amounts of combustion

- air nitroge n, and to “excess” air needed to ensure complete combustion of coal. For these concentrations, chemical sorbents have been shown to be effective at separating CO 2 

### 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 CO 2 

### “scrubber”. Possible solvents include a family of amine chemicals, which are molecular “cousins” to ammonia ; proprietary solvents designed specifically t o capture CO 2 

### , such as “KS

- 1” solvent f rom Mitsubishi Heavy Industries ; and advanced solvent concepts, such as chilled ammonia. For these chemical solvent

- based capture systems, the CO 2 

### is captured in an absorption vessel (amines typically operate at 50 o C (120 oF)). The CO 2 

### - enriched sorbent is then pumped to a second vessel and heated to about 120 oC (250 oF) to drive off a concentrated stream of CO 2 

### and regenerate the lean solvent . T he concentrated CO 2 

### is dried and compressed to about 2200 psia for pip eline transport in a supercritical state to a site for use or storage

. Parasi tic power needs are substantial and include pumps, fans, solvent regeneration, and CO 2 

### compression. In addition, the CO 2 

### solvents tend to form “heat stable salts” with any remai ning SO 2 

### or NOx in the flue gas. These stable salts do not break down in the solvent regenerator, so there is loss of solvent unless SO 2 

### and NOx are reduced to extremely low concentrations. These factors combine to lead to a 25% increase in fuel consumpt ion per kilowatt

- hour generated, and increase cost of electricity by over 6 0%. 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 20 07 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 me morandum 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 CO 2 

### absorption, and requires less energ y for regeneration than currently used chemical solvents, so success in t hese technologies could reduce the cost and energy penalty of CO 2 

### capture at conventional power plants. Oxy

- com bustion is a second approach to capturing CO 2 

### from pulverized coal power plants, and takes a radically different approach than CO 2 

### absorption. With oxy - com bustion, the coal is burned with pure oxygen, not air, so the products of combustion are primarily CO 2 

### , water vapor, and some excess oxygen (see Figure 2) . To moderate boiler temperatures to about 1900 oC (3450 oF), it is necessary to recircul ate a portion of the flue gas CO 2 

### (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) sys tem is unnecessary. The SO 2 

### system can be significantly downsized because it does not process the flow of excess air or nitrogen normally encountered with air

- based combustion. The CO 2 

### capture system consists essentially of gas drying and compression , alt hough some additional gas purification may be needed

. T his design approach can take advantage of higher temperatures and improved heat transfer from CO 2 

### /H2O mixtures to allow a more compact (cheaper) boiler. Parasitic energy demands are high (e.g., 25%), because of the oxygen plant and CO 2 

### 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 d emonstration of oxy

- combustion in Summer 2007, followed by retrofit to an existing commercial coal

- fired unit by 2015. 5 

### In 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


### CO 2 

### capture from IGCC A different approach to CO 2 

### capture is associated with Integrated Gasification Com bined Cycle (IGCC) power pla nts . 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 Dev el opment of Ion Transport Membrane Oxygen Technology for Integration in IGCC and Other Adv anced Po wer 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 CO 2 

### at t he end of this process, in an IGCC CO 2 

### 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 CO 2 

### . T his leaves a modified synthesis gas consisting largely of hydrogen, water vapor, and CO 2 

### , still under the relatively high pressure created in the gasifier. CO 2 

### is m uch easier to separate in this concentrated, pressurized state, than in nor mal flue gas. F ollowing H 2 

### S removal, a physical solvent process, such as Selexol , can be used to separate the CO 2 

### from the hydrogen. The CO 2 

### - rich solvent is then pumped to a separate vessel where c oncentrated CO 2 

### and lean solvent are regenerated by a reduction in pressu re, 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 generate s additional power, similar to an IGCC wit hout CO 2 

### capture

. The inherent advantage of this power generation approach is that the CO 2 

### 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 I GCC system (without CO 2 

### capture) remains a relatively immature technology, and costs more than comparably sized pulverized coal system without CO 2 

### 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. 7 

### These 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 CO 2 

### capture from IGCC systems, and use generation systems that do not require a hydrogen turbine, by capturing less than 90% of the plant’s CO 2 

### . For example, DOE’s most recent analysis of IGCC gasifiers indicates that the GE system converts about 30% of the coal carbon into CO 2 

### in the synt hes is gas (the rate for the Conoco Phillips design is about 25%, and the Shell system analyzed was much less)

. 9 

### This CO 2 

### could be captured at lower cost and with much less disruption to the overall plant design that a system including a shift reactor. Alt ernatively, 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 CO 2 

### capture . However, neither of the se 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 CO 2 

### c apture. 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 hi gher gasifier temperatures, which will help carbon conversion; lower cost oxygen production processes (see above discussion of Ion Transport Membrane s ); warm gas H 2 

### S cleanup, which allows efficiency improvements; dry

- feed coal “pumps” for gasifiers to r eplace 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 commercial

scale demonstration on the FutureGen system, which is scheduled to begin operation in late 2012. CO 2 

### transport Quantities of CO 2 

### 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 pip eline transport, CO 2 

### is press urized 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 CO 2 

### for enhanced oil recovery, CO 2 

### pipelines are a mature technology , and ha ve been operating reliably in the U.S. for over 30 years . There are over 1500 miles of CO 2 

### pipelines in the U.S., transporting over 50 million tons of CO 2 

### per year. For example, the Weyburn pipeline carries 5000 tonnes per day of CO 2 

### (96% CO 2 

### and 0.9% H 2 

### S ) for 200 miles between the Great Plains Synfuels plant in North Dakota and the Weyburn EOR project in Saskatchewan, Canada. Al though CO 2 

### 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

- CO 2 

### gases permitted in CO 2 

### 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 mi le pipeline for CO 2 

### from a 500 MW power plant (about 3 million TPY) is estimated to cost about $3 .00

– 5.00 / Tonne CO 2 

### , whereas transport for a 2,000 MW facility would cost about $1.40

– 2.10/Tonne CO 2 

### . 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 CO 2 

### pipeline s (eminent domain).

10 Op.Cit., IPCC 2005, p.182

- 3. 11 Op.Cit., IPCC 2005, p. 192 ; figures are in 2002 dollars

.

### 6

CO 2 

### storage A number of options are available for CO 2 

### storage. Figure 4 12 

### presents several of these options, including storage in depleted natural gas or oil reservoirs (which can involve EOR) , st orage in deep saline structures, and u se for enhanced coal

bed 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 CO 2 

### . Add itionally, power plants must compete with other, lower cost sources of CO 2 

### , such as CO 2 

### produced from underground deposits, or CO 2 

### from natural gas processing plants. Most CO 2 

### currently used for EOR in the U.S. is from underground deposits, and most of th e 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 CO 2 

### into geological formations i s well understood, having been used for approximately 90 EOR projects worldwide, which cumulatively store about 40 million tonnes per year of CO 2 

### (compared to about 3 million tons per year ( TPY ) of CO 2 

### from a single 500 MW coal

- based power plant). 15 

### The ke y features separating CO 2 

### injection for long

- term storage versus CO 2 

### injection for EOR are:

§ CO 2 

### retention is not the primary goal for EOR operations. EOR operations focused on maximizing CO 2 

### retention would likely follow different procedures.

§ With EOR ope rations, 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 r etain 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 remediat ion in the event of a leak. Leakage of CO 2 

### 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 2 nd IEA/CSLF W orkshop on Legal Aspects of Storing CO2 (draft) , International Energy Agency, 17October2006.

### 7

more of the injected CO 2 

### will be retained for 1000 years.” 16 

### However, i f l eakage occurs, it can be a serious matter. Figure 6 displays various pathways by which CO 2 

### can escape storage. 17 

### The most commonly stated concern is leakage via existing oil or gas wells that might penetrate the caprock near the CO 2 

### injection site. It is commonplace in oil producing regions to “discover” wells long since abandoned and forgotten. M itigation is straightforward: plug the well at a cost of $15,000

- $25,000. Although relatively low concentrations of CO 2 

### are essential for the support o f 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% CO 2 

### . Volcanic leaks leading to soil root concentrations of 20

- 30% CO 2 

### have kil led trees at Mammoth Mountain, California. 18 

### If CO 2 

### 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 CO 2 

### 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 criter ia.

§ “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 CO 2 

### 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 Capt ure and Storage: A Regulatory Framework for States , Interstate Oil and Gas Compact Commission, January 2005.

### 8

EPA has issued guidance applicable to pilot

- scale CO 2 

### 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 CO 2 

### and other materials like SO 2 

### or H 2 

### S would face additional, unstated requirements. 22 

### It is reas onable to expect that EPA will eventually adopt regulations governing CO 2 

### 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

- by

case ba sis, using current UIC regulatory authority. One can assume an abundance of caution will accompany early commercial projects, which could im pact 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 CO 2 

### storage. The timeframes for storage integrity exceed normal life cycles for corporations, and insur ance 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 betwee n the private and public sector, before most entities will be willing to embrace non

- EOR CO 2 

### 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 f ollowing capture cost estimates are taken from an April 2007 DOE/NETL report 23 

### ; pipeline and injection costs are taken from an IPCC report 24 

### , and adjusted to 2007 dollars using the Chemical Engineering plant cost index.

§ Capture and compression , new IGCC: $30

- 40 $/tonne CO 2 

### avoided.

§ Capture and compression , new SCPC w/ amine scrubber: 69 $/tonne CO 2 

### avoided

§ 150 mile pipeline, 12 million tonne per year capacity (~ 2000 MW): 1.80

– 2.70 $/tonne CO 2 

### . Costs per tonne approximately double for a pipeline capac ity of 3 million tonne per year.

§ Injection: Saline formation, 0.50

– 5. 80 $/t onne CO 2


### § Injection: Depleted oil field, 0.65

– 5.20 $/ t onne CO 2


### § Injection: Depleted gas field, 0.65

– 15.70 $/tonne CO 2

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 CO 2 

### purchased for EOR might range from 1

- 2 $/thousand standard cubic feet , or about 18

- 36 $/tonne CO 2 

### , and varies with the price of oil. Several caveats are essential for proper interpretation of these cost estimates. 1. I t must be emphasized that they apply to a n ew facility, where there is freedom of design. Retrofitting would amplify costs not only due to space lim itations, less likelihood of proximity to storage geology, and generally lower “beginning” plant efficiency (which exacerbates the impacts of parasiti c power consumption), but also due to hardware issues such as the inability to easily extract steam for CO 2 

### sorbent regeneration. 2. T he apparent lower cost of capture from IGCC, compared to SCPC, is significantly offset by the higher cost of the IGCC syst em 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. T he 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. O ne should not assume that power plants built near old oil or gas fields will enjoy a large “rebate” from CO 2 

### sales for oil or gas recovery. A number of existing industrial processes produce voluminous supplies of relatively pure CO 2 

### which are already separated from other gases. 25


### P robably 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 s olved, 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 th at additional RD&D will reduce the cost of CO 2 

### capture and compression , perhaps significantly . However, pipeline and injection systems use relatively mature tech nologies and are not likely to enjoy such declines over time.

25 Natural gas processing plants, for example, often proce ss raw gas that is too high in CO 2 for sale to pipelines, so the CO 2 is separated and v ented to the atmosphere. As noted earlier, t his gas is av ailable and much cheaper to capture than CO 2 fro m power plants, and natural gas processing plants are usually i n the vicinity of gas and oil fields. It is not coincidence that most of the CO 2 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 w ill need to find storage for their emissions, and that the value of CO 2 will drop as more emitters seek to sell their CO 2 .

### 10

Summary: Key issues requiring additional attention With respect to CO 2 

### capture from coal

- based power plants, the major issues are technology integration and costs. CO 2 

### capture from conventional power plants has occurred only at a very small scale (a few megawatts), and without integ ration 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 sorbe nt 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 challenge s are t he relatively high cost of the IGCC itself, absent CO 2 

### capture, and concerns regarding reliability. In addition, for 90% CO 2 

### 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 CO 2 

### are relatively mature technologies. But we have very lim ited experience with the fate of CO 2 

### injected in non

- EOR applications at rates of 3 million TPY or more (compar able to a 500 MW coal

- based power plant). We will need several multi

- year research projects, at commercial scale, in which injected CO 2 

### is carefully monitored, to gain the necessary understanding of what happens to such CO 2 

### volumes over long periods of ti me. 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 CO 2 

### storage is not well understood by the general p opulation, 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 unexp ected for regulators to im pose overl y 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 the se technologies. Aggravating thi s situation is the lack of a system to manage CO 2 

### 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 CO 2 

### , 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 te chnology 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. Depar tment 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. Environme ntal 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 - co mbustion capture.

Figure 2. Oxy - combustion system with CO 2 

### capture. Boiler

PM removal (FF or ESP) Sulfur

removal (FGD) AH 2

Flyash Recycle CO 2 Scrubbers

Ste am Turbine Sulfur By Products

Generator Stack

Drying & Comp

.

Electric

Power Coal & Air Sequestration Ready CO 2 CO 2 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 Pow er Sequestration Ready CO 2 Drying & Comp
CO 2 Capture NOx Removal (SCR)

### 13

Figure 3. IGCC power plant with CO 2 

### capture.

Figure 4. CO 2 

### storage options. Coal Gasifier

Slag/Fines Steam Cryogenic Oxygen

P articulate Removal Steam Combustion Turbine & Gen

HRSG Air

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 d ark blue)

Figure 6. Potential pathways for CO 2 

### leakage.

### Will Water Issues/Regulatory Capacity Allow or Prevent Geologic Sequestration

for New Power Plant s ? A Review of the Underground Injection Control Program and

Carbon Capture and Storage

Authors: Jonathan Gledhill, Policy Navigation Group James R ollins, Policy Navigation Group Theresa Pugh, Director, Environmental Services, APPA

a nd

American Public Power Association 1875 Connecticut Ave, NW Suite 1200 Washington, DC 20009

- 5715and 1 Executive Summary International concern over global climate chang e has spurred a search to identify ways to reduce greenhouse gas (GHG) emissions . Of the six gases comprising greenhouse emissions, carbon dioxide (CO 2 – “carbon” ) emissions far exceed the other five in the amount emitted. 1 The U.S. is considering a numb er of voluntary options for an 18 percent reduction in CO 2 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 seque stration 2 First the carbon dioxide from a power plant would have to be separated and removed from the power plant. C arbon sequestration really refers to the geologic sto ra ge in deep geological formations below the earth’s surface. Carbon dioxide injectio n 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 t esting of CCS pilot projects
. APPA suppor t s carbon storage demonstrations through the DOE and FutureGen to determine if the injection of CO 2 is safe and effective as a mitigation measure. The CCS issue is of considerable import to the electricity/power p lant sector which the U.S. DOE considers to be one of the largest emitter s of CO 2 , accounting for 38 percent of CO 2 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 nu mber of technical, regulatory, and policy issues related to long

- term CO 2 storage or geosequestration that remain to be studied and resolved. The U.S. E nvironmental Protection Agency (E PA ) has regulatory authority over injection of wastes into wells thro ugh the Underground Injection Control p rogram (UIC) created by Congress under the Safe Water Drinking Act . Congress specifically created the p rogram out of concern for the protection of underground drinking water sources . Although the UIC program has est ablished 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 wi th 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 safeguard s to ensure protection of groundwater sources . T herefore 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 CO 2 ) for a period of 10,000 years.

1 U.S. DOE National Energy Technology Laboratory, Carbon Sequestration Program Envi ronmental 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. CO 2 emissions”). 2 Sometim es 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, commercial

scale sequestration of carbon i n 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 thei r communities, the challenges include very difficult issue s . 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 Munic ipal Government ? P olicy officials and scientists alike , searching fo r viable ways to reduce carbon dioxide ( CO 2 ) emissions , have identified carbon capture and storage (CCS) 4 as a promising technology
. This technology separates CO 2 from emissions of large stationary sources like power plants and inject s the captured CO 2 deep into the earth
. Figure 1 gives a simple picture of this technology. The Intergovernmental Panel on Climate Change (IPCC) has identified C CS as a way of achieving overall reductions i n greenhouse gas emissions. 5 This 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 2 012 . The U.S. DOE is leading the Regional Carbon Sequestration Partnerships to conduct research and development of C CS 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 Operation 6

The benefits of reducing CO 2 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 Cap ture 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 a vailable 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 red uctions. According to EPA, g round 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, a nd 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, t he demand for electric is expected to increase by 39 percent from 2005 to 2 050 , 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 A merican Public Power Asso ciation (A PPA ) 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 provid e el ectric ity 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 sea mless fit between current regulation and CCS
. First, t he 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, f or CCS to have a meaningful impact on U.S. emissions, the volume of CO 2 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, da ta, 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 pro gram, its current implementation, the current regulatory framework for CCS , and the skill shortages states and EPA will face if CCS moves toward full

scale implementation. Finally, this paper highlights the major limitations for CCS that power plant and w ater 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 extracti on of fossil fuels and mineral s . 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) P rogram? Congress and EPA established the legal framework for regulating underground disposal over 30 years ago. Congress established the UI C program as part of the Safe D rinking Water Act (SDWA) of 1974 providing EPA with the authority to regulate underground injection activities to ensure the protect ion of the nation’s underground s ources of drinking water
. Almost all U.S. public water syst ems rely on some g roundwater 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 int ended 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 s tates to submit an application to EPA for primary enforcement or “pri macy” for each part, or “class , ” of the program
. EPA can delegate primacy to a s tate, U.S. territory, or a federally recognized Native American tribe
. The UIC p rogram may be executed by the E PA, the s tate, or both under four separate scenarios: 1) EPA adm inisters the program for all well classes within a s tate if the latter chooses not to apply for primacy; 2) a s tate is delegated primacy for all five classes; 3) a s tate has primacy for Class II (oil and gas) wells only; or , 4) a s tate has primacy for all c lasses e xcept 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: Ari zona, 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 d oes EPA R egulate U nderground I njection? EPA established f ive classes of injection wells (Class I, II, III, IV, and V) under the UIC p rogram based upon how the well is used , construct ed, and operat ed
. 11 The classes provide a consistent way for E PA to a pply 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 C lass V, Clas s I, or Class II wells
. All underground injection wells must have a permit. For each class, EPA has established minim um 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 the ir permitting process. With approximately 8 3 4,000 wells across the U.S. , 12 the UIC program is one of the largest environmental permitting program s .

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 C lasses of I njection W ells under the UIC P rogram? Class I Injection W

ells Subject to the most stringent regulations, Class I wel ls include industrial hazardous, nonhazardous, and municipal sewage waste
. Class I wells inject wastes deep into rock formations that are located be neath the low est underground sources of drinking water 13 and that are capped by an impermeable rock formation between the injection zone and drinking water sources above
. Figure 2: Diagram of Class I Well 14

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

I n 1984 , Congress tightened Class I requirements by instituting a no

- migration stand ard 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 prohibit ed injection of untreated hazardous wastes unless it is demonstrated that the waste has been t reated 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 C lass I wells nationwide , t h ere 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 no

migration over a 10,000 yea r 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 3 66 nonhazardous Class I waste wells in 19 states
. Nonhazardous Class I waste wells are required to comply with the same technical standa rds as hazardous waste wells. Class II Injection W

ells O il 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 . S tates 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 d eep wells. There are approximately 167,000 Class II wells , p redominantly found in the s outhwest ern U.S. The map below shows the loca tion 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 W ells 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 well s have minimum standards for which operators must comply , including requir ed 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 r equired 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 create d 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 W

ells 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 us ed by industry f or wastewater disposal as well as less advanced types found in septic systems , cesspools , and agriculture drainage wells
. I njection activities that d o not fit into the other classes

- like CCS

- are called Class V wells
. E xperimental tec hnologies 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, o ver the years EPA has issued guidance to cover certain experim ental technologies
. Notably, EPA issued guidance in 1983 clarifying that t echnologies in the experimental phase which would have otherwise fall en under another UIC p rogram class based upon well function, may be reclassified into one of the five classes on ce 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 wa ter 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 standa rds. 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 Sta tistics 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 sequestratio n of carbon dioxide when they established the program for th e chemical industry over 30 years ago so n o federal regulatory framework exists to regulate CCS activities specifically
. Yet, EPA has considered how CCS is regulated under the UIC program. I n 2006 EPA determined that CCS activities are “underground injec tion” 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 Th is policy directive might be supplanted b y an EPA rulemaking in 2008. Since t here are no federal requirements governing Class V experimental technology wells , there has been a lot of confusion and uncertainty. I n March 2007 EPA issued guidance for permitting and operation of CCS pilot projects a s 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 tha t Class V is “the best mechanism f or 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 mod ified or extended to alter the goals or timetable, but cannot exceed s tate or federal permit limits. As a counterpoint to th e 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 g uidance that protection of underground drinking water and human health is the overriding concern. EPA lays out a number of considerations for r egional and s tate d irectors 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 pr ogram d irectors 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
. Th e 2007 EPA g uidance s tresse s that the primary goal of pilot projects is for EPA, the s tates, and well operators to collect and share data to better understand how CO 2 reacts and m oves 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://ww w.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 CO 2 injection
. To determine how best to manage commercial scale CCS injection operations , the g uidance suggests EPA r egional and s tate d irectors adopt a more flexible approach i n approving permits and identifying permit conditions to allow operators to “achieve project objectives.” 25 How have S tates R egulated CCS P ilots? EPA and the s tates have looked to Class I and II regulations for permit conditions for CCS pilots because of t he depth of injection and the larger volume of CO 2 injected
. Today CO 2 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 t he 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 R equirements? The technical requirements f or 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 fi nally 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 suitab le 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 f ederal regulations for Class I hazardous waste wel ls, 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 comp uter 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 chang es 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 s tate 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 t hree 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 i t 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 t he 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 Technology 31

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. R egulations require well operators to use continuous recording de vices 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/s afewater/uic/idealwel.html. 32 40 CFR Part 144.28(g)(1). 33 40 CFR Part 144.26(g)(1).and 17

le ak while traveling to the well, will not leak out of the well as it is injected, nor move into underground dr inking 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 o perators are also required to develop approved a mbient m onitoring pr ograms 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 Dire ctor 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 th e 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 determ ine 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 eac h permit based upon site specific criteria
. 38 O perators 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 o perators 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 submi t 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 noth ing 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 opera tor is financial ly 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 abandonmen t letter of credit; 5) Plugging and abandonment insurance; 6) M eet financial criteria and obtain a corporate guarantee for plugging and abandonment; or , 7) D emonstrate 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 perm it 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 1 46.10.and 19

certified as accurate to the Director stating that well abandonment was conducted and completed in accordance with the abandonment plan. Wha t are the C hallenges for P ermitting CCS U nder the UIC P rogram for Electric Utilities Evaluating CCS Options ? With the international, f ederal, and state interest in CCS, academic, public interest groups , and the f ederal 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 believ e 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: C ost and Space Requirem ents 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 C0 2 compression and transport v ia 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 utilitie s 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 Conce rning Regulatory Requirements Since EPA is formulating guidance or reg ulation 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 whe n th ere 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 th e operators UIC permit. However, the difficulty for well operators involved in CCS operations is finding an alternative means of disposing CO 2 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 Clas s 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 technica l 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 Wyoming 51 ). 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 CO 2 hundreds of miles to a reas with Class I wells such as the Gulf Coast. Sheer Size of CCS to Have Meaningful I mpact 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 f or CCS. Comparing the relative size of CO 2 emissions and current underground injection gives some answer to this question. Power plants accounted for 2.4 billion metric tons of CO 2 emissions in 2006 52 or approximately 86 percent of point source CO 2 emissi ons 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 4 3 million metric tons of carbon dioxide is injec ted 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 CO 2 can be separated and injected and remains doubtful that a new coal p ower plant (regardless of type) could separate and inject more than 50 percent of the CO 2 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 1 1. 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) CO 2 emissions from power plan ts 2,400 56 CO 2 in Class II wells for oil recovery 43 57 Class I hazardous waste 22 58 Regional Carbon Sequestration Partnerships, total 2 Space Requir ements for the Injection Well DOE has estimated that injecting 0.9 million metric tons of CO 2 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 CO 2 captured from a 300 MW boiler, the surface area r equirement 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 SO 2 and NOX
. The inject ion 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 th en dilute d wa stewaters 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, CO 2 will flow to fill in each rise first. In other words, unlike cur rent 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 mi les currently though t 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 CO 2 from a single power plant could have traps over a 13 mile b y 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 f ederal government retaine d 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 f ederal governm ent. 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, Electrici ty 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 N ETL 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 limi tation that it is impractical, impossible, or extremely costly to acquire title to hundreds of thousands of acres of land. Unique Potential Hazard s of Carbon Dioxide Injection While deepwell injection of liquids has occurred safely for over 20 years, there is less experience with injecting gasses like CO 2 . While most CO 2 injection s 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 potentia l h azards 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 i nitial 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 res iding 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 CO 2 , a blowout occurred during drilling at a production well in March 1982 causing the free flow of CO 2 at the well head and leakage from ground fractures directly above the site. The high rate of CO 2 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 protec ting against future accidents. 64 The report issued a number of recommendations including: determining the potential for CO 2 migration along unsealed fault and fracture zones; the potential for magmatic or seismic activity to cause damage to sealing caps r esulting in CO 2 releases; the potential for wells to transport CO 2 to the surface; and implementation of public education and CO 2 monitoring programs to minimize impact to human health and the environment from releases. 65 The risk of blowout is hard to quan tify 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 estima tes 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 CO 2 from Storage Reservoirs: Identification of Features, Events, and Processes and Lessons Learned , Earnest Orlando Lawrence Berkeley National Labora tory, Feb
. 2006. 65 Lewicki et al ., at 48

- 9. 66 Source Texas Railroad Commission at: http://www.rrc.state.tx.us/news

- relea ses/2006/100606.html

. .and 23

The DOE has a method of fin ding abandoned wells under its SEQURE program , h owever this program is not set up for national application. The SEQURE program uses low flying airplanes to detect abandoned wells and , as discussed abov e , aerial methods may not detect wells which do not ha ve 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 o il and gas producing layers can dilute the value of these deposits and ultimately return the CO 2 to the atmosphere. 67 Corrosion As CO 2 rises to the top of the injection layer, it may contact closed wells or the cement casings of older wells. If the CO2 rea cts 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 CO 2 to rise up the abandoned well to drinking water layers. Whi le 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 Cos ts 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 w ith 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 renewed 71 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. mu st 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 investi gators. 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 permitt ing 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 experien ce 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 cap acity. 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 tech nical 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 well s . In 2006, Texas had ten new and eight Class I hazardous waste permit renewal s 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 so ar. 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 cur rent 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 concep t of CCS sounds promising, regulatory agencies’ paramou nt 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 CO 2 t o 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 ap pear 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 t o deal with other issues such as amending state drinking water laws or amending f ederal environmental laws such as the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA); Endangered Species Act (ESA), Resource Conservation and R ecovery 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 CO 2 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 m ade aware of the limitations of CCS as addressed in this paper and that the issues be fully investigate d prior to mandating CCS as part of permit app roval.

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, appr ove, 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 Ge ological 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 leve ls of greenhouse gasses in the atmosphere, which is widely believed to be contributing to climate ch ange. CCS involves ca pturing carbon dioxide (CO 2 

### ) from emission sources, and injecting it into deep underground geologic formations below the lowest source of dri nking water. Figure 1 shows th e locations of deep saline aquifers, which are considered suitable repositories for CO 2 

### . The concept is to trap the
CO 2 

### 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 CO 2 

### in a stable form and location so that it is not released to the atmosphe re, there are concerns that migration of CO 2 

### from the deep rock formations GS could occur, posing potential threats to under ground 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 CO 2 

### , which U.S. EPA is calling ge ological 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/E 8-16626.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 Inje ction Control (UIC) program of the Safe Drinking Wa ter 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, a nd maintaining underground injection wells. In the preamble to the proposed regula tion, 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 qual ity on GS. The American Public Power Association (APPA) is evaluating this issue because many questions have emerged regarding liabilities associated with water – particul arly 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 de monstrations (1 – 2 megawatts) of carbon separation technology are underway. 4 

### Thus, there is uncertainty regarding potential effectiveness of CCS technol ogy, including long-term stabili ty 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 Sc hwarze Pumpe, Germany, a 600 megawatt plant fueled by lignite. The CO 2 produced by the pilot plant will not be released into the atmosphere; instead, the CO 2 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 ap proximately $30 per metric ton (tonne) of captured CO 2 , 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 CO 2 

### will be injected crosses state boundaries. 1. How many states have listed or desi gnated groundwater as “waters of the state,” and what is the significance for getting CCS permitting approval? The chart at the end of th is 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 thei r definitions of “waters of th e 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 fede ral 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 a pplicability of state clean wate r 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 th e antidegradation policy as it concerns groundwater, one could raise a claim that the po licy 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 st ate for having injected CO 2 

### , or produced briny water or any contam inant related to drilling and injection ( i.e ., muds, cement, salty produced water, mercury, arsenic, boron, NORM). U.S. EPA’s proposed regulation (includi ng the preamble) addresses how the UIC program for GS would interact with th e Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or “Superfund”). 6 

### While uncertainty remain s 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 inco rporated 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 wa ter quality issues, such issues will undoubtedly arise. These issu es 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 co mmon law action against discharges from NPDES-permitted facilities. In such situa tions, 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 th is paper, the SDWA does not pre-empt states from adopting or enforcing their own laws or regulations on unde rground injection as long as the UIC program requirements are met. Thus, the potential exists for states with sufficient state-based authorit y to take action concerni ng groundwater contamination associated with a GS operation in a neighboring state. Perhaps the greatest potential li ability associated with GS is tort actions in which a party claims it has been injured by groundwater contamination due to CO 2 

### storage. In particular, there is a concern about long-term liability once an injection well has been closed. Potential tort liability for GS is si milar 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 wa ter contamination due to leaking underground storage tanks and spills. MTBE contamin ation litigation has been filed by private citizens and states against companies that pr oduced 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 author ity to address it by regulation, and that an act of Congress would be nece ssary. Congressional action w ould certainly be the best method to assure that tort liability is lim ited. 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, Congre ss has enacted the Price-Anderson Nuclear Industries Indemnity Act to address liabi lity issues related to non-military nuclear facilities. 9 

### The Price-Anderson Ac t provides partial indemnif ication against liability claims arising from nuclear incidents. It al so creates an insurance system in which the nuclear industry funds claims up to a certai n 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 poten tial nuclear energy investors about openended liability. The U.S. Supreme has upheld th e 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 bear s a rational relationship to Congress’ concern for stim ulating 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 violativ e 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 “tak e 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 fi nding 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 a pplications for a license to construct or operate a nuclear pow er plant, and since, in the event of a nuclear accident the utility itself would probably suffer the largest damages. (d) The Act provides a reasonab ly just substitute for the common law or state tort la w 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 th e 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 whos e 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 protecti on violation, since the general rationality of the Act’s liability limitation, part icularly with reference to the congression al purpose of encouraging private participation in the e xploitation of nuc lear energy, is ample justification for the difference in treatment between those injured in nucl ear accidents and those whose injuries are derived from other causes. 10 

### A similar situation exists with the potential for large-scale GS of CO 2 

### in the United States. It is possible th at through Congressional action on CO 2 

### or through a stateby-state BACT determination that IGCC plus CCS technologies for CO 2 

### sequestration

10 Duke Power Co. v. Carolina Environmental Study Group , 438 U.S. 59, 60-61 (1978).



### 7

### would be the presumed required coal ba sed generation technology to control CO 2 

### , in the near future—perhaps as early as 2009 or 2010. GS is often presumed to be a key strategy for reducing future CO 2 

### emissions to the atmosphere. The federal government appears to expect that private industry will take the lead in financing, c onstructing, operating and maintaining GS sites. Therefore, in exchange for performing this “public good” ( i.e ., reducing the environmental impacts associat ed with production of a public commodity), Congress might opt to limit industry’s liab ility for unanticipat ed and unintended consequences of GS, including groundwater co ntamination. However, to date, none of the leading bills in Congress to address CO 2 

### from power plants have included any revisions to existing Federal enviro nmental 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 co rresponding 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. Cons titution, 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 classi fied as a water of the state now and a power plant gets permitted for operatio n, could it be affected say 5 or 10 years from now if the nearby state de signated 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 “w aters of the state.” Thus, any potential liabiliti es associated with GS operati ons affecting groundwater in a

8

### neighboring state would be present at the tim e a GS operation is si ted and permitted. In other words, potential lia bility would already ex ist, 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 su it actions available through only tort litigation for alleged CWA or SDWA violat ions 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 violati ons of state-based envi ronmental laws. The CWA provision 11 

### authorizes suits following notice against any person alleged to have violated a CWA effluent standa rd or limitation or an order issued by U.S. EPA or a state related to such a standard or limitation. A su it may also be filed ag ainst 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 provision 12 

### contains a similar citize n suit provision. It is important to note that both statutes contain express statements that other statutory or common law rights are not restricte d. 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) ma y 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 syst ems are among the most diverse of the electric utility sectors, repr esenting utilities in small, me dium and large communities in 49 states (all but Hawaii). Seventy-five pe rcent of public power systems are located in cities with populations of 10,000 or less. Th e majority of public power systems do not generate electricity and serve as distribution utilities. Overall, public power accounts for about 16 percent of all kilowa tt-hour sales to consumers. Mo re than 80% of the cities with public power utilities also manage public water utilities. APPA was created in 1940 as a non-profit, no npartisan organization. Its purposes are to advance the public policy inte rests of its members and thei r 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 Chica go 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 litig ation 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 Co mmittee 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 re gulated parties that participate in EPA rulemakings and policy regarding key Clean Water Act programs. Mr. Andes also advised trade associations, i ndustries, and municipalities on TMDLs, permits, and other water quality matters on the state and fede ral levels, including development of water quality standards, lis tings, 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 Indian apolis, 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 & Thornbur g after serving as policy director for Environment and Natura l Resources for Indiana Governor Mitch

10

### Daniels. Ms. Evans previously practiced at Barnes & Thornburg from 2000 to 2005. Ms. Evans represents businesses, local governme nts, and trade associations throughout the country on all aspects of environmental comp liance, including legisl ative and regulatory development; permitting; and enforcement. She has litigated environmental cases in federal, state, and administrati ve courts, and has negotiated w ith federal, state, and local agencies to achieve resolutions to complex e nvironmental issues. As Governor Daniels’ policy director for Environment and Natu ral Resources, Ms. Evans developed and advocated policy on significant national, regi onal, 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 Barn es & Thornburg in 2000, Ms. Evans was chief of the Water Rules Section at the Indiana De partment 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 Labor atory (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 Stat e” for U.S. States and Territories.
APPA Contact: Theresa Pugh Director, Environmental Services 1875 Connecticut Ave, NW, 12 th 

### Floor Washington, DC 20009 202-467-2956 TPugh@APPAnet.orgAPPENDIX 1: “WATERS OF THE STATE” SURVEY CHARTSTATELAWDEFINITION OF “WATERS OF THE STATE”LINKAlabamaADEM 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 thestate, natural or artificial. This does not include waters which are entirelyconfined and retained completely upon the property of a single individual,partnership or corporation unless suchwaters are used in interstatecommerce.http://www.adem.state.al.us/regulations/Div6a/Div6VolIeff27May2008.pdfAlaskaAS 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 ArcticOcean, in the territorial limits of the state, and all other bodies of surface orunderground water, natural or artificial, public or private, inland or coastal,fresh or salt, which are wholly or partially in or bordering the state or underthe jurisdiction of the state.http://www.touchngo.com/lglcntr/akstats/Statutes/Title46/Chapter03/Section900.htmAmericanSamoaASC 24.0201“Fresh surface waters” means allfresh territorial waters including perennial,intermittent, and ephemeral freshwater streams, all natural and artificialimpoundments, springs, seeps and wetlands, including coastal wetlands notsurface-connected to the ocean. This includes all surface territorial watersthat are not embayments, open coastal waters, or ocean waters.“Ground water” means water in the part of the ground that includes allsubsurface waters, basal and parabasal water, perched water, waterpercolating through the unsaturated zone, and all saline waters below andalong the perimeter of the basal fresh water body.“Ocean waters” means those watersthat extend from the 100-fathom (600-foot or 183-meter) depth contour seaward.“Open coastal waters” means those waters that begin at the shoreline andextend seaward to the 100-fathom (600-foot or 183-meter) depth contourfrom mean lower low water. This category includes small bays with goodwater movement which do not qualify as embayments.“Territorial waters” means waters of the United States as defined in 40 CFR122.2, as well as those that are located within the jurisdiction of the territory.http://www.epa.gov/waterscience/standards/wqslibrary/territories/american_samoa_9_wqs.pdf1STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKArizonaARS Title 49-201“Waters of the state” meansall waters within the jurisdiction of this stateincluding all perennial or intermittent streams, lakes, ponds, impoundingreservoirs, marshes, watercourses, waterways, wells, aquifers, springs,irrigation systems, drainage systems and other bodies or accumulations ofsurface, underground, natural, artificial, public or private water situatedwholly or partly in or bordering on the state.http://www.azleg.state.az.us/FormatDocument.asp?inDoc=/ars/49/00201.htm&Title=49&DocType=ARSArkansasAR BLR 8-4-102“Waters of the state”means all streams, lakes, marshes, ponds, watercourses,waterways, wells, springs, irrigation systems, drainage systems, and all otherbodies or accumulations of water, surface and underground, natural orartificial, public or private, which are contained within, flow through, orborder upon this state or any portion of the state.http://www.arkleg.state.ar.us/NXT/gateway.dll?f=templates&fn=default.htm&vid=blr:codeCaliforniaCA CODE 2-13050“Waters of the state” means any surface water or groundwater, includingsaline waters, within the boundaries of the state.http://law.justia.com/california/codes/wat/13050-13051.htmlColorado5 CCR 1002-31“State waters” means any and all surface and subsurface waters which arecontained in or flow in or through this state, but does not include waters insewage systems, waters in treatment works of disposal systems, waters inpotable water distribution systems, and all water withdrawn for use until useand treatment have been completed.http://www.cdphe.state.co.us/regulations/wqccregs/ index.htmlConnecticutCT Statutes 22a423“Waters” means all tidal waters,harbors, estuaries, rivers, brooks,watercourses, waterways, wells, springs, lakes, ponds, marshes, drainagesystems and all other surface or underground streams, bodies oraccumulations of water, natural or artificial, public or private, which arecontained within, flow through or border upon this state or any portionthereofhttp://cga.ct.gov/2007/pub/Chap446k.htm#Sec22a-423.htm2STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKDelaware7 DNREC 7202“State Waters” or “Waters OfThe State” means all water, on the surface andunder the ground, wholly or partially within, or bordering the State, or withinits jurisdiction including but not limited to:• Waters which are subject to the ebb and flow of the tide including, but notlimited to, estuaries, bays and the Atlantic Ocean;• All interstate waters, including interstate wetlands;• All other waters of the State, suchas lakes, rivers, streams (includingintermittent and ephemeral streams), drainage ditches, tax ditches, creeks,mudflats, sandflats, wetlands, sloughs, or natural or impounded ponds;• All impoundments of waters otherwisedefined as waters of the State underthis definition;• Wetlands adjacent to waters (otherthan waters that are themselveswetlands) 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 ofsubsection (1) of this definition) arenot “State waters” or “Waters of theState.”http://regulations.delaware.gov/AdminCode/title7/7000/7200/7201.shtml#TopOfPageFloridaFL Stat. 403.031“Waters” include, but arenot limited to, rivers, lakes, streams, springs,impoundments, wetlands, and all other waters or bodies of water, includingfresh, brackish, saline, tidal, surface,or underground waters. Waters ownedentirely by one person other than the state are included only in regard topossible discharge on other property or water. Underground waters include,but are not limited to, all underground waters passing through pores of rockor soils or flowing through in channels, whether manmade or natural. Solelyfor purposes of s. 403.0885, waters of the state also include navigable watersor waters of the contiguous zone as usedin s. 502 of the Clean Water Act, asamended, 33 U.S.C. ss. 1251 et seq., as in existence on January 1, 1993,except for those navigable waters seawardof the boundaries of the state setforth in s. 1, Art. II of the StateConstitution. Solely for purposes of thischapter, waters of the state also include the area bounded by the following:[specific boundaries omitted]http://www.leg.state.fl.us/statutes/index.cfm?App_mode=Display_Statute&Search_String=&URL=Ch0403/Sec031.HTM3STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKGeorgiaGA 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 orartificial, lying within or forming a part of the boundaries of the State whichare not entirely confined and retainedcompletely upon the property of asingle individual, partnership, or corporation.http://www.gaepd.org/Documents/rules_exist.htmlGuamGuam PL 26-32“Groundwater”: all subsurfacewater and includes basal and parabasal water,perched water, all water below thegroundwater table, water percolatingthrough the unsaturated zone (vadosewater), all saline waters below andalong the permimeter of the basal fresh water body (freshwater lens), andwater on the surface that has been collected with the specific intent ofrecharging or disposing of that water tothe subsurface by means of injection,infiltration, percolation, etc.“Marine Waters”: all coastal waters off-shore from the mean high watermark, including estuarine waters, lagoonsand bays, brackish areas, wetlandsand other special aquatic sites, and other inland waters that are subject to ebband flow of the tides.“Surface Waters”: all of surface freshwater and includes: (1) waters thatflow continuously over land surfaces in a defined channel or bed, such asstreams and rivers; (2) standing water in basins, such as lakes, wetlands,marshes, swamps, ponds, sinkholes, ponding basins, impoundments, andreservoirs, either natural or man-made;and (3) all waters flowing over theland as runoff, or as runoff confined tochannels with intermittent flow.http://www.epa.gov/waterscience/standards/wqslibrary/territories/guam_9_wqs.pdfHawaiiH.R.S. 342D-1“State waters”, as definedby 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; providedthat drainage ditches, ponds, andreservoirs required as part of a water pollution control system are excluded.“State waters” means all waters, fresh,brackish, or salt, around and withinthe 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 awater pollution control system are excluded.http://www.capitol.hawaii.gov/hrscurrent/Vol06_Ch0321-0344/HRS0342D/HRS_0342D0001.htm4STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKIdahoIDAPA 58.01.02“Waters And Waters Of The State”: All the accumulations of water, surfaceand underground, natural and artificial,public and private, or parts thereofwhich are wholly or partially within, which flow through or border upon thestate.http://adm.idaho.gov/adminrules/rules/idapa58/0102.pdfIllinois35 IAC 301“Waters” means all accumulations of water, surface and underground,natural, and artificial, public and private, or parts thereof, which are whollyor partially within, flow through, or border upon the State of Illinois, exceptthat sewers and treatment works are not included except as speciallymentioned; provided, that nothing herein contained shall authorize the use ofnatural or otherwise protected waters as sewers or treatment works exceptthat in-stream aeration under Agency permit is allowable.http://www.ipcb.state.il.us/documents/dsweb/Get/ Document-33351/IndianaIC 13-11-2-265“Waters”, for purposes ofwater pollution control laws and environmentalmanagement laws, means: (1) the accumulations of water, surface andunderground, natural and artificial, publicand private; or (2) a part of theaccumulations of water; that are whollyor partially within, flow through, orborder upon Indiana.(b) The term “waters” does not include: (1) an exempt isolatedwetland; (2) a private pond; or (3) an off-stream pond, reservoir,wetland, or other facility built for reduction or control of pollution orcooling of water before discharge.(c) The term includes all waters of the United States, as defined inSection 502(7) of the federal Clean Water Act (33 U.S.C. 1362(7)),that are located in Indiana.http://www.in.gov/legislative/ic/code/title13/ar11/ch2. htmlIowaIA Code 455B.171“Water of the state” means any stream, lake, pond, marsh, watercourse,waterway, well, spring, reservoir, aquifer, irrigation system, drainagesystem, and any other body or accumulation of water, surface orunderground, natural or artificial, publicor private, which are containedwithin, flow through or border upon the state or any portion thereof.http://www.legis.state.ia.us/IACODE/2003SUPPLEMENT/455B/171.htmlKansasKS65-161“Waters of the state” means all streams and springs, and all bodies of surfaceand subsurface waters within the boundaries of the state.http://www.kslegislature.org/legsrvstatutes/getStatuteFile.do?number=/65-161.html5STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKKentuckyKRS 224A.011“Waters of the state” means all streams, lakes, watercourses, waterways,ponds, marshes, wells, springs, irrigationsystems, drainage systems, and allother bodies or accumulations of water,surface and underground, natural orartificial, which are situated wholly orpartly within, or border upon, thisstate, or are within its jurisdiction,except those private waters which do notcombine or effect a junction with natural, surface, or underground waters.http://www.lrc.ky.gov/krs/224a00/011.pdfLouisianaLAC 33, part IX,Subpart 1, Section107“Waters of the State”: both the surface and underground waters within thestate of Louisiana including all rivers, streams, lakes, estuaries, groundwaters and all other water courses andwaters within the confines of thestate, and all bordering waters and the Gulf of Mexico.http://www.deq.louisiana.gov/portal/Portals/0/planning/regs/title33/33v09-200806.pdfMaineME Title 38,Section 361 A“Waters of the State” means any and all surface and subsurface waters thatare contained within, flow through, or under or border upon this State or anyportion of the State, including the marginal and high seas, except suchwaters as are confined and retainedcompletely upon the property of oneperson and do not drain into or connect with any other waters of the State,but not excluding waters susceptibleto use in interstate or foreigncommerce, or whose use, degradation ordestruction would affect interstateor foreign commerce.http://janus.state.me.us/legis/statutes/38/title38sec361-A.htmlMarylandMD Code26.08.01.01“Waters of this State” includes:(a) Both surface and underground waterswithin the boundaries of this Statesubject to its jurisdiction, including thatpart of the Atlantic Ocean within theboundaries of this State, the Chesapeake Bay and its tributaries, and allponds, lake, rivers, streams, tidal and nontidal wetlands, public ditches, taxditches, and public drainage systems within this State, other those designedand used to collect, convey, or dispose of sanitary sewage;(b) The flood plain of free-flowing waters determined by the Department ofNatural Resources on the basis of the 100-year flood frequency.http://www.mde.state.md.us/ResearchCenter/laws_regs/index.aspMassachusetts314 CMR 4.03“Waters of the Commonwealth”: All waters within the jurisdiction of theCommonwealth, including, without limitation, rivers, streams, lakes, ponds,springs, impoundments, estuaries, wetlands, coastal waters, groundwaters,and vernal pools.http://www.mass.gov/dep/service/regulations/314cmr 04.pdfMichiganMCL 324.30101“Waters of the state” meansgroundwaters, lakes, rivers, and streams and allother watercourses and waters, including the Great Lakes, within thejurisdiction of this state.http://www.legislature.mi.gov/(S(npb1fprfohsvdafzophjhvv1))/mileg.aspx?page=getObject&objectname=mcl324-31016STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKMinnesotaMAR 115.01“Waters of the state” means all streams, lakes, ponds, marshes, watercourses,waterways, wells, springs, reservoirs, aquifers, irrigation systems, drainagesystems and all other bodies or accumulations of water, surface orunderground, natural or artificial, publicor private, which are containedwithin, flow through, or border upon the state or any portion thereof.https://www.revisor.leg.state.mn.us/statutes/?id=115.01MississippiMS WPC-1“Waters of the State” means allwaters 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, surfaceand underground, natural or artificial, situated wholly or partly within orbordering upon the State, and such coastal waters as are within thejurisdiction of the State, except lakes, ponds, or other surface waters whichare wholly landlocked and privately owned, and which are not regulatedunder the Federal Clean Water Act (33 U.S.C.1251 et seq.).http://www.deq.state.ms.us/newweb/MDEQRegulations.nsf?OpenDatabaseMissouriMRS 644.016“Waters of the state”: all rivers, streams, lakes and other bodies of surfaceand subsurface water lying within or forming a part of the boundaries of thestate which are not entirely confined and located completely upon landsowned, leased or otherwise controlled by a single person or by two or morepersons jointly or as tenants in common and includes waters of the UnitedStates lying within the state.http://www.moga.mo.gov/statutes/C600-699/6440000016.HTMMontana75-5-103“State waters” means a body ofwater, 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, orimpounding pollutants; or(ii) irrigation waters or land application disposal waters when thewaters are used up within the irrigation or land application disposalsystem and the waters are not returned to state waters.http://www.epa.gov/waterscience/standards/wqslibrary/mt/mt_8_chapter5.pdfNebraskaTitle 118, Chap. 1“Waters of the State” shallmean all waters within the jurisdiction of thisState 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 orunderground, natural or artificial, public orprivate, situated wholly or partlywithin or bordering upon the State.http://www.deq.state.ne.us/7STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKNevada:NRS 445A.415“Waters of the State” means allwaters situated wholly or partly within orbordering upon this State, including but not limited to:1. All streams, lakes, ponds, impounding reservoirs, marshes, watercourses, waterways, wells, springs, irrigation systems and drainagesystems; and2. All bodies or accumulations of water, surface and underground,natural or artificial.http://www.leg.state.nv.us/NRS/NRS445A.html#NRS445ASec415NewHampshireNH RSA 485-ANH RSA 485-C(GroundwaterProtection Act)The purpose of this chapter is to protect water supplies, to prevent pollutionin the surface and groundwaters of the state and to prevent nuisances andpotential health hazards. In exercisingany and all powers conferred upon thedepartment of environmental services under this chapter, the departmentshall be governed solely by criteria relevant to the declaration of purpose setforth 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 allstreams, lakes, or ponds bordering on the state, marshes, water courses, andother 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://www.gencourt.state.nh.us/rsa/html/NHTOC/NHTOC-L.htmNew JerseyNJAC 7:9B“Waters of the State” meansthe ocean and its estuaries, all springs, streams,wetlands, and bodies of surface or ground water, whether natural orartificial, within the boundaries of the State of New Jersey or subject to itsjurisdiction.http://www.state.nj.us/dep/wms/bwqsa/docs/0608_SWQS.pdfNew MexicoNMAC 20.8“Water” means all water including water situated wholly or partly within orbordering upon the state, whether surface or subsurface, public or private,except private waters that do not combine with other surface or subsurfacewater.http://www.nmenv.state.nm.us/Common/regs_idx.html8STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKNew YorkNYECL 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 theterritorial limits of the state of New York and all other bodies ofsurface or underground water, natural orartificial, inland or coastal, freshor salt, public or private (except those private waters which do notcombine or effect a junction with natural surface or underground waters),which are wholly or partially within or bordering the state or within itsjurisdiction.http://law.onecle.com/newyork/environmentalconservation/ENV017-0105_17-0105.htmlNorth CarolinaNC 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 orprivate, 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 hasjurisdiction.http://www.ncleg.net/EnactedLegislation/Statutes/HTML/ByArticle/Chapter_143/Article_21.htmlNorth DakotaND Century Code33-16-02.1“Waters of the state” means all waterswithin the jurisdiction of this stateincluding all streams, lakes, ponds, impounding reservoirs, marshes,watercourses, waterways, and all other bodies or accumulations of water onor under the surface of the earth, natural or artificial, public or private,situated wholly or partly within or bordering upon the state, except thoseprivate waters that do not combine or effect a junction with natural surfaceor underground waters just defined.http://www.health.state.nd.us/WQ/SW/Z7_Publications/B_NDCC_WQS.pdf9STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKNorthernMarianaIslands2 CMC 3101“Commonwealth Waters” means all waters, fresh, brackish, or marine,including wetlands, surrounding or within the Commonwealth, as providedfor by Federal and Commonwealth law.Whereas the Commonwealth is almost entirely dependent on ground waterfor its drinking water supplies, theseregulations set water quality standardsfor surface waters and land disposal activities to ensure the protection of thisnatural resource. Requirements for land disposal activities will bedetermined according to groundwatermanagement zones promulgated underthe CNMI Well Drilling and Well Operation Regulations for Saipan; forTinian and Rota these requirementswill be dependent on known geologicaland aquifer characteristics, lateral distances to nearby water wells, andgeneral quality and vulnerability of existing ground water until specificgroundwater quality managementzones are developed.http://www.epa.gov/waterscience/standards/wqslibrary/territories/northern_mariana_9_wqs.pdfOhioORC Chapter 6111“Waters of the state” means all streams, lakes, ponds, marshes, watercourses,waterways, wells, springs, irrigation systems, drainage systems, and otherbodies or accumulations of water, surface and underground, natural orartificial, regardless of the depth of the strata in which underground water islocated, that are situated wholly or partly within, or border upon, this state,or are within its jurisdiction, except those private waters that do not combineor effect a junction with natural surface or underground waters.http://codes.ohio.gov/orc/6111OklahomaOAR 785:45-1-2“Waters of the state” meansall streams, lakes, ponds, marshes, watercourses,waterways, wells, springs, irrigation systems, drainage systems, and all otherbodies or accumulations of water, surface and underground, natural orartificial, public or private, which are contained within, flow through, orborder upon this State or any portion thereof.http://www.oar.state.ok.us/oar/codedoc02.nsf/frmMain?OpenFrameSet&Frame=Main&Src=_75tnm2shfcdnm8pb4dthj0chedppmcbq8dtmmak31ctijujrgcln50ob7ckj42tbkdt374obdcli00_OregonOAR 340-041-0001“Waters of the State” means lakes, bays, ponds, impounding reservoirs,springs, wells, rivers, streams, creeks, estuaries, marshes, inlets, canals, thePacific Ocean within the territorial limits of the State of Oregon, and allother bodies of surface or underground waters, natural or artificial, inland orcoastal, fresh or salt, public or private (except those private waters that donot combine or effect a junction withnatural surface or underground waters)that are located wholly or partially within or bordering the state or within itsjurisdiction.http://arcweb.sos.state.or.us/rules/OARs_300/OAR_340/340_041.html10STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKPennsylvania35 P.S. 961.1“Waters of the Commonwealth” shall be construed to include any and allrivers, streams, creeks, rivulets, impoundments, ditches, water courses, stormsewers, lakes, dammed water, ponds, springs and all other bodies or channelsof conveyance of surface and underground water, or parts thereof, whethernatural or artificial, within or onthe boundaries of this Commonwealth.http://weblinks.westlaw.com/find/default.wl?spa=pac1000&rs=WEBL8.08&fn=_top&findtype=VQ&sr=TC&db=1000262&vr=2.0&rp=%2ffind%2fdefault.wl&cite=IC91077C034-3D11DA8A989-F4EECDB8638Puerto RicoPR Water QualityStandards“Waters of Puerto Rico”: All coastal waters, surface waters, estuarinewaters, ground waters and wetlandsas defined in this Regulation.http://www.epa.gov/waterscience/standards/wqslibrary/pr/pr_2_wqs.pdfRhode IslandRI GA 46-15“Waters of the State” or “The Waters” means all surface water andgroundwater of the State of Rhode Island, including all tidewaters, territorialseas, wetlands, and land masses partially orwholly submerged in water; andboth inter- and intra-state bodies of water which are, have been or will beused in commerce, by industry, for theharvesting of fish and shellfish or forrecreational purposes.http://www.dem.ri.gov/pubs/regs/South CarolinaSC Code 48-1-10“Waters” means lakes, bays, sounds, ponds, impounding reservoirs, springs,wells, rivers, streams, creeks, estuaries, marshes, inlets, canals, the AtlanticOcean within the territorial limits of the State and all other bodies of surfaceor underground water, natural or artificial, public or private, inland orcoastal, fresh or salt, which are wholly or partially within or bordering theState or within its jurisdiction.http://www.scstatehouse.net/CODE/t48c001.htmSouth DakotaSDAR 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, drainagesystems, and all other bodies or accumulations of water, surface andunderground, natural or artificial, public orprivate, situated wholly or partlywithin or bordering on the state, but not waste treatment systems, includingtreatment ponds or lagoons designed tomeet the requirements of the CWAother than cooling ponds as defined in 40 C.F.R. § 423.11(m) (July 1, 1991).http://legis.state.sd.us/rules/DisplayRule.aspx?Rule=74:51:01:01TennesseeTN Water ControlAct of 1977“Waters of the state”: any and all water, public or private, on or beneath thesurface of the ground, which are contained within, flow through, or borderupon Tennessee or any portion thereof except those bodies of water confinedto and retained within the limits ofprivate property in single ownershipwhich do not combine or effect a junction with natural surface orunderground waters.http://www.aswm.org/swp/tennessee9.htm11STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKTexasTX WATERCODE 26“Water” or “water in the state” means groundwater, percolating orotherwise, lakes, bays, ponds, impounding reservoirs, springs, rivers,streams, creeks, estuaries, wetlands, marshes, inlets, canals, the Gulf ofMexico, inside the territorial limits of the state, and all other bodies ofsurface water, natural or artificial, inland or coastal, fresh or salt, navigableor nonnavigable, and including the bedsand banks of all watercourses andbodies of surface water, that are wholly or partially inside or bordering thestate or inside the jurisdiction of the state.http://tlo2.tlc.state.tx.us/statutes/docs/WA/content/pdf/wa.002.00.000026.00.pdfUtahUT Admin. CodeR317-1“Waters of the state” means all streams, lakes, ponds, marshes, watercourses, waterways, wells, springs, irrigation systems, drainage systems, andall other bodies or accumulations of water, surface and underground, naturalor artificial, public or private, whichare contained within, flow through, orborder upon this state or any portion thereof, except that bodies of waterconfined to and retained within thelimits of private property, and which donot develop into or constitute a nuisance, or a public health hazard, or amenace to fish and wildlife, shall not be considered to be “waters of thestate” under this definition (Section 19-5-102).http://www.rules.utah.gov/publicat/code/r317/r317-001.htmVermont10 V.S.A. 1390,1391“Groundwater” means water below the land surface, but does not includesurface 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 groundwaterresources to maintain high quality drinking water and shall manage itsgroundwater resources to minimize the risks of groundwater qualitydeterioration by limiting human activities that present unreasonable risks tothe use classifications of groundwater in the vicinities of such activitieswhile balancing the state's groundwater policy with the need to maintain andpromote a healthy and prosperous agricultural community.http://www.leg.state.vt.us/statutes/sections.cfm?Title=10&Chapter=048Virgin Islands12 VIC 7.182(f)“Waters of the UnitedStates Virgin Islands” means all waters within thejurisdiction 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 otherbodies or accumulations of water, surface and underground, natural orartificial, public or private, situatedwholly or partly within or borderingupon the United States Virgin Islands, including the territorial seas,contiguous zones, and oceans.http://www.michie.com/virginislands/lpext.dll?f=templates&fn=mainh.htm&cp=vicode12STATE LAWDEFINITION OF “WATERS OF THE STATE”LINKVirginiaVA Code 62.1-44-2“Water” includes all waters, on the surface and under the ground, wholly orpartially within or bordering the Commonwealth or within its jurisdictionand which affect the public welfare.http://leg1.state.va.us/cgibin/legp504.exe?000+cod+62.1-10WashingtonRCW 90.48.020Wherever the words “waters of the state” shall be used in this chapter, theyshall be construed to include lakes,rivers, ponds, streams, inland waters,underground waters, salt waters and all other surface waters andwatercourses within the jurisdiction of the state of Washington.http://apps.leg.wa.gov/RCW/default.aspx?cite=90.48.020Washington,D.C.DCMR Title 21,Chapter 11Waters of the District or District waters - flowing and still bodies of water,whether artificial or natural, whether underground or on land, so long as inthe District of Columbia, but excludes water on private property preventedfrom reaching underground or land watercourses, and also excludes water inclosed collection or distribution systems.http://os.dc.gov/os/cwp/view,a,1207,q,639264.aspWest VirginiaWVC 22-11-3“Water resources”, “water” or “waters” means any and all water on orbeneath the surface of the ground, whether percolating, standing, diffused orflowing, wholly or partially within this state, or bordering this state andwithin its jurisdiction, and includes, without limiting the generality of theforegoing, natural or artificial lakes,rivers, streams, creeks, branches,brooks, ponds (except farm ponds, industrial settling basins and ponds andwater treatment facilities), impounding reservoirs, springs, wells,watercourses and wetlands.http://law.justia.com/westvirginia/codes/22/wvc22-11-3.htmlWisconsinWI NR 103.03“Waters of the state” includes those portions of Lake Michigan and LakeSuperior 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 orartificial, public or private, within the state or its jurisdiction.http://www.legis.state.wi.us/rsb/code/nr/nr103.pdfWyomingW.S. 35-11“Waters of the state” means all surface and groundwater, including watersassociated with wetlands, within Wyoming.http://soswy.state.wy.us/Rules/RULES/6547.pdf13