## Mid- Kansas Electric Co mpany, LLC Inc.
Comments To The Environmental Protection Agency SER Panel

On Rulemaking for Greenhouse Gas Emissions from Electric Utility Steam Generating Units Submitted Electronically to: Lanelle Wiggins RFA/SBREFA Team Leader U.S. EPA Office of Policy July 27th , 201 1 By Wayne Penrod Executive Manager, Environmental Policy

PO Box 1020 Hays, KS 67601 (785) 623 - 33131 

## Introduction Mid- Kansas Electric Company, LLC., (Mid- Kansas ) appreciates the opportunity to participate in the EPA’s Small Business Regulatory Enforcement Fairness Act (SBREFA) EPA Small Entity Representative (SER) panel proceedings to address the Clean Air Act (CAA) Section 111 NSPS GHG rulemaking for electric utility g enerating units (EGUs) and submit our comments as for consideration in development of the panel’s deliberations and recommendations . Mid- Kansas Electric Company, LLC., and Sunflower Electric Power Corporation (Sunflower) , an affiliated G&T wholesale power supplier, together own and operate a 1,257 megawatt system of wind, gas, and coal -based generating plants and a 2,300 -mile transmission network in western and central Kansas. Mid- Kansas is made up of six member cooperatives: Lane - Scott Electric Cooperative, Dighton, KS.; Southern Pioneer Electric Company, Ulysses, KS.; Prairie Land Electric Cooperative, Norton, KS.; Victory Electric Cooperative Association, Dodge City, KS.; Western Cooperative Electric Association, WaKeeney, KS.; and Wheatland Electric Cooperative, Scott City, KS. Collectively they

s erve more than 400,000 customers in central and western Kansas, virtually all of which are located in small towns and rural settings. N early 4 8,000 of these retail electric consumers have annual incomes considered by the United States federal government to be at or below the poverty level. B ecause the cost of generating and transmitting electricity to its members must be borne by relativel y few consumers , the average cost per kilowatt hour (“kWh”) to member cooperative consumers is approximately

$ 0.135 per kWh. In contrast, the average cost per kWh to consumers located in the Kansas City metropolitan statistical area (which includes Kansas City,2

Kansas; Johnson County, Kansas; and Kansas City, Missouri), serviced by investorowned utility

companies, is approximately $0.075 per kWh. At present, 48% of Sunflower’s generation capacity i s powered by

natural gas, 42% is powered by

c oal, and the remaining 10% c omes from wind energy . S unflower owns and operates a 360 MW net capacity pulverized coal - fired electric generating unit (“EGU”) at its Holcomb Generating Station (“Holcomb Station”) in Finney C ounty, Kansas. On December 16, 2010, Sunflower was issued a Prevention of Significant Deterioration permit authorizing the construction of a new 895 - MW supercritical pulverized coal - fired EGU and ancillary f acilities and equipment, generall y referred to in the aggregate as Holcomb 2, at Holcomb Station. Mid- Kansas and Sunflower members own, and Sunflower operates on their behalf, five existing fossil - fuel fired steam - electric generating facilities that emit CO 2 , all of which will affected by this rulemaking. Additionally, Mid- Kansas receives electric power and energy, though a power purchase agreement , that originat es from three additional fossil - fired EGUs, which also will be affected b y this rulemaking.
**1. The**  **SERs should**  **have the**  **opportunity to**  **comment on**  **regulatory options**  **presented to it by EPA.** First, we stress to EPA the difficulty in developing a “sensible” NSPS GHG regulatory

p rogram for small business entity EGUs under such an unrealistically short deadline, less than seven months from start to a proposed regulation. Developing NSPS for GHGs involves complexities heretofore not encountered in the NSPS context, because3

unlike other emissions re gulated under the CAA , there are no viable emissions control technologies applicable to reducing CO 2 , the main GHG component in EGU emissions. In parti cular carbon capture and storage (CCS) is not developed technology a s our comments below address in detail . Therefore, we expect EPA will have to rely on energy efficiency and possibly

work practice standards as a means of Section 111 regulation. But as of the yet, the SER panel has yet to see a single proposal by EPA on options it may b e considering. This is very troubling , and contrary

to the requirement that EPA present regulatory

options for review b y the panel . **2. Section**  **111 requires**  **that EPA**  **undertake an**  **“endangerment finding”**  **directed at**  **whether EGU**  **greenhouse gas**  **emissions endanger**  **public health**  **or welfare.** Section 111(b)(1)(A) clearl y requires that EPA issue a proposed regulation addressing the endangerment question as a requisite to actually regulating EGU GHG emissions. EPA has yet to do so

. 3. **NSPS provisions**  **and guidelines**  **to states**  **should be**  **technology -** **based and**  **should not**  **establish national**  **or EGU**  **source category** **- wide**  **GHG mi** **tigation requirements, reductio**  **n goals, or caps. That is not their purpose.** Section 111 standards and requirements are intended to secure uniformity b ased on proven technology

and are not meant to provide an indirect means to establish nationwide emissions reduction s or mitigation goal s . N SPS , by statute, is designed to secure implementation of technology that first and foremost has been “adequatel y demonstrated,” ty

pically referred to as “best demonstrated technology” (BDT). In this4

context, EPA has no broad mandate or even discretionary a uthority under S ection 111 to expand its powers to promulgate provisions incorporating national or source category GHG reduction s or mitigation goals. Further, EPA cannot require any new or modified source to install and operate any p articular technological system of continuous reduction to comply with any

n ew source standard of performance , s ince such emission reduction technology does not exist commerciall y, It follows that EPA cannot simply impose a fuel choice that has the same effect as the mandate of a particular control technology . Inaddition, it is important to note that Congress explicitly c onsidered a cap - andtrade regime last year to address climate concerns and rejected such an approach. It is ill advised for EPA to propose an NSPS regulatory program that would , in effect , impos e an outcome already rejected by Congress. EPA’s strategy to utilize the NSPS program in this manner has never been attempted before. It is an effort to shoe -horn an emission reduction or mitigation policy onto sources under an existing program never intended to accomplish or establish emission reduction s . Unless and until Congress specificall y acts to determine just how such a program should be structured within the Clean Air Act any regulatory program under consideration by EPA is likely

to be unsatisfactory

and have many unintended consequences . 4. **NSPS must**  **represent “best**  **demonstrated technology”**  **(BDT) at**  **the source**  **and require nothing more.** The intent of Section 111 is to disseminate BDT throughout the source category . NSPS provisions cannot be utilized in a top down methodology where BDT requirements5

are based on or designed to secure an overall source category reduction goal ; national GHG emissions reduction goal ; or a level of GHG intensity averag ed over multiple sources . Stated differently, NSPS must represent BDT for any single source factoring into a determination the costs of achieving the standard. For new or modified EGUs , BDT should not effectively dictate any

particular fuel use such as n atural gas over coal or one ty pe of coal over another . In other words BDT must be fuel dependent and based on the actual design of the source . Any standard or subcategory must be established on the basis of the emission source. Once the standards are established however, it seems reasonable that some sources could benefit from offset or mitigation or other reduction strategies, and so sources should have the option to meet source NSPS requirements by undertaking other actions apart from those at the source (emissions unit) . Some of these considerations were discussed in the second SER panel meeting, and these are not generall y objectionable so long as the BDT for those sources not willing or able to participate in “ off source ” actions are not adversel y affected . While some utilities , small and large, may b enefit from an off

- source mitigation or offset , many small entities lack economic opportunities based upon geographic or other location factors to address GHGs by incorporating off

- site actions. F or those entities which are realistically unable to utilize off - source mitigation , factoring those options into a source BDT would heavil y prejudice those small business entities unable to participate. Ultimatel y then, inclusion of “presumed” mitigation into the BDT would6

actuall y work to the detriment of small business entities which cannot avail themselves of such measures. 5. **Promulgating an**  **NSPS based**  **on an**  **output standard**  **would be difficult**  **if not**  **impossible to**  **implement. EPA**  **should not**  **set output** **- based**  **GHG emissions**  **limits.** Consistent with presentations made to the SER panel , an output derived standard such as CO 2/MWh metric cannot realistically bea pplied to EGUs without accounting for significant and unavoidable variab les, EGU heat rate s and thus the CO 2/MWh rate s vary significantl y over the EGU operating range and the duty- cycle to which the unit is committed . M oreover, EGU heat rate characteristics and thus the corresponding CO 2/MWh rates are largely unit specific , and they c an be sev erely

impacted by equipment conditions which cannot be quickly or easil y remedied . Even if such individual unit variability could be accounted for in an output standard, such a standard would be source specific. In our second meeting with the Panel, Mid- Kansas provided several charts depicting actual operating information for six power plants , two of which are operated for Mid- Kansas . The charts depicted the monthly b lock- average variability of heat rate (Btu/kWh), hours online, CO2 emissions rate (lb/mmBtu) and capacity f actor (%). These charts are not repeated here. These charts show that the significant variability of heat rate (thus CO 2 emissions) over time. F or example, the 2008 chart for Fort Dodge

– a natural gas - fired boiler operated by

Sunflower Electric Power Corporation for Mid- Kansas

– shows a range from a low of 11 , 500 Btu/kWh to a high of 13, 100 Btu/kWh.7 The Fort Dodge variability i s attributable to the utilization of the unit is primarily to back up wind resources . S erving in this functi on unavoidably c auses the unit to operate less efficientl y than it would if it did not need to “chase” the constantly-varying wind resources. This information shows that an output-based standard would not reasonabl y accommodate real -world variability in e fficiency that is caused by unavoidable operating conditions. Data for the other units presented show similar variability . We note that several additional concerns with output-based standards were raised during our meetings with the Panel. F or ex ample, how would an output-based standard accommodate differences in parasitic load attributable to different air pollution control schemes employed at different plants? S imilarly, as discussed in more detail below, certain utility

b oilers provide energy

in multiple forms

– generating not only e lectricity, but also heat used in district heating, sidewalk deicing, and industrial applications. An output based standard would not easily accommodate such units. We also note that EPA has broad authority to implement work practices in place of numeric emissions limitations because CO 2 “cannot be emitted through a conveyance designed and constructed to ... capture such pollutant.” CAA § 111(h)(2). In other words, because BDT does not currentl y consist of pollution contro l measures that “capture” CO 2 , EPA has clear authority to implement work practice standards. EPA should take full advantage of this authority . D oing so would avoid the need to set numeric emissions limitations in the first instance. But, to the extent EP A considers setting emissions limitations, EPA should use an other than output-based format in order to avoid the amazingl y complex issues relating to8

demonstrating compliance with a standard as indicated in the materials previously submitted. 6. **EPA must**  **re concile**  **the proposed**  **NSPS including**  **any standards**  **or guidelines**  **with its**  **interpretation of**  **New Source**  **Review (NSR)**  **major modification potential violations.**  As previously mentioned , c arbon dioxide is the primary GHG associated with EGUs and yet there is no available technology to directly reduce carbon dioxide emissions from these facilities. While EPA did not expressly s ay s o, presumably it will be looking at energy

e fficiency and work practice standards since no other demonstrated technologies exist . However, as discussed below, many of the current EPA regulatory initiatives are counter-productive to improved efficiency ; For example, real efficiency improvements such as turbine upgrades and numerous changes within an EGU boiler configuration such as steam tube, superheater, and reheater replacements are the sort of changes that would improve efficiency and thus reduce GHG emissions but EPA has considered such changes to be NSR major modifications triggering other costl y and impractical upgrades and changes not otherwise legall y required. In short, such efficiency improvements meant to meet EPA requirements on the one hand could lead to Clean Air Act violations on the other . It is inconsistent for EPA to require EGUs to undertake activities to comply with NSPS where such activities trigger NSR violations under EPA current policies. EPA must reconcile this conundrum if it intends to require efficiency improvements as part of its NSPS proposal.9

7. **NSPS should**  **not function**  **to economically**  **prejudice sm**  **aller systems**  **or systems**  **utilizing higher**  **carbon content**  **fuels, and**  **must account**  **for the**  **installation of additional pollution control devices.** NSPS requirements must be based on existing BDT . This requirement excludes technologies that may

be available in the future but are not commercially available now. For a new or modified facility, NSPS must not result in source “redefinition” in the BACT context. As previously stated in these comments, NSPS must be based on BDT . This requirement in practice is tantamount to BACT floor technology . EPA guidance on BACT does not require source “redefinition” and the statutory definition of NSPS requiring less than BACT precludes source redefinition here. NSPS must recognize fuel diversity and be cognizant of the fact that different fuels utilized by EGUs have different carbon contents, and with current demonstrated technologies, utilization of different fuels will yi eld different GHG emissions. NSPS must not effectively dictate fuel switching. F or example, fleet averaging based on a natural gas derived NSPS could economicall y prejudice smaller systems that operate fewer sources , have less fuel diversity or utiliz e coal. As previously stated, an NSPS based on fleet averaging is inconsistent with the NSPS statutory provisions. Further, unit size, design, and use will dictate unit efficiency . F or example, fossil fuel units that cycle or follow base - load or renewable generation cannot achieve the same overall efficiency

a s other similarly

designed units that do not cycle in this manner. As identified at the second SER panel, the efficiency o f existing facilities were long - ago determined and the tools available to improve efficiency are limited by

the design10

operating temperatures and pressures which cannot be altered short of reconstruction. In many c ases the design is limited by the size of the unit and the capital then available for the project. Also, the economics associated with installing efficiency improvements on smaller units will be quite different when compared to installing similar technologies on larger ones. The cost benefit ratio is skewed in such circumstances. The statutory definition of NSPS requires that the standards account for technology costs, thus NSPS requirements for smaller units may, and indeed should, be different than for larger ones. As EPA is well aware, new regulations finalized or likely to be finalized over the next several ye ars include the Cross State Air Pollution Rule, the Electric Utility Hazardous Air Pollutants Rule, and the Clean Water Act 316(b) cooling water intake structure rule. All these regulation will require massive new installations of add- on controls such as flue gas desulfurization units (FGDs), selective catal ytic reduction units (SCRs), baghouses, wet electro - static participators (ESPs) , dry s orbent injection and cooling towers. All these devices require significant amounts of energy, and by definition, these EGUs will become less energy efficient. It i s quite plausible many EGUs will become notably l ess energy

e fficient over the next several ye ars than they are now. NSPS requirements must take the continuing addition of these ty pes of controls resulting in rising EGU energy inefficiencies into account in this rulemaking process. Lastl y, the statute requires EPA issue guidance to the states for developing NSPS for existing units following a State Implementation Plan (SIP) like process. To carry out this mandate, EPA must consider, in addition to the factors listed above, the remaining11

useful life of an EGU and other factors that would affect existing NSPS determinations that are identified during this rulemaking process. 8. **Currently permitted EGUs should be a sep arate source category**  **.** The imposition of any NSP S standard for new EGU’s must recognize that commercial control technology, as it might be applied to all new EGUs , simply does not exist for CO 2 . Capture technology f or current pulverized- coal (PC) fired, circulating fluidized bed (CFB) steam generators , and for natural gas, combined - cycle (NGCC) facilities is under development , and while it may one day be commerciall y viable , such is not now the case. Further, while the gaseous products of combustion from integrated combustion, combined- cycle (IGCC) facilities may b e more CO 2 more capture - ready, none of s ystems have ever been constructed at the scale necessary to accommodate power generation facilities being proposed. The issuance of requirements to deplo y immature capture technology will have the undesirable effect of deferring projects that otherwise will lead to needed development of the carbon capture technology desired 1

. NRECA developed and

1 Deplo ym ent of early

supercritical pulverized coal technology, which was an industry- supported voluntary e ffort in the mid- 1960s, met with criticism of the technology

and the subsequent end of its development. Only recent wide - spread development of new generation technologies in other countries solved many o f the problems encountered. An even more severe response to an immature governmentmandated requirement that can be avoided by de - selecting certain generation12

presented to the panel a handout of 12 proposed facilities , totaling over 8000 MW, for which PSD construction permits have been issued and/or extended. Several of these projects are being developed by or for small entities. Extensive engineering and development costs for these facilities have been undertaken and in many s ituations completed. These project s include all three coal -based technologies discussed above, and the individual units range in size form 75 - MW to 900 MW. S ome of those projects included the introduction of partial carbon capture systems. At least one of them has permit terms which are BACT -based efficiency standards for CO 2 emissions. Any n ew unit NSPS standard proposed by EPA must not foreclose these permitted projects, undertaken as good faith energy s olutions, and which best meet the needs of the individual developers. These projects stand to be regulated as new sources under a proposed NSPS for GHG, which ultimatel y creates great uncertainty f or the proj ects until the rule is finalized . Ultimately the NSPS may p revent the projects from being implemented, depending on the new source standard( s ) included in the final rule. Mid- Kansas expects to be a 200 - MW owner in the 895 - MW Holcomb 2 project located in We stern Kansas. This resource will replace energy currently g enerated from other coal -based resources. The PSD permit was issued in December 201 0. By the time an air permit is issued for such a project, ye ars of effort and millions of dollars have been inve sted in it . Under ordinary c ircumstances, the developers of such technologies and fuels that would otherwise represent the best choice will likely have a similar impact.13

facilities would have ample notice of EPA’s plans to develop a potentially a pplicable NSPS and could manage their projects accordingl y – either scheduling the commencement of construction prior to proposal or factoring potential new requirements into the original design. B ut, in this case, EPA’s rulemaking schedule was announced in late 2010

– barely

six months before the date of proposal. Moreover, EPA negotiated the rulemaking deadlines in secret with environmental petitioners, making it impossible for companies to know ahead of time whether the Agenc y ultimatel y would commit itself to a fixed schedule and what milestones would be included in such a schedule. We still do not know what EPA may be intending to propose. This is extraordinarily unfair to the companies and puts at risk projects that are needed to assure reliable electric service in affected areas. If the Agency

de cides to stick with the current schedule to propose the NSPS rul e by S eptember 30, 2011, then the rule should be structured so that it does not apply to units that have been permitted, but for which construction has not yet commenced. There are several ways that this could be accomplished. F or example, EPA has broad authority to define the source category that will be regulated under any particular NSPS. In this case, the source category could be defined to exclude these units. **As justification,**  **EPA could point out that these would be the very newest units in the fl**  **eet and, as a result, can**  **reasonably be**  **expected to**  **be the**  **most efficient**  **units of**  **their kind**  . Given the severe consequences of regulating these units as new units under the NSPS, adjusting the bounds of the source category to exclude these units would be entirel y reasonable.14

9. **Carbon capture and storage is far from a demonstrated technology.** The controlling term EPA must apply for the purpose of GHG controls is “standard of performance,” which Section 111(a) of the Clean Air Act defines as:

a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non- air quality h ealth and environmental impact and energy

requirements) the Administrator determines has been adequatel y demonstrated. C arbon capture and sequestration (CCS) is not yetadequatel y demonstrated. While CCS holds the promise of removing in excess of 90 perc ent of GHG emissions from a fossil - fueled EGU and while research has accelerated in recent years , it has not progressed to the level necessary to demonstrate CCS can be deployed in power plants across the country . The Department of Energy has funded research that has demonstrated a variety of carbon capture technologies and demonstrated sequestration in promising geologic formations but these efforts were still only on a research scale and have not been demonstrated on a commercial scale. There are two commercial - scale integrated gasification combined cycle generating facilities in operation in the United States, which generate power and result in an isolable emission stream of carbon dioxide. Commercial scale quantities of carbon dioxide have been injected into oil and gas formations for many ye ars for the purpose of enhancing oil and gas recovery . However, the potential use of15

such technologies requires a happy c oincidence of geologic structures and or needs which is most certainly

not available to every

EGU. Notwithstanding these promising developments, CCS is not yet near a level of maturity that would enable its industry- wide deploy ment as a technological response to a GHG NSPS mandate. There are fewer than a handful of sites worldwide at which more than one million tons per ye ar of CO 2 has been injected, and none at which CO 2 has been injected at a rate equal to the CO 2 generated annually b y a relativel y small 250 MW EGU . There are 320 units of that size or larger in the United States, comprising the vast majority o f U.S. coal - fired generating capacity . 2 We do not have the level of experience necessary to make informed long term assessments regarding injecting carbon over long term into even one geologic formation, let alone the breadth of experience across a range of geologic formations and other site - specific conditions, necessary to make a determination that CCS has been adequatel y demonstrated. Existing fossil - fueled plants may or may not be located near suitable sequestration sites and , if not, CO 2 pipeline networks are not widel y available, even assuming lengthy transport of CO 2 would be cost- effective within the BDT context. The report of the President’s Interagency T ask Force on Carbon Capture and Storage notes:

2 “Existing U.S. Coal Plants ,” S OURCE WATCH , available at http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants (last visited Mar. 17, 2011).16 The focus of CCS RD&D is two - fold: 1) to demonstrate the operation of current CCS technologies integrated at an appropriate scale to prove safe and reliable capture and storage; and 2) to develop improved CO 2 capture component technologies and advanced power generation technologies to significantly reduce the cost of CCS, to facilitate widespread cost- effective deplo yment after 2020. [Emphasis added]. 3 In short the President’s task force assumes additional research for a number of ye ars will be necessary

before CCS can be widely deployed. Setting aside technical readiness, there are legal and commercial barriers to CCS deploy ment that apply

to all facilities, including risk management. The task force report states: Long - standing regulatory p rograms are being adapted to meet the circumstances of CCS, but limited experience and institutional capacity at the Federal and State level may hinder implementation of CCS - specific requirements. Key legal issues, such as long - term liability and property

rights, also need resolution. 4

3 Report of the Interagency T ask Force on Carbon Capture and Storage (August 2010), at 9.

4 Id., at 8.17 As the task force report notes, there are three main sets of issues that constitute significant legal barriers to undertaking CCS: regulatory structure, liability

and risk management, and property rights. It is imperative to recognize that their existence hampers the broad deploy ment of CCS, and frustrates gaining the experience needed to determine that CCS has been adequately demonstrated. EPA recentl y put in place a regulatory structure under the Underground In jection Control (UIC) program to regulate geologic sequestration of CO 2 . While helpful in many respects in providing industry with the parameters that will be required for siting, construction, operation, monitoring, and post- cl osure care of a geologic sequestration facility, the UI C rule for geologic sequestration sites leaves several key i ssues essentiall y unresolved, which are material in determining whether to proceed with CCS. In particular, EPA declined to clearl y indicate or, within the scope of its authority, limit the applicability

o f regulation and liability under the Resource Conservation and Recovery Act (RCRA) and liability under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or S uperfund). The final rule declined to state that regulation of CO 2 injectate as a RCRA hazardous waste would not apply . While clarifying that CO 2 itself is not a hazardous waste, the rule states that “owners or operators will need to determine whether the CO 218

stream is hazardous under EPA’s RCRA regulations, and if so, any injection of the CO 2 stream may

onl y occur in a Class Ihazardous waste inje ction well. 5
EPA took no steps in the final rule to limit the applicability o f Superfund liability to geologic sequestration. The final rule states:

CO 2 itself is not listed as a hazardous substance under CERCLA. However, the CO 2 stream may contain a l isted hazardous substance (such as mercury) or may mobilize substances in the subsurface that could react with ground water to produce listed hazardous substances (such as sulfuric acid). Whether such substances may result in CERCLA liability f rom a GS facility

depends entirel y on the composition of the specific CO 2 stream and the environmental media in which it is stored ( e.g., soil or ground water). 6 The final rule does note that CERCLA’s exemption for federall y permitted releases will appl y, but that “ Class VIp ermits will need to be structured to ensure that they prevent potential releases from the well, which are outside the scope of the Class VI permit and thus not considered federally permitted releases.” 7

**5** Federal Requirements Under the Underground In jection Control (UIC) Program for Carbon Dioxide (CO 2 ) Geologic Sequestration (GS) Wells, 75 Fed. Reg. 77230, 77260 (Dec. 10, 2010).

6 Id. 7 Id.19 Furthermore, other issues in the final rul e, such as monitoring that is far more extensive than many

p arties recommended was necessary, may increase the cost of compliance sufficiently

to deter deploy

ment of CCS. Regarding Liability

and Risk Management , whether geologic sequestration can be undertaken cost effectively in connection with an EGU depends in part on whether risk management is available for a proximately l ocated sequestration facility . This will depend on a variety of site - specific factors. Acritical point is that a regulator’s will ingness to approve a facility may not equate to a risk management entity’s willingness to address risk at a site. Few commercial risk management entities are likely to enter this market, as there are few with the expertise and experience in environmental risk management product lines. Abroad CCS mandate may increase pressure on regulators to approve sequestration sites in order to keep viable the continued operation of important generation assets. D ecisions about financial assurance (risk management), which is required under the final UI C rule, will depend on whether risk can be characterized and assessed adequatel y. W e raise this to emphasize that whether CCS would be available for any given facility

at some future point is a complex determination base d a range of decisions in which multiple parties will be involved.20 Further, many interested parties have called for a government role in managing CCS risks, which research has shown are an impediment to CCS deploy ment. 8 Adequate demonstration of CCS is l ikely to depend on developers understanding the boundaries of the risk associated with this nascent technology . Also, there are at least three property issues that must be addressed in conjunction with geologic sequestration: rights to the use of pore sp ace for sequestration, rights for construction of pipelines for carbon dioxide transportation, and rights to surface access for monitoring and remediation. The carbon dioxide plume from geologic sequestration will spread across an area that could comprise many s quare miles. Even if an EGU is located above a geologic formation suitable for sequestration, the owner of an electric generating unit must also acquire property rights sufficient to accommodate full - scale sequestration over a period of many ye ars on a scale large enough to address potential migration . A ssembling property rights sufficient to conduct large - scale sequestration may b e a very

c omplicated undertaking. C onsider that sequestration in even a moderatel y populated area could require acquisition of property rights from thousands of property owners. Even if sequestration would be an activity that would qualify

for use of eminent domain authority under State law, arranging property rights for the radius of a CO 2 plume is likely to

8 See Study of Legal Issues Relating to Risk and Liability in Connection with Carbon Capture and Storage , CCS ALLIANCE (July 2008).21

involve far more property owners than would be the case for a linear facility, such as a roadway, transmission line, or pipeline. Whether State eminent domain authority c ould be applied to construction of CO 2 pipelines depends both on the circumstances of the project and the specifics of State law. A survey o f State utility

l aw shows that the availability o f eminent domain authority depends on issues such as whether the entity that applies to construct the facility i s a public utility, whether the pipeline is being used to serve end-use customers in the State, and whether the facility

isto have a public use. 9 Such factors may make it difficult if not impossible to use eminent domain as an acquisition tool. To summarize, very

s ignificant progress must be made across many critical areas before CCS could be considered deplo yabl e within the EGU sector. T echnical, legal, regulatory, and financial barriers must be overcome be fore CCS would be even a candidate for NSPS BDT. Overcoming these obstacles will take ye ars and in fact CCS may never be BDT.

9 Study of Legal Issues Relating to Risk and Liability in Connection with Carbon Capture and Storage, CCS Alliance, July 23, 2008, available at www.ccsalliance.net .