Mid-Kansas Electric Company, 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, 2011

By

Wayne Penrod

Executive Manager, Environmental Policy

PO Box 1020

Hays, KS 67601

(785) 623-3313
1

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 generating 

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 serve more than 400,000 customers in central and western Kansas, 

virtually all of which are located in small towns and rural settings. Nearly 48,000 of 

these retail electric consumers have annual incomes considered by the United States 

federal government to be at or below the poverty level. Because the cost of generating 

and transmitting electricity to its members must be borne by relatively 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 is powered by natural gas, 

42% is powered by coal, and the remaining 10% comes from wind energy. Sunflower

owns and operates a 360 MW net capacity pulverized coal-fired electric generating unit 

(“EGU”) at its Holcomb Generating Station (“Holcomb Station”) in Finney County, 

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 facilities and equipment, generally 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 CO2, all 

of which will affected by this rulemaking. Additionally, Mid-Kansas receives electric 

power and energy, though a power purchase agreement, that originates from three 

additional fossil-fired EGUs, which also will be affected by 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 program 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, because 
3

unlike other emissions regulated under the CAA, there are no viable emissions control 

technologies applicable to reducing CO2, the main GHG component in EGU emissions. 

In particular carbon capture and storage (CCS) is not developed technology as 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 be considering. This is very troubling, and contrary to the requirement that EPA 

present regulatory options for review by 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) clearly 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 mitigation 

requirements, reduction goals, or caps. That is not their purpose. 

Section 111 standards and requirements are intended to secure uniformity based 

on proven technology and are not meant to provide an indirect means to establish nationwide emissions reductions or mitigation goals. NSPS, by statute, is designed to secure 

implementation of technology that first and foremost has been “adequately 

demonstrated,” typically referred to as “best demonstrated technology” (BDT). In this 
4

context, EPA has no broad mandate or even discretionary authority under Section 111 to 

expand its powers to promulgate provisions incorporating national or source category

GHG reductions or mitigation goals.

Further, EPA cannot require any new or modified source to install and operate 

any particular technological system of continuous reduction to comply with any new 

source standard of performance, since such emission reduction technology does not exist 

commercially, It follows that EPA cannot simply impose a fuel choice that has the same 

effect as the mandate of a particular control technology. 

In addition, it is important to note that Congress explicitly considered a cap-andtrade regime last year to address climate concerns and rejected such an approach. It is illadvised for EPA to propose an NSPS regulatory program that would, in effect, impose 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 reductions. Unless and until Congress specifically 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 requirements 
5

are based on or designed to secure an overall source category reduction goal; national 

GHG emissions reduction goal; or a level of GHG intensity averaged 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 natural gas over coal or 

one type 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 generally objectionable so 

long as the BDT for those sources not willing or able to participate in “off source” actions

are not adversely affected.

While some utilities, small and large, may benefit 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. For those 

entities which are realistically unable to utilize off-source mitigation, factoring those 

options into a source BDT would heavily prejudice those small business entities unable to 

participate. Ultimately then, inclusion of “presumed” mitigation into the BDT would 
6

actually 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 CO2/MWh metric cannot realistically be applied to EGUs without accounting for 

significant and unavoidable variables, EGU heat rates and thus the CO2/MWh rates vary 

significantly over the EGU operating range and the duty-cycle to which the unit is 

committed. Moreover, EGU heat rate characteristics and thus the corresponding 

CO2/MWh rates are largely unit specific, and they can be severely impacted by

equipment conditions which cannot be quickly or easily 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 block-average variability of heat rate 

(Btu/kWh), hours online, CO2 emissions rate (lb/mmBtu) and capacity factor (%). These 

charts are not repeated here.

These charts show that the significant variability of heat rate (thus CO2 emissions) 

over time. For 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 is attributable to the utilization of the unit is primarily 

to back up wind resources. Serving in this function unavoidably causes the unit to 

operate less efficiently 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 

reasonably accommodate real-world variability in efficiency 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. For example, how would an output-based standard 

accommodate differences in parasitic load attributable to different air pollution control 

schemes employed at different plants? Similarly, as discussed in more detail below, 

certain utility boilers provide energy in multiple forms – generating not only electricity, 

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 CO2 “cannot be emitted through a conveyance 

designed and constructed to ... capture such pollutant.” CAA § 111(h)(2). In other 

words, because BDT does not currently consist of pollution control measures that 

“capture” CO2, EPA has clear authority to implement work practice standards. EPA 

should take full advantage of this authority. Doing so would avoid the need to set 

numeric emissions limitations in the first instance.

But, to the extent EPA considers setting emissions limitations, EPA should use an 

other than output-based format in order to avoid the amazingly complex issues relating to 
8

demonstrating compliance with a standard as indicated in the materials previously 

submitted.

6. EPA must reconcile the proposed NSPS including any standards or 

guidelines with its interpretation of New Source Review (NSR) major 

modification potential violations. 

As previously mentioned, carbon 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 say so, presumably it will

be looking at energy efficiency 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 costly and 

impractical upgrades and changes not otherwise legally 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 smaller 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 yield different GHG emissions. NSPS 

must not effectively dictate fuel switching. For example, fleet averaging based on a 

natural gas derived NSPS could economically prejudice smaller systems that operate

fewer sources, have less fuel diversity or utilize 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. For example, fossil 

fuel units that cycle or follow base-load or renewable generation cannot achieve the same 

overall efficiency as other similarly designed units that do not cycle in this manner. As 

identified at the second SER panel, the efficiency of existing facilities were long-ago 

determined and the tools available to improve efficiency are limited by the design 
10

operating temperatures and pressures which cannot be altered short of reconstruction. In

many cases 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 years 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 catalytic reduction units 

(SCRs), baghouses, wet electro-static participators (ESPs), dry sorbent injection and 

cooling towers. All these devices require significant amounts of energy, and by

definition, these EGUs will become less energy efficient. It is quite plausible many 

EGUs will become notably less energy efficient over the next several years than they are 

now. NSPS requirements must take the continuing addition of these types of controls 

resulting in rising EGU energy inefficiencies into account in this rulemaking process. 

Lastly, 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 remaining 
11

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 separate source category.

The imposition of any NSPS 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 CO2. Capture technology for 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 commercially viable, such is 

not now the case. Further, while the gaseous products of combustion from integrated 

combustion, combined-cycle (IGCC) facilities may be more CO2 more capture-ready, 

none of systems have ever been constructed at the scale necessary to accommodate power 

generation facilities being proposed.

The issuance of requirements to deploy immature capture technology will have 

the undesirable effect of deferring projects that otherwise will lead to needed 

development of the carbon capture technology desired1. NRECA developed and 

 

1 Deployment of early supercritical pulverized coal technology, which was an 

industry-supported voluntary effort 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 of the 

problems encountered. An even more severe response to an immature governmentmandated requirement that can be avoided by de-selecting certain generation 
12

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 situations 

completed. These projects include all three coal-based technologies discussed above, and 

the individual units range in size form 75-MW to 900 MW. Some 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 CO2 emissions. Any new 

unit NSPS standard proposed by EPA must not foreclose these permitted projects, 

undertaken as good faith energy solutions, 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 ultimately creates great uncertainty for the projects until the rule is 

finalized. Ultimately the NSPS may prevent 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 Western Kansas. 

This resource will replace energy currently generated from other coal-based resources. 

The PSD permit was issued in December 2010.

By the time an air permit is issued for such a project, years of effort and millions 

of dollars have been invested in it. Under ordinary circumstances, 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 applicable 

NSPS and could manage their projects accordingly – either scheduling the 

commencement of construction prior to proposal or factoring potential new requirements 

into the original design. But, 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 Agency ultimately 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 decides to stick with the current schedule to propose the NSPS rule 

by September 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. For 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 fleet 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 entirely 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 health and environmental impact 

and energy requirements) the Administrator determines has been 

adequately demonstrated.

Carbon capture and sequestration (CCS) is not yet adequately demonstrated. 

While CCS holds the promise of removing in excess of 90 percent 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. Commercialscale quantities of carbon dioxide have been injected into oil and gas formations for many 

years for the purpose of enhancing oil and gas recovery. However, the potential use of 
15

such technologies requires a happy coincidence 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 deployment 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 year of CO2 has been injected, and none at which CO2 has been 

injected at a rate equal to the CO2 generated annually by a relatively small 250 MW 

EGU. There are 320 units of that size or larger in the United States, comprising the vast 

majority of 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 adequately demonstrated. Existing fossil-fueled plants 

may or may not be located near suitable sequestration sites and, if not, CO2 pipeline 

networks are not widely available, even assuming lengthy transport of CO2 would be 

cost-effective within the BDT context.

The report of the President’s Interagency Task Force on Carbon Capture and Storage 

notes:

 

2

“Existing U.S. Coal Plants,” SOURCE 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 CO2 capture 

component technologies and advanced power generation 

technologies to significantly reduce the cost of CCS, to 

facilitate widespread cost-effective deployment after 2020. 

[Emphasis added].3

In short the President’s task force assumes additional research for a number of years will 

be necessary before CCS can be widely deployed.

Setting aside technical readiness, there are legal and commercial barriers to CCS 

deployment that apply to all facilities, including risk management. The task force report

states:

Long-standing regulatory programs 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 Task 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 deployment of CCS, and frustrates gaining the experience needed to 

determine that CCS has been adequately demonstrated.

EPA recently put in place a regulatory structure under the Underground Injection 

Control (UIC) program to regulate geologic sequestration of CO2. While helpful in many

respects in providing industry with the parameters that will be required for siting, 

construction, operation, monitoring, and post-closure care of a geologic sequestration 

facility, the UIC rule for geologic sequestration sites leaves several key issues essentially 

unresolved, which are material in determining whether to proceed with CCS. 

In particular, EPA declined to clearly indicate or, within the scope of its authority, 

limit the applicability of regulation and liability under the Resource Conservation and 

Recovery Act (RCRA) and liability under the Comprehensive Environmental Response, 

Compensation, and Liability Act (CERCLA or Superfund).

The final rule declined to state that regulation of CO2 injectate as a RCRA 

hazardous waste would not apply. While clarifying that CO2 itself is not a hazardous 

waste, the rule states that “owners or operators will need to determine whether the CO2
18

stream is hazardous under EPA’s RCRA regulations, and if so, any injection of the CO2

stream may only occur in a Class I hazardous waste injection well.5

EPA took no steps in the final rule to limit the applicability of Superfund liability

to geologic sequestration. The final rule states:

CO2 itself is not listed as a hazardous substance under CERCLA. 

However, the CO2 stream may contain a listed 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 from a GS facility depends entirely on 

the composition of the specific CO2 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 federally permitted 

releases will apply, but that “Class VI permits 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 Injection Control (UIC) Program 

for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, 75 Fed. Reg. 77230, 

77260 (Dec. 10, 2010).

6

Id. 

7

Id. 
19

Furthermore, other issues in the final rule, such as monitoring that is far more 

extensive than many parties recommended was necessary, may increase the cost of 

compliance sufficiently to deter deployment 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 located sequestration facility. This will 

depend on a variety of site-specific factors. A critical point is that a regulator’s 

willingness 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. A broad CCS mandate may increase pressure on regulators to approve 

sequestration sites in order to keep viable the continued operation of important generation 

assets. Decisions about financial assurance (risk management), which is required under 

the final UIC rule, will depend on whether risk can be characterized and assessed 

adequately. We raise this to emphasize that whether CCS would be available for any 

given facility at some future point is a complex determination based 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 deployment.8 Adequate 

demonstration of CCS is likely 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 space 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 square 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 years on a scale large enough to address potential migration. Assembling 

property rights sufficient to conduct large-scale sequestration may be a very complicated 

undertaking. Consider that sequestration in even a moderately 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 CO2 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 could be applied to construction of CO2

pipelines depends both on the circumstances of the project and the specifics of State law. 

A survey of State utility law shows that the availability of eminent domain authority 

depends on issues such as whether the entity that applies to construct the facility is a 

public utility, whether the pipeline is being used to serve end-use customers in the State, 

and whether the facility is to have a public use.9Such factors may make it difficult if not 

impossible to use eminent domain as an acquisition tool.

To summarize, very significant progress must be made across many critical areas 

before CCS could be considered deployable within the EGU sector. Technical, legal, 

regulatory, and financial barriers must be overcome before CCS would be even a 

candidate for NSPS BDT. Overcoming these obstacles will take years 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.