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Monday, June 25, 2012

June 25, 2012

Attn: Docket ID No. EPA-HQ-OAR-2011-0660

U.S. Environmental Protection Agency

EPA Docket Center

Mail Code: 2822T

1200 Pennsylvania Ave., NW

Washington, DC 20460

RE: Comments of Coal Utilization Research Council on EPA’s Proposed Standards of 

Performance for Greenhouse Gas Emissions for New Stationary Sources: 

Electric Utility Generating Units, 77 Fed. Reg. 22,392 (April 13, 2012), Docket ID 

No. EPA-HQ-OAR-2011-0660

The Coal Utilization Research Council (CURC) respectfully submits the following comments on 

the Environmental Protection Agency’s (EPA) proposed New Source Performance Standards 

(NSPS) for carbon dioxide (CO2) emissions from certain new fossil-fuel electric generating units 

(EGUs).1 CURC was formed in 1997 and is a coalition of over 50 organizations that represent 

all aspects of the coal industry. A key part of CURC’s mission is to support the use of coal by 

advocating for the development and employment of technologies that enable coal to be used in 

an economical, efficient and environmentally compatible manner.2

INTRODUCTION & OVERVIEW OF COMMENTS

On April 13, the Environmental Protection Agency (EPA or Agency) proposed a rule to set New 

Source Performance Standards (NSPS) that limit carbon dioxide (CO2) emissions from new 

power plants burning fossil fuels. The proposed rule sets an emissions limit of 1,000 pounds of 

CO2 per megawatt-hour of power generated. While a new natural gas combined cycle unit can 

likely meet this CO2 emissions limit without additional emission controls, currently there is no 

system of controls that has been adequately demonstrated to achieve this standard for new coal 

fueled power plants. 

The impact of this proposal is nothing less than to stop the development of new coal technology, 

and the deployment of coal-based capacity in the United States, as well as frustrate efforts to 

 1 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating 

Units, 77 Fed. Reg. 22,392 (Apr. 13, 2012) (hereinafter referred to as the “proposed NSPS”). 2 See CURC website at www.coal.org.
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commercialize carbon capture utilization and storage (CCUS)3 technology. Such an outcome 

will seriously impact our Nation’s ability to continue to benefit from a strong and growing 

economy based upon a diversity of cost-competitive and abundant energy sources and also 

jeopardize the use of a key domestic energy resource – coal – that historically has been the 

lowest cost, most abundant, and reliable energy source available to electricity consumers.

No power plant developer will commit to build a new coal fueled plant without assurance that a 

cost effective, commercially acceptable CCUS technology will be available within its first 10 

years of operation to achieve CO2 emissions compliance over the extended averaging period 

proposed in the rule. Even government-supported CCUS demonstration projects that are being 

planned or underway are placed at risk by the proposed rule albeit they may be classified as a 

transition project and therefore exempt. Compounding the lack of proven CO2 capture 

technology are unresolved technical, legal, and regulatory issues concerning CO2 storage 

options. 

In addition, despite the need for further government assisted research, development, and 

demonstration of CCUS technologies, the Administration’s fiscal year (FY) 2013 budget request 

for coal-related research and development has been reduced by $93 million (nearly one-quarter) 

from what Congress appropriated in FY 2012. In the absence of a legal and regulatory structure 

to address CO2 storage options and requesting a diminished federal budget for CCUS technology 

development, the effective requirement for deployment of unproven CCUS technology is a 

wholly unrealistic expectation and does not represent a control technology that “has been 

adequately demonstrated” for establishing an NSPS. The Agency has concluded that no new 

coal fueled power generation will be built for a prolonged period of time and therefore no 

consequences will come of this proposed CO2 rule. This conclusion must be challenged. If the 

proposed rule will have no effect at this time and it endangers the development of CCUS, the 

rule should be withdrawn.

The Coal Utilization Research Council (CURC) has significant concerns regarding the proposed

rule. Our comments have been organized into the following three general categories and 

thereafter we have set forth recommendations that we ask the Agency to consider: 

I. CONCERNS REGARDING THE USE OF A SINGLE SOURCE CATEGORY THAT WOULD 

APPLY TO ALL NEW FOSSIL FUEL-BASED ELECTRIC GENERATING UNITS (EGUs);

II. CONCERNS REGARDING THE INOPERABILITY OF THE PROPOSED ALTERNATIVE 

COMPLIANCE PLAN;

III. OTHER CONCERNS REGARDING VARIOUS SECTIONS OF THE PROPOSED RULE AS IT 

APPLIES TO THE APPLICATION OF CCS; and

IV. RECOMMENDED ALTERNATIVE APPROACH TO ADDRESSING GHG NSPS FOR NEW 

COAL-FUELED POWER GENERATION

 3 Wherever CCS (carbon capture and storage) or CCUS (carbon capture utilization and storage) are referenced in 

these comments they are used interchangeably and unless specifically noted otherwise both have reference to CCS 

as defined in the proposed rule. 
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Monday, June 25, 2012

Because the status and future development of carbon capture utilization and sequestration 

(CCUS) is central to the concerns we have about the proposed rule, and the assumption made in 

the proposed rule as to the commercial availability of CCUS, we have also attached (as 

Attachment A) to these comments a recently-completed CURC assessment that specifically 

addresses the technology readiness of carbon capture and storage (CCS). This assessment 

describes the three primary electricity generation options either currently available (Integrated 

Gasification Combined Cycle, advanced pulverized coal combustion including Supercritical and 

Ultra supercritical systems) or under active development (Oxycombustion) that would be the 

coal-based power generation options relied upon for the installation of CO2 capture. 

I. CONCERNS REGARDING THE USE OF A SINGLE SOURCE CATEGORY THAT WOULD 

APPLY TO ALL NEW FOSSIL FUEL-BASED ELECTRIC GENERATING UNITS (EGUs);

A fuel neutral standard, as proposed by the EPA sets a single standard for electric generating 

units using coal in steam boilers and natural gas in combined cycle units even though these fuels 

are different and use fundamentally different technologies to convert the fuel to useful energy. 

Absent the installation of commercially unproven CCUS, coal will not be able to achieve the 

performance standard set forth in the proposed rule. 

A. GENERAL STATEMENT OF CONCERNS REGARDING THE USE OF A SINGLE SOURCE 

CATEGORY:

The methodology for setting the CO2 NSPS is a significant departure from what EPA has

previously used to establish performance standards for new fossil-fueled power plants. In past

NSPS rulemakings for power plants, EPA has set different performance standards for each fuel 

(e.g., coal, oil, natural gas) or the Agency has set a single emissions standard for all fuels based 

on the “best demonstrated technology” at all power plants, regardless of the fuels used. The 

single emissions standard is set so it can be met by the highest emitting fuel, if properly 

controlled through application of technology, and also by other fuel types with inherently lower 

emissions thereby establishing a fuel “neutral” standard.

The Agency has never set a single performance standard for all power plants based on emission 

rates achievable only by the lowest emitting fuel and technology. Yet that is what EPA is 

proposing in this rulemaking by establishing an emission rate that only natural gas combined 

cycle (NGCC) units have the potential to achieve. In the absence of proven CCUS, the rule is 

functionally equivalent to a requirement that NGCC is the sole available system of emission 

reduction. Therefore, this proposal is inconsistent with the Congressional direction that EPA’s 

standards under Section 111 of the Clean Air Act cannot “be construed to require, or to authorize 

the Administrator to require, any new or modified source to install and operate any particular 

technological system of continuous emission reduction” in order to comply with an NSPS 

standard. 42 U.S.C. § 7411(b)(5). Further, EPA explicitly states in the proposal that the 

“proposed standard is based on the degree of emission limitation achievable through natural gas 

combined cycle generation.” This statutory restraint on EPA’s authority is particularly critical in 

matters of national energy policy, where fuel diversity has proven to be one of the key elements 

in assuring adequate, reliable and affordable electricity for residential consumers, industrial 

concerns, and manufacturers. 
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B. THE SINGLE SOURCE CATEGORY APPROACH IS NOT APPROPRIATE AND CCS IS NOT 

COMMERCIALLY AVAILABLE:

The proposed rule aggregates all types of fossil fuel-fired power plants into a proposed new 

category (the TTTT category) for purposes of regulating GHG emissions.4 EPA then proposes 

an emission limit of 1000 lb. CO2/MWh, “based on the demonstrated performance of natural gas 

combined cycle (NGCC) units.”5 No other means of compliance is identified as having met the 

statutory criteria for setting a standard of performance which is problematic in three respects. 

First, a standard is applied to coal-based power systems for which EPA has not identified a 

pathway to compliance which meets either pragmatic economic standards, or the statutory 

definition for a standard of performance. Indeed, as recently as December 2011, EPA declared 

the fundamentally sound legal arguments prohibiting such a “single rule” approach.6 Second, 

the limitation has been set without a serious review of energy impacts. The EPA simply has 

assumed that currently low cost natural gas will remain so forever. Third, the reliance on a 

single compliance technology (NGCC power systems) is in clear violation of Section 111(b)(5) 

of the Clean Air Act.7

It is important to recognize that CCUS has not been applied at commercial scale to any power 

plant anywhere in the world. The Agency observes that technologies that support CO2 capture, 

CO2 compression, and pipeline transport, have already been proven and there are commercial 

integrated facilities storing and monitoring CO2 in deep saline formations. None of these 

projects, however, are simultaneously producing electricity, capturing, cleaning, compressing, 

transporting, and storing large volumes of CO2 (10-12,000 tons/day) on a continuous basis. 

Development of CCUS systems in an integrated fashion with a power generating facility under 

commercial-scale operating conditions is one of the key goals of the technology demonstrations 

and early adopter plants that the Department of Energy (DOE) is now supporting. 

These CCS demonstration projects are currently underway, financially supported by significant 

government resources, and generally utilizing enhanced oil recovery (EOR) as a storage medium 

for CO2 and as a revenue source to offset part of the cost of installing and operating CO2 capture 

systems. The existence of these projects does not constitute evidence that CCS is currently a 

commercially available technology, nor that it will be commercially available in the near future. 

As discussed in more detail below, significant technical, economic, legal, and regulatory barriers 

 4 Standards of Performance for GHG Emissions for New Stationary Sources: Electric Utility Generating Units, 

Proposed Rule, EPA, 77FR22394, April 13, 2012.

5 Ibid.

6 Response to Public Comments on Rule Amendments Proposed May 3, 2011, EPA background document 

supporting the Standards of Performance Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and 

Small Industrial-Commercial-Institutional Steam Generating Units, EPA, December 2011. In support of the 

December 2011 criteria pollutant NSPS rule, EPA stated, “basing these standards on [natural gas or distillate oil] 

would result in standards that are neither technically nor economically achievable for coal-fired EGUs. Basing the 

amended standards on the use of natural gas would preclude the development of new coal-fired EGUs since the 

standards would not be technically achievable...Therefore, basing the NSPS on [natural gas] emissions would not be 

achievable for coal-fired EGUs with any technology that EPA is aware of.” 7 Section 111(b)(5) provides, “nothing in this section shall be construed to require, or to authorize the Administrator 

to require, any new or modified source to install and operate any particular technological system of continuous 

emission reduction to comply with any new source standard of performance.”
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must be addressed before CCS is commercially available for coal-based power generation. 

Certainly, the scope and magnitude of the barriers are significant enough that CCS fails to meet 

the statutory criteria for setting a standard of performance. EPA’s inability to assert that CCS 

does not achieve these criteria (“we are not proposing that CCS does or does not qualify as the 

‘best system of emission reduction’ that ‘has been adequately demonstrated’...”)8, given the 

broad discretion of the 1973 Portland Cement decision (which accepts almost any projection of 

technology advances short of “ ‘crystal ball’ inquiry”)9 speaks for itself. 

In proposing to create a national standard that will have very adverse impacts upon the future use 

of coal, the EPA cannot simply assert “that CCS has been demonstrated to be technologically 

achievable”, that “CCS is feasible and sufficiently available”. The Agency references an August, 

2010 report by the Interagency CCS Task Force (IATF) which noted that early CCS projects face 

economic challenges, first-of-a-kind technology risks and high cost, but the EPA concludes 

“there are no insurmountable technological, legal, institutional, regulatory or other barriers that 

prevent CCS from playing a role in reducing GHG emissions.” The IATF also concluded that 

“CO2 removal technologies are not ready for widespread implementation on coal-based power 

plants, primarily because they have not been demonstrated at the scale necessary to establish 

confidence for power plant application”10 and “.... CCS technologies will not be widely 

deployed in the next two decades absent financial incentives that supplement projected carbon 

prices. In addition to the challenges associated with cost, these projects will need to meet 

regulatory requirements that are currently under development. 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.” The report further cited there are “other technical challenges associated with the 

application of these CO2 capture technologies...” including, “high capture and compression 

auxiliary power loads, capture process energy integration with existing power system, impacts of 

flue gas contaminants (NOx, SOx, PM) on CO2 capture systems, increased water consumption 

and cost effective O2 supply for oxy-combustion systems.”11 

Given that coal plants emit approximately one ton (2,000 lb.) of CO2 per MWh produced, a 

carbon capture level of about fifty percent (50%) will be required to achieve a 1,000 lb.

CO2/MWh standard. Relative to a baseline coal plant without capture, DOE estimates that the 

increase in cost of electricity (COE) at 50 percent carbon capture would be 43.3 percent,

12 

This also represents a 43.3 % increase in costs over a NGCC13 and demonstrates that this

standard will result in coal being noncompetitive relative to a NGCC plant which requires no 

additional equipment.

 8 Op. Cit., Standards of Performance for GHG Emissions, 77FR22411, April 13, 2012.

9 Portland Cement Association v EPA, 486 F.2d 375 (D.C. Cir.), 1973. 10 Report of the Interagency Task Force on Carbon Capture and Storage, p.34, August 2010. 11 Ibid., p.35. 12 US DOE, Cost and Performance of PC and IGCC Plants for a range of Carbon Dioxide Capture, DOE/NETL 

1011/1498, May 27, 2011

13 US DOE, Cost and Performance Baseline for Fossil Energy Plants, Volume 1, Bituminous Coal and Natural Gas to 

Electricity, Revision 2, DOE/NETL-2010/1397 November 2010
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Similarly, a recent Congressional Research Service (CRS) report14 noted that there are 

numerous non-technical barriers to CCS that must be effectively resolved before the technology 

can be broadly deployed. While observing that recent Underground Injection Control rules may 

protect groundwater, CRS found that other key issues remain to be addressed. “Some of these 

include the long-term liability for injected CO2, regulation of potential emissions to the 

atmosphere, legal issues if the CO2 plume migrates underground across state boundaries, private 

property rights of owners of the surface lands above the injected CO2 plume, and ownership of 

the subsurface reservoirs (also referred to as pore space).” Other recently issued reports have 

reached similar conclusions regarding the readiness and commercial availability of CCS.

In general, it is doubtful that performance guarantees can be obtained for CCS systems that 

employ saline storage, and there are unanswered questions regarding the accounting of CO2

storage resulting from EOR. Such storage may be project-specific, given the general 

misalignment between power plant production of CO2 and CO2 needs over time by an EOR 

project. This misalignment argues for addressing CCS in a case-by-case Best Available Control 

Technology (BACT) context (as currently required by the Tailoring Rule) instead of a mandatory 

NSPS context. In any event, it leads to the conclusion that CCS fails to meet the statutory 

criteria required for relying on the technology as a basis for setting an NSPS.

CURC which includes manufacturers and suppliers of CCS related equipment and technologies 

as well as potential users of CCS technologies, submits that CCS has not been adequately 

demonstrated at any level that would suggest it is “technologically achievable, sufficiently 

available” and therefore ready to be deployed on a commercial basis

The preamble to the proposed CO2-NSPS discusses technical feasibility of CCS technologies 

without regard to cost, commercial performance guarantees, the complexity of CO2 storage, or 

associated legal issues and storage liabilities. The limited number of planned demonstration 

projects in the U.S. is falling, due in part to the weak economy, high costs, technical risks, and 

liability risks. In the time period since EPA proposed its rule on April 13, two other CCS-related 

projects have indicated that they will not move forward. These are the Taylorville project in 

Illinois, and the Good Spring IGCC project in Pennsylvania (both now moving forward as 

NGCC projects). It is CURC’s opinion that this proposed rule does nothing to incentivize, and 

may in fact discourage, the further development or deployment of CCS technologies. The 

economic, technology, legal, and regulatory risks are significant. Commercially available CCS 

for coal-based power generation will not be a viable control option until those risks have been 

appropriately addressed through multiple demonstrations and the experience gained through long 

term operation by early adopters. Stringent standards increase the technology risk of CCS and 

will further hinder demonstration and deployment; therefore it is unclear how EPA can then 

conclude that CCS technology will mature and costs will decline.

II. CONCERNS REGARDING THE INOPERABILITY OF THE PROPOSED 

ALTERNATIVE COMPLIANCE PLAN

The Agency has included in the proposed rule an “alternative compliance option” that would 

allow construction of a new coal fired plant without immediate inclusion or operation of CCS. 

 14 Carbon Capture and Sequestration: Research, Development, and Demonstration at the U.S. DOE, CRS, R42496, 

April 23, 2012.
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EPA states that it believes the 30-year averaging option, in addition to potential government 

programs that could fund near-term CCS projects, “helps to alleviate any concerns that today’s 

action could restrict new coal-fired construction.”15

It is worthwhile to understand the Agency’s logic behind the alternative compliance option. 

A. THE PROPOSED RULE REQUIRES COAL-FUELED ELECTRIC GENERATING UNITS TO USE A 

TECHNOLOGY THAT HAS NOT BEEN ADEQUATELY DEMONSTRATED

First, by not designating CCS as a best system of emission reduction (BSER)16 the Agency is not 

required to show that CCS is an “adequately demonstrated” system of emission reduction. In 

fact, EPA’s inability to assert that CCS meets the statutory criteria for BSER demonstrates that it 

does not meet the required criteria for setting a standard of performance. EPA specifically states 

that “we are not proposing that CCS does or does not qualify as the ‘best system of emission 

reduction’ that ‘has been adequately demonstrated.’”.

17 It is telling that even though the Agency 

has broad discretion in projecting technology advances as part of an NSPS as a result of the 1973 

Portland Cement decision (which accepts almost any projection of technology advances short of 

“ ‘crystal ball’ inquiry”)18 the agency is still unwilling to posit CCS as a technology that can 

meet BSER. It is clear that CCS is currently, at least, not an available compliance option, and 

the Agency does not have the ability to determine that it will in fact be proven over the 10 years 

that sources have to install and begin operation of CCS under the alternative compliance pathway

Second, when designating BSER, the Agency is required to take into account “energy 

requirements” and, if CCS is not an available option, the test of “energy requirements” is 

jeopardized. The Agency argues19 that the alternative compliance option allows for the use of 

coal with CCS either immediately or after 10 years through use of the alternative compliance 

option. If CCS is not currently available (which the Agency avoids saying by not designating 

CCS as BSER but which CURC absolutely argues is the case) then the fuel diversity test cannot 

be met because the standard of performance (coal only with CCS) is not achievable by coal. The 

Agency’s argument, therefore, is circular because it wishes to include CCS as an alternative for 

coal but knows that CCS cannot meet the BSER requirements. The 30-year alternative 

compliance option is essential to a showing that fuel diversity is achieved because no new coal

units can be built without CCS. While the BSER requirements do not themselves mandate fuel 

diversity, EPA is required to assess “energy requirements.” In this proposed rule EPA moves 

away from its historical approach without justification by offering an alternative compliance 

approach that even it concedes cannot meet the BSER test.

To support the alternative compliance option, the Agency asserts, inter alia, that (1) the costs of 

CCS will decrease over time;20 (2) there will be no more than a few CCS projects by 2020 and 

those plants can take advantage of available government-provided CCS funds;21 and (3) several 

states have set standards that require CCS if coal plants are constructed in those states and,

 15 77 Fed. Reg. at 22,399. 16 77 Fed. Reg. 22419 (April 13, 2012). 17 Op. Cit., Standards of Performance for GHG Emissions, 77 Fed. Reg. 22411, (April 13, 2012). 18 Portland Cement Association v EPA, 486 F.2d 375 (D.C. Cir.), 1973. 19 77 Fed. Reg. 22392, 22398 (April 13, 2012). 20 77 Fed. Reg. 22395 (April 13, 2012). 21 77 Fed. Reg. 22395 (April 13, 2012).
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therefore, only CCS can be used in those states.

22 The alternative compliance option is simply a 

mechanism to increase the time period during which CCS technology might be demonstrated and 

costs of CCS might be reduced. Citing state requirements for CCS is irrelevant to the 

justification for the rule because the EPA must write a rule that can be complied with in all 50 

states. 

In proposing the rule, EPA applies models23 to argue that because of low natural gas prices and 

other market conditions, almost no coal capacity (only 2 GW with CCS) will be built until 

2020.24 Arguing that little coal will be used between now and 2020, however, merely lessens 

the perceived burden of the proposed rule and permits the Agency to make the argument that few 

CCS projects will be required and those projects that are built will likely be the recipients of 

federal assistance. This argument ignores the real question: Why is EPA proposing this 

requirement for coal now if the Agency is arguing it will have no effect? 

There are high costs and technical risks currently associated with CCS. Therefore, it is probable 

that only those CCS projects that are awardees of federal government financial support will be 

pursued. The more reasonable inquiry, however, one that the Agency does not pursue, is 

whether any coal plants employing CCS would even be considered at this time but for the 

government support. Even if some or all of the demonstration projects are actually constructed 

and operate (an unlikely occurrence due to financial and technical hurdles) the subsequent cost of 

CCS without further government subsidy will not decrease sufficiently to enable coal with CCS 

to compete for market share with low cost abundant natural gas. By prohibiting the use of coal 

without CCS, demand for electricity would be met with natural gas or other cost competitive 

available options, but not coal with CCS, which will remain significantly more expensive. 

Currently, no additional government financial assistance is available for CCS because the 

available programs have all been committed. In addition, the current technology challenges of 

capturing and storing CO2 remain too great for subsequent CCS equipped coal plants to be built 

and operate.

In short, the proposed “alternative compliance plan” with 30-year averaging for CCS is 

predicated on completely unrealistic assumptions. Businesses would need to invest several 

billion dollars in power plants betting that after ten years of operation, or sooner, commercial 

CCS technology will be available for retrofit installation and operation. No power plant 

developer will commit to build a new coal fueled plant without assurance that a cost-effective 

CCS technology will be available within its first 10 years of operation to achieve CO2 emissions 

compliance over the extended 30-year averaging period proposed in the rule.

The Agency’s further assumption that within ten years coal-fueled plants equipped with CCS 

technology could achieve an emission rate of 600 lbs CO2 per MWh, far lower than the 

proposed standard of 1,000 lbs CO2 per MWh, anticipates a technology breakthrough and 

 22 77 Fed. Reg. 22416 (April 13, 2012). 23 EPA Regulatory Impact Analysis for the Proposed Standards of Performance for Greenhouse Gas Emissions for 

New Stationary Sources: Electric Utility Generating Units, at 5.1 (page 59). 24 EPA Regulatory Impact Analysis for the Proposed Standards of Performance for Greenhouse Gas Emissions for 

New Stationary Sources: Electric Utility Generating Units, at 5-9 (page 67). “By 2020, EPA forecasts roughly 27 GW 

of new renewable capacity, 2 GW of coal with CCS, and 10 GW of new natural gas-fired capacity.”
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commercialization schedule that is unrealistic and beyond the pace of project development 

currently underway. To be commercialized on a large scale, CCS installation will also have to 

be cost competitive with other energy production options. 

Compounding the lack of proven CO2 capture technology are unresolved technical, legal, and 

regulatory issues concerning CO2 storage options. EPA ignores these sizable hurdles in 

proposing its alternative compliance option. In the absence of a legal and regulatory structure to 

address CO2 storage the requirement for deployment of unproven CCS technology is wholly 

unrealistic. Again, the Agency’s conclusion that new coal fueled power generation will not be 

built for a prolonged period of time and therefore no consequences will come of this proposed 

CO2 rule is incorrect. 

Finally, the Agency’s contention that this proposed rule is actually a technology driver for the 

adoption of CCS is wrong. The Agency argues that if coal is chosen to fuel a power plant and 

CCS is required by law it will drive development and adoption of the technology. This scenario 

might occur if the technology were commercially mature and other less costly fuel options were 

not available, however, neither of these circumstances exists. No utility, no business, and no 

regulator, will choose to permit a more expensive power generating option, when less expensive 

options, fullfilling the same generation and capacity requirements, exists. EIA projects no new 

coal builds and years of less expensive and abundant natural gas from shale resources. Further, 

if the coal market is severely limited or the necessary technologies are non-existent, and if the 

EIA forecasts no new coal builds for several decades, what is to keep utilities and equipment 

suppliers interested in CCS technology development? This proposed rule does not “drive” CCS 

technology development or deployment, it would actually “freeze” the technology because 

advocates for CCS stop advocating, technology innovators find other paths for innovation, and 

the U.S.will lose its current global leadership position in developing CCS while China and other 

countries continue a forward march towards greater coal use without serious regard to 

technologies to control CO2, or alternatively, choose to develop the CCS technologies for sale 

around the world. 

Even assuming, for the sake of argument, that few new coal plants will be built over the next 

one or two decades, and any coal use could be accommodated through the 30-year averaging 

compliance option, the Agency has not constructed a sustainable system because fuel diversity is 

achieved only because any modest use of coal can be met with CCS projects that are now 

receiving government support. When that government support no longer exists, it is not clear 

how the industry will move forward given the requirement for CCS. EPA assumes that the cost 

of CCS will decrease over time, yet the Agency cannot know how much or how quickly costs 

will come down and indeed does not undertake any analysis in this regard. EPA cannot base its 

compliance requirements on vague estimates of CCS expansion. EPA contradicts itself in the 

proposed rule when it assumes both that no new coal fired EGUs will be built and that CCS 

technology will continue to develop over the next ten years.With the current abundant supplies 

of low-priced natural gas, and no clear path to reducing the costs of CCS nor resolving storage 

issues, the Agency has offered a compliance option for coal that is completely unrealistic.

EPA argues on one hand that the 30-year compliance option evidences the reasonableness of its 

NGCC based BSER by allowing an alternative pathway for coal as CCS technology matures. 

But, EPA also argues it is not proposing that CCS itself is BSER, and therefore there is no need 
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to show that CCS is “adequately demonstrated.” How does the proposed rule meet the section 

111(a)(1) requirement that the standard of performance takes into account “energy requirements” 

and be “adequately demonstrated”? By not designating CCS as BSER, the “adequately 

demonstrated” requirement is avoided. By asserting that coal will not be used to meet any 

energy requirements and what little might occur can be met with government subsidized CCS 

projects through use of the alternative compliance option, the energy requirements standard is 

met. Coal without CCS is abundant and cost competitive with natural gas, even at low natural 

gas prices, but this proposed rule eliminates this important option. 

B. ELECTRIC GENERATORS WILL NOT COMMIT TO CONSTRUCTION OF A MULTI-BILLION 

DOLLAR PROJECT ASSUMING THAT CCS TECHNOLOGY WILL BE AVAILABLE AND 

ADAPTABLE IN YEAR ELEVEN OF A PROJECT’S LIFE, AND FINANCIAL MARKETS WILL NOT 

FUND SUCH PROJECTS

Under the “alternative compliance option” owners have the option to build a coal plant today and 

add an integrated CCS system in later years to meet a 30-year, 1000 lb. CO2/MWh average 

emission rate.25 First-generation CCS technologies, however, are just moving into the 

demonstration phase. DOE has a suite of CCS demonstrations projects that are in various stages 

of development, most of which are still in the engineering phase. If these projects move ahead at 

a reasonable pace, it will still be at least 3-5 years before they complete construction and another 

3 years after that before these CCS projects will have operated long enough to determine their 

success or failure. 

In addition, given the cost and technology risk associated with CO2 capture, a small number of 

successful demonstration projects will not be sufficient to provide widespread acceptance of the 

technologies as proven. Any successful demonstration projects must be followed by a first round 

of early adopter CO2 capture projects that will take at least 10 more years to develop, permit, 

procure, erect, and commission. Following start-up, the plants will then have to successfully 

operate for 3-5 years to prove the technologies are commercially viable. Only after several of 

these early adopter CCS projects are proven successful will CO2 capture technologies gain 

widespread acceptance for commercial deployment. As can be seen, this reasonable technology 

development timeline will require many years before anyone can expect CCS to be commercially 

deployed.

Furthermore, challenges remain with permanent CO2 storage. While CO2 storage technology 

development is advancing, property rights and liabilities associated with permanent CO2 storage

remain to be addressed. 

For an owner to choose to build a coal-fired facility today with the requirement to have an 

integrated CCS system implemented within the next 10 years, they would have to know today

that CO2 capture is a proven and cost-competitive technology and that CO2 storage sites can be 

permitted and will be accepted by the public as safe. Given the technological, economic, and 

legal risks of integrating an expensive and untested technology to what is already a very costly 

power plant, owners will not build (and lenders will not finance) coal-fired electric generation 

projects under this proposed rule. Adoption of this rule as written will stop commercial 

 25 77 Fed Reg 22392, 22406 (April 13, 2012).
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development of new coal-based electric generation. With the reality that no coal plants will be 

built, CCS technologies will have little incentive and little opportunity for continued 

development.

C. 1,800 LB. CO2/MWH BASELINE IS NOT AN APPROPRIATE STANDARD UPON WHICH TO 

PREDICATE THE ALTERNATIVE COMPLIANCE OPTION FOR VARIOUS TYPES OF COAL 

PLANTS. 

The EPA proposed an alternative compliance option whereby power plants would be limited to 

1,800 lb. CO2/MWh on a gross basis for the first 10 years of operation and then be required to 

install an integrated CCS system. It is not appropriate to apply this baseline to all ranks and 

types of coals, which differ in their pollution characteristics. The normal operation of power 

plants, including start-up and level of load operation, demonstrate that it is not possible, in all 

instances, to achieve the stringent standard EPA has proposed. 

The EPA reviewed data from its Clean Air Markets Database and concluded that this annual 

standard is appropriate for all new coal-fired power plants, regardless of fuel type. Specifically, 

EPA states that this standard is achievable by a supercritical coal plant.26 Advanced coal-based 

electric generation technologies have the potential to achieve this emission level for selected 

fuels and optimal operating conditions. However, coal-based power plants are not always 

steady-state operations. In practice, the performance of such units varies due to fuel 

characteristics, load cycles, site/ambient conditions, and equipment degradation, among other 

factors. These variations will make compliance with the proposed 1,800 lb. CO2/MWh limit 

challenging and uncertain. These factors will create a risk profile that will effectively preclude 

consideration of coal as an option for future power generation because it will not be possible to 

guarantee compliance with the rule, even prior to the CCS requirement.

Table 1 shows the expected CO2 emissions rates for selected U.S. fuels, ranging from bituminous 

coal to lignite, being combusted in modern pulverized coal (“PC”) power plants operating at full 

load conditions. Natural gas is included for comparison. This table shows that the 1,800 lb.

CO2/MWh limit may be achievable at full load conditions for bituminous coals, barely 

achievable for subbituminous coals, and unattainable for lignite coals.

Table 1: Specific CO2 Emissions Rates vs. Fuel Type at Full Load

There are a number of other factors that impact plant heat rate and thus CO2 emissions and such 

additional factors also must be taken into account. All of these factors make the proposed EPA 

standard much more difficult or impossible to achieve. Each of these factors is described below:

 26 77 Fed Reg 22392, 22406 (April 13, 2012).

Fuel lb. CO2/Mwh-gross

Texas Lignite 1827

North Dakota Lignite 1857

Wyoming Sub-Bit 1781

Illinois High Vol Bit 1698

Natural Gas 922
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Partial Load Operation

The plant heat rate increases as the plant operating load is reduced, which corresponds to 

increases in the specific CO2 emissions rate. Based on the performance of a specific modern 

commercial power plant, the heat rate increases 1% at 75% load and 6% at 50% load. The heat 

rate increases more dramatically at even lower loads, rising by almost 20% at 35% load. The 

heat rate has a great impact on the specific CO2 emissions rate as a result of normal plant load 

variations. Coal-based power plants typically follow either a base load or cycling operation load 

profile, depending upon factors such as the plant’s dispatch cost and grid requirements. These 

situations have quite different patterns of load variations and corresponding emissions rates, and 

the EPA has not taken this reality into account when setting the standard.

Base load Operation

All power plants have some load variation that will impact heat rate and CO2 emissions rate. A 

typical PC base load plant may operate 60% of the time at 100% load and another 35% between 

50-75% load. The average capacity factor would be about 85% and it would have an average 

heat rate typically about 1% higher than at 100% load. This variation alone would be sufficient 

to increase the specific CO2 emissions rate from a PC plant firing Wyoming subbituminous coal 

from 1,781 to 1,799 lb. CO2/MWh. This example highlights the limited compliance margin, if 

any, that is afforded by the 1,800 limit. In turn, it identifies the challenges and compliance risk 

that will be experienced over the life of the unit.

Cycling Operation

A typical PC cycling plant may operate 30% of the time at 100% load, another 55% between 50-

75% load with the balance of operation at even lower loads. The average capacity factor would 

be about 70%, and it would have an average heat rate typically about 4-5% higher than at 100% 

load. A 5% heat rate increase from cycling operations would increase the specific CO2 emission

rate of the Illinois bituminous coal from 1,698 to 1,783 lb. CO2/MWh – already getting very 

close to the 1,800 limit. Plant cycling is particularly significant as more plants are expected to 

cycle in the future as renewables increase their share of power generation.

Degradation Due To Plant Age

Power plants are designed to operate for many years, they are long life assets and many have cost 

effectively operated for 50 years and more. Normal expected wear and tear has a detrimental 

impact on a plant’s heat rate. Looking solely at the steam turbine, a plant’s heat rate could 

deteriorate by about 1% after 10 years of operation based on a steam turbine degradation curve 

known as the PTC6 curve.

Site Factors 

Other factors can impact the design of an advanced coal-based power plant that can also have a 

negative impact on plant heat rate and thus the CO2 emissions. For example, areas with limited 
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water resources could require an air-cooled condenser rather than water cooling. Local water 

temperature can also have an impact on condenser operating pressure and heat rate. 

Table 2 summarizes the impact of an increase in plant heat rate due to the above factors on the 

specific CO2 emissions rate for a state-of-the-art ultra-supercritical PC power plant. A plant that 

is required to cycle would likely have a heat rate 5% higher than its design 100%-load heat rate. 

In this scenario, a bituminous coal-fired unit, under ideal conditions, would achieve the standard 

with minimal compliance margin, while the lower rank fuels would exceed the 1,800 lb.

CO2/MWh rate. It is likely that the bituminous plant would also exceed this target after 

appropriately accounting for site specific factors, impacts of startup, shutdown, and age 

deterioration. The cycling impact could be even more significant in the future as renewables 

assume a larger portion of the total power generation.

Table 2: Impact of Heat Rate Degradation on Specific CO2 Emissions Rates

EPA Clean Air Markets Database

The EPA cited data from their Clean Air Markets Database to support their proposed 1,800 lb.

CO2/MWh limit. A review of the database showed that the bulk of the reporting plants exceeded 

it by a wide margin. After removing obvious outliers, the average specific CO2 emissions rate

from 230 plants was 1,916 lb. CO2/MWh.

Table 3 shows a comparison of the four supercritical PC plants that the EPA cited in justifying 

the proposed 1,800 lb. CO2/MWh target. The Agency stated that it considered these four plants 

as representative of a new coal-fired power plant. An independent check was made of this data 

by reviewing the hourly emissions reported in the Energy Velocity database. The results show 

similar CO2 emission rates. It was apparent, however, that the capacity factor for each of these 

four plants was high. All four units were clearly operating as base load plants, with capacity 

factors in the mid-80% range for three units. EPA should have taken into consideration that 

none of these units would have met the proposed limit if they were operated as typical cycling 

units.
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Table 3: Comparison of EPA Clean Air Markets and Energy Velocity Databases

EPA states that marginal units can still achieve the proposed standard by applying costly 

improvements, such as double reheat, coal drying (for lignite coals), or co-firing with natural gas. 

These modifications all add additional equipment at the expense of increased capital/operating 

cost and potentially decreased availability. EPA should not be requiring the installation of this 

type of equipment in order to achieve their target. These requirements would be added expense 

and makes coal-fired technology less competitive.

Next, the long-term limit should be designed so that applicable limits during the non-CCS phase 

of operations (which in the proposed rule would be ten years) accurately reflect the best 

demonstrated emission rate achieved by operating advanced coal technologies. The current 

assumed rate of 1,800 lb. CO2/MWh should be revisited because it is not consistently possible 

for even very efficient new coal plants to meet the standard under varying conditions 

D. MANY OF THE PLANNED CCS DEMONSTRATIONS WILL NOT BE COMPLETED

A consensus conclusion in recent reports of the IATF on CCS chaired by EPA and DOE, the 

2009 National Research Council Report titled “America's Energy Future: Technology and 

Transformation”, and the National Coal Council report “Low-Carbon Coal: Meeting U.S. 

Energy, Employment And CO2 Emission Goals With 21st Century Technologies” (December 

2009), was that five to ten large-scale integrated CCS projects will need to be underway by 2015 

for the technology to be commercially ready by 2020. In this context, “large-scale” is considered 

to mean greater than 1 million tonnes per year of CO2 captured and either stored in geological 

formations or put to beneficial use (i.e. EOR). The current DOE research, development, and 

demonstration program for CCS, which is the most robust and ambitious in the world, is 

comprised of the Clean Coal Power Initiative (CCPI), the Industrial CCS program (ICCS), the 

FutureGen 2.0 project, and the Regional Carbon Sequestration Program (RCSP), as well as 

certain tax credit and loan guarantee programs. These programs have announced support for ten 

major integrated CCS or CCUS demonstration projects, six of which are coal- or petcoke-based 

power generation projects, only one of which has broken ground for construction, and only one 

of which is coal-based power generation with non-EOR CO2 sequestration. 

A recent report by the Congressional Research Service titled “Carbon Capture and Sequestration: 

Research, Development, and Demonstration at the U.S. Department of Energy” (April 2012), 

recognizes that “...the CCS RD&D program in 2012 is just now embarking on commercial-scale 

demonstration projects for CO2 capture, injection, and storage. The success of these 

demonstration projects will likely bear heavily on the future outlook for widespread deployment 

of CCS technologies...” That report goes on to describe in great detail the difficulties 

Data from EPA Clean Air Markets Database Data from Energy Velocity Database

Facility Time Period Primary Fuel

Max 12 month 

CO2 Emissions 

Rate - lb 

CO2/MWhr-gr Time Period

Max 12 month CO2 

Emissions Rate (lb 

CO2/MWhr-gr)

Average 

Capacity 

Factor (%)

Bull Run 1 2009-2010 Bituminous 1740 2009-2011 1753 86

Weston 4 2008-2010 Subbituminous 1740 2007-2011 1740 84

WH Zimmer 1 2005-2009 Bituminous 1760 2005-2009 1721 86

Walter Scott Jr 4 2007-2010 Subbituminous 1800 2005-2011 1815 77
15

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experienced by the FutureGen project as it attempted to move forward, and concludes that “if all 

the CCS demonstration projects encounter similar changes in scope, design, location, and cost as 

FutureGen, the chances of meeting goals laid out in the DOE 2010 Strategic Plan—namely, to 

bring at least five commercial-scale CCS demonstration projects online by 2016—may be in 

jeopardy.”

The National Coal Council also evaluated the adequacy of the CCS demonstrations programs in 

collectively achieving the advancements needed for CCS technology on coal-based generation to 

be commercially ready by 2020, and reported in “Expedited CCS Development: Challenges & 

Opportunities” (March 2011) that “the current DOE CCS development program, although robust 

by world standards, has not moved fast enough and is not on pace to have the level of impact 

hoped for by 2020. At the current rate, CCS technologies will continue to be in an early 

development stage by 2020.” Moreover, it stated that “on the basis of the past experience with 

the DOE’s large-scale demonstration programs, it is unlikely that more than two or three projects 

of the existing suite will initiate the injection of 1 million tonnes of CO2 per year into geologic 

formations (excluding EOR) by 2020.” Thus, it appears likely that few of these CCS 

demonstration projects will proceed to completion and that the demonstration program will be 

insufficient to allow CCS technology to be commercially ready by the early 2020s. In light of 

this information, it is doubtful that any power generator would proceed with committing $2 

billion or more in a new coal-fired power plant under EPA’s proposed alternative compliance 

plan for at least the next ten years. Thus, the rule’s Alternative Compliance option is not a real 

alternative at all.

III. OTHER CONCERNS REGARDING THE APPLICATION OF THE PROPOSED RULES TO CCUS

In addition to the central issues addressed above, EPA’s proposed rule contains several 

additional technology-related concerns. These include the rule’s creation of barriers to CCS 

development, the inadequacy of enforcement provisions, EPA’s failure to recognize the

consequences of the precedents which would be established by promulgation of the proposed 

rule, EPA’s superficial assessment of energy and economic impacts (both of which are statutory 

determinants of the standard itself), and issues related to modified and reconstructed sources.

TECHNOLOGY BARRIERS. As an entity constituted primarily to advance improved coal 

utilization technologies, CURC is particularly sensitive to regulatory actions which create 

additional barriers to new coal-related technologies. CURC believes that adoption of the 

proposed rule would create, not mitigate, such barriers to CCS technology. We offer the 

following concerns for consideration:

1. A hard regulatory requirement ties regulators’ hands when working with developers of an 

innovative technology like CCUS.

2. Adding additional compliance and enforcement risks to already significant technical and 

financial risk will effectively eliminate new coal builds, and with it the economic 

motivation of a future market that technology developers need to justify their investment. 

3. An effective mandate to apply integrated CCS systems will eliminate the ability of the 

power facility to receive full market value for CO2 sold for EOR purposes, as EOR 

project developers correctly assess the disadvantaged position of power plant operators 

who must “get rid of” their CO2 under a mandatory rule. While significant payments for 
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CO2 to be used in EOR may be insufficient to make CCUS projects economically 

competitive at current costs of capture, failure to realize this significant revenue stream 

for CO2 will almost certainly prohibit coal-based projects in the near and medium term, 

even where additional subsidies or economic incentives are provided.

4. A 1000 lb. CO2/MWh limit effectively moves the case-by-case negotiations for 

determining New Source Review BACT to a more restrictive zone.

CURC believes that the existing New Source Review requirement for case-by-case BACT 

determinations has established a reasoned weighting of factors which might lead to a choice to 

require CCS on a new coal-fueled electric generating unit when the technology is commercially 

and technically viable at utility scale, and maintains appropriate pressure for technology 

developers to provide resources for CCS development.

INADEQUATE ENFORCEMENT PROVISIONS. The proposed rule does not provide an adequate 

basis for determining compliance if a source chose to put on an integrated CCS system. The rule 

is focused solely on stack emission rates, and basic compliance requirements but procedures for 

meeting the emission limit by using CCS or CCUS are not discussed in the preamble or included 

in the Part 60 regulatory language. Some have suggested, for example, that oil produced by 

EOR does not displace traditional oil production, and the credit for injected CO2 should be 

diminished by the CO2 which would be emitted if the produced oil were burned.27 Such an 

approach would effectively terminate interest in EOR as a storage mechanism for CO2. It is 

impossible to understand the ultimate cost, environmental impact, energy impact, or practicality 

of CCS or CCUS if the full regulatory requirements are not defined as part of the rule.

HARMFUL PRECEDENTS. Promulgation of the proposed rule would create precedents which 

would have dramatic adverse economic and energy impacts. The most significant of these 

precedents is probably the proposal to reverse EPA’s historic practices and regulate all fossil 

fueled power plants by a standard achievable only by the lowest emitting fuels and technology. 

This precedent should not be applied to the upcoming Section 111(d) regulation of existing 

power plants. The inescapable result will be the wholesale closure of much or all of the existing 

coal-fired power plants. Since these existing units produce power for 2-3 ¢/kWh, and any 

replacement power system would produce power costing at least 7-10 ¢/kWh, the economic 

impact on the nation would be dramatic as the macro-economic effects of higher electricity costs 

percolate through the economy, destroying consumer purchasing power and adversely impacting 

the competitiveness of U.S. manufactured goods in international markets. Similarly, once EPA 

has established the principle that it has the authority to “redefine” a proposed new source to use a 

fundamentally different fuel and technology than included in the permit request, permitting 

authorities will be free to specify that a proposed new fossil-fueled power plant should instead be 

a nuclear power plant or a renewable energy power plant. Some might argue that EPA has 

already assumed such authority, citing decisions by the EPA Environmental Appeals Board,28

 27 See for example, Life Cycle Inventory of CO2 in an Enhanced Oil Recovery System, P. Jaramillo, et. al., Carnegie 

Mellon University, Environmental Science & Technology, 2009, Vol. 43, No.21, 8027-8032. 28 See Order Denying Review In Part and Remanding In Part, USEPA Environmental Appeals Board, PSD Appeal No. 

08-02, February 18, 2009. 

http://yosemite.epa.gov/oa/eab_web_docket.nsf/Filings%20By%20Appeal%20Number/06DBEC31EBFD8C3E85257

5620052318B/$File/Denying%20and%20Remanding...79.pdf In this decision, EPA remanded a permit by the 

Michigan DEQ for a new heating plant at Northern Michigan University. The proposed permit for a multiple fuel 
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but the proposed rule would greatly expand EPA’s authority to dictate fuel choice and power 

plant design. CURC believes that there is no statutory authority for such regulatory measures.

INADEQUATE ENERGY AND ECONOMIC ANALYSIS. Using what can appropriately be described as 

“heroic assumptions”, EPA has concluded that the rule will have no economic, energy, or 

environmental impact. Many of these assumptions are embedded in the model used by U.S. 

DOE/EIA to project future electricity markets in both the AEO-2011 (cited by EPA), and the 

more recent AEO-2012. However, EIA acknowledges that it considers only current regulatory 

requirements. Moreover, EIA’s expectations for future conditions change from year to year and 

in the past have changed a great deal regarding natural gas price expectations – which are 

primarily responsible for EIA’s recent projections regarding limited future coal builds. 

Government estimates of domestic natural gas reserves have fluctuated wildly over the past two 

years, as the implications of new extraction technologies have been considered by EIA and the 

USGS. For example, the USGS increased its estimate of Marcellus shale resources by 40 fold in 

August 2011,29 but this estimate remained about one-fifth the magnitude of EIA’s estimate in the 

AEO-2011. It remains unclear how much of whatever estimate of “technically recoverable” 

resources will move into the “proven reserve” category that implies a fuel is economically and 

environmentally practical for commercial use. Future EPA regulations on natural gas 

production, changing natural gas markets such as increasing LNG exports, competition for 

natural gas by industrial and chemical applications, and volatility in oil prices (which impact 

demand for coproduced gas and natural gas liquids) are but a few of the factors which could 

significantly change the future domestic supply of dry natural gas and natural gas prices. 

Additionally, NEMS, the EIA model used to project future power demand, has not yet been 

programmed to address the complex issues associated with CO2 EOR markets. To the extent that 

the EPA rule discourages development of CCS technology or CCUS employing EOR (as 

discussed above), the economic impact of the rule could be hundreds of billions of dollars over 

the next several decades. 

EPA’s decision to evaluate economic impacts over an 8 year period is inappropriate for 

evaluating a far-reaching technology like CCS. By taking a short term perspective based on a 

weak technical foundation, the proposed rule could fail to identify unintended and potentially 

profound long-term economic consequences which eliminate coal as a domestic energy resource. 

Furthermore, as discussed above, the rule is more likely to have an adverse, not beneficial, effect 

on the rate of development of technology that will ultimately be necessary to slow, halt, and 

finally reduce emissions of anthropogenic CO2. The US is the global leader in CCS development 

and taking the US out-of-play will effectively defer or even halt CCS and CCUS development. 

As discussed above, the Section 111(b) rule tends to define the outer limits of reasonable action, 

as well as reasonable approaches for the upcoming Section 111(d) rule. Extending the principles 

proposed in this rule to existing sources will cause major economic disruptions.

 

circulating fluidized bed boiler, which was designed to use coal as a primary fuel, was rejected by EPA because it 

did not adequately assess using wood as the source’s primary fuel in order to reduce sulfur dioxide emissions. 29 Assessment of Undiscovered Oil and Gas Resources of the Devonian Marcellus Shale of the Appalachian Basin 

Province, 2011, US Geological Survey, US Department of Interior, Fact Sheet 2011-3092, August 2011.
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MODIFIED AND RECONSTRUCTED SOURCE ISSUES. CURC agrees with EPA that the proposed 

rule should not apply to modified sources. We believe, however, that EPA has offered an 

incomplete justification for this policy. The reasoning EPA offered for transition sources – that 

the units have already been configured for a non-CO2 limiting regulatory environment and would 

experience much higher costs for retrofitting – applies even more so to existing sources. 

Additionally, retrofitting CCS may be wholly impractical for many facilities, due to lack of space 

or lack of sufficient cooling water for the additional equipment introduced by carbon capture 

technologies. A third factor favoring exclusion of modifications from the rule would be that 

such a policy would be environmentally counterproductive, discouraging possible efficiency 

improvements which could reduce CO2 emissions. 

CURC also agrees with EPA’s decision to exclude reconstructed facilities from the proposed 

rule. However we are concerned that an existing facility which elected to retrofit CCS, 

potentially to enter EOR markets for example, might become a “reconstructed” facility for 

purposes of non-CO2 NSPS, given the high cost of CCS technology. Retrofits are a key platform 

for technology demonstration and validation. EPA rules state that: “‘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 the fixed capital cost that would be required to 

construct a comparable entirely new facility, and (2) It is technologically and economically 

feasible to meet the applicable standards set forth in this part.”30 Reconstructed plants are 

subject to the NSPS, MATS, and potentially other requirements, even if the reconstructed source 

has no increase in regulated emissions. Absent an exclusion of reconstructed sources related to 

CCS, the addition of carbon capture could trigger re-permitting under these rules. Although the 

proposed rule would exclude reconstructed sources from application of the CO2-NSPS, it does 

nothing to insulate projects which retrofit CCS from reconstruction provisions applicable to other 

air emissions. CURC encourages EPA to consider ways to eliminate such barriers to the 

voluntary use of carbon capture. 

COMBINED HEAT AND POWER. New combined heat and power (CHP) facilities would be 

subject to the same CO2 performance standard as other covered EGUs. Because CHP facilities 

generate useful thermal energy as well as electrical output the Agency proposes to adjust the 

manner of calculating the CO2 emissions rate from these facilities. The proposed rule would 

provide that a CHP unit divide its total CO2 emissions by the sum of its gross electrical energy 

output and its useful thermal energy output to determine compliance with the proposed standard.

In addition, a CHP facility whose useful thermal output represents at least 20% of its total energy 

output would increase its electrical output by 5% to reflect avoided transmission and distribution 

losses. Both adjustments would increase the apparent energy output of a CHP facility, thereby 

lowering the CO2 emissions rate per unit of output. 

EPA should exempt combined heat and power (CHP) sources whose useful thermal output is at 

least 20% of their total output, on the basis that CHP is a highly desirable configuration for both 

reduced emissions and conservation of fuel, and the exemption will promote its adoption.

 30 40CFR60.15(b).
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IV. RECOMMENDED ALTERNATIVE APPROACH TO ADDRESSING GHG NSPS FOR 

NEW COAL-FUELED POWER GENERATION.

A. EPA MUST ADOPT FUEL SPECIFIC EMISSION LIMITS FOR NEW SOURCE 

PERFORMANCE STANDARDS.

EPA concludes that CCS is not an appropriate technology on which to base NSPS “best system 

of emission control” for natural gas power plants, and that requiring an efficiency limit that

reflects a performance level achieved by the vast majority of NGCC units built between 2006 

and 2010 is reasonable.31 CURC is not commenting upon whether NGCC units are capable of 

meeting the proposed standard, rather it is the approach used by the Agency in determining a 

standard for natural gas which is an approach that would also be appropriate for coal-based 

power plants. This can only be achieved by establishing a separate coal standard that reflects the 

“best system of emission control” for coal. Further, an appropriate performance standard for 

coal-fired units must be based on data from operating coal-based generation units, not on a 

design specifications or expected performance levels. It is imperative also that such a 

performance standard account for the use of different coal types, different combustion 

technologies (that is, pulverized coal boilers or fluidized bed boilers), and differences in plant 

operating conditions (i.e., base load, load following, load cycling) all of which will impact 

average heat rate and CO2 emissions rate. Finally, such a standard for coal must also 

accommodate startup/shutdown or these periods need to be excluded from compliance 

calculations.

Under Clean Air Act § 111,32 the EPA, in establishing performance standards for new sources, 

must consider a standard which has been “achieved in practice.”33 In order to set standards, 

“the Administrator may distinguish among classes, types, and sizes within categories of new 

sources for the purpose of establishing such standards.”34 Historically, the setting of standards 

has included utilizing different standards for fuels and technologies that have different 

characteristics. This process allows for various fuels to meet the highest possible pollution 

control levels, without summarily removing one type of fuel or technology from the 

marketplace because it cannot meet the standard which another fuel can meet.

Contrary to prior precedent, in the proposed GHG NSPS , the approach proposed by the Agency 

would combine NGCC units and coal steam boilers and require both to meet the same standard, 

a standard achievable only by a new NGCC unit .

35 This approach is contrary to EPA’s practice 

 31 NSPS Preamble, 77FR22414, April 13, 2012 32 42 USC § 7411(b). 33 “When implementation and enforcement of any requirement of this chapter indicate that emission limitations 

and percent reductions beyond those required by the standards promulgated under this section are achieved in 

practice, the Administrator shall, when revising standards promulgated under this section, consider the emission 

limitations and percent reductions achieved in practice.” 42 USC §7411(b).

34 42 USC §7411(b)(2). 35 EPA states that it is “proposing to combine electric utility steam generating units (boilers and IGCC units, which 

are currently in the Da category) and combined cycle units that generate electricity for sale and meet certain size 

criteria (which are currently included in the KKKK category), into a new category for new sources (the TTTT 

category) for the purposes of GHG emissions.” 77 Fed. Reg. 22394 (April 13, 2012). The standard proposed is 1,000 

lb. Co2/MWh.
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under the CAA, which has historically allowed for fuel diversity. In order to continue this 

practice and comply with the intent of the Clean Air Act, EPA should either create separate 

categories for different types of fuel and technology, or if it wishes to have one combined 

category for GHGs from base load EGUs, such as category TTTT in the proposed rule, it should 

subcategorize by fuel and boiler types to allow for an achievable standard for each fuel. 

It is important for EPA to appropriately categorize fuels to determine achievable Best System of 

Emission Reduction (BSER) requirements. EPA should not have a system wherein coal and 

natural gas are combined into one category and the BSER standard is applied to all base load 

power sources, as the agency has done in this rule. The combination of source categories has 

historically been based on the characteristics of the fuel or the source, not the use of the source 

(e.g. base load power). Here EPA combines categories into one, TTTT, for all base load EGUs 

solely because EPA asserts that they perform the same function, not because of similar 

characteristics or pollution control procedures. Indeed only within the last several years has a 

large percentage of NGCC units operated as base load units. Prior to the period of low prices 

for natural gas such natural gas fired units operated as cycling plants and therefore did not 

perform the same function as base load coal-fueled power plants.

Instead of combining categories in this way, EPA should look to the best performing units with 

respect to different types of major coal usage and conversion, and define categories and 

subcategories around such different fuel types and sources. We strongly suggest that EPA 

consider the type of technology and the type of fuel and create categories and subcategories that 

reflect these differences and address their effects on achievability, in order to comport with the 

CAA and to maintain the goal of fuel diversity.

B. EPA MUST NOT RELY ON CCS AS A COMPLIANCE OPTION BECAUSE IT IS NOT

COMMERCIALLY AVAILABLE.

In the proposed rule, EPA asserts that Carbon Capture and Sequestration (CCS) is commercially 

available and therefore is a reasonable control technique to be employed by coal-fired EGUs. 

However, the EPA is mistaken in its assessment concerning the level of technology development 

that has occurred, as well as the current state of the CCS market. 

There are no commercial-scale electricity generation facilities fully integrated with CCS 

operating anywhere in the world. Even the DOE, in its CCS Roadmap, finds that the technology 

will be ready to “begin commercial deployment in 2030.”36 Studies, including a report by the 

CRS, have noted that CCS is still in the demonstration phase and that there are no full scale 

commercial (non-subsidized) applications of CCS to date.37 Indeed, in 2012 DOE’s CCS RD&D 

program is just now embarking on commercial-scale demonstration projects for CO2 capture, 

injection, and storage. In short, an integrated CCS system on a coal fueled electric generating 

 36 Department of Energy, Carbon Capture and Storage Roadmap, found at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/CCSRoadmap.pdf

37 Carbon Capture: A Technology Assessment, CRS Report, Peter Folger, July 19, 2010. 

http://www.cnie.org/NLE/CRSreports/10Aug/R41325.pdf, which notes, “At present, there are still no full-scale 

applications of CO2 capture on a coal-fired or gas-fired power plant (i.e., a scale of several hundred megawatts of 

plant capacity).”
21

Monday, June 25, 2012

unit has simply not been commercially tested and is not available, and therefore should not be 

viewed as a compliance option by EPA.

Indeed, even the current slowly-progressing CCS demonstration projects are not indicative of 

industry readiness because they are heavily dependent on federally subsidized financing 

incentives and have unique characteristics, like proximity to a site for enhanced oil recovery 

(EOR). One of the rationales that EPA provides for setting a standard that will require the 

installation of CCS is that there are a number of CCS demonstration projects that are currently 

slated to be completed by 2016. Planning to have a CCS demonstration does not in itself make 

CCS commercially available. Whether or not these projects are actually completed by that time, 

they have many factors that make them non-replicable, including large subsidies and very 

specific geographic placement, and therefore such projects should not be used to suggest that the 

industry as a whole is ready to employ this technology.

Given that CCS is not commercially available for coal-based generation, CURC recommends 

that the agency undertake a thorough review of currently operating coal-fueled electricity 

generating units and thereafter establish reasonable performance standards based upon this “best 

in class” examination. It is important to recognize that size of the power generation facility, type 

of coal conversion technology applied (e.g. pulverized coal versus circulating fluidized bed 

(CFBs)), and ranks and characteristics of specific coals need to be considered in setting 

performance standards for new coal fueled power plants. The agency is required by statute to 

periodically review and revise the NSPS requirements. Under the Clean Air Act, “the 

Administrator shall, at least every 8 years, review and, if appropriate, revise such standards 

following the procedure required by this subsection for promulgation of such standards.”38 It is 

premature for the EPA to include CCS technology as a compliance option. The EPA should wait 

until the next round of changes to the NSPS to re-evaluate the status of CCS and only if 

technically and economically available integrate CCS into the compliance system. By that time it 

is more likely that the technology will have been demonstrated and may then be commercially 

available thereby providing real technology application upon which to make a decision requiring 

widespread application. 

C. EPA SHOULD RELY ON THE EXISTING PSD PERMITTING PROCESS AND CASE-BYCASE BACT TO ASSESS GHGS FROM NEW COAL PLANTS.

Instead of creating an NSPS with an unachievable standard and a compliance option based on 

unproven technology, the EPA should rely on the existing Prevention of Significant 

Deterioration (PSD) permitting structure and individual BACT determinations to address GHGs 

from new coal plant development. This case-by-case approach is better able to include a number 

of factors that are important to the development of the CCS industry without requiring 

applications that are not commercially available or possible. 

For instance, in the near-term to medium-term some new coal plants may be able to employ CCS 

if they are heavily subsidized and located near EOR opportunities. These plants have unique 

characteristics that would make it reasonable to include CCS in their BACT determinations, and 

the process of undertaking a PSD permit with such requirements will assist the agency in 

determining the factors that do make CCS feasible in particular instances. 

 38 42 USC §7411(b)(1)(B).
22

Monday, June 25, 2012

The case-by-case process will also allow for new coal plant development in areas of the country 

requiring additional sources of base load power but where capturing CO2 and sequestering into 

deep geologic formations or using it for EOR is not feasible. Such a case by case approach 

would allow flexibility for state regulators to potentially permit the use of coal based upon the 

application of commercially available technology. It is imminently more reasonable to require 

that these determinations be made on a case-by-case basis in which CCS may be selectively 

included in sites where it is possible. CCS for all new coal-fueled developments should not be 

required until it is commercially available on coal-fueled electric generation units and at a nonprohibitive cost.

CONCLUSION:

The CURC respectfully requests that the EPA make significant revisions to the proposed rule. 

Coal resources in the United States are vast, accessible and proven to be a dependable, cost 

competitive source of fuel for electricity generation. By its own finding the Agency has 

concluded that only a very modest amount of new coal plant construction is contemplated for 

several years into the future. To avoid jeopardizing progress being made in the development of 

CCS technologies the Agency should table or significantly alter these proposed rules as 

suggested in these comments. Such action will provide industry, now partnering with 

government, the time needed to mature CCS technologies and thereby insure commercial 

availability for use in the electricity generation sector.
ATTACHMENT A 

Monday, June 25, 2012 23

Carbon Capture and Storage: Technology Status, Cost, Deployment and Timing 

for Electric Power Generation

Summary

The U.S. enjoys significant economic and energy security benefits from the use of coal. Coal is used 

primarily for the production of electricity, but can also be converted to transportation fuels, synthetic 

natural gas or serve as a source of feedstock for the chemical industry. Concerns about climate change 

have led to requirements to reduce greenhouse gas emissions (i.e. carbon dioxide, CO2) from coal based 

processes. To maintain the ability for the U.S. to continue to use this abundant and low cost resource 

effective and affordable carbon capture and storage (CCS) technologies must be developed and brought 

to commercial deployment. This paper l focuses on CCS technologies that can be integrated with coalbased power plants.

Much progress has been made in the development of technologies required to capture, compress, 

transport and utilize or store CO2. Many of the components required to enable CCS have already been 

developed and employed in other industries. However, these technologies have not been integrated 

into electric generating facilities at any scale nor has the application of CCS been demonstrated as costeffective. Further, the use of CCS technology requires a substantial amount of energy from the power 

plant itself in order to operate. This use of parasitic power adds to the cost of generation and the need 

for replacement electricity from other sources. A recent analysis conducted by CURC calculated that 

incorporating current CCS technology into a coal-based power plant could roughly double the cost of 

electricity from the facility.39

Progress has occurred in the storage of captured CO2. For example, underground injection and storage 

(in saline formations) of CO2 has been used at small scale for over 20 years in Alberta, Canada, and a few 

large scale operations on non-power applications also exist. The US Department of Energy (DOE) has 

implemented a multiyear R&D program to develop a better understanding of the physical and chemical 

behavior of CO2 stored in deep saline formations. CO2 from the Dakota Gasification facility in Beulah, 

North Dakota, has been used for enhanced oil recovery (EOR) operations at the Weyburn EOR project40. 

, The use of “natural” CO2 for EOR has been commercially applied in the U.S. since 1972. However, CO2

from a commercial scale coal-fueled electric generating facility has yet to be captured, compressed, 

transported and used for EOR or stored in deep geologic formations.

 39 Levelized cost of electricity (LCOE), based on 90% capture and storage in a saline formation, versus a 

supercritical pulverized coal power plant without CCS.

40 Weyburn Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/weyburn.html .
ATTACHMENT A 

Monday, June 25, 2012 24

In addition to ongoing R&D, several commercial scale CCS demonstration projects are underway in

collaborative efforts by the public and private sectors (see Attachment 1). The first of these facilities 

(Southern Company’s Kemper County IGCC) is scheduled to commence operation in 2014.

The challenge for CCS is four-fold:

 Continue to support the on-going First Generation CCS demonstration facilities now under 

construction or in planning. These projects will integrate many of the components needed to 

demonstrate CCS at commercial scale electric generation facilities so that we may start “learning 

by doing.” These plants are not expected to be commercially competitive absent the substantial 

government subsidies that are being provided. It is expected that second and third generation CCS 

facilities may also be economically challenged but their construction and operation is essential if 

we are to maintain progress and mature the technology.

 Accelerate research and development on second generation advanced CCS systems, especially 

capture technology (which contributes most of the total cost of CCS), to dramatically reduce cost 

and improve performance.

 Fund Second Generation CCS demonstration facilities to verify that the products of R&D will 

operate as expected at commercial scale.

 Create a legal framework for permanent storage of CO2 that addresses private property rights and 

questions about the long-term liabilities related to CO2 storage.

Introduction

CCS technology has been cited by most authoritative sources on climate change mitigation, including the 

Intergovernmental Panel on Climate Change (IPCC) and the International Energy Agency (IEA), as a 

critical, if not the most important, technology to enable society to meet stringent greenhouse gas (GHG) 

reduction goals.41 U.S. emissions of CO2 are dominated by the electric power industry and 

transportation which contributed 34% and 27% of total U.S. emissions in 2010, respectively.42 

CO2 emissions from electric power production can be reduced by generating less electricity, generating 

electricity more efficiently, relying on electricity sources which are less carbon intensive, or capturing 

CO2 from power plants. In 2010, coal and natural gas generated 69% of total U.S. electricity. EIA 

projects that coal and natural gas will still generate 66% our electricity in 2035.43 This continued 

reliance on fossil fuels for power generation suggests that systems to capture and store CO2 from power

 41 See: Energy Technology Perspectives – 2008, International Energy Agency, June 2008; and Carbon Dioxide 

Capture and Storage, Intergovernmental Panel on Climate Change, 2005. 42 U.S. GHG Inventory – 2012, Table ES-7, USEPA, April 2012. 43 Annual Energy Outlook – 2012, USDOE/EIA, http://www.eia.gov/forecasts/aeo/er/ .
ATTACHMENT A 

Monday, June 25, 2012 25

plants will be essential to reducing CO2 emissions not only in the United States but globally where use of 

fossil fuels in developing countries is projected to increase dramatically.

The technologies needed to capture CO2 and store CO2 are separate, and each faces its own set of 

challenges. The three primary technologies for capturing CO2 are in various phases of commercial 

development and include post combustion capture using amine based solvents, pre-combustion capture 

systems associated with integrated gasification combined cycle (IGCC) and oxycombustion-based 

capture systems.

These three CO2 capture technologies as well as the processes used to clean, compress, transport, and 

store CO2 are reviewed in this paper. 

Carbon Capture

Three types of carbon capture systems are currently under development:: 

 Post-combustion capture (PCC) systems, which utilize chemical-based solvents, are used to 

separate and concentrate CO2 from the flue gas stream of a coal fired boiler. Other non-solvent 

based PCC technologies are also under development.

 IGCC technology converts coal to a combustible gas (synthesis gas) and separates the CO2 from the 

synthesis gas prior to combustion (rather than from the flue-gas after combustion).

 Oxy-combustion systems, that resemble traditional coal-fired power plants, use pure oxygen 

mixed with recycled flue gas rather than air for combustion. Oxycombustion produces a flue gas 

stream that is highly concentrated with CO2. This concentrated stream of CO2 can be more easily 

separated, cleaned and compressed than the CO2 in the flue gas of a conventional air fired boiler. 

Once the CO2 has been captured it must be compressed into a liquid form, transported by pipeline, 

injected into deep saline formations for permanent storage or used beneficially for other 

purposes, including enhanced oil recovery (EOR).

Post-combustion Capture systems 

Post-combustion CO2 capture systems add a CO2 “scrubber” to remove the CO2 from combustion gases. 

The CO2 scrubber is located after the traditional Air Quality Control System. Figure 1 presents a 

simplified diagram of a pulverized coal power plant equipped with post-combustion CO2 capture and 

compression.
ATTACHMENT A 

Monday, June 25, 2012 26

Figure 1. Pulverized power plant with CO2 capture.

Pulverized Coal Plant 

with Carbon Capture

Boiler

PM removal

(FF or ESP)

Sulfur 

removal

(FGD) 

AH2

Flyash

Recycle

Condenser

CO2

Scrubbers

Steam Turbine

Sulfur

By Products

Generator

Stack

Drying &

Comp.

Electric

Power

Coal

Air

Sequestration

Ready CO2 

CO2 Capture

NOx

Removal

(SCR)

Current PCC systems use amine based solvents for capture. The amine is sprayed into an absorber 

vessel where the CO2 is stripped from the flue gas. In a separate desorber vessel the liquid solution is 

heated and the CO2 is released. The concentrated CO2 gas can then be compressed into a liquid for 

pipeline transport. 

While CO2 capture systems using amine solvents are commercially available today, these systems 

operate under very different conditions from an electric generating facility. For example, amines have 

been used to separate CO2 from other gases in the oil/gas processing and petrochemical industry for 

over 60 years. However, these systems typically operate under high pressures (20 – 30 times 

atmospheric pressure) and a pressure swing process can be used to separate the CO2 from the solvent. 

This is not the case in power plants where PCC systems will operate at roughly atmospheric pressure.

There are several impediments to deployment of PCC technology:

• Due to the low operating pressure, a power plant system will need to use heat to force the release 

of CO2 from the solvent. This operating condition requires that a huge amount energy from the 

plant be used to heat the solvent in order to release the CO2. The solvent must then be cooled 

before being returned and reused in the absorber tower. This requires additional energy, as well 

as additional cooling water for the facility. 

• A large amount of electricity is needed for CO2 compression. In total, the energy requirement for 

CO2 capture and compression is about 30-35% of the total energy produced by the power plant.
ATTACHMENT A 

Monday, June 25, 2012 27

• Contaminants in the flue gas can degrade the solvents and corrode process equipment. New 

designs and process adaptations must be developed to avoid these problems.

• No existing power plant has integrated commercial scale carbon capture and power production. 

System integration is critical to the successful application of PCC systems for CCS. 

• The application of CCS to power generating facilities can double the cost of electricity from the 

plant compared to a conventional pulverized coal system without CCS.

44

Progress on CCS technologies is expected to result from multiple cycles of research and development as 

well as complementary commercial scale demonstrations (learning by doing). Two power plants utilizing 

first generation CCS technology are under development and will demonstrate post combustion capture 

technology. The two projects are:

• The Tenaska Trailblazer plant, a 600 MW(net) supercritical pulverized coal power plant located 

near Sweetwater, TX. The unit will achieve 85-90% CO2 capture using the Fluor Econamine FG 

Plus solvent technology. Captured CO2 will be used for EOR in the nearby Permian Basin. The 

project, estimated to cost $3 billion, has obtained needed permits and completed its detailed 

Front End Engineering Design (FEED) study.45 The project has not been awarded federal funding, 

but it may be eligible for state financial incentives.

• The W.A. Parish retrofit project, Houston, TX. The project will also apply Fluor Corporation’s 

Econamine FG Plus post combustion capture technology. The system will be retrofit to a partial 

flue gas stream from the existing Parish power plant to remove 90% of that gas stream’s CO2. 

Captured CO2 would be used for EOR in Texas Gulf Coast oil fields. The project was initially 

conceived at 60 MW with about 500K tons per year of CO2 captured. However upon further 

evaluation it was determined that the volume of CO2 supplied by the plant was insufficient to 

interest oil producers to use the CO2 for EOR and the project size was increased to 240 MW. 

This increased the cost of the project by at least 3 times the original projection of $334 million. 

The project is presently looking into ways to fund this additional cost and DOE is evaluating the 

potential for added federal cost share.46 Other CO2 post combustion capture projects in the 

United States, Canada, Australia and Germany were announced and pursued but later 

abandoned due to costs, public opposition or other reasons. 

Ongoing CCS R&D for conventional coal-fired power plants, conducted primarily via collaborative efforts 

by the public sector and the private sector, is described in DOE publications.47 DOE-supported postcombustion capture projects currently include laboratory and bench scale research on 11 capture 

 44 Based on calculations performed by CURC as part of the CURC-EPRI 2012 Fossil Energy Technology Roadmap 

assessment. 

45 Trailblazer Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/tenaska.html . 46 W.A. Parish Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/wa_parish.html .. 47 The US DOE’s CO2 Capture RD&D Program, J. Ciferno, NETL, Presented at 2011 NETL CO2 Capture Technology 

Meeting, August 2011, http://www.netl.doe.gov/publications/proceedings/11/co2capture/index.html#mon1. 

Other presentations available at this same website have additional detail on specific R&D projects.
ATTACHMENT A 

Monday, June 25, 2012 28

solvents, 4 solid sorbents, and 4 membranes. Pilot-scale research is being performed on 4 solvents and 

1 membrane technology. In addition to R&D in second generation capture systems, R&D is also 

underway to improve the efficiency of the basic power plant, which reduces the amount of CO2

produced.

As first generation capture systems are demonstrated, R&D in second generation CSS technologies must 

proceed. If adequately funded, these R&D activities can result in development of second generation 

PCC demonstrations by 2025.48 Given successful demonstration, these advanced PCC technologies 

could begin commercial operation by 2030.

Gasification Based Systems

Gasification based CO2 capture systems work in a different manner than post-combustion systems. 

These systems take advantage of the fact that coal gasification produces a pressurized fuel gas (referred 

to as “synthesis gas”) from the gasifier. This synthesis gas is converted to mostly hydrogen and CO2, 

stripped of CO2, cleaned, and then used to generate electricity in a combined cycle power system known 

as Integrated Gasification Combined Cycle (IGCC).49 Figure 2 presents a simplified diagram of an IGCC 

power plant with pre-combustion CO2 capture and compression.

 48 Op. Cit., CURC, 2012. 49 Gasification systems can also be configured to produce synthetic natural gas, or to be converted to liquid fuels or 

chemical feed stocks, which are not included here. 
ATTACHMENT A 

Monday, June 25, 2012 29

Figure 2. IGCC with CO2 capture.

IGCC with Carbon Capture

Coal

Syngas

Quench 

Gasifier

Slag/Fines

Steam

Sulfur 

Removal

Cryogenic 

Oxygen

Particulate 

Removal

Mercury

Removal Steam

Combustion Turbine & Gen

Air HRSG

Electricity

Stack

Water

Solids

Pure Sulfur

Compressor

CO2

Shift Reactor

H2

Steam Turbine & Gen

CO2 Capture

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
ATTACHMENT A 

Monday, June 25, 2012 30

A substantial amount of CCS R&D has been completed on IGCC systems. As a result, three DOE 

sponsored commercial-scale first generation demonstration projects are under development. 

• The Texas Clean Energy Project (TCEP), led by Summit Power, is a “polygeneration” facility, 

designed to produce 245 MW of electricity, urea fertilizer, and CO2 for EOR The plant will 

employ Siemens gasifiers and gas turbine/generators, and will use the Rectisol technology to 

capture 90% of the CO2 produced. Overall project cost is reported to be $2.3 billion. The facility 

was originally announced to start operations in 2014.52 The company has signed engineering, 

procurement, and construction contracts.53 The construction start has been delayed.

• The Kemper County IGCC Project, led by Mississippi Power, a subsidiary of Southern Company, is 

a lignite fired IGCC. The plant is a 524 MW unit designed for 65% carbon capture with captured 

CO2 being used for EOR. The project employs the Transport Integrated Gasification (TRIG) 

system developed by Southern Company and KBR with the support of DOE. The project is 

estimated to cost $2.4 billion and is currently under construction. Start-up is scheduled for 

2014.54

• The Hydrogen Energy California (HECA) Project is another polygeneration project designed to 

gasify coal and petcoke and will produce 250 MW of electricity, urea for fertilizer and CO2 for 

EOR. The facility will use the Rectisol technology to capture 90% of the CO2 produced by the 

plant. Construction was originally scheduled to begin in 2012, with plant operation scheduled 

for late 2016.55 The construction start has been delayed.

More R&D is needed to reduce the cost and improve the performance of IGCC systems equipped with 

CO2 capture systems. Current R&D addresses both fundamental design of the IGCC system,56 and 

improvements specific to capture systems. As with post-combustion systems, DOE and industry are 

collaborating on a range of innovative CO2 separation techniques at laboratory, bench and pilot-scale.57 

 

power output and better efficiency but these H class turbines are not ready for use in IGCC systems that 

capture most of the CO2.

51 Op. Cit., CURC, 2012. 52 TCEP Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database,

http://sequestration.mit.edu/tools/projects/tcep.html . 53 Summit’s TCEP reaches major milestone, Summit Power, February 14, 2012, http://www.summitpower.com/inthe-news/summits-texas-clean-energy-project-reaches-major-milestone/ . 54 Kemper County IGCC Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/kemper.html . 55 HECA Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/heca.html . 56 Gasification Systems, USDOE/NETL, 

http://www.netl.doe.gov/technologies/coalpower/gasification/pubs/project-information.html . 57 Op. Cit., NETL, August 2011.
ATTACHMENT A 

Monday, June 25, 2012 31

With success of the First Generation demonstration facilities and the DOE’s ongoing R&D program, 

Second Generation pre-combustion CCS systems with substantial improvements in cost and 

performance could be demonstrated at commercial scale by 2025.58 Replications of these 

demonstration projects could lead to deployment of commercial systems by 2030. 

Oxy-combustion systems

Oxy-combustion systems generally resemble traditional pulverized coal or circulating fluidized bed 

power plants. However, there are some differences. First, high purity oxygen, instead of air, is used in 

the combustion process. At present Air Separation Units (ASU) are used to provide the large volume of 

oxygen needed for the oxycombustion process. Second, as the combustion of coal with high purity 

oxygen would produce flame temperatures that are too high to use in a conventional boiler design, a 

portion of the flue gas from the boiler is recycled and mixed with the oxygen to reduce the flame 

temperature and provide sufficient flue gas volume to support the proper heat transfer process in the 

boiler. Third, the CO2 rich flue gas must be cleaned and processed to remove particulates, SOx, NOx, 

mercury, water vapor and other contaminants prior to compression, transport and storage. 

The inherent advantage of oxycombustion systems is that the CO2 in the flue gas is much more 

concentrated (and therefore less costly to capture) than CO2 in the flue gas from a traditional power 

plant using air as an oxidant. However, this advantage is diminished somewhat by the capital and 

operating cost of the oxygen plant. Figure 3 shows a simplified diagram of an oxycombustion power 

plant with CO2 capture and compression. 

 58 Op. Cit., CURC, 2012.
ATTACHMENT A 

Monday, June 25, 2012 32

Figure 3. Oxycombustion power plant with CO2 capture.

Oxy-Coal Combustion Plant

With Carbon Capture

Boiler

PM removal

(FF or ESP) Sulfur

(FGD)

AH2

Flyash

Recycle

Condenser

Coal

Steam Turbine

Sulfur

By Products

Solid

By Products

Generator

Flue Gas Recycling

Air 

Separation

Plant

O2

Air

Electric

Power

Sequestration

Ready CO2 

Drying &

Comp

CO2 Capture

NOx

Removal

(SCR)

There are several challenges that Oxy-combustion systems must overcome:

 Oxycombustion has yet to be demonstrated at large scale. The only experience to date comes 

from pilot scale facilities the largest of which is approximately 10 MW electric. 

 An oxygen plant (ASU) is required to supply the oxygen for the oxycombustion process. It is an 

expensive and energy intensive process.

 A means of compression and purification (CPU) of the captured CO2 is required. While 

compression is common to all CCS process it is still an expensive and energy intensive process to 

integrate into the plant operation. 

 The integration of a large ASU and CPU into the operation of a power plant has never been 

demonstrated. 

 The recirculation of large volumes of flue gas has never before been demonstrated. 

 Similar to the cost of electricity from the other first generation CCS systems, the cost of electricity 

from oxycombustion power plants is expected to be very high.59,60 Without a significantsubsidy, 

the cost of electricity from any of the first generation CCS systems will not be competitive with 

conventional generating facilities.

 59 The Cost of CO2 Capture, Zero Emissions Platform, July 2011. 60 Economic Assessment of Carbon Capture and Storage Technologies – 2011 Update, WorleyParsons and 

Schlumberger, for Global CCS Institute, 2011.
ATTACHMENT A 

Monday, June 25, 2012 33

Oxycombustion technologies are considered to be less mature than pre-combustion and postcombustion CCS technologies. The FutureGen 2 project will repower an existing 200MW oil fired electric 

generating unit located in Meredosia, Illinois with a commercial-scale coal fired oxycombustion boiler 

design. This project is a collaborative effort between DOE and the FutureGen Industrial Alliance. The 

design calls for 90% capture of the CO2 produced in the boiler with the CO2 stored in a nearby geologic 

saline formation. Construction was scheduled to begin late in 2013, with start-up in 2015.61 Due to a 

change of ownership in the project the construction start will be delayed by at least 1 year.

R&D on oxycombustion technology is on-going, including research on corrosion, CO2 purification, 

chemical looping combustion, and lower cost methods of oxygen production.62,63

CO2 Compression and Transport

Compression and pipeline transport of CO2 are relatively mature technologies. Before the CO2 can be 

transported by pipeline, it must be purified of any oxygen, sulfur compounds, water and other 

contaminants. It is then compressed into a liquid at about 2,200 psig for transport via pipeline. The 

petroleum industry has extracted “natural” CO2 from underground reservoirs, cleaned, compressed and 

transported it by pipeline for various uses for over 30 years. As significant power is needed to compress 

CO2 to liquid form, research is underway to develop less energy intensive methods of CO2 compression. 

CO2 Storage 

Two approaches are being pursued for CO2 storage.64 The first approach is injection into deep 

underground geologic saline formations. This resource has the potential to store over 450 years of U.S. 

CO2 emissions at current emission rates.65

The second storage approach under consideration is use of captured CO2 to enhance oil recovery (EOR) 

from mature oil fields. CO2 injected into partially depleted oil reservoirs mixes with the remaining oil 

and lowers its viscosity allowing more oil to be extracted from the field. EOR has the potential to double 

the output from an existing oil field. Eventually the CO2 displaces the oil in the underground reservoir 

and is left there to be permanently stored. EOR is a mature technology and has been in commercial use 

 61 FutureGen Fact Sheet: Carbon Dioxide Capture and Storage Project, MIT CCS Project Database, 

http://sequestration.mit.edu/tools/projects/futuregen.html . 62 Op. Cit., NETL, August 2011. 63 Oxycombustion CO2 Control, USDOE/NETL, 

http://www.netl.doe.gov/technologies/coalpower/ewr/co2/OxyCombustion.html . 64 Carbon Storage, FAQ Information Portal, USDOE/NETL, 

http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carbonstorage2.html . 65 Carbon Storage, FAQ Information Portal, USDOE/NETL, 

http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carbonstorage2.html .
ATTACHMENT A 

Monday, June 25, 2012 34

since 1972. EOR projects are generally supplied CO2 from low cost naturally occurring underground CO2

reservoirs or the CO2 is separated at relatively low cost from raw natural gas. Sale of CO2 for EOR could 

partially offset the cost of capture for power generating facilities with CCS. However, with the relatively 

high cost of CO2 capture from power plants using current technology, this revenue stream is still 

insufficient to make the cost of electricity from CO2 capture plants competitive with conventional power 

generating facilities.

Research is ongoing to explore other opportunities for productive use of captured CO2 such as 

converting the CO2 into solid byproducts.66

Saline storage

It is believed that permanent CO2 storage in deep underground geologic formations will be viable on a 

widespread basis. However, many financial, institutional, regulatory, and technical hurdles remain.67 A 

variety of intermediate and large-scale CO2 injection tests in diverse geologies are required to 

adequately characterize and validate this U.S. geologic storage resource. Much of this work is already 

underway through collaborative efforts by DOE and the private sector.68

The basic process for injecting CO2 underground begins with identification of a suitable porous rock 

formation that is naturally “capped” by an impermeable rock strata. This cap permanently seals the 

injected CO2 in the target formation so that it cannot escape back to the surface or into drinking water 

formations. Once the target formation is identified a well is drilled into the porous structure, and 

supercritical liquid CO2 is injected with enough pressure to overcome the pressure within the porous 

formation. 

Suitable storage formations are typically one-half mile to over one mile below the earth’s surface. 

Depending on the size of the plant, the volume of CO2 produced and the size and porosity of the saline

formation it is anticipated that several injection wells could be needed over operating life of a power 

plant. Other test wells are needed to monitor the spread of CO2 within the geologic formation to ensure 

that the CO2 remains confined to the planned storage area.

 66 Carbon Storage, CO2 Utilization Focus Area, USDOE/NETL, 

http://www.netl.doe.gov/technologies/carbon_seq/corerd/co2utilization.html . 67 To address these challenges, multiple integrated, large scale (> 1 million tons / year) CO2 capture and storage 

system projects are needed to prove out the technology. 

68 Carbon Storage: Program Overview, USDOE/NETL, 

http://www.netl.doe.gov/technologies/carbon_seq/overview.html .
ATTACHMENT A 

Monday, June 25, 2012 35

When a formation has received its intended amount of CO2, injection ceases, and the well is capped to 

ensure that it will not be a conduit for release of the permanently stored CO2. Monitoring of the storage 

field will be required for some period of time to validate that the stored CO2 does not migrate beyond 

the designated storage site and that it remains permanently stored in place.

The cost of transportation, injection and monitoring is projected to be relatively small compared to the 

costs of capturing CO2. These costs will vary depending upon the local geology and the distance 

between the plant and the storage site.69

Injecting and storing gasses in deep geologic formations has been demonstrated to be technically viable. 

Natural gas has been successfully stored in geologic formations for many years. Injection of relatively 

low volumes of acid gasses into geologic formations has been in commercial use in Alberta, Canada since 

the 1980’s. While large-scale injection experience has been promising, mainly in conjunction with EOR 

or enhanced gas recovery (EGR), there is limited CO2 injection and storage experience from power 

plants. 

A small number of industrial projects have demonstrated the feasibility of large scale (>1 million TPY) 

CO2 storage in saline formations. The Sleipner project in Norway has been successfully storing about 1 

million TPY of CO2 co-produced with natural gas in deep saline formations since 1996, with no recorded 

leakage.70 Two similar projects, the In Salah project in North Africa (1 million TPY) and the Snohvit

project in the Barents Sea (0.7 million TPY), have been operational since 2004 and 2008, respectively, 

and are storing CO2 produced from natural gas processing.71

The major barriers to deployment of saline CO2 storage are:

• Geologic formations vary across the country. Some have features that make containment more 

certain than others. The best storage sites may not be located near existing power plants or 

where the power generation is needed. 

• While the industry believes saline geologic storage of CO2 can be as safe as natural gas storage and 

CO2 use for EOR, the public’s willingness to accept the geologic storage of large volumes of CO2

remains uncertain. Education of all stakeholders is critical for successful implementation of largescale storage facilities.

 69 Transportation cost of CO2 varies almost proportionately with the length of pipeline required to transport the 

CO2 from the power plant to the site of injection. If the captured CO2 is transported over great distances then the 

cost of the pipeline could constitute a significant expenditure of the overall CCS system.

70 The CO2 sequestration project in Norway, the Sleipner project, uses an amine system to clean natural gas that is 

high in CO2 content. 71 Key Projects, Global CCS Institute, http://www.globalccsinstitute.com/ccs/key-projects .
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• Monitoring, reporting, and verification (MRV) of CO2 stored in saline reservoirs is required by 

regulation but remains an area of development.72 Better tools must be developed to predict the 

capacity of storage reservoirs and monitor the lateral and vertical movement of injected CO2 over 

time. Technology, know-how and experience from the oil and gas industries are expected to be 

useful in addressing this area of need.

• Regulations promulgated by EPA to protect underground sources of drinking water, pursuant to 

the Underground Injection Control (UIC) program include monitoring and financial assurances that 

last 50 years beyond the period in which CO2 is injected into the formation.73 This liability appears 

to be beyond the coverage available under existing insurance policies and could pose an 

unacceptable cost to power plant owners.

• Similarly a mechanism to address long-term storage integrity is also needed. A method to ensure 

perpetual monitoring and leak mitigation must be developed. The Interstate Oil & Gas Compact 

Commission (IOGCC) has published model rules74 which offer one possible approach.

Basic research on storage is probably not as necessary to overcome these barriers as are experience and 

empirical data. To overcome these technical barriers some storage projects, preferably at well 

characterized sites that are inherently low risk, need to be built and tested to determine the true 

potential for safe and secure long term CO2 storage. 

EOR storage

Reports published by DOE/NETL conclude that 20 billion tonnes of CO2 could be stored in the process of 

producing 67 billion barrels of oil via “next generation” CO2-EOR.75 For perspective, emissions of CO2

from the U.S. electric power sector totaled 2.3 billion tonnes in 2010.76 The concept of using CO2 for 

productive purposes has generated the term: CCUS, or carbon capture, utilization, and storage. 

From a power plant’s perspective, the motivation for using CO2 for EOR is twofold. First sale of CO2 for 

EOR creates revenues that can partially offset the cost of capture and second, legal issues relating to 

property rights, monitoring, and long-term liability are more settled, and less stringent for EOR than for 

saline storage of CO2.

 72 Federal Requirements Under the UIC Program for CO2 Geologic Sequestration Wells, USEPA, 75FR77230, 

December 10, 2010.

73 Ibid. 74 CO2 Storage: A Legal and Regulatory Guide for States, IOGCC, 2007, http://groundwork.iogcc.org/topicsindex/carbon-sequestration/executive-white-papers/co2-storage-a-legal-and-regulatory-guide-fo . 75 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR), USDOE/NETL, June 20, 2011. 76 Op. Cit., U.S. GHG Inventory.
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In evaluating the economics of EOR projects, DOE has used a range of values for the price of CO2 that are 

pegged to the global price of crude oil. For oil priced at $100 per barrel, the range equates to $38-58 

per tonne of CO2.

77 After subtracting transportation costs, (that could be significant depending on how 

far the EOR opportunity might be from the power plant) studies still suggest a significant offset to 

capture costs is possible.78

CO2 storage in EOR fields also presents lower risk. With EOR storage, oil and water are withdrawn from 

the formation as CO2 is injected, thereby limiting the increase in formation pressures. Lower pressure 

means diminished risk that the CO2 will migrate from its intended storage area. Additionally, there is 

much more experience with EOR storage of CO2 than with saline storage. This should mitigate some of 

the risks associated with storage liabilities.

Based on the DOE’s analysis, EOR does not provide adequate capacity for storing CO2 generated from all 

present and future fossil fuel power plants. Nevertheless, the fact that all but one of the current CCS 

demonstration projects are pursuing EOR storage suggests that EOR-based CO2 storage (i.e., CCUS) may 

dominate CO2 storage in the U.S. for decades.

DOE is working with industry to develop additional productive uses for CO2 beyond EOR. Specific 

elements of the R&D can be found on the DOE’s website for the CO2 Utilization Focus Area.79

Legal ownership and Liability Issues Related to CO2 Storage 

Ownership issues associated with geological formations and the right to inject above, in or below 

minerals is an area of great uncertainty for CCS. Equally, the liability related to CO2 injection operations 

and long-term maintenance remains uncertain and offers another potential barrier to large-scale 

storage projects. 

Some states are advancing legislation to address the rights of land owners regarding mineral ownership 

and liabilities regarding CO2 injection. The liabilities related to a CCS project include a local damage 

element during operations and post-closure phases, a global damage element for carbon reversal if 

there is leakage from the storage and personal injuries if there is personal or environmental damage 

that results from CO2 leakage. 

 77 Op. Cit., Improving Domestic Energy Security. 78 It remains to be seen how much of this revenue will flow to the capture facility and how much will go to the 

owner of the connecting pipeline, or if the EOR developer will provide this much revenue. In some regions of the 

U.S., lower cost sources of CO2 may be available. 79 http://www.netl.doe.gov/technologies/carbon_seq/corerd/co2utilization.html .
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Cost of CCS

Current technology

The addition of first generation CCS technology to a new coal fired power plant will approximately 

double the cost of electricity from that plant. A common cost metric used in the electric power industry 

is the “levelized” cost of electricity (LCOE). The LCOE represents the average cost over a defined period 

of operation, typically 30 years, and can be expressed in either nominal or constant (excluding the 

effects of inflation) dollars. LCOE includes annualized capital cost, fixed and variable operating and 

maintenance (O&M) costs, fuel costs, and in the case of CCS units, a cost for transportation and storage 

of captured CO2. Table 1 and Figure 4 provide estimates of costs for 2010 vintage power plant 

technology, both with and without CCS, based on data from a 2011 analysis published by GCCSI.80 As 

noted in Figure 4, the cost estimates in Table 1 and Figure 4 reflect an engineering assessment. No 

power plant equipped with commercial scale CCS has actually been built.

Table 4. Current CCS Technology Costs. 

Cost in constant 2010 

$/MWh SCPC, no CCS SCPC, 90% CCS IGCC, no CCS IGCC, 90% CCS

Capital 38 63 46 57

O&M 10 17 14 18

Fuel 22 33 30 41

CO2 T&S - 11 - 9

Total 70 124 90 125

 80 Op. Cit., Economic Assessment of Carbon Capture and Storage Technologies. Published values were adjusted to 

reflect different assumptions regarding fuel costs and storage costs. 
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Figure 4. Current Power Plant CCS Costs.

Future CCS Technologies

CURC projects that these costs could be dramatically reduced over the next 15 to 20 years through 

continued technology development via RD&D and the use of CO2 from the capture plants for EOR. 

Revenue from CO2 sales to EOR users would provide a revenue stream to offset a portion of the CO2

capture cost. Figure 5 shows how these factors might combine for second and third generation power 

systems with CCS. Importantly, Figure 5 reflects the date at which a first of a kind demonstration of the 

technology is operational. A minimum of 4 to 7 years must be assumed before this initial demonstration 

project can be replicated and before a first commercial offering with guarantees of the replicated 

technology can be offered.
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Figure 5. Projected costs of CCS.

Retrofit CCS Technology

The costs presented above reflect estimates for new coal-based power plants. Application of CCS to 

existing power plants will be more complicated and more costly. Much of the reduction in CCS system 

costs in the future is attributable to improvements in the basic power plant, such as higher operating 

efficiency. That type of fundamental redesign of the power plant is generally not practical for a retrofit 

CCS system. 

Application of CCS to an existing power plant can double the facility’s cooling water requirements, and 

requires large amounts of space – two factors that may prohibit the installation of CCS at many existing 

sites. An additional complication involves the large amount of energy that will be consumed by the CCS 

system. Lastly, some units are so small or so old that the large capital investment required by CCS would 

not be considered. 
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Monday, June 25, 2012 41

These factors make predictions regarding the current and future costs of retrofit CCS systems highly 

uncertain. The practice of applying a “retrofit factor”, similar to what was done for less disruptive 

technologies like SO2 scrubbers and NOx control systems may not be valid for a technology which poses 

the complex integration issues that come with CCS. That said, a rough estimate for current CCS 

technology cost at a plant meeting the general requirements of a good retrofit candidate would be 20-

30% greater than the incremental cost of CCS on a new facility. In other words, if the incremental cost 

of CCS on a new pulverized coal system were $55/MWh, the cost of retrofitting that technology on an 

existing system might be $70/MWh.81 

Three factors which could reduce the cost of CCS retrofit technologies are (1) capturing less than 90% of 

the CO2, (2) selling the CO2 for EOR; and (3) reduction in CO2 capture costs through technology 

improvement

Conclusions:

CCS is an emerging technology which is likely to be demonstrated as technically feasible in first 

generation facilities over the next several years. However, these first generation CCS technologies are 

projected to double the cost of electricity and without significant subsidies these plants will not be 

competitive with alternative sources of electric power, such as coal or natural gas combined cycle 

systems that do not include CCS 

Continuing to pursue existing CCS RD&D programs, when combined with demonstration of second 

generation CCS technologies, could significantly improve the cost and performance of CCS systems by 

2025. Deployment of these second generation systems could begin to occur as soon as 2030, 

In addition to CCS technology development, we also need to overcome institutional barriers to CO2

storage that include resolution of property rights, and creation of a system to address long-term 

monitoring and liabilities associated with CO2 storage sites. The IOGCC has worked with a broad 

coalition of stakeholders to develop model legislation and regulations for states to consider in 

establishing these needed rules. Several states have already used the model rules to adopt such 

regulations and regulations are under development in other states. 

 81 This cost would be additive to the current cost of electricity from the unit, typically about $30/MWh.
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Monday, June 25, 2012 42

Attachment 1. Federally supported CCS demonstration projects.

Southern Company IGCC

Total:~$2.9B; DOE: $270M 

EOR Storage – 3.0 MTPY

HECA

IGCC

Total:~$2.8B; DOE: $408M 

EOR Storage – 2.0 MTPY

Summit TX Clean Energy IGCC 

Total:~$1.7B; DOE: $450M

EOR Storage – 3.0 MTPY

NRG W.A. Parish

Post Combustion 

Total: $339M; DOE: $167M 

EOR Storage – 0.4MTPY

FutureGen 2.0

Oxy-Combustion

DOE: $1.0B

Saline Storage – 1.0 MTPY

Archer Daniels Midland 

CO2 Capture from Ethanol Plant

Total $208M; DOE:$141M 

Saline - 1 MTPY

Air Products

CO2 capture from Steam 

Methane Reformers

Total$ 431M; DOE:$284M 

EOR - 1 MTPY

Leucadia Energy

CO2 Capture from 

Methanol Plant

Total$ 436M;

DOE:$261M 

EOR - 4.5 MTPY

Major CCS Demonstration Projects Tax Credit

CCPI

FutureGen

ICCS

Loan Guarantee

Tenaska Taylorville

IGCC

Total: $3.5B; DOE: $2.6B

EOR - 2.25 MTPY

Leucadia Indiana SNG

DOE: $1.6B

EOR

Leucadia Mississippi

SNG

DOE: $1.7B

EOR - 4.0 MTPY

DKRW Medicine Bow

Coal to Liquids

DOE: undisclosed

EOR - 3.6 MTPY

*Additional Advances Coal Demonstration Projects include Duke Edwardsport IGCC (no C02 capture component) 

and Tenaska Trailblazer Energy Center (no public funds received)