Basis for Denial of Petitions to Reconsider the CAA Section 

111(b) Standards of Performance for Greenhouse Gas 

Emissions from New, Modified, and Reconstructed Fossil 

Fuel-Fired Electric Utility Generating Units

April 2016
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Basis for Denial of Petitions to Reconsider the CAA Section 

111(b) Standards of Performance for Greenhouse Gas Emissions 

from New, Modified, and Reconstructed Fossil Fuel-Fired 

Electric Utility Generating Units

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sectors Policies and Programs Division

Research Triangle Park, NC 27711

April 2016
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SUMMARY: The U.S. Environmental Protection Agency (EPA) received six petitions for 

reconsideration of the final Standards of Performance for Greenhouse Gas Emissions from New, 

Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, published in 

the Federal Register on October 23, 2015. The agency is denying five of these petitions, and 

deferring action on the petition of the Biogenic CO2 Coalition.

Table of Contents

I. Executive Summary

II. Background

III. The Petitions

A. Petition of Utility Air Regulatory Group (UARG)

B. Petition of American Electric Power (AEP)

C. Petition of Ameren Corp. (Ameren)

D. Petition of the State of Wisconsin (WI)

E. Petition of Energy and Environment Legal Institute (EELI)

IV. Response to the Petitions

A. Response to UARG Petition

B. Response to AEP Petition

C. Response to Ameren Petition

D. Response to State of Wisconsin Petition

E. Response to EELI Petition

V. Conclusion
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I. Executive Summary

Pursuant to section 111(b) of the Clean Air Act (“the Act”), the EPA has promulgated 

new source performance standards that establish, for the first-time, standards of performance for 

greenhouse gas emissions from newly constructed, modified, and reconstructed fossil fuel-fired 

electric utility generating units (EGUs). 80 FR 64510 (Oct. 23, 2015). The standard for newly 

constructed steam generating EGUs reflects the level of CO2 emission reduction achievable by a 

highly efficient supercritical pulverized coal-fired boiler implementing partial carbon capture and 

sequestration (CCS) technology. 80 FR 64545. The standard for newly constructed and 

reconstructed stationary combustion turbines reflects the performance of a modern, wellperforming natural gas-fired combined cycle (NGCC) unit. 80 FR 64612.1

The EPA has received six petitions for reconsideration of the final standards of 

performance, focusing mostly on issues related to the standard of performance for newly 

constructed steam generating units and, more specifically, on the performance and cost of carbon 

capture technology. One petition maintains that the post-promulgation performance of carbon 

capture technology in actual operation at the Canadian SaskPower Boundary Dam Unit 3 facility 

shows that carbon capture is not yet adequately demonstrated at commercial scale. The EPA is 

denying reconsideration on this issue because, contrary to the petitioner’s contention, the 

facility’s performance, through March 2016, corroborates the EPA’s conclusion in the 

rulemaking that partial CCS is an adequately demonstrated technology within the meaning of 

CAA section 111(b). The same petition maintains that the SaskPower Boundary Dam facility 

uses a different carbon capture process than the one the EPA evaluated at proposal. This 

contention is incorrect. The petition further maintains that the EPA has not accounted for cost 

overruns at that facility. This contention is significantly exaggerated and not borne out by the 

facts.

The same petition maintains that the EPA failed to provide adequate public notice and 

opportunity to comment on the uncontrolled baseline emission rate (i.e., the emission rate of an 

uncontrolled coal-fired boiler) that it used as the starting point for calculating the percent of 

partial carbon capture needed to meet the applicable standard. In fact, the proposed rule provided 

ample public notice and opportunity to comment on this issue. The petition also maintains that 

the baseline is not achieved in practice, so that EPA’s cost estimates fail to account for some 

measure of increased boiler efficiency. The EPA disagrees with this contention, but even 

accepting the allegations, the costs of the standard would remain reasonable using the same 

methodology the EPA used in the rulemaking for assessing cost reasonableness. Another

objection raised regarding partial CCS in this petition is that the EPA’s cost estimates of partial 

carbon capture reflect an inappropriate methodology for scaling down full carbon capture costs 

to partial capture costs. The EPA is denying reconsideration on this issue because the scaling 

methodology used in the rulemaking is well-established and normative, and the petition presents 

no legitimate reason to deviate from this standard methodology. 

 

1 The EPA also set standards for reconstructed steam EGUs and for those units that make large 

modifications. The EPA withdrew proposes standards for modified stationary combustion turbines. This 

is discussed in greater detail in the preamble for the final rule. No petitioners raised issues associated with 

the standards for modified or reconstructed steam EGUs.
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Other petitioners address the partial CCS-based standard for newly constructed steam 

generating EGUs, but these petitions simply reiterate issues already raised in their rulemaking

comments. The EPA has already addressed these comments in the preamble to the final rule and 

in the Response to Comment document. These petitions are untimely and the EPA is therefore

denying them.

The remaining petition addressing the partial CCS-based standard alleges that the 

rulemaking process was tainted by impermissible communications involving an EPA official and 

various members of non-governmental organizations. This petition’s legal theory is flawed, and 

the petition rests on a plethora of inaccurate factual assertions. The EPA is accordingly denying 

this petition. 

The final rule also contains standards for stationary combustion turbines, and one of the 

petitions discussed above also challenges the definition of “base load rating” included as part of 

that standard. The EPA is denying reconsideration of this issue because the decision to include 

the heat input from duct burners in the definition of “base load rating” was not only reasonable, 

but advantageous to the regulated industry. 

Two of the petitions – from the Biogenic CO2 Coalition and from the State of Wisconsin 

– raise issues associated with the agency’s treatment of biomass emissions when co-fired with 

fossil fuels. The EPA is deferring action on this issue pending further on-going consideration of 

the underlying issue of whether and how to account for biomass, for purposes of compliance 

with applicable standards, when co-firing with fossil fuels. 

The EPA is accordingly denying five of the six petitions for reconsideration, and 

deferring action on the remaining petition. 

II. Background

Section 307(d)(7)(B) of the CAA requires the EPA to convene a proceeding for 

reconsideration of a rule if a party raising an objection to the rule “can demonstrate to the 

Administrator that it was impracticable to raise such objection within [during the public 

comment period] or if the grounds for such objection arose after the period for public comment 

(but within the time specified for judicial review) and if such objection is of central relevance to 

the outcome of the rule.” The requirement to convene a proceeding to reconsider a rule is thus 

based on the petitioner demonstrating to the EPA both: (1) that it was impracticable to raise the 

objection during the comment period, or that the grounds for such objection arose after the 

comment period but within the time specified for judicial review (i.e., within 60 days after 

publication of the final rulemaking notice in the Federal Register, see CAA section 307(b)(1)); 

and (2) that the objection is of central relevance to the outcome of the rule.

In the EPA’s view, an objection is of central relevance to the outcome of the final rule 

only if it provides substantial support for the argument that the promulgated regulation should be 

revised. See, e.g., the EPA’s Denial of the Petitions to Reconsider the Endangerment and Cause 

or Contribute Findings for Greenhouse Gases under Section 202 of the Clean Air Act, 75 FR 

49556, 49561 (August 13, 2010); see also Coalition for Responsible Regulation v. EPA, 684 F. 

3d 102, 125 (D.C. Cir. 2012) (acknowledging and applying the EPA’s interpretation of the 

central relevance criterion); North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008) (holding that 
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a petitioner fails to demonstrate that its objection is of central relevance when the petitioner 

“vaguely alludes to EPA’s incorrect factual assumptions,” but “fails to support [its] assertion”) 

(internal quotation omitted).2 Put another way, an objection is of central relevance to the 

outcome of the rule if the EPA would have reached a different outcome in the rulemaking if the 

objection has merit. Should the EPA deny petitions for reconsideration, “EPA certainly may ... 

provide an explanation for that denial, including by providing support for that decision, without 

triggering a new round of notice and comment for the rule.” Coalition for Responsible 

Regulation, 684 F. 3d at 126.

The EPA has received six petitions for reconsideration of the CAA section 111(b) 

greenhouse gas (GHG) new source performance standard (NSPS) from the following entities: the 

Utility Air Regulatory Group (UARG); American Electric Power (AEP); Ameren Corp.

(Ameren); the Energy and Environmental Legal Institute (EELI); State of Wisconsin (WI); and 

the Biogenic CO2 Coalition. The EPA is denying all but the last of these petitions as not 

satisfying one or both of the statutory conditions for compelled reconsideration. The EPA is 

deferring action on the issue raised in the petitions of the Biogenic CO2 Coalition and the State 

of Wisconsin regarding treatment of biomass emissions pending our further on-going 

consideration of the underlying issue of whether and how to account for biomass emissions when 

co-firing with fossil fuels. We discuss in turn each of the five petitions we are denying.

III. The Petitions

A. Petition of Utility Air Regulatory Group (UARG)

UARG’s petition seeks reconsideration of several issues. First, UARG maintains that the

operational experience with the newly installed carbon capture system3at the SaskPower 

Boundary Dam Unit 3 (BD3) belies EPA’s reliance on this facility’s operating experience in 

support of the agency’s conclusion that carbon capture is an adequately demonstrated technology 

within the meaning of section 111 of the Act. Specifically, UARG maintains that BD3’s carbon 

capture system has experienced significant operating issues, including prolonged shutdowns, and 

has failed to reach its 90 percent capture design level. The petition further states that the 

company has incurred financial penalties for failing to provide contractually agreed upon 

amounts of CO2 to its sequestration site (where the CO2 is used for enhanced oil recovery

(EOR)), again because of these operational shutdowns and other problems. The petition suggests 

that these operational issues have caused SaskPower to reconsider its announced plans to retrofit 

others of its units with carbon capture systems, quoting the company’s chief executive officer as 

stating, “[w]e need a year of stable operation near maximum performance to really test the 

 

2 See also CAA sections 307(d)(8) and (d)(9)(D)(iii), which likewise apply a “central relevance” criterion 

to judicial review of alleged procedural errors, requiring that the error be essentially outcomedeterminative: “so serious and related to matters of such central relevance to the rule that there is a 

substantial likelihood that the rule would have been substantially changed” if a procedural error had not 

occurred. 

3 UARG refers to “CCS” – carbon capture and sequestration (or storage) – throughout this part of its 

petition, but the issues it raises relate entirely to operation of the carbon capture system, not the 

transportation or sequestration/storage parts of the project (beyond its assertion that Boundary Dam has 

failed to provide the volume of CO2 for sequestration specified by contract and has incurred financial 

penalties as a result).
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technology and commercial viability going forward” (UARG petition Exh. I). UARG also states

that the carbon capture system in use at BD3 served as the basis for the Department of Energy’s 

National Energy Technology Laboratory (NETL) cost estimates for carbon capture systems, 

which were in turn used by the EPA for its cost estimations in the rulemaking, and that BD3 is 

now experiencing costs not accounted for in the NETL estimates.

Finally, UARG states that BD3 has not shown that it could achieve the promulgated 

standard of 1,400 lb CO2/MWh-g (demonstrated on a 12-month basis). The petition contains 

various supporting exhibits, most of which are press accounts of Saskatchewan (Canada) 

Parliamentary debates discussing BD3’s operations. The petition claims that this information is 

of central relevance since the performance of BD3 provides the primary rationale for the EPA’s 

finding that carbon capture is adequately demonstrated. (UARG Petition p. 8) Because BD3’s 

operating history reflects post-proposal, and in many instances, post-promulgation developments, 

commenters could not have been presented the information to the EPA during the rulemaking.

The second issue raised in the UARG petition (effectively joined by petitioners AEP and 

State of Wisconsin, which raise the identical issue in their petitions) is that the EPA selected an 

arbitrary uncontrolled baseline CO2 emission rate from which to calculate quantified CO2

emission reductions, and did so without providing adequate opportunity for public comment. 

Specifically, UARG maintains that at proposal the EPA indicated that the Best System of 

Emission Reduction (BSER) for CO2 was partial CO2 capture applied to an emission stream 

reflecting performance of a supercritical pulverized coal boiler (SCPC). The baseline should thus 

be the initial performance of a SCPC unit. UARG states that “[t]he proposed GHG NSPS did not 

in any way address the baseline emission rate for new SCPC units or analyze the proposed 

standard’s achievability for such units. Instead, the proposal only conceptually described ‘the 

emission reductions that can be achieved by an IGCC [Integrated Gas Combined Cycle] with a 

single-stage ... reactor and a two-stage acid gas removal system’ – i.e., an IGCC applying precombustion CCS,” citing to 79 FR 1470 (UARG Petition p. 9). In the final rule, according to 

UARG, the BSER is partial CO2 capture applied to an emission stream reflecting performance of 

an ultra-supercritical pulverized coal (USCPC) boiler, performing at hitherto undisclosed levels 

of between 1,618 to 1,737 lb CO2/MWh (depending on the type of coal being utilized). UARG 

maintains that SCPC units cannot meet this baseline level, and therefore that the final standard 

would not be achievable without additional carbon capture, which UARG maintains the EPA has 

implicitly found would not be cost-effective. UARG further maintains that even ultrasupercritical boilers cannot meet the baseline levels over the 12-month operating period specified 

in the rule for compliance. (UARG Pet. p. 13.) According to the Petition, the issue is of central 

relevance to the rule’s outcome because it pertains to the standard itself.

UARG’s third issue relates to the EPA’s estimates of CCS capital costs, which UARG 

maintains are arbitrarily low. UARG asserts that the EPA “did not address the capital cost of 

partial CCS” at proposal (UARG Pet. p. 14), and that its estimates of capital costs for the final 

rule are erroneous because the costs a) do not reflect costs of actual projects utilizing CCS; b) 

fail to reflect the proper baseline, a well-operated SCPC (reiterating issue 2 above); c) fail to 

include a design margin; and d) are based on NETL reports that misapply NETL’s own 

methodology for estimating costs when scaling. The issue is of central relevance, according to 

the Petition, because the purported costing errors call into question the EPA’s conclusion that 

CCS is an adequately demonstrated technology, considering its cost.
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The Petition also seeks reconsideration of two issues that are ancillary to the promulgated 

standards of performance. UARG maintains that the EPA changed the applicability criteria for 

stationary combustion turbines without proper notice, and that this issue is of central relevance to 

the rule’s outcome since it relates to which units are subject to the standard of performance. 

Specifically, UARG argues that the EPA should reconsider its decision to include the heat input 

from duct burners in the definition of “base load rating,” 40 CFR 60.5580, because UARG did 

not have an opportunity to comment on this aspect of the final rule. UARG explains that this 

change affects the applicability criteria for stationary combustion turbines, which only subject 

turbines that have “a base load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either 

alone or in combination with any other fuel)” to the requirements of the rule. 40 CFR 

60.5509(a)(1). UARG objects to the inclusion of the heat input from duct burners in the 

definition of “base load rating” because the approach is allegedly inconsistent with the approach 

taken in the proposed rule and the EPA’s historical treatment of stationary combustion turbines 

under Subpart KKKK. UARG asserts that the issue is centrally relevant to the Rule because it 

implicates the fundamental question of what units are subject to the 111(b) GHG NSPS.

The last issue raised in UARG’s petition is that the final rule unreasonably restricts the 

entities who may submit electronic reports under the final standard. The petition maintains that 

the final rule purportedly reflected public comments submitted by UARG, but misinterpreted 

those comments. UARG maintains that this issue is of central relevance to the outcome of the 

rule as it relates to who can make submissions under the rule.

B. Petition of American Electric Power (AEP)

American Electric Power Co. (AEP) maintains that the EPA misinterpreted and 

misapplied information relating to a project whereby AEP retrofitted one of its operating plants 

(the Mountaineer Power Plant, New Haven, WV) with CCS. AEP maintains that it (and others) 

submitted extensive comments regarding the Mountaineer Power Plant retrofit, and that, despite 

these comments, the final rule unaccountably still indicates that the Mountaineer project provides 

support for partial CCS being an appropriate best system of emission reduction. The petition 

does not maintain that AEP lacked adequate notice of issues pertaining to the Mountaineer 

project, or that the issue of the plant’s performance is of central relevance to the outcome of the 

rulemaking. 

AEP also maintains that certain alternative compliance options for meeting the standard, 

namely using natural gas co-firing in either a steam generating unit (boiler) or Integrated 

Gasification Combined Cycle (IGCC) unit, are not technically demonstrated, and seeks 

reconsideration of this finding. The State of Wisconsin likewise seeks reconsideration of this 

finding, for similar reasons. Finally, as noted above, AEP also contends that the EPA selected an 

arbitrary uncontrolled baseline CO2 emission rate from which to calculate quantified CO2

emission reductions, and did so without providing adequate opportunity for public comment. 

C. Petition of Ameren Corp.

Ameren Corp. (Ameren) maintains that the CAA section 111(b) GHG NSPS, the CAA 

section 111(d) existing source standards of performance and emission guidelines, and the 

proposed federal plan requirements are closely intertwined and should be considered as a single 

unit of rules. The petition then mentions a series of issues relating exclusively to the CAA 
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section 111(d) existing source standards and emission guidelines as (purportedly) necessitating 

reconsideration.4 The petition does not seek reconsideration of any specific issue in the section 

111(b) rulemaking. The only mention of an issue specific to the section 111(b) NSPS is an 

allegation that partial CCS is not yet adequately demonstrated (Ameren Petition p. 24) (with a 

supporting quotation that relates to full CCS rather than partial CCS). The petition does not 

allege that Ameren lacked notice and opportunity to comment on this issue.

D. Petition of State of Wisconsin

The State of Wisconsin seeks reconsideration of various issues raised in its public 

comments, which it asserts that the EPA failed to address. These issues include whether CCS is 

adequately demonstrated when it is an “emerging technology”; whether the standard is arbitrary 

because it is more stringent than a best available control technology (BACT) limit for a coalfired plant in Wisconsin; and whether the standard impermissibly disadvantages Wisconsin 

sources for various reasons, including lack of geologic sequestration capacity within the state. 

The petition further maintains that the EPA did not account for the full cost of transporting 

captured CO2, at least for Wisconsin sources. Additionally, with respect to combustion turbines, 

the petition argues that EPA set a standard of performance for base load units that cannot be 

achieved by simple cycle technology. Finally, the petition raises a number of issues in common 

with the other petitions, as noted above. 

Similar to the AEP petition, the Wisconsin petition maintains that co-firing of natural gas

in either a steam generating unit (boiler) or Integrated Gasification Combined Cycle (IGCC) unit, 

has not been technically demonstrated, and the petition seeks reconsideration of the EPA’s

finding that natural gas co-firing can serve as an alternative compliance option for meeting the 

standards. Finally, as noted above, the petition also contends that the EPA selected an arbitrary 

uncontrolled baseline CO2 emission rate from which to calculate quantified CO2 emission 

reductions, and did so without providing adequate opportunity for public comment. The petition 

does not address the section 307(d) criteria for granting reconsideration.

E. Petition of Energy and Environment Legal Institute (EELI)

EELI maintains that the final standard of performance is tainted due to pre-proposal 

communications between a particular EPA official and representatives of environmental nongovernmental organizations (NGOs), which the petition characterizes as illegal ex parte contacts 

that are of central relevance to this proceeding because of the purported influence the 

communications had on the standard.

IV. Response to Petitions

A. Response to UARG Petition

1. Performance of SaskPower Boundary Dam Unit 3 (“BD3”)

 

4 Note that Ameren Corp. also submitted essentially the same petition to the agency requesting 

reconsideration of these issues in the CAA section 111(d) emission guidelines.
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SaskPower’s Boundary Dam has installed retrofit “full CCS”

5

technology on its Unit 3 

boiler and is currently operating it at commercial scale. UARG, in essence, maintains that the 

post-proposal/post-promulgation performance of BD3 shows that the CCS system is not 

working, and, therefore shows that the technology is not adequately demonstrated at the facility. 

The petition further states that since the performance of the BD3 system was the critical element 

in the EPA’s finding that partial CCS is an adequately demonstrated technology, the unit’s

subsequent operational failures undermine the entirety of the EPA’s finding, and is necessarily 

an issue of central relevance to the outcome of the rulemaking. UARG further maintains that it 

lacked opportunity to comment on these issues because the critical elements of the BD3

performance occurred either after proposal or after the August 2015 promulgation date of the 

final standards. 

The EPA agrees that the grounds for UARG’s objection arose after the public comment 

period, but disagrees that the objection is of central relevance to the rule’s outcome because the 

EPA did not rely solely on the expected performance of BD3 (see 80 FR 64550-556) and

because the actual performance of BD3 confirms that partial CCS is adequately demonstrated at 

the facility, and thus corroborates the EPA’s finding that the technology is adequately 

demonstrated. 

The suggestion that BD3 has experienced operational failures calling into question the 

reliability, feasibility, or demonstrability of the carbon capture technology is greatly exaggerated 

and essentially incorrect. As described below, the CO2 capture system at BD3 is operating 

successfully, the unit meets the Canadian performance standard for CO2 emissions (which is

more stringent than the U.S. standard), and it is producing more CO2 for enhanced oil recovery 

than called for by contract. Operational issues in the first year of operation were related largely 

to ancillary systems and not to the carbon capture system, and appear to have been successfully 

resolved.

The BD3 carbon capture system commenced operation in October 2014. The system was 

shut down for two weeks in June 2015 for maintenance, and for nearly two months (most of 

September and all of October) in the fall of the same year for further maintenance.

6 The system 

has operated with high reliability since.

7 BD3 continued to generate electricity during the entire 

18-month period, with the exception of the September maintenance period.

8

 

5 As explained in both the proposal (79 FR 1469) and the final standards (80 FR 64548), “full CCS” 

means that the system is designed to capture 90 percent (or greater) of the CO2 emissions from the plant 

usually by treating the entire combustion flue gas or syngas stream. “Full CCS” is distinguished from 

“partial CCS” in that the latter is a system that is designed to capture some amount less than 90 percent of 

the CO2 emissions, often by treating only a portion (or slip stream) of the combustion flue gas or syngas 

stream.

6 SaskPower Report March 2016 posted at http://www.saskpower.com/about-us/blog/bd3-status-updatemarch-2016/ .

7

Id., indicating that the system “was operational 82 of 91 days of the year, primarily due to planned 

maintenance, for a 90% reliability factor in the first quarter of 2016.”

8

Id.
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It is not unusual for plants to experience operational issues after first installing and 

operating a complex technical system. See, e.g., 79 FR 1482.9 However, according to 

SaskPower, most of the technical issues experienced by the unit in its initial year of operation

involved ancillary equipment and control systems rather than technical issues that are directly 

attributable to the carbon capture system itself.

10 For example, there were idiosyncratic issues

associated with the design or misplacement of ordinary components – such as exhaust valves 

being installed too near intake valves. There was also a delay associated with the need to install a 

new, larger storage tank for the amine solvent and then to fix the tank, which the company 

described as being delivered with visible hairline cracks in the tank floor.

11 In addition, in the 

initial months of operation, the unit experienced some operational difficulties associated with 

SaskPower’s ability to control the amine regeneration temperature because of a leaky steam 

valve. This resulted in overheating and subsequent degradation of the amine solvent.12 While the 

leaky steam valve resulted in an overall degradation of the performance of the carbon capture 

system, few would characterize steam valve technology as “not adequately demonstrated” or 

“first-of-a-kind”. Nor is a cracked storage tank the type of development that raises issues 

regarding the feasibility of carbon capture technology.

The company brought the carbon capture system down in September and October of 

2015 to address various operational issues related to sodium-based sub-micron particles that 

were fouling demisters at the exit of the SO2 scrubber upstream of the carbon capture system.13

The issue was resolved and the carbon capture system resumed operation in November 2015.

The system has demonstrated high rates of CO2 capture since its initial coming on-line. In 

its initial months of operation, the system operated at a relatively constant CO2 removal rate of 

approximately 61.5 percent of its design capacity (or approximately 1,700 tons of CO2 per day). 

Since November 2015, after the two month hiatus, the unit captured approximately 60,000 tons 

of CO2 in November 2015 and approximately 61,000 tons of CO2 in December 2015, capture 

 

9 See also letter from SaskPower President and CEO Mike Marsh to Administrator Gina McCarthy (Nov. 

17, 2015) (“[w]e have achieved an 80 per cent capture rate in our early operations; however, the capture 

rate has fluctuated over the course of the year. Since the launch, SaskPower has experience various 

problems with a number of sub-systems within the process and has worked to develop solution and to fix 

them. These challenges are not uncommon in a large-scale industrial project during the early stages of 

operation....”). 

10 Memorandum of conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), 

February 2, 2016; Email from Mr. Mike Monea (SaskPower) to Dr. Nick Hutson (EPA), February 2, 

2016).

11 Memorandum of conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), 

February 2, 2016. See also SaskPower Press Release of Sept. 14, 2015

(http://www.saskpower.com/about-us/media-information/newsreleases/large-piece-of-saskpowerequipment-makes-its-way-from-saskatoon-to-estevan/), and UARG Petition Exh. G p. 2 which note the 

replacement of the amine storage tank, and note the storage tank’s very substantial size. Exh. G (at p. 2) 

also notes the issue of the leaky valve.

12 Memorandum of conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), 

February 2, 2016.

13 http://www.saskpower.com/about-us/blog/bd3-status-update-january-2016/; Memorandum of 

conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), February 2, 2016. The 

system was also down for maintenance for two weeks in June 2015. 
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rates exceeding 70 percent of design capacity.

14 In January 2016, the unit captured

approximately 85,000 tons15– slightly better than 100 percent of design capacity, and an amount 

that exceeds the monthly quantity of CO2 that SaskPower has contracted to provide to Cenovus 

Co. for EOR operations.

16 Capture rates for February and March, 2016, are approximately 60 and 

100 percent of design capacity respectively.17 SaskPower has, at several times, conducted socalled nameplate testing, designed to test the capture limits of the facility, and was able to 

achieve the intended 90 percent capture rates on those occasions.

18 The company has stated 

publicly that it expects the carbon capture system to be operational 85 percent of the time in 

2016 (allowing time off for routine scheduled maintenance) and to capture 800,000 tons of CO2

over that year, a projected average capture rate of approximately 80 percent of design capacity.

19

Over the one-year operating period from October 2014 through September 2015, even 

considering the facility downtime, BD3 captured approximately 415,000 tons of CO2. This is a 

capture rate exceeding 40 percent,

20 which is significantly more efficient than the 12-month 

annual capture rate (reflecting partial carbon capture at an annual rate of approximately 16 to 23

percent depending on coal type) on which the section 111(b) new source standard is predicated.21

See 80 FR 64573-74. Indeed, the plant’s capture amount would have comfortably satisfied the 

standard for a plant with five times the volume of CO2 emissions (i.e., a 500 MW SCPC plant).22

From February 2015 through January 2016, the plant captured 625,000 tons of CO2, a capture 

 

14 Letter of January 20, 2016, from SaskPower CEO Mike Marsh to EPA Administrator Gina McCarthy, 

p. 1.

15 “In some months routine maintenance and inspection is planned and in other months, such as January, 

the facility can be operated nearly 100 per cent of the time. Over a year, we expect the facility to be up 

and running approximately 85 percent of the time... It allowed us to capture and sequester a record 

84,976 tonnes of carbon dioxide. We continue to target the capture of 800,000 tonnes this year.” 

SaskPower Report January 2016 posted at http://www.saskpower.com/about-us/blog/bd3-status-updatejanuary-2016/.

16 Email from Mr. Mike Monea (SaskPower) to Dr. Nick Hutson (EPA), Feb. 2, 2016; UARG Petition 

Exh. B.

17 SaskPower Report March 2016 posted at http://www.saskpower.com/about-us/blog/bd3-status-updatemarch-2016/.

18 Letter from Saskpower CEO Mike Marsh to Administrator Gina McCarthy, Nov. 17, 2015 p. 1; Letter 

from Saskpower CEO Mike Marsh to Administrator Gina McCarthy, Jan. 20, 2016 p. 1; email of 

February 2, 2016; see also the chart in UARG Petition Exh. H and Exh. J p. 2-3 showing individual days 

where the plant achieved a 90 percent capture rate. Boundary Dam conducted its most recent nameplate 

testing in December, 2015.

19 SaskPower Report January 2016 posted at http://www.saskpower.com/about-us/blog/bd3-status-updatejanuary-2016/.

20 The system is designed to capture 1 million tons of CO2 per year. UARG Petition Exh. D; see also id. 

Exh. B, D, E p. 2, and G (all noting 400,000 tons of CO2 captured in the initial year of operation), and 

Exh. C and D (noting 40% + capture rate in initial year of operation).

21 Letter of January 20, 2016, from CEO Mike Marsh to Administrator McCarthy p. 1; see also Exh. B, D, 

E (p. 2), H (p. 1 of 4), and J (p. 2-3) of UARG’s petition, all of which likewise show that Boundary Dam 

has recovered more CO2 over its initial 12 months of operation than would be required under the CAA 

section 111(b) NSPS.

22 See Table 12 of preamble to final rule (80 FR 64574) showing capture of 354,000 tons of CO2 annually 

would be required for a 500 MW SCPC plant to meet the promulgated standard. 
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rate exceeding 60 percent, which is, as noted, well in excess of what the NSPS requires 

(notwithstanding downtime for the system in June, September, and October).23 The initial

capture rates for the months immediately following the two month maintenance period also 

greatly exceed those on which the NSPS are predicated, as does the plant’s projected 2016 

capture rate.24 

Equally important is that the plant’s initial operational issues appear to be resolved, and 

that most of these operational issues were related, in any case, to ancillary systems at the plant, 

not to the carbon capture system. The unit’s operation also bears out the EPA’s prediction that 

the 12-month averaging period is “forgiving” and accommodates significant operational 

variability. 80 FR 64573 (12-month averaging period is “very forgiving of short-term excursions 

that can be associated with non-routine events such as start-ups”); Achievability TSD (July 31, 

2015) at pp. 1-2 (similar finding). 

Importantly, the carbon capture system at BD3 is a retrofit to an existing unit, which 

poses special complexities and difficulties that a new source would not experience.25 One can 

reasonably assume that future plants will benefit from BD3’s operational and startup experience, 

and need not encounter the same issues. See 80 FR 64565-66. BD3’s carbon capture operations 

remain transparent to the general public with SaskPower providing regular updates on plant 

performance that are posted on their website www.saskpower.com (listed as “BD3 Update” on 

the site). In addition, SaskPower and BHP Billiton have established the “Carbon Capture and 

Storage Knowledge Centre” to help advance CCS as a means of managing greenhouse gas 

emissions.26 SaskPower is also helping advance CCS knowledge and technology through the 

creation of the Shand Carbon Capture Test Facility (CCTF).27 The CCTF provides technology 

developers with an opportunity to test new and emerging carbon capture systems for controlling 

carbon emissions from coal-fired power plants.

Although BD3’s early operational issues reduced the volume of CO2 it was able to 

deliver for EOR, because it has resolved those issues, it now “satisfies the volume needs of our 

carbon dioxide buyer,” and, since November 2015, is generating more CO2 than specified by 

 

23 http://www.saskpower.com/about-us/blog/bd3-status-update-january-2016.

24 The unit has also achieved the more stringent Canadian emission limitation of 420 kg CO2/MWh (926 

lb CO2/MWh) per calendar year. Email from Mr. Mike Monea (SaskPower) to Dr. Nick Hutson (EPA), 

Feb. 2, 2016.

25 See 80 FR 64551 (“In fact, retrofit of [CCS] technology at an existing unit can be more challenging 

than incorporating the technology into the design of a new facility”); id, at 64557 (“Much has been 

written about the complexities of adding CCS systems to fossil fuel-fired power plants. Some commenters 

argued that the EPA minimized – or even ignored – these publicly-voiced concerns in the discussion 

presented in the ... proposal. On the contrary, the EPA has not minimized or ignored these complexities, 

but it is important to realize that most of these statements come in a different context: [n]amely, 

implementing full CCS, or retrofitting CCS onto existing power plants”); see also Comment Response 

6.3-47 (special difficulties experienced by American Electric Power Mountaineer project due to it being a 

retrofit to an existing facility) and response B infra (response to petition of American Electric Power). 

26 http://www.bhpbilliton.com/investors/news/bhp-billiton-and-saskpower-establish-carbon-capture-andstorage-knowledge-centre.

27 http://saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
- 11 -

contract.28 The company indicates that revenues from EOR will exceed any contract penalties for 

the 2015 operating year.29 Moreover, some of the foregone revenue resulted from BD3 

generating more CO2 in its initial months of operation than the EOR buyer could 

accommodate.30

The petition likewise quotes SaskPower CEO Mike Marsh as stating “we need a year of 

stable operation near maximum performance to really test the technology and commercial 

viability going forward”. (UARG Petition Exh. I, p. 1.) The statement is in the context of 

whether to retrofit full-scale CCS on the company’s fleet of coal boilers, and thus of minimal 

relevance in deciding here whether to reconsider a standard reflecting performance of partial 

capture of CO2 by a newly constructed source. In addition, there is no requirement under the Act 

or in case law that a technology operate for any given period before it can be considered to be 

adequately demonstrated, and, in fact, under certain circumstances, the EPA may determine that 

a technology is adequately demonstrated even before it begins to operate. Moreover, SaskPower 

evidently views the carbon capture technology as operating successfully, as shown by its public 

letters and statements, which are part of the record here. Furthermore, as noted in the final rule,

the BD3 project is only one of the examples of post-combustion capture that the agency relied on 

in its determination that post-combustion partial CCS has been adequately demonstrated. See 80 

FR 64548.

In any case, the quote from CEO Marsh relates to SaskPower’s decision about whether or 

not to retrofit additional coal-fired units with CCS technology. As the EPA noted in both the 

proposed and final CAA 111(b) standards, coal-fired units currently face tremendous competitive 

pressure from other generation options – especially from natural gas-fired combustion turbines 

and renewable energy sources. See, e.g., 80 FR 64558-59 and 64641-42; see generally RIA 

chapter 4. SaskPower is faced with a requirement to either retire its aging fleet of coal-fired 

boilers or retrofit them with CCS technology (in order to meet the Canadian emission standard). 

Given these options, it certainly makes sense that the company would allow the BD3 system to 

operate for some time so that the company can “really test” not just the performance of the 

technology, but also the commercial viability of retrofitting its fleet of coal-fired boilers with the 

CCS system vis-à-vis other investment options for generating electricity.

The petition also suggests that BD3’s failure to operate at a day-to-day 90 percent capture 

rate shows the technology is not operating reliably because the plant system is designed to 

achieve a 90 percent capture rate. See, e.g., UARG Pet. Exh J pp. 2-2 to 2-3. The EPA disagrees. 

The plant has, in fact, achieved 90 percent capture when doing nameplate testing (i.e., pushing 

the technology to its design limit) and has operated at capture rates exceeding even its 90 percent 

design level, but the more important point is that the plant has operated and is operating reliably, 

and is now providing more CO2 monthly than required by contract. It is meeting the Canadian 

 

28 Letter from Saskpower CEO Mike Marsh to Administrator Gina McCarthy, Jan. 20, 2016 p. 1. 

29 Memorandum of conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), 

February 2, 2016; UARG Petition Exh. D p. 3. 

30 Email from Mr. Mike Monea (SaskPower) to Dr. Nick Hutson (EPA), Feb. 20, 2015 (EPA-HQ-OAR2013-0495-11699) (“We are running about 75% capture, roughly 2,600 tonnes/d of 99.999% CO2. 

Cenovus Energy is phasing in our CO2 so we will have five months of lower sales for EOR to Cenovus.”); 

see also UARG Pet. Exh. D p. 2 (“In some of the months, it was running more efficient than Cenovus 

would take”).
- 12 -

CO2 emission standards (which are more stringent than the NSPS at issue here). Even more 

basically, operational ‘hiccups’ in an initial year of operation are to be expected (see e.g., 79 FR 

1482 (Jan. 14, 2014)), and do not, by themselves, show that a control technology is infeasible, or 

otherwise not demonstrated. The EPA believes that is the case here where plant managers and 

executives indicate that the operational problems involved are resolved (and, for the most part, 

were not attributable to the carbon capture system itself), and the plant is operating on a highly 

successful upward trajectory. 

The EPA thus is denying this aspect of the petition as not showing that the objection is of 

central relevance to the outcome of the rulemaking. As just noted, the EPA did not project that 

plants would operate CCS without experiencing some initial operational issues,31 and established 

a standard with an extended averaging time to provide an ample compliance margin. See 79 FR 

1481; 80 FR 64573. BD3 is operating successfully, and has demonstrated that it can achieve

capture rates well in excess of its contractual obligations, as well as sufficient to achieve 

compliance with the (more stringent) Canadian CO2 emission standard. More importantly, the 

retrofit carbon capture system at BD3 has demonstrated the ability to achieve carbon capture 

rates, over an extended averaging time, that are far in excess of the capture rates needed to 

comply with the standard established by the EPA for new steam generating EGUs under the 

subject rulemaking. The EPA thus believes that Boundary Dam’s performance corroborates 

rather than undermines a finding that partial CCS is an adequately demonstrated technology, 

within the meaning of section 111(b) of the Act. 

2. Use of NETL (2015) Cost Estimates/Cost of Shell Cansolv Carbon Capture Technology

UARG also maintains that BD3 uses the Shell Cansolv carbon capture process, that the 

Cansolv process served as the basis for cost estimates from a National Energy Technology 

Laboratory (NETL) study that was issued in June 2015 (after the comment period), and that 

those cost estimates do not (and could not) reflect cost overruns experienced by BD3. More 

generally, UARG states that the EPA based its cost estimates for carbon capture at proposal on a 

different carbon capture technology, and maintains broadly that the public lacked opportunity to 

comment on the 2015 NETL cost estimates. UARG Petition pp. 7-8. None of these contentions 

justify reconsideration, and the EPA is accordingly denying this part of the petition.

It is well settled that agencies may rely on studies not subjected to notice and comment 

where those studies serve as additional support for the data and conclusions in a proposal, 

particularly where there is no change to the methodology by which the information is developed 

and assessed. See, e.g., Chamber of Commerce v. SEC, 443 F. 3d 890, 900 (D.C. Cir. 2006) 

(“further notice and comment are not required when additional fact gathering merely 

supplements information in the rulemaking record by checking or confirming prior assessments 

without changing methodology” (citing Solite v. EPA, 952 F.2d 473, 485 (D.C. Cir. 1991)). 

There was no methodological change here. The 2015 NETL report was an update (listed as 

“Revision 3”) of the studies that the EPA used at proposal. As is further explained below, all of 

these updates use the same basic methodology (e.g., a component-by-component cost evaluation 

of a post-combustion CCS system with the same key financial assumptions). The EPA used the 

 

31 See, e.g., 79 FR 1482 (noting that a potential 84-month averaging time “offers increased operational 

flexibility and will tend to compensate for short-term emission excursions, which may especially occur at 

initial startup of the facility and the CCS system”).
- 13 -

NETL studies to derive the cost estimates presented in the proposal and then used the updated 

NETL studies to derive cost estimates for the final standards. The EPA then, as at proposal,

compared those estimates to the cost of non-fossil fuel-fired electricity generating technologies, 

in particular technologies providing baseload dispatchable power, using the Levelized Cost of 

Electricity (LCOE) metric. Compare 79 FR 1475-78 and 80 FR 64560-563. As at proposal, 

carbon capture is considered to be a technology with cost estimates reflecting a next commercial 

offering (or next-of-a-kind) of the technology.

32 As at proposal, the updated study remains a 

Class 4 feasibility study, with cost estimates presented with the same range (-15 to +30 percent

uncertainty on the capital cost).33 Consistent with earlier studies, the updated NETL study 

assumes high-risk financing for the carbon capture system.34 There is the same level of 

transparency in each study, based on identical overall methodology for assessing and presenting 

costs for each operating system.

The 2015 NETL cost information supplements and corroborates information used at 

proposal. First, UARG is not correct in stating that the EPA considered a different carbon 

capture technology in its cost estimates for the final rule as compared to the one it used at 

proposal. For both the proposed and final standards, the EPA’s cost estimates were for a new,

highly efficient, coal-fired boiler implementing partial post-combustion CCS through the use of 

an amine-based capture system which scrubs CO2 from a slip stream of the post-combustion flue 

gas. The CCS capture system (i.e., the equipment) was the same in both studies – only the 

solvents differ.35 In the proposed action, the NETL studies that served as the basis for those costs 

assumed that the post-combustion CCS system used the Fluor Econamine solvent.36 For the final 

action, the EPA relied on updated NETL studies that assumed the use of the Shell Cansolv 

solvent.37 The Shell Cansolv amine solvent was used in the updated studies because it is the 

better performing solvent.38 As it happens, BD3 uses the Cansolv solvent in its carbon capture 

system.

 

32 79 FR 1476; Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal 

(PC) and Natural Gas to Electricity Revision 3”, DOE/NETL-2015/1723 (July 6, 2015) (“NETL 2015”) 

(EPA-HQ-OAR-2013-0495-11341 (“NETL 2015”), p. 38.

33 Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, Revision 1, 

DOE/NETL-2011/1498 (“NETL 2013”)(EPA-HQ-OAR-2013-0495-11635) p. 37; 80 FR 64567.

34 NETL 2015 p.17, Exh. ES-4; see also NETL 2013 pp. 41-42.

35 Each study evaluates (individual component by individual component) the following systems: coal 

sorbent handling, coal preparation and feed, feedwater, boiler and accessories, flue gas cleanup, CO2

recovery, ducting and stack, steam turbine generator and auxiliaries, cooling water, accessory electric 

plant, and ash and spent sorbent recovery and handling. See NETL 2013 pp. 109-115; NETL 2015 pp. 

103-108. 

36 NETL 2013 pp. 65-69 (EPA-HQ-OAR-2013-0495-11635). 

37 “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate 

in Coal-Fired Power Plants” DOE/NETL-2015/1720, pp. 6-7 (EPA-HQ-OAR-2013-0495-11661); NETL 

2015 pp. 59-68.

38 In addition, in considering the updated studies, the EPA was responding to comments, including from 

Petitioner UARG, urging the EPA to consider costs reflecting actual operation of carbon capture. See 80 

FR 64567 (“[t]he EPA used this latest version of the NETL studies not only to assure that it considers the 

most up-to-date information but also to address public comments criticizing the proposal for relying on 

out-of-date information”). This fact further obviates the Petitioner’s notice and comment concerns. See 
- 14 -

Also, as shown in Figure 1 below, the overall estimated costs for the partial CO2 capture 

system in the 2015 updated NETL study (presented as the percent increase in cost of the system 

over an uncontrolled (i.e., no carbon capture) baseline) are virtually identical to those at proposal 

for the same post-combustion capture system using a different solvent.39 See also 80 FR 64567-

69 (other studies and industry information which corroborate NETL cost estimates for CCS). 

Under these circumstances, the EPA was not obligated to re-notice the cost estimates, or the 

NETL report itself.

Figure 1. Comparison of Percent Increase in LCOE from Proposal (Econamine solvent) 

and Final (Cansolv solvent)40

UARG nonetheless maintains that these estimated costs don’t reflect costs actually 

experienced by BD3. However, as explained earlier in Section III.A.1, the UARG petition 

greatly exaggerates the degree of BD3’s performance difficulties. Moreover, as also explained 

 

Chemical Manufacturers Ass’n v. EPA, 870 F. 2d 177, 201-02 (5th Cir. 1989) (no further notice and 

opportunity for comment required where “[t]he EPA did not supplant its economic-impact study, or 

replace its original data with completely new and different data, but, in response to industry criticisms, 

updated and expanded one of several data sources”); see also Community Nutrition Inst. v. Block, 749 F. 

2d 58 (D.C. Cir. 1984) (“Rulemaking proceedings would never end if an agency's response to comments 

must always be made the subject of additional comments”, and this response can take the form of further 

corroborative scientific studies without triggering a new round of notice and comment) (Scalia, J.).

39 These cost estimates reflect updated estimates for certain common costs between the two technologies, 

notably labor and material costs.

40 Exhibit ES-14 from NETL 2013 ( “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture,” Rev 1 (September 19, 2013)), DOE/NETL-2011/1498; and Exhibit A-3 from 

“Cost and Performance Baseline for Fossil Energy Plants Supplement:

Sensitivity to CO2 Capture Rate in Coal-Fired Power Plants” (June 22, 2015), DOE/NETL-2015/1720 

(EPA-HQ-OAR-2013-0495-11661). 

0

10

20

30

40

50

60

70

80

90

0 2 0 4 0 6 0 8 0 100 120

% Increase in LCOE over Uncontrolled

% CO2 Captured

Econamine

Cansolv
- 15 -

above, most of those performance issues relate to ancillary equipment and systems other than 

those specifically for carbon capture. These are facility-specific issues (e.g., cracks in the amine 

storage tank) which need not be assumed to be generally applicable. Moreover, the EPA 

evaluated cost estimates as a range (consistent with the NETL methodology), so that the capital 

costs could range up to 30 percent higher. 80 FR 64567. The cost estimates that the EPA used in 

the rule thus account for some measure of potential cost increases.

UARG made particular note of the carbon capture system not capturing sufficient CO2

for BD3 to meet its contractual obligations, incurring financial penalties and lost revenues as a 

result. See UARG Petition p. 7. Any costs incurred by SaskPower related to EOR are irrelevant 

here since the EPA’s cost estimates assume geologic sequestration of the captured CO2 rather 

than use in EOR operations. 80 FR 64564/2. In any case, UARG exaggerates the extent of 

SaskPower’s difficulties. As again noted above, the company expects to show a profit, even in 

the short-term, from sales of CO2 and is presently not only meeting its contractual targets but 

actually generating more CO2 than the EOR operator can accommodate.41 Under these 

circumstances, UARG’s information is not of central relevance to the outcome of the rulemaking 

since it would not affect the rulemaking’s result. 

3. Performance Baseline from Which Carbon Capture Is Measured

UARG maintains that the EPA failed to give notice of the uncontrolled baseline emission 

rate (i.e., the emission rate of an uncontrolled coal-fired boiler) used as the starting point for 

calculating percent of partial carbon capture needed to meet a standard which is demonstrated at 

reasonable cost. UARG Petition p. 9 (“The proposed GHG NSPS did not in any way address the 

baseline emission rate for new SCPC units or analyze the proposed standard’s achievability for 

such units”). Consequently, UARG asserts that it was necessarily impractical to address this 

issue in comments on the rulemaking, and that the EPA must grant reconsideration to afford 

opportunity for comment.

UARG’s contention is mistaken. At proposal, the EPA indicated that “[a]ccording to the 

DOE NETL estimates, ... a new SCPC unit using bituminous coal would emit nearly 1,700 lb 

CO2/MWh ....”). 79 FR 1468. “SCPC” is an acronym for “supercritical pulverized coal.” The 

exact baseline value used by the EPA at proposal for a supercritical PC boiler using bituminous 

coal was 1,675 lb CO2/MWh.42 In addition, the EPA recognized that “[t]he emissions would be 

higher for units utilizing subbituminous coal or lignite ...” 79 FR 1471. The EPA proposed that

“highly efficient new generation with partial capture CCS” is the BSER for new fossil fuel-fired 

boilers and then estimated the cost of applying partial CCS to such a boiler emitting at the

proposed emission level. See 79 FR 1476 (Table 6). The EPA then determined in the final rule

that an “efficient new supercritical pulverized coal (SCPC) utility boiler implementing partial 

 

41 Memorandum of conversation between Dr. Nick Hutson (EPA) and Mr. Mike Monea (SaskPower), 

February 2, 2016; Pet. Exh. G p. 3.

42 Exhibit ES-2 from “Cost and performance Baseline for Fossil Energy Plants Vol. 1: Bituminous Coal 

and natural Gas to Electricity,” Revision 2, Report DOE/NETL-2010/1397 (Nov. 2010). The EPA cited 

to this source when presenting the baseline value (“nearly 1,700 lb CO2 MWh”) in the preamble to the 

proposed rule. 79 FR 1468 n. 178. We discuss below why an ultra-supercritical PC boiler may also be 

referred to as a “highly efficient supercritical pulverized coal (SCPC)” boiler.
- 16 -

carbon capture and storage (CCS)” is the BSER for such units and calculated the cost of applying 

CCS to such a boiler in the same way as at proposal.

The baseline values used by the EPA for the final rule were very similar to the value used 

at proposal: 1,620 lb CO2/MWh (for bituminous coal) and 1,737 lb CO2/MWh (for low rank

coal). Final Preamble Tables 8 and 9; Achievability TSD Table 2.43 Moreover, the proposed and 

final rule use the same methodology to estimate a baseline emission rate. For both the proposed 

and the final rule, the EPA used baseline estimates drawn from the DOE/NETL “cost and 

performance” studies for an efficient supercritical PC boiler. Emission estimates for units 

burning low rank coal were from the original (2011) “Volume 3b: Low Rank Coal to Electricity” 

report. Emission estimates for units burning bituminous coal were from the original (2011) 

“Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity” report for the proposal, while 

the emissions at final were from the updated (2015) version of that report. And, as at proposal, 

EPA estimated costs for applying partial CCS to a boiler emitting at the specified emission rate. 

80 FR 64562 and Table 8.

The EPA thus fully presented all information necessary for comment on this issue at 

proposal. Specifically, the EPA gave notice of the potential level of performance for a highly 

efficient, uncontrolled supercritical boiler. Indeed, the EPA received a great deal of public 

comment on performance of highly efficient boilers without CCS, including quantification of 

potential levels of performance, confirming that the proposal provided ample notice of the 

issue.

44 The petition consequently fails to demonstrate that it was impractical to comment on this 

issue during the rulemaking.

UARG also fails to demonstrate that the issue it raises is of central relevance to the 

outcome of the rulemaking. UARG maintains that the baseline is not achieved in practice even 

by the two best performing plants, the Longview and Turk plants. As a result, according to 

UARG, the EPA has improperly estimated the rule’s costs since a plant with a higher 

uncontrolled baseline emission would require a higher level (i.e., a greater percentage) of partial 

carbon capture in order to meet the emission standard than the level predicted (and costed) by 

EPA in the final rule. Therefore, UARG claims that the level of the standard must be adjusted 

accordingly to be less stringent in order to stay within the cost level that the EPA has deemed to 

be reasonable. Pet. pp. 11-14.

The EPA disagrees with this assessment. First, as the EPA showed in the Achievability 

TSD, the Turk plant’s best monthly rate (1,725 lb CO2/MWh) was actually better than the EPA’s 

assumed uncontrolled emission rate (1,737 lb CO2/MWh). Achievability TSD p. 6. The plant’s 

best 12-month average rate (1,753 lb CO2/MWh) was only slightly higher (by less than 1 

percent) than the EPA’s assumed uncontrolled emission rate. Id. And the plant’s worst 12-month 

average rate (1,817 lb CO2/MWh) was only 4.6 percent higher than the EPA’s estimated 

 

43 There is a typographical error in the final preamble at 80 FR 64594/3, stating “1,720” instead of the 

correct “1,620”.

44 See RTC comment 6.3-423; see generally id. at comments 6.3-410 through 6.3-424 and 80 FR 64594-

95; see also cases cited at n. 39 above, and National Association of Manufacturers v. EPA, 750 F. 3d 921, 

926 (D.C. Cir. 2014) (notice adequate where petitioners’ comments show that they “had no problem 

understanding the scope of the issues up for consideration”).
- 17 -

uncontrolled emission rate. Id. The Longview Power plant was identified as the best performing 

supercritical PC plant burning bituminous coal. Id. The best 12-operating-month average rate for 

the plant was only 1.9 percent higher than the EPA’s assumed uncontrolled baseline. The highest 

12-operating-month average for the Longview Power plant was about 11 percent higher than the 

EPA’s assumed uncontrolled emission – but the Longview Power plant utilizes different steam 

conditions from those assumed by NETL in the cost and performance report used by the EPA. Id. 

As the EPA found, newly constructed, properly operated, and well maintained bituminous-fired 

plants that do incorporate the more efficient ultra-supercritical technology would expect to 

achieve better performance than the Longview Power plant – performance that is consistent with 

the baseline emissions assumed by the EPA. Id.

Further, even assuming that an ultra-supercritical plant (like Turk) could not make 

modest performance improvements to continue to match its documented monthly performance, 

the costs of meeting the standards with a slightly increased rate of CO2 capture would continue to 

be reasonable. In order to assure that the final standard could be met without imposing 

unreasonable or exorbitant costs, the EPA finalized a standard with projected costs that are 

within the range of costs for other non-NGCC generation base load, dispatchable options. 80 FR 

64566-567 (explaining why this is a reasonable comparison). Specifically, the EPA finalized a 

standard with projected costs that are similar in range to a new nuclear unit. The costs for a new 

highly efficient SCPC EGU emitting at 1,620 lb CO2/MWh (bituminous coal) and at 1,737 lb 

CO2/MWh (low rank coal) with partial capture meeting a standard of 1,400 lb CO2/MWh are

projected to be $92 – $117 per MWh for a plant burning bituminous coal and to be $95 - $121 

per MWh for a plant burning low rank coal. 80 FR 64562, Table 8. These projected costs are 

well within the ranges projected for a new nuclear unit – estimated to be $87 - $115 per MWh by 

EIA and estimated to be $92 - $132 per MWh by Lazard. Id. Small changes in the amount of 

CO2 that must be captured to meet the final standard would result in small increases in cost, but 

would still be within the range of costs for a new nuclear plant.45

To show this, the EPA evaluated the cost of a new highly-efficient SCPC plant utilizing 

low rank coal to meet the final standard of performance of 1,400 lb CO2/MWh-g by 

implementing partial CCS. The baseline for such a new plant was assumed to range from 1,753 

lb CO2/MWh-g to 1,817 lb CO2/MWh-g, a range consistent with the Turk facility’s “best 12-

month average” emission rate and its “worst (or highest) 12-month average emission rate”. A 

comparison of the baseline emission rates and the CCS control levels required to meet the 1,400 

lb CO2/MWh-g standard for the examples used in the final rule as well as for the range of 

performance for a unit consistent with those exhibited by Turk is shown in Figure 2 below.46

 

45 Indeed, as shown in the following Section IV.A.4, even using the cost estimates in UARG Petition 

Exhibit J developed using their alternative methodology regarding scaling, which increases estimated 

costs, estimated costs remain within the range of the Lazard cost estimates for a new nuclear plant 

presented in preamble Table 8.

46 This figure essentially adds a new highly efficient SCPC with Turk’s “best 12-month average” and with 

Turk’s “worst 12-month average” baselines to Figure 1 from the Achievability TSD. It should be noted 

that the EPA mentioned the Turk facility at proposal as an example of an ultra-supercritical unit, 79 FR 

1468, further undercutting the Petitioner’s claims of inadequate notice.
- 18 -

Figure 2. Facility CO2 emission (lb CO2/MWh) versus CO2 partial capture (%)

As can be seen in Figure 2, the “SCPC at 1,753 lb CO2/MWh-g” (consistent with Turk’s 

best 12-month average) capture line is essentially the same as the model plant highly efficient 

SCPC using low rank coal that was estimated in the final rule - requiring about 23 percent

capture to meet the 1,400 lb CO2/MWh-g standard. A new plant exhibiting an emission level of 

1,817 lb CO2/MWh-g (equivalent to Turk’s highest (or worst) 12-month average) would require 

about 27 percent capture to meet the 1,400 lb CO2/MWh standard. This information is 

summarized in Table 1 below.

This Table (which updates Table 2 from the Achievability TSD to include additional 

information relative to the performance of the Turk facility) shows that a new facility with 

baseline emissions consistent with Turk’s poorest performing 12-month average would have 

required approximately 27 percent partial capture to meet the 1,400 lb CO2/MWh-g standard and 

the cost of a capture system to achieve that capture level would range from $98 - 125/MWh, 

which is in the range of projected cost for new nuclear (EIA at $87 - $115/MWh and Lazard at 

$92 - $132/MWh).

47 Similarly, if the highly efficient new SCPC EGU emitting at 1,620 lb 

CO2/MWh were to experience a higher than predicted emission rate consistent with the Turk 

“worst 12-month average” (i.e., + 5 percent), the unit, with an uncontrolled emission of 1,700 lb 

CO2/MWh, would require less capture than the 23 percent that was costed for the new unit using 

 

47 The range of Turk’s emission rates (from the best to the worst), coupled with the use of the 12-month 

rolling average compliance period, cover the range of conditions that new plants may be expected to face. 

See Achievability TSD, at pp. 1-2 (EPA-HQ-OAR-2013-0495-11771).

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

0% 10% 20% 30% 40% 50%

Emission, lb/MWh-g

Carbon Capture, %

Highly Eff SCPC (1,620, bit)

Highly Eff SCPC (1,737, low rank)

Highly Eff SCPC (1,753, low rank)

Highly Eff SCPC (1,817, low rank)
- 19 -

low rank coal (and certainly less than the 27 percent capture costed in the Table above for a new 

unit with the Turk “worst 12-month average” performance).48,49

Table 1. Predicted Cost and CO2 Emission Levels for a Range of Potential New Generation 

Technologies 

New Generation Emission LCOE

Technology lb CO2/MWh-g $/MWh

SCPC - no CCS (bit) 1,620 76 - 95

SCPC - no CCS (low rank) 1,740 75 - 94

SCPC - no CCS (low rank) – consistent with Turk’s

best 12-month average

1,753 75 - 94

SCPC - no CCS (low rank) – consistent with Turk’s

worst 12-month average

1,817 75 - 94

SCPC + ~16% CCS (bit) 1,400 87 - 115

SCPC + ~23% CCS (low rank) 1,400 95 - 121

SCPC + ~27% partial CCS (low rank) 1,400 98 - 125

Nuclear (EIA) 0 87 - 115

Nuclear (Lazard) 0 92 - 132

Biomass (EIA) 0 94 - 113

Biomass (Lazard) 0 97 - 116

IGCC 1,430 94 - 120

NGCC 1,000 52 - 86

 

48 The UARG Petition also states that the EPA cost estimates should have included costs for a design (or 

compliance) margin, since plants are typically designed to perform below the level of a standard to 

account for performance variability. UARG Petition p. 11; the same point appears in the Petition of the 

State of Wisconsin at p. 4. The EPA cost estimates already are evaluated as a range and so could be up to 

30 percent higher. 80 FR 64567. Including costs for a design margin (if needed) on top of this range 

would be overly conservative, effectively double counting costs. The 12-month averaging period also 

accounts for process variability. Id. at 64573.

49 UARG quotes the 2015 NETL study as stating, “Actual average annual emissions from operating plants 

are likely to be higher than the design emissions rates shown due to start-up, shutdown, part-load 

operation, and performance degradation through maintenance cycles.” UARG Petition p. 11 (quoting 

NETL (2015), p. 1). The cost analysis just discussed makes clear that plants can adjust to higher baseline 

emissions by capturing greater amounts of CO2, but without significantly increasing costs, and, as a 

result, remaining within the range of overall costs that the EPA determined to be reasonable. The 2015 

NETL study quoted by UARG went on make a similar point. See NETL (2015), p. 1 (stating that meeting 

a required CO2 emission limit by adjusting for increased emission rates due to, e.g., performance 

degradation through maintenance cycles, “does not have major cost implications,” except for plants with 

“low capture rates.” Because the control costs in the NETL study increase linearly starting with capture 

rates at 16 percent and higher, “low capture rates” below 16 percent are not relevant for this rulemaking.
- 20 -

UARG also overstates when it maintains that the level of carbon capture on which the 

rule is predicated is EPA’s absolute measure of what is cost-effective for the standard. UARG 

Petition p. 9. In fact, the only costs the EPA did not determine would be reasonable were for full 

CCS (for either a PC or IGCC unit), and this was because estimated costs “are predicted to 

substantially exceed the costs for other dispatchable non-NGCC generating options that are being 

considered by utilities and developers”. 80 FR 64596 (emphasis added); see also the similar 

finding at 79 FR 1477. In contrast, capturing an additional small increment (one to four percent)

of CO2 emissions would not result in costs that substantially exceed the other non-NGCC 

baseload, dispatchable technologies. Indeed, as just shown, the costs of such additional capture 

would remain within the same range as the cost of new nuclear generating technology.

Moreover, the plant would have the ready option of co-firing a small amount of natural gas 

rather than increasing the rate of CO2 capture, and thus incur virtually no increased cost. See 80 

FR 64564-65. Finally, as noted in the final rule, the EPA expects, in most cases, that utilities and 

project developers who choose to construct a new coal-fired generating sources, will do so, at 

least in part, because of revenue opportunities from the sale of captured CO2. This potential 

revenue was not factored into the EPA’s primary cost analysis and, therefore the costs presented 

in Table 1 above are likely to be conservative. See 80 FR 64563.

In addition, UARG claimed that it is “nonsensical” for the EPA to base its analysis for

supercritical boilers combusting low rank coal on projections for ultra-supercritical boilers 

combusting subbituminous coal. Petition p. 11. This objection is purely semantic, and without 

substance. As the EPA explained at proposal, supercritical coal-fired boilers are designed and 

operated with a steam cycle above the critical point of water. Any boiler that operates above the 

critical point of water is a supercritical boiler. 79 FR 1468 n. 176. Ultra-supercritical (USC) is a 

term used to designate a coal-fired power plant design with steam conditions well above the 

critical point. Id. n. 182. The EPA proposed that “highly efficient new generation with partial 

capture CCS” is the BSER for new fossil fuel-fired boilers and then finalized that an “efficient 

new supercritical pulverized coal (SCPC) utility boiler implementing partial carbon capture and 

storage (CCS)” is the BSER for such units. Subcritical boilers operate using steam conditions 

below the thermodynamic critical point of water and supercritical boilers operate using steam 

conditions above the critical point of water. Adjectives such as “ultra” or “advanced” are used to 

describe SCPC units that are more advanced or more efficient than units operating with steam 

conditions that are just slightly above the thermodynamic critical point. In other words, an ultrasupercritical PC boiler may also be referred to as a “highly efficient supercritical pulverized coal 

(SCPC)” boiler.

More important, the issue is not the nomenclature used to describe the highly efficient 

SCPC boiler, but the quantified level of emissions assumed. As shown above, the level proposed 

and the level used in the final rule are roughly the same, were developed using the same 

methodology, and are reasonable. Neither UARG’s notice issue nor its semantic objections 

justify reconsideration.

UARG also claimed that it is arbitrary for the EPA to use baseline emission rates for units 

burning subbituminous rather than lignite coal to represent the emissions performance of low 
- 21 -

rank coals generally. (UARG Pet. at 12) They further noted that, although the EPA grouped these 

coal types together as “low rank” and treated them identically, the CO2 emissions of EGUs 

combusting lignite are substantially different from those of EGUs combusting subbituminous 

coal and, therefore lignite units would need to capture a greater share of CO2 emissions, at 

greater cost, to meet the final standard of 1,400 lb CO2/MWh-g.

The EPA agrees that the CO2 emissions of EGUs combusting lignite are different from 

those of EGUs combusting subbituminous coal. However, the EPA disagrees that a new EGU 

utilizing lignite would need to capture a greater share of CO2 emissions at greater cost to meet 

the final standard of 1,400 lb CO2/MWh-g because the emissions from units burning subbituminous coal and dried lignite are very similar. In the final rule, as UARG noted, the EPA 

very specifically referred to sub-bituminous and dried lignite as “low rank” coal. See, e.g., 80 FR 

64513 (“A newly constructed, highly efficient SCPC utility boiler burning subbituminous coal or 

dried lignite will be able to meet this final standard of performance by capturing and storing 

approximately 23 percent of the CO2 produced from the facility.”) (emphasis added). UARG 

contends that lignite drying technologies “are not sufficiently developed or commercially 

available to provide a viable CO2 control option” (UARG Petition, Exhibit J at 3-1) and 

referenced a 2014 analysis prepared by the National Coal Council (NCC)50. The EPA disagrees. 

In fact, the cited reference supports the EPA’s approach. The NCC report states that “[c]oal 

drying with waste heat is a commercially available option, but one that not every plant can 

effectively deploy. [...] Less improvement would be expected for drying higher coal ranks ... 

because they tend to be much lower in moisture content than lignite.” (NCC report at 59, 

emphasis added) The NCC was essentially concluding that coal drying is a commercially 

available option for lignite, but is not likely effective for higher rank coals because of the lower 

moisture content. But, the EPA only identified coal drying for use with lignite – not with subbituminous or bituminous coals.

While it is difficult, if not impossible, to find real world examples that fully isolate the 

impact of burning subbituminous versus dried or undried lignite (because other variables 

including boiler design impact those rates), current emission data confirm the reasonableness of 

the EPA’s approach. Great River Energy has utilized lignite drying at its Coal Creek (North 

Dakota) plant with average 2015 emission rates of 2,145 lb CO2/MWh-g and 2,100 lb 

CO2/MWh-g for its units #1 and #2, respectively. These emissions are very similar to those from 

the sub-bituminous fired units at Colstrip (Montana) that had 2015 emission rates of 2,090 lb 

CO2/MWh-g and 2,115 lb CO2/MWh-g at its units #3 and #4, respectively. In contrast, emission 

rates in 2015 from a plant burning non-dried lignite, the Antelope Valley (North Dakota) plant, 

were distinctly higher. It is clear that the emissions from the Coal Creek units are more similar to 

those from the sub-bituminous fired units at Colstrip (Montana).51

Finally, UARG claims that the pre-CCS emission baseline should be calculated from the 

performance of SCPC boilers (i.e., boilers not fully optimized for efficiency) rather than from the 

 

50 Reliable and Resilient: The Value of Our Existing Coal Fleet, prepared by the National Coal

Council (June 2014).

51 All emissions data are from the EPA’s Air Markets Program Data (AMPD) available at 

https://www.epa.gov/airmarkets. 
- 22 -

most efficient boilers like the Turk facility. UARG Petition pp. 11-12.52 This objection is 

mistaken, and therefore not of central relevance to the outcome of the rulemaking. The argument 

is that the EPA “may not focus solely on the best performing units to determine whether an 

NSPS is achievable”, and that to be achievable, the EPA must demonstrate that the standard can 

be met under the range of operating conditions that may reasonably occur. Id. p. 11. Of course a 

best system of emission reduction may reasonably reflect performance of optimized control 

technologies, and if one means of control results in lower emissions, the EPA may reasonably 

identify that system as a basis for BSER. See 80 FR 64539; see also Sierra Club v. Costle, 657 F. 

2d 298, 326 (D.C. Cir. 1981) (amount of emissions reduction is obviously relevant in 

determining a best system). Thus, the EPA may reasonably select as BSER a system that 

includes a type of boiler designed for optimized operating efficiency. 

4. Application of NETL Scaling Methodology

UARG claims that the EPA’s estimates of the capital cost of CCS are unreasonably low. 

UARG Petition pp. 14-17. Most of the argument reiterates points made in comments to the 

rulemaking, among them, that the EPA should have placed greater weight on capital costs in its 

analysis,

53 should have used costs of current projects rather than estimated costs, and should have 

assumed that new projects will incur ‘first-of-a kind’ costs rather than ‘nth–of-a-kind’. None of 

these issues are new, and all have been addressed by the EPA in the preamble to the final rule 

and in comment responses. See, e.g. 80 FR 64566-571. Since all of these objections can, and 

were, raised during the rulemaking, it was obviously practical to do so within the meaning of 

section 307(d)(7)(B). The EPA is accordingly not granting reconsideration on these objections.

UARG further objects to the methodology by which costs were scaled in the NETL 2015 

cost estimates. UARG contends that the estimated capital costs for implementing partial CCS are 

invalid because they claim that NETL misapplied cost scaling principles to extrapolate costs for 

partial capture from estimated costs for full capture.

 

52 It is evident that the ultra-supercritical technology is adequately demonstrated. It is deployed both 

domestically (the Turk plant), and internationally. See Comments of American Electric Power (EPA-HQOAR-2013-0495-10938) p. 117, documenting operation or construction of ultra-supercritical units in 

Poland, Germany, Malaysia, Japan, and Denmark from as early as 1998. Numerous commenters, among 

them petitioners here, urged its adoption as BSER (rather than partial CCS). Comments of UARG (EPAHQ-OAR-2013-0495-10938) pp. 69 and 77; Comments of American Electric Power (EPA-HQ-OAR2013-0495-10938) pp. 114-15; Comments of Alstom (EPA-HQ-OAR-2013-0495-9033) p. 6. The EPA 

received no significant adverse comment on its statement in the proposal that “[g]eneration technologies 

representing enhancements in operational efficiency (e.g., supercritical or ultra-supercritical coal-fired 

boilers or IGCC units) are clearly technically feasible....” 79 FR 1435.

53 The Petition states incorrectly that “[t]he proposed GHG NSPS did not address the capital cost of 

partial CCS” (UARG Petition p. 14). Estimated capital costs are presented in NETL 2011 at 8-9, 35-7, 

and then presented for all of the individual study cases at sections 4.2.5 and 4.2.6 and in NETL 2013 at 

pp. 8, 35-37, and 39 and then presented for all of the individual study cases in the report at section 3.2.4. 

In the proposal, the EPA relied on the levelized cost of electricity (LCOE) as the cost metric, and LCOE 

includes capital costs. 79 FR 1435 n. 9. Commenters urged the EPA to consider capital costs as a separate 

metric, and in the final rule, the EPA did so (along with continued analysis using the LCOE metric), and 

concluded that this capital cost metric also supported the EPA’s determination that the costs of partial 

CCS are reasonable. 80 FR 64559-60.
- 23 -

However, both EPA and NETL have clearly presented that the capital cost estimates 

documented in their reports reflect an uncertainty range of -15 percent to +30 percent - consistent 

with AACE Class 4 cost estimates (i.e., a feasibility study). The NETL cost estimates are 

intended to represent the next commercial offering, and relied on vendor cost estimates for 

component technologies. 

As part of the NETL partial CCS studies, it was necessary to estimate the cost of some 

lower capacity or “scaled down” carbon capture equipment when little or no cost data are 

available for such smaller equipment. In the 2015 report, NETL specified that a power law with 

an exponent of 0.6 was assumed to scale 40 percent of the cost of the CO2 capture system based 

on the inlet gas volumetric flow to the process and the remaining 60 percent of the cost scaled 

based upon the captured CO2 mass flow rate in accordance with Quality Guidelines for Energy 

System Studies procedures. This power law scaling approach is a very common application of 

what is referred to as the “six-tenths rule”. In their classic chemical engineering textbook, Peters 

and Timmerhaus described this rule and its use as follows:

It is often necessary to estimate the cost of a piece of equipment when no 

cost data are available for the particular size of operational capacity involved. Good 

results can be obtained by using the logarithmic relationship known as the sixtenths-factor rule, if the new piece of equipment is similar to one of another capacity 

for which cost data are available. ... However, the application of the 0.6 rule is an 

oversimplification of a valuable cost concept since the actual values of the cost 

capacity factor vary from less than 0.2 to greater than 1.0 ... . Because of this, the 

0.6 factor should only be used in the absence of other information.”54 (emphasis 

added)

Following the advice of Peters and Timmerhaus, it is common practice for design 

engineers to use the 0.6 factor “in the absence of other information” when estimating equipment 

costs by scaling. The UARG petition acknowledges this normative approach, but maintains that 

“other information” may justify deviating from it. UARG Petition p. 16 and Exh. J at 4-5 to 4-6. 

UARG first suggests that because an EPRI Technical Assessment Guide (“Electricity 

Supply – 1993 (EPRI TR-102276-V1R7, Vol. 1)) recommends the use of exponents from 0.24 to 

0.28 for “power generation equipment”, the cost analysis “may merit scaling exponents 

considerably less than the 0.6 value used by DOE/NETL” for large, capital intensive components 

such as flue gas absorbers and stripping towers. Exh. J at 4-5 (emphasis added), citing to EPRI 

Guidance at p. 8-11. UARG then provides an analysis showing how the selection of alternative 

scaling exponents would affect the projected costs. They also provide a case where a “design 

margin” is included (i.e., a larger portion of the flue gas is treated as compared to that assumed in 

the NETL study). In UARG’s “alternative projections”, their example in “Row E” (Exhibit J, 

Table 4-2), includes an adjustment to the scaling exponents and a “design margin”. They claim 

that this “alternative projection” – according to their calculation – would add $6/MWh to EPA’s 

LCOE projection. They then claim that this “alternative projection” cost invalidates EPA’s 

conclusion that the cost of partial CCS is reasonable. 

 

54 Peters, M.S., and Timmerhaus, K.D.; Plant Design and Economics for Chemical Engineers, Third 

Edition, McGraw-Hill Book Company, New York, NY USA, 1980 (emphasis supplied).
- 24 -

UARG’s reference to the EPRI Technical Assessment Guide for power plants is not 

persuasive. The Guide is for power plant equipment. UARG specifically mentions “foundations, 

high pressure steam components, and precision equipment such as steam turbines” in their 

petition. See Exh. J, p. 4-5. As the EPA explained in the rulemaking, a carbon capture system is 

more similar to a chemical plant than to the equipment traditionally found at a coal-fired power 

plant. In the post-combustion system, which is the BSER here, liquid solvents are used to 

separate CO2 from the flue gas using chemical absorption or chemisorption. In this separation 

process, flue gas is processed through the CO2 scrubber and is absorbed by the liquid solvent and 

then released by heating to form the high purity CO2 stream. See generally 80 FR 64549 and 

other sources there cited. This process has nothing to do with generating electricity. It is a 

chemical process to yield a high purity chemical, in this case, CO2. Guidance applicable to power 

plants does not support a deviation from the 0.6 rule-of-thumb to scaling cost estimates for this 

chemical plant type of process. In fact, Schnelle, et al., recommend the use of the six-tenths 

factor rule for scaling air pollution control technologies:

55

A key consideration for equipment costing is the economy of scale. In 

general, the cost of equipment does not double as the size of the equipment 

doubles. In fact, the general cost relationship for equipment as a function of the 

equipment capacity is referred to as the six-tenths factor rule ... .

UARG also claims that the NETL cost estimates are invalid because they applied the 

power-law scaling correlation (i.e., the 0.6 rule-of-thumb) for mass rates of CO2 processing 

below the range of 445,000 to 689,000 lb/hr, claiming that the NETL Quality Guidelines provide 

that the power law scaling correlation is valid only when used within that range. Petition Exh. J 

at 4-6. However, the NETL guidelines do not say that. Instead, the NETL guidelines state that 

“[t]here are limitations on the ranges that can accurately be addressed by the scaling approach. 

... Care should be taken in applying the scaling factors when there is a large percentage 

difference between the scaling parameters.”56 The NETL guidelines thus do not provide that use 

of the power law correlation is invalid outside the recommended ranges – but, rather, they 

instruct users to take care when applying the cost correlation in those instances. Similarly, Peters 

and Timmerhaus advise that:

In general, the cost-capacity concept should not be used beyond a tenfold 

range of capacity, and care must be taken to make certain the two pieces of 

equipment are similar with regard to type of construction, materials of construction, 

temperature and pressure operating range, and other pertinent variables.

A CO2 flow rate that is “beyond a tenfold range of capacity” would be one that is less than 

44,500 lb CO2/hr and none of the NETL costing evaluations are less than that amount. In 

addition, the EPA did “[take] care ... to be certain the two pieces of equipment are similar” 

because partial CCS involves the same equipment as full capture.

 

55Schnelle, K.B.; Dunn, R.F.; and Ternes, M.E.; Air Pollution Control Technology Handbook, Second 

Edition, CRC Press, Taylor & Francis Group, LLC, Boca Raton, FL (2016). (emphasis in the original)

56DOE/NETL Quality Guidelines for Energy System Studies: Capital Cost Methodology (DOE/NETL –

341/013113 at p. 18 (attached as Exh. K to the UARG Petition).
- 25 -

Moreover, even if the EPA were to accept UARG’s alternative analysis – which we do 

not – we would not reach the conclusion that the resulting re-estimated costs are unreasonable. 

First, even UARG acknowledges that their alternative costs still fall within the LCOE ranges 

reported for nuclear (Nuclear/Lazard)57 and are therefore reasonable using the rationale applied 

in both the proposal and in the final rule. Second, the UARG analysis fails to acknowledge the 

uncertainty that has already been included in the NETL cost analysis. As mentioned earlier, the 

capital cost estimates documented in the reports reflect an uncertainty range of -15 percent to 

+30 percent - consistent with AACE Class 4 cost estimates (i.e., a feasibility study). Third, as 

was also mentioned earlier, even if UARG’s alternative projections were convincing, they have 

again incorrectly assumed that the EPA has defined a “break point” of cost reasonableness. That 

is not the case. The EPA promulgated a final standard of performance with a projected cost range 

that is consistent with projected cost ranges for other competing generation technologies. 

However, the EPA did not find – nor ever suggest – that costs above those ranges are 

unreasonable or exorbitant. In fact, the EPA only found that because the costs of new generation 

technologies implementing full CCS were significantly beyond the projected cost for competing 

generating technologies, full CCS was not the best system of emission reduction. Finally, cost 

increases could be either ameliorated or eliminated by co-firing with a minor amount of natural 

gas, as noted above. See generally 80 FR 64564-565.

Overall, UARG has not convincingly established why the costing exponents that they 

have chosen for their “alternative projections” are preferred over the very common “rule-ofthumb” 0.6 exponent that NETL adopted in the absence of better information. UARG has also 

not convincingly established that the use of the power law cost correlation is “invalid” when 

applied beyond the capacity ranges recommended by NETL. Further, even if the EPA were to 

adopt UARG’s “alternative projection”, the EPA is still not convinced that the resulting costs are 

unreasonable or exorbitant. Therefore, the EPA does not find these issues to be of central 

relevance and is denying the petition for reconsideration.

5. Inclusion of the Heat Input from Duct Burners in the Definition of “Base Load Rating”

The EPA is denying UARG’s petition for reconsideration of the final rule’s definition of 

“base load rating.” While the EPA agrees that it was impracticable for UARG to raise its 

objection during the public comment period, UARG has failed to explain how its objection is of 

central relevance to the outcome of the final rule. Contrary to UARG’s suggestion, a petitioner 

seeking reconsideration must demonstrate that its “objection” is of central relevance, not merely 

that the objection discusses an “issue” of central relevance. UARG Pet. at 17 (“The issue is 

centrally relevant to the Rule because it implicates the fundamental question of what units are 

subject to the GHG NSPS.”). In fact, the EPA’s decision to include the heat input from duct 

burners in the definition of “base load rating” was not only reasonable, but advantageous to 

industry and its members, including UARG. The final definition provides certain stationary 

combustion turbines with greater flexibility to generate and sell to the grid larger amounts of 

electricity without triggering more stringent regulatory requirements. Finally, no more than a 

few, if any, combustion turbines will become subject to the rule’s requirements as a result of the 

 

57 UARG’s “alternative projection” for the “SCPC + ~16% CCS (bit)” case increases the cost from $92 -

$117 per MWh to $98 - $123 per MWh. The estimated cost for a new nuclear unit, as estimated by 

Lazard, is $92 - $132 per MWh.
- 26 -

change, and the record demonstrates that even those few turbines will be able to achieve the 

standard of performance. 

At the outset, UARG does not meet its burden of demonstrating central relevance. UARG 

objects to the inclusion of the heat input from duct burners in the definition of “base load rating” 

by noting alleged inconsistencies with the proposed rule and the criteria-pollutant NSPS for 

stationary combustion turbines. However, UARG does not explain why these alleged 

inconsistencies, which (as explained below) exist for good reason, are problematic. UARG also 

cites to comments it submitted on the proposed emission guidelines for existing fossil-fuel-fired 

EGUs, but the citation provided consists of an irrelevant discussion of why Building Block 1

(i.e., heat rate improvements) is allegedly unachievable for coal-fired EGUs, not combustion 

turbines.

58 The EPA reviewed UARG’s comments on the emission guidelines in full,59 but the 

only mention of duct burners is in a similarly irrelevant discussion of why Building Block 2

would allegedly require existing natural gas combined cycle (NGCC) units to fire their duct 

burners on a continuous basis.

60 The inclusion of the heat input from duct burners in the 

definition of “base load rating” relates to the final rule’s applicability requirements, however, not 

the achievability of the BSER. Because UARG has not provided the EPA with sufficient 

information to evaluate its conclusory objection to the definition of “base load rating” as it 

applies to stationary combustion turbines, the EPA finds that UARG’s objection is not of central 

relevance to the outcome of the rule.

In any event, the definition of “base load rating” in the final rule is reasonable for several 

reasons. First, the definition is consistent with other changes the EPA made to the proposal. The 

proposed rule included subcategories for small and large stationary combustion turbines, 

consistent with the criteria-pollutant NSPS.61 At the time of proposal, the EPA’s rationale for 

subcategorizing based on size was that NGCC units that use aeroderivative combustion turbine 

engines were less efficient than NGCC units that use large industrial frame combustion turbine 

engines. 79 FR 1486. Specifically, the small subcategory covered units with a heat input of 850 

MMBtu/h or less, including both aeroderivative and smaller industrial frame combustion turbine 

engines. The large subcategory covered units larger than 850 MMBtu/h, all of which are large 

industrial frame combustion turbine engines.

At proposal, the EPA defined “base load rating” as “100 percent of the manufacturer’s 

design heat input capacity of the combustion turbine engine at ISO conditions using the higher 

heating value of the fuel (heat input from duct burners is not included).” 79 FR 1509. If the EPA 

had included the supplemental heat input from duct burners in the definition of “base load 

rating” at proposal, some aeroderivative and small industrial frame combustion turbines likely 

would have exceeded the 850 MMBtu/h threshold and become subject to the more stringent 

 

58 See Comments of the Utility Air Regulatory Group on the United States Environmental Protection 

Agency’s Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility 

Generating Units; Proposed Rule at 212 (Dec. 1, 2014), EPA-HQ-OAR-2013-0602-22768.

59 Even though the EPA undertook such a review here, the EPA notes that the CAA does not require the 

agency to search through a petitioner’s previously-filed comments to account for incorrect citations.

60 Comments of UARG at 206.

61 40 CFR Part 60, Subpart KKKK.
- 27 -

standard for large units, which was based on the supposedly more efficient operation of large 

industrial frame combustion turbines. 

In response to comments, however, the EPA eliminated the proposed size-based 

subcategories in the final rule and, consistent with a noticed alternative approach, 79 FR 1459-

61; 79 FR 34979-81, established a single emission standard for all natural gas-fired combustion 

turbines operating at base load. The EPA concluded that size-based subcategories were not 

appropriate for a CO2 emission standard because (1) no clear cut-point exists between “small” 

and “large” units; (2) size-based subcategories could unduly influence the development of future 

NGCC offerings; (3) actual operating and design data showed a relatively weak correlation 

between turbine size and CO2 emission rates, with the emission-rate variability among similar 

size units far exceeding any variability that could be attributed to a difference in size; (4) most 

existing small units had already demonstrated emission rates below the proposed emission 

standard for large units; and (5) the lower design efficiencies of some small units were primarily 

related to model-specific design choices in the turbine engine and heat recovery steam generator, 

not inherent limitations in the ability of small units to achieve comparable efficiencies to large 

units. 80 FR 64608-09. By eliminating the size-based subcategories, the EPA’s prior concern—

that including the heat input from duct burners in the definition of “base load rating” would 

cause some aeroderivative and small industrial frame combustion turbines to be included in the 

large unit subcategory—was no longer an issue.

Second, the final definition of “base load rating” actually benefits industry. As the EPA 

explained in the final rule, the definition of “base load rating” includes the heat input from duct 

burners to accurately account for the potential electric output of the affected unit. 80 FR 64608.

This definition complements both the finalized operations-based subcategorization approach and 

the exemption for industrial combined heat and power (CHP)62 facilities. 

In regards to the former, the final rule established non-base load and base load 

subcategories for natural gas-fired stationary combustion turbines. The base load subcategory is 

subject to an output-based emission standard of 1,000 lb CO2/MWh-g that reflects modern,

efficient NGCC technology. The non-base load subcategory, on the other hand, is subject to a 

less-stringent input-based emission standard of 120 lb CO2/MMBtu that reflects the use of clean 

fuels. The distinction between the base load and non-base load subcategories is based on an 

affected unit’s net-electric sales and potential electric output. Potential electric output is 

determined, in part, by multiplying a unit’s design efficiency by its base load rating. At a given 

design efficiency, units with a higher base load rating will have a higher potential electric output. 

The higher a unit’s potential electric output, the more electricity that unit can sell to the grid 

before being classified as a base load unit subject to the more stringent output-based standard. In 

other words, by including the heat input from duct burners in the definition of “base load rating,”

the EPA increased the amount of electricity that a non-base load unit with duct burners can sell 

to the grid. This result favors industry, and UARG has not objected to it.

 

62 “Combined heat and power unit or CHP unit, (also known as ‘cogeneration’) means an electric 

generating unit that use[s] a steam generating unit or stationary combustion turbine to simultaneously 

produce both electric (or mechanical) and useful thermal output from the same primary energy source.” 

40 CFR 60.5580.
- 28 -

In regards to CHP facilities, the final applicability criteria are not intended to cover

industrial CHP units that are primarily intended to provide useful thermal output (e.g., steam) to 

a host facility. 80 FR 64533-35. To differentiate between industrial and utility CHP units, the 

EPA used a similar approach to the one used to distinguish between base load and non-base load 

units, i.e., a comparison between net-electric sales and potential electric output. As described 

previously, potential electric output is determined, in part, by multiplying a unit’s design 

efficiency by its base load rating. CHP units often include duct burners to satisfy the steam 

demands of the host facility. Thus, the inclusion of the heat input from duct burners in the 

definition of “base load rating” means that CHP units with duct burners will have a higher base 

load rating and a higher potential electric output than they would otherwise. The result is that 

industrial CHP units with duct burners can sell more electricity to the grid without becoming 

subject to the final rule’s requirements. This result also favors industry, and UARG has not 

objected to it.

Third, few, if any, new NGCC units are likely to become subject to the final rule’s 

requirements as a result of the change to the proposed definition,

63 and even these units will not 

be disadvantaged because they will be able to achieve the 1,000 lb CO2/MWh-g standard. There 

are two types of duct burners: (1) small duct burners designed to recover lost output during 

periods of high ambient temperatures and (2) large duct burners designed to create additional 

output during all types of conditions.

64 Combustion turbines combust less fuel when ambient 

temperatures are higher than ISO65 conditions (288 Kelvin (15 °C), 60 percent relative humidity, 

and 101.3 kilopascals pressure), reducing electric output. Relatively small duct burners (e.g., less 

than 5 percent of the potential heat input of the affected unit) are often used to make up this 

shortfall. Owners and operators typically only run these smaller duct burners during periods of 

peak summer demand, when ambient temperatures are high. To calculate a unit’s base load 

rating, however, an owner or operator must determine the amount of fuel that the unit can 

combust at steady state and ISO conditions.66 Because the base-load-rating calculation is based 

on the affected unit’s operation at ISO conditions, not ambient conditions, the heat input from

this type of smaller duct burner will not affect the calculation.

In contrast, large duct burners (e.g., greater than 5 percent of the potential heat input of 

the affected unit) are used to create additional steam turbine output at ISO conditions, meaning 

the final definition of “base load rating” could potentially affect combustion turbines equipped 

with this type of burner. However, (where no exemption applies) the final rule only applies to 

units that (1) have a base load rating greater than 250 MMBtu/h of fossil fuel and (2) serve a 

 

63 For example, UARG could not identify any example existing stationary combustion turbines that would 

be impacted by the change. See Utility Air Regulatory Group, Petition for Reconsideration of EPA's 

"Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating 

Units," 80 Fed. Reg. 64,662 (Oct. 23, 2015), at 17 (Dec. 22, 2015). 

64 Backlund, Jon and Froemming, Jim; Thermal & Economic Analysis of Supplementary Firing Large 

Combined Cycle Plants, http://www.coen.com/library/technical-papers/thermal-economic-analysis-ofsupplementary-firing-large-combined-cycle-plants/.

65 ISO refers to the “Industrial Organization for Standards.” See http://www.iso.org/iso/home.html.

66

“Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a 

steady state basis, as determined by the physical design and characteristics of the EGU at ISO 

conditions.” 40 CFR 60.5580 (emphasis added).
- 29 -

generator capable of selling greater than 25 MW of electricity to the grid. 40 CFR 60.5509(a)(1)-

(2). Most new NGCC units will have a base load rating greater than 250 MMBtu/h even without

the heat input from large duct burners. In fact, the smallest NGCC units capable of meeting the 

25 MW criterion will have a heat input rating of approximately 200 MMBtu/h (not including the 

heat input from duct burners).

67 The record for the final rule shows that NGCC units with a base 

load rating of only 190 MMBtu/h can comfortably achieve the final rule’s 1,000 lb CO2/MWh-g

standard with a design compliance margin68 of 11 percent.

69 Therefore, while a handful of 

smaller NGCC units might exceed the 250 MMBtu/h threshold and become affected units once 

the heat input from their duct burners is accounted for, even these units will not be 

disadvantaged. As a result, UARG’s conclusory objections are unfounded, and the EPA is 

denying reconsideration on this issue.

6. Objections Related to Identity of Reporting Entities

UARG’s final objection relates to the mechanics of electronic reporting. UARG complains 

that the final rule restricts the person submitting reports to a “Designated Representative”, 

whereas the proposal would have allowed anyone qualifying as an “owner or operator” to submit 

reports. UARG claims it had no notice of this possibility, and that there are substantive reasons 

that a designated representative should not submit reports. UARG Petition p. 18.

UARG has not met either of the requirements for granting reconsideration on this issue. 

The EPA proposed that owners/operators of affected EGUs submit reports. 80 FR 1452. UARG 

submitted comments on the issue, noting among other things that the proposal was meant to be 

consistent with e-reporting under the acid rain program, and that under that program a 

“designated representative” files reports. UARG Comments p. 194. The comment continued that 

under various applicable rules, not all designated representatives are owners/operators, and that 

EPA should deal with this issue in the final rule so that “any individual who meets the definition 

of ‘owner or operator’” can certify and submit reports. Id. p. 195. The EPA responded in the 

final rule by allowing reports to be submitted by a designated representative, a person appointed 

as alternate designated representative, or a person authorized by either of these. Any of these can 

be an owner/operator. Section 60.5555(d) and (e); see also RTC 12.4-6 indicating that the final 

rule was being clarified to address UARG’s comment. 

It is clear both from EPA’s proposal and from UARG’s comment that it had adequate 

notice of the question of who reports, and indeed, their comment directly addressed the issue of 

the relationship between owner/operator and designated representative. Moreover, this issue is 

not of central relevance to the rule, since it deals with a nuance of rule implementation, not with 

 

67 While there is sufficient oxygen in the combustion turbine engine exhaust to theoretically support duct 

burners with a maximum heat input value greater than the combustion turbine itself, for practical reasons, 

the duct burners used in electric-only NGCC units are generally limited to approximately 20 percent of 

the heat input of the affected unit. Newell, Samuel A., et al.; Cost of New Entry Estimates for Combustion 

Turbine and Combined Cycle Plants in PJM with June 1, 2018 Online Date, https://www.pjm.com/~/

media/documents/reports/20140515-brattle-2014-pjm-cone-study.ashx.

68 A compliance margin is the difference between a unit’s performance capability and the actual standard 

of performance.

69 Gas Turbine World Efficiency Combined Cycle Efficiency, EPA-HQ-OAR-2013-0495-11888.
- 30 -

whether the standard of performance reflects a best system of emission reduction which is 

adequately demonstrated.

In any case, UARG’s objection lacks substantive merit. UARG reiterates that there are 

distinctions between the acid rain and NSPS programs such that only owner/operators should 

report under the NSPS program. Petition pp. 18-19. Even assuming this is the case, the final rule 

obviates UARG’s concern because it allows owners/operators to report if affected EGUs wish to 

do so. Specifically, the rule provides that for affected EGUs subject to the acid rain program, 

either a designated representative, authorized designated representative, or person authorized by 

either of these, can report. 60 CFR section 60.5555(d). Thus, even if they are not already one 

and the same, a designated representative or authorized designated representative can in turn 

authorize the owner/operator70 to file. UARG notes that section 60.5555(d) begins by stating that 

the report “shall be submitted by”, and misreads the provision to assume that this means only 

designated representatives can file. UARG Petition p. 19. Section 60.5555(d)(3) makes clear that 

a designated representative can in turn authorize any other entity, including an owner/operator, to 

file.

Identical provisions apply in the case of affected EGUs not subject to the acid rain 

program: filing can be done by a designated representative, authorized designated representative, 

or an entity authorized to file by the designated representative. Section 60.5555(e). 

Since this objection does not satisfy any of the requirements in the Act for granting 

reconsideration, the EPA is denying it. Moreover, since the final rule allows owner/operators to 

file, it appears to provide UARG with all the relief it seeks on this issue so that there is no basis 

for objection.

B. Response to AEP Petition

AEP essentially objects to the EPA’s characterization of its experience in retrofitting one 

of its plants, the Mountaineer Plant (New Haven, WV), with partial CCS in a demonstration 

project. The EPA viewed (and views) that experience as providing support for partial CCS being 

an adequately demonstrated technology. AEP claims that it and others submitted extensive 

comment that EPA failed to adequately address.

The EPA cited to AEP’s own figures in finding that the project achieved CO2 capture 

rates on the slip stream of from 75 to 90 percent. The EPA also cited AEP’s own FEED report71

on how the demonstration project could be scaled up to full scale capture. 80 FR 64552, 64557; 

see also 79 FR 1436 and 1475 (discussing the Mountaineer project at proposal). The EPA also 

quoted AEP Chief Executive Officer’s own praise of the project’s performance: “we feel that we 

have demonstrated to a certainty that the carbon capture and storage is in fact viable technology 

for the United States and quite honestly for the rest of the world going forward.” (80 FR 64556) 

The EPA likewise quoted Alstom senior Vice President Joan MacNaughton’s 2011 public 

statement that “[t]he Validation Plant at Mountaineer demonstrated the ability to capture up to 90

 

70 “Owner/operator” is defined in the general provisions at 40 CFR 60.2. The definition is 

capacious and does not limit the ability of a designated representative to delegate filing authority 

to an owner/operator.

71 FEED = Front End Engineering Design
- 31 -

percent of the CO2 from a stream of the plant’s emissions. The technology works.” RTC Chapter 

6 at 6-152. (Alstom was a partner in the demonstration project, which used its chilled ammonia 

carbon capture technology.)72

AEP did indeed submit comments in this rulemaking maintaining that the Mountaineer 

project did not demonstrate that partial CCS is BSER. Among other things, those comments 

maintained that the project was too small in its scale to demonstrate that partial CCS is 

adequately demonstrated at commercial scale, and that there were extensive cost overruns on the 

project, many of them attributable to difficulties in siting monitoring wells used to assure 

integrity of the CO2 sequestration area. Comments of AEP (May 8, 2014) pp. 80-83. The EPA 

responded to all of these comments, noting among other things that both AEP’s own FEED study 

and the NETL studies set out in point-by-point, system-by-system detail how the capture 

technology could be scaled up to full-scale73, why the costs at the project were not indicative of 

costs at a new facility (for example, since the project was a retrofit, the project presented siting 

issues (including siting for monitoring wells) that could be avoided for a new plant)74, and 

generally why partial CCS is not exorbitantly costly.75

AEP does not maintain (nor could it do so plausibly) that it lacked notice of the issue to 

which it now objects. The EPA also believes that the agency reasonably characterized the 

performance of the Mountaineer project, reasonably responded to AEP’s public comments, and 

accurately quoted and interpreted the public statements of AEP and Alstom executives 

characterizing the performance of the Mountaineer project. See, e.g., RTC response 2.1-235. The 

project does provide strong support for the technical feasibility of partial CCS, including at 

commercial scale. Moreover, the costs incurred at the project are not indicative of costs for a new 

source given that the project is a retrofit. Consequently, in addition to being untimely, AEP’s 

objection is not of central relevance to the outcome of the rulemaking, and the EPA is therefore 

denying the petition to reconsider.

AEP also maintains that the record contains no information showing that Boundary Dam 

Unit 3 is capable of achieving the promulgated standard since it had operated for less than one 

year at the time of promulgation.76 The EPA’s basis for finding that the standard is achievable is 

fully set out at 80 FR 64573-74 and in the Achievability TSD. The EPA gave ample notice that it 

regarded Boundary Dam as a plant preparing to utilize full scale CCS, and noted that its design 

level and reported initial performance were well in excess of the rate of carbon capture on which 

the standard of performance is predicated. 79 FR 1435; 80 FR 64549-50. AEP’s objection 

 

72 See also RTC response 6.3-107 (more quotes from AEP and Alstom executives praising performance of 

CCS); id. at response 6.3-320 (Alstom Senior Vice President MacNaughton states publicly that “coal with 

CCS is cost competitive with the cost of electricity generated by other low- or no-carbon energy sources”; 

the full text of the press release from Alstom Vice President MacNaughton is at EPA-HQ-OAR-2013-

0495-11320. 

73 See, e.g. Final Preamble section V.G.3; RTC response 6.3-23 at p. 6-17.

74 See, e.g. 80 FR 64573; RTC responses 6.3-93, 6.3-247 (at pp. 150-151), 6.3-259 (at p. 167), 6.3-272 (at 

p. 183). 

75 RTC response 6.3-286.

76 UARG raises a similar point at p. 11 of its Petition. The exhibits to UARG’s own petition show that 

BD3 met the U.S. standard in its initial year of operation. See III.A.1 above.
- 32 -

therefore fails to demonstrate that there was lack of opportunity to comment during the 

rulemaking or that the objection is of central relevance to the rulemaking’s outcome.

C. Response to Ameren Petition

Ameren’s petition deals virtually in its entirety with objections to the section 111(d) 

emission guidelines. The petition states correctly that the section 111(b) NSPS is related to the 

emission guidelines, but the only specific objection raised to the section 111(b) standards is a 

claim that partial CCS is not adequately demonstrated, an issue on which there was obvious 

opportunity to comment during the rulemaking. Since the petition states no legitimate grounds 

for granting reconsideration, the EPA is denying it.

D. Response to State of Wisconsin Petition

The State of Wisconsin largely reiterates comments it made during the rulemaking, but 

claims that the EPA did not adequately respond to them. These include comments regarding 

achievability of the proposed NSPS; consistency of the standard with individual BACT 

determinations (including a BACT determination made by the State Of Wisconsin for the Elm 

Road power plant); CCS’ status as an “emerging technology” that cannot be BSER; and lack of 

geologic storage capacity in Wisconsin, which the State asserts puts Wisconsin at a competitive 

disadvantage. Wisconsin Petition Attachment 1 at 1. The EPA in fact addressed all of these 

issues, and Wisconsin’s comments regarding them, in the rulemaking. See e.g., RTC comment 

responses 9.5-2, 6.3-237, 6.3-291, 6.3-332 and 80 FR 64631-32 (responses relating to BACT 

determinations and choice of partial CCS as BSER)77; 2.1-147, 2.1-149, 2.1-157, 2.1-238, 6.3-23 

(responses relating to “emerging technology”); 6.3-60; 6.3-72, 6.3-84, 6.3-99, 6.3-100, 6.3-251,

 

77 The State asserts that its 2012 determination that full CCS was not BACT for the Elm Road 

coal fired plant undercuts EPA’s technical determination that partial CCS is BSER for new 

plants. This assertion lacks a reasoned basis. First, individual state BACT determinations, while 

relevant, do not constrain federal technical determinations in the different context of section 111 

standards (80 FR 64631). Second, this particular BACT determination is not properly 

comparable to the new source standard. The determination involved application of CCS to an 

existing facility, not to a new source. Thus, the BACT determination was triggered by an existing 

source’s request to burn sub-bituminous rather than bituminous coal. The State determined that 

although full CCS was a technically feasible control technology for CO2, the technology was 

economically infeasible for two reasons: there was insufficient land available at the existing site 

to sequester captured carbon, and the nearest sequestration site was out of state, necessitating 

very high transport costs. See generally, “ANALYSIS AND PRELIMINARY 

DETERMINATION FOR THE CONSTRUCTION PERMIT FOR THE PROPOSED 

MODIFICATION OF TWO COAL FIRED POWER BOILERS FOR Wisconsin Electric Power 

Company, d.b.a WE ENERGIES-OAK CREEK STATION, LOCATED AT 11060 S 

CHICAGO RD., OAK CREEK, MILWAUKEE COUNTY, WISCONSIN” Construction 

Permit No.: 12-SDD-047 (October 22, 2012), pp. 13-14. Thus, this determination is consistent 

with the EPA’s determination in the section 111(d) emission guideline rulemaking and the 

section 111(b) rulemaking that full CCS is not BSER for existing or modified power plants. The 

determination in the permitting proceeding also is at odds with the State’s position here that CCS 

is not a technically feasible technology. See also RTC Response 6.3-291 where the EPA gave a 

similar response to the similar comment regarding a BACT determination for an Iowa facility.
- 33 -

2.1-228 and 80 FR 64549-54, 64556-57, 64575-82 (responses relating to availability of 

sequestration capacity and demonstration of partial CCS technology). The petition thus fails to 

state any grounds requiring EPA to reconsider any of these issues.

The State also maintains that EPA miscalculated costs relating to transport of captured 

CO2 for Wisconsin new sources, largely because the EPA cost estimates assume transport for 62 

miles (100 km) rather than the 270 miles Wisconsin sources would need to use. Wisconsin 

Petition Attachment 1 pp. 1-2 and n.9. In fact, a New Source Performance Standard is developed 

on a nationwide, not state-by-state basis, and the EPA’s evaluation of costs was reasonable. The 

record shows, and indeed Wisconsin does not contest (or even address) that 95 percent of the 

largest CO2 sources are within 50 miles of a potential storage reservoir. The State also does not 

contest or even address the other potential compliance paths noted in the administrative record: 

CO2 storage can be provided by enhanced oil recovery (EOR); a new source can be sited out-ofstate proximate to a sequestration site (for example, in Illinois, the example given in the State’s 

petition) and still provide electricity via ‘coal-by-wire’ arrangements. These arrangements are 

documented for distances considerably greater than the 270 miles the State refers to in its 

Petition. See 80 FR 64572, 64579-81, 64582-83; RTC comment responses 6.3-251; 6.3-277; 

responses in unit 6.3.4.

In addition to a coal-by-wire compliance alternative, the EPA noted that coal plants could 

co-fire natural gas and meet the standard without the need for CCS (partial or otherwise). 80 FR 

64564. Wisconsin challenges this determination in its Petition, although it (properly) does not 

claim that it lacked opportunity to comment on the issue, or that its objection is of central 

relevance to the outcome of the rulemaking. Wisconsin asserts that co-firing at rates of 30

percent or higher is not an adequately demonstrated technology and so this compliance path may 

not exist for some sources. Specifically, the Petition states that “EPA’s own reference 

documents show that co-firing natural gas up to 30 percent (on a heat input basis) has not moved 

beyond the design/pilot state; therefore co-firing gas at 40 percent has not been adequately 

demonstrated”. Wisconsin Petition Attachment 1 p. 2, referring to the EPRI technical report “Gas 

Cofiring Assessment for Coal Fired Utility Boilers” cited by the EPA at 80 FR 64564 n. 288

(“EPRI Cofiring Assessment”). This contention is mistaken. The EPA found that natural gas cofiring rates of up to 40 percent could be achieved by using a combination of natural gas 

reburning and supplemental gas firing. 80 FR 64564/3. The EPRI Cofiring Assessment indicates 

that these rates of co-firing are demonstrated and achievable. EPRI Cofiring Assessment at pp. 2-

4, 2-5, 2-35. The petition mistakenly confused these well-established technologies, which are the 

ones the EPA evaluated and costed, with a different technology, coal/gas co-firing burners 

(discussed in unit 2.6 of the EPRI Cofiring Assessment) (See, e.g., EPRI Cofiring Assessment 

unit 2.6 at pp. 2-40 to 41; Executive Summary p. 1; Executive Summary p. xvii “The largest 

number of applications and the longest experience time is with reburning and supplemental gas 

firing.”. Because these co-firing techniques introduce natural gas at different locations - in a 

boiler’s primary combustion zone (supplemental gas co-firing) and in the upper regions of the 

primary furnace above the primary coal combustion zone (reburning techniques) - they can be 

implemented in combination.

The State of Wisconsin also argued that coal boiler operators would likely need to fire 

even more than 40 percent natural gas to be in compliance with the final standard, since 1) they 

need to have a sufficient compliance margin below the standard, and 2) the EPA’s assumed base 
- 34 -

rate of 1,618 lb CO2/MWh-g is lower than what has been achieved in practice. There is no 

technological reason that a new boiler cannot be designed to accommodate an increased level of 

natural gas co-firing (there is at least one existing EGU with the capacity to fire 100 percent coal 

or 100 percent natural gas – and to co-fire combinations of the two). Further, even if a new EGU 

needed to (or chose to) co-fire more than 40 percent natural gas to meet the standard of 

performance, the cost would be well within the range of costs that the EPA found to be 

reasonable (See 80 FR 64565, Table 9).

The petition also maintains that EPA cannot consider natural gas co-firing as an 

alternative compliance path in any case because doing so impermissibly redefines the source. 

Wisconsin Petition Attachment 1 p. 2. This issue was raised in public comment and the EPA has 

already responded. RTC Comment and Response 2.1-103; 2.1-213; 2.1-214; 2.4-6. Thus, the 

objection is untimely. 

It also lacks central relevance. In brief, redefining a source is a concept that has 

developed exclusively in the context of the Prevention of Significant Deterioration (PSD)

program, under different statutory criteria. PSD determinations are case-by-case preconstruction 

requirements that require the incorporation of the “best available control technology” (BACT) at 

the time of construction of a new major emitting facility or as part of a major modification78 of 

an existing facility. Because BACT applies at the preconstruction stage on a case-by-case basis 

and generally requires the installation of control technology, it is appropriate, though not 

required, for a permitting authority to limit the scope of BACT to avoid frustrating the 

fundamental purpose and to consider the inherent design of such projects on a case-by-case 

basis. 

Under the PSD program, there is no absolute prohibition against redefining the source,79

but rather an EPA-developed policy of caution concerning fundamentally redefining the source 

and disrupting the basic business purpose of a project in the context of BACT determinations.80

The State’s argument consequently fails even if one were to accept its logic that the concept 

applies to establishing section 111(b) standards of performance. 

The State is in fact in error in its contention that the redefining the source concept is even 

relevant in the section 111(b) context. Under section 111(b), the Administrator identifies a list of 

adequately demonstrated control options, selects the best of those control options after 

considering cost and other factors, then selects an achievable limit for the category through the 

application of the BSER across the industry. The BSER for purposes of section 111(b) is not 

limited to technology that can be built into a specific source because affected sources have 

already been constructed. Rather, it is generally based on pollution control systems that can be 

implemented by a new source. A best system of emission reduction certainly can entail some 

 

78 Note that the requirements of a NSR “modification” are distinct from the standards for “modifications” 

finalized under CAA section 111(b).

79 PSD and Title V Permitting Guidance for Greenhouse Gases at 27 (March 2011) (“EPA does not 

interpret the CAA to prohibit fundamentally redefining the source and has recognized that permitting 

authorities have the discretion to conduct a broader BACT analysis if they desire’); In re Knauf 

Fiberglass, 8 E.A.D. 121, 136 (EAB 1999) (“redefinition of the source is not always prohibited”). 

80 In re Praire State Generating Company, 13 E.A.D. 1, 15-28 (EAB 2006). 
- 35 -

measure of fuel substitution.81 Moreover, natural-gas co-firing here is an alternative compliance 

path noted by EPA, but not part of the Best System of Emission Reduction, see 80 FR 64564, so 

any analogy with the BACT process fails in any case.

Indeed, as EPA has already explained, natural gas co-firing has been used for years as a 

mechanism for reducing air pollution from coal-fired boilers. 80 FR 64564; see also 79 FR 1471.

Consequently, the EPA reasonably determined that natural gas co-firing could constitute an 

alternative compliance path for meeting the 1,400 lb CO2/MWh standard of performance, that 

this alternative compliance pathway is generally available and obviates issues of access to 

geologic sequestration and EOR capacity, and that the statute does not preclude this type of 

finding. The State’s objection is consequently not of central relevance to the outcome of the 

rulemaking. Consequently, the EPA is denying these aspects of the petition.

Finally, Wisconsin argues that the final rule set a standard of performance for natural gasfired stationary combustion turbines operating as base load units that cannot be achieved by 

simple cycle technology. Wisconsin makes no effort to explain how its objection meets the 

criteria for reconsideration under section 307(d)(7)(B). 

At proposal, the EPA provided clear and adequate notice that the BSER for base load 

turbines was natural gas combined cycle (NGCC) technology. The EPA specifically rejected 

simple cycle technology as the BSER for this subcategory, noting that even advanced simple 

cycle units “have a base load rating of 1,150 lb CO2/MWh, which is higher than the base load 

rating emission rates of 830 and 760 lb CO2/MWh for the conventional and advanced NGCC 

model facilities, respectively.” 79 FR 1430, 1485. The EPA also explained that “NGCC has a 

lower cost of electricity than simple cycle turbines at intermediate and high capacity factors” 

(i.e., base load operation). 79 FR 1485. The EPA received numerous comments on this issue. See 

Response to Comments Chapter 7.4.2 at 7-36 to 7-40 (EPA-HQ-OAR-2013-0495-1186); see also 

80 FR 64,614/1 (summarizing comments). 

In the final rule, the EPA explained:

Many commenters mistakenly thought that the EPA proposed to require 

some simple cycle combustion turbines to meet an emission standard of 1,000 lb 

CO2/MWh-g, a level that they assert is unachievable. On the contrary, the EPA is 

not finding that NGCC technology and a corresponding emission standard of 1,000 

lb CO2/MWh-g is the BSER for simple cycle turbines. Instead, the EPA is finding 

that NGCC technology is the BSER for base load turbine applications. This means 

that if an owner or operator wants to sell more electricity to the grid than the amount 

derived from a unit’s nameplate design efficiency calculated as a percentage of 

potential electric output, then the owner or operator should install a NGCC unit. If 

 

81 Indeed, Congress amended section 111(a) in 1990 to remove the language that standards of 

performance reflect the best technological system and achieve a percent reduction in emissions, 80 FR 

64537 n. 124, confirming that non-technological controls such as fuel substitution could be part of that 

best system. Similarly, under the CAA section 112 National Emission Standard for Hazardous Air 

Pollutant program, the EPA is mandated to consider “substitution of materials” in assessing what 

standards reflect performance of maximum achievable control technology. See CAA section 

112(d)(2)(A).
- 36 -

the owner or operator elects to install a simple cycle turbine instead, then the 

practical effect of our final standards will be to limit the electric sales of that unit 

so that it serves primarily peak demand, not to subject it to an unachievable 

emission standard.

80 FR 64,615/2. 

Because the grounds for Wisconsin’s objection did not arise after the public comment 

period and Wisconsin has not explained how its concerns are centrally relevant, the EPA is 

denying reconsideration on this issue.

E. Response to EELI Petition

EELI’s Petition is premised entirely on undocketed email communications between a 

single former EPA official and various members of non-governmental organizations (NGOs). 

Several dozen emails are attached as exhibits to the petition in support. EELI claims that these 

emails show that the whole rulemaking process was tainted by “ex parte communications”, that 

the agency decision maker was impermissibly biased, and that the contacts between the single 

EPA official and NGO personnel constituted an advisory committee established in contravention 

of the provisions of the Federal Advisory Committee Act (FACA). The petition asserts lack of 

opportunity to raise its objection during the rulemaking because some of the emails in question 

were not yet available. According to the petition, the objection raised is of central relevance to 

the rulemaking’s outcome because the rule’s outcome was determined by non-agency personnel. 

EELI Petition p. 4 (“[t]his direction from private parties was not simply manifest in the final 

rule; it documents a predetermination of the material substance of the rule, controlled by nonagency personnel”).

This petition is significantly incorrect as a matter of both law and fact. First, the concept 

of ex parte communication does not apply to informal rulemakings,82 either under the 

Administrative Procedure Act or under the procedural requirements of the Clean Air Act. Sierra 

Club v. Costle, 657 F. 2d 298, 400-402 (D.C. Cir. 1981).83 The reason is that, unlike adjudicative 

proceedings, informal rulemakings involve policymaking, quasi-legislative types of 

determinations benefitting enormously from “continuing contact with a regulated industry, other 

affected groups, and the public”. Id. at 401. Informal rulemakings stand in contrast with 

adjudicative, trial-type proceedings where conflicting claims to a valuable privilege militate in 

 

82 “Informal rulemakings” (as opposed to rulemakings required by statute to be made on the record after 

opportunity for an agency hearing) involve notice by the agency via the Federal Register, and opportunity 

for public comment to that notice. 5 USC section 553(b) and (c).

83 See also Administrative Conference of the United States “Ex parte communications in informal 

rulemakings” (June 10, 2014) stating “Informal communications between agency personnel and 

individual members of the public have traditionally been an important and valuable aspect of informal 

rulemaking proceedings conducted under section 4 of the Administrative Procedure Act (APA), 5 U.S.C. 

§ 553. Borrowing terminology from the judicial context, these communications are often referred to as 

“ex parte” contacts.[1] Although the APA prohibits ex parte contacts in formal adjudications and formal 

rulemakings conducted under the trial-like procedures of 5 U.S.C. §§ 556 and 557,[2] 5 U.S.C. § 553 

imposes no comparable restriction in the context of informal rulemaking”. Available at 

https://www.acus.gov/recommendation/ex-parte-communications-informal-rulemaking
- 37 -

favor of insulation of the decision-maker. Id. at 400. EELI cites Home Box Office v. FCC, 567 F. 

2d 9 (D.C. Cir. 1977) as its (sole) support. EELI Petition p.5. However, that case does not apply 

to informal rulemakings. Sierra Club, 657 F. 2d at 402 (“Later decisions of this court ... have 

declined to apply Home Box Office to informal rulemaking ... and there is no precedent for 

applying it to the procedures found in the Clean Air Act....”).

The EPA was also not required to docket these pre-proposal communications. Section 

307(d)(3) of the Clean Air Act indicates that “[a]ll data, information, and documents referred to 

in this paragraph on which the proposed rule relies shall be included in the docket on the date of 

publication of the proposed rule.” However, when a proposed rule is not based on any 

information or data arising from a particular contact, the information is not required to be 

docketed. See Sierra Club, 657 F. 2d at 407. That is the case here. First, all of the emails 

attached as exhibits to the petition are from 2011 and relate to a different proposal than the one 

that led to the standard at issue here. In 2012, the EPA proposed a new source standard for coalburning boilers, but withdrew that proposal and commenced a new proceeding. 77 FR 22392 

(April 13, 2012); 79 FR 1352 (January 8, 2014) (withdrawing the 2012 proposal). The different 

proceeding at issue here was proposed at 79 FR 1430 (January 8, 2014). Second, the potential 

standards discussed in the emails are unrelated to those that the EPA proposed. Thus, the emails 

discuss a potential standard of 1,600-2,100 lb CO2/MWh based on burning natural gas along with 

coal. The standards that the EPA proposed were 1,000 lb CO2/MWh based in the withdrawn 

proposal on constructing only natural gas combined cycle plants (i.e., not burning coal at all) (77 

FR 22392), or (in the new proposal) on the performance of a control technology, carbon capture 

and sequestration, which uses a chemical process to capture CO2 and convert it to a phase state 

where it can be piped to a sequestration site for permanent disposition. 79 FR 1446, 1469-75. 

There is no requirement to docket information on regulatory alternatives that the agency never 

proposed, never solicited comment on, and never otherwise pursued.

Moreover, the EPA did disclose all factual and methodological information underlying 

the proposal, indeed exhaustively so. See, e.g., 79 FR 1462-1485 (legal rationale for proposal; 

rationale for proposed selection of partial CCS as BSER; cost information; information on 

geologic sequestration of captured CO2). Even were the suggestions of outside parties reflected 

in a proposal (which is not the case here), then what would matter would be the content of that 

proposal, and whether the data and methodology underlying the proposal are disclosed. This is 

the information that is critical to a proposed rule (see CAA section 307(d)(3)(A)-(C)), not the 

identity of individuals making suggestions.84

 

84 As it happens, EPA staff sought out the views of numerous parties from industry and academia, as well 

as the environmental community, in crafting the new source performance standards. See e.g., 

Meeting with Lignite Energy Council on 05/09/14 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-9674; 

EPA Meeting with Golden Spread Electric Cooperative on June 17, 2014 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-11064; 

Meeting between EPA and Representative Tom Sloan on January 6, 2014 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-0078; 
- 38 -

The further suggestion that the EPA’s decision is the product of impermissible bias is 

untenable. See generally RTC Response 2.4-19. Petitioners need to make a “clear and convincing 

showing of an unalterably closed mind on a matter critical to disposition of the proceeding”.

Lead Industries Ass’n v. EPA, 647 F. 2d 1130, 1178 (D.C. Cir. 1980). At most, the Petition 

shows that one EPA official, who was not in the lead office developing the rulemaking, sought 

out pre-proposal comment on regulatory alternatives that the agency never pursued, which 

alternatives were considerably less stringent than the standards the EPA actually proposed. 

Rhetorical flourishes notwithstanding, the Petitioner has failed to make any semblance of the 

requisite showing here. 

For all of these reasons, the EPA is denying this Petition.

V. Conclusion

The new source standards require a new coal-burning power plant to reduce carbon 

dioxide emissions to a level reflecting both the most highly efficient boiler design, and partial 

capture and sequestration of carbon dioxide. Carbon capture and sequestration is a proven 

technology, with a history of reliable use at coal-fired plants and other industrial sources. At the 

level of capture on which the standard of performance is predicated, partial capture and 

sequestration is available at reasonable cost. An unprecedented coalition of major industrial 

entities (including Peabody Energy, Arch Coal, Archer Daniel Midland, Occidental Petroleum), 

major NGOs, unions (including the AFL-CIO),and diverse states (including Kentucky, 

Maryland, and Michigan) recently stated that “CCUS [carbon capture utilization and storage]

represents an essential component of our nation’s strategy for achieving greenhouse gas emission 

reductions. Without widespread deployment of CCUS technologies, we will simply fail to meet 

global mid-century goals for mitigating carbon emissions from electric power generation and a 

wide range of industrial activity.”85 The same impressive coalition noted that “[c]apturing and 

 

USEPA Meeting with EEI Regarding CAA 111(b) and (d) Proposals for GHG Emissions from EGUs, 

February 3, 2015 http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-11270; 

Meeting with NRDC Regarding Proposed Carbon Pollution Standard for New Power Plants, December 

18, 2014 http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-11269; 

AES Meeting on 05-13-14 http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-

10947; 

Meeting between USEPA and Union representatives on July 26, 2013 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-0061; 

Attendee List from USEPA Meeting with GE on December 16, 2013

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-0071; 

Meeting with Environment America on 05-09-14 http://www.regulations.gov/#!documentDetail;D=EPAHQ-OAR-2013-0495-9673; 

Meeting Memorandum http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-

11806; 

Meeting between USEPA and Power4Georgians on February 13, 2013 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0495-0063.

85 Letter of February 3, 2016 from coalition members to the Honorable Kevin Brady and the Honorable 

Sander Levin, urging retention of the section 45Q tax credit for carbon capture and utilization; see also 
- 39 -

utilizing power plant and industrial CO2 through EOR [enhanced oil recovery] yields additional 

American oil from existing wells that would otherwise not be accessed thereby expanding 

domestic reserves and reducing imports. The United States independent oil and gas industry is 

the world leader in CO2-EOR and could produce billions of barrels of additional American oil 

from existing fields, while safely and permanently storing billions of tons of CO2.”86

The standards of performance also serve to promote further development and 

implementation of carbon capture and sequestration technology. It is a documented phenomenon 

that national rules requiring large emission reductions have resulted in significant upswing in 

inventive activity to develop and perfect needed emission control technologies. 80 FR 64575.

The new source performance standard will not be an impediment to construction of new 

coal-burning capacity. Indeed, availability and deployment of carbon capture technology could 

prove a lifeline to the industry. As the scourge of climate change becomes increasingly manifest, 

the ability to use coal without substantially adding to CO2 emissions will be more and more 

important. The new source performance standard sends a strong signal that low-emitting coalburning capacity is feasible, and that coal can thereby have an important place in a lower-carbon 

energy future. As American Electric Power stated, “AEP still believes the advancement of CCS 

is critical for the sustainability of coal-fired generation.” 80 FR 64572.87 The petitions for 

reconsideration here present no information that cause the EPA to deviate from these findings 

and conclusions.

The petitions for review of UARG, Ameren, AEP, State of Wisconsin, and Energy and 

Environment Legal Institute are denied in their entirety.

 

parallel letter from the same coalition to Senators Orrin Hatch and Ron Wyden (April 4, 2016). These 

letters are part of the record for this action.

86 Id.

87 The quote is from “CCS LESSONS LEARNED REPORT American Electric Power Mountaineer CCS 

II Project Phase 1”, prepared for the Global CCS Institute project #PRO 004, January 23, 2012, p. 2. 

(EPA-HQ-OAR-2013-0495-11680).