5-1

Chapter 5

Reconstructed Fossil Fuel-fired Utility Boilers and IGCC Units

Contents

5.1 General................................................................................................................................. 3

5.2 Identification of BSER......................................................................................................... 5

Efficient IGCC unit as BSER ................................................................................................. 5

5.2.1 Technical Feasibility.......................................................................................................... 7

Disagree that BSER is a SCPC or SC CFB boiler for large sources, and the use of the 

highest available subcritical steam conditions for small sources.......................................... 10

Too many conditions to provide meaningful comments....................................................... 14

Coal refuse CFB.................................................................................................................... 15

5.2.2 Costs, Structure of the Energy Sector.............................................................................. 16

Reduced fuel costs for supercritical units not enough to make cost of generating electricity 

less compared to a subcritical EGU...................................................................................... 16

To evaluate cost of BSER, EPA should consider conversion cost from a subcritical to a 

supercritical boiler ................................................................................................................ 16

Proposal would necessitate costly conversion from subcritical to supercritical unit and 

create a disincentive for upgrades......................................................................................... 17

Required conversion from subcritical to supercritical means emission standard is not 

economically viable and would cause early retirement of coal-fired units .......................... 18

EPA solicited comment on having an upper capital cost threshold for reconstruction ........ 19

5.2.3 Incentive for Technological Innovation........................................................................... 20

EPA's objective is reducing air pollution, not incentivizing sources to avoid the purpose of 

the CAA ................................................................................................................................ 20

5.3 Determination of the Level of the Standard....................................................................... 21

Limits not achievable............................................................................................................ 21

More stringent standard for existing sources is backwards.................................................. 23

Unreasonable to apply standards of performance for reconstructed sources to modified 

sources................................................................................................................................... 24

Emissions standards are too lenient ...................................................................................... 24

Support mass-based standard................................................................................................ 25

5.3.1 Large Units Standard of 1,900 lb CO2/MWh; solicited comment on range of 1,700-2,100 

lb CO2/MWh ............................................................................................................................. 25

Limit is unachievable............................................................................................................ 25
5-2

Performance standards are not supported by an adequate technical analysis....................... 26

EPA reliance on information from one unit, Weston Unit 4, to support the proposed 1,900 

lbs CO2/MWh standard is inappropriate ............................................................................... 26

For the possible range of 1700 to 2100 lb CO2/MWh-net emissions for large units, a limit of 

2100 lb CO2/MWh-net is more reasonable........................................................................... 27

Technical justification for CO2 emission standards at the lower end of the range EPA is 

considering for reconstructed sources is not sufficient......................................................... 28

5.3.2 Small Units Standard of 2,100 lb CO2/MWh; solicited comment on range of 1,900-2,300 

lb CO2/MWh ............................................................................................................................. 28

Standard does not reflect BSER and is not achievable ......................................................... 28

5.4 Subcategories..................................................................................................................... 29

Additional subcategorization is warranted based on IGCC and utility boilers, boiler type and 

coal rank................................................................................................................................ 29

Subcategory for lignite.......................................................................................................... 33

Subcategory for coal refuse .................................................................................................. 33

Support for a case-by-case assessment for each utility boiler .............................................. 34

Applying national averages to individuals units rather than case-by-case basis.................. 36

Need for subcategories.......................................................................................................... 37

Subcategorize by fuel type and boiler configuration ............................................................ 38

Identify appropriate BSER for modified/reconstructed sources and apply to determine 

standards of performance achievable by the source category............................................... 39
5-3

5.1 GENERAL

Comment 5.1-1: Commenter 0215 stated that given the rarity of EGU reconstructions, EPA 

should withdraw the Proposed Standards and decline to set a standard. Commenter suggested 

EPA should explicitly deem this proposal economically infeasible - and therefore not a 

reconstruction - any situation where the imposition of the NSPS would result in an EGU shutting 

down.

Response 5.1-1: Yes, EGU reconstructions are rare. Even so, we also recognize (and we discuss 

in the preamble) that the power sector is undergoing significant change and realignment in 

response to a variety of influences and incentives in the industry. However, we have no way to 

predict which units may or may not decide to conduct a reconstruction. Therefore, it is 

appropriate to finalize standards in the event of such an occurrence.

Comment 5.1-2: Commenter 0215 stated that the reconstruction rule, which is codified in the 

generally applicable provisions of 40 C.F.R. part 60, applies to all of the nearly 100 NSPS source 

categories. Commenter quoted that "[a]n existing facility, upon reconstruction, becomes an 

affected facility, irrespective of any change in emission rate." 40 C.F.R. section 60.15(a). 

Commenter said the NSPS modification rule applies only to projects at existing facilities that 

"result[] in an increase in the emission rate to the atmosphere of any pollutant to which a 

standard applies." Id. section 60.14(a). Under the reconstruction rule, a reconstruction analysis is 

triggered when an owner or operator replaces the components of an existing facility to such an 

extent that "[t]he fixed capital cost of the new components exceeds 50 percent of the fixed 

capital cost that would be required to construct a comparable entirely new facility." Id. section 

60.15(b)(1). Commenter pointed out that a unit is not considered to be reconstructed, however, 

even if it meets the 50 percent threshold when meeting the applicable NSPS would be 

"technologically and economically" infeasible. Id. section 60.15(b). 

Commenter 0215 stated that EPA notes that "[h]istorically, few EGUs have undertaken 

reconstructions." 79 Fed. Reg. at 34,971. Commenter agreed with the Agency's 

observation. Commenter referred to the Pennsylvania v. Allegheny Energy, Inc, (No. 05-885, 

2014 WL 494574 (W.D. Pa. Feb. 6, 2014)) which rejected the reconstruction cost methodology 

applied by EPA's enforcement arm, and found that the projects at Armstrong Units 1 and 2 were 

not "reconstructions" because the capital cost of the new components did not exceed 50 percent 

of the capital cost needed to construct a comparable new facility. The states have appealed to the 

U.S. Court of Appeals for the Third Circuit, Pennsylvania v. Allegheny Energy, Inc., No. 14-

1584 (3d Cir. filed Mar. 11, 2014), and EPA has filed a notice of intent to support the appeal as 

amicus curiae. 

Commenter 0291 stated that EPA's existing general reconstruction rule codified in the general 

provisions of 40 (17.F.R. Part 60, applies to over a hundred categories of NSPS sources. An 

existing facility fails under the reconstruction rule "upon reconstruction, [...] irrespective of any 

change in emission rate." In contrast, the NSPS modification rule applies only where projects at 

existing facilities "resulti[ng in an increase in the emission rate to the atmosphere of any 

pollutant to which a standard applies," - Reconstruction is triggered when an owner or operator 

replaces the components at an existing facility to such an extent that the fixed capital cost of the 

new components exceeds 50 percent of the fixed capital cost that would be required to construct 
5-4

a comparable entirely new facility. A reconstructed unit is not required to meet the standards if 

doing so would be "technologically and economically" infeasible. EPA proposes that the BSER 

for reconstructed fossil fuel-fired boiler] and IGCC EGUs will the "the most efficient generating 

technology." This technology includes using "higher steam, temperature and pressure. Even if 

the boiler was not originally designed to do so." BSER for large sources is a supercritical 

pulverized coal or supercritical circulating fluidized bed boiler, while a subcritical pulverized 

coal or circulating fluidized bed boiler is BSER for small sources. EPA asserts that requiring 

supercritical technology for large sources is "technically feasible" because "supercritical steam 

conditions has !sic] been demonstrated by many facilities since the 1960s," and that the steam 

tubing and other equipment necessary to allow the use of the best demonstrated steam cycle can 

be replaced at any existing EGU. It maintains that a boiler that has been reconstructed to use this 

technology will produce fewer emissions than before and that no add-on technology to control 

emissions would be involved. EPA also asserts that this option is "economically feasible." It 

bases this assertion on a U.S. Department of Energy National Energy "Technology Laboratory 

theoretical study that estimated that a new supercritical boiler using subbituminous goal would 

emit 7 percent less CO2 per MWh at an additional cost of only 3% compared to a subcritical 

boiler. EPA observes that utility boilers are numerous and diverse in size and configuration," and 

acknowledges that it often -does not have sufficient information" about them.. However. The 

Department of Energy study examined only two units, both of which burn subbituminous coal 

and only recently began operation. The LK respectfully submits that EPA's current approach 

seeks to arbitrarily pursue a major rule that could apply to almost a thousand diverse EGUs. 

Many of which burn different coals. The LEC is not aware that any existing subcritical unit has 

ever been converted to a supercritical unit, and strongly believes it would be impractical to do so. 

EPA cannot therefore base its Proposed Rule on an as-yet-untested boiler conversion. Basing a 

proposed. Emission limits on an unlawfully unsupported BSER. EPA proposes that sources with 

a heat input above 2,000 MMBtu/h (large units) must meet an emission limit of 1,900 lb 

CO2/MWh-net while sources with a heat input equal to or less than 2.000 MMBtu/h (small units) 

must meet an emission limit or 2,100 lb CO2/MWh-net. EPA requests comment on a range of 

limits between 1,700 to 2.100 lb CO2/MWh-net for large units and between 1,900 to 2,300 lb CO 

2/MWK-net for small units, using a 12 operating-month rolling basis. The 1..EC believes that 

although some new state-of-art supercritical boilers might the able to achieve 1,900 lbs 

CO2/MWh-net for large coal-fired boilers, it is not possible for existing units undergoing 

reconstruction to do so. Even relatively new supercritical Units may not achieve 1,900 lbs 

CO2/MWh-net, depending on duty cycle, local environmental siting conditions, and water 

cooling method. In addition to issues concerning EPA's authority, the Proposed Rules for 

reconstructed units lack supporting technical justification and should therefore be withdrawn. 

Response 5.1-2: The EPA points out that triggering the reconstruction provision is a significant 

economic hurdle - and it has only rarely been done. Per 40 CFR 60.15 - 'Reconstruction' means 

the replacement of components of an existing facility to such an extent that: (1) the fixed capital 

cost of the new components exceeds 50 percent of the fixed capital cost that would be required to 

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

feasible to meet the applicable standards set forth in this part. 50% of fixed capital cost that 

would be required to construct an entirely new EGU would almost certainly involve significant -

and very costly investment (if not entire replacement of) the boiler. At that time, conversion from 

a subcritical boiler to a supercritical boiler can be done [or complete replacement with a new 
5-5

supercritical boiler]. However, if the owner/operator can show it is not "technologically and 

economically feasible to meet the applicable standards set forth in this part", then it would not 

trigger the reconstruction provisions. The EPA also points out here - and in the preamble in 

section VII - that owners/operators can also consider the use of natural gas co-firing to achieve 

the final emission limitation without the need to convert the subcritical boiler to supercritical. 

Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce air 

emissions of criteria and hazardous air pollutants. EPRI sponsored a study to assess both 

technical and economic issues associated with natural gas co-firing in coal-fired boilers and 

determined that the largest number of applications and the longest experience time is with natural 

gas re-burning and with supplemental gas firing. Natural gas re-burning - which can introduce up 

to 20 percent total fuel heat input - has been used primarily as a NOx control technology. Higher 

levels of natural gas co-firing can be met by utilizing supplemental gas co-firing (either alone or

along with natural gas re-burning). This involves the simultaneous firing of natural gas and 

pulverized coal in a boiler's primary combustion zone. Others have also evaluated configurations 

that would allow coal-fired units to utilize natural gas. A 2013 article entitled "Utility Options 

for Leveraging Natural Gas" [10/01/2013 article in Power. Available at 

http://www.powermag.com/utility-options-for-leveraging-natural-gas/] noted that: Utility owners 

of coal-fired power stations that wish to balance their exposure to coal-fired generation with 

additional natural gas-fired generation have several options to consider. The four most practical 

options are co-firing coal and gas in the same boiler, converting the coal-fired boiler to gas-only 

operation, repowering the coal plant with natural gas-fired combustion turbines, or replacing the 

coal plant with a combined cycle plant. [...] Co-firing is the lowest-risk option for substituting 

gas use for coal. 

According to EPA CAMD data (which is discussed in the TSD “Achievability of the Standard 

for Newly Constructed Steam Generating EGUs” available in the rulemaking docket), the best 

monthly rate for the AEP John W. Turk plant is 1,725 lb CO2/MWh-g. The unit’s best 12-

operating-month average rate is 1,753 lb CO2/MWh-g and its highest 12-operating-month 

average is 1,817 lb CO2/MWh-g. Since its startup the performance of the Turk facility has 

improved with time and its most recent emission rates are well below the 1,800 lb CO2/MWh-g 

final emission limitation for large reconstructed EGUs. 

5.2 IDENTIFICATION OF BSER

Efficient IGCC unit as BSER 

Comment 5.2-1: Commenter 0232 stated that if EPA does not adopt conversion to gas as BSER 

for reconstructed coal-fired EGUs, it should base the standard on performance of an efficient 

IGCC unit. The commenter stated that EPA did not fully consider an efficient IGCC unit as 

BSER for reconstructed coal-fired EGUs as they only stated that the DOE/NETL estimates that 

an IGCC unit emission rate is comparable to those achieved by a supercritical coal-fired EGU. 

The commenter stated that if EPA had fully considered efficient IGCC technology, they likely 

would have concluded it is the most efficient coal-fired generation technology available and that 

this technology supports an emission standard as low as 1,600 lb CO2/MWh net. The commenter 

presented the following reasons for its position that IGCC better satisfies the statutory criteria for 

BSER than the conventional, uncontrolled SCPC system that EPA has proposed:
5-6

-Technical feasibility. IGCC systems have been commercially available for years and are 

adequately demonstrated. In the proposed standards for new EGUs, EPA stated that generation 

technologies representing enhancements in operational efficiency (e.g., supercritical or ultrasupercritical coal-fired boilers or IGCC units) are clearly technically feasible and present little or 

no incremental cost compared to the types of technologies that some companies are considering 

for new coal- fired generation capacity. EPA's proposal for new units indicates that each of the 

coal-fired units EPA found to be in the advanced stages of construction and development utilizes 

IGCC. The technical literature confirms the technical feasibility of IGCC technology. EPA 

incorrectly suggested that IGCC technology could not achieve a lower emissions rate than an 

SCPC facility. Even five years ago, a new IGCC facility could achieve an emission rate of 1,745 

lb CO2/MWh net, substantially lower than the 1,900 lb/MWh net emission rate that EPA has 

proposed for large reconstructed coal-fired EGUs. Today, IGCC units with Shell Global 

Solutions gasifiers can achieve an emission rate of 1,595 lb CO2/MWh net. IGCC configurations 

using General Electric Energy and ConocoPhillips gasifiers can achieve rates of 1,723 lb 

CO2/MWh net and 1,710 lb CO2/MWh net, respectively. Accordingly, modern IGCC technology 

can readily achieve an emission standard between 1,600 and 1,700 lb CO2/MWh net. A facility 

that cannot feasibly meet this standard is not reconstructed (see 40 C.F.R. 60.15(b)(2) 

(establishing technological and economic feasibility as part of the definition of reconstruction). If 

site-specific challenges make it impossible for certain units to achieve an emissions rate between 

1,600 and 1,700 lb CO2/MWh net, those units would not be considered reconstructed sources and 

would be required to comply with state plans under section 111(d). 

-Emission reductions. Establishing a standard that is 200-500 lb CO2/MWh net lower than the 

one EPA has proposed can lead to significant emission reductions over the lifetime of a facility. 

Fossil fuel-fired utility boilers and IGCC units have lifespans of several decades. It is essential 

that EPA avoid policies that would allow the lock-in of high-emitting infrastructure.

-Costs. A reconstructed unit can deploy IGCC technology at reasonable cost, well below the 

legal standard for BSER. NETL estimates the levelized cost of electricity from an IGCC unit to 

be about $94 to $103/MWh (in 2007 dollars). This is slightly higher than the levelized cost of 

electricity from an SCPC unit, which NETL estimates to be $75/MWh (2007$). It is also 

comparable to the cost of electricity a new coal-fired EGU with partial CCS, which EPA 

estimated at approximately $110/MWh (2011$) excluding revenue from sale of the captured 

CO2. The cost of an IGCC unit is well within the range of costs determined to be appropriate by 

courts reviewing section 111 performance standards. Thus, cost considerations are not a barrier 

to selecting IGCC as BSER for these reconstructed units. EPA should also consider how changes 

in the regulatory environment may affect the relative costs of IGCC and SCPC units. The NETL 

report was based on a study that was conducted before EPA promulgated MATS and its cost 

projections assumed that the performance target for new IGCC and SCPC units would be a 

mercury emissions rate that is significantly less stringent than the finalized MATS standard for 

these units. The mandate to rigorously control mercury emissions may have eroded the SCPC 

units' cost advantage over IGCC.

-Non-air health and environmental impacts. Selecting an efficient IGCC facility as BSER would 

avoid significant impacts on water resources. IGCC facilities produce much less wastewater than 

SCPC facilities and consume less water than SCPC facilities.
5-7

-Innovation. EPA has the opportunity to spur significant innovation in IGCC technology. A 

recent study by EPRI identified several key technological advances that could contribute to 

increasing net plant efficiency at an IGCC facility with CCS by more than 11 percentage points 

while cutting the cost of electricity in half. Several of these innovations could improve efficiency 

and reduce costs at an IGCC facility that does not utilize CCS. For instance, advanced gas 

turbines with a firing temperature of 2900 F are predicted to increase efficiency by 5.5% and 

reduce the cost of electricity by 21% (measured in cost/MWhr). EPRI predicts that the capital 

costs of IGCC should come down as the technology matures and more units are constructed, but 

it is the next generation of technologies discussed in this roadmap that will have the most 

significant impact on the competitiveness of IGCC relative to other coal power technologies. 

Relying on IGCC technology is also consonant with deploying CCS technology. With currently 

available technology, CCS is generally more economical at an IGCC facility than at an SCPC 

facility. Each of the three coal-fired EGUs that are at an advanced stage of construction and 

development are utilizing CCS and IGCC technology together, taking advantage of opportunities 

for efficient deployment of CCS.

-Energy requirements and impacts on power sector. The net plant efficiency (measured on an 

HHV basis) is comparable at IGCC and SCPC facilities. Accordingly, basing BSER on the 

reductions achievable with efficient IGCC technology would not impose more burdensome 

energy requirements than an SCPC-based standard. In addition, selecting efficient IGCC 

technology as BSER would not have a significant impact on nationwide electricity prices, fuel 

diversity, the structure of the power sector, or electricity supply. EPA reasonably concluded that 

the proposed rule would not have significant impacts on these issues because few units are 

expected to undergo reconstructions and there are already strong incentives to utilize efficient 

generation technologies at these facilities, and the same analysis would apply to a standard based 

on IGCC.

Response 5.2-1: The EPA recognizes IGCC as an advanced technology that provides increased 

flexibility. However, on a net basis, the emission reductions are similar to those of a highly 

efficient SCPC and the EPA does not determine it to be the BSER for reconstructed sources.

5.2.1 Technical Feasibility

Comment 5.2-2: EPA misinterpreted or misused the Sargent & Lundy report to support its 

proposed standard and BSER. 

Commenter 0259 stated that in the unlikely event they modified or reconstructed a unit, such unit 

could not meet the emission reductions set out in the Proposed Rule. The commenter stated that 

perhaps such reductions are too stringent because the EPA misinterpreted or misused the key 

report it relies on to support its proposed standard and BSER. The commenter stated that the 

EPA reviewed the engineering studies available and selected the Sargent & Lundy 2009 study as 

the basis for its assessment of heat rate improvement potentials from equipment and system 

upgrades. In regard to that study, Sargent & Lundy recently confirmed to the commenter that 

they did not view the heat rate savings to be cumulative and that Sargent & Lundy believe the 

EPA misinterpreted the study results. See Sargent & Lundy letter to Jolin M. Meacham of NPPD 

dated September 16, 2014. The commenter stated that Dr. Raj Gaikwad, Sargent & Lundy's head 

of environmental services, made a presentation concerning potential heat rate savings and 
5-8

indicated that there is difficulty in generalization that every facility is different and that same 

solution cannot be applied. See presentation made by Dr. Gaikwad, Reducing CO2 Emissions 

through Improved Generation Efficiency, at 7. The commenter stated that the Nicholas Institute 

workshop published a report in January of 2013 which quotes Dr. Gaikwad as saying "the 

potential for improvements in heat rate is source-specific because that potential depends upon 

factors that differ from unit to unit: combustion type, fuel type, elevation, maintenance and 

retrofit history, and air controlled technology, to name a few." See Nicholas Institute, Regulating 

Carbon Dioxide under Section 111(d) of the Clean Air Act: Options, Limits and Impacts 

(January 2013), at pp. 12 and 13. The commenter stated that the report states that "Bilirgen and 

Gaikwad emphasize the difficulty in generalizing the potential for heat rate improvements in 

units across the nation absent calculations on a granular, unit-by-unit level." The commenter 

stated that the Sargent & Lundy study used by EPA stated that all estimated capital and 

installation costs were as of the year 2008. See attachment of Sargent & Lundy letter to Jolin M. 

Meacham of NPPD dated September 16, 2014 The commenter stated that the study goes on to 

warn that: "S&L cautions that the costs presented herein are not indicative of those that may be 

expected for a specific facility due to variables such as equipment, material, and labor market 

conditions and site specifications." Sargent & Lundy, Coal-Fired Power Plant Heat Rate 

Reductions, at 1-3 (Jan. 22, 2009). The commenter stated that heat rate improvement projects can 

be very costly and reliance on S&L's 2008 cost estimates for non-specific plants do not comport 

with Section 111(a)(1)'s requirement that the cost of achieving emission limitations must be 

taken into account. The commenter stated that the EPA's apparent misunderstanding or confusion 

concerning the Sargent & Lundy report underscores the fact that the EPA has not shown that its 

proposed BSER is achievable, cost effective or adequately demonstrated. The commenter 

recommended that the EPA adopt a unit specified assessment and thereafter a unit-specific 

emission limit for modified or reconstructed sources. Such a plan would not depend on the 2009 

S&L study as a basis.

Response 5.2-2: The S&L study was not used to develop standards for reconstructed sources. 

Comments related to use of the S&L study have been addressed in Chapter 6 of this RTC.

Comment 5.2-3: Commenter 0215 stated EPA's proposed BSER determination is based on data 

from only two units that do not address feasibility at the nearly one thousand diverse EGUs 

throughout the country, many of which burn different coals than those assessed in the studies 

EPA cites. No subcritical unit has ever been converted to a supercritical unit, and it would be 

impractical to do so. Conversion to supercritical steam conditions, therefore, has not been 

adequately demonstrated for subcritical EGUs that undertake reconstructions. 

Commenter 0215 continued that any control technology selected as BSER must be "adequately 

demonstrated." The D.C. Circuit has held that a system that has been adequately demonstrated is 

"one which has been shown to be reasonably reliable, reasonably efficient, and which can 

reasonably be expected to serve the interests of pollution control without becoming exorbitantly 

costly in an economic or environmental way." Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 

433 (D.C. Cir. 1973); see also Natural Res. Def. Council v. Thomas, 805 F.2d 410, 428 n.30 

(D.C. Cir. 1986). Commenter concluded that an adequately demonstrated system must have an 

operational history that shows more than mere technical feasibility. It must be dependable, 

effective, and affordable for individual sources, based on actual operating experience within the 

source category or at sufficiently similar sources. Moreover, a technology must be adequately 
5-9

demonstrated for all sources within a category or subcategory and available for each source type 

to which the standard will apply. For example, in its 2005 proposed revisions to the NSPS for 

Subpart Da units, EPA rejected supercritical boiler design, IGCC technology, and the use of 

clean fuels as potential bases for its revised standards due in part to the unavailability of these 

options across source types to which the standards would apply. 70 Fed. Reg. 9706, 9712, 9714, 

9715 (Feb. 28, 2005). Commenter said the conversion of subcritical units to supercritical units 

has not been adequately demonstrated by any stretch of the imagination.

Commenter 0289 stated doubt that the vast majority of supercritical units could meet these 

standards "taking into account the cost of achieving such reduction;" it would not be 

technologically and economically feasible. Commenter said EPA asserts that requiring 

supercritical technology for large sources is "technically feasible" because "[t]he use of 

supercritical steam conditions has been demonstrated by many facilities since the 1960s." While 

supercritical steam technology itself may be a feasible technology, there is insufficient evidence 

to demonstrate that reconstructed supercritical units could comply with the proposed limits. 

Further, there is absolutely no demonstration that a reconstructed subcritical unit can be 

reconstructed in the form of a compliant supercritical unit. A supercritical unit cannot be re-built 

on the site of a subcritical power plant without essentially requiring the construction of a power 

plant with a completely different design. Commenter said there is much more to converting a 

subcritical plant to a supercritical plant than "replace the steam tubing and other necessary 

equipment." Numerous support facilities and infrastructure would have to change, pushing these 

changes far beyond technological and economic feasibility. Furthermore, the regulations state 

that the 50-percent threshold that triggers reconstruction requirements is based on the "fixed 

capital cost that would be required to construct a comparable entirely new facility," but 

subcritical and supercritical units are not comparable-they are far too distinct to use a 

supercritical unit to set the triggering threshold for subcritical units. Ultimately, the standards 

proposed by EPA for reconstructed units cannot be met. Commenter said EPA must impose 

more lenient limits for supercritical units, as those limits currently proposed are not achievable. It 

must then also create categories for subcritical units, with correspondingly less onerous 

standards. Furthermore, within each of those primary categories (subcritical and supercritical), it 

must then create fuel-specific subcategories. There must be subcategories for lignite, with further 

relaxed emissions limits and standards that reflect the unique characteristic of the fuel and the 

design of the facilities to burn the fuel. 

Commenter 0215 stated EPA acknowledges that the existing fleet of fossil fuel-fired steam 

generating boilers is "numerous and diverse in size and configuration" and that it often "does not 

have sufficient information" about them, but EPA's TSD for reconstruction nevertheless attempts 

to support its proposal based on a study of two brand new units that recently commenced 

operation, both of which burn subbituminous coal. Commenter argued that the record is 

insufficient to support a rule that could apply to almost a thousand diverse EGUs, many of which 

burn different types of coal. Commenter highlighted a key point from one of their attachments 

from one of their consultants, that no existing subcritical unit has ever been converted to a 

supercritical unit, and it would be impractical to do so. See Cichanowicz Heat Rate Report at 4-

2. Commenter said it is arbitrary and speculative for EPA to base its proposed reconstruction rule 

on a radical boiler conversion that has never been undertaken; therefore, the proposed NSPS is 

unlawful because EPA has failed to demonstrate that it is adequately demonstrated, achievable, 
5-10

or even feasible, across the entire source category. Commenter said BSER for all coal-fired units, 

except those that are already designed to be supercritical units, should be their original 

subcritical design. 

Response 5.2-3: With regard to the comment that "no existing subcritical unit has ever been 

converted to supercritical technology since it is economically impractical", the EPA points out 

that triggering the reconstruction provision is a significant economic hurdle - and it has only 

rarely been done. Per 40 CFR 60.15 - 'Reconstruction' means the replacement of components of 

an existing facility to such an extent that: (1) the fixed capital cost of the new components 

exceeds 50 percent of the fixed capital cost that would be required to construct a comparable 

entirely new facility, and (2) it is technologically and economically feasible to meet the 

applicable standards set forth in this part. 50% of fixed capital cost that would be required to 

construct an entirely new EGU would almost certainly involve significant - and very costly 

investment (if not entire replacement of) the boiler. At that time, conversion from a subcritical 

boiler to a supercritical boiler can be done [or complete replacement with a new supercritical 

boiler]. However, if the owner/operator can show it is not "technologically and economically 

feasible to meet the applicable standards set forth in this part", then it would not trigger the 

reconstruction provisions. Importantly, the EPA notes that the reconstructed unit is not required 

to convert a subcritical boiler to a supercritical boiler – the EPA does not specify any particular 

technology that must be used. Rather the reconstructed unit must meet a standard of performance 

consistent with the emission reductions achieved by the BSER. Owners/operators can consider 

other options – such as the use of natural gas co-firing to achieve the final emission limitation 

without the need to convert the subcritical boiler to supercritical. Natural gas co-firing has long 

been recognized as an option for coal-fired boilers to reduce emissions of air pollutants.

Disagree that BSER is a SCPC or SC CFB boiler for large sources, and the use of the 

highest available subcritical steam conditions for small sources

Comment 5.2-4: Several commenters (0146, 0149, 0149, 0152, 0158 0160, 0171, 0177, 0183, 

0187, 0195, 0199, 0203 0214, 0222, 0226, 0227, 0239, 0242, 0249, 0278) disagreed with the 

EPA's proposed BSER for reconstructed fossil fuel-fired utility boilers and IGCC units: that 

BSER is a supercritical pulverized coal or supercritical circulating fluidized bed boiler for large 

sources, and the use of the highest available subcritical steam conditions for small sources; that 

supercritical technology for large sources is technically feasible because the use of supercritical 

steam conditions has been demonstrated by many facilities since the 1960s and that the steam 

tubing and other equipment necessary to allow the use of the best demonstrated steam cycle can 

be replaced at any existing EGU; that such a redesigned boiler would result in fewer emissions 

and that no add-on technology to control emissions would be involved and that this option is 

economically feasible based on a DOE NETL theoretical study that estimated that a new 

supercritical boiler using subbituminous coal would emit 7 percent less CO2 per MWh at an 

additional cost of only 3 percent when compared to a subcritical boiler; and that the proposed 

emission limits would be 1,900 lb CO2/mwh-net for units with a heat input of greater than 2,000 

mmbtu/h or 2,100 lb CO2/mwh-net for sources with a heat input of 2,000 mmbtu/h or less.

Several commenters (0146, 0150, 0167, 0171, 0177, 0183, 0201, 0214, 0222, 0224, 0229, 0249, 

0254, 0277) stated that the EPA had provided no evidence that the proposed BSER is 

technologically feasible nor a demonstration that the standard can be met.
5-11

Commenter 0227 stated that comparing the cost of constructing a new unit of one design versus 

another design reveals nothing about the cost to "reconstruct" an existing unit for duty it was 

never designed initially to accommodate. The commenter stated that a reconstruction analysis is 

most likely to be undertaken if there has been a catastrophic event that has damaged a sufficient 

number of the components that make up the "affected facility" that complete replacement of the 

damaged components is required. The commenter stated that while such replacements may 

present some opportunities to rebuild with materials that are capable of accommodating the 

higher pressures and temperatures that are employed in supercritical units, the ability to do so in 

an economically feasible fashion will depend almost entirely on the components that need to be 

replaced. Even then, supporting supercritical operations may require the addition of components 

not present in the original steam generator configuration for which there is no space, including 

steam reheat cycles as proposed by EPA, making the conversion technically infeasible. EPA has 

no basis for its assumption that such reconstructions are possible, let alone economical.

Commenter 0222 stated that a supercritical unit cannot be re-built on the site of a subcritical 

power plant without essentially requiring the construction of a power plant with a completely 

different design. The commenter stated that there is much more to converting a subcritical plant 

to a supercritical plant than replacing the steam tubing and other necessary equipment; numerous 

support facilities and infrastructure would have to change, pushing these changes far beyond 

technological and economic feasibility. The commenter stated that furthermore, the regulations 

state that the 50 percent threshold that triggers reconstruction requirements is based on the fixed 

capital cost that would be required to construct a comparable entirely new facility, but subcritical 

and supercritical units are not comparable - they are far too distinct to use a supercritical unit to 

set the triggering threshold for subcritical units. 

Commenter 0226 stated that the EPA estimated capital costs of a SCPC EGU (3 percent greater 

than a subcritical unit) does not demonstrate that the proposed standards for reconstructed coalbased boilers and IGCC units are achievable in a modified/reconstructed unit context. The 

commenter stated that such a cost does not appear the meet the second prong of the test of a 

reconstructed unit test. That is, that the component replacement constitutes a reconstruction only 

if it is technologically and economically feasible for the source to meet the applicable standards.

Commenter 0149 stated that EPA's Reconstructed Memorandum discusses EPA's efforts to 

project achievable emission rates through the hypothetical reconstruction of a small sample of 

existing coal-based units and that as part of these hypothetical reconstructions, EPA alters not 

only the boiler and steam cycle, but also requires that units use different coal ranks and install 

different cooling systems and then concludes that the resulting standard has been demonstrated 

as nationally achievable. The commenter stated that these types of wholesale changes likely 

would be equal to or more expensive than building an entirely new, completely different new 

unit, in part because EPA is requiring the construction of an entirely new unit. The commenter 

stated that in essence, the proposed BSER and standards for reconstructed units prohibit 

reconstructions and standards that effectively prohibit reconstructions are, by definition, 

unachievable, regardless of EPA's hypothetical projections about potential emission rates.
5-12

Commenter 0160 stated that utilities would likely be forced to build new power plants, rather 

than attempt compliance with the EPA's proposed reconstruction rules and that new power plants 

may not represent the most efficient allocation of utility resources creating unnecessary costs that 

would be passed along to customers through higher power prices. The commenter stated that the 

EPA has also not addressed the most likely form of reconstruction, the conversion of boilers to 

burn natural gas rather than coal.

Commenter 0169 stated that in the BSER Memo, EPA discusses the design parameters for the 

most efficient power plant inferring that all modified or reconstructed power plants should utilize 

all the technologies discussed. See BSER Memo, pp. 2-5. The commenter stated that all of these 

ideal design parameters may not be feasible, practical, economical, or possible to use at every 

modified or reconstructed facility. The commenter stated that, for example, EPA discusses that 

once-through cooling systems have an efficiency advantage over recirculating systems, yet 

power generating facilities are under constant barrage from environmental advocacy groups to 

replace existing once-through cooling with recirculating cooling tower technology. The 

commenter stated that under the Clean Water Act 316(b) Phase I requirements it is virtually 

impossible to construct a new large power plant without utilizing recirculating system cooling 

tower technology to meet these requirements. The commenter stated that in an effort to optimize 

efficiency within the required cooling tower recirculating system, the commenter's facility was 

designed and constructed using advanced cooling tower packing. The commenter stated that as 

this example shows, when modifying or reconstructing a new power plant, every ideal design 

parameter cannot be met, and choices are made that influence other design parameters.

Commenters (0146, 0249) stated that EPA attempts to support the proposed standards in a TSD 

based on a DOE NETL study of two units that recently commenced operation, both of which 

burn subbituminous coal. The commenters stated that this is an inadequate basis to demonstrate 

achievability of a standard that could apply to a category of sources that are numerous and 

diverse in size and configuration, that vary in age, and that use different ranks of coal. The 

commenters stated that for this reason alone the proposed NSPS is unlawful because EPA has 

failed to demonstrate that it is achievable, or even feasible, across the entire source category. The 

commenters stated that they are not aware that any existing subcritical unit has ever been 

converted to a supercritical unit, and strongly believes it would be impractical to do so

Commenter 0146 stated that EPA has proposed to base its NSPS for large modified Subpart Da 

units on a system that has never been demonstrated; no existing subcritical unit has ever been 

converted to a supercritical unit, and it would be impractical and exorbitantly expensive to do so. 

The commenter stated that EPA may be correct that many units have been constructed that 

incorporate supercritical steam design, but that is irrelevant to whether an existing subcritical 

utility boiler's owner can, at reasonable cost, redesign the entire facility to accommodate 

dramatically increased steam temperature and pressures. The commenter stated that as a practical 

matter, it would never be technologically and economically feasible for a source to undertake 

such a radical boiler conversion, meaning that no source would ever qualify as reconstructed; the 

proposed NSPS would therefore be meaningless.

Commenter 0222 stated that under the proposed rule, reconstructed sources would be able to 

comply with an emissions limit that would be achievable at a supercritical steam turbine. The 
5-13

commenter stated that they do not believe that the vast majority of even supercritical units would 

be able to meet these standards taking into account the cost of achieving such reduction; it would 

not be technologically and economically feasible. The commenter stated that while supercritical 

steam technology itself may be a feasible technology, there is insufficient evidence to 

demonstrate that reconstructed supercritical units could comply with the proposed limits and 

there is no demonstration that a reconstructed subcritical unit can be reconstructed in the form of 

a compliant supercritical unit.

Commenter 0183 stated that EPA's proposed standards for reconstructed units fail to recognize 

the extraordinary nature of converting a subcritical unit to supercritical operation. The 

commenter stated that such a rebuild would involve an unprecedented steam condition 

conversion from a lower energy steam (subcritical) to a higher energy process (supercritical). 

The commenter stated that not only is such a conversion not economical, it would require the 

replacement of pressure parts on a massive scale and result in an extremely long outage. The

commenter stated that while new supercritical units can be constructed, their mere existence does 

not make a retrofit of existing units to this type of unit adequately demonstrated. The commenter 

stated that even if conversion were possible, EPA provides no evidence that the unit, particularly 

lignite unit, would be able to meet the standard proposed by EPA.

Commenter 0201 stated EPA proposed that BSER for reconstructed units is "the most efficient 

generating technology". The commenter agreed, in general, that efficient generating technology 

does represent BSER, but said the technology could vary depending on the type of unit that is in 

place at the facility. The commenter stated that a source should not be expected to alter their 

original unit design to accommodate an entirely different technology that EPA deems is more 

efficient.

Commenter 0242 stated that they have concerns with EPA setting a limit with the assumption all 

units that would fall under the applicability of this section would be able to reconstruct the boiler 

to use higher steam temperature and pressure, even if the boiler was not originally designed to do 

so because there may be cases where this is not physically and/or economically feasible. The 

commenter stated that the United States' first ultra super critical boiler (AEP Turk) was 

commissioned for commercial operation in December of 2012 and was designed from the ground 

up. The commenter stated that there has been insufficient time to determine the long-term 

efficiency of this unit and to attempt to apply this type of efficiency to modified and 

reconstructed units is premature and without foundation.

Commenter 0183 stated that their engineering consultant, with substantial experience in coalfueled power plant design and air quality control system retrofits, reports that it has never been 

engaged in a project where a subcritical to supercritical conversion was considered, much less 

undertaken. The commenter stated that setting BSER for reconstruction at the emission level for 

supercritical units completely eliminates the reconstruction of an existing unit as a viable 

business decision. The commenter stated that EPA may justify this extreme decision by saying 

that reconstruction is unlikely, but the likelihood of reconstruction is not a legal consideration in 

setting BSER under the CAA.

Several commenters (0149, 0160) stated that there is only one supercritical CFB in the world, 

located in Poland and EPA has not explained how a single operational unit can serve to 
5-14

adequately demonstrate that reconstruction of an existing unit is "achievable" as a system of 

emission reduction, as required by CAA section 111(a)(1). Commenter 0149 stated that from an 

engineering standpoint, the supercritical conditions described by EPA as BSER could, in fact, 

offset the advantages of using CFB technology, since CFB units are designed to operate at low 

temperatures, in part to minimize nitrogen oxide formation.

Commenter 0153 stated that subcritical, supercritical and CFB EGUs are so different in so many 

basic ways that it is not possible for EPA to justify the conclusion that it is technically feasible to 

convert to SCPC or CFB; even it were possible, the conversion costs would be excessive (far 

from reasonable) and the resulting decrease in CO2 emissions rate small in comparison to the 

cost. The commenter stated that the only example that EPA gives where changes in production 

technology are used as BSER is the Kraft Pulp Mill NSPS; pulp and paper mills are complex 

manufacturing facilities where production technologies are routinely improved, which is not the 

case for EGUs.

Response 5.2-4: Triggering the reconstruction provision is a significant economic hurdle - and it 

has only rarely been done. Per 40 CFR 60.15 - 'Reconstruction' means the replacement of 

components of an existing facility to such an extent that: (1) the fixed capital cost of the new 

components exceeds 50 percent of the fixed capital cost that would be required to construct a 

comparable entirely new facility, and (2) it is technologically and economically feasible to meet 

the applicable standards set forth in this part. A project that entails costs that are 50% or greater 

of fixed capital cost that would be required to construct an entirely new EGU would almost 

certainly involve very significant - and very costly - investment (if not entire replacement of) in 

the boiler. At that time, conversion from a subcritical boiler to a supercritical boiler can be done 

[or complete replacement with a new supercritical boiler]. Commenters claim that such a 

conversion would be technically or economically infeasible. The EPA disagrees – however, if 

the owner/operator can demonstrate it is not "technologically and economically feasible to meet 

the applicable standards set forth in this part", then it would not trigger the reconstruction 

provisions. Importantly, the EPA notes that the reconstructed unit is not required to convert a 

subcritical boiler to a supercritical boiler – the EPA does not specify any particular technology 

that must be used. Rather the reconstructed unit must meet a standard of performance consistent 

with the emission reductions achieved by the BSER. Owners/operators can consider other 

options – such as the use of natural gas co-firing to achieve the final emission limitation without 

the need to convert the subcritical boiler to supercritical. Natural gas co-firing has long been 

recognized as an option for coal-fired boilers to reduce emissions of air pollutants.

Too many conditions to provide meaningful comments 

Comment 5.2-5: Commenter 0242 stated that they cannot provide meaningful comments on this 

proposal. The commenter stated that the EPA proposed a small and large unit category for both 

utility boilers and IGCC units that are reconstructed yet acknowledges subcategorizing by 

primary fuel type may be necessary, that it may be necessary to restrict the smaller category to 

boilers so that all IGCC units would be in the large category regardless of size, or as an 

alternative possibility, eliminating the small category all together and subjecting all to the larger 

category standard. The commenter stated that there are too many variables that the EPA has 

introduced to evaluate as possibilities against the different standards and ranges presented and, 

compounding the issue is that all these options are to be considered in conjunction with the 
5-15

multitude of changes being considered regarding applicability. The commenter stated that while 

it is apparent the lower end of the range is not achievable, it may be possible the higher end of 

the range could be achievable for some types of units, but the EPA has not provided enough 

specificity for the commenter to determine the achievability of the proposed standards of 

performance; thus, the commenter is not able to provide meaningful comments.

Response 5.2-5: The EPA often solicits comment on a range of potential regulatory approaches. 

The proposed standards for modified and reconstructed sources contained a range of potential 

options. However, the proposal was not so complex as to make it no understandable. The 

number of informed and thoughtful comments received on the proposal is testament to its clarity.

Coal refuse CFB

Comment 5.2-6: Commenter 0182 stated that coal refuse CFB's control of acid gases for MATS 

compliance is based on limestone injection into the bed of the boiler, which increases CO2

emissions over those of conventional fossil fuel fired plants due to the CO2 released when the 

limestone calcines in the boiler and also due to the additional fuel needed to calcine the 

limestone with estimated CO2 increases of 8-9% based simply on MATS compliance. The 

commenter stated that Cross States Air Pollution Rules (CSPAR) considerations may require 

further increases in limestone consumption and further increases in CO2 generation. The 

commenter stated that coal refuse CFBs are limited to the fuel they have available within 

reasonable transportation distances and that this fuel has degraded in heat content and increased 

in sulfur content over the lives of the plants. The commenter stated that as the heat content 

decreases the efficiency generally decreases and as sulfur increases more limestone is required, 

both of which contribute to increased CO2 emissions. Fuel changes that are forced on the plants 

by the changing availability of appropriate fuel make it impossible to establish a CO2 emission 

rate that can be consistently met. The commenter stated that coal refuse CFBs are also under 

pressure from the economics of operation and the reduced price of electricity in the markets in 

which they operate resulting in increased operation at reduced loads, which also impacts 

efficiency negatively. The commenter stated that while all of the above factors make it 

impossible for a coal refuse CFB to meet historically demonstrated levels of CO2 emissions, 

there is no technological solution for such plants as there aren't any scrubber technologies that 

can be employed; carbon capture and sequestration is not a BSER technology; and co-firing with 

natural gas, even where available is not BSER by EPA's own determination. The commenter 

stated that because of the myriad of factors that make it impossible to capture CO2 emissions 

from coal refuse CFBs and the lack of available BSER to capture the CO2, it is not feasible to 

establish performance standards for coal refuse CFBs. The commenter stated that since 

performance standards are not feasible, and since the Administrator is authorized, under Section 

111(h) to promulgate a work practice standard in those circumstances, that a work practice 

standard is the only feasible approach for coal refuse CFBs to minimize CO2.

Response 5.2-6: Readers are directed to response to a very similar comment in Chapter 6 of this 

RTC.
5-16

5.2.2 Costs, Structure of the Energy Sector

Reduced fuel costs for supercritical units not enough to make cost of generating electricity 

less compared to a subcritical EGU 

Comment 5.2-7: One commenter 0149 stated that EPA is incorrect in stating that reduced fuel 

costs are significant enough that the overall cost to generate electricity is actually lower for a 

supercritical pulverized coal EGU compared to a subcritical EGU and that the emission 

reductions are cost effective for larger EGUs. The commenter stated that a 2006 paper 

evaluating the performance of existing supercritical and subcritical units noted that when 

deciding between building a supercritical or a subcritical unit, reduced fuel costs (where 

supercritical processes have an advantage over subcritical due to their higher efficiency) was not 

the only variable for operators to consider. See Anthony J. Carrino and Richard B. Jones, 

Modeling New Coal Projects: Supercritical or Subcritical?, Power Engineering (Nov. 1, 2006), 

The commenter stated that the lower fuel costs of a higher efficiency supercritical unit have to be 

balanced against a supercritical unit's higher initial capital costs, higher operation and 

maintenance costs and more frequent outage rates. The commenter stated that the authors also 

observed that, while a supercritical unit can have a five to 10 percent efficiency advantage over a 

subcritical unit, part of this advantage can be attributed to economic dispatch models keeping the 

supercritical units at a higher load level than subcritical units. The commenter stated that given 

EPA's expected shift towards greater dispatch of existing natural gas-based units under the 

proposed section 111(d) guidelines, which will likely decrease coal-based unit utilization rates, it 

is not clear what cost advantage a supercritical unit would realistically provide.

Response 5.2-7: The most important difference between subcritical and supercritical units in this 

case is the difference in the emissions of CO2. As noted, the CO2 emissions from a well 

performing supercritical unit are significantly lower than those of a well performing subcritical 

unit. Triggering the reconstruction provision is a significant economic hurdle - and it has only 

rarely been done. However, in the event that a unit does trigger the reconstruction provisions, the 

reconstructed unit would not required to convert a subcritical boiler to a supercritical boiler – the 

EPA does not specify any particular technology that must be used. Rather the reconstructed unit 

must meet a standard of performance consistent with the emission reductions achieved by the 

BSER. Owners/operators can do so by installing a new supercritical boiler, or by converting a 

large subcritical boiler to supercritical conditions or by utilizing other options – such as the use 

of natural gas co-firing to achieve the final emission limitation without the need to convert the 

subcritical boiler to supercritical. Natural gas co-firing has long been recognized as an option for 

coal-fired boilers to reduce emissions of air pollutants. In any case, per 40 CFR 60.15, if the 

owner/operator can demonstrate it is not "technologically and economically feasible to meet the 

applicable standards set forth in this part", then it would not trigger the reconstruction provisions.

To evaluate cost of BSER, EPA should consider conversion cost from a subcritical to a 

supercritical boiler 

Comment 5.2-8: Commenter 0214 stated that EPA did not appropriately evaluate the cost of its 

BSER determination for reconstructed boilers and IGCCs. The commenter stated that in 
5-17

justifying the cost reasonableness of an existing subcritical unit converting to a supercritical unit, 

the Agency compared the capital cost of a new subcritical pulverized coal boiler and a new 

supercritical pulverized coal boiler. The commenter stated that this comparison is inappropriate 

and EPA must consider the incremental costs incurred to implement BSER, which is the 

conversion cost from a subcritical to a supercritical boiler. The commenter stated that they

believe an appropriate cost analysis will demonstrate that EPA's BSER cannot be implemented at 

a reasonable cost.

Response 5.2-8: In the event that a unit does trigger the reconstruction provisions – which, for 

EGUs, has only rarely occurred – the reconstructed unit would not be required to convert from a 

subcritical boiler to a supercritical boiler – the EPA does not specify that any particular 

technology must be used to meet the final standard. Rather the reconstructed unit must meet a 

standard of performance consistent with the emission reductions achieved by the BSER. 

Owners/operators can do so by installing a new supercritical boiler, or by converting a large 

subcritical boiler to supercritical conditions or by utilizing other options – such as the use of 

natural gas co-firing to achieve the final emission limitation without the need to convert the 

subcritical boiler to supercritical. Natural gas co-firing has long been recognized as an option for 

coal-fired boilers to reduce emissions of air pollutants. Regarding cost – a reconstruction project 

that exceeds 50% of fixed capital cost that would be required to construct an entirely new EGU 

would almost certainly involve very significant cost and likely considerable investment in (if not 

entire replacement of) the boiler. At that time, conversion from a subcritical boiler to a 

supercritical boiler can be done. In any case, per 40 CFR 60.15, if the owner/operator can 

demonstrate it is not "technologically and economically feasible to meet the applicable standards 

set forth in this part", then it would not trigger the reconstruction provisions.

Proposal would necessitate costly conversion from subcritical to supercritical unit and 

create a disincentive for upgrades

Comment 5.2-9: Several commenters (0149, 0183) stated that the proposal would be too costly 

and a disincentive to upgrade units.

Commenter 0183 stated that the conversion of a coal-fired power plant from subcritical steam 

conditions to supercritical steam conditions, which EPA's standard would essentially require,

means the steam pressure must be increased from a typical operating pressure of 2,400 psig to 

3,600 psig. The commenter stated that while some of the plant components and a portion of the 

steam cycle equipment could be retained, the following pieces of equipment would likely require 

replacement if converting a subcritical unit to a supercritical unit: 

- Boiler pressure parts (water walls, economizer, superheaters, reheaters, etc.)

- High pressure steam turbine

- Main steam piping

- Boiler feed pump and driver

- High pressure feedwater heaters

- Boiler feed piping

The commenter stated that these components, in aggregate and installed at the same time during 

a one-time retrofit of a unit, represent a significant investment and one that most operators would 
5-18

decline to make. The commenter stated that their engineering consultant estimates the current 

cost to replace the equipment listed above to be between $300 million to $500 million for a 

typical unit.

Response 5.2-9: The commenter is concerned about the cost to replace the listed equipment. 

However, a reconstruction project that exceeds 50% of fixed capital cost that would be required 

to construct an entirely new EGU would almost certainly involve very significant cost and likely 

considerable investment in (if not entire replacement of) the boiler – including, likely, many of 

the pieces of equipment listed. 

Required conversion from subcritical to supercritical means emission standard is not 

economically viable and would cause early retirement of coal-fired units 

Comment 5.2-10: Commenter 0183 stated that by requiring the conversion from subcritical to 

supercritical, EPA is establishing an emission standard that is not economically viable for an 

existing source. The commenter stated that where a generator might otherwise consider building 

a new supercritical unit, the New Unit Proposal eliminates that as a viable alternative; thus the 

reconstruction standard effectively would require the replacement of the unit and appears to 

force early retirement of coal-fueled equipment. The commenter stated that this is not setting a 

standard of performance, it is mandating shutdown. The commenter stated that, if subjected to 

the proposed standard, those coal-fueled EGUs that invested in control equipment to comply 

with the MATS would be left with stranded investments, having spent millions of dollars to 

remain operational and comply with EPA's other rules.

Commenter 0242 stated that they are concerned that some changes required to meet the standard 

of performance under this proposal or under the proposal for existing sources, such as a 

reconstruction of a subcritical unit to a supercritical unit, may necessitate replacement of the 

entire footprint at the unit/facility. The commenter stated that they are very concerned over the 

EPA's interpretation under this proposal with regards to when reconstructed units become new 

units. The commenter stated that the EPA is proposing that replacement of the entire footprint 

would qualify the change as a new unit and therefore subject the unit to the new unit CSS 

provisions. The commenter stated that the EPA must be careful to ensure changes made to a unit 

that are necessary to comply with these rules (or the Section 111(d) rules) are not excluded as an 

option thereby creating a disincentive for meaningful reductions in CO2 that could occur.

Commenter 0242 is concerned that this proposal, in conjunction with the Section 111(d) 

proposal, will provide a disincentive for coal-fired plant owners to commit to a major upgrade of 

their plants to gain efficiency. According to the commenter, upgrading a supercritical boiler to an 

ultra-supercritical would likely exceed the 50 percent cost threshold necessary to trigger the 

definition of "reconstruction." The commenter stated that this rule then requires the source to 

submit information to the EPA for a determination of whether the proposed upgrade qualifies as 

a "reconstruction"; in making that determination EPA states that, "it is EPA's view that a unit that 

entirely, or for all practical purposes, completely replaces an existing sources by being 

constructed on the replaced source's existing footprint would also constitute a newly constructed 

source." The commenter stated that under this interpretation, any regulated entity that intends to 

invest in an upgrade to ultra-supercritical for efficiency purposes and to decrease their heat rate, 

will then qualify as a "new" source and be subject to the proposed CCS obligations. The 
5-19

commenter stated that while the EPA has stated that they do not expect any new coal-fired power 

plants to be built, this interpretation of reconstruction will effectively prevent any established and 

well demonstrated advancements in efficiency at existing plants too, reinforcing the concept that 

the Section 111(b) and Section 111(d) rules are designed to reduce the use of, or eliminate, coalfired power plants.

Response 5.2-10: The commenters confuse a “reconstruction” with smaller projects to improve 

the heat rate or even modifications. A reconstruction project is one that exceeds 50% of fixed 

capital cost that would be required to construct an entirely new EGU. Such projects have been 

historically rare in EGUs. Utilities have not undertaken such projects in the past as a means of 

improving efficiency or heat rate or to prolong the operating life of a unit. Thus this final 

standard will not discourage investment in efficiency projects.

EPA solicited comment on having an upper capital cost threshold for reconstruction 

Comment 5.2-11: Commenter 0192 opposed such an upper threshold for reconstruction stating 

that regardless of the scope of capital expenditures associated with a reconstruction project, an 

existing facility is always limited to some degree by prior design decisions and, therefore, lacks 

the same degree of flexibility that is available to newly constructed sources. The commenter 

stated that while a newly constructed coal-fired EGU could, in theory, be designed in a manner 

that could accommodate partial CCS technology, the same is not true for an existing source 

undergoing modification. The commenter stated that, for example, an existing facility may lack 

the space to incorporate a carbon capture system and may lack access to the pipeline 

infrastructure and CO2 storage areas needed to implement CCS; thus, as long as a project 

qualifies as a reconstruction project under existing regulatory criteria rather than as new 

construction, it should be subject to the reconstructed source standard. The commenter stated 

further that establishing an upper threshold for reconstruction could produce perverse and 

unintended consequences as reconstruction projects are typically designed to maximize 

economic and environmental benefits, but establishing an upper threshold may cause facilities to 

adopt less efficient reconstruction plans in order to stay below the upper threshold. The 

commenter stated that the EPA must avoid this outcome by treating all reconstructed sources 

equally. 

Commenter 0142 stated that in response to the EPA requests for comment on an upper capital 

cost threshold for reconstruction, they believe there is no need to identify an upper capital cost 

threshold for reconstruction, if the EPA is confident in their projection that there will be very few 

units that reconstruct with capital costs exceeding 50 percent. The commenter stated that

establishing any range of capital costs is arbitrary and its only purpose is to justify a 

reconstruction standard which is significantly less stringent than the new source standards 

proposed in January 2014. The commenter stated that the EPA makes the argument that it has 

historically considered reconstructed sources as new sources, yet now the EPA struggles to 

justify a basis for not making reconstructed sources meet the new source standard. The 

commenter stated that the root problem is that the EPA established an unreasonable new source 

standard that new sources and reconstructed sources cannot meet. The commenter stated that the 

EPA offers very little justification or reconciliation as to why BSER for reconstructed sources 

(which the EPA assumes to be new sources) is based upon supercritical steam cycle efficiency, 
5-20

yet the BSER for newly constructed sources is based upon partial carbon capture and 

sequestration.

Commenter 0259 stated that concerning EPA's request for comments on specific changes, they 

support EPA adjusting the upper capital cost threshold to the higher end of the 75-100 percent 

range. The commenter stated that the original 50 percent threshold contained in Part 60 was 

established in 1975 and the cost of components has increased significantly since that time and it 

is important to update the regulations. The commenter stated that furthermore, given the spatial 

constraints existing units have with regard to installing controls to meet the NSPS, it is 

appropriate for EPA to use the higher end of the percentage range to reduce the likelihood that 

the reconstruction requirements are triggered.

Response 5.2-11: The EPA is not finalizing an upper cost threshold on the definition of 

reconstruction. The determination of whether or not an existing source has triggered the 

Reconstruction provisions is done as specified in 40 CFR 60.15(d), (e), and (f).

5.2.3 Incentive for Technological Innovation

EPA's objective is reducing air pollution, not incentivizing sources to avoid the purpose of 

the CAA 

Comment 5.2-12: Commenter 0282 stated that they were disconcerted to see EPA declare that 

the Proposed Rule is intended to provide an incentive, and the information needed, for existing 

sources to structure their actions to achieve their operating and business goals without triggering 

the modification or reconstruction standards. The commenter stated that incentivizing sources to 

evade the purpose of the Clean Air Act, i.e., protecting human health and welfare from 

dangerous, and in the case of climate change, catastrophic pollutants, and to elude the new 

source performance standards in particular, decidedly is not the business of the nation's 

Environmental Protection Agency. The commenter stated that to the contrary, it is EPA's 

business to reduce air pollution to the maximum feasible extent, and we trust EPA will continue 

to do so in finalizing the Proposed Rule.

Commenter 0263 stated that requiring implementation of the identified energy efficiency 

improvements is redundant and will stifle innovation. The commenter stated that EPA is already 

proposing that the CAA section 111(d) implementing authority determine a unit-specific 

emission limit based on the results of an energy assessment; companies will be responsible for 

complying with the limit. The commenter stated that if an innovative approach to meeting the 

limit is later determined to be technically achievable and economically favorable, then the 

companies should be afforded the opportunity to use the innovative approach. The commenter 

stated that requiring implementation of a specific energy efficiency improvement may forestall 

the opportunity to install a better performing technology or work practice. The commenter stated

that it is foreseeable that the results of an energy improvement audit may conflict with the 

requirements of a CAA 111(d) plan if the audit is performed before a comprehensive 111(d) 

compliance strategy is in place; in such instances, the energy efficiency improvement would not 

be allowed to operate over its depreciable life.
5-21

Response 5.2-12: The EPA most certainly has not finalized standards that incentivize sources to 

evade the purpose of the Clean Air Act. The suite of CAA 111 rules that are being finalized 

together will assure that fossil fuel-fired EGUs – whether they are new, modified, reconstructed, 

or existing – will achieve GHG emission reductions consistent with the best system of emission 

reduction that has been adequately demonstrated. Further, the EPA is not finalizing standards 

based on the results of energy efficiency audits. 

5.3 DETERMINATION OF THE LEVEL OF THE STANDARD

Limits not achievable 

Comment 5.3-1: Several commenters (0149, 0150, 0162, 0178, 0193, 0215, 0218, 0239, 0249, 

0257, 0260, 0284) stated that the proposed limit of 1,900 lb CO2/MWh for large reconstructed 

boilers and 2,100 lb CO2/MWh for small reconstructed boilers cannot be achieved.

Several commenters (0195, 0199, 0260) stated that EPA should finalize emissions limits on the 

upper end of EPA's proposed ranges. Two commenters (0260, 0199) urged EPA to adopt the 

highest standards within the proposed ranges but on a gross output basis. Commenter 0260 stated 

that the highest proposed standards more accurately account for unit cycling, performance 

degradation, and other factors. The commenter stated that if EPA does not adopt the higher 

performance standards, EPA should consider using a sliding scale based on generation thresholds 

to determine the performance standard for EGUs on an individualized basis; for example, the 

highest limit should apply to units operating at low capacity factors (i.e., in the 33 percent to 45 

percent range). The commenter stated that the emissions limit could be reduced incrementally as 

the generation threshold increases. The commenter stated that adoption of standards on the high 

end of the proposed ranges, or a sliding scale approach, will account for the impacts of the 

widespread re-dispatch that is expected to occur pursuant to EPA's proposed Clean Power Plan. 

The commenter stated that if states continue to increase the amount of renewable energy, as 

required by EPA's Proposed Clean Power Plan, fossil-fired units are more likely to serve as loadfollowing units in support of the highly variable generation from renewable sources.

Commenter 0260 stated that the increasing dispatch of NGCCs would reduce the dispatch of 

coal-fired EGUs, which results in lower heat rate performance at those units. The commenter 

stated that a coal-fired EGU's heat rate is highest (i.e., least efficient) at the minimum load point 

at which the unit can safely operate and at low load points, many plant components operate 

below their most efficient design points. The commenter stated that heat rate decreases (i.e., 

improves) in a non-linear fashion as the load increases until it reaches an optimal load point; the 

heat rate may then increase slightly as load approaches the maximum capability of the unit. 

According to the commenter, the heat rate at the lowest load can be 15 percent to 20 percent 

higher than at the optimum load point. The commenter stated that extra energy is required to 

move a unit from low to higher loads to overcome inertia in the system and the more frequently a 

unit must move up and down the load curve, the more excess energy will be required to produce 

the desired load and, thus, the unit will be less efficient on average. The commenter included a 

table that shows the average heat rate for varying load scenarios at a coal-fired EGU, 

demonstrating the impact of lower load operations on heat rate. The commenter recommended 

that because the proposed Clean Power Plan is expected to impact heat rates in this manner, EPA 
5-22

should finalize higher standards for modified and reconstructed sources or employ a sliding scale 

approach.

Two commenters (0257, 0284) stated that, as discussed in the Cichanowicz Heat Rate Report, 

achieving 1,900 lbs CO2/MWh-net for large coal-fired boilers may be achievable for some 

individual new state-of-art supercritical boilers, but it is not achievable for existing units 

undergoing reconstruction. Commenter 0284 stated that even relatively new supercritical units 

may not achieve 1,900 lbs CO2/MWh-net, depending on duty cycle, local environmental siting 

conditions, and water cooling method. Commenter 0257 stated that of the 183 large electric 

generating units identified to likely continue to operate in future decades and potentially subject 

to the proposed standards for modified and reconstructed sources, the proposed rate of 1,900 lb 

CO/MWh was achieved by only 40 units (20 percent). The commenter stated that the proposed 

NSPS for reconstructed small Subpart Da units is based on an emission rate that no small 

supercritical unit has ever achieved. The commenter stated that as EPA acknowledges, its 

selected best performing facility for this category had an emission rate of 2,320 lb CO2/MWh, 

and the proposed NSPS of 2,100 lb CO2/MWh actually reflects a "normalized" emission rate 

based on improvements in unspecified design factors for a "theoretical reconstructed facility." 

The commenter stated that they do not believe that an NSPS should be based on the performance 

of a "theoretical reconstructed facility". The commenter, therefore, request that EPA identify 

variable conditions that might contribute to the amount of expected emissions, establish that the 

test data relied on are representative of potential industry-wide performance, given the range of 

variables that affect the achievability of the standard, and re-propose the standard accordingly. 

Commenter 0215 stated that the emission limits EPA proposes cannot be achieved by existing 

units undergoing reconstruction. Commenter said new units may not be able to meet the limit for 

large units, and no small supercritical unit has ever achieved the limit EPA proposes for small 

units. 

Commenter 0259 stated that they cannot support any of the range of limits proposed because, 

based on historical records, these limits could not be consistently achieved. The commenter 

stated that reconstructed units face design and technical constraints that are not present in new 

construction, and thus cannot achieve as stringent a level of emission reductions; accordingly, 

the reconstructed emission limits should be set higher to account for this reality. The commenter 

stated that older units do not run as efficiently as new units; this factor also suggests that 

reconstructed units will not be able to achieve as stringent emission levels as new units and EPA 

has not suggested that the high end of the ranges of permissible emission limits is within a zone 

of reasonableness, thus setting higher limits for reconstructed units should not violate the statute.

Commenter 0259 stated that, in response to EPA's request for comment on whether other factors 

should be considered in setting emission limits, they request that consideration be given to the 

fact that not all coal-fired EGUs are pulverized coal units. The commenter's Sheldon Station unit 

is a cyclone unit that burns larger pieces of coal and is less efficient than a pulverized coal unit; 

accordingly, it (and presumably other cyclone units) will not be able to meet even the high end of 

the identified range for units under 2,000 MWBtu/h, of 2,3001b CO2/MWh net. The commenter 

recommended that a standard for cyclone units be set at 2,600 lb CO2/MWh net to recognize the 

differences between them and pulverized coal units.
5-23

Commenter 0263 that the emission limits as proposed for reconstructed units are not achievable 

based on real-world performance of regulated sources. The commenter stated that the best 

performing unit in Wyoming with a heat input greater than 2,000 MMBtu/hr exceeds the 

proposed limit of 1,9001b CO 2/MW-hr by nearly 11 percent despite significant recent upgrades 

that have targeted improvements in energy efficiency. The commenter stated that a smaller unit 

that would be subject to the proposed limit of 2, l 001b CO 2 /MW-hr currently exceeds the limit 

by 12 percent, and that unit is less than five years old; the plant is already energy efficient and 

therefore requiring additional reductions is not practical. 

Response 5.3-1: The EPA points out that triggering the reconstruction provision is a significant 

economic hurdle - and it has only rarely been done. Per 40 CFR 60.15 - 'Reconstruction' means 

the replacement of components of an existing facility to such an extent that: (1) the fixed capital 

cost of the new components exceeds 50 percent of the fixed capital cost that would be required to 

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

feasible to meet the applicable standards set forth in this part. 50% of fixed capital cost that 

would be required to construct an entirely new EGU would almost certainly involve significant -

and very costly investment (if not entire replacement of) the boiler. At that time, conversion from 

a subcritical boiler to a supercritical boiler can be done [or complete replacement with a new 

supercritical boiler]. However, if the owner/operator can show that it is not "technologically and 

economically feasible to meet the applicable standards set forth in this part", then it would not 

trigger the reconstruction provisions. The EPA also points out here - and in the preamble in 

section VII - that owners/operators can also consider the use of natural gas co-firing to achieve 

the final emission limitation without the need to convert the subcritical boiler to supercritical. 

Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce air 

emissions of criteria and hazardous air pollutants. 

The commenters claim that the final emission standard for reconstructed sources cannot be 

achieved. According to EPA CAMD data (which is discussed in the TSD “Achievability of the 

Standard for Newly Constructed Steam Generating EGUs” available in the rulemaking docket), 

the best monthly rate for the AEP John W. Turk plant is 1,725 lb CO2/MWh-g. The unit’s best 

12-operating-month average rate is 1,753 lb CO2/MWh-g and its highest 12-operating-month 

average is 1,817 lb CO2/MWh-g. Since its startup the performance of the Turk facility has 

improved with time and its most recent emission rates are well below the 1,800 lb CO2/MWh-g 

final emission limitation for large reconstructed EGUs.

More stringent standard for existing sources is backwards

Comment 5.3-2: Two commenters (0157, 0183) stated that with this proposal, EPA has reversed 

the progression of stringency. The commenter stated that where one would expect to see the most 

stringent limits on brand new, yet-to-be-constructed sources, in fact the lowest (most stringent) 

limits are applied to existing units under 111(d), and units yet to be constructed must meet only a 

rate of 1,110 lb CO2/MWh-net, and that with carbon capture and sequestration; and modified or 

reconstructed units would have to meet a maximum emission rate of 1,900 lb CO2/MWh-net. 

EPA's more stringent standard for existing sources is backwards and departs from past agency 

interpretations without explanation.
5-24

Response 5.3-2: Comments regarding the stringency of the 111(d) existing source standards are 

addressed in the 111(d) final Emissions Guidelines preamble and are out-of-scope for this RTC.

Unreasonable to apply standards of performance for reconstructed sources to modified 

sources 

Comment 5.3-3: Commenter 0192 stated that they do not support EPA's proposal to apply the 

standard of performance for reconstructed sources to modified sources. The commenter stated 

that first, the standard of performance for reconstructed sources is arbitrary and capricious; 

second, it is based on installation of an ultra-supercritical boiler, and it is unreasonable to apply 

those emission limits to modified sources after EPA rejected boiler upgrades as BSER for 

modified sources. The commenter stated that EPA must identify a numeric limit that is related to 

heat rate improvements to ensure that sources that have already implemented available heat rate 

improvements will not have to find other ways to further reduce CO2 emissions in the event that 

they undergo a modification.

Response 5.3-3: EPA did not propose to apply the standard of performance for reconstructed 

sources to modified sources.

Emissions standards are too lenient

Comment 5.3-4: Commenter 0282 stated that the proposed emission standards for modified or 

reconstructed coal-fired power plants are too lenient. The commenter stated that EPA may not 

set any standard for modified and reconstructed sources other than the proposed 111(b) standard 

for new sources. The commenter stated that the standards for reconstructed large and smaller 

boilers and IGCCs are insufficiently stringent and legally unjustifiable. 

Commenter 0244 stated that the proposed limits are too lenient and that many existing coal-fired 

EGUs already meet these emission limits, whereas the purpose of the NSPS program is to 

advance the technological vanguard, not entrench the status quo. The commenter stated that EPA 

must ensure that reconstructed EGUs satisfy a performance standard that is both sufficiently 

rigorous and technologically forward-looking. Our proposal for reconstructed sources is the 

application of the 111(b) new source standard. [The commenter referred EPA to their comments 

for the agency's proposed new source rule, attached as Exhibit 1 and incorporated by reference 

herein, for a detailed discussion of the issue.] The commenter stated that in keeping with the 

proposed new source standard, EPA should designate efficient generation technology with partial 

CCS as BSER for reconstructed steam EGUs and should impose a performance standard at least 

as stringent as 1,200 lbs CO2/MWh on a net output basis. The commenter stated that partial CCS 

is economically feasible and technologically achievable for reconstructed units and should be 

mandated for all such facilities. Reconstructed units have historically been extremely rare. The 

commenter stated that they see little reason why a plant operator would choose to undergo such a 

project if not for the express purpose of extending the life of an aging plant rather than 

constructing a new facility that would be subject to a rigorous new source standard, a scenario 

not in keeping with the goal or purpose of the Clean Air Act; the statute grants EPA the tools to 

ensure that it does not occur. The commenter stated that the agency must therefore utilize the 

tools at its disposal and prevent environmentally harmful life extension projects by adopting our 

proposal for reconstructed steam EGUs.
5-25

Response 5.3-4: Triggering the reconstruction provision is a significant economic hurdle - and it 

has only rarely been done. Per 40 CFR 60.15 - 'Reconstruction' means the replacement of 

components of an existing facility to such an extent that: (1) the fixed capital cost of the new 

components exceeds 50 percent of the fixed capital cost that would be required to construct a 

comparable entirely new facility, and (2) it is technologically and economically feasible to meet 

the applicable standards set forth in this part. A project that exceeds 50% of fixed capital cost 

that would be required to construct an entirely new EGU would almost certainly involve 

significant cost. The determination of whether or not an existing source has triggered the 

Reconstruction provisions is done as specified in 40 CFR 60.15(d), (e), and (f).

Support mass-based standard

Comment 5.3-5: Commenter 0282 stated that they support EPA's choice of a mass-based 

standard for the Proposed Rule and the proposed 111(b) standards and believe it is critical that 

the section 111(d) standards be expressed on a mass basis rather than a rate basis, primarily to 

provide an actual cap to emissions rather than a rate-based limitation that allows emission to 

increase depending on energy demand, but also to avoid difficult conversion and intra-state trade 

issues that could allow system gaming. The commenter stated that in addition, the inconsistency 

between a rate-based section 111(d) plan and a mass-based section 111(b) standard can be 

avoided by requiring mass-based section 111(d) standards.

Response 5.3-5: The EPA did not propose mass-based standards in any of the proposals under 

CAA 111(b).

5.3.1 Large Units Standard of 1,900 lb CO2/MWh; solicited comment on range 

of 1,700-2,100 lb CO2/MWh

Limit is unachievable

Comment 5.3-6: Commenter 0173 stated that a performance standard of 1,900 lbs CO2/MWh 

for large reconstructed coal-fueled EGU boilers with a heat input greater than 2,000 MMBtu/h is 

unachievable for existing coal-fueled utility boilers undergoing a reconstruction and is also too 

stringent for new coal-fueled power plants. The commenter stated that this was demonstrated by 

an analysis of CO2 emissions rates, which the commenter submitted to EPA as part of its 

comments on the CO2 performance standards for new coal-fueled EGUs. The commenter stated 

that the study reviewed 21 EGUs that began operation after January 1, 2007 and used data from 

CAMD. The commenter stated that the analysis demonstrated that new coal-fueled EGUs can 

achieve emission rates of 1,915 lbs CO2/MWh for supercritical boilers burning bituminous and 

subbituminous coals; 2,080 lbs CO2/MWh for subcritical boilers burning bituminous and 

subbituminous coals; and 2,150 lbs CO2/MWh for all boiler types burning lignite coal. The 

commenter stated that as demonstrated by these emissions rates, a new state of the art coal-fueled 

power plant cannot consistently meet the 1,900 lbs CO2/MWh standard for large reconstructed 

sources; even the most efficient new large supercritical units may not be able to achieve 1,900 

lbs CO2/MWh-net due to duty cycle, local environmental siting conditions, water cooling 

method, and auxiliary power demands. The commenter stated that if too stringent for new state 

of the art facilities, a performance standard of 1,900 lbs CO2/MWh is clearly unachievable for 

reconstructed facilities. The commenter did not specifically address the CO2 standard of 2,100 
5-26

lbs CO2/MWh for smaller reconstructed units, but stated this standard is also invalid and should 

be withdrawn for the reasons highlighted in the UARG comments. 

Commenter 0197 disagreed with the 1,900 lb CO2/MWh-net limit for larger coal-fired units.

Response 5.3-6: The achievability of the final standards has been addressed in previous 

comments.

Performance standards are not supported by an adequate technical analysis 

Comment 5.3-7: Commenter 0173 stated EPA's proposed performance standards for modified 

and reconstructed sources are supported by inadequate technical analysis and an inaccurate 

interpretation of an engineering study. The commenter stated that to support a CO2 emissions 

rate of 1,900 lbs CO2/MWh for reconstructed utility boilers, EPA relied on the performance of a 

single EGU and to justify a two-percent heat rate improvement standard for modified utility 

boilers, EPA incorrectly interpreted an engineering analysis conducted by Sargent & Lundy.

Commenter 0242 stated that EPA's consideration of ranges as low as 1, 700 or 1,900 lb 

CO2/MW-h-net is irrational. The commenter stated that even the EPA acknowledges a rate of 

1,700 lb CO2/MWh-net could potentially be met by an EGU using advanced ultra-supercritical 

steam conditions. The commenter stated that although this technology has been discussed, the 

actual alloys needed to construct such a unit are still being researched and developed and there 

are no long term data at the existing ultra-supercritical unit operations (AEP Turk) to assess 

long-term viability. The commenter stated that these standards should be established consistent 

with the requirements of CAA section 111 (b), so that these proposed standards reflect the degree 

of emission limitation achievable through the application of BSER that has been adequately 

demonstrated. The commenter stated that the EPA is proposing standards on unproven 

technology in direct conflict with the purpose and intent of BSER. 

Response 5.3-7: Comments on the technical basis for the standards for modified steam 

generating EGUs have been addressed in Chapter 6 – including critiques of the use of the 

Sargent & Lundy study. The EPA stands by the technical basis for the standard for reconstructed 

EGUs and maintains – as we have discussed in response to many other comments – that they are 

achievable.

EPA reliance on information from one unit, Weston Unit 4, to support the proposed 1,900 

lbs CO2/MWh standard is inappropriate 

Comment 5.3-8: Commenters 0173, 0195 stated that EPA relied on emissions information from 

one unit, Weston Unit 4, to support the proposed 1,900 lbs CO2/MWh standard. Commenters 

said EPA's analysis failed to demonstrate that the proposed performance standard is achievable 

by all affected coal-fueled reconstructed EGUs based on a wide range of operating conditions, 

including duty cycle, local environmental siting conditions, water cooling method, and auxiliary 

power demands. EPA provided no explanation as to why Weston 4 is a representative plant of 

the fleet or an appropriate basis for a performance standard, and further, if undergoing a 

reconstruction, could a reconstructed unit achieve an emissions rate similar to the one achieved 

by Weston 4. Weston 4 is a new unit built in 2008 that employs supercritical generating 
5-27

technology that is not realistically applicable to existing subcritical boilers, and even if 

applicable, may not achieve the same performance due to the operation of the plant and the size 

of the unit. EPA's analysis ignores the fact that the CO2 emissions rate for any particular EGU is 

determined by many design parameters, including thermodynamic steam cycle, coal rank and 

quality, EGU cooling system, EGU geographic location and ambient conditions, EGU duty cycle 

and load generation flexibility requirement, EGU size, and installed pollution control technology. 

The commenter stated that EPA has therefore conducted an inappropriate analysis in establishing 

the emissions rate standard for reconstructed EGU boilers and as a result, the selection of 

supercritical technology as the basis for BSER for large EGUs has not been demonstrated and 

does not meet the requirements of section 111.

Commenter 0146 stated that EPA has not justified the proposed 1,900 lb CO2/MWh-net for large 

units. The commenter stated that for large units, although EPA was able to identify one recently 

constructed unit that achieved a 99 percent confidence emission rate below 1,900 lb 

CO2/MWh=net, it has provided no information on the emissions performance of other similar 

units. The commenter stated that a rate of 1,900 lbs CO2/MWh-net may be achievable for some 

individual large, new state-of-the-art supercritical boilers, but it may not be achievable for many 

other new supercritical boilers depending on duty cycle, local environmental siting conditions, 

water cooling method, and auxiliary power demands, and it is certainly not achievable for 

existing units undergoing reconstruction. 

Response 5.3-8: As EPA shown in previous response – and in response to similar comments in 

Chapter 6 of this RTC – the AEP Turk facility has demonstrated an ability to meet the final 

standard of 1,800 lb CO2/MWh-g. In addition, affected reconstructed units can consider 

alternative compliance options such as natural gas co-firing to meet the final standard. In any 

case, per 40 CFR 60.15, if the owner/operator can demonstrate it is not "technologically and 

economically feasible to meet the applicable standards set forth in this part", then it would not 

trigger the reconstruction provisions.

For the possible range of 1700 to 2100 lb CO2/MWh-net emissions for large units, a limit of 

2100 lb CO2/MWh-net is more reasonable 

Comment 5.3-9: Commenter 0169 stated that regarding EPA's request for comments on a range 

of 1700 to 2100 pounds (lb) CO2/MWh-net emissions for large units, the commenter said that a 

limit of 2100 lb CO2/MWh-net is a much more reasonable emission rate than 1700, and should 

be achievable with varying conditions. The commenter stated that an EGU cannot be expected to 

operate under ideal conditions all the time. The commenter stated that Figure 7 of the BSER 

Memo clearly shows that anything less than 2100 lb CO2/MWh-net is not consistently 

achievable, and BSER is clearly required to be achievable under routine operating basis, not only 

under ideal operating conditions. 

Response 5.3-9: The EPA has finalized a standard of 1,800 lb CO2/MWh-gross, which the EPA 

finds to be achievable.
5-28

Technical justification for CO2 emission standards at the lower end of the range EPA is 

considering for reconstructed sources is not sufficient 

Comment 5.3-10: Commenter 0142 stated that they do not agree that there is sufficient technical 

justification to establish CO2 emission standards at the lower end of the range the EPA is 

considering for reconstructed sources. The commenter stated that EPA proposed the 1,700 lb 

CO2/MWh-net standard based upon the ultra-supercritical steam cycle and they are aware of just 

one ultra-supercritical coal-fired boiler located in the U.S., which only recently commenced 

operation in December 2012. The commenter stated that they are unaware of any reconstructed 

subcritical or supercritical units being reconstructed to an ultra-supercritical unit that has 

demonstrated it can achieve 1,700 lb CO2/MWh-net. The commenter stated that EPA has no 

basis for establishing an emission limit without data supporting its achievability. 

Commenter 0215 stated without adequate basis, EPA proposes that sources with a heat input 

above 2,000 MMBtu/h (large units) must meet an emission limit of 1,900 lb CO2/MWh-net while 

sources with a heat input equal to or less than 2,000 MMBtu/h (small units) must meet an 

emission limit of 2,100 lb CO2/MWh-net. Commenter referred to one of their attachments, a 

consultant's report, that stated achieving 1,900 lbs CO2/MWh-net for large coal-fired boilers may 

be achievable for some individual new state-of-the-art supercritical boilers, but it is not 

achievable for existing units undergoing reconstruction. See J. Edward Cichanowicz & Michael 

C. Hein, "Critique of EPA's Proposed CO2 NSPS For Modified and Reconstructed Subpart Da 

Sources," at 1 (Oct. 13, 2014). Commenter said even relatively new large supercritical units may 

not achieve 1,900 lbs CO2/MWh-net, depending on duty cycle, local environmental siting 

conditions, water cooling method, and auxiliary power demands. 

Commenter 0215 mentioned that the proposed NSPS for large reconstructed Subpart Da boilers 

is based on the "99% Confidence Emission Rate" of one recently constructed unit burning 

subbituminous coal, and EPA does not explain what a "99% Confidence Emission Rate" is or 

how it is calculated.

Response 5.3-10: The EPA is not finalizing the lower end of the range that was proposed. The 

EPA has finalized a standard of 1,800 lb CO2/MWh-gross (approximately 1,900 lb CO2/MWhnet), which the EPA finds to be achievable by a large reconstructed source.

5.3.2 Small Units Standard of 2,100 lb CO2/MWh; solicited comment on range 

of 1,900-2,300 lb CO2/MWh

Standard does not reflect BSER and is not achievable 

Comment 5.3-11: Several commenters (0146, 0195, 0215, 0218) stated that EPA did not 

provide justification for the proposed standard for smaller reconstructed units.

Commenters 0146, 0195, 0215 stated that with regard to smaller reconstructed EGUs, while EPA 

selects subcritical technology as BESR for these units, the Agency sets the numerical limit at a 

level that is not even achieved in practice by the new unit used to set the standard. The 

commenters stated that the TSD explains that for the Wygen III unit, "even though the emission 

rate for the Wygen III facility is 2,320 lb CO2/MWh-net, based on the normalization of that data 
5-29

the EPA has determined that the 12-month emission limit that corresponds to BSER is 2,100 lb 

CO2/MWh-net for reconstructed EGUs with a base load rating of 2,000 MMBtu/h or less." The 

commenters stated that although EPA itself does not have information regarding the design 

factors and operation and maintenance practices that form the basis of this normalized emission 

rate, the Agency inexplicably assumes that a reconstructed EGU would be able to incorporate 

both of these into the design and operation and maintenance practices of a reconstructed EGU. 

The commenters stated that putting aside the fact that EPA uses a new unit to set a standard for 

reconstructed units, EPA needs to finalize a standard that reflects what a subcritical unit achieves 

in actual operation; otherwise, the standard will not reflect BSER and is unlawful. Commenters 

added EPA has no authority to base an NSPS on the performance of a "theoretical reconstructed 

facility." 

Commenter 0215 added the Agency must "(1) identify variable conditions that might contribute 

to the amount of expected emissions, and (2) establish that the test data relied on by the agency 

are representative of potential industry-wide performance, given the range of variables that affect 

the achievability of the standard." Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981). 

EPA may not rely on "mere speculation or conjecture," as it has done here. See Lignite Energy 

Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999) (per curiam). Commenter said given EPA's 

failure even to attempt to justify its proposed NSPS for reconstructed units in accordance with 

these legal criteria, it should be withdrawn.

Response 5.3-11: Triggering the reconstruction provision is a significant economic hurdle - and 

it has only rarely been done. However, in the event that a unit does trigger the reconstruction 

provisions, the EPA does not specify any particular technology that must be used. Rather the 

reconstructed unit must meet a standard of performance consistent with the emission reductions 

achieved by the BSER. Owners/operators can do so by installing a new well-performing 

subcritical boiler, or by upgrading the existing subcritical boiler to best performing conditions or 

by utilizing other options – such as the use of natural gas co-firing to achieve the final emission 

limitation. Natural gas co-firing has long been recognized as an option for coal-fired boilers to 

reduce emissions of air pollutants. In any case, per 40 CFR 60.15, if the owner/operator can 

demonstrate it is not "technologically and economically feasible to meet the applicable standards 

set forth in this part", then it would not trigger the reconstruction provisions.

5.4 SUBCATEGORIES

Additional subcategorization is warranted based on IGCC and utility boilers, boiler type 

and coal rank

Comment 5.4-1: Several commenters (0169, 0173, 0182, 0183, 0192, 0277, 0203, 0222) stated 

that there was a need for EPA to establish subcategories with different emission limits.

Commenter 0173 stated that EPA's proposed performance standards are subcategorized in two 

general ways: first, EPA subcategorizes between utility boilers and natural gas turbines; and 

second, within the utility boiler category, EPA subcategorizes based on plant size. The 

commenter stated that in the past, EPA has routinely subcategorized coal-fueled utility boilers 

with more granularity than they are subcategorized here and as an example, cited the MATS 

where EPA subcategorized coal units based on coal rank and whether the plant was a boiler or an 
5-30

IGCC power plant. The commenter stated additional subcategorization is warranted based on 

boiler type and coal type for both modified and reconstructed utility boilers. The commenter 

stated that different types of boilers that use coals of different rank have significantly different 

CO2 emissions rates on average with emissions rates varying by more than 200 lbs CO2/MWh 

between the highest and lowest emitting category. The commenter stated that according to the 

DOE, coal plant efficiency varies from 27 percent in the lowest decile to 37 percent in the 

highest.

Commenter 0183 stated that EPA fails to acknowledge the fundamental design differences 

between IGCC units and coal-fueled units that use a more traditional coal boiler. The commenter 

stated that significant process differences exist between IGCC and pulverized coal boilers 

(subcritical, supercritical, and ultra-supercritical) or fluidized bed boilers and the differences are 

conceded in EPA's own report. According to the commenter, similarities between IGCC and 

more traditional pulverized coal or fluidized bed electric generating units are limited to the raw 

fuel (coal) consumed and the electricity produced. The commenter stated that the intervening 

process varies greatly as pulverized coal and fluidized bed units burn fuel and generate heat to 

produce steam for electricity production, while IGCC units gasify fuel to produce syngas 

(hydrogen and carbon monoxide) which is ultimately combusted in gas turbines. The commenter 

stated that IGCC may be viewed as a process similar to that of a gas-fueled combined cycle unit 

closely coupled with a multiple stream chemical plant, whereas a coal-fueled boiler is a 

traditional Rankine cycle plant utilizing a traditional steam turbine and conventional pollution 

controls; these are fundamentally different source types.

Commenter 0183 stated that it is inappropriate to set a CO2 emission standard that applies to both 

IGCC and coal-fueled boilers (i.e., pulverized coal or fluidized bed). The commenter stated that 

these technologies share little with each other except that both produce steam from releasing 

energy stored within fossil fuels and different standards are necessary to reflect the different 

processes and emissions profiles of these different types of sources. The commenter stated that it 

is impossible to create a "best system of emission reduction" that takes into account the required 

factors (cost, energy requirements, etc.) for a category that lumps together coal-fueled boilers 

and IGCC units because the economic and operational considerations for these units are totally 

different. 

Commenter 0183 stated that an IGCC unit uses coal as a feedstock, not as a fuel, and the 

equipment within the unit is fundamentally designed to function differently than a traditional 

pulverized coal unit. The commenter describes the IGCC process and contrasts it with that of a 

coal-fueled boiler. The commenter stated that these process differences between an IGCC and a 

coal-fueled boiler produce entirely different emission "footprints" that drive distinct emission 

control strategies and thus cannot be lumped together into a single CO2 emission target. The 

commenter stated that the Clean Air Act 1977 Conference Report authorized the EPA to "set a 

range of pollutant reduction that reflects varying fuel characteristics," and, historically, the EPA 

has used that discretion to treat various fuels, designs, and circumstances differently in 

fashioning emission limitations. The commenter stated that the Modified and Reconstructed Unit 

Proposal is inconsistent with how these same units are categorized under other overlapping CAA 

programs and unlike other CAA programs, the Modified and Reconstructed Unit Proposal treats 

coal-fueled boilers and IGCC plants interchangeably simply because they both use coal, despite 
5-31

their significantly different designs, operations, and emissions footprints. The commenter stated 

that EPA provides no explanation as to why these very different EGU designs should be treated 

identically under a single source category; considering the differences between coal-fueled 

boilers and IGCC plants, the use of a single source category for both cannot be sustained.

Commenter 0183 stated that EPA must further subcategorize modified and reconstructed sources 

based on coal type and boiler type. The commenter stated that Cichanowicz and Hein analyzed 

data from a larger data set than was used by EPA and found that coal composition, load factors, 

boiler design, and coal moisture all affect CO2 emissions. The commenter stated that with regard 

to moisture content, Powder River Basin subbituminous fuel may contain 30% moisture 

compared to 6% moisture content for a typical eastern bituminous coal, resulting in a 3-5% 

thermal efficiency penalty due to the amount of fuel that must be com busted to generate a fixed 

amount of steam. The commenter stated that despite this thermal penalty, Cichanowicz and 

Hein's statistical analysis (using EPA's methodology) demonstrates that boiler steam conditions 

are more relevant for creating categories for CO2 emissions than whether the coal is 

subbituminous or bituminous; on the other hand, lignite coal faces firing and utilization 

challenges that have a bigger effect on CO2 emissions than the boiler steam conditions. The 

commenter stated that the Cichanowicz and Hein report recommends three different emissions 

standards: one for supercritical boilers burning subbituminous or bituminous coals, one for 

subcritical boilers burning subbituminous or bituminous coal, and one for boilers burning lignite. 

The commenter stated that any final rule must provide a separate standard for IGCC units and a 

separate standard for coal-fueled utility boilers subcategorized by type (i.e., lignite, subcritical 

bituminous and subbituminous, and supercritical bituminous and subbituminous) and that in the 

absence of separate standards, EPA must recognize the differences in emissions from these three 

categories and adjust the performance standard accordingly. The commenter believes standards 

for EGUs should be subcategorized by primary fuel type as provided in the statute to distinguish 

among classes, types, and sizes within categories of new sources; failure to do so, or even 

consider it, would be arbitrary and capricious. The commenter stated that EPA's own prior 

analysis and findings with respect to units that burn low-rank virgin coal demonstrate the need 

for subcategories. The commenter stated that in establishing subcategories for its MATS rule, 

EPA determined that the differing heat content of low-rank virgin coal justified a subcategory for 

mercury emissions; that same rationale applies with equal force to require a subcategory for CO2

emissions from these same units.

Commenter 0169 stated that EPA has long recognized the need for categories of EGUs under the 

NSPS and as far back as 1979, when EPA divided Subpart D for Steam Generating Units into 

three (3) subparts, it was recognized that standards were needed to recognize the limitations 

associated with certain equipment. The commenter stated that categories for plant designs, sizes, 

and ages (i.e. appropriate EGU criteria), should be developed for this standard as well. The 

commenter stated that EPA acknowledges in the rule preamble that utility boilers are numerous 

and diverse in size and configuration and further states that developing a single standard for all 

modified utility boilers or IGCC units is challenging. For these reasons and if this rule moves 

forward, the commenter asserts that EPA should subcategorize under Section 111(b)(2) and 

account for the many differences in boilers. The commenter stated that EPA has conceded it is 

open to creating categories for NGCCs and has solicited comment on establishing separate 

standards for load following NGCC (i.e. intermediate capacity factor) EGUs with a more 
5-32

stringent standard applying only during periods of high annual capacity factors and a less 

stringent standard applying during periods of intermediate load. The commenter stated that EPA 

explains that using this approach addresses potential issues with regards to design of NGCCs. 

The commenter stated that if EPA is open to creating categories for NGCC units, then it should 

be open to creating categories for coal-fired EGUs in the Modified Source Rule. Commenter 

0201 stated that the standards should not only be subcategorized by primary fuel type, but also 

by the type of unit that is in place and the type of emission control technologies in use on the 

unit, since these factors can all directly impact operating efficiency and emissions.

Commenter 0192 stated that rather than proceeding with this rulemaking, EPA must withdraw 

this proposed rule and conduct a new BSER analysis for reconstructed coal-fired EGUs that 

addresses not only the commercial availability of emission reduction technologies, but also 

whether or not they can be retrofitted for use by existing sources. The commenter stated that as 

the D.C. Circuit explained, under Section 111 due consideration must be given to the possible 

impact on emissions of recognized variations in operations and some rationale offered for the 

achievability of the promulgated standard given the test conducted and the relevant variables 

identified. To facilitate public comment, we think this rationale should appear in the Agency's 

initial support statement. National Lime Ass'n v. EPA, 627 F.2d 416, 434 (D.C. Cir. 1980). The 

commenter stated that thus, as part of its BSER analysis for reconstructed sources, EPA must 

consider important differences among coal-fired EGUs, including differences between subcritical 

boilers, supercritical boilers, and IGCC facilities and, if appropriate, establish different standards 

of performance for different subcategories of reconstructed coal-fired EGUs. The commenter 

stated that this analysis must include consideration of all associated support systems, water and 

steam systems, and steam turbine design and capabilities and that it is likely that such a change 

to ultra-supercritical operation would necessitate installation of an entirely new facility, thus 

EPA's regulatory approach would, as a practical matter, eliminate continued use of a 

reconstructed steam generator.

Commenter 0242 stated that coal fired generators were largely engineered to operate at high 

capacity factors. The commenter stated that these proposed rules, along with the proposed rules 

for existing units, will force many coal-fired units to operate as load following units, outside of 

their design parameters and at the expense of efficiency. The commenter stated that the EPA 

cannot provide a sound technical rationale as to why these same concepts do not apply to coalfired EGUs and urges the EPA to extend those considerations offered to NGCC units to coalfired units; otherwise, it is clear that the EPA is choosing a winning fuel, natural gas, over a 

losing fuel, coal, and that was not the intention of the CAA.

Commenter 0222 stated that ultimately, the standards proposed by EPA for reconstructed units 

cannot be met. The commenter stated that the EPA must impose more lenient limits for 

supercritical units and must also create categories for subcritical units, with correspondingly less 

onerous standards. The commenter stated that within each of those primary categories 

(subcritical and supercritical), it must then create fuel-specific subcategories; there must be 

subcategories for lignite, with further relaxed emissions limits and standards that reflect the 

unique characteristic of the fuel and the design of the facilities to burn the fuel. 
5-33

Subcategory for lignite 

Commenter 0222 stated that lignite-fired power plants are technologically and operationally 

distinct from traditional coal-fired power plants, and even more distinct from IGCC units, and 

include different design elements that warrant and require a separate subcategory within the 

overarching coal category. The commenter stated that this lignite subcategory should include 

more relaxed emissions limits and standards. The physical and chemical characteristics of lignite 

demand sub categorization: lignite has a lower heat-value than other types of coal, resulting in 

the need to combust additional fuel in order to meet comparable generation amounts; the 

physical and chemical composition of lignite also typically requires larger, more energy 

intensive, control technologies than other coal-fired units and the parasitic load of these 

technologies inherently impacts GHG emissions and performance capabilities of these units; and 

lignite EGUs are almost always at mine-mouth power plants that are co-located with the mines 

that supply their coal. The commenter stated that imposing limitations that would require a 

source to comply with the emissions standards of non-lignite units following modification or 

reconstruction is simply not feasible and would require a power plant to change fuel types in 

order to continue to operate, but fuel switching is impossible for many of these mine-mouth 

plants, as they do not possess the infrastructure, whether it be rail lines to import alternative coal, 

pipelines to transport natural gas, or the boiler/burner design to fire either. The commenter stated 

that these types of changes would be far beyond the scope of any modification and 

reconstruction.

Commenter 0222 stated that EPA, as recently as the MATS Rule, established a subcategory for 

lignite within the larger coal subcategory, not only because of the chemical composition of the 

fuel source, but also because lignite units are universally constructed at or near a mine containing 

lignite with designated and narrowly limited conveyance mechanisms to transport lignite from 

the mine to the power plant. According to the commenter, if EPA does not provide a lignite 

subcategory, operators of existing lignite-fired power plants conducting a modification or 

reconstruction would be required to shut down, forfeiting use of extremely valuable and 

affordable generating units. The commenter stated that it would also require those units to forfeit 

access to domestic, plentiful, and affordable lignite and would signal the end of the ability of colocated mine-mouth plants to conduct modifications or reconstruction, as well as the ability to 

recover potentially sizable investments in their mines because of the limitations placed on an 

operator's ability to maintain, expand, or add capacity to use these local, domestic, and sizeable 

fuel supplies. The commenter stated that natural gas is not available in many areas reliant on 

lignite, but beyond those areas, natural gas supplies (or even alternative coal supplies) are also 

not readily available in all parts of the country, including large regions dependent on lignite-fired 

generation. The commenter stated that EPA has not accounted for the regional availability of 

natural gas or coal that may be imposed on modified/reconstructed units by a rule without a 

separate lignite subcategory.

Subcategory for coal refuse

Commenter 0182 suggested that EPA separately define BSER for coal refuse CFB units.
5-34

Response 5.4-1: The EPA sees no need to subcategorize the reconstructed standard for anything 

beyond size as the EPA has determined that smaller boilers cannot implement measures to meet 

the emissions achievable by supercritical boiler technology. The EPA has based the emission 

limitation for larger reconstructed units on the performance of a supercritical unit burning 

subbituminous coal. That standard can be met by similar units burning bituminous cost (e.g., the 

Longview plant in WV) and by units burning dried lignite (which will have a similar heat input 

as subbituminous coal. The EPA re-emphasizes ... triggering the reconstruction provision is a 

significant economic hurdle - and it has only rarely been done. If it is triggered, the EPA does not 

specify any particular technology that must be used. Rather the reconstructed unit must meet a 

standard of performance consistent with the emission reductions achieved by the BSER. 

Owners/operators can do so by installing a new boiler or by converting an existing boiler or by 

refurbishing the existing boiler or by utilizing other options – such as the use of natural gas cofiring to achieve the final emission limitation. In any case, per 40 CFR 60.15, if the 

owner/operator can demonstrate it is not "technologically and economically feasible to meet the 

applicable standards set forth in this part", then it would not trigger the reconstruction provisions.

Comment 5.4-2: Commenter 0222 stated that the proposed emissions levels are far too low and 

would be extremely difficult to meet by even the newest supercritical coal-fired power plant 

burning the highest heat-rate fuel. The commenter stated that for the vast majority of existing 

units, those that would be subject to modification requirements, would not be able to reach these 

targets even following a modification. The commenter stated that it would take a completely 

different type of design and/or the reliance on a completely different fuel source; these problems 

are particularly acute for lignite-fired units. The commenter stated that EPA should set these 

emission levels at a much higher level and also create separate subcategories for regulated units.

Response 5.4-2: Achievability of the final standard has been addressed elsewhere in this RTC.

Support for a case-by-case assessment for each utility boiler

Comment 5.4-3: Commenter 0215 stated EPA's general reconstruction rule requires an analysis 

of whether it is technologically and economically feasible to meet a limit, including a 

consideration of the estimated life of the facility after the replacements. See 40 C.F.R. section 

60.15(f). This provision inherently requires case-by-case reconstruction determinations in light 

of economic and technological feasibility considerations, which EPA fails even to acknowledge 

(let alone discuss) in the Proposed Standards. Commenter said EPA concedes that existing EGUs 

are a diverse population, therefore, it may be difficult for EPA to set a single NSPS that can be 

achieved at all reconstructed units. Commenter said EPA is authorized, however, to 

subcategorize under section 111(b)(2) and can undertake the necessary analyses to account for 

the many differences in the boiler population. Given the rarity of reconstruction, however, 

commenter suggested that EPA withdraw its Proposed Standards and decline to set a standard. 

At a minimum, based on the foregoing discussion, EPA should explicitly deem economically 

infeasible "and therefore not a reconstruction" any situation where the imposition of the NSPS 

would result in an EGU shutting down.

Several commenters (0253, 0259) stated that the condition for defining reconstruction as being

technologically and economically feasible to meet the applicable standard should be continued as 

a condition for an EGU to be subject to the reconstructed emissions standards. The commenter 
5-35

stated that ascertaining that this condition is met would be, as it has been, a critical part of the 

case-by-case assessment option because it allows the state or EPA to evaluate each units specific 

factual constraints and how they affect its ability to reach emission limits.

Commenter 0218 stated that heat rate improvement is a potential approach for reducing carbon 

emissions from modified or reconstructed EGUs but it must be analyzed on a case-by- case basis 

to allow for consideration of current unit configurations and operating and maintenance 

practices. The commenter stated that for each EGU, possible heat rate improvements are 

dependent on load, temperature, design and control configuration, operation and maintenance 

practices, and availability of cost-effective equipment upgrades and, because a static limit is not 

a reasonable standard in the case of variable CO2 emissions from utility boilers or IGCC units, 

BSER should require best practices of operation and maintenance which limit heat rate 

variability and consequent CO2 emissions. The commenter stated that based upon the limited 

data available and the wide variation that may be expected from the types and sizes of EGUs that 

may modify or reconstruct in the future, it is inappropriate for EPA to establish specific emission 

limitations for CO2. The commenter stated that the Agency's attempt to define a specific limit as 

BSER fails to account for the recommendation by Sargent & Lundy to provide flexibility by 

performing a power plant energy audit, to determine the availability of cost-effective equipment 

upgrades and commensurate improvements in heat rate. 

Commenter 0146 stated that BSER for all reconstructed Subpart Da units should be based on 

their design steam conditions. 

Commenter 0224 stated that states should set standards of performance for individual EGUs 

rather than the proposed numerical range of potential emission limits for the several different 

source categories. The commenter stated that this uniformity within a category ignores that no 

economically viable, commercially available CO2 control technologies are available for existing 

units, thus calling into question whether the proposed standards can be achieved. The commenter 

stated that if no commercially viable CO2 control technology is available for installation on 

existing units that are modified or reconstructed, a proposed standard based on an assumption of 

availability is not achievable; the same point applies to other technologies retrofitted to existing 

plants. The commenter stated that even if available, there is no degree of certainty that adding 

certain controls to existing EGUs within a category would necessarily result in a uniform (or 

close to uniform) emission reduction level within the category; rather, an existing unit's 

achievable efficiency and CO2 emission rate will depend largely on its underlying design and 

site-specific conditions. The commenter stated that for this reason, standards for reconstructions 

are done on an individual facility basis. See 40 C.F.R. section 60.15(b)(2) (reconstruction means 

"the replacement of components of an existing facility" to the extent it "is technologically and 

economically feasible to meet the applicable standards"); 79 FR at 34971/2 (recognizing "need to 

clearly delineate between a reconstructed source and a newly constructed source" when setting 

standards).

Commenter 0291 stated that EPA cannot reasonably assume that any specific level of emission 

reduction can be achieved across the board by EGUs undertaking a modification. The level of 

additional emission reductions, if any, that can be obtained from a source undergoing a 

modification can only be determined on a case-by-case basis, depending on: (1) the current level 
5-36

of heat-rate efficiency at which the unit operates; (2) the nature of the modification being 

undertaken; (3) the nature of previous modifications made and the emission reductions achieved 

during such earlier modifications; (4) the cost and burden of obtaining additional emission 

reductions relative to the amount of additional emission reductions achievable; and (5) the effect 

of such additional reduction-related requirements on the continuing ability of the unit to provide 

a reliable source of power. Commenter suggested that rather than specifying any across-theboard numeric emission reduction goal to be obtained by EGUs undertaking a modification, EPA 

should instead adopt a standard that allows for a state determination, on a case -by-case basis, of 

what emission reductions are possible and reasonable after consideration of the above five 

factors. 

Response 5.4-3: The EPA has properly finalized 111(b) standards of performance for 

reconstructed units – rather than setting up a case-by-case determination of the final standard. 

The EPA also has not proposed to – nor finalized – any changes to 40 CFR 60.15 provisions for 

reconstructed sources.

Applying national averages to individuals units rather than case-by-case basis 

Comment 5.4-4: Commenter 0187 stated that the Agency's heat rate improvement assertion is 

flawed for several reasons: national averages cannot be applied directly to individual units as 

each unit must be evaluated on a case-by-case basis and specific unit's heat rate is primarily due 

to factors outside of the source's control such as plant location, design, age, and size, coal type, 

cooling system type, grid dispatch, time of year the unit is dispatched, ambient temperature, 

auxiliary load requirements, pollution controls, and other factors; also, the operation of SO2

scrubbers, SCR controls, and fabric filter baghouses degrade the heat rate of EGUs. The 

commenter stated that because many utilities took steps to improve the efficiency of their units, it 

would be inappropriate for EPA to use any year prior to the year in which those projects were 

undertaken as the baseline for heat rate improvements; furthermore, future projects that will

reduce unit efficiency will need to be taken in response to environmental regulations, such as 

MATS and Regional Haze; and other future compliance requirements must be accounted for 

prior to any heat rate improvement requirement.

Commenter 0242 stated that the permitting or implementing authority should be making a unitspecific determination based upon potential energy efficiency improvements for all source types 

based upon unit-specific information and the cost and technically feasibility.

Commenter 0257 stated that the efficiency improvements cited by the EPA were determined on 

an industry-wide aggregate basis; therefore, they apply well to some individual generating units 

and not so well to others. The commenter stated that it is inappropriate to apply measures 

determined in aggregate to individual units, especially when the information is available to 

determine what improvements are achievable for each. The commenter stated that in some cases, 

recent investments already have been made to improve the heat rates of existing coal-fired units 

and additional efficiency gains of the magnitude proposed in the rule would be infeasible both 

physically and economically. The commenter requested that to the extent EPA retains a 

requirement to improve efficiency for modified or reconstructed units, the EPA allow affected 

units to credit previous efforts to improve heat rate toward compliance with these standards.
5-37

Commenter 0214 stated that the EPA erred in relying on its GHG Abatement Measure TSD 

(which was developed to support the Agency's section 111(d) Proposed Guidelines) as it 

primarily analyzed national annual average CO2 emission rates which do not support unitspecific standards. The commenter stated that the GHG Abatement Measures TSD, thus, mutes 

unit-level CO2 emission rate variability; for example, the net CO2 emission rates of the 

commenter's coal-fired units show significant CO2 emission rate variability at the unit level. The 

commenter included figures in their submission to illustrate the unit-level variability. The 

commenter stated that EPA's assumptions regarding nation-wide emission rate averages are a 

poor estimate for what a single modified boiler could achieve nor does the GHG Abatement 

Measures TSD provide any data resembling EPA's proposed compliance criteria (i.e., 12-

operating month rolling average net CO2 emission rate data). The commenter stated that, thus, no 

support is provided to justify the achievability of the Agency's proposed standards for modified 

boilers and IGCC units.

Commenter 0291 stated EPA cannot reasonably assume that any specific level of emission 

reduction can be achieved across the board by EGUs undertaking a modification. Commenter 

said the level of additional emission reductions that can be obtained from a source undergoing a 

modification can only be determined on a case-by-case basis, depending on: (1) the current level 

of heat-rate efficiency at which the unit operates; (2) the nature of the modification being 

undertaken; (3) the nature of previous modifications made and the emission reductions achieved 

during such earlier modifications: (4) the cost and burden of obtaining additional emission 

reductions relative to the amount of additional emission reductions achievable: and (5) the effect 

of such additional reduction-related requirements on the continuing ability of the unit to provide 

a reliable source of power, rather than specifying any across-the-board numeric emission 

reduction goal to be obtained by EGUs undertaking a modification, EPA should instead adopt a 

standard that allows for a state determination, on a case -by-case basis, of what emission 

reductions are possible and reasonable after consideration of the above five factors. 

Response 5.4-4: The EPA has properly finalized 111(b) standards of performance for 

reconstructed units – rather than setting up a case-by-case determination of the final standard. 

The EPA also has not proposed to – nor finalized – any changes to 40 CFR 60.15 provisions for 

reconstructed sources.

Need for subcategories 

Comment 5.4-5: Regarding EPA's claims of the cost of BSER and the commensurate 

improvements in efficiency, Commenter 0169 stated that for a newly constructed unit, it does not 

matter if the best practices are high cost, low cost, or no cost, if the unit has been designed and 

built with those options already included. The commenter stated that as a newly-constructed, 

technologically advanced, stand-alone unit, their unit is disproportionately affected by presuming 

that either a 2 or 4 percent reduction in CO2 emissions is achievable. The commenter stated that 

this demonstrates the need for sub-categorization of units within the Modified Source Rule, 

giving newly constructed units a separate performance standard than older units; in fact, these 

newer units should set the bar for BSER. 

Commenter 0169 stated that for a newly constructed unit, it does not matter if the best practices 

are high cost, low cost, or no cost, if the unit has been designed and built with those options 
5-38

already included, as the commenter has. The commenter stated that as a newly-constructed, 

technologically advanced, stand-alone unit, they are disproportionately affected by presuming 

that either a 2 or 4 percent reduction in CO2 emissions is achievable. Both of these demonstrate 

the need for sub-categorization of units within the Modified Source Rule, giving newly 

constructed units a separate performance standard than older units. In fact, these newer units 

should set the bar for BSER. In a footnote, the commenter stated that the GHG Abatement TSD 

does not support EPA's conclusion in this context. EPA prepared the GHG Abatement TSD to 

demonstrate in the ESPS docket the available average heat rate improvements compared to 2012 

values for existing EGUs; yet EPA attempts to use that same analysis to demonstrate that 

individual units which perform modifications can reduce emissions an additional 2 percent 

beyond their best demonstrated historical performance from 2002 through the time of the 

modification.

Response 5.4-5: This comment addresses standards for modified EGUs – which have been 

addressed in Chapter 6 of this RTC. The final standards for modified sources reflect the best 

historical performance of the affected source itself and therefore there is no need to 

subcategorize by size, fuel-type, location, or boiler type.

Subcategorize by fuel type and boiler configuration 

Comment 5.4-6: Commenter 0255 stated that EPA should subcategorize the modified [sic] 

boiler carbon dioxide intensity floor for fuel type and boiler configurations. The commenter 

stated that a limit of 1,900 lb CO2/MWh-net is not appropriate for plants that fire lower-ranked 

fuels such as lignite. The commenter stated that under EPA's CPP, North Dakota power plants 

would have to achieve an intensity goal of 2,226 lb CO2/MWh-net, a much more reasonable 

floor for pulverized coal boilers firing North Dakota lignite fuel; cyclone-fired boilers may 

require an even higher floor.

Commenter 0222 stated that the EPA proposes to group utility boilers, mainly coal- and lignitefired power plants, into the same source category as IGCC units. The commenter stated that 

traditional coal-fired power plants are in a completely different class and are of an entirely 

different type than IGCC units and the differences in generation technologies result in different 

emissions profiles, including differences in the rate of CO2 emissions. The commenter stated that 

like the lignite category, the distinction between coal-fired power plants and IGCC units was 

explicitly recognized in the MATS Rule, in which the IGCC category was subject to distinct 

emissions limits, recognizing these differences in generation technologies. The commenter stated 

that in the New Source Rule 111(b) proposal, EPA proposed creating a separate subpart (subpart 

TTTT) which would separate utility boilers and IGCC units into different categories; this new 

subpart is evidence of EPA's own recognition that traditional coal and lignite-fired power plants 

should not be grouped into a single category with IGCC power plants. The commenter stated that 

for the reasons discussed in the MATS Rule and New Source Rule Proposal, the EPA must not 

group traditional coal- and lignite-fired generation units with IGCC units; the differences 

between the technologies are too great and necessitate a separate subcategory.

Response 5.4-6: Triggering the reconstruction provision is a significant economic hurdle - and it 

has only rarely been done. However, in the event that a unit does trigger the reconstruction 

provisions, the reconstructed unit would not be required implement any particular technology or 
5-39

take any specific actions. Rather the reconstructed unit must meet a standard of performance 

consistent with the emission reductions achieved by the BSER. Owners/operators can do so by 

installing a new well-performing boiler, or by refurbishing an existing boiler in order to meet the 

final standard. Owners/operators can also take advantage of other options to further reduce 

emissions and meet the final standard of performance – such as coal drying (for lignite-fired 

units) or natural gas co-firing which has long been recognized as an option for coal-fired boilers 

to reduce emissions of air pollutants. In any case, per 40 CFR 60.15, if the owner/operator can 

demonstrate it is not "technologically and economically feasible to meet the applicable standards 

set forth in this part", then it would not trigger the reconstruction provisions.

Identify appropriate BSER for modified/reconstructed sources and apply to determine 

standards of performance achievable by the source category 

Comment 5.4-7: Commenter 0214 stated that they are concerned that establishing a source 

category-wide, or even subcategory-wide, numerical standard that is achievable by most 

potentially affected units is likely impossible, given the significant variability from unit to unit, 

and even at the same unit from year to year. The commenter stated that if EPA attempts to 

develop appropriate separate standards of performance for modified and reconstructed coal-fired 

and natural gas-fired units it must: (1) identify an appropriate BSER and (2) apply that BSER to 

determine standards of performance that are achievable by the source category. 

Response 5.4-7: The EPA has identified separate standards for modified and reconstructed 

sources based on the determination of different BSERs for each category.