Chapter 6
 Modified Fossil Fuel-fired Utility Boilers and IGCC Units
6.1	Identification of BSER	4
Same BSER for modified and reconstructed sources	4
6.1.1 Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades	5
Efficiency improvements can be made without triggering a modification	5
EPA Underestimates the Potential for Efficiency Improvements	7
<IP_ADDRESS> Technical Feasibility	8
<IP_ADDRESS> CO2 Reductions	42
<IP_ADDRESS> Costs	43
<IP_ADDRESS> Incentive for Technological Innovation	46
6.2	Determination of the Level of the Standard	47
2% HRI not achievable due to many factors	47
In setting standards, EPA incorrectly interpreted the 2009 Sargent & Lundy report in regards to improvements related to Building Block 1	49
Proposed standards of performance are not achievable and are therefore not lawful	50
Standards equivalent to reconstructed sources are not appropriate	50
Modified/reconstructed source standards should not be same as standards for new sources	51
Relationship with 111(d)	51
Setting limits using EPA proposed ranges	52
Standards are too lenient	53
6.2.1 Unit-specific Emission Limit	56
Unit-specific standards illegal	56
Standards at each unit should be feasible based on a proven, operational, technological and economic standpoint	59
Compliance options	61
Exemption from 2% additional emission reduction	61
EPA must set a numeric emission rate	63
EPA proposed practicable emissions standard	63
6.2.2 Dependent on the Timing of the Standard	64
Standards based on timing of a modification are not lawful.	64
Concern over date of state plan submittal and impact on utilities considering a modification or reconstruction.	65
Alternative dates for compliance.	65
Favors Alternative #2, but believes EPA provides little detail for these alternatives.	66
Favor Alternative #2 for sources that modify after becoming subject to 111(d) plan.	66
Problems with option 1 (modification occurs before state plan) under Alternative #2.	66
6.2.3 Historical Performance Data	67
Reducing emission rate by 2% below historical best performance not achievable.	67
Proposal of Alternative #2 implies that Alternative #1 is not demonstrated.	68
Heat rate is not a good measure for identifying the "best demonstrated historical performance."	68
Prefer Alternative #1, but make historical performance period from 2002 to last full calendar year before modification expected construction start date.	70
Prefer Alternative #1, but standard should be based on multiple years.	71
Prefer Alternative #1, but period of best historical performance should be years from 2002 to the time when the unit becomes subject to section 111(d).	74
Heat rates prior to a PCP should not be used in determining best historical CO2 emission rate.	74
Prefer Alternative #1, but implement in a way that does not penalize investments in heat rate improvements.	75
Establish limit based on expected future operations including lower operating loads levels due to greater use of renewables.	76
6.2.4 Energy Assessment: Similar to NESHAP for Industrial Boilers	78
Contrary to NSPS and CAA	78
Energy efficiency audit in not a standard of performance that reflects BSER for the source category as required under CAA 111(a).	78
Contrary to NSPS and CAA - Lack of details on procedures and demonstration of feasibility & fails the notice and comment obligations of CAA.	80
EPA's proposed site specific standard and failure to provide for notice and comment are unlawful.	81
There is no CAA authority for third party audit as basis of standard.	82
Lack of details and lack of support call into question the feasibility of audit approach.	82
Energy audit requirements not well defined, and, instead, support work practice standards.	83
Alternatives #1 and #2 are unachievable.	83
In absence of energy audit expert certification process, EPA should not require one.	84
Use of previous energy audits.	84
Instead of the proposed vaguely defined auditing process, EPA should use PSD programs pre-permitting BACT reviews.	84
Purpose of energy audits unclear as states would have to rely on methods other than unit-specific emission rates for modified units to meet their state goals.	85
Standard that allows states to determine on a case-by-case basis what emission reductions are possible and reasonable after consideration of site specific factors is reasonable alternative.	85
EPA should consider using the BACT process to set emission standards for modified and reconstructed units	87
6.2.5 Subjectivity to 111(d)	88
Support for being subject to the lower of the 111(d) plan instead of the unit's best performance since 2002	88
Heat rate improvement potential - an additional 2 percent efficiency improvement may be unachievable for sources that make efficiency improvements as part of a 111(d) state plan. There is simply no record basis for this.	88
Heat rate improvement potential - EPA is applying existing unit standards (aggregated data for older and newer units) with modified unit standards (unit level rates). This results in standards not shown to be achievable at unit level (not supported in the proposal) as required by 111(a)(1).	88
Reliance on the Sargent & Lundy study does not justify heat rate improvement potential.	90
Modified source emission standard should consider whether a modification occurs after or before the Section 111 (d) requirements are effective.	90
Sources subject to 111(d) guidelines should remain under 111(d) guidelines and not be subject to Section111 (b).	90
Modified sources subject to a 111(d) plan should be evaluated on a case-by-case basis to determine whether or not they should be subject to the 111(d) requirements.	92
If EPA requires the 2 percent reduction requirement, it should require that the reduction be off of a unit's heat rate at full load per, calculated pursuant to ASME performance test codes.	93
Existing unit reductions are not achievable, it is unrealistic to expect an additional 2% reduction for modified units, and reliance on hypothetical unit is overly simplistic.	93
Should uniform emission standards be available only to sources that modify before becoming subject to an approved 111(d) plan?	94
EPA lacks authority to require modified sources to remain subject to section 111(d) regulation after modification.	94

Identification of BSER
Commenter 0215 believed that EPA revealed an incomplete nature for its Proposed Standards for modified units by posing a long series of questions that seems calculated to shift the burden of developing a basis for the Proposed Standards to the regulated community. EPA's queries essentially showed that the Agency wasn't confident how its Proposed Standards might affect or apply to the approximately 955 coal-fired Subpart Da units that UARG expects will be operating in 2015. The Agency's failure to complete the necessary background work suggests that a more appropriate course of action at this time would have been an advance notice of proposed rulemaking designed to elicit information to use in formulating a proposal, rather than propose an approach that is both poorly-conceived and has not been analyzed. Commenter said they appreciates the Agency's interest in obtaining information necessary to develop a sound proposal, but the myriad questions posed here confirm that EPA has failed to collect the data and perform the technical analyses needed to identify and analyze the impacts of its Proposed Standards. Commenter said they can respond to some of EPA's inquiries, but many of EPA's questions cannot be answered without detailed analyses of emissions and other data that the Agency should have undertaken and placed in the docket as part of its basis and purpose of the Proposed Standards. See CAA section 307(d)(3). Commenter said the APA defines a rule as a statement of "future effect" designed to "prescribe law or policy." See 5 U.S.C. section 551(4). Because a rule is intended to prescribe the legal standards that govern the future conduct of regulated parties, a proposed rule must be more than a vague set of criteria for future applications with a series of questions regarding how the Agency might formulate a final rule. See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 549 (D.C. Cir. 1983) ("Agency notice must describe the range of alternatives being considered with reasonable specificity" to allow for adequate public comment and "better-informed agency decision-making"; unspecified, general notice is inadequate). Commenter said the Agency's Proposed Standards are entirely inadequate in this regard, and thus EPA should terminate this proceeding until it has had time to gather and analyze the data needed to formulate a proper proposed rule.
The EPA did provide appropriate and adequate specificity concerning the standards that were being considered in the proposed action. The well-developed and considered comments received on the proposed action  -  and summarized in this Response-to-Comment document  -  are testament to that specificity.
Same BSER for modified and reconstructed sources
Commenter 0263 stated that the EPA chose BSER for modified sources as the most efficient generation at the affected source achievable through a combination of best operating practices and equipment upgrades; however, for reconstructed sources, EPA proposed most efficient generating technology at the affected source as BSER. The commenter stated that EPA should choose the same BSER for modified and reconstructed sources, and BSER should be comprised of increased efficiency achieved through a combination of best operating practices and equipment upgrades. The commenter stated that CAA regulations mandate that BSER sets the floor for future BACT determinations, but EPA rules do not require a state to consider any control technology that would require a redesign of the proposed source. The commenter stated that the EPA's own guidance on GHG permitting states that a control technology can be excluded from a BACT analysis if the control strategy would disrupt the facility's basic or fundamental business. The commenter stated that if EPA were to select supercritical technology as BSER, it would force source redesign as BACT and would eliminate the states's ability to consider a source's primary business purpose when assessing appropriate emission controls. The commenter recommended that EPA maintain its proposed combination of best operating practices and equipment upgrades as BSER for modified utility boilers and IGCC units; they also recommended that EPA determine the combination of best operating practices and equipment upgrades as BSER for modified natural gas combined cycle (NGCC) and all reconstructed units as well.
The EPA has maintained its proposed combination of best operating practices and equipment upgrades as BSER for modified utility boilers and IGCC units as suggested by the commenter.  However, we have done so only for those EGUs that make modifications that result in an increase of potential hourly CO2 emissions of more than 10 percent. As we indicated in the proposal and reiterate in the final preamble, the EPA has been notified of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. 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. We do not have sufficient information at this time, however, to anticipate the types of modifications, if any, that may result from these changes. In particular, for steam generating EGUs (utility boilers and IGCC units) we do not have sufficient information about the types of modifications, if any, that would result in hourly increases in CO2 emissions of 10 percent or less, and what the appropriate standard for such sources should be. Therefore, we conclude that it is prudent to delay issuing standards for sources that undertake small modifications (i.e., those resulting in an increase in CO2 emissions of less than or equal to 10 percent) and we have withdrawn the proposed standards for those sources in the final action.
The commenter also recommended that EPA determine the combination of best operating practices and equipment upgrades as BSER for modified natural gas combined cycle (NGCC) and all reconstructed units as well. The EPA is not finalizing standards for modified stationary combustion turbines and in withdrawing those standards in the final action (see preamble sections VII, VIII, and XV.)
6.1.1 Efficiency Improvements Achieved Through a Combination of Best Operating Practices and Equipment Upgrades
Efficiency improvements can be made without triggering a modification
Commenter 0244 stated that efficiency improvement projects can be undertaken without modifying an EGU for NSPS purposes. [The commenter lists several efficiency upgrades that have been identified for existing EGUs that include improvements on a number of operation and maintenance controllable variables.] The commenter pointed out that within the potential efficiency improvement options, only one upgrade option - turbine blade replacements - has been mentioned as a potential NSPS modification. The commenter stated that industry representatives have suggested that EPA should not establish rigorous standards for modified units because some potential projects that improve the plant's overall thermal efficiency may also increase a unit's hourly emissions rate of CO2. These representatives argue that projects of this nature should be encouraged to the greatest extent possible, and highlight in particular the example of turbine blade replacements. While individual blades or groups of blades may routinely be replaced with new blades of the original designs, the maximum generating capacity of the unit (in terms of megawatts) and the unit efficiency can be improved by replacing all of the blades in one or more of the three stages of a steam turbine with improved blade design, blade layout, and edge seals that more effectively convert thermal steam energy into electricity. For those operators seeking the maximum available capacity increase, the engineering solution is to add additional heat capacity to the boiler. If this choice is made, the unit produces more electricity per unit of fuel than it did previously, but now emits more CO2 and criteria pollutants per hour as well, in which case the unit may qualify as modified for NSPS purposes. The commenter stated that source operators can implement many of the potential efficiency upgrade options in a way that would constitute a NSPS modification, but only because those upgrades would result in capacity increases. The commenter stated that this is a choice that is available to owners for condensers, fans, burners, and other components, but under no circumstances is it necessary to select a larger capacity component in order to achieve greater efficiency. It is therefore incorrect to assert, as some industry representatives have done, that plant operators cannot improve their units' thermal efficiency without triggering the NSPS modification rules.
The commenter stated that under the agency's current policy, turbine blade replacements by themselves do not constitute section 111 modifications and thus do not trigger applicability of a modified source performance standard because the agency has specified that steam turbines are not part of the existing affected facility for NSPS purposes. The commenter stated that EPA regulations at 40 C.F.R. 60.14(e)(2) specify that if an increase in production rate of an existing facility can be accomplished without a capital expenditure on that facility, then it does not constitute a modification under section 111. The commenter stated that under the agency's current policy, a turbine blade replacement project that does not entail capital expenditures to the boiler itself or some other piece of equipment that falls within the definition of electric utility steam generating unit does not qualify as a modification for the purposes of the NSPS program, even if the project increases the hourly emission rates of CO2 or other pollutants.
The commenter stated that the most appropriate limit for modified units is the new source standard, which we believe should be no less stringent than 1,200 lbs CO2/MWh on a net output basis, reflecting a BSER of efficiency generating technology with partial CCS. According to the commenter a number of successful turbine blade replacement projects have been undertaken over the years without associated capital boiler projects that increase hourly emissions and EPA has published at least one Applicability Determination confirming that turbine blade replacements can be done in a manner that does not constitute a modification under the NSR program. Commenter referenced a Siemens report and a letter from EPA region 5. The commenter stated that to their knowledge EPA has only asserted that the NSPS program applies to large life extension projects, in which a turbine blade replacement would be part of a larger project that included capital boiler upgrades.
The EPA agrees with the Commenter that there are many efficiency / heat rate improvements that EGUs can make  -  and have made  -  that do not result in an increase in hourly emissions of CO2 and thus do not trigger the 111(b) modification provisions. However, the EPA does not provide specificity on exactly what projects or scenarios would or would not trigger 111(b) modification for GHG emissions as sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.
EPA Underestimates the Potential for Efficiency Improvements
Commenter 0244 summarized BSER for modified coal plants and noted that these units would remain subject to any applicable state plan under section 111(d) regardless of modification. The commenter stated that in the event a court found that existing units that undergo modifications cannot remain subject to the requirements of the (d) plan, EPA's proposal would be far less stringent than the proposed emission guidelines for unmodified existing units, and even if these sources are retained in 111(d) plans, modifications that extend the life of 50-year old plants should be discouraged by stringent 111(b) obligations. The commenter stated that EPA has provided no adequate rationale for not applying the new source standard, nor has it sufficiently justified its rejection of other BSER options for modified steam EGUs, including the use of combined heat and power (CHP), hybrid power plants, and reductions in generation associated with dispatch changes, renewable generation, and demand-side energy efficiency.
The commenter stated that a capital intensive modification that increases the emissions of an NSPS-regulated unit is and should remain rare; if such an investment is warranted because of the value of the unit, the modifying unit should incorporate the full suite of available efficiency improvement options. The commenter stated that the record does not support any threshold emission rate for existing units below which efficiency improvements are no longer feasible; EPA's unit-level emission data set included in its 111(d) Goal Computation TSD contains at least 25 coal-fired EGUs with reported emission levels of less than 1,900 lbs CO2/MWh (net), and many more smaller units with emission rates below 2,100 lbs CO2/MWh (net), belying any notion that emission limits of 1,900 and 2,100 lbs CO2/MWh represent a technological barrier for efficiency in existing units. The commenter stated that data maintained by EPA's Air Markets Program Division confirms that efficiency improvements below 1,900 lb CO2/MWh (net) are readily achievable. The commenter provided two examples (Rush Island Unit One and Belews Creek Unit One) that can be found in EPA's data to illustrate their point. The commenter stated that the agency has the means to evaluate these data fully and make a determination based on actual evidence rather than an unsupported, generalized assumption.
As we indicated in the proposal and reiterate in the final preamble, the EPA has been notified of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. 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 implement projects that will result in an increase in hourly emissions of 10% or more and considering that the current fleet of fossil fuel-fired steam-generating EGUs varies considerably in terms of the age, location, size, technology, etc., it was most appropriate to finalize a standard that could be met by the affected modified EGU. The final standard, which is based on the best potential performance of the modified EGU, is achievable regardless of age, location, technology, or other unit-specific parameters.
<IP_ADDRESS> Technical Feasibility
Not achievable and not demonstrated
Several commenters (0144, 0150, 0152, 0156, 0153, 0157, 0170, 0179, 0183, 0187, 0192, 0195, 0203, 0208, 0215, 0218, 0221, 0222, 0223, 0226, 0229, 0231, 0235, 0242, 0249, 0254, 0276, 0278, 0284) stated that the EPA has not provided the required support and technical demonstration that the proposed BSER is technically feasible.
The EPA disagrees with this premise. As shown in responses to subsequent comments in this section of the Response-to-Comment document, the EPA has demonstrated the technical feasibility and achievability of the final standards for affected modified and reconstructed EGUs.
Commenter 0183 stated that an engineering firm conducted a preliminary analysis of potential heat rate improvement opportunities at the commenter's coal-fueled units and that analysis determined that EPA's 4 percent projection overstates the potential for heat rate improvements, which for the commenter's units showed a range of potential heat rate improvements of less than 0.5 percent. Thus, from all perspectives, EPA's projections are vastly overstated and unachievable. The commenter stated that even the modest improvements that may be possible cannot be sustained given that additional factors negatively impact heat rate efficiency, including the addition of environmental control equipment and their auxiliary load in response to other EPA rules. According to the commenter, assuming the remaining fleet will be required to implement these technologies as the EPA continues to lower the emission requirements for the existing coal fleet, the heat rate of the existing fleet would likely be increased over 1 percent.
As provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of existing coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection.
Commenter 0221 stated that EPA's proposed standard for modified and reconstructed EGUs exceed its statutory authority since they are not achievable as required by section 111. The commenter stated that no existing subcritical unit has ever been converted to supercritical technology since it is economically impractical; therefore, conversion to supercritical technology has not been adequately demonstrated. The commenter stated that the emission limits proposed, 1,900 pounds of CO2 per megawatt hour (lb CO2/MWh) net or 2,100 lb CO2/MWh-net depending on heat input, have not been achieved by new units much less existing units undergoing reconstruction.
See response to previous comment on the technical feasibility of the final standards for modified sources. 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. The 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. The EPA 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.
Commenter 0183 stated that the EPA has failed to demonstrate the achievability of a 1,900 lbs CO2/MWh standard for the source category, a value that is not sustainable even at an ultra-supercritical (and thus highly efficient) unit, much less by the existing fleet of coal plants in the country. According to the commenter, the only ultra-supercritical plant operating in the country, AEP's Turk unit was designed to emit approximately 1,940 lbs CO2/MWh. The commenter stated that while early data from the first year of operations showed that the Turk unit could, at times, operate below 1,900 lbs CO2/MWh, its efficiency will likely degrade over time, as with all coal plants, and would exceed 1,900 lbs CO2/MWh; the first year of operation will likely be atypical from a CO2 emissions standpoint. The commenter stated that EPA fails to address or account for these data; further, based on research by J. Edward Cichanowicz and Michael C. Hein, a reasonable standard must subcategorize sources to address the clear differences in CO2 emission rates from subcritical, supercritical, and ultra-supercritical units and from different coal types. The commenter stated that EPA has attempted to show that a value of 1,900 lbs CO2/MWh may be achievable in the short term at a new ultra-supercritical unit designed to meet that rate, but it has not identified any control technology or retrofit of an existing coal unit that could bring a supercritical unit, especially a lignite unit, into compliance with that rate.
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. The commenter claimed that the Turk unit's first year of operation will likely be atypical from a CO2 emissions standpoint and that the performance will likely degrade over time. The figure below does not show that to be the case.  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. Further, as the EPA has noted in the preamble in section VII, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation.

Figure 6-1. Monthly CO2 emission rates (lb CO2/MWh-g) from the AEP John W. Turk plant

Commenter 0214 stated that EPA's proposed BSER determination for modified boilers and IGCC units is flawed because EPA failed to analyze the technical feasibility and cost reasonableness of equipment upgrades for all affected sources - that is - all fuel types, technologies, and sizes. The commenter stated that while EPA mentions equipment upgrades have been made at a "wide range of power plants," the Agency must provide real-world examples not just broad general statements; specifically, EPA must provide sufficient information regarding the equipment upgrades that EPA claims are capable of achieving compliance with EPA's proposed standards at all potentially affected sources, taking into account all different fuel types, combustion technologies, and size classes, which it has not done.
Commenter 0218 stated that the EPA failed to correlate their statistical study with actual case studies of base-load EGUs which employ such best practices to reduce heat rate variability relying instead on a 2009 Sargent & Lundy study, which determined a potential heat rate improvement range for each of the identified equipment upgrades based on a literature review. The commenter stated that based on the average of the study's ranges of potential heat rate improvements from equipment upgrades, and a determination that half of the equipment upgrade opportunities outlined in the study remain for existing units, EPA proposed the technical potential for heat rate improvements that could be achieved from equipment upgrades are on the average of two percent. The commenter stated that to account for facilities that have already implemented BSER, i.e., best practices and equipment upgrades, EPA proposed that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed facilities; EPA proposed a unit specific standard equal to a 2 percent reduction in the unit's historical CO2 emission rate, but not lower than the proposed standard for reconstructed units. The commenter stated that EPA did not provide any data to support this proposed standard. Therefore, it must be considered arbitrary and capricious.
First, the EPA notes that the additional 2% reduction that was suggested in the proposal has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of existing coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.
Commenter 0242 stated that they have concerns regarding a unit encroaching upon a low end cap rate that would be achievable by reconstructed units applying BSER and that this is why setting any fixed limits based upon energy efficiency potential that are technically and economically feasible outside of a source specific analysis is not appropriate.
Commenter 0214 stated that the EPA's claim that a unit can consistently perform at its historical best demonstrated annual performance is unreasonable and unsupported and that the EPA does not consider that a unit's efficiency is variable over time due to uncontrollable factors, such as: shifting operating conditions (e.g., changing capacity and load factors), changes to parasite load due to environmental controls, natural efficiency degradation, prevailing weather conditions, availability of other units and resulting impacts to load profile, and fuel switches (e.g., bituminous to subbituminous coal), and other factors.
In Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. The most conservative approach that is supported by the weight of evidence yields average potential heat rate improvements of 2.1 percent in the Western Interconnection, 2.6 percent in the Texas Interconnection, and 4.3 percent in the Eastern Interconnection. In that Chapter of the TSD, EPA discusses the issues of variability and factors outside the operators' control, and provides additional information on heat rate improvement practices and equipment upgrades that might be available to coal-fired EGUs. Implementation of these best practices and equipment upgrades will allow units to maintain best potential performance. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.

Commenter 0253 stated that EPA's proposed numerical range of potential emission limits for the several different source categories 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 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 EPA did not suggest that proposed or final standards for modified steam generating units should be met with CO2 specific control technologies, such as carbon capture and sequestration. The EPA proposed and is finalizing that the standards for affected modified steam generating EGUs can be met through unit efficiency improvements achievable through a combination of best operating practices and equipment upgrades. The commenter notes that "an existing unit's achievable efficiency and CO2 emission rate will depend largely on its underlying design and site-specific conditions". The EPA largely agrees  -  which is why the final standard of performance for affected modified steam generating EGUs is unit-specific and will depend upon that unit's own best potential performance  -  inherently taking into account its underlying design and site-specific conditions.
Commenter 0226 stated that the suggestion in the proposal that heat rates can be improved at existing units up to 2 percent through equipment upgrades is not adequately supported. The commenter stated that part of the proposed support is found in the docket in Chapter 2 of the document GHG Abatement Measures; section 2.5.9 of the document discussed that 16 EGU s were identified that reported a single year-to-year heat rate improvement of 3-8 percent. The commenter stated a search of the docket reveals, at EPA-HQ-OAR-2013-0602-0236, that a Cleco unit, Brame Energy Center Unit ID 2, is listed as one of the identified 16 units. The commenter stated that they are not aware of reporting heat rate data to EPA in the past and they calculated the annual heat rate for Brame Energy Center Unit ID 2 over the years 2002-2012 using measured fuel input and measured generated electricity (gross) and that none of the changes in heat rate from one year to another are as much as a 2 percent increase. The commenter stated that they are not aware of any upgrades taking place during the time period that would account for any heat rate improvements referred to in the TSD GHG Abatement Measures; the variation in heat rate is thought to be due to the way in which the unit was operated.
Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603) has been updated in response to comments received on this proposed action as well as the proposal, under CAA 111(d), for emission guidelines for existing sources. The analyses in the final document (Chapter 2) indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. Further, as the EPA has noted in preamble section VI, owners/operators can also consider the use of natural gas co-firing to achieve the final emission limitation for affected modified EGUs.
Commenter 0144 requested that the EPA provide the support and technical demonstration of the feasibility of requiring an additional 2 percent reduction in annual CO2 emissions, particularly when there is already a debate on whether the 6 percent heat rate improvement is achievable. The commenter stated that because the EPA intends for units to be subject to both Sections 111(d) and 111(b), they are interested in the technical review of how these requirements were evaluated together. The commenter stated that EPA has not provided the historical calendar year CO2 emissions data from 2002 to 2013 that would be the basis for this proposal, nor has it calculated the specific emissions limit that would have to be achieved for the EGUs subject to this proposal using its 2 percent methodology; without adequate record support, such requirements are arbitrary and capricious and contrary to the CAA.
The EPA is not finalizing the requirement of an additional 2% reduction as proposed.
Commenter 0150 stated that EPA's proposed BSER is each unit's own best potential performance based on a combination of best operating practices and equipment upgrades. The commenter stated that EPA has provided no analysis supporting this conclusion and, for this reason alone, the Modified/Reconstructed Proposed Rule for modified Subpart Da EGUs is unlawful.
The EPA disagrees. The information provided in the GHG Abatement Measures Technical Support Document provided ample support for the proposed standards. The analysis provided in the final Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that modified units also have the option of meeting the final standard of performance through the use of natural gas co-firing.
Commenter 0192 stated that EPA overestimates the potential for heat rate improvements at existing coal-fired EGUs by assuming that all of the heat rate improvements identified in studies cited in the GHG Abatement Measures Technical Support Document are additive when in reality, many of the identified heat rate improvements will have overlapping effects, meaning that if implemented together, the overall reduction in CO2 emissions would be less than what EPA projects by simply adding together their isolated impact on CO2 emissions. The commenter stated that EPA also does not establish that any single facility could implement each of the heat rate improvements identified by EPA; in some cases, due to design constraints and other technical issues, two or more of the heat rate improvements may be mutually exclusive and a facility would have to choose between them when seeking to reduce emissions through heat rate improvements. The commenter stated that EPA's failure to consider these impediments to emissions reduction through heat rate improvements is arbitrary and capricious.
Commenters on the 111(d) proposed emission guidelines also commented that many of the heat rate improvement equipment upgrades cited in the GHG Abatement Measures Technical Support Document might not be additive because many of the identified heat rate improvements will have overlapping effects. As noted in section 2.5 of the final `GHG Mitigation Measures' TSD, the EPA generally agrees with this point but does not agree that it improperly characterized or misused information from the cited studies (specifically the Sargent & Lundy study  -  "Coal-fired Power Plant Heat Rate Reductions", Sargent & Lundy LLC, January 2009. Available at http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf). Specific responses to commenter's criticisms of the EPA's statistical analysis are provided in Chapter 2 of the `GHG Mitigation Measures' TSD.
Commenter 0146 stated that although EPA has said that its proposed NSPS can be met through a combination of best operating practices and equipment upgrades, the rulemaking docket is utterly devoid of any TSD that provides any support for that assertion. The commenter stated that the Agency has completely failed to analyze whether its proposed standard is achievable for the units to which it would apply and has violated its obligation under section 111 to propose standards of performance that are achievable. The commenter stated that, more fundamentally, EPA has violated its obligation under section 307(d) of the CAA to provide the basis and purpose for the proposal, which is to include a summary of (A) the factual data on which the proposed rule is based; (B) the methodology used in obtaining the data and in analyzing the data; and (C) the major legal interpretations and policy considerations underlying the proposed rule. The commenter stated that, of particular note, the docket fails to include the annual historical operating performance for each affected facility using historical CO2 emissions data for the calendar years 2002 through the present that the Agency refers to in proposed section 60.46Da(c)(3)(i)(A) and that without such data, regulated EGUs cannot determine what numerical emission limits they would potentially be subject to upon modification, and cannot meaningfully comment on the proposed NSPS. The commenter stated that also missing from the docket are any EPA calculations using its proposed methodology and any estimates by the Agency of the range of emission limits that modified Subpart Da units might be expected to achieve; without such calculations, which logically would have been included in the TSD that is absent from the docket, EPA cannot have conducted a reasonable inquiry into whether those limits are achievable. According to the commenter, this is an egregious failure to comply with section 307(d)(3) and will render any final rule unlawful. Commenter 0146 stated that the EPA does not provide data and analysis to support its proposal for modified Subpart Da EGUs although the Agency does generally refer to theoretical information from its Proposed Existing Source Guidelines rulemaking for existing EGUs. The commenter stated that the EPA's analysis to determine opportunities for heat rate improvement (a total of 6 percent improvement, on average, from best operating practices and equipment upgrades) in the U.S. coal-fired utility power fleet does not explain how that analysis supports its claim that individual modified Subpart Da EGUs can consistently replicate their "best demonstrated historical performance with an additional 2 percent emission reduction. The commenter stated that the document EPA references (which was prepared to support the building block 1 analysis for its proposed Existing Source Guidelines) outlined emission requirements for existing EGUs that are radically different in form, applicability, and stringency from those proposed here, and it cannot reasonably be read to support EPA's claims regarding what emission-improving measures are available for individual modified Subpart Da units.
Claims that the rulemaking docket is "utterly devoid of any TSD that provides any support" for the proposed standard is completely false. At numerous times in the proposal, the EPA points to Chapter 2 `GHG Abatement Measures' TSD, which was placed in the rulemaking docket. Commenters also note that "the docket fails to include the annual historical operating performance for each affected facility using historical CO2 emissions data for the calendar years 2002 ...  and, that without such data, regulated EGUs cannot determine what numerical emission limits they would potentially be subject to upon modification, and cannot meaningfully comment on the proposed NSPS." The EPA disagrees. The regulated EGUs have been reporting numerical emissions data to the EPA under 40 CFR part 75 for some time and the CAMD data is commonly understood to be the best, most reliable, most complete data source to the industry. The proposal `GHG Abatement Measures' TSD was explicit about the source of the data noting "The EPA performed this study using hourly heat input (Btu), and electricity output (MWh) data from the Clean Air Markets Division" (p. 2-16 of the proposal TSD, EPA-HQ-OAR-2013-0603-0005). These data were included in the docket.
Commenter 0146 stated that the conclusions in the GHG Abatement Measures TSD that EPA cites are flawed and do not support the Agency's claims regarding potential heat rate improvements, either in the proposed NSPS for modified Subpart Da units or in the Proposed Existing Source Guidelines. The commenter stated that EPA's analysis does not consider certain limitations on the heat rate improvements available at any individual EGU including the fact that the availability and benefits of efficiency-improving measures are highly site-specific and that many EGUs have already implemented at least some of the measures EPA identifies, meaning that their associated benefits are already accounted for in a unit's historical emissions performance. The commenter stated that many of the efficiency improvements are temporal and as a result, the immediate impact of a heat rate improvement measure on a unit's CO2 emission rate may overstate the benefits of that measure over its expected lifetime. The commenter stated that heat rate-improving actions are not additive, as EPA assumed.
The EPA proposed and is finalizing that the standards for affected modified steam generating EGUs can be met through unit efficiency improvements achievable through a combination of best operating practices and equipment upgrades. The commenter notes that benefits of efficiency-improving measures are highly site-specific and that many EGUs have already implemented at least some of the measures EPA identifies, meaning that their associated benefits are already accounted for in a unit's historical emissions performance. The EPA largely agrees  -  which is why the final standard of performance for affected modified steam generating EGUs is unit-specific and will depend upon that unit's own best potential performance  -  inherently taking into account its site-specific conditions. The EPA further notes that units can also utilize natural gas co-firing as an alternative means of meeting the final standard of performance. Moreover, sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.

Commenter 0178 stated that the data used for development of the existing source standards is not applicable to modified sources and should not be used. The commenter stated that any requirements associated with heat rate improvement in general are dependent on the original design of the unit and heat rate and the impact of heat rate improvements will vary along the load curve for each generation unit. The commenter stated that production at partial loads requires the majority of plant equipment to operate below design, or most efficient levels. The commenter stated that improvements that result in reducing heat rate at a high load point may result in marginal improvement or higher heat rates at a lower load point; thus, the average heat rate improvement will be less than the heat rate reported at the high load point depending on the unit capacity factors.
The EPA disagrees the data used for development of the existing source standards is not applicable to modified sources and should not be used. Modified sources are existing sources that have undertaken modification (as defined in 40 CFR 60.14) and thus it is very appropriate to use existing source data.  Further, as we indicated in the proposal and reiterate in the final preamble, the EPA has been notified of very few modifications for criteria pollutant emissions from the power sector to which NSPS requirements have applied. As such, we expect that there will be few NSPS modifications for GHG emissions as well. 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. We do not have sufficient information at this time, however, to anticipate the types of modifications, if any, that may result from these changes ... nor are we able to anticipate the types of units that may modify.
Commenter 0178 stated that almost all forms of heat rate improvement will degrade over time, requiring ongoing maintenance efforts to return the unit to near design conditions. The commenter stated that opportunities to incorporate heat rate improvements at one load point are rare and are even less likely to carry that level of improvement across the load curve. The commenter stated that a significant driver of average heat rate is the capacity factor of a unit, and is unlikely that an average heat rate improvement could be achieved and sustained on coal units that may be dispatched at reduced load points in the future in order to meet an emission reduction goal, or because of increased utilization of NGCC units or increased renewable generation.
 Yes, the standards may require ongoing maintenance efforts to sure that the unit operates according to its best potential performance.
Commenter 0156 stated that it does not appear that EPA adequately considered the factors identified above that would impact the ability of a modified unit to meet the proposed performance standard. The commenter requests that EPA withdraw the proposed rule so that it can conduct a more detailed analysis of the CO2 emissions from all supercritical boilers and other efficient subcritical units and review the GHG BACT determinations that have been made to date; the EPA can then propose a performance standard that will be able to be met by modified units across a variety of potential operating scenarios.
The final standards for affected modified steam generating EGUs (i.e., those conducting modifications resulting in an increase of hourly CO2 emissions of more than 10 percent) are achievable. Since the final standard is based on the modified unit's own historical performance, the standard represents an emission rate that the affected unit has already achieved. Sources have other options other than heat rate improvements to meet the final standards.  For example, sources can use natural gas co-firing as a way to meet the final standards. Moreover, sources undertaking projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants.
Commenter 0156 stated that the CO2 emission rate for these units may decrease a bit at higher capacity factors, but an emission rate of 1,900 lbs CO2/MWh-net is not likely achievable on an annual basis. The commenter stated that in their experience, the dispatch of units is highly variable and the capacity factor of a unit affects the unit's heat rate, and correspondingly, its CO2 emission rate. The commenter stated that even the most efficiently designed unit cannot operate consistently at the capacity factor necessary to reduce its CO2 emission rate to the level in the proposed rule. The commenter stated that for efficiently designed and maintained units, like the ERGS units, there may be no additional economically reasonable actions that can be taken to further reduce an already low CO2 emission rate an additional 2 percent on an annual basis; if efficiency improvements had a reasonable rate of return, they likely have already been implemented.
This comment involves the achievability of the final standards for reconstructed sources. First, as the EPA has noted numerous times, we are only aware of 1 EGU that has triggered the reconstructed standards and, as such, we expect very few, if any, units to do so in the future. Still, if a unit does trigger the reconstruction provisions (see 40 CRF 60.15), it would be the result of expending a very large amount of capital (more than 50 % of that needed to replace the unit with a new unit  -  and these are not cumulative expenses, but rather, from a single reconstruction investment). It is certainly reasonable for a reconstructed unit to meet the emission of the best performing generation available, which for larger units is 1,800 lb/MWh-g and for smaller subcritical units is 2,000 lb/MWh-g.
Commenter 0214 stated that the EPA has justified the technical feasibility of equipment upgrades for modified boilers and IGCC units based on one fuel type - coal - and primarily on one technology - pulverized coal combustion; although EPA's BSER determination is applicable to the entire subpart Da source category. The commenter stated that the EPA has not provided sufficient evidence of the technical feasibility of equipment upgrades for all subpart Da sources. The EPA's acknowledgement that equipment upgrades may not be appropriate at every existing coal-fired EGU facility in the U.S. contradicts its BSER determination for coal-fired units while further eroding any justification for the equipment upgrades EPA cites as BSER for other subpart Da sources.
While all available equipment upgrades may not be available or appropriate for all types of utility boilers, the final standards are nonetheless achievable at all utility boilers and IGCC units. The standard is based on the affected unit's own historical performance  -  and thus the affected unit has already demonstrated that it can achieve the final standard.
Several commenters (0183, 0242, 0249, 0284) stated that the EPA recognizes that many units will already have made equipment upgrades and implemented the best operating practices that this standard contemplates and that, as a result, the EPA is concerned that some sources would be unable to undertake additional improvements to meet the highest level of efficiency plus the additional 2 percent reduction (based on equipment upgrades) being considered. Commenter 0183 stated that this concern should extend to EGUs that undertake efficiency improvements for any reason - whether to comply with a section 111(d) plan or for some other purpose - no matter when they are undertaken. Commenter 0284 stated that 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. The commenter stated that rather than specifying 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 determination, on a case-by-case basis, of what emission reductions are possible and reasonable after consideration of the above five factors. Commenter 0242 stated that an additional 2 percent improvement is not appropriate because it would dramatically increase costs on the most efficient facilities as they invest more heavily to achieve a new 2 percent theoretical improvement target; in a deregulated market, like Ohio, these units become less likely to "clear" the capacity market and could have the effect of older, less efficient units that have not been upgraded being used more than the newly modified more efficient reconstructed units.
Commenter 0222 stated that a proper analysis would have shown that the proposed 2 percent reduction is not feasible, particularly in deregulated markets. The commenter stated that Texas' deregulated electricity market is extremely competitive, and the market demands that operators operate at peak efficiency and with the best operating practices; there is simply no ability to leave any potential megawatt-hours on the table, rather than putting that energy into the market for sale. The commenter stated that the types of "best operating practices and equipment upgrades" contemplated by EPA have already been made by Texas EGUs.
Commenter 0183 stated that they have implemented all projects that are technically practical, economical, and would not otherwise trigger additional federal permitting requirements in response to competitive market incentives and believes that other utilities in competitive markets have done the same. The commenter stated that within that set of projects, some are temporary, and the improvements degrade over time and others that have already been accomplished cannot be repeated for additional improvement; in sum, the achievable heat rate improvements on which EPA relies have already been implemented. The commenter stated that for these reasons, EPA's targeted emission (or heat rate) improvement of 2 percent beyond a historically low emission rate is unachievable and arbitrary. According to the commenter, EPA correctly identifies the types of upgrades that can be made to improve heat rate and is correct that these types of projects and others are routine at EGUs; the commenter stated that EPA misapplies that fact to justify its proposal.
Commenter 0204stated that it is inappropriate to apply the 2 percent additional emission reduction as EPA proposes for sources that have already implemented aggressive measures to improve operating efficiency. The commenter stated that EGUs in Wisconsin already implement equipment upgrades (including periodic overhauls) on a regular basis to return efficiency to near original heat rates. The commenter stated that the EPA should also recognize that new plants, particularly supercritical units such as Elm Road 1 and 2 and Weston 4 in Wisconsin, will likely not be able to improve their heat rates.
The EPA is not finalizing the additional 2 percent emission reduction suggested in the proposal.
Commenter 0204 stated that as part of our review of EPA's concurrent 111(d) proposal for existing sources we performed an initial review of EPA's assumed HRI actions with many Wisconsin EGU operators. According to the commenter all of these utilities have operating and administrative programs in place to constantly maintain and improve coal-fired EGU heat rates. As part of their submission, the commenter provided a summary table of their review as an appendix. The commenter stated that the EGUs listed in the appendix generated approximately 95 percent of the electricity generated by the Wisconsin coal-fired EGU fleet in 2012. The commenter stated that the table contains the HRI actions that EPA associates with equipment improvements - turbine overhaul/maintenance, flue gas system improvements, economizer replacement, and acid dew point control. Referring to the table, the commenter stated that most EGUs in Wisconsin have already undertaken these improvements, if appropriate; this indicates that any one unit is not likely to be able to achieve EPA's assumed 2 percent HRI due to equipment improvements. The commenter stated that this also indicates that any EGU that becomes a modified source should instead be evaluated on a case-by-case basis to see what HRI equipment improvements are actually feasible at that unit, based on improvements completed to date.
The EPA is not finalizing the additional 2 percent emission reduction suggested in the proposal.
Commenter 0178 stated that emission control systems that have been installed or are expected to be installed will reduce heat rates (degrade) by approximately 1.5 percent to 1.75 percent. Each of the commenter's units has been subject to asset life cycle management based on maintaining unit performance for the duration of operation required to satisfy their generation needs. The commenter stated that major equipment for each unit is covered by a life cycle management which optimizes performance and expenses within the rate structure; overall, they had been very successful at maintaining performance of generation assets without material impacts to electric rates. The commenter stated that by virtue of this success the argument can be brought forth that improvements in O&M will be hard pressed to result in significant improvement in heat rate above current performance levels.
Commenter 0178 stated that they are currently in the process of installing the ReACT emission control system on Weston Unit 3. Once the ReACT system is installed the commenter stated that they expect a 3.2 percent increase in full load heat rate for this unit; this degradation in heat rate compared to the existing EPA baseline creates additional concern regarding the treatment this unit will receive under this regulation.
Commenter 0263 stated that several EGUs in Wyoming have recently completed extensive turbine upgrades, which are recognized as the most effective way to increase energy efficiency; for example, beginning in 2007 authorizations were issued to PacifiCorp Energy and Basin Electric Power Cooperative for turbine upgrades at their Jim Bridger and Laramie River Station facilities, respectively. The commenter stated that most of these upgrades have been completed and an expectation that either Jim Bridger or Laramie River Station could automatically introduce a further 2 percent reduction in CO2 emissions from its best performing year since 2002 is unreasonable, even more so when considering the requirements that are proposed for 111(d).
The EPA is not finalizing the additional 2 percent emission reduction that was proposed. We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
Commenter 0215 stated EPA did not provide any analysis to support the conclusion that NSPS can be met through a combination of best operating practices and equipment upgrades. Commenter said this violates section 307(d)(3) of the CAA.
The EPA disagrees. The information provided in the GHG Abatement Measures Technical Support Document provided ample support for the proposed standards. The analysis provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that modified units also have the option of meeting the final standard of performance through the use of natural gas co-firing.
Commenter 0242 stated that there has to be flexibility for states to determine the best rate that is economically and technically feasible for facilities that reconstruct or modify. The commenter stated that EPA suggests, as an example, a circumstance where "aggressive" measures were taken recently to improve efficiency. The commenter requested clarification on the term "aggressive". The commenter also urged the EPA to review the 2011 EPRI study, "Cycling and Load Following Effects on Heat Rate, 2011," which details the incorporation of "heat rate initiatives" at the unit examined in the study, including increased training of operators, enhanced coal sampling and analysis techniques, and excess air management measures. The commenter stated that the unit was able to manage and improve the initial heat rate degradation of 2.3percent to less than 1percent; however, these measures could not overcome the full impacts of cycling on the unit's heat rate. The commenter stated that they consider the measures taken in the above study to be extensive and aggressive, despite the modest heat rate improvement resulting from these efforts. The commenter urged the EPA to avoid vague terms such as "aggressive" when describing heat rate improvement measures, and to consider recognized past efficiency improvement measures when determining what additional measures a particular unit may implement.
We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
Commenter 0231 stated that it is unreasonable for EPA to assume that any specific level of emission reduction can be achieved across the board by EGUs that undertake 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. The commenter recommended that 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 determination, on a case-by-case basis, of what emission reductions are possible and reasonable after consideration of site-specific factors.
The final standards for affected modified steam generating EGUs is determined on a case-by-case basis.  The final standards are determined by the affected EGU's own best potential performance.
Commenter 0231 stated that they are concerned that where a state imposes efficiency improvements on a source, or where a source undertakes efficiency improvements to comply with the state plan, it will have already attained the maximum level of efficiency improvement that is achievable for that unit; as a result, the source would be unable to undertake additional improvements to meet the highest level of efficiency plus the additional 2 percent reduction.
Commenter 0256 stated that, under the proposed approach whereby efficiency improvements constitute a system of emissions reductions, the standard should not apply numerical CO2 limits to a modified or reconstructed unit, whether the numerical limit is given in the standard or based on historical operation. The commenter stated that the idea that a generating unit could achieve a 2 percent emission reduction through energy efficiency measures makes little sense for most units as any economically beneficial efficiency improvement would have already been implemented. The commenter stated that for years the EPA has pursued enforcement action against utilities for conducting routine maintenance, repair, and replacement projects under the claim that they would result in efficiency improvements and therefore constitute NSR modifications and it now appears that EPA is proposing to implement a rule that may require review and additional controls under a different regulation. And, according to the commenter, any controls implemented under NSR would most likely cause an increase in the CO2 emission rate for the unit, not allowing the unit to meet the proposed NSPS CO2 standard.
The EPA is not finalizing the additional 2 percent emission reduction that was proposed. We note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
Most stringent limits
Commenter 0183 stated that EPA is soliciting comments on whether the heat-input based most stringent emission limits of 1,900 lbs CO2/MWh and 2,100 lbs CO2/MWh should take into account the current steam cycle of the facility. The commenter stated that the EPA erred in setting the lower limit for all modified units (of all fuel types) at a level established with reference to the operation of a supercritical steam generating unit burning subbituminous coal. The commenter stated that the limits cannot be extrapolated to all units, regardless of fuel type. The commenter stated that EPA assumes that lignite-fueled sources can meet this limit by using ultra-supercritical steam conditions, but provides no explanation as to why the emission limit should be transferrable between units using different types of fuel. The commenter stated that the EPA also fails to acknowledge the impossibility of operating a supercritical unit as an ultra-supercritical unit to achieve the emission limit. The commenter stated that based on their experience with coal-fueled units, particularly while firing lignite fuel, no amount of efficiency improvement projects, operational changes, or maintenance would allow a unit designed and built to operate as a subcritical or supercritical unit to operate with the efficiency and process conditions of an ultra-supercritical unit and at an emission rate of 1,900 lbs CO2/MWh. The commenter stated that the proposed numerical standard, based on a unit burning subbituminous coal, is not achievable by lignite-fueled boilers, regardless of the type of boiler.
Commenter 0142 stated that, regarding EPA's solicitation of comments on whether the most stringent standard for modified steam generating units should take into account the current steam cycle of the facility, the existing steam cycle should be considered only in understanding realistic limits for modified units in establishing standards. The commenter stated that, specifically, the EPA should not propose standards based upon one type of unit and then require a completely different type of unit to comply with those standards. The commenter stated that the difference in efficiency resulting from different steam cycles is inherent in the design and construction of the unit; no matter the adjustments made, a subcritical unit cannot approach the efficiency of a supercritical boiler. The commenter stated that modifications tend to be more incremental adjustments to a unit's design than a complete unit redesign that would be required to convert a subcritical unit to a supercritical unit. For these reasons, the commenter stated that they not believe that the EPA's proposed unit-specific 1,900 lb CO2/MWh-net standards are appropriate BSER for subcritical units.
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. The 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. The EPA 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.
Commenter 0204 disagreed with the proposed "most stringent" standard for modified units, which accounts only for the size of a unit; instead, they agree with the alternative option that the "most stringent" standard should also take into account the current steam cycle of the facility. Commenter said this is based on the BSER limit that EPA proposes for a reconstructed fossil fuel-fired boiler, which EPA determined based on their review of emission rate information submitted by owners/operators of coal-fired EGUs to EPA's CAMD. The commenter stated that under this alternative option, EPA first suggests an emission standard for supercritical boilers of 1,900 lb CO2/MWh-net for units with a heat input rating of greater than 2,000 MMBtu/h; EPA then suggests a higher (i.e., less stringent) standard for all modified subcritical sources and for modified supercritical sources of 2,100 lb CO2/MWh-net with a heat input rating of 2,000 MMBtu/h or less. The commenter agrees with this alternative option, with an exception: the 1,900 lb CO2/MWh-net standard for supercritical units with a heat input rating of greater than 2,000 MMBtu/h is too stringent.
Commenter 0178 stated that, regarding EPA's soliciting comment on whether the most stringent standard for modified steam generating units should take into account the current steam cycle of the facility, they agree that the current steam cycle of the facility should be taken into account. The commenter stated that because of the design differences between subcritical and supercritical units, it is not reasonable to subject a subcritical unit to standards based on supercritical unit performance. The commenter stated that EPA has asserted that reconstructed units must use the most efficient generation technology available regardless of the original design of the unit prior to the reconstruction; because EPA goes further by identifying that supercritical pulverized coal or a supercritical circulating fluidized bed boiler technology represents the most efficient generation technology, the requirements would dictate that a unit without this design initially would be required to achieve the efficiencies from these advanced boiler designs. The commenter stated that a subcritical boiler can't achieve supercritical performance without essentially requiring that the unit is rebuilt nearly in its entirety. The commenter stated that the EPA analysis requires not only alteration of the boiler and steam cycle but also requires units to use different coal and install different cooling systems; these assumptions regarding the feasibility of making these wholesale changes to a unit are unsupportable and have the effect of making reconstruction impossible. 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 thereby resulting in a degraded overall heat rate. The commenter stated that because the proposed Clean Power Plan is expected to impact heat rates in this manner, EPA should finalize higher standards for modified and reconstructed sources.
The EPA finds the final standards of performance for both affected modified steam generating EGUs and for reconstructed EGUs to be appropriately stringent as discussed in preamble sections VI and VII.
Commenter 0231 stated that EPA's alternative to the 2 percent better than the best historical performance, an emission standard no more stringent than the corresponding standard for reconstructed EGUs is unreasonable because it assumes that all coal-fired EGUs can obtain the level of emissions achievable by a facility undergoing a complete reconstruction, even if those EGUs have already undertaken the equipment upgrades and implemented the best operating practices contemplated by the standard.
Commenters 0154, 0204 stated that EPA should evaluate emission rates that modern units are actually achieving. Commenters referred to the Elm Road Generating Station (ERGS) in Wisconsin that is powered by supercritical boilers firing bituminous and sub-bituminous coal, began operation in 2010 and is one of the most modern and efficient coal fired power plants operating in the country. Commenters said based on available data, this proposed emission rate isn't achievable on these units, let alone sustainable across a range of capacity factors or as the heat rate efficiency degrades between maintenance activities. The commenters stated that the Elm Road plant is only demonstrating a CO2 emission rate of 2,061 lb/MWh-net. This was based on 2014 CAMD operating data for Elm Road, which operated at a 63% capacity factor during this period. The commenters stated that based on this example, EPA needs to reevaluate the proposed "most stringent" limits for supercritical coal-fired units.
Commenter 0291 stated EPA recognized that many (if not most) units will already have undertaken the equipment upgrades and best operating practices that this standard contemplates, and offers what it sees as a limitation, that modified facilities would not have to meet an emission standard more stringent than the corresponding standard for reconstructed. EPA assumes that all coal-fired EGUs can obtain the level of emissions achievable by a facility undergoing a complete reconstruction, even if those EGUs have already undertaken the equipment upgrades and implemented the best operating practices contemplated by the standard. Commenter believed that EPA tacitly admits the unreasonableness of their proposal in text relating to a unit's implications with 111(d) state plan implementation. The EPA showed concern over a unit's ability to achieve an additional 2% efficiency improvement, as the unit may have already attained the maximum level of efficiency improvement achievable. Commenter said this concern should extend to EGUs that undertake efficiency improvements for any reasons, not just compliance with 111(d).
First, the EPA notes that the additional 2% reduction that was suggested in the proposal has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs return, on average, to their best past performance between 2002 to 2012. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved.
EPA's suggested equipment upgrades are not part of the affected unit.
Commenter 0215 stated that many of the operating practices and equipment upgrades that EPA asserts will improve the heat rate at a Subpart Da unit are not part of the affected facility, and EPA lacks authority to regulate them under section 111(b). Moreover, EPA has exaggerated the short-term and long-term benefits of the heat rate improvement methods described in the Proposed Standards by relying on flawed analyses and unverified assumptions. Commenter said the affected facility is limited to the boiler island. See commenter's attached Rasnic Memorandum. The following equipment is specifically beyond the purview of section 111(b): water purification equipment; water-supply systems; air cleaning and cooling apparatus; condensers; main exhaust and main steam piping; water screens, motors, and moisture separator for turbine steam.
Commenter 0187 disagreed that a modified Subpart Da EGU could achieve an emission rate determined by the unit's best annual performance, plus an additional two percent efficiency improvement. The commenter stated that: the affected facility is limited to the steam boiler unit; many of the practices and equipment upgrades suggested by the EPA are not part of the affected steam boiler unit; and the EPA lacks authority to require them. The commenter stated that other auxiliary equipment, such as condensers, main exhaust and main steam piping, and moisture separators are not directly a part of the steam boiler and, therefore, cannot be relied upon pursuant to 111(b) for EGU efficiency improvements.
First, the EPA notes that the additional 2% reduction that was suggested in the proposal has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10%. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Regarding comments about what is the affected facility  -  the EPA is not regulating any emissions from the facility components listed, nor is the EPA requiring in any way that the affected modified EGU conduct specific actions. The owner/operator is free to meet the final standard in the way that is best for the facility. For example, an affected modified EGU can meet the final standard through the use of natural gas co-firing.
Past HRI not a demonstration of possible future HRI
Commenter 0153 stated that EPA's analysis of past heat rate improvements at existing EGUs does not demonstrate that future heat rate improvements can be performed to reduce CO2 emissions. According to the commenter, the remaining available plant efficiency improvement for EGUs is closer to 1 percent and the proposed Clean Power Plan will force those improvements to be made.
Commenter 0278 stated that the six percent heat rate improvement EPA proposes as Building Block 1 is unachievable for existing fossil fuel-fired EGUs and without adequate technical justification and the proposed modified unit rates assume heat rate improvements beyond Building Block 1's six percent. The commenter stated that EPA provides no justification or technical support for this assumption and there simply are not efficiency projects that EGUs can perform to achieve a six percent improvement in heat rate. The commenter stated that the fact that EPA's analysis of past heat rate improvements at existing EGUs has shown that EGUs work to improve heat rates, does not demonstrate that future heat rate improvements can be performed to reduce CO2 emissions; the remaining available plant efficiency improvement for EGUs is closer to 1 percent, and the proposed Clean Power Plan will force those improvements to be made.
Commenter 0257 stated that the assumption that a unit can feasibly replicate its lowest heat rate since 2002 is questionable, as variation in any individual unit's heat rate is largely due to factors beyond the unit's control, such as ambient temperature, operating duty, and auxiliary load requirements; for example, the installation of scrubbers, selective catalytic reduction and baghouses significantly degrade the net heat rates of coal-fired EGUs because of the associated parasitic power. The retrofit of SCR increases auxiliary power by about 1.5 percent of gross output, while flue gas desulfurization retrofit may increase auxiliary power by 1-2 percent, depending on coal type. The commenter stated that since 2002, about 140,000 MW of SCR and 120,000 MW of FGD have been installed on EGUs and they have installed seven of their eight SCRs and four of their seven wet scrubbers post 2002.
Comments specifically on provisions of the Clean Power Plan (111(d)) are out-of-scope for this Response-to-Comments and will not be responded to. As provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10%. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Regarding comments about factors beyond the plant operator's control, Section 2.5 of Chapter 2 of the `GHG Mitigation Measures' TSD explains how EPA controlled for several of those factors.
Inappropriate reliance on 2009 Sargent & Lundy report
Several commenters (0157, 0183, 0187, 0199, 0214, 0215, 0242, 0257, 0278) stated that EPA's reliance on the 2009 Sargent and Lundy report, to determine the type and degree of heat rate improvements that are possible to be achieved nationwide is not appropriate.
Commenter 0215 stated that the GHG Abatement Measures TSD relies heavily on a 2009 Sargent & Lundy study purportedly showing that existing EGUs are "theoretically capable" of achieving sufficient heat rate improvements to comply with the Proposed Guidelines and EPA's statistical analysis of data from existing Subpart Da EGUs. Commenter attached technical reports discounting EPA's analysis in the GHG Abatement Measures TSD, showing the analysis to be deeply flawed, and not supporting the Agency's claims regarding potential heat rate improvements, either in the Proposed Guidelines under section 111(d) or in the Proposed Standards for modified Subpart Da EGUs. See Cichanowicz Heat Rate Report; J. Edward Cichanowicz & Michael C. Hein, "Critique of EPA's Use of Reference Units to Select Heat Rate Reduction Targets" (Oct. 13, 2014).
Commenter 0215 stated EPA relies on a 2009 Sargent & Lundy study that they misused. Commenter noted that Sargent & Lundy has responded that it did not conclude that any individual coal-fired EGU, or any aggregation of coal-fired EGUs, can achieve the 6 percent heat rate reductions that are a primary basis of EPA's proposal.
Commenter 0242 stated that the EPA's use of one study, the S&L study, to determine the type and degree of heat rate improvements that are possible to be achieved nationwide is not sound science. After reviewing the S&L study, the commenter determined that the purpose was to examine potential heat rate improvement opportunities and potential heat rate reductions over a wide range of sources and that the methodology and results of the study are very general and cannot be applied to every EGU. The commenter stated that the study does not present an analysis of the application of the recommended improvement opportunities, nor does the study present measured heat rate reductions after the application of suggested/proposed improvement methods and there is no empirical data demonstrating the real-world application of such measures; such an undertaking was simply not the purpose of the study. The commenter stated that the use of the S&L study as a foundation for demonstrated HRIs is an over-simplification of the complexities and variability in power plant design and function. The commenter stated that in many cases, the potential projects referenced for HRIs are not functionally applicable to specific units; for example, replacing economizers for better performance could cause additional problems such as: fouling issues can arise in finned tube designs depending on type of coal used; corrosion, ash deposition and increased use of preheaters are needed for reduced exit temperatures which increase heat-rate; and lower temperatures sent to SCRs can sacrifice SCR efficiency.
Commenter 0242 stated that the S&L study alone was used to estimate the ability for sources to achieve HRIs through equipment upgrades. The commenter stated that the EPA used the estimated ranges of potential heat rate improvement achievable through a variety of equipment upgrades from the S&L study, which were screened into a subset to identify what the EPA considers to be a reasonable subset of equipment upgrades that would generally be beyond the scope of investments they would expect to be made for purposes of achieving the best-practices heat rate improvements. The commenter stated that based on the average of the study's ranges of potential HRIs from implementation of this full subset of HRIs, it is expected any single EGU could achieve an aggregate HRI of 4 percent from equipment upgrades alone. The commenter stated that, because EPA recognized that this may overstate the opportunity across all EGUs where some EGUs may have already implemented some of these upgrades, the EPA therefore proposed on average across the fleet of affected EGUs, the technical potential for a 2 percent HRI improvement opportunity due to equipment upgrades (modification). The commenter stated that they disagree with this assessment stating that the EPA did not perform any analysis to determine if there is a true technical potential of 2 percent HRI from equipment upgrades that is cost-effective for each individual EGU; the EPA is assuming technical potential at each individual unit based on using an assumed average from one inappropriately applied study.
Commenter 0242 stated that the EPA acknowledges that the S&L study's wide ranges of estimated BTU reductions and capital costs are indicative of the wide range of real differences in the many details of site specific EGU designs, fuel types, age, size, ambient conditions, current physical conditions, etc.; yet, the EPA chose to use an average to determine the level of the standard. The commenter stated that considering unit-specific data is being used to determine a best historical performance rate and the EPA is requesting an additional 2 percent reduction, there may be some units that will not be able to achieve this if these units are on the wrong end of the wide ranges.
Commenter 0157 stated that EPA uses the Sargent & Lundy study to support a 4% heat rate improvement if all improvements were applied on an EGU that has not made those upgrades. The commenter stated that given the study is five years old and is based on data even older, it is not realistic to assume that every regulated EGU has not already made some of those upgrades. The commenter stated that promulgating a uniform standard based on an assumption that is not uniform is arbitrary; if an EGU had already undertaken numerous efficiency improvements, it would nonetheless be penalized under EPA's proposal for making improvements early. The commenter stated that the standard would be even lower for such a unit, and potentially unattainable; on other hand, a unit that has made no improvements could comply more easily. The commenter stated that EPA's approach in this proposal punishes those who acted early, before they were required to do so.
Several commenters (0278, 0153) stated that EPA relies on a 2009 Sargent & Lundy (S&L) study that was never intended to predict the technical feasibility of a six percent heat rate improvement across the entire fleet of fossil fuel-fired EGUs. The commenters stated that in a October 15, 2014 letter to Rae Cronmiller at NRECA (the commenters attached the letter to their submittal), S&L clarified that the 2009 Report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6 percent HRI or any broad target, as estimated by the EPA and that the only technically appropriate method to properly evaluate potential HRI is to conduct a unit-by-unit evaluation. The commenters stated that EPA's reliance on the S&L study cannot form the technical basis for its modification rule BSER finding. The commenters stated that S&L also notes that many of the options for HRI listed in the 2009 Report have triggered NSR actions by EPA and others. The commenters stated that EPA provides no NSR relief in the proposal and suggested that EPA clarify that all of these HRI projects should be treated as routine maintenance, repair and replacement. The commenters stated that if the projects are also evaluated to determine whether there is a reasonable possibility that they will result in a significant emissions increase, a potential NSR carve out would be for the NSPS emissions rate test to apply; this test is only triggered by increases in the maximum achievable emissions rate before and after the physical change.
Commenter 0199 stated that since their report's publication in 2009, Sargent & Lundy have performed unit-specific HRI potential studies and has yet to encounter a single unit that can achieve a six percent HRI; a more realistic figure is a 2 percent HRI or less, realizing that all units will experience degradation over time from its initial HRI.
Commenter 0187 stated that the projects cited in the Sargent & Lundy 2009 study over-estimate the potential heat rate improvements and the length of time they have been effective as many of the improvements are short-term and any estimate is only for a given point in time, and the effectiveness degrades over time. The commenter stated that, for example, the best year may not be representative of the entire unit's outage cycle; the unit may operate most efficiently the year after the outage and degrade until the next outage.
Commenter 0214 stated that EPA did not consider the technical feasibility of equipment upgrades across the size classes of potentially affected sources; EPA's proposal covers facilities constructed for the purpose of supplying more than one-third of its potential electric output and more than 219,000 MWh as net-electric sales on an annual basis. The commenter stated that the EPA, in establishing equipment upgrades as BSER, referenced studies that removed units with capacity factors under 50 percent, low pressure subcritical units, and 0 to 200 MW subbituminous units. The commenter stated that by eliminating certain units, these studies do not justify the technical feasibility of equipment upgrades at all potentially affected size classes. The commenter stated that EPA relies heavily, if not exclusively, on a 2009 Sargent & Lundy study that only analyzed three sizes of coal-fired power plants - 200 MW, 500 MW, and 900 MW. The commenter stated that the report fails to analyze the technical feasibility of equipment upgrades at all potential affected size classes. The commenter stated that the EPA must provide information that directly proves equipment upgrades are technically feasible for all potentially affected subpart Da sources.
Commenter 0214 stated that the EPA's exclusive reliance on the 2009 Sargent & Lundy report to justify the achievability of a two percent net CO2 emission rate reduction is misplaced. The commenter stated that the potential four percent heat rate improvement EPA used (based on four upgrade methods, if all were applied on an EGU that had not already made such upgrades, which was then adjusted to two percent to account for unknown details of current actual unit configurations), could be zero if a unit has already implemented them. The commenter stated that EPA, however, dismisses this possibility while providing no basis for its arbitrary conclusion. The commenter stated that the Agency also ignores Sargent & Lundy's 850 MW EGU case study which depicts a potential heat rate reduction lower than two percent. The commenter stated that, moreover, the 2009 Sargent & Lundy report does not provide any insight on the long-term sustainability of heat rate improvements.
Commenter 0257 stated that all of EPA's rationale is based upon extrapolations and assumptions from data EPA uses to support entirely different emission standards for existing fossil fuel-fired EGUs including a 2009 study by Sargent & Lundy regarding heat rates as the basis for its assessment of heat rate improvement potentials from equipment and system upgrades. The commenter stated that the EPA presents no independent data addressing modified utility boilers and IGCC units to support the proposed standards; missing from the docket are any calculations using the EPA's proposed methodology and its emissions database to provide the source-specific numerical standards that it would expect modified EGUs to achieve. The commenter stated that in its use of heat rates, the EPA does not appear to recognize the difficulties in their measurement that affect how applicable they are to actual emissions. The commenter stated that it has long been recognized that heat rates must be measured at a standard set of conditions to limit the number of variables that can obscure the conclusions and that these variables are in play during actual operation, with the result that the calculated heat rate does not fully correlate to emissions integrated over time; thus anticipated improvements may not be fully realized when trying to achieve permit compliance.
Commenter 0257 stated that EPA has exaggerated the short- and long-term benefits of some of the heat rate improvement methods cited in the Sargent & Lundy study. The commenter stated that many of the payoffs are temporal - for example, steam turbine blades wear with time, revised and reconfigured heat exchangers accumulate deposits, and new condensers retrofitted to provide clean and uncompromised surfaces for reliability may not deliver the same heat reduction due to material properties - as a result, the immediate impact of a heat rate improvement measure on a unit's CO2 emission rate may overstate the benefits of that measure over its expected lifetime, i.e., a given estimate of heat rate improvement may be merely a snapshot that changes with time. The commenter stated that EPA assumes that heat rate improving actions are additive, and many are not - for example, heat from a boiler can be recovered only once, and projects that improve heat transfer within the boiler or refurbish the air heater are not cumulative. The commenter stated that the Agency also fails to recognize that many of the actions are routinely deployed as good maintenance practice, and their associated benefits are already accounted for in a unit's historical emissions performance, meaning that remaining opportunities for additional heat rate improvements are limited and highly site-specific.
Commenter 0183 stated that the EPA also misuses the Sargent & Lundy 2009 Study and the National Energy Technology Laboratory studies; for example, EPA wrongly extrapolates that each of the heat rate improvement methods identified by the S&L Study can be combined in practice to achieve a greater improvement, an assumption that is flawed. The commenter stated that many of the heat rate improvement methods that EPA identifies cannot be combined and are not cumulative; in other words, once the improvement is achieved by one method, another method cannot achieve the same or similar improvement. The commenter stated that, for example, Intelligent Sootblowers (S&L) would reduce the benefits realized by reducing boiler slagging (NETL); in this way and others, EPA overstates the potential for heat rate improvements.
Commenter 0215 stated a 2014 analysis by Sargent & Lundy ("S&L") (prepared in support of NRECA's comments) is highly critical of the Agency's use of its 2009 report and concludes that EPA greatly exaggerated the amount of heat rate improvements that can realistically be expected at coal-fired EGUs. The report emphasizes many of the issues noted by this commenter's consultant, including the fact that actual benefits from many heat rate improvement methods are non-additive, temporal, and highly site-specific. Among other things, the NRECA S&L Report Study Conclusions specifically disavows EPA's use of the earlier report by stating the "Sargent & Lundy's 2009 report does not conclude that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA." Sargent & Lundy also note that the potential benefits cited in their 2009 report "were estimated at a conceptual level, and were not based on detailed site-specific analyses." These conclusions are confirmed by EPRI and the National Coal Council, a U.S. Department of Energy advisory group. See EPRI, "Range and Applicability of Heat Rate Improvements" at 5-1, 6-1 (Apr. 2014); National Coal Council, "Reliable & Resilient-The Value of Our Existing Coal Fleet: An Assessment of Measures to Improve Reliability & Efficiency While Reducing Emissions" at 69-70 (May 2014). Commenter said as a result, the 2009 Sargent & Lundy report does not support a conclusion that any individual coal-fired EGU or any aggregation of coal-fired EGUs can achieve 6% [heat rate improvement] or any broad target, as estimated by the EPA.
Responses to criticism of the use of the Sargent & Lundy study ("Coal-fired Power Plant Heat Rate Reductions", Sargent & Lundy LLC, January 2009. Available at http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf) are provided in the final Chapter 2 of the `GHG Mitigation Measures' TSD in the rulemaking docket.
Compliance will require many units to operate in a manner that will reduce their efficiency
Commenter 0187 stated that many boilers may operate in a load-following mode for at least a portion of their operation and the efficiency of a boiler decreases when the unit is operated at reduced loads. The comment included a figure showing the typical impact to efficiency when boilers are operated at reduced loads. According to the commenter, compliance with the proposed standards for existing units will require many units to operate.
The EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10%. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as simultaneously implementing measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Further, an affected modified EGU can meet the final standard through the use of natural gas co-firing.
Perceived HRI actually result of CEMS reporting
Commenter 0187 stated that in the EPA's GHG Abatement Measures TSD, EPA points to large heat rate improvements via equipment upgrades that could be replicated on other EGUs. According to the commenter, in many of the cases where EPA believed an efficiency improvement occurred, the perceived efficiency improvement was actually the result of a change in continuous emission monitoring system reporting methodology and not the result of an equipment or operational change to lower heat rate. See Critique of EPA's Use of Reference Units to Select Heat Rate Reduction Targets, J. Cichanowicz and M. Hein, October 2014. Commenter said a more accurate assessment of air flow through the stack caused the units to report an apparent improved heat rate.
Commenter 0257 stated that the EPA's discussion in the GHG Abatement Measures TSD also relies heavily on 16 reference units that purportedly achieved large heat rate improvements via equipment upgrades that EPA assumed could easily be replicated elsewhere. The commenter stated that in nearly every case, the owners stated that the reported heat rate improvement was related to a change in CEMS reporting methodology and not the result of an equipment or operational change that was undertaken to lower heat rate. The commenter stated that the actual heat rates did not improve; rather a more accurate assessment of air flow through the stack caused the units to report an apparent improved heat rate; other units did attain modest improvements in heat rate through equipment upgrades, but these improvements were more than offset by decreased unit efficiency due to retrofit of environmental controls.
Commenter 0215 stated EPA's discussion in the GHG Abatement Measures TSD relies heavily on 16 reference units that purportedly achieved large heat rate improvements via equipment upgrades that EPA assumed could easily be replicated elsewhere. Commenter indicated that EPA didn't question the cause of the HRI, but het commenter did. In virtually every case, the owners stated that the EPA calculated heat rate improvement was due to a change in stack flow monitor calibration, or other unrelated source of variability in CEMS measurements, and not the result of an equipment or operational change that was undertaken to lower heat rate. Commenter attached documentation for this information. The actual heat rates did not improve, rather, in many cases, routine annual changes in stack gas flow monitor calibration to better equate to manual reference methods, and changes in flow methods used in flow monitor calibrations to compensate for stack flow characteristics resulted in an apparent improved heat rate. Other units did attain modest improvements in gross heat rate through equipment upgrades, but these improvements were more than offset by decreased unit efficiency due to retrofit of environmental controls, which increased the units' net heat rates. In a few cases, projects were undertaken that did improve gross heat rates, and those tended to have involved the steam turbine, which is not part of the affected facility. Commenter said these results indicate that CEMS-derived gross heat rate data are an inadequate basis for assessing modest changes in heat rate due to equipment upgrades given that reported values can vary for a number of unrelated reasons including the allowed error inherent in all CEMS measurements, stack flow monitor and other CEMS recalibrations, physical changes in flue gas handling systems, changes in CEMS and CEMS technologies, and other factors.
Chapter 2 of the `GHG Mitigation Measures' TSD discusses the impact that relative accuracy of CEMS might have on the results (Section 2.5.1) and the impact that changes in flow measurement might have (Section 2.6.6). EPA disagrees the measurement errors and/or method changes are primarily responsible for the significant differences in heat rate performance at coal-fired EGUs. Regarding the comment about offsetting decreases in efficiency from retrofit of environmental controls, EPA's analysis, as discussed in Chapter 2 of the `GHG Mitigation Measures' TSD, is based on EGUs' gross heat rates which is not affected by auxiliary power requirements of retrofit controls.
Measurement of heat rate improvement
Commenter 0178 stated that an issue with the demonstration of heat rate improvement is the method by which measurement of the improvement is accomplished. The commenter stated that usually, heat rate tests are conducted using calibrated equipment; however, on-line testing would use installed equipment which is not as accurate. The commenter stated that clarity is needed regarding the demonstration of a two percent heat rate improvement because online instrumentation would have a two percent instrument error associated with heat rate measurement.
The commenter stated that any requirements associated with heat rate improvement in general are dependent on the original design of the unit - for example, a sub-critical pressure, coal-fired Rankine cycle plant will not be able to achieve the efficiency of a natural gas combined cycle plant because of inherent physical design considerations. The commenter stated that heat rate and the impact of heat rate improvements will vary along the load curve for each generation unit. The commenter stated that production at partial loads requires the majority of plant equipment to operate below design, or most efficient levels. The commenter stated that improvements that result in reducing heat rate at a high load point may result in marginal improvement or higher heat rates at a lower load point; thus, the average heat rate improvement will be less than the heat rate reported at the high load point depending on the unit capacity factors.
The commenter stated that almost all forms of heat rate improvement will degrade over time, requiring ongoing maintenance efforts, such as a turbine overhaul, to return the unit to near design conditions; opportunities to incorporate heat rate improvements at one load point are rare and are even less likely to carry that level of improvement across the load curve. The commenter stated that a significant driver of average heat rate is the capacity factor of a unit, and is unlikely that an average heat rate improvement could be achieved and sustained on coal units that may be dispatched at reduced load points in the future in order to meet an emission reduction goal, or because of increased utilization of NGCC units or increased renewable generation.
The commenter stated that emission control systems that have been installed or are expected to be installed will reduce heat rates (degrade) by approximately 1.5% to 1.75%. The commenter stated that each of the their units has been subject to asset life cycle management based on maintaining unit performance for the duration of operation required to satisfy their generation needs. According to the commenter, the major equipment for each unit is covered by a life cycle management which optimizes performance and expenses within the rate structure. The commenter stated that overall, they had been very successful at maintaining performance of generation assets without material impacts to electric rates. The commenter stated that by virtue of this success the argument can be brought forth that improvements in O&M will be hard pressed to result in significant improvement in heat rate above current performance levels. The commenter stated that through current maintenance practices they are already realizing the "cost effective" improvements through O&M best practices.
Commenter 0215 stated EPA's analysis incorrectly assumes that the existence of variation in heat rate at individual units means there is significant variation in the operation of EGUs" indicating that "significant potential for heat rate improvement is available through the application of best practices, because heat rate variability at individual units is driven by the design, duty cycle, fuel type, size, and location of each unit, and it cannot be ameliorated by changes in operating practices. Commenter said EPA did not assess differences in variability based on these factors or control for these factors in its achievability analysis. Commenter continued that EPA uses the best net heat rate since 2002 as the basis for determining a required heat rate improvement. It is arbitrary and capricious to use any year prior to retrofit of energy-consuming pollution control equipment as the baseline for net heat rate. Similarly, EPA has not accounted for the impact of load duty on net heat rate or provided any technical analysis supporting this element of its proposal.
First, the EPA notes that the additional 2% reduction that was suggested in the proposal has not been incorporated into the final requirements in the final standards of performance for modified steam generating units. Also, as provided in Chapter 2 of the "GHG Mitigation Measures" Technical Support Document for the CPP Final Rule (and available in the Carbon Pollution Standards (111b) rulemaking dockets: EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-0603), analyses indicate that there is significant potential for heat rate improvement from the fleet of coal-fired EGUs, ranging from 4.0 to 6.6 percent nationally if coal-fired EGUs, on average, return to their best past performance between 2002 to 2012. We further note that the EPA is only finalizing standards for EGUs that conduct modifications resulting in an increase in potential CO2 hourly emissions of more than 10 %. Based on historical trends, we expect few, if any, EGUs to trigger that threshold and become subject to the finals standards. Those that do will do so only after taking actions  -  likely capital intensive actions  -  that trigger the modification provisions. Sources undertaking such capital-intensive projects can take steps to avoid triggering modification, such as measures to avoid increasing their emissions of pollutants  -  or can take measures at the time of the capital-intensive modification project to ensure that the final standard can be achieved. Regarding comments about actions to improve and maintain heat rates, Section 2.6.1 of Chapter 2 of the `GHG Mitigation Measures' TSD discusses the effect of actions undertaken by EGUs to improve and maintain heat rates during the study period, and Section 2.6.8 discusses the impact of equipment degradation.
BSER Unsupported by Data
Commenter 0183 stated that EPA's proposed BSER for modified units is unsupported by the data resulting from numerous data errors including EPA's assumed heat rate improvements. The commenter stated that EPA failed to recognize that the heat rate improvements in the TSD (9% from 2002-2004 and 2% from 2010-2012) are likely tied, not to actual heat rate improvements, but to a conversion to different CEMS and that EPA mistakenly attributed an improvement (via calculation) in heat rates that was seen in the acid rain database to actual heat rate improvement. The commenter stated that EPA must reconsider its analysis of emissions data to take into account the change in calculation methodology, which will demonstrate that this decrease occurs on paper only and not in the real world. The commenter stated that EPA cites a wide range of studies regarding unit heat rate improvement potential but fails to consider how these studies may or may not apply in ERCOT or even more generally to units in a competitive market like ERCOT. According to the commenter, EGUs operating in a competitive environment such as ERCOT have a strong incentive to operate as efficiently as possible and, as a result, cost effective heat rate improvements have already been implemented by the generating units; once these improvements have been made, they are essentially complete and in most cases cannot be replicated at the units again. The commenter stated that EPA is effectively penalizing early adoption of efficiency improvements by disregarding the fact that heat rate improvements have already been made in the competitive market. The commenter stated that EPA's error in assuming that a 2% improvement in emissions is possible is exacerbated by the requirement that the 2% be calculated from the best historical emission rate and, without an understanding of what factors may have contributed to the historical low emission rate for a particular unit, it is impossible to say whether it can be repeated, much less improved upon. According to the commenter, unit heat rates consistently degrade following improvements and by requiring a 2% improvement over a unit's best year's emission rate, EPA is by definition establishing an impossible heat rate improvement.
Commenter 0242 stated that they have a particular concern with the EPA's claims that there are a wide range of studies and detailed engineering studies to support the proposed heat rate improvement potentials. The commenter stated that the studies cited by the EPA appear limited to a very small sample size from EPA Region 7, which presents the results of a heat rate improvement study provided by EPA Region 7 for seven coal fired units with details on capital upgrades and maintenance activities and measured heat rate improvements. See GHG Abatement Measure TSD. The commenter stated that examination of these data reveals that the majority of demonstrated, measured heat rate improvements at the seven coal fired power plants are characterized directly by Region 7 as returning unit performance to original design performance; thus, these measures are maintenance activities, which degrade over time, and cannot be adequately characterized as permanent heat rate improvements. The commenter stated that they understand via stakeholder outreach that the regular maintenance during a planned boiler/generator outage is done to restore, as much as possible, the unit to its original design performance and the assumption that these activities are not already occurring universally across the existing coal fired fleet is simply not appropriate. The commenter stated that the Region 7 study also reveals that capital improvements were limited to turbine efficiency upgrades and variable frequency drives; the largest heat rate improvement resulting from these capital expenditures was 1.83percent. The commenter stated that thus, the contention that a utility boiler or IGGC unit wishing to modify would be required to achieve an additional 2 percent heat rate efficiency improvement has not been adequately demonstrated. The commenter stated that if a well-designed efficient plant is maintained and is operating at near design efficiency, an additional 2 percent improvement in efficiency will not be possible and the small subset of units examined by EPA Region 7 is not representative of coal-fired units nationwide and should not be relied on for such an important rulemaking.
Commenter 0215 stated the EPA did not include the results of any analysis in the docket showing that is true. Commenter was unable to locate any TSD in the docket that provides a justification for EPA's proposed standards for modified Subpart Da units, even though UARG has requested the analyses referred to in the preamble. See Emails from Craig S. Harrison, Hunton & Williams LLP, to Robert Wayland, EPA OAQPS, Re: Modified and Reconstructed Proposal (June 18 & 19, 2014). Commenter said this is unlawful and must be withdrawn, according to CAA Section 307(d)(3). Under this section, EPA is required to provide the basis and purpose for the Proposed Standards. The basis and purpose must include "a summary of . . . (A) the factual data on which the proposed rule is based; (B) the methodology used in obtaining the data and in analyzing the data; and (C) the major legal interpretations and policy considerations underlying the proposed rule." Id. The docket fails to include the "annual historical operating performance for [each] affected facility using historical CO2 emissions data for the calendar years 2002 through [2013]" that the Agency refers to in Proposed Section 60.46Da(c)(3)(i)(A). Commenter said also missing from the docket are any EPA calculations using its proposed methodology and its emissions database to provide the source-specific numerical standards that it would expect modified EGUs to achieve. Without such information, the commenter wasn't able to comment meaningfully on the source-specific standards that the Agency proposes that the units, if modified, could achieve. Without such calculations, which logically would have been included in the TSD that is absent from the docket, EPA cannot have conducted a reasonable inquiry into whether those limits are achievable. Commenter said EPA is "play[ing] hunt the peanut with technical information, hiding or disguising the information that it employs," and is "treat[ing] what should be a genuine interchange as mere bureaucratic sport." See Conn. Light & Power Co. v. Nuclear Regulatory Comm'n, 673 F.2d 525, 530 (D.C. Cir. 1982).