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TABLE OF CONTENTS

CHAPTER 7 INTERACTIONS WITH OTHER EPA PROGRAMS AND RULES............ 2

7.1 EGU NSPS - New .................................................................................................................... 2

7.2 EGU NSPS - Modified and Reconstructed ........................................................................... 7

7.3 New Source Review (NSR)..................................................................................................... 9

7.4 Title V Program .................................................................................................................... 44

7.5 40 CFR Part 75...................................................................................................................... 53

7.5.1 Monitoring of electric generation: equipment standards............................................... 53

7.5.2 Monitoring of electric generation: specification and frequency of quality assurance 

testing ............................................................................................................................... 56

7.5.5 Monitoring of non-electric output at CHP units............................................................. 57

7.5.6 Reporting of net electric generation and CHP net energy output................................. 59

7.5.7 Reporting of monitoring plan data and quality assurance testing data ....................... 64

7.5.8 Monitoring of stack gas volumetric flow rate.................................................................. 67

7.5.9 Other ................................................................................................................................... 76

7.6 Greenhouse Gas Reporting Program.................................................................................. 92

7.7 Other EPA Rules................................................................................................................... 92

7.8 Other .................................................................................................................................... 106
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CHAPTER 7 INTERACTIONS WITH OTHER 

EPA PROGRAMS AND RULES

This chapter addresses comments received on interactions of the EGU GHG Emission 

Guidelines with other EPA programs and rules. Comments received on the following topics are 

covered by this chapter: EGU NSPS - new (Section 7.1), EGU NSPS - Modified and 

Reconstructed (Section 7.2), New Source Review (NSR) (Section 7.3), Title V Program (Section 

7.4), 40 CFR Part 75 (Section 7.5), Greenhouse Gas Reporting Program (Section 7.6), Other 

EPA Rules (Section 7.7), and comments received on other topics relevant to this chapter (Section 

7.8).

Commenters also raised issues on topics that are not covered by this chapter. Please refer to the 

following chapters for responses specific to those issues:

• Chapter 1: Legal

• Chapter 2: Applicability

• Chapter 3: GHG Mitigation Measures

• Chapter 4: State Goal Computation

• Chapter 5: State Plan Considerations

• Chapter 6: State Plans

• Chapter 8: Impacts and Cost Analysis

• Chapter 9: Statutory and Executive Orders

• Chapter 10: Rule Language Corrections

7.1 EGU NSPS - NEW

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the EGU GHG NSPS regarding new sources.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: While it may be possible to make some further improvement in the heat rates of 

existing coal-fired plants, the marginal costs are likely to be burdensome.
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Response 1: The EPA disagrees with the commenters assertions based on our analyses of lowand no-cost best practices that can provide for heat rate improvements via reduced variability. 

Please see the details of our analysis in chapter 2 of the GHG Mitigation TSD supporting this 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that at the heart of Building Block 1 is the assumption that coal steam turbine 

heat rates may be improved by 65%, however, many coal-fired plants have already undergone 

significant efficiency upgrades and improvements, which in large part contributed to the 13.2% 

reductions in CO2 emissions achieved since 2005. Commenters stated that they have invested 

millions of dollars in maintaining its fossil fueled EGUs to comply with environmental 

regulations and increase their energy efficiency. Commenters stated that while it may be possible 

to make some further improvement in the heat rates of existing coal-fired plants, the marginal 

costs are likely to be burdensome. Commenters stated that under Building Block 2 of the 

Proposal, NGCC will replace much of the output from coal plants, reducing revenues and placing 

expensive environmental upgrades out of reach. Commenters stated that if EPA's 111(b) 

regulation goes into effect this would in turn require the unit to deploy carbon capture and 

sequestration technology, likely rendering the project unviable. Commenters proposed that the 

coal plant efficiency target of 6% be reduced to a more achievable target.

Comment 2: NSPS Limits for NGCC

Response 2: Commenters asserted that the New Source Standard under section 111(b) of the 

Clean Air Act creates a negative disincentive or penalizes cycling to accommodate variable 

renewable generation even though the CO2 reductions would be sizable. This is really a 

comment on a different regulation rather than a comment on the proposed 111(d) emissions 

guidelines. None-the-less EPA would like to point the commenters to the recent study from the 

National Renewable Energy Lab that found that the there is only a negligible increase in CO2 

emissions from ramping and load-following to accommodate renewables. See:

http://www.nrel.gov/electricity/transmission/western-wind-2.html

The following are summaries of the specific public comments under this comment:

Commenters stated that if NGCC units, as BSER, cannot comply with the proposed new source 

standards under current and expected normal, real-world operating conditions, the standards are 

not achievable as required in CAA section 111(a)(1). Commenters stated the EPA has not met its 

burden with respect to demonstrating that the proposed emissions standards for NGCCs are 

achievable. The commenters stated that in order for EPA to demonstrate the achievability of the 

standard, it must: (1) identify variable conditions that might contribute to the amount of expected 

emissions, and (2) establish that the data relied on by the agency are representative of potential 

industry-wide performance, given the range of variables that affect the achievability of the 

standard. The commenters stated that a review of the supporting documentation indicates that 

EPA has identified and considered some, but not all, relevant variables when proposing an 
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emissions standard for NGCC units; in particular, EPA has failed to fully consider the effect of 

the expected increase in renewables deployment and the concomitant effects of increased cycling 

of NGCC units to support the integration of variable renewable resources. The commenters

stated that without such consideration, EPA's analysis cannot be said to be reasonable, nor can 

the resulting emissions standard be deemed achievable. 

Commenters stated that the overall impact of cycling is to reduce overall emissions because 

fossil units are being used less, even though increased cycling leads to increased short-term GHG 

emissions by the units that are ramping up and down because of the negative effect on heat rates. 

The commenters stated that in these cases, while the emissions increases due to cycling may 

result in a unit operating out of compliance with the proposed CO2 standards for new units, these 

increases are likely to be dwarfed by the GHG emissions avoided when renewable facilities are 

operating; accordingly, EPA's proposal for new natural-gas based units would serve to punish, 

rather than reward, those units that are required to undergo more frequent cycling to 

accommodate renewable resources. The commenters stated that EPA should not penalize 

practices that foster the emissions benefits associated with increased operation of variable, 

renewable resources. The commenters stated that increasing the proposed emissions standards 

for all NGCC units to at least 1,100 lb CO2/MWh would help avoid periods of noncompliance 

for these NGCC units.

Comment 3: Startup and Shutdown

Response 3: Because the rule is based on annual average emission rates, start up and shutdown 

events have significantly less impact than in a rule with shorter averaging periods, EPA believes 

there is no need to have separate provisions for startup and shutdown events.

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposed standards must accommodate lower utilization rates and 

more frequent periods of startup and shutdown. The commenters stated that in the NSPS 

Proposal, the numeric emissions limit proposed by EPA is intended to be effective during all 

operating hours, whereas in previous rules (for example, the final industrial boiler MACT rule 

and the MATS rule), EPA has differentiated between startup and shutdown (SS) periods and 

periods of normal operation, providing work practice standards to minimize emissions during SS 

periods. 

As commenters haves commented on past rules, the Agency's rationale for imposing numeric 

emissions limits during SS periods instead of work practice standards appears to be based on 

incorrect, overly broad assumptions about utility operations. The commenters stated that units 

that are utilized at lower capacity factors than those associated with baseload generally have 

frequent SS periods, which results in increased CO2 emissions. The commenters stated that it is 

not correct to assume that the majority of natural gas-based units operate at high capacity factors 
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all of the time, which would correspond to less frequent SS periods, when, in fact, just the 

opposite is true. NGCC units are designed to be flexible, capable of responding relatively quickly 

to changing load and supply. The commenters stated that in fact, the NG TSD notes that the 

mean annual capacity factor for the 307 NGCC units in the study population over 2007-2011 was 

only 36 percent and failing to account for lower utilization rates and more frequent SS periods 

punishes NGCC units for the flexibility for which they are regularly designed and built. The 

commenters stated that while the TSD also asserts that there is no relationship between periods 

of SS and exceedances of the standard, this analysis is based on an analysis of only half of the 

newly built NGCC units, is retrospective in nature and fails to account for the future operational 

characteristics of new NGCCs in accommodating increasing amounts of intermittent renewables 

and distributed generation. The commenters stated that the 2013 Special Reliability Assessment 

also notes that increased renewables integration will result in a greater number of SS periods and 

lower capacity factors for natural gas-based units, which will damage equipment. The 

commenters stated that EPA should increase the proposed standard for new units to 

accommodate actual usage and emissions data from the full range of NGCC unit operations. 

The commenters stated that EPA also should be aware of a high likelihood of unintended 

consequences if it fails to exclude SS emissions from the compliance calculation. The 

commenters stated that if an NGCC unit is only requested by an ISO or RTO to run on an 

intermittent basis with frequent SS, or even at low capacity factors, causing CO2 emissions to be 

high, units would be at risk of noncompliance; rather than risk noncompliance, a utility would be 

likely to withhold a unit from the market, or only offer it into the market at times when the unit 

could be dispatched at high loads. The commenters stated that such practices would risk 

distorting electricity markets and not producing a least-cost outcome for consumers.

Comment 4: The NSPS effectively prevents replacement of retiring coal-fired EGUs with new 

supercritical or ultra-supercritical plants

Response 4: The final standard for new fossil fired steam generating EGUs (the NSPS) does not 

effectively prevent the construction of new supercritical or ultra-supercritical coal fired plants to 

replace retiring coal-fired EGUs. As detailed in the final preamble for the NSPS (see section V 

of the NSPS preamble), the EPA finds that a new highly efficient supercritical boiler can meet 

the final standard of performance of 1,400 lb CO2/MWh-g by implementing 16% CCS – and can 

do so at a reasonable cost. EPA disagrees that the implementation of the CPP will cause a 

reliability problem just because retiring coal units are very likely to be replaced with cleaner 

generation. We also would want to assure the commenters even with the CPP is fully 

implemented in 2030, the U.S. will still have a diverse mix of generation types and coal 

generation will remain a significant contributor as more efficient well controlled plants will 

continue to operate.

The following are summaries of the specific public comments under this comment:
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Commenters stated that EPA should consider the impacts of the NSPS for EGUs; specifically the 

NSPS effectively prevents replacement of retiring coal-fired EGUs with new supercritical or 

ultra-supercritical plants. The commenters stated that despite a 2013 Congressional Research 

Service report observation that an advanced ultra-supercritical CFPP could see an efficiency of 

46 to 48 percent - which could mean as much as 18 to 22 percent less CO2 per MWh generated 

than an equivalent sized subcritical PC (pulverized coal-fired) unit and would simultaneously 

help reduce GHG emissions while helping to maintain the diversity, reliability, and flexibility

required of our electrical power system - because these new units would be subject to the 

proposed NSPS for GHG emissions from new EGUs, they could not be built without carbon 

capture and sequestration (CCS) add-on systems. The commenters stated that they will not be 

built because CCS would negate their efficiency benefits and render them economically 

infeasible.

The commenters stated that the net effect of the CPP and NSPS is to force a relatively rapid and 

extensive concentration of the nation's baseload power generation to one energy source, natural 

gas, which is a reckless, dangerous policy shift that far exceeds the EPA's statutory authority. 

The commenters stated that a significant number of coal-fired EGUs are slated for retirement due 

to a combination of EPA regulatory policies and the proposed Clean Power Plan rule will 

escalate this trend, while the proposed NSPS will preclude replacement of these retiring units 

with newer, more efficient units. The commenters stated that in Montana the projected loss of 

generating load due to CPP will jeopardize grid reliability in the region. 

Comment 5: Existing units that are new will be operated less under 111(d) 

Response 5: As EPA made clear in the proposal and in the final rule, the CPP rule does not 

contemplate disrupting the existing energy dispatch market. The standard approach to 

dispatching generation is through Security Constrained Economic Dispatch (SCED), a wellestablished practice in the electric power industry.1 As the name indicates, SCED is based on the 

economic operation of generating facilities and ensures that the electric system remains reliable 

and secure. Like most regulations affecting the utility power sector, the CPP may change the 

relative cost of generation and that would affect dispatch. It is ultimately up to states to 

determine how best to implement the CPP emission guidelines, which will influence how EGUs 

achieve the required emission reductions (see section VIII of preamble for more detail on state 

plans). Grid operators are practiced at accommodating such changes.

The following are summaries of the specific public comments under this comment:

 

1 See Addressing Biogenic Carbon Dioxide from Stationary Sources; Janet G. McCabe, Acting 

Administrator, Office of Air and Radiation, US EPA, to Air Division Directors, Regions 1-10; 

November 19, 2014.
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Commenters stated that their newest, cleanest unit does not and cannot come close to meeting the 

1,100 lb/MWh limit for new plants. The commenters stated that there is little to no technology to 

reduce carbon emissions from such existing new plants, other than possibly an untested, 

commercially unavailable CCS, meeting the state's targeted reduction requires a scheme in which 

the newest unit operates less. The commenters stated that section 111(d) does not support a GHG 

Rule that authorizes the EPA to disrupt or even to redirect the existing energy dispatch market of 

the independent system operators like MISO and PJM, created to enable a reliable grid at the 

most affordable price.

7.2 EGU NSPS - MODIFIED AND RECONSTRUCTED

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the EGU GHG NSPS regarding modified and reconstructed sources.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Few EGUs will undertake reconstruction which will not result in any significant 

impact. 

Response 1: EPA appreciates the commenters input.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA anticipates that few EGUs will undertake reconstruction through 

2025; for this reason, the proposed standards will not result in any significant emission 

reductions, costs, or quantified benefits in the period of analysis. 

Comment 2: Changes to comply with 111(d) could trigger NSPS modification and limit costeffective compliance options

Response 2: The EPA is not promulgating final standards of performance for, and is 

withdrawing the proposed standards for steam generating sources that make modifications 

resulting in an increase of hourly CO2 emissions of less than or equal to 10 percent (see Section 

XV of the final NSPS preamble). As we indicated in the proposal, 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 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 

NSPS modifications, if any, that may result from these changes. In particular, we do not have 
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sufficient information about the types of modifications, if any, that would result in increases in 

CO2 emissions of 10 percent or less, and what the appropriate standard for such sources would 

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). We are not promulgating final standards of performance for stationary combustion 

turbines that make modifications at this time.

The effect of EPA’s deferral on setting standards for sources undertaking NSPS modifications 

resulting in smaller increases in CO2 emissions and the withdrawal of the June 2014 proposal 

with respect to such sources is that such sources will continue to be existing sources and subject 

to requirements under section 111(d). This is because an existing source does not always become 

a new source when it modifies. Under the definition of “new source” in section 111(a)(2), an 

existing source only becomes a new source if it modifies after the publication of proposed or 

final regulations that will be applicable to it. Thus, if an existing source modifies at a time that 

there is no promulgated final standard or pending proposed standard that will be applicable to it 

as a modified “new” source, that source is not a new source and continues to be an existing 

source. Here, because EPA is not finalizing standards for sources undertaking modifications 

resulting in smaller increases in CO2 emissions and is withdrawing the proposal with respect to 

such sources, these sources do not fall within the definition of “new source” in section 111(a)(2) 

and continue to be an “existing source” as defined in section 111(a)(6).

The following are summaries of the specific public comments under this comment:

Commenters stated that although NSPS modification is triggered less frequently than NSR 

modification, the energy efficiency focus of EPA's Section 111(d) guidelines could compel a 

larger number of physical and operational changes at EGUs that could lead to increases in a 

source's maximum hourly emission rate - the emissions trigger for NSPS modification. The 

commenters urged the Agency to clarify that not only traditional pollution control projects 

qualify for the exclusion, but also physical or operational changes undertaken by sources to 

comply with CAA Section 111(d) plans; this includes projects that improve efficiency and, as a 

result, reduce the amount of CO2 emissions produced per MW of electricity generated.

Commenters stated the EPA proposes to keep existing units that modify in the 111(d) plan 

because 111(b) requirements may be less stringent. Commenters said for example, South 

Dakota's one coal-fired power plant estimates under the EPA's 111(d) proposal that it will only 

be able to operate at 23 percent of its design capacity annually. Commenters stated if it modified 

its operations and fell under 111(b), it could potentially operate as normal because the EPA 

proposed the 111(b) carbon dioxide limit at 2 percent less than the electric generating unit's best 

annual heat rate.

Comment 3: Credit for CO2 reductions in 111(d) plan for units that undergo modification or 

reconstruction and trigger 111(b) requirements 

Response 3: If an EGU undergoes a change to decrease its hourly reductions that EGU would 

not become a modified EGU and would therefor get credit for the decrease in its emissions in 
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complying with an emission standard or state measure. Additionally, that decrease in emissions 

would be reflected in the States overall average or cumulative sum of emissions.

The following are summaries of the specific public comments under this comment:

Commenters requested clarification where an affected unit in a state's 111(d) plan makes a 

modification that triggers the 111(b) requirements for modified and reconstructed sources (e.g. 

conversion from coal to natural gas); will the state receive full credit in its 111(d) plan for the 

resulting CO2 reductions. The commenters stated that providing such credit would appropriately 

incentivize states and utilities to invest in such conversions and EPA should clearly state in the 

final rules that states may receive full credit for the resulting CO2 reductions.

Commenters stated that EPA anticipates that few EGUs will undertake reconstruction through 

2025; for this reason, the proposed standards will not result in any significant emission 

reductions, costs, or quantified benefits in the period of analysis. 

7.3 NEW SOURCE REVIEW (NSR)

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the new source review (NSR) program.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Commenters requested clarification from EPA as to how a state plan could protect 

a source from triggering NSR regulations.

Response 1: Commenters’ assertions regarding what they perceive as EPA’s theme to force 

fossil fuel-fired units to reduce utilization and generation and whether EPA has such authority 

are misplaced as they represent a misunderstanding of the discussion about NSR interactions and 

possible state plan components that could limit the number of sources that would trigger NSR as 

a result of complying with state 111(d) compliance plans. In the proposal we took comment on 

the possibility of states using the flexibility in designing their 111(d) implementation plans in a 

way that would consider the possible situation where an affected source would trigger NSR as a 

result of the state plan requirements and whether it would be possible for that state to include 

provisions in such plan to minimize or eliminate those instances. We continue to believe that it is 

possible for states and affected EGUs to work together during the plan development phase to 

take into consideration how the state measures being considered would affect the EGUs subject 

to the plan requirements and develop strategies, including specific permit terms and conditions, 

the use of EE/RE programs to displace some expected generation increases at the EGU in 

question, etc., to limit the number of sources triggering NSR as a result of the state 111(d) plan. 
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Regarding commenters’ suggestion that EPA provide an NSR exemption for sources that would 

trigger NSR as a result of complying with the state’s 111(d) plan, the EPA appreciates the 

commenters’ suggestions, however, the EPA has previously promulgated similar exemptions 

from the NSR rules in order to remove regulatory disincentives to undertaking positive, or even 

required, actions such as installing pollution controls, only to have these exemptions rejected by 

reviewing courts. The United States Court of Appeals in State of New York, et al., v. U.S. 

Environmental Protection Agency (NY I) was clear that we lack the authority to create such 

exemptions from the NSR rules. In addition, commenters’ suggestion that EPA define an 

“increase”in emissions under the NSR program to only include increases in lbs/MWh for sources 

complying with the 111(d) program is inconsistent with EPA’s practice and the decision in 

Environmental Defense et. al v. Duke Energy Corp. et al, decided by the US Supreme Court 

April 2, 2007. Commenters’ statement objecting to what they interpret as EPA’s suggestion that 

a state could lawfully force a source to subject itself to NSR requirements by requiring 

compliance with the section 111(d) plan is misplaced. The requirement to obtain a 

preconstruction permit under NSR is independent of other applicable requirements to affected 

sources and is triggered as a matter of law. For example, a source may become subject to a new 

national emissions standard for hazardous air pollutants which will require the source to install 

certain air pollution control devices to comply with the new rule and these requirements may in 

turn trigger some collateral emissions increases that would trigger the need for a NSR permit. 

The same set of circumstances can exist in the context of a state 111(d) plan but as discussed in 

the preamble and elsewhere in this section, states have great flexibility in developing their 

compliance plans including provisions to minimize the number of sources that trigger the 

requirements for NSR permits.

Finally, regarding the comment on lack of cost and economic impact related to NSR 

applicability, as discussed in the preamble to the proposed emissions guidelines, our analysis 

shows that only a small percentage of affected EGUs are expected to potentially trigger the need 

to apply for a NSR permit as a result of changes made to comply with requirements resulting 

from 111(d) state plans and that result in emissions increases large enough to trigger NSR but 

this analysis is just one example of a compliance path that is not required to be followed in 

exactly the same way by any particular state. As a result, while the EPA analysis shows few 

instances where triggering NSR is a possibility, it is not clear whether any sources will actually 

trigger NSR since they will be subject to state plan requirements that can include flexibilities and 

specifically designed requirement to limit or completely avoid any sources from triggering these 

requirements. The EPA expects that the majority of heat rate improvements will be made to 

sources that are already well controlled, so expected to remain in operation for a long enough

period to recover those investments. The EPA’s modeling does not show heat rate 

improvements made at many units that would require additional control technology for NOx or 

SO2 beyond the control already in place at these units. . 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA discusses implications of the proposed CO2 guidelines for other 

EPA programs and rules, including implications for the New Source Review ("NSR") program. 

Commenters said EPA acknowledges that a state plan under EPA's CO2 guidelines might impose 

requirements on a source which could increase a unit's annual emissions, thus potentially 

triggering NSR requirements. Commenters said NSR requirements could cost a utility hundreds 
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of millions of dollars, both to comply with BACT requirements and potentially for other costs 

and penalties. Commenters said that EPA offers little help for states in avoiding the obvious 

conundrum that complying with a state's CO2 compliance plan will assuredly cause a source to 

violate NSR regulations. Commenters said EPA suggests that perhaps reducing the demand for 

generation would save a utility from becoming subject to NSR or, failing that, a state could 

"limit the unit's ability to move up in the dispatch enough to resolve a significant net emissions 

increase that would trigger NSR ..." Commenters said these suggestions are merely more 

variations on EPA's theme to force fossil fuel units to reduce utilization and generation. 

Commenters said not only is it questionable whether EPA has authority to require such 

reductions, but also it is not good policy to force an EGU owner to choose between complying 

with a state's CO2 plan or complying with NSR regulations.

Commenters stated that EPA is not at all instructive on how a state could devise a plan, based on 

some unexplained, underlying analysis, that would not subject units to NSR when they add 

controls to comply with the state's Section 111(d) plan. Commenters said the appropriate 

solution, in commenters' view, would be a determination that if compliance with the section 

111(d) plan causes a unit to have a significant net emission increase of an applicable pollutant, 

the activities at the unit bringing the unit or source into Section 111(d) compliance shall not be 

deemed to trigger NSR. Commenters said in the alternative, if an operator of a unit provides 

projections to show that to bring a unit into compliance with a state's Section 111(d) plan there 

would be a reasonable possibility that the unit would become subject to NSR requirements, 

compliance costs or penalties, then the unit should not be required to comply with the 111(d) 

plan, but the state would still be credited with a reduction in its 2030 CO2 target in the amount of 

the CO2 reduction anticipated by the utility had the project(s) been completed.

Commenters stated that it is not clear what EPA's intentions are. Commenters said that to the 

extent that EPA is suggesting that a state could lawfully force a source to subject itself to NSR 

requirements by requiring compliance with the section 111(d) plan, commenters object. 

Commenters said nowhere in the proposed CO2 guidelines has the EPA analyzed the 

significance, cost and economic impact that such a nationwide program would have. 

Commenters said as such, there is no basis in this record that could support such a result.

Commenters stated CAA section 111(a)(4) defines "modification" to mean "any physical change 

in, or change in the method of operation of, a stationary source which increases the amount of 

any air pollutant emitted by such source or which results in the emission of any air pollutant not 

previously emitted." The commenters stated that section 111 does not, however, define either the 

term "increases" or "amount." The commenters stated that EPA retains discretion to determine 

what those words mean in the context of the program at issue and provides EPA, and states 

adopting plans pursuant to the guidelines, with the flexibility to develop approaches to treat 

efficiency projects as not having emissions increases that would trigger major NSR. The 

commenters recommended that EPA clarify that for EGUs, the applicable NSR emissions 

increase test for regulated NSR pollutants will be on a pounds-per-MWh basis. The commenters 

stated that EPA could use a pound-per-MWh emissions test as the sole emissions applicability 

test for projects undertaken by EGUs. The commenters stated that while not necessary (and 

contrary to achieving early deployment of upgrades nationwide), EPA could tie the use of this 

test to EGUs complying with a section 111(d) state plan. The commenters stated that to avoid 

unintended consequences with projects that do not have a pounds-per-MWh decrease, EPA could 
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also use a two-step emissions test: EGUs would first determine whether a physical or operational 

change would achieve a reduction in emissions on a pound-per-MWh produced basis; if poundper-MWh remained stable or increased, EPA could then revert to its traditional approach to 

assessing NSR modification by determining whether the emissions increase in tons per year 

exceeds significance levels for the regulated pollutants.

Commenters proposed that if a state seeks to meet their Building Block 1 goals by adopting a 

fleet-wide cap on carbon emissions that reduces over time, they should be allowed some 

flexibility under the modification and reconstruction provisions of both NSPS and PSD rules. 

Commenters stated that it is important to note that the changes required to convert Spruce 1 to a 

supercritical boiler would, without question, be considered non-routine physical changes under 

EPA new source review (NSR) or prevention of significant deterioration (PSD) programs. 

Commenters stated that if CPS Energy were to invest in these improvements and continue 

planned retirement of older coal-fired units, both plant utilization and emissions would increase, 

triggering PSD permitting requirements and installation of additional emission controls. 

Commenters stated that whatever efficiency improvements might be possible by the increase in 

plant efficiency would be lost (because of the parasitic load of such emission controls) and cost 

prohibitive because of the added costs of the emission controls 

Comment 2: Exempt sources from NSR for actions taken to comply with guidelines

Response 2: The EPA appreciates the commenters’ suggestions for adding or expanding 

exemptions to the New Source Review (NSR) rules for physical changes undertaken to comply 

with the Clean Power Plan. However, the EPA has previously promulgated similar exemptions 

from the NSR rules in order to remove regulatory disincentives to undertaking positive, or even 

required, actions such as installing pollution controls, only to have these exemptions rejected by 

reviewing courts. The United States Court of Appeals in State of New York, et al., v. U.S. 

Environmental Protection Agency (NY I) was clear that we lack the authority to create such 

exemptions from the NSR rules. The same court ruled in a later case, State of New York, et al., 

v. U.S. Environmental Protection Agency (NY II) that we did not have the authority to expand 

what we covered under the exemption for routine maintenance, repair and replacement. 

Several commenters expressed concern that the EPA had overstated the ability of some natural 

gas-fired units to achieve the level of production assumed in Building Block 2 because of 

existing permit limits taken to avoid major NSR. The EPA agrees with these commenters that 

some units with permit restrictions that were taken to avoid NSR at the time of construction or 

modification could trigger NSR if/when those restrictions are removed as a result of a change to 

comply with a state 111(d) implementation plan. The commenters have not provided information 

in the record to demonstrate that there are a significant number of units that have taken permit 

restrictions. The EPA does not have information that the majority of gas-fired units have such 

permit restrictions and as a result, as long as the unit is not undergoing a physical change or 

change in the method of operation as defined in the NSR regulations, believes that such sources 

would be able to increase their utilization without the need for a NSR permit. 
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Regarding the comment that the EPA instead of states conduct an analysis consistent with the 

NSR regulatory requirements that supports a determination that, as long as affected sources 

comply with the standards of performance in their section 111(d) plan, the source's emissions 

would not increase in a way that triggers NSR requirements, we note that state permitting 

agencies do NSR applicability analysis routinely and are better positioned that EPA to know 

whether a particular source in their state will trigger NSR or not as a result of a 111(d) plan 

requirement. These analyses would have to be conducted for all NSR regulated pollutants, not 

just CO2, as is required by the NSR regulations.

Finally, the final emissions guidelines do not require states to apply the BSER building blocks in 

the same way that EPA applied them to develop the standards of performance and state targets. 

The final guidelines provide states with ample flexibility to develop state plans that take into 

consideration a number of factors including the possibility of NSR permit requirements on 

affected units and develop plans that minimize such impact.

The following are summaries of the specific public comments under this comment:

Commenters stated that actions necessary to comply with state guidelines have the potential to 

trigger NSR. The commenters recommended that EPA exempt sources from NSR as they comply 

with 111(d) guidelines or provide an expedited permitting path.

Commenters stated that changes that are necessary to meet specified GHG reduction 

requirements under EPA guidelines should be exempt from triggering New Source Review, as 

compliance with the GHG reduction requirements should not force further reductions in criteria 

pollutants.

Commenters stated that EPA should correct disincentives to upgrades through regulatory and/or 

interpretative changes that would facilitate compliance with Section 111(d) without triggering 

NSR. The commenters recommended that in the final rule, EPA should state that upgrades 

conducted pursuant to an approved Section 111(d) plan to improve efficiency are covered by the 

routine maintenance, repair, and replacement exclusion; given that these projects and their 

upkeep are necessary under Building Blocks 1 and 2 of the Proposed Rule, they can be 

considered part of a unit's routine maintenance and repair.

Commenters recommended the following regulatory language to avoid triggering NSR 

permitting requirements:

• A change in utilization at a source as a result of a change in dispatch of affected 

entities under this Rule that results in an increase in emissions of any regulated 

NSR pollutant (as defined in paragraph (b)(50) of 40 CFR section 52.21) shall not 

be a change in the method of operation for purposes of establishing a major 

modification under 40 CFR section 52.21(b)(2)(i).

• An increase in emissions resulting from a physical or operational change 

undertaken to comply with this Rule that improves the heat rate of an affected 

entity subject to this Rule shall not be a physical change or a change in the 
14

method of operation for purposes of establishing a major modification under 40 

CFR section 52.21(b)(2)(i).

Commenters recommended as an alternative to the above, that EPA consider whether physical or 

operational changes undertaken pursuant to the CPP could be handled in a similar fashion to 

GHG emissions under EPA's Tailoring Rule. The commenters stated that EPA could find that 

physical or operational changes undertaken solely to comply with a state plan under the CPP 

(e.g., Building Block 1) that result in an emissions increase of any regulated NSR pollutant 

(including CO2) would not trigger NSR permitting requirements, but if the source undertakes a 

project that results in an improvement to heat rate, but was not done in furtherance of achieving a 

state goal under the CPP, the source may trigger NSR permitting requirements. The commenters 

requested also that EPA specifically streamline provisions for modifications to air permits, 

primarily for gas units, when the existing air permit contains limits on the hours of operation and, 

to the extent that this is not possible due to air quality impacts, then the EPA should specifically 

exempt such units from any aspect of Building Block 2.

Commenters stated that projects to improve heat rate may reduce emissions of CO2, but may 

increase emissions of other regulated pollutants and trigger NSR requirements. The commenters

recommended that the EPA include an explicit exemption to NSR permitting requirements for 

projects or activities undertaken by affected entities to comply with Section 111(d) and in order 

to assume consistent enforcement should not be left to individual state implementation plans. 

The commenters recommended adding language that excludes projects undertaken pursuant to a 

state Section 111(d) plan from the definition of "major modification." The commenters stated 

that another approach would be to handle physical or operational changes made pursuant to 

Section 111(d) in a manner similar to GHG emissions under the Tailoring Rule; the EPA could 

find that physical or operational changes undertaken solely to comply with a state plan under 

Section 111(d) that result in an emissions increase of any regulated NSR pollutant would not 

trigger NSR permitting requirements. The commenters stated that this approach could recognize 

that if the source undertakes a project that results in an improvement to heat rate, but was not 

done in furtherance of achieving a state goal under Section 111(d), the source may trigger NSR 

permitting requirements. The commenters stated that EPA should also note that while most NSR 

discussions are focused on Building Block 1, there are also natural gas units that have taken 

synthetic minor restrictions to avoid NSR and increasing utilization may impact the status of 

these units and trigger NSR. The commenters stated that as such, it should not be assumed that 

these units can meet or exceed a 70 percent utilization rate without the removal of certain permit 

restrictions.

Commenters stated that implementation of the proposed rule's building block 1 is likely to 

trigger NSR requirements. The commenters recommended that EPA develop alternative 

screening methods for an expedited, streamlined NSR process designed to ensure that any 

criteria pollutant increase would not interfere with the attainment of NAAQS. The commenters

stated that these screening tools can confirm that well-controlled sources and sources with net 

emissions increases of criteria pollutants below levels that would interfere with attainment have 

satisfied NSR requirements. The commenters stated that EPA could also find that compliance 

with Section 111(d) standards satisfies applicable PSD and BACT requirements for GHG 

emission reductions, since the standards should represent the maximum degree of reduction 

achievable, taking into account energy, environmental, and economic impacts and other costs.
15

Commenters stated that even the seemingly already-available NGCC capacity for re-dispatching 

needs further consideration. The commenters stated that it is possible that in order to achieve 

increased capacity factor as required by the rule, that the existing under-utilized NGCCs will 

need to undergo a physical change or change in the method of operation. The commenters stated 

that efforts made by existing NGCC to accommodate a heavy increase in dispatching could most 

certainly be identified as a physical change or change in the method of operation, which would 

fit EPA's broad interpretation of the major modification definition. The commenters stated that 

an exception to this broad interpretation of "physical change or change in the method of 

operation" is an activity that is exempted which are identified at 40 CFR 52.21(b)(2)(iii)(a) 

through (k). The commenters stated that none would appear applicable to a NGCC which 

requires a project either related to or unrelated to the re-dispatching. The commenters stated that 

with no major modification exemption appearing to be applicable, if a project results in a 

significant emissions increase, PSD review provisions (and/or NA NSR review provisions) 

would need to be addressed in any pre-modification permit application/permit review exercise. 

The commenters stated that the methodology for determining the project emissions increase 

would be completed, for the modified EGU, using the applicability procedures outlined at 40 

CFR 52.21(a)(2)(iv)(c), the actual-to-projected actual applicability test.

Commenters stated that unless NGCC facilities are already permitted at 70 percent capacity or 

more, re-dispatching could cause a facility's increased usage to trigger NSR, making this option 

either infeasible or very costly. The commenters stated that the Afton Generating Station is 

permitted to operate only 1,920 hours per year with its duct burner, yet EPA assumed full 

nameplate capacity using duct burner's to determine the amount of re-dispatch to this facility 

under Building Block 2. The commenters stated that for this assumption to be a possibility, the 

facility would need to undergo NSR permitting in order to fully utilize the duct burners, which 

would require the evaluation of additional impacts to the air shed, additional emission controls 

which lower the unit's efficiency, and increased operating costs. The commenters stated that 

because NSR permitting may limit a unit's operation, the EPA estimate of re-dispatch to this 

facility is greatly overestimated.

Re-dispatch. Commenters stated that EPA needs to be conscious of any possible constraints 

regarding dispatch of less CO2 emitting units. The commenters stated that under Building Block 

2, Regional Transmission Organizations would be expected to dispatch the lower CO2 intensive 

energy first, which could result in facilities that produce energy at a lower CO2 rate being called 

on to dispatch more frequently than in the past and, as a result, exceed limits that could trigger 

NSR.

Commenters stated that EPA should issue a determination that EGUs in compliance with their 

section 111(d) performance standards would not trigger NSR requirements, rather than as EPA 

proposed, that states could conduct an analysis consistent with the NSR regulatory requirements 

that supports a determination that, as long as affected sources comply with the standards of 

performance in their section 111(d) plan, the source's emissions would not increase in a way that 

triggers NSR requirements. The commenters agreed with EPA that such an analysis would be 

appropriate but does not agree that the analysis should be left up to the states. The commenters

stated that the statement in the preamble is insufficient to provide states with sufficient guidance 

on how the analysis should be done to ensure that it is legally defensible under the NSR 

regulations. The commenters stated that, for example, it is unclear whether EPA intends that 
16

such a determination would be made for all NSR regulated pollutants or only for CO2; a 

determination that did not consider all NSR regulated pollutants would be insufficient to ensure 

that EGUs can avoid NSR for their heat rate improvement projects. The commenters stated that 

EPA should undertake the analysis and make the determination that sources in compliance with 

their standards of performance in their section 111(d) plans would not trigger NSR requirements. 

The commenters stated that without an EPA determination or at least more detailed guidance 

from EPA on how such a determination should be made, most states will decline to undertake 

such an analysis on their own; even if a state undertakes the analysis and issues such a 

determination, it is unlikely to curb citizen suits directed at EGUs that are undertaking heat rate 

improvement projects to meet their section 111(d) performance standards or even enforcement 

actions brought by EPA.

Commenters stated that to the extent that assurance cannot be provided that an efficiency 

increase required under a state plan will not trigger NSR, EPA should scale back the emission 

reductions assumed for purposes of building block 1.

Comment 3: EPA did not account for constraints that NSR requirements would place on EGU's 

achieving proposed heat rate improvements 

Response 3: The EPA does not dispute that modifications that are included in the Sargent and 

Lundy report used as the basis for Building Block 1 (BB1) have been cited in NSR enforcement 

cases. The enforcement cases have focused primarily on those units that did not install 

appropriate controls, particularly for NOx and SO2, when they should have (as a result of 

making modifications). So while EPA agrees that there may be some sources that trigger NSR 

permitting as a result of implementing changes to comply with state 111(d) plans the modeling 

conducted for this rule making does not indicate that many of these would be required to install 

controls for NOx or SO2. There are, however, many factors that affect whether an emissions 

unit will trigger NSR and this is not just because of improved efficiency of the units.

Several commenters went on to say that the EPA had not properly considered the costs 

associated with either obtaining NSR permits or taking actions to avoid permitting. As discussed 

in the preamble to the proposed emissions guidelines, our analysis shows that only a small 

percentage of affected EGUs are expected to potentially trigger the need to apply for a NSR 

permit as a result of changes made to comply with requirements resulting from 111(d) state plans 

and that result in emissions increases large enough to trigger NSR but this analysis is just one 

example of a compliance path that is not required to be followed in exactly the same way by any 

particular state. As a result, while the EPA analysis shows few instances where triggering NSR 

is a possibility, it is not clear whether any sources will actually trigger NSR since they will be 

subject to state plan requirements that can include flexibilities and specifically designed 

requirement to limit or completely avoid any sources from triggering these requirements. Based 

on the modeling supporting this rule, the EPA does not expect a significant number of sources to 

either need to obtain NSR permits, or take actions to avoid them. . Commenters also expressed 

concern with being able to recover the investments made in these efficiency improvements. The 

EPA expects that heat rate improvements will be made to sources that are expected to remain in 

operation for a long enough period to recover those investments. 
17

Commenters also stated that the EPA had not provided sufficient time before the interim CO2

emission performance rate milestone to obtain NSR permits. In response to numerous comments 

regarding the time need to develop state plans and begin to make reductions, the EPA has 

extended the interim performance rate milestone by two years, to 2022. With this extension, the 

EPA believes there will be sufficient time to obtain any necessary NSR permits. 

Commenters expressed concern that if they were required to get PSD permits, and go through a 

BACT determination, that they could be required to install carbon capture and sequestration 

because that is what has been proposed as the Best System of Emissions Reduction (BSER) for 

newly constructed fossil-fuel fired electric utility generating units (EGUs). Because the 

improved efficiency achieved by any heat rate improvements is intended to result in decreased 

emissions of CO2, the EPA believes it is unlikely that sources will be required to get a PSD 

permit for increases in CO2. It is important to understand that a PSD permit and BACT analysis 

can only be required for an existing major PSD source if there is also a major modification that 

increases a pollutant other than CO2. In those instances where a PSD permit and BACT analysis 

is required, BACT cannot be less stringent than any applicable standard of performance under 

the NSPS. The NSPS applicable to existing EGUs will be this standard, the Clean Power 

Plan. So, while the development of CCS technology may require that it be assessed as an 

available technology in the BACT analysis, the reliance on it as BSER for newly constructed 

EGUs will not set the BACT floor for existing EGUs 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA did not take potential NSR permitting costs or limitations into 

account in establishing that heat rate improvements were BSER under Building Block 1 or in 

determining that coal-fired EGUs would be able to achieve such improvements by the beginning 

of the interim compliance period.

Commenters stated that EPA failed to consider NSR constraints on achieving heat rate 

improvements at coal-fired EGUs. The commenters stated that in setting state emissions 

reduction goals, EPA assumed that each state's coal-fired EGUs that are projected to continue 

operating after 2020 would achieve a two percent heat rate improvement from equipment

upgrades that increase the unit's efficiency although some coal-fired EGUs may choose not to 

implement these efficiency projects due to uncertainty over whether the projects are major 

modifications that would trigger NSR requirements or may seek an applicability determination 

from the state before undertaking the project, which likely would significantly delay installation 

of the improvements. The commenters stated that EPA did not take potential NSR permitting 

costs or limitations into account in establishing that heat rate improvements were BSER under 

Building Block 1 or in determining that coal-fired EGUs would be able to achieve such 

improvements by the beginning of the interim compliance period. The commenters

recommended that EPA ensure in the final rule that current NSR policies do not discourage 

EGUs from undertaking heat rate improvement projects.

Commenters stated that EPA's conclusion in the proposed guidelines that there will be few 

instances where an NSR permit would be required in response to the guidelines is incorrect. The 

commenters stated that the increased output and utilization associated with an efficiencyimprovement project could trigger NSR under EPA's current regulations and guidance; 
18

furthermore, unlike NSPS, NSR rules do not contain an applicability exclusion for pollution 

control projects. The commenters stated that a key aspect of pre-reform NSR that discouraged 

sources from considering upgrade projects include the manner in which EPA guidance has 

required emission increases from a project to be determined by comparing baseline actual 

emissions (highest actual emissions over a 24-month period preceding a change) to future 

potential emissions. The commenters stated that as a result, if the facility operated at a relatively 

low capacity factor, and the future potential emissions are based on a higher capacity factor, the 

NSR significant emission levels could easily be triggered. The commenters stated that under the 

NSR reform rules, which apply in many, but not all, states, an actual-to-projected-actual 

emission increase test applies; but even that test does not effectively and reliably exclude 

emissions associated with increased utilization from an efficiency upgrade. 

Commenters stated that projects will be reviewed for compliance with NSR; however, 

procedures to review heat rate improvement projects conducted to comply with the Clean Power 

Plan should clearly exclude eligible projects from NSR applicability. The commenters stated that 

every efficiency project will require review and application of the demand growth exclusion. The 

commenters stated that they are aware of numerous instances where applicability of NSR to 

efficiency upgrades could be subjected to legal review, which will be a legal impediment to 

accomplishing the goals set out in the plan. The commenters stated that EPA must address this 

issue by providing procedures for exempting EGU heat rate improvements from NSR 

applicability; this exemption process should also prevent NSR applicability for SO2, NOx and 

other criteria pollutants. The commenters provided the following example: consider two identical 

coal units located in a state with a goal of reducing coal dispatch 38% after heat rate 

improvements. Commenters stated both units are operated at an 80 percent capacity factor prior 

to the rule's effective date. Commenters stated if both units continue in operation, they would 

both be reduced to a capacity factor of 50 percent and both units would require heat rate 

improvements. Commenters stated one solution would be, theoretically, to retire one unit, 

improve the heat rate of the remaining unit, shift all coal generation to the remaining unit up to a 

capacity factor of 95 percent, and shift a small amount of generation to other resources. In this 

example, commenters stated it is not clear that the generation shift would qualify as demand 

growth. Commenters stated while the environmental benefits of this action are clear, NSR should 

also not be applicable to this project. 

Commenters stated that NSR is triggered by an annual increase in emission mass (tons per year), 

which may occur with increased operations after an efficiency improvement project. The 

commenters stated that because EPA considers NSPS as the floor in determining a BACT 

emission limit for an existing unit modification project subject to NSR, sources attempting to 

comply with BB #1 would find themselves subject to an emission limit that may prove 

impossible to meet. The commenters stated that the modified and reconstructed NSPS emission 

limit (a 2% efficiency improvement and an emission limit floor of 1900 lb/MWh) is not 

specifically applicable to BACT and would provide the bottom for a top-down BACT 

determination. The commenters stated that as control technology becomes available, it is 

conceivable that a BACT could require partial carbon capture and sequestration because, while 

EPA has said that it will not require CCS for existing units, the current EPA cannot bind a future 

EPA. The commenters stated that, even if EPA did not follow its traditional regulatory 

interpretation that NSPS is the BACT floor, environmental groups across the country could 

challenge any and all of these improvements at a coal plant as requiring partial CCS. The 
19

commenters recommended that before finalizing this rule, EPA must directly address the NSR 

issue by exempting all projects and demand growth due to re-dispatch undertaken to meet the 

requirements of this rule. 

Commenters stated that significant investments into an existing source may cause the facility to 

undergo NSR, meaning it is subject to regulations applicable to new, not existing sources. The 

commenters stated that if the 111(b) regulation for new EGUs is finalized as proposed, coal 

plants investing the capital to achieve the expected 6 percent improvement might then be 

expected to deploy CCS, which, as discussed above in this testimony, would render the project 

economically unviable. The commenters stated that even in the absence of finalization of the 

111(b) rule, EPA's NSR requirements create perverse environmental incentives, and can actually 

impede the deployment of newer and more efficient technologies.

Commenters stated that a project to improve the heat rate of a unit - while reducing emissions of 

CO2 - can simultaneously result in an emissions increase of other regulated pollutants and trigger 

NSR requirements if there is a significant increase of any one regulated pollutant under the CAA. 

The commenters stated that to create the regulatory environment necessary for existing sources 

to timely and economically meet the proposed heat rate improvements, EPA must exempt such 

projects from NSR. The commenters stated that, further, implementation of the CPP may trigger 

NSR for coal-fired power plants that decrease or otherwise modify their operations to reduce 

utilization; the majority of existing coal-fired power plants were designed to operate as base load 

plants. The commenters stated that it is foreseeable that affected EGUs will implement, or be 

forced to implement, operational changes to turn base load plants into cycling plants and because 

the majority of coal-fired plants were not designed for such operation, such operational changes 

are foreseeable and may result in increases in emissions sufficient to trigger NSR. The 

commenters stated that, lastly, the CPP is designed to increase sales of energy generated with 

less carbon intensive fuels; on paper, the NSR rules exempt emission increases that are projected 

to be due to increases in demand (i.e., demand growth). But, the commenters stated, in practice 

EPA has allowed sources to use this demand growth exclusion narrowly, especially in 

circumstances where a source has changed fuels. The commenters stated that EPA has argued 

that emission increases due to demand that follow a fuel switch are generally not excludable 

because the source could not have accommodated those emissions caused by the new fuel before 

the project occurred. Commenters stated the practical effect of all of this is that a rule that 

increases demand by requiring sources to implement efficiency projects, under EPA's current 

interpretation of its NSR rules, will likely trigger NSR permitting requirements for affected 

sources. The commenters stated that, thus, the goal of the proposal contravenes the existing 

promulgated NSR rules that are already being enforced by EPA in that it will increase demand 

for some electrons - the product - that were formerly generated by coal. The commenters stated 

that additionally, states must prepare a SIP that will likely require increased utilization due to 

demand growth for less-intensive carbon generated energy. The commenters recommended that 

EPA specifically exempt from this rule, and specifically announce a departure from its past 

enforcement policy that exempts, this type of increase. The commenters stated that EPA should 

also accept statements of future business planning, whether announced publicly or merely 

incorporated into company planning documents, as relevant business expectations; and a 

"planned" increase in CO2 emissions at one unit in order to build a less intensive unit should be 

exempted. The commenters stated that, in sum, EPA cannot ignore the potential interaction 

between NSR and the CPP and, because we believe that efficiency projects should not - as a 
20

matter of law - trigger NSR permitting requirements, we recommend that EPA categorically 

exclude such projects from NSR permitting requirements.

Commenters stated that unlike NSPS, NSR rules do not contain an applicability exemption for 

pollution control projects and, for this reason, NSR has represented a substantial impediment to 

broad implementation of otherwise feasible, cost-effective efficiency upgrade projects. The 

commenters stated that the NSR permitting process can have many negative consequences for a 

source, including construction delays, and can delay projects one to two years beyond the much 

shorter minor NSR permitting process. Commenters stated because NSR requires case-by-case 

review, there is often significant uncertainty regarding the likely outcomes, including whether 

the project will be approved, and what new permit conditions may be attached, including their 

potential costs. The commenters stated that EPA's existing network of regulatory requirements is 

complex and constantly changing; often customers are faced with the problem of responding to

new permit conditions from regulatory changes that occurred following the permit application, 

creating a difficult do-loop for permit seekers. The commenters stated that finalizing a section 

111(d) rule without including regulatory changes that address NSR applicability would 

significantly undermine the ability of EGUs to comply with state 111(d) plans and will 

discourage many facilities from making physical or operational changes that would improve 

efficiency and facilitate compliance with section 111(d).

Commenters stated that EPA is underestimating NSR's impacts on sources and over-estimating 

the ability of states to allow sources to avoid NSR. The commenters stated that EPA's 

assumption that HRI changes would infrequently trigger NSR because of state flexibility is 

incorrect. The commenters referred to their Appendix X, which contains a listing of HRIs which 

EPA identified as violating either PSD or NSR rules, as well as the October 15, 2014 Sargent & 

Lundy letter that states that many of the options for HRI listed in their 2009 Report have 

triggered NSR actions by EPA and others. The commenters stated that they do not agree with 

EPA's assumptions that states could adjust EE/RE as a way of reducing the future emissions of 

an affected source and, thereby, avoid NSR. The commenters stated that this is another example 

of EPA negating the perceived flexibility they are affording states; now in the process of 

developing our plans we must add in another complex layer of eliminating measures that could 

trigger NSR for our sources. The commenters stated that the process of triggering NSR would 

further exacerbate the timing issues under this proposal; there is not enough time for companies 

to analyze regulations, conduct HRI studies, prepare NSR permit applications, perform 

modeling, and obtain permits under EPA's timeline. The commenters stated that, contrary to 

EPA's beliefs, the HRI part of the state plan will require lead time for these types of 

improvements, to obtain internal approval, acquire parts and/or equipment, manpower, and 

approval in order to have down time in some cases, is considerable; adding NSR to the mix will 

greatly hinder the state's ability to develop plans with any type of early reductions. 

Commenters stated that regarding EPA's request for comment on whether the state plan could 

include a provision, based on underlying analysis, stating that an affected source that complies 

with its applicable standard would be treated as not increasing its emissions, and if so, whether 

such a provision would mean that, as a matter of law, the source's actions to comply with its 

standard would not subject the source to NSR, they do not believe the states should have to 

provide any analysis to support not subjecting sources to NSR under this plan. The commenters

stated that they believe this rule should exempt any source from NSR that undertakes a change 
21

that results in the triggering of NSR, not just for CO2 but for an increase in any other pollutant, 

because the change is required under the state plan.

Commenters stated that the EPA claim that there will be few instances for which an NSR permit 

would be required as a result of implementing Block 1 heat rate improvements is incorrect. The 

commenters stated that in their case the high pressure and intermediate pressure (HP/IP) turbine 

replacement project discussed elsewhere in their comments required NSR permitting specifying 

new carbon monoxide (CO) emission limits and related CEMS monitoring and reporting 

requirements. The commenters' experience suggests that NSR permitting will likely be required 

for heat rate improvement projects involving HP/IP turbine replacement; consequently the CPP's 

compliance schedule is unrealistic because it does not include time for affected EGUs to 

complete what likely will be contentious NSR permitting efforts.

Commenters stated that EPA's assumptions regarding the achievable improvement in heat rate 

across the fleet of twelve coal-fired EGUs in Arizona, both through adoption of best practices for 

operation and maintenance and through equipment upgrades, do not take into account the 

requirements of the agency's NSR programs; EPA's assumptions regarding achievability of 

increased capacity factor at NGCC units similarly fails to take these effects into account. The 

commenters stated that EPA's analysis of the economic impacts of the Proposed Rule does not 

address any costs for even the limited number of NSR-triggering projects that it assumed. The 

commenters stated that EPA also fails to recognize that the predominant costs of compliance

with the NSR programs are incurred not in the context of obtaining NSR permits, but in efforts to 

avoid triggering preconstruction NSR permitting; EPA's speculation regarding the number of 

sources that would trigger preconstruction NSR permitting is therefore not informative as to the 

total costs to comply with NSR program requirements, if it were possible to achieve the heat rate 

improvements and increased capacity factor required by the Proposed Rule.

Commenters stated that although EPA ignores the NSR permit avoidance compliance option and 

overlooks the costs of this compliance mechanism, it is not because EPA is unaware. The 

commenters stated that, for example, in both internal and external correspondence regarding the 

project proposed by WEPCO, which ultimately led to the landmark WEPCO court decision, EPA 

specifically recognized the possibility that WEPCO would implement emissions-reducing 

measures in order to avoid preconstruction NSR permitting requirements. The commenters stated 

that in addition, in responding to Congressional oversight regarding its implementation of the 

NSR programs for coal-fired EGUs, EPA touted the flexibility provided by the NSR program for 

implementation of emissions-reducing measures to avoid preconstruction NSR permitting 

requirements. The commenters stated that the source may employ any method or technique it 

chooses, either voluntarily or through enforceable permit terms, to avoid emissions increases and 

thereby avoid preconstruction NSR permitting requirements. Commenters stated compliance 

with the NSR program, even under this interpretation, is very costly, but not as costly as it would 

be if source owners and operators were constrained with respect to the available techniques for 

avoiding emissions increases. The commenters stated that referring to a statement in the 

preamble to the Proposed Rule (79 Fed. Reg. at 34,928), EPA's conclusion regarding a small 

number of EGUs at which preconstruction NSR permitting requirements will be triggered is 

based on the assumption that, even for a modification to an EGU which is initially projected to 

cause a threshold emissions increase, the owner or operator of the EGU may lawfully avoid NSR 

simply by hoping that electric demand will not increase. The commenters stated that EPA has not
22

demonstrated how such an approach is consistent with the existing major NSR provisions that 

require a major source to project post-change emissions before undertaking a project. The 

commenters stated, with respect to demand growth, EPA has explicitly stated that even if a 

facility could have met the level of demand before a change, if it can be shown that the increase 

is related to the changes made to the unit, then the emissions increases resulting from the 

increased operation must be attributed to the modification project.

Commenters stated that EPA's assurances that few projects at existing EGUs implemented for 

the purpose of complying with the Proposed Rule will trigger preconstruction NSR permitting 

requirements ring hollow, as those assurances are reminiscent of EPA's earlier statements 

regarding maintenance projects, and pollution control projects. The commenters stated that with 

EPA's history of pollution control technology exclusion from major NSR for environmentally 

beneficial projects, EPA cannot expect any facility to trust that EPA would craft a legally 

supportable exclusion that would be upheld by the Court, and that EPA would not enforce 

against a facility relying on such an exclusion, when a Court later rules against that exclusion. 

The commenters stated that EPA's request for comments regarding the appropriateness of a 

categorical exemption from NSR for projects undertaken to comply with the proposed rule is 

disingenuous. The commenters stated that it is telling that this, a legal issue plainly turning on 

the clarity of statutory language and on congressional intent, is nowhere raised in the legal 

memorandum prepared by EPA, the express purpose of which is to provide background for the 

legal issues discussed in the preamble for the proposed rule. The commenters stated that as EPA 

is well aware, policy-driven exemptions such as this are contrary to the broad statutory language 

governing applicability of the NSR program to modifications at existing EGUs, and efforts to 

provide these exemptions have been consistently rejected by the courts.

Commenters stated that EPA's proposed guidelines do not adequately address what 

circumstances would trigger NSR with regard to HRI measures; therefore, EPA fails to consider 

relevant, substantive and costly additional requirements that may accompany implementation of 

the proposed BSER. Referring to a table of NSR enforcement cases over HRI measures, the 

commenters stated there has historically been much confusion as to whether and what efficiency 

projects and practices trigger NSR. The commenters stated that a failure to provide sufficient 

information as to whether and what HRI activities will trigger NSR and how those requirements 

will be handled poses a significant risk to generators in determining whether or not to invest in 

HRI and will put the states in a precarious position to require these measures in their state plans. 

Regarding EPA assurances that a state plan could ensure reduced generation and/ or emissions 

from EGUs pursuing HRI that would otherwise potentially trigger NSR, the commenters stated 

that this assumes that the HRI measures would be implemented at the same time or directly 

before application of reduced generation - that is unlikely to happen for a number of reasons: 

first, this leaves no room for the generator to recoup the HRI investment and the reduced 

generation will likely immediately impact the HRI projected; second, EPA's own application of 

BSER requires reductions associated with building block 1 and 2 to start simultaneously in 2020 

and be held constant thereafter, making it highly likely that any HRI measures undertaken will 

occur over time between 2017 and 2020 as will correlated re-dispatch and generation reductions 

required in the other aspects of BSER. The commenters stated that EPA also suggests that there 

could be a method of providing credit to sources for other actions to reduce emissions in order to 

show compliance, but does not provide further discussion of what that would entail. The 

commenters stated that the failure to provide guidance in this area puts states in a difficult 
23

position as they will be asked these same questions relating to NSR application by utilities when 

determining what measures will be included in the plan; states cannot include requirements for 

HRI measures without a clear understanding of what the respective permitting requirements and 

costs are. The commenters stated that EPA is seeking comment on whether, with adequate record 

support, the state plan could include a provision, based on underlying analysis, stating that an 

affected source that complies with its applicable standard would be treated as not increasing its 

emissions, and if so, whether such a provision would mean that, as a matter of law, the source's 

actions to comply with its standard would not subject the source to NSR. The commenters stated 

that given the history of the NSR enforcement initiative, the commenters stated that EPA is the 

best party to answer that question and they recommend that EPA provide clear legal and 

regulatory guidance as to the consequences of pursuing HRI measures and, taking into 

consideration those consequences, including cost, modify the proposed BSER in building block 1 

accordingly.

Commenters stated that owners of coal-fired plants may refrain from making improvements 

based on the financial risks associated with potentially triggering NSR and are a potential 

impediment which should be recognized in the rule's calculations. The commenters stated that a 

July 2009 the NETL workshop concluded that the largest barriers to heat rate improvement 

projects are the NSR provisions and the lack of economic incentives exacerbated by the fuel 

adjustment clauses in utilities electrical rates permitting them to pass-through changes 

(increases) in fuel costs directly to consumers and that these conclusions are supported by a 

National Coal Council report. The commenters stated that the finances of power generating 

companies require that any large expenditure be justified, create a return on investment, or both. 

The commenters stated that some heat rate improvement modifications and actions are costly and 

require a long period of operation to realize a return on investment; thus some of these 

modifications may not be economically attractive for smaller and/or older units with a few or 

unknown years of remaining projected lifetime.

Commenters stated that even if California law were changed such that they could invest in 

efficiency upgrades at these facilities, such investments very well could trigger the EPA's NSR 

permitting requirements, which would significantly raise the cost and uncertainty of 

implementing these efficiency improvements; these additional costs should be included in the 

evaluation of whether the identified heat rate improvements are truly adequately demonstrated in 

light of future costs and other barriers.

Commenters stated that although EPA does not foresee many circumstances where projects that 

are required to achieve heat rate improvements at coal power plants trigger NSR, past experience 

demonstrates that coal-fired EGUs may face lawsuits from citizen groups, states or even EPA if 

they fail to obtain NSR permits prior to making efficiency improvements. Commenters stated 

even when citizen suits lack merit, they often delay the implementation of efficiency 

improvement projects, take several years to litigate, are very expensive, and drain scarce 

resources of the parties and courts. Commenters stated that they have refrained from undertaking 

heat rate efficiency improvements due to the uncertainty of triggering NSR. The commenters 

stated that EPA should include in the final rule an explicit NSR exemption for heat rate 

efficiency improvements made at EGUs that are undertaken specifically to comply with the rule.
24

Commenters stated that the EPA acknowledges and quickly dismisses the potential NSR 

implications associated with the heat rate improvements required by Building Block 1. The 

commenters stated that the projects that EPA contemplates for heat rate improvements from the 

S&L Report and EPA's GHG Abatement TSD include upgrades to the following components 

that could improve heat rate: turbines, air heaters, boilers, forced draft and induced draft fans, 

condensate pumps, economizers, sootblowers, condensers, pulverizers, ash handling systems, 

feedwater heaters, boiler feed pumps, flue gas conditioning systems, neural network optimization 

systems, selective catalytic reduction systems, system controls, and electrostatic precipitators. 

The commenters stated that EPA and citizens have brought NSR enforcement actions against 

utilities for undertaking these very same types of projects (over 400 efficiency improvement 

projects upgrading these types of components since 1999 and over 600 other projects that consist 

of like-kind replacement of worn equipment, which EPA identifies as important to maintaining 

and improving the efficiency of coal-fired EGUs in the GHG Abatement Measures TSD.)

Commenters cited clarifications from Sargent & Lundy regarding their 2009 study. The 

commenters stated that one of the clarifications was that many of the options for HRI listed in 

the 2009 S&L Report have triggered New Source Review actions by EPA and others. 

Commenters stated that EPA identifies several heat rate improvement methods but ignores the 

fact that several of these methods have been identified as NSR violations in enforcement cases 

brought by EPA, states, and citizen groups. The commenters stated that in light of EPA's 

projection that one-fifth of the existing coal-fired generators will retire by 2020, it is likely that 

many of the remaining units will be projected to operate at higher capacity factors and have 

higher annual emissions. The commenters stated that EPA's statement that the state permitting 

authority may simply project lower future emission rates as a result of the CPP is, at best, 

disingenuous. 

Commenters stated that EPA has contradicted itself on whether heat rate improvement projects 

would be expected to increase emissions and, thus, trigger NSR and it is untenable for EPA to 

conclude that heat rate improvement projects do not increase emissions and later enforce against 

EGUs by claiming that the EGU should have projected that such heat rate projects would 

increase emissions and trigger NSR. The commenters recommended that EPA issue new NSR 

guidance that heat rate improvement projects are not the type of projects that should trigger NSR 

requirements. 

Commenters stated that of all the equipment upgrades identified that could provide total heat 

improvement, all but one has been targeted in NSR enforcement actions. The commenters stated 

that, although EPA expects few instances of where an NSR permit would be required, these 

views are not shared by EPA's enforcement arm, as is evident from the Detroit Edison 

determination and the hundreds of projects targeted in the enforcement initiative since then. 

Based on the history of EPA's NSR enforcement initiative, EPA's assurance that there will be 

few instances in which building block 1 projects would trigger NSR is not supported by the 

preponderance of past actions by the agency. The commenters stated that citizen plaintiffs have 

been just as active as EPA in litigating NSR suits over the past 15 years. The commenters stated 

that this is an artifact of EPA's Proposal that adds considerable risk and expense and EPA's 

failure to account for the potential cost of NSR - and NSR uncertainty - for building block 1 

projects is arbitrary and capricious. The commenters stated that as a result, utilities implementing 
25

building block 1 that do not project an increase in emissions as a result of an equipment upgrade 

will face the ongoing threat of NSR litigation years after their projects. 

Commenters recommended that legal impediments to heat rate efficiency improvements in the 

form of NSR standards, and any others, should be removed and that EPA should create 

incentives for EGU operators by specifically exempting heat rate efficiency improvement 

projects from NSR.

Commenters stated that a clear statement in the final guidelines that any upgrades necessary to 

achieve efficiency improvements at existing coal-based units via HRI projects do not trigger 

NSR would encourage, rather than discourage, efforts to cost effectively reduce emissions at the 

unit level by removing the threat of protracted and potentially unnecessary NSR litigation.

Commenters stated that the final rule should establish an NSR accounting methodology to allow 

for HRI projects to be completed without triggering NSR requirements. The commenters stated 

that the 10 major (over 500 MW) coal-fired power units in Georgia not currently slated for 

shutdown are all considered major PSD sources for multiple pollutants and that, for those plants, 

ensuring that the net emission increases from a given project are not considered significant under 

NSR is a common way of avoiding a protracted NSR review. The commenters stated that plants 

often rely on an NSR applicability test called netting, where a facility will account for all 

creditable emissions increases and decreases over a 5-year contemporaneous period to determine 

if indeed the changes associated with a project are considered "significant" under NSR. The 

commenters stated that NSR avoidance is made enforceable by limiting a units operation or 

utilization so that the net emission increases never exceed significant emission rates that would 

trigger NSR review. The commenters stated that limiting the operation of updated units can be 

detrimental to efficiency if capacity factors fall below levels recommended to optimize unit heat 

rate efficiency. The commenters recommended that because NSR rules will restrict large HRI 

projects required under Building Block 1, clear NSR avoidance strategies and options should be 

laid out for coal-fired units attempting to comply with a 111(d) plan.

Commenters stated that EPA has taken NSR enforcement actions in the past and continues to 

issue Notices of Violation for some of the very same actions assumed in Building Block 1 to 

improve coal unit efficiency. The commenters stated that it takes time to get an NSR permit and 

install emission controls but EPA has not allowed enough time in the compliance schedule for 

this process and has not included in its analysis the constraints on utilities that result due to NSR 

issues. The commenters stated that EPA should provide a specific NSR exemption for efficiency 

improvement projects, or at a minimum include in its analysis the negative impacts and costs of 

NSR issues on reasonably achievable efficiency improvement actions.

Commenters stated that EPA has failed to address significant NSR issues presented by the 

Proposed Guidelines. The commenters listed the following NSR issues: The projects 

contemplated in Building Block 1 to improve heat rates at EGUs have been targeted by EPA and 

others as triggering NSR; EPA asserts incorrectly that there will be few instances when an NSR 

permit will be required (Although the commenters agree that measures taken to implement 

Building Block 1 do not trigger the Act's NSR requirements, Attachments A and B to their 

comments demonstrate that such projects have been challenged as NSR violations by EPA's 

enforcement arm, by states, and by environmental organizations.); and EPA should eliminate the 
26

threat of protracted NSR litigation and provide a clear statement that any upgrades necessary to 

implement Building Block 1 of EPA's Clean Power Plan do not trigger NSR.

Commenters stated that they have analyzed EPA notices of violation, citizen notices of intent to 

sue, and complaints available in the public record since EPA began its NSR enforcement 

initiative in 1999. The commenters stated that based on that analysis, they have identified over 

400 efficiency improvement projects targeted by the EPA or citizens since 1999 as allegedly 

violating NSR. The commenters provided a list of these projects in an attachment. Commenters 

stated the listed projects are the same types of projects identified in the 2009 Sargent & Lundy 

report and GHG Abatement Measures TSD. Commenters stated that during that same period, 

EPA and citizens have targeted almost 600 other projects as violating NSR and are provided in 

an attachment and, like the projects cited by Sargent & Lundy and EPA, are also important to 

maintaining and improving the efficiency of coal-fired generating units. The commenters stated 

that these projects consist of "like-kind replacement of worn existing components," which EPA 

also identifies as essential to maintaining and improving the efficiency of coal-fired generating 

units (see GHG Abatement Measures TSD at 2-16).

Commenters stated that the upgrade projects identified in 2009 Sargent & Lundy report and the 

GHG Abatement Measures TSD have been targeted by EPA and citizen plaintiffs as triggering 

the NSR provisions of the CAA. The commenters stated that EPA issued an applicability 

determination for a turbine upgrade at Detroit Edison's Monroe Plant in 1999 citing that the 

efficiency improvement was a major factor weighing against a finding that the project was 

routine maintenance, repair or replacement and thus excluded from NSR permitting 

requirements. The commenters stated that they agree with EPA that very few efficiency projects, 

if any, should trigger NSR, as the ones listed in attachments to their comments, constitute routine 

repair and replacement of deteriorated components and do not trigger NSR. The commenters

stated that, moreover, efficiency improvements of 1 to 6 percent are too small to significantly 

and identifiably change the dispatch of a unit in a large system, and in any event, such changes 

are minute with respect to the fluctuations in all other factors that can affect dispatch of a unit at 

any particular year. The commenters stated that these views are not shared by EPA's enforcement 

arm, as is evident from the Detroit Edison Determination and the hundreds of projects targeted in 

the enforcement initiative since then. The commenters stated that the threat of litigation is 

compounded by the fact EPA maintains it can bring a suit alleging an NSR violation years after a 

project is undertaken and regardless of whether emissions in fact increase after the project. The 

commenters stated that EPA's own recognition that the NSR program has impeded or resulted in 

the cancellation of projects which would improve efficiency confirms the need for regulatory 

certainty for utilities implementing Building Block 1. The commenters stated that instead, EPA 

suggested that the states can provide the necessary relief as a part of their state plans under 

section 111(d) either by adjusting statewide demand side measures and renewable energy 

requirements so as to counterbalance the supposed impact of unit-specific efficiency 

improvements on unit utilization or imposing synthetic minor limits on all coal-fired sources. 

Commenters stated imposing such synthetic minor limits across the board would, for example, 

prevent a state plan from relying on the shutdown of smaller, less efficient units and increased 

utilization of larger, more efficient units. The commenters stated that, in sum, at least Building 

Block 1 of EPA's Proposed Guidelines are based on measures that EPA's enforcement arm has 

declared illegal, as EPA has at least implicitly acknowledged. Because EPA's justification of the 

state emission goals relies on the ability of sources to implement efficiency improvement 
27

measures, and because EPA has failed to propose any credible regulatory provisions to otherwise 

address this issue, EPA has failed to demonstrate the achievability of its goals as required by 

section 111. The commenters stated that EPA's failure to account for the potential cost of NSR, 

and NSR uncertainty, for Building Block 1 projects in the Proposed Guidelines is arbitrary and 

capricious.

Commenters stated that EPA and citizen plaintiffs have targeted efficiency-improving measures 

like steam turbine upgrades in NSR enforcement suits alleging that such measures constitute 

major modifications triggering strict permitting requirements and to the extent that these groups 

can successfully argue that NSR requirements apply to Building Block 1 measures, NSR review 

could result in coal-fired EGUs having to install even more stringent emission controls, further 

increasing parasitic load. The commenters stated that EGU owners typically perform the kinds of 

upgrades discussed in the 2009 Sargent & Lundy report in conjunction with emission control 

projects in order to minimize the resulting efficiency losses, but the heat rate improvements are 

generally outweighed by the new auxiliary load. The commenters stated that affected EGUs will 

be forced to overcome the energy penalties associated with these controls, and then achieve an 

additional 4 to 6 percent improvement in heat rate on average in order to comply with the 

Proposed Guidelines.

Commenters stated that EPA's solution to the NSR problem appears to be that states should 

require utilities to make efficiency upgrades, and then require the plant owners to accept 

operating constraints that limit the ability of the utility to deploy the improved power plant. The 

commenters stated that this is not a practical solution to a recognized barrier to implementing the 

measures on which EPA based building block 1.

Commenters stated while not motivated by the same competitive pressures that exist in ERCOT, 

electric utilities in the non-ERCOT regions of Texas have also likely made most or many of the 

heat rate efficiency improvements that can reasonably be made without triggering the NSR 

provisions of the CAA.

Commenters stated that EPA acknowledges that many of the heat rate improvement projects 

involve equipment replacements or upgrades that have been targeted in suits filed by EPA and 

citizen groups under the NSR provisions of the CAA. The commenters stated that these suits 

claim that by improving unit efficiency, operators will run units for more hours during the year, 

increasing annual emissions above the thresholds that trigger an NSR permitting obligation. The 

commenters stated that these suits have resulted in widely differing opinions about what 

remedies are barred by the statute of limitations, how to interpret the exclusion for routine 

maintenance, repair, and replacement, and how to calculate emissions before and after an 

efficiency improvement project. The commenters stated that EPA offers no relief from NSR 

enforcement for operators who seek to comply with the Clean Power Plan by improving unit 

efficiency, and without such relief, many operators will be reluctant to engage in more expensive 

efficiency improvements like turbine replacements and other equipment upgrades that offer the 

most cost-effective improvements.

Commenters stated that over 400 specific efficiency improvement projects of the type described 

in the S&L report referenced in the proposed rule have been identified based on a review of 

Notices of Violation issued by the EPA, and complaints filed by the Department of Justice or 
28

environmental advocacy groups alleging violations of the NSR permitting program for failing to 

obtain a permit prior to undertaking equipment replacement or other heat rate improvement 

projects at EGUs. The commenters stated that those NOVs and complaints also identify another 

600 equipment replacement or repair projects that involve other components not specifically 

identified in the S&L report or EPA's GHG Abatement Measures Technical Support Document; 

these allegations are not an indication that a violation actually occurred, but are an indication of 

the chilling effect that EPA's enforcement initiative will have on the willingness of EGU 

operators to pursue these or other heat rate improvement opportunities identified in EPA's GHG 

Abatement Measures Technical Support Document in the absence of clarification from EPA that 

these activities will not trigger NSR permitting requirements.

Commenters stated that the first element of an NSR-triggering change mentioned by EPA in the 

preamble, a physical or operational change, is a phrase in the statutory definition of modification 

in section 111(a)(4), incorporated by reference in sections 169(2)(C) and 171(4). The 

commenters stated that EPA has interpreted that phrase in notice-and-comment rulemaking, 

going back to the 1970s, to have some common-sense exclusions; it is well within EPA's 

discretion to add to its existing exclusions from the meaning of modification and/or physical 

change or change in the method of operation those efficiency improvements an affected EGU 

makes in furtherance of a section 111(d) plan pursuant to EPA's Clean Power Plan. The 

commenters stated that if EPA does not eliminate the risk of NSR applicability for building 

block 1 heat rate improvements, then the agency needs to reevaluate its proposed BSER and 

repropose appropriately revised emission guidelines.

Commenters stated that in the past that modifications similar to those that may be required to 

improve a unit's heat rate have resulted in the issuance of NSR NOV. The commenters stated that 

they would like to work with EPA to obtain the legislative changes to the NSR rule to make heat 

rate improvements more viable as, historically, NSR has been such a concern for the electric 

utility industry that sources have been reluctant to invest in heat rate improvements for fear of 

reopening their permit to BACT analyses on the criteria pollutants for which they already have 

permits. The commenters stated that NSR provisions have been an unintended impediment to 

heat rate improvements in the coal fired sector; for this reason, it is difficult to assess what 

overall heat rate improvement is actually possible.

Commenters stated that a major modification, under the CAA, excludes routine maintenance, 

repair and replacement. The commenters stated that NSR court cases have been inconsistent 

defining routine maintenance, however, some of EPA's NSR NOV have identified items such as 

economizer replacement, steam turbine upgrades, feedwater heater replacements and other 

activities as non-routine maintenance. The commenters stated that some court case decisions 

have agreed with EPA on the non-routine activities however some courts case decisions have 

not; some of these modifications could be necessary to improve a plant's heat rate. 

Commenters stated that the proposed regulation goes on to say that if the emissions associated 

with unit's changes exceeds the thresholds in the NSR regulations, the changes would trigger 

NSR. The commenters stated that they have looked at a typical 500 MW bituminous coal fired 

unit with typical CO emissions ranging from 0 to 50 ppm of CO. The commenters stated that one

approach to improving heat rate would be to lower excess air if possible; but when the excess air 

is lowered one problem could be an increase in CO emission. The commenters stated that 
29

assuming a 10 ppm increase in CO this typical 500 MW unit having a heat rate of 10,300 

Btu/kWh and a 70 percent capacity factor would increase the CO emissions by 131 tons per year 

thereby triggering NSR.

Commenters stated that the NSR risk cannot be defined at this time especially as it relates to 

operating time. The commenters stated that if a utility makes heat rate improvements or changes 

fuels (co-burning) and emissions of NSR pollutants are reduced and does not increase operating 

capacity then there should be no NSR implications; however, if the plant becomes more efficient 

it could change its position on the dispatch curve and there could be a NSR violation. 

Commenters stated that despite assurances from EPA that NSR was unlikely to be an issue, as of 

the end of FY2013, EPA has 862 coal units under investigation for NSR violations and EPA is 

not the sole entity challenging utilities. The commenters stated that EPA has tried multiple times 

to clarify some of the unanswered questions regarding NSR; however, EPA's clarifications have 

been struck down by various courts or never finalized. The commenters provided two examples 

(WEPCo and Duke Energy) of court cases that underlie current NSR policy interpretations.

Commenters stated that they would like the EPA to examine the impact of the proposed average 

coal-fired plant heat rate improvement through (a) the actual pounds per hour increase in 

emission(s) of specific pollutants and (b) the net increase in emissions as a result of unit physical 

or operational changes. The commenters stated that regarding item (a), increase of specific 

pollutant following physical or operational modifications to the unit, they do not anticipate any 

obvious significant increases in typically permitted emissions for coal fired power plants except 

for modifications to the combustion systems; however, certain combustion modifications to 

improve heat rate could increase CO emissions (e.g., reduction in operating excess air) beyond 

the 100 tons / year significance level assuming no increase in capacity factor. The commenters

stated that regarding item (b), net increase in tons/year of emissions, they see modifications that 

although they do not increase individual pollutant levels, could result in an increase in operating 

hours and hence a net tons/year increase of pollutants. The commenters stated that Block 

Andrews of Burns & McDonnell has compiled a summary of historical NSR violations and then 

compared this list with the heat rate improvements as presented in the Sargent and Lundy NETL 

reports used by EPA in their evaluations; this summary clearly shows that clarification needs to 

be provided to give EGUs certainty before committing to heat rate upgrades.

Commenters stated that one example of a simple upgrade that can trigger an NSR action is if a 

500 MW plant upgraded their coal burners. The commenters stated that under the circumstances, 

an increase in CO emissions by as little as 10 ppm would exceed the 100 ton/year PSD limits; as 

a result, heat-rate improving activities might improve net output or dispatch or make the plant 

economically viable for a longer period of time. The commenters stated that even if EPA 

includes in its final rule means to mitigate this concern, it will not be determined until the 

conclusion of any ensuing litigation whether EPA, in fact, has the authority to do so.

Commenters stated that once triggered, the NSR permitting process can have many negative 

consequences for a source, including construction delays; major NSR permit reviews can delay 

projects 1 to 2 years beyond the much-shorter minor NSR permitting process. The commenters

stated that because NSR requires case-by-case review, there is often significant uncertainty 

regarding the likely outcomes, including whether the project will be approved, and what new 
30

permit conditions may be attached, including their potential costs. The commenters stated that 

EPA's existing network of regulatory requirements is also complex and constantly changing; 

often customers are faced with the problem of responding to new permit conditions from 

regulatory changes that occurred following the permit application, creating a difficult do-loop for 

permit seekers. The commenters stated that many of their customers express a reluctance to go 

through the NSR process due to the vagueness of the program provisions and the extensive case 

law history around the program leading customers to install like or in-kind replacement parts 

instead of technology improvements. The commenters stated that finalizing a 111(d) rule without 

including regulatory changes that address NSR applicability would significantly undermine the 

ability of EGUs to comply the proposed guidelines.

Commenters stated that the CPP would require a major shift for coal generating stations (CGS) 

but it did not provide a clear permitting path to make modifications to existing units to 

accommodate changes in the operations. The commenters stated that the time required for 

permitting modifications to existing CGS and subsequent challenges to permits and nongovernmental organizations litigation creates regulatory uncertainty and discourages changes to 

meet the requirements of the proposed rule. The commenters recommended that the final CPP 

should include a clear and defined path for permitting projects that improve CGS heat rate and 

allow for improved cycling capabilities to accommodate renewable energy generation.

Comment 4: NSR effects on cost savings of HRI

Response 4: Some commenters expressed concern about EPA underestimating the overall costs 

of the proposed rule and the potential impact the cost associated with NSR permitting would 

have on the feasibility of the application of Building Block 1 (heat rate improvements) in the 

BSER. The EPA acknowledges that the costs associated with obtaining a NSR permit were not 

included in the cost analysis included with the proposal. As discussed in the preamble to the 

proposed emissions guidelines, our analysis shows that only a small percentage of affected EGUs 

are expected to potentially trigger the need to apply for a NSR permit as a result of changes made 

to comply with requirements resulting from 111(d) state plans and that result in emissions 

increases large enough to trigger NSR but this analysis is just one example of a compliance path 

that is not required to be followed in exactly the same way by any particular state. As a result, 

while the EPA analysis shows few instances where triggering NSR is a possibility, it is not clear 

whether any sources will actually trigger NSR since they will be subject to state plan 

requirements that can include flexibilities and specifically designed requirement to limit or 

completely avoid any sources from triggering these requirements. In addition, the modeling 

show that of those that could potentially trigger the need to obtain an NSR permit, only a very 

few of those would require additional controls on their emissions of NOx or SO2. As also 

discussed at length in the proposed rule preamble, states have ample flexibility in designing their 

compliance plans under the emissions guidelines in a way that it minimized or completely avoids

affected EGUs from triggering NSR. As a result of this great flexibility coupled with the low 

number of affected sources expected to potentially trigger NSR, the EPA believes that the overall 

costs associated with NSR triggers as a result of this rule are negligible. Nonetheless, the EPA 

has included such costs in its analysis in support of the final emissions guidelines. 
31

The following are summaries of the specific public comments under this comment:

Commenters stated that if modifications are likely to trigger NSR, the additional cost of 

compliance should be included in determining whether a unit can go forward with 

improvements; for example, if viable heat rate improvements for a unit require the types of 

physical or operational modifications that historically trip new source review entailing 

significant additional expenditures, that should be a paramount factor in concluding that the 

implementation of the heat rate improvements is not feasible or is not cost-effective based on 

costs associated with new source review compliance. 

Commenters stated that if modifications are likely to trigger NSR, the additional cost of 

compliance should be included in determining whether heat rate improvements are feasible or 

cost effective. The commenters stated that complying with NSR entails significant additional 

expenditures and project delays and legal costs associated with NSR on a plant specific basis can 

be significant. EPA's failure to account for potential cost of complying with NSR is arbitrary and 

capricious. 

Commenters estimated that the remaining coal-fired EGUs would be forced to operate at 

capacity factors less than 20 percent to achieve the proposed CO2 reduction goal for 

Pennsylvania. The commenters stated that it is unlikely that the owners or operators of an EGU 

limited to such a low opportunity to operate could recoup the cost for required heat rate 

improvements in addition to the other normal operational costs; NSR in this situation creates 

another issue for these EGUs. The commenters stated that in the event one of these EGUs retires, 

because of the establishment of the emissions baseline in the NSR applicability analysis, the 

remaining EGU s would be unable to increase their capacity factor to assume the generating 

opportunity that would be provided by that retirement. The commenters stated that if the 

increased opportunity were due to an increase in demand, an increase in capacity factor would be 

possible; however, Building Block 4 is designed to ultimately reduce the overall demand for 

electricity and, consequently, the proposed Clean Power Plan would cause the expeditious 

retirement of existing coal-fired EGUs through the imposition of the existing NSR program. 

Commenters stated that EPA overestimated the cost savings of heat rate improvement. The 

commenters stated that in its cost estimate for HRI, it does not appear that EPA considered the 

potential costs related to NSR as units engaging in HRI projects could trigger NSR's 

preconstruction permitting requirements, which likely would require installation of additional 

pollution controls. The commenters stated that projects that improve thermal efficiency will 

incur additional costs related to permitting delays and control installations, which may 

completely undermine EPA's assertions that the costs of HRI are reasonable. Commenters stated

nowhere in the cost analysis does EPA recognize the non-permanent nature of HRI, which may 

begin to deteriorate almost immediately, requiring ongoing O&M to maintain the improved heat 

rate; accordingly, EPA has not adequately supported its claims that reductions associated with 

HRI measures can be achieved at reasonable cost.

Commenters stated that the New Source Review ("NSR") is a deterrent to making investments 

that reduce heat rate.
32

Comment 5: To avoid NSR, some units have permits that limit their generation; not enough time 

Response 5: The EPA recognizes that it is possible some NGCC units have permit limits that in 

some cases would need to be revised in order for those units to be able to increase their 

operation. However, commenters have not provided information that there are a substantial 

number of units with permit limits that need to be changed. In addition, as described in the 

preamble, states are not required to follow the application of BSER as EPA did to develop state 

goals and have great flexibility in designing their state plans to take into account such 

circumstances. For example, states could design their plans in a way the emissions reductions 

are first realized by units that do not contain such permit limits while phasing in the remainder of 

the NGCC fleet as the permit modification are made for those units needing it. In addition, states 

have the ability to include EE/RE and demand side energy efficiency programs as part of their 

state plans that would reduce the amount of generation needed resulting in emissions reductions 

and potentially lower need for increased generation from units that have permit limits such as 

those cited by the commenters. Finally, in response to numerous comments, the EPA has 

extended the interim performance rate milestone by two years, to 2022. We believe this provides 

sufficient time for those sources that would need to undergo permit modifications either due to 

NSR or to modify any other permit terms or conditions, including those that were previously 

taken to avoid NSR, to obtain the necessary permit. 

The following are summaries of the specific public comments under this comment:

Commenters stated that some existing NGCC units currently have permits that limit their 

generation, which were taken to avoid NSR permitting requirements or, in some cases, for 

economic reasons. The commenters stated that a state will not be able to rely on such units for 

redispatch purposes under Building Block 2 unless the units' permits are revised, which could 

trigger NSR requirements, including the installation of BACT, or technology to meet the LAER 

and emissions offsets. 

Commenters stated that it is highly unlikely that the permit revision process, locating of any 

required emissions offsets, and the design and installation of control technology could be 

accomplished by 2020. The commenters stated that, in many cases, it takes over a year to obtain 

a NSR permit, and a permit application could not even be submitted until after all necessary 

analyses have been completed, including air quality analyses and control technology evaluations. 

The commenters stated that the source could not begin construction on required controls until the 

final permit was issued, and could be delayed even further if the permit was challenged. 

Commenters stated it would be difficult to obtain any required NSR permits in the limited 

amount of time between expected approval of the state plan and 2020. The commenters stated 

that, perhaps more importantly, the owner of a "synthetic minor" NGCC may not want to lift the 

permit limits if doing so would trigger PSD/NSR requirements or lead to a NAAQS violation 

precipitating installation of expensive controls.

Comment 6: Synthetic limitations not a viable option for avoiding NSR
33

Response 6: The final emissions guidelines don’t require any affected EGU’s to obtain synthetic 

minor limits to avoid NSR. The proposed guidelines cited the use of synthetic minor limits as a 

potential technique that states and affected sources could use as a way to possible avoid 

triggering NSR permitting where a source was required by a state compliance plan to make 

certain upgrades that could result in emissions increases large enough to trigger NSR. As 

discussed in the preamble to the proposed and final guidelines, states have great flexibility in 

designing their compliance plans and are expected to work closely with their affected EGUs in 

doing so. Where a state and its affected EGUs believe that including synthetic minor limits on a 

particular unit to avoid trigger NSR or some other state requirement, it should be able to do so 

under the final guidelines. Therefore, while not required by this rule, we continue to believe that 

synthetic limitations are an option to avoid triggering NSR requirements for those units that 

make physical changes that could potentially result in emissions increases that would trigger 

NSR. The modeling conducted for this rule does not predict a large percentage of sources 

making heat rate improvements and also increasing emissions of NOx and/or SO2 in amounts 

that could trigger NSR. Therefore we believe that the combination of the flexibility inherent in 

the rule, and the ability to take synthetic minor limitations at individual facilities, if desired, 

mitigate the possible impacts of NSR.

The following are summaries of the specific public comments under this comment:

Commenters stated that synthetic limitations are not a viable option for avoiding NSR because: 

first, it likely would delay the installation of the upgrades due to the permitting process; and 

second, it would then prevent the EGU from exceeding its baseline even where emissions 

increases would meet the demand growth exclusion in 40 C.F.R. section 52.21(b)(41)(i)(c). The 

commenters stated that the EPA suggests that fossil fuel-fired units can avoid triggering NSR by 

limiting their utilization such that there is no increase in annual emissions; however, coal-fired 

EGUs that are in operation after 2020 may very well be facing demand growth due to the limited 

coal-fired generation expected to remain after implementation of this rule and other 

requirements, such as MATS and regional haze, regardless of whether or not they undertake heat 

rate improvements. The commenters stated that accepting synthetic minor limits simply would 

not be a viable option for such units and could force re-evaluation of whether a heat rate 

improvement project is economical or even of the EGU's continued viability.

Comment 7: Support approach that gives states flexibility to demonstrate compliance without 

triggering NSR review 

Response 7: The EPA continues to support an approach that provides states with ample 

flexibility to design compliance plans, including the use of certain strategies and requirements 

that limit the number of affected EGUs that would trigger NSR as a result of complying with the 

111(d) state plan. The commenters seem to suggest a state-wide netting program that looks at 

overall state-wide emissions reductions that are then used by affected EGUs to net out of NSR 

depending on their generation capacity. The triggering of NSR is a case-by-case decision based 

on the facts of the particular action and emissions increases and decreases at the source. The idea 

of a state-wide netting program is not allowed as a way to avoid triggering NSR. The final 

emissions guidelines do include provisions for trading of emissions reduction credits (ERCs) and 
34

allowances as described in the final preamble and rule language. These ERCs and allowances 

can be used by states as a way of achieving the GHG reductions needed to meet the state goals of 

the final guidelines but are not credits toward NSR netting calculations. 

The commenters request clarification on why EPA expects that improvements in efficiency at 

affected EGUs would not frequently trigger NSR permitting. The modeling conducted in support 

of this rulemaking does not predict that a large percentage of EGUs that make heat rate 

improvements will also increase their emissions of NOx and SO2 sufficient to trigger NSR. 

Only a few of the sources projected to trigger NSR are expected lack post combustion control, 

and be required to install it as a result of triggering NSR. As discussed in the preamble, states 

have great flexibility in designing their compliance plans and have the ability to work with their 

affected EGUs to ensure that any EGU that may trigger NSR as a result of the state planning 

process has the opportunity to develop permit conditions that limit the number of sources that 

would trigger NSR as a result of the state plan. In addition to permit conditions, states have the 

ability to include EE/RE and demand-side energy efficiency programs that have the effect of 

reducing the amount of generation these affected entities would need to produce and could result 

in limiting emissions increases due to increases in dispatch. While we recognize that there are 

some circumstances under which affected EGUs may trigger NSR as a result of 111(d) state plan 

requirements stemming from this rule, we continue to believe, and our modeling supports, that 

these will be infrequent in nature.

The following are summaries of the specific public comments under this comment:

Commenters stated that as a means of demonstrating compliance with NSR, they support an 

approach that allows states the flexibility to: estimate the amount of generation from coal-fired 

units that can be avoided statewide through the deployment of section 111(d) plan measures 

(such as heat rate improvements, demand-side energy efficiency, and expanded low-carbon and 

zero-carbon generation); calculate the statewide emission reductions achieved from the 

displacement of coal-fired generation; allocate emissions reductions to each coal-fired unit based 

on their generation capacity; and make emissions reductions creditable for plants that wish to 

engage in a netting analysis to show that net emission increases will not trigger NSR review. The 

commenters recommended that EPA finalize this approach or provide an alternative approach 

that clearly allows HRI projects to be completed without triggering NSR requirements.

Commenters stated that EPA's expectation is that improvements in EGU efficiency will 

infrequently trigger NSR and that states have the flexibility to write their state implementation 

plans in such a way that affected EGUs would not trigger NSR. The commenters stated that they 

seek clarification from EPA on why EPA expects these situations to be infrequent, given that 

increases in dispatch may lead to increases in emissions that may come close to the emission 

limits already established in the EGU's existing NSR permits.

Comment 8: Predetermine activities or practices that would trigger NSR permitting 

Response 8: The EPA is not, as the commenters have suggested, attempting to pre-determine 

whether certain activities or business practices would trigger NSR. Rather, in the proposal we 

took comment on the possibility of states using the flexibility in designing their 111(d) 
35

implementation plans in a way that would consider the possible situation where an affected 

source would trigger NSR as a result of the state plan requirements and whether it would be 

possible for that state to include provisions in such plan to minimize or eliminate those instances. 

We continue to believe that it is possible for states and affected EGUs to work together during 

the plan development phase to take into consideration how the state measures being considered 

would affect the EGUs subject to the plan requirements and develop strategies, including specific 

permit terms and conditions, the use of EE/RE programs to displace some expected generation

increases at the EGU in question, etc., to limit the number of sources triggering NSR as a result 

of the state 111(d) plan. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's proposal to predetermine whether certain activities or business 

practices would trigger NSR permitting is not feasible for the following reasons: by defining and 

documenting the scope of an activity or project to such a degree that NSR applicability is 

completely defined, much of the flexibility touted by this option is removed; geographic 

considerations (such as NAAQS attainment status) may change over time and also be a factor in 

such NSR determinations; site specific considerations may preclude usage or require adjustments 

to a list of pre-selected activities or business practices; the effort required to predetermine NSR 

applicability would outweigh the very small number of situations anticipated to be able to take 

advantage of this concept; and an attempt to predefine NSR would also be subject to attack, on 

the basis that EPA is attempting to evade the requirements of the CAA by rewriting them in a 

regulation.

Comment 9: Do not exempt sources from NSR

Response 9: The EPA is not proposing to exempt sources from NSR. Rather, we don’t expect 

that heat rate improvements made at coal-fired power plants, which result in less fuel burned, 

and lower emissions, would be coupled with an increase in demand from those plants that is 

large enough to exceed the NSR applicability thresholds. Where such changes do result in 

emissions increases large enough to trigger NSR, such sources would still be subject to the 

permitting requirements of the applicable pre-construction program. The overall effect of the 

Clean Power Plan is expected to be reduced demand from coal-fired generation. So, we do not 

expect that NSR will be widely triggered simply because the demand for generation from many 

of these plants is expected to be less in the future.

The following are summaries of the specific public comments under this comment:

Commenters objected to sources' efforts to comply with 111(d) guidelines being excused from 

NSR.

Commenters stated that actions taken by a facility to comply with its obligations under Section 

111(d) should not be excused from NSR stating that it is a fundamental and critical element of 

air pollution control strategies for greenhouse gases and criteria pollutants and would set a bad 

precedent to allow power plants to avoid NSR when complying with a state or regional program 
36

for 111(d). Commenters stated new equipment must continue to meet Best Available Control 

Technology and provide offsets when required to contribute to clean air goals. 

Commenters stated that their agency objects to an exemption from NSR requirements when 

EGU's are being modified to comply with the rule. NSR is a hallmark feature of the CAA and is 

one of the primary mechanisms through which public health is protected from the adverse effects 

of air pollution. The commenters recognized that modifications to existing EGUs may be 

necessary in order to, for example, increase operational efficiency. However, commenters stated

EPA should ensure that EGUs undergoing these modifications meet the requirement of BACT 

for all pollutants, not just for GHGs. Commenters stated many areas of the country continue to 

experience the worst effects of ozone pollution and ensuring the existing fleet of EGUs operate 

as cleanly as possible will help states with their attainment of air quality standards and ensure air 

quality is not further degraded.

Commenters, in response to comments made by Nevada DEP and others, stated that they do not 

support exempting modifications for heat rate improvements from new source review 

requirements because it is critical to look at the overall impacts of extending the life of any fossil 

fuel unit with major modifications compared to the value of instead bringing on new clean 

energy resources.

Comment 10: The EPA proposal is in conflict with new source performance standards and new 

source review 

Response 10: The commenters seem to be confused between the New Source Performance 

Standards (NSPS) under Section 111 of the Clean Air Act, and the New Source Review (NSR) 

permitting program under Section 110. The requirement to apply BACT is a component of the 

NSR program which is based on an analysis conducted on a case-by-case basis for each new 

construction or modification at existing major stationary sources and it applies across a wide 

range of industrial categories. The NSPS requirements apply on a source category basis, in this 

case fossil fuel-fired EGUs. Regarding the comment on the proposed emissions limit for new 

generation units and how it compares with the proposed rule’s emissions limits for existing units, 

the NSPS limits are develop through the application of the Best System of Emissions Reduction 

(BSER) on a source category basis. The BSER for new units is determined by analyzing the 

technologies available for the universe of affected entities, in this case new fossil fuel-fired 

EGUs and is independent of the BSER for existing units. As described in the proposed 

emissions guidelines for existing units under 111(d), the BSER for existing units is made up of a 

group of building blocks that include heat rate improvements at the source, changes in the order 

EGUs are dispatched, and a series of energy efficiency and renewable energy programs. The 

application of these building blocks is the basis for the existing source NSPS limit and is 

independent of the NSPS requirements for new sources. Finally, the commenters’ statement that 

sources subject to NSR cannot be regulated under section 111(d) because it only applies to 

existing sources and NSR applies to new sources is misplaced. NSR applies to both new 

construction and modifications at existing major stationary sources as previously described and 

is independent of requirements under section 111(d). As such, the EPA does not agree with the 

commenters that there is a conflict between 111(d) and NSR.
37

The following are summaries of the specific public comments under this comment:

Commenters stated that new generation units, or modifications to existing units, require 

compliance with BACT under the new source performance standards. The commenters stated 

that EPA's proposed emission limits for new generation units of 1,000-1,100 lbs CO2/MWh for 

fossil fuel-fired units (depending on heat input rating) are in excess of the proposed rule's 

emissions for existing units in more than half of all states. The commenters stated that this is 

beyond any reasonable approach to regulating existing sources and if an EGU is going to 

comply, it is assumed that existing sources must be modified in ways that will trigger new source 

standards. The commenters stated that 111(d), however, applies only to stationary sources other 

than new sources and is not available to regulate existing plants which are required to comply 

with new source review. The commenters stated that the EPA acknowledges that, as part of its 

111 (d) compliance plan, a state may impose requirements that require an affected EGU to 

undertake a physical or operational change to improve the unit's efficiency that results in an 

increase in the unit's dispatch and an increase in the unit's annual emissions. The commenters

stated that if the emissions increase associated with the unit's changes exceeds the thresholds in 

the NSR regulation, the change would trigger NSR. The commenters stated that 111(d) can't 

apply to new sources (modified sources are new sources), so the application of building blocks to 

existing units may well create improvements which would make an EGU subject to NSR; thus, 

EPA has created a conflict between 111(d) and NSR.

Commenters noted that the CPP proposes state emission rates for existing generation units below 

achievable rates for new NGCC units and stated that the proposed 111(d) rule should not 

establish state rates more stringent than the proposed 1,100 lbs/MWh in section 111(b) rule for 

new units. Commenters stated that it is more difficult and costly to improve heat rates and reduce 

emissions at existing units, and 111(d) was not intended to set rates below the NSPS. 

Commenters questioned how will simple cycle units, new NGCC and RICE be treated in state 

plans? 

Commenters noted that there has been increased reliance on simple cycle units within the 

Southwest Power Pool's integrated marketplace and at least one simple cycle unit in the 

commenter's state is in the process of being converted to NGCC. In addition, commenters added, 

their state is seeing the construction of several >100 MW electric generating facilities composed 

of multiple natural gas-fired RICE, which will be relied upon for both very fast startup times and 

low CO2 emission rates (<1,100 lbs/MW). Commenters asked the EPA to clarify how simple 

cycle units, new NGCC and RICE might be treated for compliance in a state plan. 

Commenters stated that new natural gas-fired power plants would, under the proposal, face an 

emissions limit of 1,000 or 1,100 lb CO2/MWh, depending on the size of the units. Commenters 

said that natural gas-fired power plants would not be required to operate using CCS as an 

emissions control, and industry estimates that nearly all existing natural gas power plants could 

meet the more stringent standard of 1,000 lb CO2/MWh. 

Comment 11: Current NSR guidance discourages natural gas co-firing projects 
38

Response 11: We agree with the commenters that co-firing coal units with natural gas is a 

potential approach for reducing emissions and can be included as part of a state’s compliance 

strategy and planning. Regarding inclusion of co-firing as part of goal setting, the EPA did not 

include co-firing in establishing state goals in the proposal and did not include co-firing in the 

application of BSER for establishing the sub-category standards of performance under the final 

emissions guidelines. The commenters cite to a Region III letter regarding the treatment of 

emissions increases at the Northampton Generating Company and the potential for the use of cofiring to trigger NSR as an example for why it would not be appropriate to consider co-firing in 

the goal setting. As the commenters appropriately point out, whether a particular project triggers 

NSR is a case-by-case determination that takes into consideration the specific circumstances 

surrounding the project, including whether emissions increases are related to the project in 

question and whether the increases are the result of “demand growth” among other factors. We 

encourage affected EGUs considering the use of co-firing or any other CO2 emissions reduction 

techniques to work closely with their permitting authorities to ensure all of the applicable 

regulatory requirements, including the possibility of needing an NSR permit, are fully considered 

and complied with.

The following are summaries of the specific public comments under this comment:

Commenters stated that they agree that natural gas co-firing is appropriate as a compliance 

option for coal-fired EGUs but objects to the consideration of co-firing in goal setting. The 

commenters stated that based on EPA's current guidance, co-firing cannot be undertaken at most 

coal-fired EGUs without triggering NSR. The commenters stated that under the NSR regulations, 

EGUs can compare baseline emissions to projected actual emissions to determine whether a 

project will result in a significant increase in emissions, and in calculating projected actual 

emissions, EGUs shall exclude any increase in emissions that (1) is unrelated to the project, and 

(2) could have been accommodated during the baseline period (this is commonly referred to as 

the demand growth exclusion). The commenters stated that in guidance regarding the 

Northampton Generating Company, EPA Region III made clear that both conditions are required 

before emissions increases can be excluded from the projection; for example, according to the 

Northampton Guidance, if a company proposed to switch fuels, it may have been able to 

accommodate the emissions from the new fuel during the baseline period but it nonetheless 

would not be able to exclude any projected emissions from use of the new fuel under the demand 

growth exclusion because the emissions would be related to the fuel switch. Northampton 

Guidance at 4-5. The commenters stated that, further, the Northampton Guidance indicates that 

all post-project emissions would be considered to result from the project and would have to be 

included in calculating the projected emissions even if the projected increase in utilization is due 

to additional coal-firing. The commenters stated that as a result, a coal-fired unit that proposes to 

co-fire natural gas would be unable to increase its coal-fired utilization and corresponding 

emissions over the baseline period without potentially triggering NSR, at least for NOx and 

particulate matter. The commenters stated that such a consequence will discourage companies 

from undertaking natural gas co-firing projects at their coal-fired units. The commenters stated 

that given the risk that co-firing will trigger NSR or require units undertaking such projects to 

limit their future utilization, it is not appropriate to consider co-firing in the computation of the 

emission rate goals. The commenters recommended that before considering this option, EPA 

should evaluate the costs associated with obtaining an NSR permit for co-firing, including the 

potential installation of hundreds of millions of dollars in controls for conventional pollutants.
39

Comment 12: Measures to avoid triggering NSR 

Response 12: The EPA agrees with the commenters that states cannot unilaterally create an 

exemption from NSR based on the standards of performance in the Clean Power Plan and we did 

not propose that they do so in this rule. Neither did the EPA propose to create an NSR 

exemption for projects undertaken to comply with the Clean Power Plan, either explicitly or by 

expanding the existing exemption for routine maintenance, repair and replacement. Commenters 

requested that we create such exemptions or make changes to the NSR rules to specifically 

exclude emissions increases related to the Clean Power Plan, however, we do not intend to 

finalize such exemptions.

The EPA does not agree with the commenters that source-specific limits on a unit’s emissions or 

operations is the most straightforward way to ensure that sources do not trigger NSR. If such 

limits are necessary to avoid NSR, the EPA believes that the individual source’s permit is the 

best place for the limits to reside. 

Commenters also stated that the options offered for avoiding NSR permitting and installation of 

pollution controls, i.e., taking limits on generation, would create a disincentive to making heat 

rate improvements. We recognize that there may be instances where an affected source may not 

want to accept a limit in the hours of operations or some other restrictions in order to recover its 

investment, and as a result, our analysis does show a limited number of affected EGUs 

potentially triggering NSR as a result of changes made to comply with 111(d) plans. 

Nevertheless, this rule provides sources and states with the flexibility to have those conversations 

and plan accordingly to minimize the number of instances an affected EGU would trigger NSR 

as a result of complying with the state’s 111(d) plan. The proposed emissions guidelines do not 

impose any specific requirements on affected EGUs, instead, the guidelines established targets 

based on the application of BSER and provides states with the flexibility to establish plans to 

meet these targets in a way that is best for the particular state and its affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters responded to EPA's request for comments on options to avoid triggering NSR. 

Commenters stated that the potential options proposed by EPA to avoid CPP projects triggering 

NSR are too tenuous to consistently implement at the state level and they are unlikely (or have 

no guarantee) to be approved by EPA when a state submits its 111(d) plan for approval into its 

SIP. The commenters explained: First, the CAA and EPA regulations prohibit states from 

developing SIPs that are less stringent than their federal NSR counterpart. States cannot 

unilaterally create an exemption from NSR permitting requirements based on the development of 

some standard of performance in a 111(d) plan. And states with delegated PSD programs, lack 

the flexibility to propose any condition inconsistent with EPA's delegated PSD program. Any 

standard of performance or condition implemented at the state level that exempts CPP projects 

from NSR - without an explicit exemption in EPA's regulations - will likely be treated by EPA as 

being inconsistent with and less stringent than the federal NSR program and, thus, not 

approvable. Second, EPA appears to suggest that a source may take into account decreases in 

utilization in response to expected increases in less-carbon intensive energy sources when 
40

determining whether an efficiency project triggers NSR. While permissible under the EPA's NSR 

regulations, in practice EPA's proposal is unlikely to be effective. NSR requires that sources 

determine projected emission increases in the 5 or 10 years following the project. There is no 

way to ensure that sufficient low-carbon generation will exist in the post-project period for the 

source to offset any projected emissions increase from the efficiency project.

Commenters stated that while EPA's proposed options for preventing sources from triggering 

NSR may work, they would also eliminate incentives for an owner or operator to make the 

required efficiency improvements. The commenters stated that the key reason to invest in 

equipment upgrades in mature existing units is to increase efficiency, lower fuel costs, and 

increase reliability; EPA's proposal would ask sources to make the investment but then limit the 

unit's hours of operation, impeding the source's ability to recover its investment. Commenters 

stated this approach would reduce investments in existing units that could trigger NSR, thereby 

eliminating many of the energy efficiency measures sources would otherwise undertake to 

comply and increase system reliability. The commenters stated that the proposed solutions that 

limit hours of operation also run counter to the objectives of the proposed guidelines to reduce 

CO2 emissions from electricity generation in the most cost-effective manner possible. The 

commenters stated that EPA notes repeatedly in the proposed guidelines that states will have 

considerable flexibility to design state programs, but then suggests limits on major compliance 

options, such as improvements in energy efficiency at existing units, even though these options 

will reduce emissions per megawatt of electricity produced. The commenters stated that EPA's 

proposed solution to have the state effectively limit the dispatch of the unit is also problematic 

because it assumes authorities that many states, as members of regional transmission 

organizations, do not possess. The commenters stated that currently, the variable operating cost 

of electric power generation is a key factor in determining which units of a power system are 

dispatched; plants with the lowest variable operating costs are generally dispatched first, and 

plants with higher variable operating costs are brought on line sequentially as electricity demand 

increases. The commenters stated that it is unclear how the requirements of the proposed 

guidelines will impact the structure and operation of electric markets; any solution that hinges on 

such an outcome is highly uncertain and unlikely to encourage needed upfront investment in 

EGU upgrades. 

Commenters stated that, in regards to EPA's request for comment on a general approach to 

resolve concerns about NSR applicability associated with projects undertaken to comply with a 

state's 111(d) plan, they recommended the following approaches individually or in combination: 

a) Interpret "increases" for EGUs on a pound-per-MWh basis. In the 111(a)(4) definition of 

"modification," neither "increases" nor "amount" is defined so that EPA, and states, 

retain discretion to base NSR applicability on a pounds-per-MWh basis, instead of or in 

addition to annual emissions. To avoid unintended consequences with projects that do not 

have a pounds per MWh decrease, EPA could also use a two-step emissions test: EGUs 

would first determine whether a physical or operational change would achieve a 

reduction in emissions on a pound-per-MWh produced basis; if pound-per-MWh 

emissions increased, EPA could then revert to its traditional approach of assessing NSR 

modification by determining whether the emissions increase in tons per year exceeds 

significance levels for the regulated pollutants. 
41

b) Use the routine maintenance, repair, and replacement exclusion to address NSR 

applicability concerns associated with efficiency improvement projects. EPA could take 

the position that upgrades conducted pursuant to an approved 111(d) plan to improve 

efficiency are covered by the routine maintenance, repair, and replacement exclusion. 

Being required (or at least strongly encouraged) to undertake efficiency improvements in 

Building Blocks 1 and 2 certainly suggests that the gatekeeper of "routine" has been 

satisfied. 

c) Use state-wide netting (or a state-wide applicability limit) to avoid a determination of 

emission increases. Any source in compliance with these statewide systems that has an 

emissions increase by itself will not trigger NSR modification because under the state 

plan, the emission increase is being offset by emission decreases elsewhere in the state. If 

this approach is selected, it is critical that the netting exclusion be able to apply on a 

pollutant-specific basis for all pollutants and not be limited to CO2 because efficiency 

improvement projects have the potential to result in increases in emissions per unit time 

of multiple pollutants, including NOx and PM. For this reason, any NSR applicability 

solution, including state-wide netting, would need to apply across the range of pollutants 

emitted. 

d) Clarify that increases in emissions associated with increased utilization of efficiency 

projects are properly excluded under the demand growth exclusion. In light of 

interpretation of the current regulatory language, the demand growth exclusion fails to 

provide relief from PSD applicability concerns for efficiency projects designed to 

improve efficiency under the proposed CPP. With amendments to its PSD rules and an 

accompanying explanation in its rule preamble, however, the commenters believed that 

the demand growth exclusion could clarify the non-applicability of PSD for projects 

designed to improve efficiency under the proposed CPP. This relief could be provided 

with the following rule changes to EPA's PSD rule:

e) Change 40 CFR 52.21(b)(41)(ii) to add new subsection (b)(41)(ii)(e) as follows: 

f) For projects specifically undertaken to meet efficiency improvements associated with [the 

proposed CPP], emission increases resulting from any increased utilization due to product 

demand growth are deemed to not be related to the particular project.

g) Change 40 CFR 51.166(b)(40)(ii) to add new subsection (b)(40)(ii)(e) as follows: 

h) For projects specifically undertaken to meet efficiency improvements associated with [the 

proposed CPP], emission increases resulting from any increased utilization due to product 

demand growth are deemed to not be related to the particular project. 

Commenters commented on two issues for which EPA requested comments: (1) the level of 

analysis and plan requirements that may be needed to ensure that sources will not trigger NSR 

when complying with the state's 111(d) plan, and (2) whether state plans could include 

provisions determining, as a matter of law, that affected sources' actions to comply with plan 

requirements would not subject those sources to NSR. The commenters stated that the most 

straightforward way for states to address these issues is to include in their plans source-specific 
42

limits on affected sources' emissions or operations that are sufficiently rigorous to ensure the 

sources will not generate enough emissions to trigger NSR. The commenters stated that 

consistent with EPA's NSR regulations, any such limits must be enforceable; therefore, among 

other things, adequate testing, monitoring, and record-keeping procedures would have to be 

included in the state plan. 

Commenters stated that beyond such source-specific limits in state plans, however, states cannot 

lawfully or rationally include in their plans generic provisions that effectively exempt sources in 

advance from NSR; the Act does not authorize such exemptions, nor can EPA allow them, 

regardless of whether the plan's purpose is to reduce emissions. The commenters referred to the 

D.C. Circuit invalidation of EPA's attempt to add a pollution control project exemption from 

NSR in New York v. EPA, 413 F.3d 3, 41-42 (D.C. Cir. 2005).

Commenters stated that EPA fails to identify any way that states could reliably assure that 

providing flexible compliance options would foreclose specific sources from taking actions that 

would trigger NSR. The commenters stated that even if a state's analysis shows that a source's 

implementation of section 111(d) plan would not trigger NSR, including in the plan an exception 

from NSR could lead to difficult-to-answer questions, for example, about whether particular 

physical changes made at the source were undertaken to comply with 111(d) plan requirements, 

or were made for another purpose. The commenters stated that finally, to the extent that an 

affected source triggers NSR due to an emissions increase, exempting that source would 

undermine the purposes of the NSR program and put neighboring communities at risk; such 

sources should be required to comply with NSR requirements, including emission limits based 

on best available control technology. The commenters stated that the only projects that are likely 

to increase annual emissions, and trigger the NSR provisions to install modern controls, are those 

that reduce forced outages that are endemic in the aging U.S fleet. The commenters stated that 

many of these projects also extend the useful life of existing units and there is no valid public 

policy interest in artificially extending the "grandfathering" of existing units that was provided 

by Congress in 1970 under the expectation that existing units would soon retire and no longer 

emit at unnecessarily high levels. The commenters stated that nothing in the Act prevents older, 

grandfathered units from upgrading and improving the performance of those units, provided the 

owners (1) install modern pollution controls or (2) accept enforceable permit conditions that 

limit annual emissions to levels emitted in recent years of operation. The commenters stated that 

exempting sources from NSR would encourage life extension programs at fossil fuel-fired EGUs 

that would undermine one of the fundamental structures of the Clean Air Act, the eventual end to 

grandfathered status where modifications increase annual emissions. The commenters stated that 

it would also undermine the fundamental purpose of the Climate Action Plan to transition the 

U.S. electric supply sector to lower carbon intensity technologies; the orderly retirement of 

existing units and transition to low carbon electricity generation would be severely disrupted by 

the NSR exemption that has been suggested.

Commenters stated that EPA's proffered solutions for avoiding NSR-adjusting demand side 

measures or increasing reliance on renewable energy to reduce future emissions of an affected 

source that may trigger NSR or, develop conditions for a source expected to trigger NSR that 

would limit the unit's ability to move up in the dispatch enough to result in a significant net 

emissions increase that would trigger NSR (effectively establishing a synthetic minor limit) - are 

ineffective and run counter to the objectives of the proposed guidelines. The commenters stated 
43

that while these proposed options have the potential to prevent a source from triggering NSR, 

they would also eliminate any incentive (i.e., increased efficiency, lower fuel costs, and greater 

reliability) to make the required upgrade investment. The commenters stated that EPA's proposal 

would ask sources to make the investment but then limit the unit's hours of operation, effectively 

impeding the source's ability to recover its investment. Commenters stated this approach would 

limit investments in existing units that could trigger NSR, thereby eliminating many of the 

energy efficiency measures sources would otherwise undertake to comply and increase system 

reliability. 

Commenters stated that the proposed solutions to limit hours of operation runs counter to the 

objectives the proposed guidelines to reduce CO2 emissions from electricity generation in the 

most cost-effective manner possible. The commenters stated that EPA notes repeatedly in the 

proposed guidelines that states will have considerable flexibility to design state programs, but 

then suggests limits on major compliance options, such as improvements in energy efficiency at 

existing units, even though these options will reduce emissions per megawatt of electricity 

produced.

Commenters stated that the EPA's proposed solution to have the state limit the dispatch of the 

unit is problematic because it assumes authorities that many states, as members of regional 

transmission organizations, do not possess. The commenters stated that it is unclear how the 

requirements of the proposed guidelines will impact the structure and operation of electric 

markets; any solution that hinges on such an outcome is highly uncertain and unlikely to 

encourage needed upfront investment in EGU upgrades.

Commenters stated that, in the case of NGCC, restricting hours of operation run directly counter 

to the objective of Block 2, namely re-dispatch to lower CO2 emitting generation. The 

commenters stated that an existing gas turbine EGU would benefit from the increased output, 

efficiency, and cost effectiveness of deploying an upgrade option; all of these factors, along with 

the stated objectives of Block 2, would lead to the desired result of increased cost effective gas 

turbine operation leading to the ultimate goal of reduced grid-wide CO2 emissions. Commenters 

stated NSR permitting poses a direct barrier to deployment of beneficial gas turbine upgrades, 

and reducing operating capacity to avoid NSR permitting is directly counter to every objective of 

the proposed rule.

Comment 13: Supplemental Proposal for Tribal and Territorial - NSR a deterrent to making 

investments to reduce heat rate 

Response 13: The final emissions guidelines do not require states, tribes or territories to apply 

the BSER building blocks in the same way that EPA applied them to develop the standards of 

performance and state targets. The final guidelines provide states, tribes and territories with

ample flexibility to develop implementation plans that take into consideration a number of 

factors including the possibility of NSR permit requirements on affected units and develop plans 

that minimize such impact. The EPA did not propose any changes to the NSR applicability 

regulations and is not finalizing any with this final rule. As such, NSR applicability is not 

affected by this final rule and remains unchanged.
44

The following are summaries of the specific public comments under this comment:

In response to the Tribal and Territorial supplemental proposal, commenters stated that EPA's 

assumed improvement in heat rate overlooks the potential for triggering NSR and associated 

Best Available Control Technology requirements. The commenters stated that any modification, 

maintenance or repair made at a power plant must be evaluated with the objective of avoiding 

modifications that trigger NSR that would then require much higher capital investments; heatrate improving activities that might improve net output or dispatch or make the plant 

economically viable for a longer time are of concern in this regard. The commenters stated that 

even if EPA includes means to mitigate this concern in the rule, such an approach would likely 

be challenged; legislative reform of the NSR program may be necessary to give appropriate 

assurance to the utility industry regarding NSR triggers, but legislative actions are beyond the 

scope of EPA's rulemaking. The commenters stated that absent such legislative reform of the 

NSR program, companies must be very cautious regarding capital improvements to improve heat 

rate.

Comment 14: As interim measure to aid in transition in BB#2, eliminate PSD/BACT permitting 

requirements for existing simple cycle NG units

Response 14: The EPA appreciates the commenters’ suggestions for adding an interim 

exemption from NSR for existing simple cycle natural gas units. However, the EPA has 

previously promulgated exemptions from the NSR rules in order to remove regulatory 

disincentives to undertaking positive, or even required, actions such as installing pollution 

controls, only to have these exemptions rejected by reviewing courts. The United States Court of 

Appeals in State of New York, et al., v. U.S. Environmental Protection Agency (NY I) was clear 

that we lack the authority to create such exemptions from the NSR rules. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the increase in CCNG units on which building block #2 is based, at least 

in the short-term, is exceedingly optimistic. The commenters stated that to aid in the near term 

transition envisioned in BB #2, the EPA should consider eliminating the PSD/BACT permitting 

requirement for existing simple cycle NG units at least in the short-term, until such time as 

CCNG units and the concomitant transportation network necessary, reach the expected increase 

the EPA has set for Illinois in the GHG Rule.

7.4 TITLE V PROGRAM

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the Title V program.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.
45

Comment 1: EPA failed to consider existing permit limitations

Response 1: The EPA developed the individual state goals through application of BSER, using 

the building blocks as described in the final rule preamble. The final emissions guidelines do not

require states to apply the building blocks in the same way that EPA did to establish the state 

targets, instead, it provides ample flexibility to states to develop implementation plans to achieve 

the necessary reductions to meet the state goals. This flexibility allows states to consider a broad 

spectrum of techniques and types of emission reduction options to meet the goal. 

Regarding existing enforceable restrictions included in Title V permits, we recognize some 

affected EGUs may have them in their title V permits as a result of some other applicable 

requirement under the Clean Air Act (CAA) and that there may be a need to make modifications 

to title V permits as a result of state 111(d) plan requirements. The title V program includes a 

series of provisions design to allow for permit modifications and inclusion of new CAA 

requirements when these become applicable to a title V source. State permitting authorities have 

been implementing EPA-approved operating programs (i.e., title V programs) for many years 

and are well positioned to make any necessary modifications to affected EGUs title V permits. 

Whether these modifications are needed or not would depend on the specific requirements a state 

includes in its 111(d) plan. As such, we encourage state air permitting agencies to work closely 

with other parts of the state environmental agency as they develop their 111(d) state plan. 

The following are summaries of the specific public comments under this comment:

Commenters stated that, in setting state goals, EPA failed to recognize existing permit limitations 

that would prevent a facility from reaching a 70 percent capacity utilization.

Commenters stated that in its broad application of a 70 percent post-redispatch capacity factor 

for existing NGCC facilities, EPA fails to consider any permit limitations that may restrict the 

operation of a particular NGCC facility. The commenters stated that in response to a request for 

such information from PJM, generators within that RTO cited environmental limitations in their 

permits that limit the total hours that a generation resource may operate; an example of these 

types of restrictions follows. The commenters provided the following information: In the state of 

Michigan, where EPA ramps up existing NGCC capacity to 70 percent in the Building Block 2 

goal setting methodology, the Jackson Michigan Facility (649 MW) currently operates under a 

Title V permit that contains enforceable restrictions sufficient to limit operation under a 70 

percent capacity factor. The Title V permit for this facility contains hourly and 12-month rolling

NOx emission limits, such that high capacity factors (utilization rates) would result in annual 

NOx emissions above their annual limits. Consumers Energy, which has a contract to purchase 

the facility, undertook an internal analysis and examined the 2012 high utilization period (May to 

August), concluding the capacity factor for the entire plant would be limited to 49 percent. 

Comment 2: States can add specific GHG limits to existing Title V permits
46

Response 2: The supportive commenters correctly state that authority exists under the Clean Air 

Act to incorporate new applicable requirements, including emissions limits developed by the 

state in the context of their 111(d) plans into a source’s title V permit. The final rule for section 

111(d) plans sets forth a state goal for each state and provides flexibility for states on how to 

develop compliance options for sources under a state plan to meet the state goal. Thus, it is the 

requirements of the state 111(d) plan that are applicable requirements to the affected EGU that 

would be incorporated into a source’s permit.

The following are summaries of the specific public comments under this comment:

Commenters supported EPA setting emission targets for each state using the proposed BSER, 

and commends EPA's determination that BSER for existing EGUs recognizes the complex 

interactions of generation, renewable energy and demand side reductions in the power grid. The 

commenters commended EPA for providing states multiple options in designing their 

compliance plans that can be tailored to ensure this reliability, as well as encouraging a multistate approach for regional cooperation and supports an approach that allows states the flexibility 

to commit to specific plans of action, with regular reporting and oversight, but without federal 

enforceability of each individual regulatory action or enforcement process. 

The commenters stated that to the extent that states implement 111(d) programs that require 

specific power plant emission limits for GHGs, they believe that the authority already exists for 

such limits to be added to existing title V permits for affected facilities. The commenters stated 

that section 504 of the Clean Air Act (42 U.S.C. section 7661(c)(a)) requires that every Title V 

permit include such conditions as are necessary to assure compliance with applicable 

requirements of this chapter, including the requirements of the applicable implementation plan. 

The commenters stated that the relevant chapter is Chapter 85 of Title 42, and encompasses the 

entire Clean Air Act and, therefore, the Clean Air Act requires a Title V permit to include 

conditions to ensure compliance with standards applicable to individual units.

The commenters stated that consistent with Clean Air Act Section 504, EPA has defined 

applicable requirements for purposes of the Title V regulations to include any standard or other 

requirement under Section 111 of the Act, including Section 111(d). The commenters stated that 

EPA has already explicitly concluded that requirements under Section 111(d) are applicable 

requirements. The commenters stated that EPA regulations further require that each Title V 

permit include emission limitations, standards and requirements that assure compliance with all 

applicable requirements at the time of permit issuance. The commenters stated that at least to the 

extent that 111(d) requirements for power plants apply directly to the individual unit, these 

requirements undoubtedly constitute emission limitations, standards, or requirements.

Comment 3: Exemption of biogenic CO2

Response 3: This final action is taken under section 111 of the Clean Air Act and in no way it 

modifies any of the permitting programs or the treatment of biogenic CO2 emissions for the 

purposes of PSD or title V, such actions are beyond the scope of this rule. 
47

The EPA has recently issued a memo describing it past actions and next steps on assessing 

biogenic CO2 emissions from stationary sources as part of the EPA’s broad climate strategy.2

 In 

the memo the EPA stated that it was preparing to release the second draft of the Framework for 

Assessing Biogenic CO2 Emissions from Stationary Sources, which included information on the 

EPA’s ongoing work on developing an accounting framework for biogenic emissions of GHGs

and additional activities under development, such as a plan to revise the PSD rules to exempt 

GHGs from waste-derived feedstocks and from non-waste biogenic feedstocks derived from 

sustainable forest or agricultural practices.

The following are summaries of the specific public comments under this comment:

Commenters requested that EPA provide a permanent applicability exemption of biogenic CO2 

emissions from the CAA PSD and Title V Programs because the combustion of such material 

would cause no net increase in GHG emissions on a lifecycle basis. The commenters stated that 

renewable and carbon neutral fuels should be considered a part of a diverse energy supply 

portfolio. The commenters stated that by not properly exempting biogenic CO2 emissions, the 

PSD and Title V Programs potentially create a disincentive to proceed with bioenergy projects, 

thus eliminating the renewable energy and GHG reduction benefits achieved by using a carbon 

neutral fuel - biomass. The commenters stated that future biomass projects will be impacted if 

biogenic CO2 emissions are not provided a permanent applicability exemption from the PSD and 

Title V Programs. The commenters stated that one commonality between EPA's listed studies 

and other biomass studies researched is the conclusion that bioenergy produces GHG benefits. 

The commenters stated that prior to the Tailoring Rule, good scientific data lead to numerous 

international, federal, and state policies exempting biogenic CO2 emissions from GHG reduction 

programs and excluding them from energy sector GHG inventories. The commenters stated that 

EPA's abrupt biomass policy shift in the Tailoring Rule is unsubstantiated. The commenters

stated that since EPA released the final Tailoring Rule, the Agency collaborated with the 

Department of Energy, the Department of Defense, the General Services Administration, the 

Department of the Interior, the Department of Commerce and other agencies to develop draft 

Federal GHG Reporting and Accounting Guidance, which exempts biogenic CO2 emissions 

from Federal agency reduction targets. The commenters stated that these consistent actions and 

statements make clear that EPA must revisit the treatment of biogenic CO2 emissions in the 

Tailoring Rule and provide these emissions a permanent applicability exemption from the PSD 

and Title V Programs.

Commenters stated that stationary source facilities that combust biomass may still be subject to 

PSD and title V permitting requirements if their non-GHG pollutant emissions meet statutory 

thresholds; for this reason, biomass supporters have urged EPA to issue a final biogenic 

accounting framework that treats biogenic carbon emissions as carbon neutral.

 

2 See Addressing Biogenic Carbon Dioxide from Stationary Sources; Janet G. McCabe, Acting 

Administrator, Office of Air and Radiation, US EPA, to Air Division Directors, Regions 1-10; 

November 19, 2014.
48

Comment 4: Applicability of title V requirements to affected entities 

Response 4: The final rule under 111(d) rule did not include a proposal to exempt non-major 

(area) sources from the title V permitting, as provided for under CAA section 502(a). The 

authority to exempt such a source from title V requirements is a discretionary duty of the 

Administrator that is based upon a finding that “compliance with the permitting requirement is 

“impracticable, infeasible, or unnecessarily burdensome on such source categories.” The 

Administrator has made no such finding with respect to area sources that may be subject to this 

final rule , thus sources that are subject to the final emissions guidelines promulgated today are 

required to apply for, and operate pursuant to, a title V permit that assures compliance with all 

applicable CAA requirements, including any GHG-related applicable requirements. EPA does 

not expect that many, if any, area sources would be subject to the requirements of this rule.

The commenters on the “portfolio approach” of the proposal are concerned that the approval of a 

state plan may expand the types of source that are defined as EGUs that are subject to the final 

rule. This concern is misplaced because the final rule does not expand the source category of 

fossil fuel-fired EGUs that are subject to this rule. 

The title V permit for an affected EGU under the final emissions guidelines would need 

incorporate any new applicable requirement for the source that is created under the state 111(d) 

plan, rather than directly implement the requirements of this final rule. The final rule requires the 

states develop a section 111(d) plan, which is designed with flexibility to provide for meeting the 

state goal. In this way, there are no specific requirements in this final rule for any particular 

source to implement any particular compliance options, as such determinations are left to state 

discretion in the context of the development of the state plan. Once the state plan is approved by 

the EPA, consistent with the flexibility provided in the state plan, the affected EGUs in the state 

would need to incorporate into its title V permit any new applicable requirement based on the 

state 111(d) plan, which may include an allowance trading program, and associated monitoring, 

recordkeeping and reporting requirements for the options. The title V permit would be either 

reopened or revised to incorporate the applicable requirement under the state plan that applies to 

the source and provide for the compliance options that the source will implement under the state 

plan.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA's proposal omits critical information about the Title V requirements 

applicable to affected entities potentially included in state 111(d) plans, contrary to EPA's Title 

V regulations. The commenters stated that EPA has not made any proposed determination of 

whether to exempt any or all non-major (area source) compliance entities subject to a standard or 

other requirement under the proposed Clean Power Plan from the duty to obtain a Title V permit. 

The commenters stated that making certain types of entities compliance entities results in an 

unauthorized expansion of EPA's authority, and will present unresolvable issues for state 

permitting authorities. The commenters stated that applicability or non-applicability of Title V 

permitting requirements also determines the enforcement mechanisms available to the states for 

section 111(d) plan requirements applicable to compliance entities, and illustrates the absurd 
49

results that would follow from making the state itself, other governmental entities, or nonemitting generators subject to the enforcement provisions of the Title V permitting program. The 

commenters stated that to the extent EPA continues to rely on its portfolio approach to 

developing section 111(d) plans, EPA's final rule must clarify the application of Title V's 

permitting requirements to compliance entities, and avoid the absurd results that would ensue if 

section 111(d) were interpreted to encompass a broad range of entities far beyond the affected 

facilities that are within the listed source categories and can legitimately be subject to a 111(b) 

standard.

Commenters stated in response to EPA's request for comments as to whether specific emission 

limits or control technology requirements applicable to individual units should be considered 

"applicable requirements" under Title V, section 504 of the CAA requires that every Title V 

permit include such conditions as are necessary to assure compliance with applicable 

requirements of this chapter, including the requirements of the applicable implementation plan. 

The commenters stated that the relevant chapter is Chapter 85 of Title 42, and encompasses the 

entire CAA; therefore, the CAA requires a Title V permit to include conditions to ensure 

compliance with standards applicable to individual units. The commenters stated that EPA has 

defined "applicable requirements" for purposes of the Title V regulations to include "Any 

standard or other requirement under Section 111 of the Act, including Section 111(d)." The 

commenters stated that EPA regulations further require that each Title V permit include emission 

limitations, standards, and requirements that "assure compliance with all applicable 

requirements at the time of permit issuance." The commenters stated that at least to the extent 

that 111(d) requirements for power plants apply directly to the individual unit, these 

requirements undoubtedly constitute "emission limitations, standards, or requirements."

Comment 5: For Title V permitting purposes, "any air pollutant" does not include CO2 

Response 5: It is unclear what the commenters’ point is related to the Supreme Court ruling in 

the Tailoring Rule case (Utility Air Regulatory Group v. Environmental Protection Agency) and 

the title V permitting program. The U.S. Supreme Court ruled, in Massachusetts v. EPA, that 

greenhouse gases (GHGs)3 meet the definition of “air pollutant” in the CAA. On June 23, 2014, 

the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection 

Agency, issued a decision addressing the application of PSD permitting requirements to GHG 

emissions. The Supreme Court held that the EPA may not treat GHGs as an air pollutant for 

purposes of determining whether a source is a major source (or modification thereof) for the 

purpose of PSD or Title V applicability. The Court also said that the EPA could continue to 

require that PSD permits, otherwise required based on emissions of pollutants other than GHGs, 

 

3The EPA’s 2009 endangerment finding defines the air pollution which may endanger public 

health and welfare as the well-mixed aggregate group of the following gases: CO2, methane 

(CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), and 

perfluorocarbons (PFCs).
50

contain limitations on GHG emissions based on the application of BACT. The Supreme Court 

decision effectively upheld PSD permitting requirements for GHG emissions under Step 1 of the 

Tailoring Rule for "anyway sources" and invalidated application of PSD permitting requirements 

to Step 2 sources based on GHG emissions. The Court also recognized that, although EPA had 

not yet done so, it could “establish an appropriate de minimis threshold below which BACT is 

not required for a source’s greenhouse gas emissions.” 134 S. Ct. at 2449.

In accordance with the Supreme Court decision, on April 10, 2015, the U.S. Court of Appeals for 

the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the 

regulations that implemented Step 2 of the Tailoring Rule, but not the regulations that implement 

Step 1 of the Tailoring Rule. The court specifically vacated sections 51.166(b)(48)(v) and 

52.21(b)(49)(v) of the EPA’s regulations, but did not vacate sections 51.166(b)(48)(iv) or 

52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its 

regulations are appropriate in light of UARG v. EPA, and, if so, to undertake such revisions. 

Independent from the Supreme Court rulings discussed above, the Clean Air Act (CAA) and the 

title V implementing regulations require that major sources of air pollutants apply for and obtain 

an operating permit under the provisions of the applicable title V program or state approved 

program. Such operating permits must contain all CAA applicable requirements for the affected 

major stationary source, which includes applicable requirements developed under section 111 of 

the CAA. As such, affected sources under the final emissions guidelines for which state 111(d) 

plans establish new applicable requirements, are required to file and application for obtaining a 

title V operating permit if they didn’t already have one or make the necessary permit 

modifications to incorporate the new applicable requirements into their existing operating permit 

following the applicable permitting program permit modification requirements.

The following are summaries of the specific public comments under this comment:

Commenters stated that on June 23, 2014, the Supreme Court held that EPA "may not treat 

greenhouse gases as a pollutant for purposes of defining a major emitting facility (or a 

modification thereof) in the PSD context or a major source in the Title V context" of the CAA, 

and so invalidated a rulemaking imposing PSD and Title V permitting requirements for GHG

emissions. The commenters stated that the basis of the decision was that while the "Act-wide" 

definition of air pollutant was broad enough to include GHGs as the Court had held in 

Massachusetts v. EPA in 2007 the use of the term "any air pollutant" within the context of "the 

permit-requiring provisions" applicable to PSD and Title V was not broad enough to include 

carbon dioxide and the other GHGs EPA sought to regulate (CO2e). The commenters stated that 

the reason for this is that interpreting "any air pollutant" to include CO2e, and so trigger 

permitting, would conflict with the statutory design by compelling results that would be extreme, 

counterintuitive, or contrary to common sense; in short, EPA's interpretation would require 

regulating far more sources than Congress ever intended. The commenters stated that although 

EPA had tried to address the results of its interpretation, including having to permit nearly every 

large building in America, by rewriting the statutory trigger to increase by as much as 1,000-fold 

the permitting thresholds set forth in the statute, the Court refused to defer to this interpretation 

under Chevron. The commenters stated that it refused to do so because EPA's reinterpretation of 
51

the permitting thresholds was too obviously a redrafting of the statute simply replacing those 

numbers with others of its own choosing to fall within the bounds of reasonable interpretation.

Comment 6: Title V fees 

Response 6: The section 111(d) final rule does not include any regulatory changes related to 

title V fees for CO2, and thus, this fee issue is beyond the scope of this final rule. The section 

111(b) rulemaking, also being finalized today, addresses title V fee issues related to GHGs, 

which includes CO2 as one of the well mixed six gases that make up the regulated pollutant 

GHG. Nevertheless, the exemption of GHGs from program cost considerations under the 

presumptive minimum fee approach of § 70.9(b)(2) that is included in the parallel section 111(b) 

final rule is authorized under CAA section 502(b)(3)(B)(i), which requires a state to demonstrate 

it will collect adequate fees based on the “$25/ton of each regulated pollutant” formula cited by 

the commenters or on “such other amount as the Administrator may determine adequately 

reflects the reasonable costs of the permit program” and the EPA has made a finding that the 

exemption of GHG from the presumptive minimum fee approach of part 70, coupled with the 

promulgation of a new, modest GHG cost adjustment, will allow states that use the presumptive 

minimum fee approach to demonstrate that they will collect adequate fees, consistent with the 

statute. Also, the section 111(b) final rule explains that the GHG cost adjustments we are 

finalizing are related to the increased costs for permitting authorities to perform certain GHG 

reviews in the title V context, and that the costs are not related to the costs of implementing any 

particular applicable requirements. 

The following are summaries of the specific public comments under this comment:

Commenters stated that they disagree with U.S. EPA's proposal to exempt CO2 from the $/ton 

Title V fees. The commenters stated that they are not suggesting that the $25/ton adjusted to the 

CPI is the appropriate amount for CO2, only that U.S. EPA is obligated under the CAA to 

calculate the proper value and not just "exempt" these emissions. The commenters stated that the 

recent U.S. Supreme Court case UARG vs. EPA related to permitting of CO2 sources should be 

an important reminder that the federal government cannot create exemptions that do not exist in 

the CAA. The commenters referred to their comments on Title V fees for CO2 for EGU's that 

were part of the comments for U.S. EPA proposal for new sources under Section 111(b).

Commenters stated that EPA did not address the potential impact of the CPP on permitting fees 

as they relate to CO2 emissions. The commenters stated that EPA previously indicated that its 

proposed rulemaking for CO2 emissions from new sources under section 111(b) did not trigger 

the emissions fee requirement for CO2 because in that case EPA is not actually proposing to 

regulate emissions of CO2, but rather emissions of greenhouse gases. The commenters stated 

that in this case, the proposed Rule states that CO2 is being regulated; EPA must address the 

impact of regulating CO2 in this proposal on air permit fees under Section 502 of the Act.
52

Comment 7: Role of Title V Program in Enforcing Section 111(d) Allowance Trading 

Requirements 

Response 7: The title V permit for an affected EGU under the final emissions guidelines would 

need incorporate any new applicable requirement for the source that is created under the state 

111(d) plan, including any requirement to hold allowances under a trading program, rather than 

directly implement the requirements of this final rule. Once the state plan is approved by the 

EPA, consistent with the flexibility provided in the state plan, the affected EGUs in the state 

would need to incorporate into its title V permit any new applicable requirement based on the 

state 111(d) plan, which may include an allowance trading program, and associated monitoring, 

recordkeeping and reporting requirements for the options. 

The title V permit would be either reopened or revised to incorporate the applicable requirement 

under the state plan that applies to the source and provide for the compliance options that the 

source will implement under the state plan, for example, an allowance trading program. After 

that, a permit revision would not necessarily be required to reflect changes in allowance under a 

trading program. Title V is structured so that a source may typically make individual trades 

under an allowance trading program without the need for formal permit revisions because most 

trading activity would already be addressed and allowed by the specific terms and conditions of 

the permit and such trading would not normally conflict with the permit. This is the principle 

expressed by section 70.6(a)(8) of the CFR, which states that permit revisions are not required 

for trading program changes that are ‘provided for’ in the permit.”

The following are summaries of the specific public comments under this comment:

Commenters stated that in an allowance trading program the requirement to hold sufficient 

allowances to cover emissions, and to perform required monitoring, record keeping, and 

reporting, would need to be included in the EGU's Title V permit, and made enforceable in that 

manner. The commenters stated that this follows from the fact that EPA has already defined 

"applicable requirements" under Title V to include "Any standard or other requirement under 

Section 111 of the Act, including section 111(d)." 40 C.F.R. Section 70.2 (definition of 

applicable requirement, subsection (3).)

Comment 8: Permitting on federally controlled and tribal lands 

Response 8: The implementation of the final rule will occur on federal or tribal lands under a 

federal plan implemented by the EPA, federal plan delegated to a state or tribal entity by the 

EPA, or by a tribal entity through a state plan, provided the tribe has been granted “treatment as a 

state” by the EPA. In cases where EPA is responsible for permitting, the EPA intend to issue any 

permits on a timely basis. The EPA has issued a memo to clarify the timing and processing of 
53

PSD permit applications when the EPA or a delegated agency issues a PSD permit.4 The memo 

summarizes the permit processing requirements of the Clean Air Act, the EPA’s implementing 

regulations, and recommend procedures for permitting authorities to use to ensure that permitting 

decisions are consistent with applicable regulations, including a goal to make permit decisions 

(issue or deny) on PSD permit applications within 10 months after the date the Regional Office 

has determined that the application is complete. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the large proportion of federally controlled and tribal lands in western 

states creates its own challenges with respect to the timely permitting and construction of new 

generation resources and any supporting pipeline or transmission infrastructure. Commenters

stated the presence of federal and tribal land makes the permitting, environmental review and 

public review processes for siting of new energy infrastructure significantly more complex and 

time-consuming compared to the rest of the nation and will impact the ability of many of the 

western states to meet the compliance deadlines.

7.5 40 CFR Part 75

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with 40 CFR Part 75. We have organized the comments in this section under nine subsections, 

7.5.1 to 7.5.9. Responses to the comment topics of these subsections are discussed below along 

with summaries of the specific public comments.

7.5.1 Monitoring of electric generation: equipment standards

This section addresses comments received on monitoring of electric generation, specific to 

equipment standards.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Requirements for net electricity metering and QA/QC requirements.

 

4 See Timely Processing of Prevention of Significant deterioration (PSD) Permits when EPA or a 

PSD-Delegated Air Agency Issues the Permit; Stephen D. Page, Director, Office of Air Quality 

Planning and Standards to Regional Air Directors, Regions 1-10; October 15, 2012.
54

Response 1: Regarding the metering of net electricity and the QA/QC requirements for net 

meters, the EPA believes that the vast majority of units have sufficient watt meters to report net 

generation. Net generation is currently reported to EIA by approximately 92 percent of 

respondents to the EIA-923 survey. EPA requested comment on the specification of ANSI 0.2 

class watt meters and received few comments on this matter. Regarding the comments about 

costs to install sufficient watt meters, not enough supporting documentation was submitted 

evaluate commenters’ assertions. Regarding the proposed ANSI standard for watt meters, 

commenters did not provide any suggested alternatives to this standard in order to ensure 

consistent measurement of net electricity, which is essential to ensure that all parties are 

reporting this key compliance metric on a consistent basis. The agency does not provide access 

to copyrighted materials in its dockets. The fee to access the ANSI standard is nominal and 

should not have been a barrier for this industry to evaluate the standard. EPA did estimate the 

costs the monitoring, recordkeeping and reporting of the proposed rule in its Regulatory Impact 

Analysis and solicited comment regarding those costs. Auxiliary loads that supply energy to 

equipment related to the performance of the EGU are within the boundary of the EGU and EPA 

has the authority to request such information to determine the net energy output performance of 

the EGU. Therefore, in the final rule, EPA is requiring use of ANSI 0.2 class meters to measure 

and report net electric generation. However, to ensure that the monitoring requirements for net 

electric output are not overly burdensome at a facility, in the final rule, EPA is allowing a facility 

to request alternative monitoring under 40 CFR 60.13(i) to alleviate unreasonable costs or to 

allow for delayed installation of meters during the next planned period of downtime. In final 

rule, EPA is requiring the reporting of hourly net energy output. However; EPA is not requiring 

the equipment used to measure net energy output to be included in the electronic monitoring 

plan. The Agency is also not requiring the results of the QA/QC tests on such equipment to be 

reported electronically. States and tribes have the flexibility to require more stringent monitoring 

requirements for watt meters in their state plan submissions. 

Regarding the metering of auxiliary loads that serves multiple units, the EPA will allow for 

reasonable apportionment of such auxiliary loads to multiple units. 

The following are summaries of the specific public comments under this comment:

Commenters opposed the proposed ANSI 2010 C12.20 equipment standards for various reasons 

including the following: EPA has not provided justification for that proposal; EPA has not 

provided information to that EGUs are not already using meters of acceptable accuracy; EPA has 

not provided any information to show that the proposed equipment standard would not be 

burdensome or require the upgrading of equipment; EPA has never before found it necessary to 

impose such requirements because EGUs already have sufficient incentives to ensure that the 

electricity they generate and use is accurately measured; the ANSI standard is extraordinarily 

detailed and not at all suited to a regulatory program under which penalties could be sought for a 

failure to comply; EPA has not provided a copy of the standard in the docket, or discussed the 

content of the standard in any meaningful way; if the monitoring of net electric output is 

required; the ANSI standard is not publicly available and must be purchased from ANSI, which 

charges a significant sum for access to the standard and restricts the networking and sharing of 

the purchased file; if the monitoring of net electric output is required, EPA must allow EGUs to 

use existing equipment and methods for metering station service, and to apportion common 

station service to individual units using unit generation; the EPA's proposal to require adherence 
55

to ANSI Standard C12.20 will require many EGU facilities to replace existing equipment at 

considerable cost; if EPA were to require replacement of existing equipment or to impose more 

stringent standards on existing equipment, EPA would need to revise its proposal to estimate and 

solicit input on the additional costs and burdens of such metering 

Commenters stated that compliance with the proposed requirement would be burdensome; 

although some EGUs may have meters that comply with all or parts of the ANSI standard, some 

do not and the cost of replacing such meters is not insignificant. The commenters stated that with 

respect to the monitoring of net electric output, EPA's proposal appears to be based on an 

assumption that net output would be determined using existing equipment and simple 

apportionment schemes. The commenters stated that measurement of unit-specific net output can 

be complicated by the difficulty in measuring auxiliary energy consumption of numerous plantspecific devices and most plants do not have the internal electrical distribution system designed 

to distribute and measure internal usage on a unit basis. 

Commenters stated that requiring the use of ANSI Standard C12.20 instrumentation and 

calibration procedures is not justified as newer power generating stations or stations that have 

replaced older metering equipment may be capable of meeting that standard, but there are many 

stations where some or all of the equipment will not meet ANSI Standard C12.20 requirements. 

Commenters stated that with respect to the monitoring of net electric output, the EPA's proposal 

appears to be based on an assumption that net output would be determined using existing 

equipment and simple apportionment schemes. The commenters agreed that if the monitoring of 

net electric output is required, the EPA must allow EGUs to use existing equipment and methods 

for metering station service, and to apportion common station service to individual units based 

on unit generation. The commenters stated that the EPA's proposal to require adherence to ANSI 

Standard C12.20 will, in fact, require many EGU facilities to replace existing equipment at 

considerable cost. If the EPA were to require replacement of existing equipment or to impose 

more stringent standards on existing equipment, the EPA would need to revise its proposal to 

estimate and solicit input on the additional costs and burdens of such metering.

Commenters stated that because auxiliary support facilities are outside of the boundary of the 

defined affected emissions source, the EPA does not have the authority to require upgrade of 

auxiliary power usage metering systems. The commenters stated that in addition, the specific 

requirement to apply ANSI Standard C12.20 to auxiliary power meters is not justified because 

the incremental gain in accuracy would be inconsequential. The commenters stated auxiliary 

power usage accounts for less than 10 percent of gross electric generation and a small 

improvement in accuracy will have an inconsequential impact on the reported net generation. 

Commenters stated that, regarding EPA's consideration of a specification of 0.2 accuracy class 

meters to determine net electric output (or gross electric output), the additional accuracy 0.2 

devices are not typically installed for gross measurements and is typically only specified for use 

in recently built power stations at the "point of sale" transfer point. The commenters stated that if 

any parasitic loads were metered, that would be with a 0.5 class device. The commenters stated 

that only the point of sale meters undergo checks on any periodic basis, which is already 

specified by the regional transmission authority. The commenters requested that EPA abandon 

requiring a 0.2 accuracy meter.
56

Commenters stated that, regarding the use of ANSI Standard C12.20 instrumentation and 

calibration procedures, newer power generating stations or stations that have replaced older 

metering equipment may be capable of meeting that standard, but there are many stations where 

some or all of the equipment will not meet ANSI Standard C12.20 requirements. 

Commenters stated that compliance with that proposed requirement would be burdensome 

because many of the meters do not meet all or parts of the ANSI standards and the cost of 

replacing such meters is not insignificant. With respect to the monitoring of net electric output, 

commenters stated that EPA's proposal appears to be based on an assumption that net output 

would be determined using existing equipment and simple apportionment schemes; the 

commenters agreed that if the monitoring of net electric output is required, the EPA must allow 

EGUs to use existing equipment and methods for metering station service, and to apportion 

common station service to individual units based on unit generation. 

Commenters stated that they do not believe that there is any benefit to including equipment used 

to measure electric and energy output in the Part 75 monitoring plan or to requiring additional 

QA/QC for that equipment; EGUs already have sufficient incentives to ensure that their 

equipment for measuring output is accurate, and EPA has not provided any information to 

suggest that additional quality assurance is warranted. The commenters stated that also, any 

increase in accuracy would be dwarfed by other sources of allowed error in the overall 

measurements that cannot be eliminated; on the other hand, the resources necessary to track such 

equipment, to purchase and install new equipment if necessary to meet new accuracy standards, 

and to perform such testing would be significant. The commenters requested that EPA eliminate 

the provisions for the equipment used to measure electric and energy output to be included in the 

Part 75 monitoring plan and eliminate additional QA/QC for this equipment.

Commenters stated that the statement on page 3 of the TSD that electric generation and parasitic 

loads are universally measured at EGUs is not correct; station service transformers are not 

universally measured. The commenters stated that Regional Transmission Authorities typically 

mandate calibration of power measurement devices used at the boundary between the power 

generating station and the transmission grid; other measurement devices, such as unit specific 

devices and auxiliary bus indications may not be calibrated at all. The commenters stated that 

since the other power measurement devices are not compliance devices, a ballpark indication is 

sufficient for most current purposes.

7.5.2 Monitoring of electric generation: specification and frequency of quality assurance 

testing

This section addresses comments received on monitoring of electric generation, specific to 

specification and frequency of quality assurance.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 
57

Comment 1: EPA should conduct a formal Information Collection Request for station metering 

schemes before proposing such requirements.

Response 1: The agency did not submit a formal information collection request regarding the 

equipment and meters used to monitor net electric output at EGUs before proposing this rule. 

The agency did perform enough research to determine the majority of EGUs have equipment in 

place to determine net energy output. See response to comment 1 in section 7.5.1 above for 

further information.

The following are summaries of the specific public comments under this comment:

Commenters stated that to the extent EPA intends to establish equipment and electricity metering

quality assurance requirements, they request that EPA conduct a formal Information Collection 

Request for station metering schemes before proposing such requirements in order to fully 

understand the ramifications of such provisions.

7.5.5 Monitoring of non-electric output at CHP units

This section addresses comments received on monitoring of non-electric output at CHP units.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Useful thermal output 

Response 1: The final rule includes an equation for the calculation of net energy output at 40 

CFR 60.5860(a)(5)(iv), which includes any useful thermal output of steam from a CHP unit. The 

final rule does not specify any technologies to monitor or measure the parameters needs to 

calculate useful thermal output. The final rule does not prescribe any quality assurance protocols 

for equipment used to measure parameters necessary to calculate useful thermal output. EPA 

believes that owners and operators of CHP units have sufficient incentive to accurately monitor 

the parameters used to calculate useful thermal output.

The following are summaries of the specific public comments under this comment:

Commenters responded to EPA's request for comment on the calculation of equivalent electrical 

energy for thermal output of fossil CHP installations. The commenters stated that EPA's 

proposed definition of net energy output in section 60.5820 establishes a default calculation 

method that oversimplifies how thermal energy is and is not used beneficially in an industrial 

plant. The commenters stated that the balancing of thermal loads and losses is complex and not 

amenable to a simple one approach fits all formula. The commenters stated that in a facility, for 

example, like an oil refinery or petrochemical plant, plant steam supplied by an EGU may be 

sent through equipment whose primary purpose is to reduce the energy content of the steam 

(pressure reducers) to allow it to be used in a specific process unit or through wasting steam to 
58

the process sewer system. The commenters recommended that if EPA plans to follow the 

proposed approach to calculating net energy output, there should be a secondary approach used if 

the EGU/CHP facility does not wish to go through a plant-specific thermodynamic analysis of 

the steam system.

Commenters stated that, regarding EPA's request for comment on the measurement of useful 

thermal energy and quality assurance protocols, the commenters stated that they do not believe 

that it would be appropriate for the EPA to specify which technologies to use or to impose 

requirements for periodic quality assurance because any accuracy gains that might be achieved 

from imposing additional requirements surely would be lost in the noise of the calculations and 

assumptions used to justify the percent credit for thermal output. The commenters stated that 

identifying best practices may be well-intended, but decisions on appropriate measures each 

facility will take to provide what it believes are accurate measurements are best left to the 

engineers responsible for the facility; each EGU should be allowed to select the technologies that 

best suit its needs under the circumstances, and to determine the best mechanism to ensure an 

appropriate level of accuracy. The commenters stated that steam supply systems are unique to 

each facility, and measurement technology decisions will consider many factors. The 

commenters stated that different types of meters, instruments, and calculation methods also 

provide varying levels of accuracy depending on the steam conditions, which can vary from 

source to source; for example, some steam is supplied, and therefore metered, at conditions that 

are barely superheated or barely at the saturation temperature. The commenters stated that some 

equipment simply would not benefit from any periodic QA; for example, thermocouples and 

resistance temperature detectors either work or fail completely. The commenters stated that 

because removing such sensors for calibration may be difficult, and even dangerous in high 

pressure processes, there is no benefit to removing them until they fail and have to be replaced; 

manufacturers' recommendations also are not universally appropriate for ongoing maintenance or 

QA, and are not appropriate for use in rules because they vary from vendor to vendor and can 

change over time without any opportunity for the regulated community to comment on the 

impact of any changes in the recommendations. The commenters stated that the EPA has not 

provided any details of what requirements, procedures, or specifications that it may consider to 

be reasonable best practices; further rulemaking, supported by analysis of the possible 

requirements and impacts, needs to be proposed for public comment before EPA can issue any 

final requirement.

Commenters stated that EPA specifically references the American Society of Mechanical 

Engineers ("ASME") Performance Test Codes as quality assurance requirements; these standards 

are not appropriate for ongoing quality assurance because they were designed for performance 

testing, not long term performance. The commenters stated that although most flow meters 

probably would meet the ASME mass flow controller ("MFC") standards generally, the 

commenters do not believe EPA has justified such standards in this context, and any requirement 

for their use would have to refer simply to the standard series as a whole in order to ensure that 

the entire range of flow meter types and conditions used at existing plants would be covered.
59

7.5.6 Reporting of net electric generation and CHP net energy output

This section addresses comments received on reporting of net electric generation and CHP net 

energy output.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Reporting net electric generation

Response 1: In response to the comment regarding monitoring and reporting of net generation at 

an EGU in a state that elects to implement a mass based program, rather than a rate based 

program, the EGU still must monitor and submit net energy output data. This is required to 

enable the State to demonstrate that compliance with the mass based program also demonstrates 

that the state’s rate based goal is net. Owners and operators of utility and non-utility EGUs 

already report net electric generation to EIA via Form EIA-923 on a prime mover basis and a 

sample of EGUs on a unit basis. This rule cannot use the EIA data directly for several reasons: 

some of the EIA data is reported in an aggregated manner to EIA and is not reported on a unit 

level as is commonly (but not always) metered; the discrete units of time measurement for which 

the data is reported to EIA is insufficient for the purposes of this rule; there are occasions for 

which EIA alters reported data prior to publication. Many owners and operators of EGUs also 

report net generation to NERC via GADS. This rule does not impose a significant cost to install 

meters to measure net generation on this industry.

As stated in section VIII.F.1 of the preamble, the EPA agrees with commenters that the reporting 

of net energy output via ECMPS is the preferred approach. EPA recognizes that there are 

technical challenges in apportioning auxiliary loads at facilities having multiple EGUs, 

especially during periods of time when one or more units are operating and one or more units are 

not producing power, yet auxiliary loads are supplying energy to multiple units. EPA is 

committed to work with states, tribes, and owners and operators of EGUs to implement this rule, 

especially as it relates to the measurement and reporting of emissions and net energy output, the 

reporting of data via the Emissions Collection and Monitoring Plan System (ECMPS), and 

related changes to Data Acquisition and Handling Systems (DAHS). EPA is committed to work 

out these technical details in the reporting instructions and will provide default methods of 

apportionment and will allow for reasonable alternative methods of apportionment for infrequent 

operating scenarios involving multiple units (e.g., when some units are not producing power).

Regarding the comment about calibration of watt meters, the EPA is not requiring any quality 

assurance testing or protocols for calibration of watt meters in this final rule. EPA believes there 

are already sufficient incentives for owners and operators of EGUs to maintain the accuracy of 

equipment used to measure net generation. 

Regarding the comment about EGUs that cycle in response to change in grid demand, we are not 

creating any special net energy output monitoring provisions in the final rule for such units. For 

each operating hour, the owner or operator of an EGU subject to this rule is required to report 
60

emissions and net generation, regardless of whether the unit is “cycling”, that is generating net 

electricity at an increasing or decreasing power output. The final rule requires all auxiliary loads 

to be counted toward net generation, regardless if the nature of such loads (e.g. if the auxiliary 

load is associated with air pollution control equipment). To count only some auxiliary loads in 

the net generation calculation would make the measurement of net generation far more 

complicated and more difficult to implement. Also, excluding auxiliary loads associated with a 

specific type of equipment (i.e. air pollution controls) would mask information that could hinder 

improvements in actual emission rate performance of the electric system. The nature of an 

integrated electric grid is for generators to respond to demand for electricity. The grid operator 

or power control authority dispatches different EGUs to balance generation and demand. This 

rule requires the reporting of actual emissions and actual generation to determine the actual 

emission rate for all hours in which the EGU generating energy output. The final rule does allow 

units to report zero net generation when actual net generation is less than zero to prevent the 

reporting of negative net generation, which would otherwise penalize units by counting energy 

consumption not related to production of electricity against the EGU’s emission performance. 

Preventing the reporting of negative net generation when a unit is not operating is a much 

different scenario from the case when an EGU is “cycling,” increasing or decreasing its power 

output, but still has certain emissions and certain net generation. 

The following are summaries of the specific public comments under this comment:

Commenters stated that, regarding monitoring and reporting of electric output, EGUs already are 

required to record and report hourly gross unit load from fuel combustion under Part 75. 40 

C.F.R. sections 72.2 (defining unit load), 75.57(b)(3) (requiring recording of hourly gross unit 

load), and 75.64(a)(2) (requiring reporting of recorded values). The commenters stated that as a 

result, all existing EGUs already measure and record gross MWs for all generation. The 

commenters stated that in order to facilitate reporting under state plans, EPA proposes that 

affected EGUs also could report hourly net electric generation under Part 75 via ECMPS. 

Commenters stated it is not clear whether EPA is proposing that Part 75 be revised to simply 

provide a mechanism for such reporting in the event a state chooses to require or allow it, or 

whether EPA is suggesting that sources reporting under Part 75 be required to report net electric 

generation. The commenters stated they would oppose the latter requirement in that EPA has no 

authority under section 111(d) to require reporting of net generation or output under Part 75. 

Commenters stated that a power generation facility with multiple units currently typically 

measures gross MWe from each electrical generator hourly, and station net MWh daily; the EGU 

to generator relationship is not 1:1 at all facilities, so converting between net load and gross load 

would be a technical challenge. The commenters stated that design of power station electrical 

distribution, if metered and used to correct gross to net, would tend to reduce a units net MW 

reported load when other EGUs at the facility were in startup or maintenance mode (drawing 

measureable power, like running boiler fans during boiler inspections) without producing power; 

also units that add advanced pollution control projects for other regulatory compliance, which 

reduce available net load, would also become the highest CO2e/Net MW emitters. 

Commenters stated that they do not support adding net load reporting to ECMPS as an option as 

it would require adding an "Electrical Monitoring Plan" to support the hourly data elements in 

ECMPS. The commenters stated that this would also trigger QA event reporting for the power 
61

transducers. The regional transmission authorities already require calibrations for watt 

transducers. If this provision is implemented, we request that EPA reconsider the justification for 

the increased cost of dual reporting this information to different agencies. 

Commenters stated that if the monitoring of net electric output is required, they request that EPA 

allow EGUs to use existing equipment and methods for metering station service, and to 

apportion common station service to individual units using unit generation. The commenters 

stated the measurement of unit-specific net output can be complicated by the difficulty in 

measuring auxiliary energy consumption of numerous plant-specific devices. The commenters

stated that most plants do not have the internal electrical distribution system designed to 

distribute and measure internal usage on a unit basis, particularly when a significant percentage 

of house load is attributable to unit-common equipment. The commenters stated that if EPA were 

to require replacement of existing equipment to make it unit specific or to impose more stringent 

standards on existing equipment, EPA would need to revise its proposal to estimate and solicit 

input on the additional costs and burdens of such metering. 

Commenters stated that they support EPA's proposed approach to require that hours with no 

gross generation or gross generation less than auxiliary loads be reported as zero rather than a 

negative value; furthermore, the commenters requested that EPA consider provisions in the 

standard to ensure that units that cycle are not unfairly penalized. Commenters stated these 

EGUs, particularly those serving as backup to renewable generation or operating to serve 

reliability needs, should not be penalized for responding to an electric grid which cycles daily 

forcing units to cycle to follow the electrical load demand.

Commenters stated that state plans would need to require affected EGUs to monitor CO2 

emissions, and net energy output if applicable, in accordance with 40 CPR Part 75. The 

commenters stated that 40 CFR 75 does not require monitoring net energy output. The 

commenters stated that emissions data submitted quarterly through the ECMPS tool is certified 

by the Designated Representative or Alternative Designated Representative or a delegated agent 

of the DR. The commenters stated that using ECMPS for this data would require modification of 

ECMPS to allow the 111(d) data to be certified by an appropriate authority, or designated agent 

of that authority. The commenters stated that reporting load under 40 CFR 75 to ECMPS is on a 

gross load basis per 40 CFR 75.57(b)(3); reporting net load would be an additional 

recordkeeping and reporting burden. Again, we request that EPA not require the monitoring of 

net energy output.

Commenters stated that the EPA proposal is constructed to penalize coal fired power by 

imposing limits on the net emissions rate of CO2 rather than the gross weight; coal plants are 

being penalized for power that is consumed by pollution control equipment recently mandated by 

other EPA rules.

Comment 2: Reporting of hourly generation

Response 2: As the commenters correctly state, under Part 75, the reported gross load in 

megawatts is an hourly rate. Therefore, if the load is reported as 100 MW and the unit operates 
62

for only 30 minutes in the hour (0.5 hr), the hourly generation is 50 megawatt hours. The final 

rule requires partial operating hours to be taken into account when calculating electrical 

generation and net energy output. Thus the partial hours will be taken into consideration in the 

final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that they are concerned that EPA has overlooked important details regarding 

how generation already is being reported. The commenters stated that EPA has made clear in its 

ECMPS Reporting Instructions for Emissions, the value reported under Part 75 represents an 

hourly rate and not the total load for the hour and that, for hours of partial operation, the value 

already reported under Part 75 will not represent the actual output for that hour (see ECMPS 

Emissions Reporting Instructions section 2.4). The commenters stated that, similarly, units on 

common stacks report the weighted sum of the hourly unit loads for all units that exhaust through 

the stack and that reported steam load for an hour is reported at the measured temperature and 

pressure (i.e., is not corrected to ISO conditions). The commenters stated that EPA's Proposed 

Guidelines, on the other hand, require calculation and use of actual electrical output for each 

hour and useful thermal energy relative to standard ambient temperature and pressure conditions. 

The commenters stated that if EPA intends sources to include partial unit operating hours in state 

compliance calculations, the values already being reported under Part 75 would need some 

adjustment for use in compliance calculations. Commenters stated EPA suggested as much with 

respect to output in its proposal to require that EGUs with common stacks or multiple stacks 

monitor stack operating time; as a result, EPA should clarify whether it intends that partial hours 

be included in state calculations; and, if EPA anticipates that states rely on data reported to 

ECMPS, EPA must address the discrepancies.

Comment 3: Use of existing reporting mechanisms

Response 3: The final rule requires the CO2 emissions data to be reported electronically 

according to §75.64(a), and the compliance calculations for §111(d) must use these data. 

However, a separate report must be submitted to the State that includes hourly data among other 

things, in order to document compliance with the rate-based or mass-based standards under 

111(d). However, the report for mass-based standards can be simplified if the compliance period 

is a discrete number of calendar years (e.g., one or three). Then, the cumulative annual CO2

mass emissions reported in the part 75 electronic data report for each year of the compliance 

period may be reported in lieu of reporting the hourly data for those years.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA indicates that annual reporting requirements by affected EGUs of 

CO2 emissions and useful energy output could be fulfilled under 40 CFR Part 75 through EPA's 

existing reporting mechanisms using EPA's Emission Collection and Monitoring Plan System 

(ECMPS). The commenters stated that they support using existing reporting mechanisms for cost 

savings and data consistency, instead of submitting an additional, separate report as this will 

minimize duplicative reporting requirements and ease the burden on affected EGUs. The 
63

commenters stated that they also expect to use existing reporting mechanisms where possible to 

allow non-EGU affected entities to comply with reporting requirements. 

The commenters stated that existing reporting mechanisms should fulfill the requirement for 

annual, electronic reporting accessible to the states, EPA, and the public; any additional reports 

from affected entities submitted pursuant to the 111(d) plan, other than those required under 

other applicable NSPS provisions or Part 75, should be submitted to the states for inclusion in 

annual reports to EPA. The commenters stated that if EPA wants this information to be made 

available electronically to the public, EPA should request funding from Congress to develop and 

operate a reporting platform.

Comment 4: Failure to report all electrical generation and thermal energy

Response 4: The commenters are correct in observing that not all NGCC units are following 

EPA’s guidance for reporting gross electric generation. To address this, the Agency is 

considering Part 75 rule revisions to make reporting of the steam turbine generation or steam 

energy mandatory. However, the §111(d) rule does require the reporting of all net electric

output and useful thermal output. Therefore, for this rule, NGCC units must report net steam 

turbine generation and steam energy, regardless of how they report gross load under Part 75.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA suggests specific changes to the Part 75 reporting requirements to 

explicitly require reporting of all electrical generation and thermal energy provided by EGU 

required to report the EPA Clean Air Markets Division (CAMD) under Part 75; the suggested 

changes are reasonable and will help clarify an issue that has arisen with some of their NGCC 

plants. The commenters stated that despite EPA guidance indicating EPA's preferred approach, 

we have NGCC units that have failed to report their steam turbine generation or steam energy to 

CAMD; any change to the Part 75 reporting requirements that clarify how this electrical output is 

to be reported will improve the consistency of the date reported to the CAMD database. The 

commenters stated that their experience indicates that most NGCC unit owner/operators do not 

report electricity produced by the steam turbine, or do not apportion the steam turbine output 

when two combustion turbines produce steam for use in one steam turbine. The commenters

stated that EPA seems to be proposing that these changes be made within this Part 60 rule 

proposal; however, these changes should be made in Part 75, so as to be applicable to all 

generation facilities including those that are not subject to this existing EGU rule.

Comment 5: Oppose reporting both electrical generation and useful thermal output

Response 5: The EPA disagrees with the commenters in that we reject the notion that EGU’s 

functioning as cogeneration facilities should be exempted from compliance with reporting 

requirements of this rule. In tracking the net energy output from an EGU it is important to 

consider all cogeneration activities as those may represent a significant and not necessarily static 
64

portion of the overall energy output from the EGU. The EPA is finalizing this rule to track CO2 

emissions from EGU’s in terms of tons per net electric output and, for cogeneration units, in 

terms of tons per total net energy output. Additional monitoring of parameters needed to 

calculate useful thermal output is necessary to determine total net energy output where 

cogeneration is a portion of the unit operation. EGU’s functioning as cogeneration facilities are 

subject to this rulemaking and must provide total net energy output, which includes any useful 

thermal output for their cogeneration beyond net electrical generation measured in megawatt-hr. 

The following are summaries of the specific public comments under this comment:

Commenters stated that they do not support reporting both the electrical generation and the 

useful thermal output for cogeneration facilities; this is not a fair reporting burden on 

cogeneration facilities when other facilities that produce thermal energy, but not electricity, are 

not counted. The commenters stated that additionally, given the small number of cogeneration 

facilities, the additional effort in recordkeeping provides very little benefit in driving down CO2 

emissions.

7.5.7 Reporting of monitoring plan data and quality assurance testing data

This section addresses comments received on reporting of monitoring plan data and quality 

assurance testing data.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Monitoring plan

Response 1: The commenters are correct in stating that this rule requires each monitoring 

system meet the applicable certification and quality assurance procedures in 75.20 and 

Appendices A and B rather than Appendices B and D. The final rule corrects a mistake in the 

proposed rule, which referred to Appendices B and D. 

Additional equipment used to meter net generation is not required to be identified in the sitespecific electronic monitoring plan under §75.53 (g). 

Regarding the metering of net electricity and the QA/QC requirements for net meters, the EPA 

believes that the vast majority of units have sufficient watt meters to report net generation. Net 

generation is currently reported to EIA by approximately 92 percent of respondents to the EIA923 survey. EPA requested comment on the specification of ANSI 0.2 class watt meters and 

received few comments on this matter. Regarding the comments about costs to install sufficient 

watt meters, not enough supporting documentation was submitted evaluate commenters’ 

assertions. Regarding the proposed ANSI standard for watt meters, commenters did not provide 

any suggested alternatives to this standard in order to ensure consistent measurement of net 
65

electricity, which is essential to ensure that all parties are reporting this key compliance metric 

on a consistent basis. The fee to access the ANSI standard is nominal and should not have been 

a barrier for this industry to evaluate the standard. Therefore, in the final rule, EPA is requiring 

use of ANSI 0.2 class meters to measure and report net electric generation. However, to ensure 

that the monitoring requirements for net electric output are not overly burdensome at a facility, in 

the final rule, EPA is allowing a facility to request alternative monitoring under 40 CFR 60.13(i) 

to alleviate unreasonable costs or to allow for delayed installation of meters during the next 

planned period of downtime. States and tribes have the flexibility to require more stringent 

monitoring requirements for watt meters in their state plan submissions. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA proposes to require preparation of a site-specific monitoring 

plan consistent with 40 C.F.R. 75.53(g) and (h) and that each monitoring system meet the 

applicable certification and quality assurance procedures in section 75.20 and Appendices B and 

D to part 75. (The commenters stated that it appears that the references to Appendices B and D 

are incorrect and the sentence should read Appendices A and B.) The commenters stated that 

they support the use of Part 75 for preparation of a monitoring plan for systems to measure and 

record CO2 mass emissions and submission of that plan to ECMPS; however, they do not 

believe that there is any benefit to including equipment used to measure electric and energy 

output in the Part 75 monitoring plan or to requiring additional QA/QC for that equipment. The 

commenters stated that EGUs already have sufficient incentives to ensure that their equipment 

for measuring output is accurate, and the EPA has not provided any information to suggest that 

additional quality assurance is warranted. The commenters stated that they also believe that any 

increase in accuracy would be dwarfed by other sources of allowed error in the overall 

measurements that cannot be eliminated; on the other hand, the resources necessary to track such 

equipment, to purchase and install new equipment if necessary to meet new accuracy standards, 

and to perform such testing would be significant.

Comment 2: Commenters request EPA to minimize the number of new monitoring 

requirements and/or coordinate existing monitoring requirements that EGUs face with those in 

the final rule. 

Response 2: Regarding the elimination of current Part 75 monitoring procedures, the EPA has 

determined that the vast majority of the affected EGU’s currently utilize CEMs or the excepted 

monitoring methodologies in Appendices D and G for oil and gas fired units when determining 

CO2 mass emissions. Therefore it is not burdensome or unreasonable to require affected EGU’s 

to either utilize CEMs or Appendices D and G (specifically Equation G-4) to determine CO2 

mass emissions. Furthermore, because the CO2 mass emissions data in this rulemaking are used 

for compliance determinations, rather than for purely informational purposes, the most accurate 

measurement methods available should be required. 

EPA has clarified in the final rule that the use of data substitution is not allowed for a rate based 

demonstration. Rather only “valid operating hours”, as defined in 40 CFR 60.5820 may be used 

for compliance purposes. However, for a mass-based demonstration, a complete data record is 
66

required, i.e., CO2 emissions must be reported for all operating hours. Therefore, operating 

hours in which substitute data values are reported must be included in the calculations.

The following are summaries of the specific public comments under this comment:

Commenters stated that according to EPA, monitoring under 40 CFR Part 75 and reporting to 

EPA's Emission Collection and Monitoring Plan System (ECMPS) would satisfy the monitoring 

and reporting requirements in the Proposed Guidelines at Subpart UUUU Section 60.5805. The 

commenters noted that the Proposed Guidelines generally recognize the adequacy of Part 75 data 

by proposing that states allow use of two of the four options allowed under Part 75, and by 

requiring compliance with Part 75 monitoring plan and quality assurance and quality control 

(QA/QC) requirements. However, in some instances, the commenters stated that the EPA is 

proposing to require that states impose new requirements, some of which could increase burden 

and stringency beyond existing requirements once state plans are implemented.

The commenters supported the EPA's proposal that states rely on Part 75 monitoring procedures 

but objected to the proposed elimination of one of those options and imposition of additional 

requirements for existing units. The commenters stated that the EPA has provided no 

justification for requiring states to impose on EGUs monitoring that is different from, let alone 

more stringent than, Part 75.

In addition, the commenters expressed concern about the Agency's failure to make clear that use 

of Part 75 missing data substitution procedures is not appropriate in compliance calculations. The 

commenters stated that the proposed GHG NSPS for new and for modified and reconstructed 

sources under CAA Section 111(b), made clear that Part 75 missing data substitution procedures 

cannot be used. The commenters requested that the EPA provide the same clarification in the 

final rule.

Commenters stated that the final section 111 rules for carbon emissions from the power sector 

should ensure consistent monitoring and recordkeeping requirements and rule definitions to 

facilitate the interaction of multiple permitting requirements: the CO2 standard for new sources 

under 111(b), the CO2 standard for modified and reconstructed under 111(b), and the federal 

guidelines for existing sources under 111(d). Commenters were concerned that inconsistencies 

between these inter-related regulations could yield redundant or conflicting requirements in 

permits. Commenters also stated that the final rule should also correct any inconsistencies in rule 

definitions among the various rules, such as the definitions of "facility", "affected source", and 

what constitutes a "reconstruction" because consistent rule definitions are especially important in 

the permitting process for stationary sources.

Commenters recommended that EPA should ensure consistent monitoring and recordkeeping 

requirements and rule definitions under multiple federal rules. Commenters stated that the 

interaction of multiple permitting requirements under the two 111(b) rules for new sources and 

modified/reconstructed sources and the 111(d) existing source proposal will be complex. 

Commenters recommended that EPA the monitoring and recordkeeping of various regulatory 

programs, and consistently use the monitoring and recordkeeping protocols currently in place to 

demonstrate compliance with CO2 regulations in order to avoid redundant or conflicting 

requirements. Commenters recommended that the EPA also correct any inconsistencies in rule 
67

definitions among the various rules, such as the definitions of "facility", "affected source", and 

what constitutes a "reconstruction" because consistent rule definitions are especially important 

for permitting.

7.5.8 Monitoring of stack gas volumetric flow rate

This section addresses comments received on monitoring of stack gas volumetric flow rate.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Most accurate RATA reference method for specific stack configurations and use of 

a computational adjustment

Response 1: In the final rule, EPA, is requiring plans to include monitoring methodologies that 

are at least as stringent as the Acid Rain Program monitoring under Part 75, as appropriate. Part 

75 monitoring is currently the underlying data source for many of the EPA pollutant programs 

and has gone through multiple rulemakings to ensure that the quality of data is acceptable and 

sufficient for EPA programs. In this final rule the EPA does not require any “adjustment factors”

to be applied to volumetric flow rate data, such as those that were proposed, nor does the final 

rule impose any restrictions or requirements on the use of specific flow rate reference methods

during relative accuracy test audits (RATAs). The final rule also does not require the use of 

calibrated Type-S pitot tubes rather than the default Type-S pitot tube coefficient of 0.84 when 

conducting reference method testing for RATA purposes.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA proposes to require that if an EGU chooses to use Method 2 to 

perform the required RATA on a flow monitoring system, the EGU must use a calibrated Type-S 

pitot tube (rather that the default Type-S pitot). Proposed Subpart UUUU section 

60.5805(a)(2)(v). The commenters do not oppose such a requirement; however, EPA also solicits 

comment on requiring use of what it calls the most accurate RATA reference method for specific 

stack configurations when performing tests on stack gas flow monitors, and use of a 

computational adjustment when an EGU changes RATA reference methods. 79 Fed. Reg. at 

34,913-14. Approved methods for flow RATAs under Part 75 include Methods 2F, 2G, 2H, and 

conditional test method (CTM) 041. The commenters stated that Method 2F uses a three 

dimensional (3-D) probe to determine yaw angle, pitch angle, axial velocity, and volumetric 

stack flow and was developed to eliminate high bias of stack flow measurements in stacks with 

cyclonic flow; Method 2H and CTM-041 provide procedures for adjusting stack flow 

measurements to correct for velocity decay near a stack or duct wall that is not present in the 

measurements taken elsewhere in the stack. 
68

The commenters stated that in the Part 75 GHG Guideline TDS at 7-8, EPA expresses concerns 

that allowing sources to use these alternative methods (and in particular allowing EGUs to 

change methods over time) could lead to inconsistencies between emissions or heat input values. 

The commenters stated that to avoid this result, EPA solicits comment on whether it should 

require use of the more accurate methods, and whether it should develop adjustment factors for 

normalizing data when an EGU opts to use a different reference method to calibrate its stack 

flow monitor during a RATA. The commenters stated that although EPA must allow use of 

Methods 2F and 2H (or CTM-041), EPA should not require either one. The commenters stated 

that first, not all EGUs will obtain more accurate measurements using these methods; EGUs with 

axial flow and smooth stack liners may not experience any improvement in flow measurements 

from those methods, which are designed to correct for non-axial flow and wall effects caused by 

friction. The commenters stated that although the methods can provide more accurate (and 

lower) stack flow measurements for other EGUs, they also impose additional burdens; any EGU 

concerned about overestimation of measured flow due to cyclonic flow conditions, or wall 

effects, can opt to use the methods, but there is no basis to require their use. The commenters

stated that EPA also should allow use of Method 2G, which uses a 2-dimensional probe to 

measure yaw angle (but not pitch) and near-axial velocity and also can provide more accurate 

(i.e., lower) flow measurements than Method 2 under some conditions. The commenters stated 

that Method 2G is often performed using an auto-probe, which can reduce testing time. The 

commenters stated that Part 75 allows use of Methods 2, 2F, 2G, 2H, and CTM-041 and that 

EGUs should be allowed to choose which version of the flow method is best for the particular 

application and should not be required to perform 3-D testing where it is not needed. 

Commenters requested that EPA eliminate the most accurate RATA reference method for 

specific stack configurations when performing tests on stack gas flow monitors, and use of a 

computational adjustment when an EGU changes RATA reference methods. The commenters

stated that although EPA must allow use of Methods 2F and 2H (or CTM-041), EPA should not 

require either one; although these methods can provide more accurate (and lower) stack flow 

measurements for certain EGUs, they also impose additional financial burdens. The commenters

stated that more accurate methods are typically conducted with an auto-probe system. 

Commenters stated leasing a United Sciences auto-probe system could add $100,000 to a single 

flow RATA; if the test is not done with an auto-probe, then the duration of the test will be 

extended and reduce the accuracy of the flow profile from a single test run. The commenters

stated that if the more accurate test methods are mandated, then EPA needs to consider the 

additional cost burdens for each unit. 

Commenters stated that because of these flexibilities regarding use of optional reference methods 

used in flow RATAs, the EPA is considering two approaches to ensure consistent and accurate 

accounting of stack gas volumetric flow measurements. The commenters stated that the first 

approach is the development of adjustment factors for normalizing data when the reference 

methods change; the second approach that the EPA is considering is requiring the use of the most 

accurate reference method taking into account the specific configuration of the stack. The 

commenters stated that EPA's proposed first correction would not work; the percent of change 

from Method 2 to Method 2P (3-D test) or 2G (2-D test) is unit specific and is directly 

proportional to the amount of angular velocity in the stack. The commenters stated that if EPA 

applied this correction, then a unit with no angular flow would see no improvement going to a 2-

D or 3-D flow method, but would have to apply EPA's correction and result in over-reporting 
69

CO2 emissions (i.e. compensating for a flow reduction that did not occur); in addition, a change 

in the flow RATA results could also be caused by increasing from the minimum number of 

traverse test points in a stack to a higher number of traverse points, or applying a wall factor 

correction (Method 2H). The commenters stated that it would therefore be impractical to try and 

regulate an anti-correction to EGUs that increase their flow system accuracy, without taking a 

case-by-case approach; even with a case-by-case approach, it would be hard to identify exactly 

how much difference was due to an adjustment of test methodology alone.

Commenters stated that although the EPA must allow use of Methods 2F and 2H (or CTM-041), 

it should not require the use of either one. The commenters stated that first, not all EGUs will 

obtain more accurate measurements using these methods; EGUs with axial flow and smooth 

stack liners may not experience any improvement in flow measurements from either method, 

each of which is designed to correct for non-axial flow and wall effects caused by friction and 

although the methods can provide more accurate (and lower) stack flow measurements for other 

EGUs, they also impose additional burdens. The commenters stated that any EGU concerned 

about overestimation of measured flow due to cyclonic flow conditions, or wall effects, can opt 

to use either method; there is no basis, however, to require their use. The commenters stated the 

EPA also should allow use of Method 2G, which uses a 2-dimensional probe to measure yaw 

angle (but not pitch) and near-axial velocity and can provide more accurate (i.e., lower) flow 

measurements than Method 2 under some conditions. The commenters stated that Method 2G is 

often performed using an auto-probe, which can reduce testing time. The commenters stated that 

EGUs should be allowed to choose which version of the flow method is best for the particular 

application and should not be required to perform 3- D testing where it is not needed.

Commenters stated that, regarding the EPA's suggestion that it develop "adjustment factors" that 

would be applied if an EGU changed flow methods, the EPA has not provided sufficient 

information to justify such a requirement; the EPA's example - that a unit that transitions from 

Method 2 to Method 2H when performing flow RATAs would apply a percentage reduction of 

baseline data - is unclear. The commenters stated that specifically, it is not clear what data the 

EPA is suggesting would be altered - the baseline data used in setting the state goal or data used 

to determine compliance under an approved state plan. The commenters stated that EPA's 

suggestion that data would be reduced by some percentage suggests that the EPA's reference is to 

baseline data; but that would seem to require recalculation of the state goal every time an EGU 

changed flow RATA methods. The commenters stated that the altering of data collected under 

Part 75 could have serious consequences and the commenters would object to the use of such 

altered data for any other program. The commenters stated that EPA also does not provide a 

timeframe for this requirement; if the EPA is suggesting that the compliance data - not baseline 

data - be altered, there would be no adjustment needed for data collected prior to implementation 

of the state plan, or for changes in methods made before 2012. The commenters stated that 

finally, the EPA has not provided any information to inform how it might calculate an 

adjustment factor; since the impact of a change in flow methods would be site specific, the EPA 

presumably would have to require a comparison of flow data collected with the CEMS before 

and after the RATA, but that is hardly a concept that is sufficiently developed to allow for 

meaningful comment.

Commenters stated that in short, the two sentences of vague conceptual language in the Part 75 

TSD is not sufficient to inform commenters of the scope or impact of the EPA's proposal and if 
70

the EPA intends to pursue such a requirement, it must issue a rulemaking proposal that fully 

explains what kind of adjustment it is proposing and specifically how the percentage value would 

be determined. The commenters stated that the vague concepts the EPA has discussed are 

troubling because they suggest that the EPA might set a Guideline that is in effect a moving 

target, not just for an individual EGU but for all the interrelated sources and entities that are tied 

to a state's implementing regulations, and even beyond the borders of a state where the 

recalculated state emissions goal would have repercussions for any agreements with other states. 

The commenters recommended that the EPA not pursue this issue of adjustments to baseline 

calculations.

Commenters stated that under this proposal, U.S. EPA is not defining what "most accurate" 

means or who determines the "most accurate" RATA test method. The commenters stated that a 

requirement that leads to "most accurate" is unwise, indefensible, and will result in a never 

ending pursuit of "more accurate" equipment. The commenters stated that because CO2 is such a 

ubiquitous pollutant, and emitted in such large quantities, a "most accurate" standard is not 

necessary for purposes of determining CO2 emissions from point sources. The commenters

stated that the EPA also does not specify who would be responsible for developing any 

"computation adjustment" when there is a change in test methods; the commenters stated that it 

should be the states determining when and how an adjustment is applied. The commenters stated 

that if EPA is worried that the slight variances that may show up when comparing flow numbers 

measured using the various allowed test methods are skewing data a significant amount, EPA 

should adjust the approved test methods. The commenters stated that because there are multiple 

flow measurement test methods that are defined as reference methods, and available equally for 

use in Part 75 and for cap and trade programs, the commenters questioned why does the addition 

of CO2 require the use of even more accurate measurements. The commenters stated that the 

resolution of data that is seemingly being required would lead one to believe that no 

computational adjustments or standardized work conversions should be allowed, as, depending 

on the particular emissions unit being monitored, this could bias the data either high or low. The 

commenters asked will extensive emission unit specific testing be required to develop specific 

conversions and adjustments necessary for each subject emissions unit. The commenters stated 

that this topic needs more consideration by the EPA and an additional proposal. The commenters

stated that the ability of both the reference method and the facility's monitoring systems to 

measure flow or CO2 accurately may also be dependent on many factors, some of which could 

vary from day to day. The commenters stated that these variances could be as simple as a change 

in the operator, and how the operator runs the emissions unit; other factors could include 

barometric pressure, the amount of moisture in the fuel supply, and the ambient temperature.

Commenters stated that with regard to requiring a certain stack gas flow monitor RATA 

reference method, the commenters' preference is to continue to allow the affected EGU to make 

that determination. The commenters stated that they believe that most EGUs already use the 

more accurate RATA reference methods so the adjustment would only affect a few EGUs and 

need to only apply during the first affected compliance period. 

Commenters stated that, regarding the alternative reference methods provided in Part 75 that are 

designed to reduce or remove over-reporting of gas flow by accounting for cyclonic flow and 

wall effects in stacks for units for which these conditions are present, these alternatives are 

currently options under Part 75 and the commenters requested that EPA retain them as options in 
71

the guideline rules and not include them as requirements. The commenters stated that making 

optional Flow RATA reference methods mandatory should not be required since the optional 

Methods can only be performed with a significant test cost increase as discussed above.

Comment 2: Adjustment factor

Response 2: The final rule does not require any adjustment factors to be applied to the 

volumetric flow rate reference method data obtained during a RATA, when the reference method 

is different from the method used in the previous RATA(s).

The following are summaries of the specific public comments under this comment:

Commenters stated that regarding EPA's suggestion that it develop adjustment factors that would 

be applied if an EGU changed flow methods, EPA has not provided sufficient information to 

comment on the reasonableness of such a requirement. The commenters stated that EPA's 

example - that a unit that transitions from Method 2 to Method 2H when performing flow 

RATAs would apply a percentage reduction of baseline data - is unclear; specifically, it is not 

clear what data EPA is suggesting would be altered - the baseline data used in setting the state 

goal or data used to determine compliance under an approved state plan. The commenters stated 

that EPA's suggestion that data would be reduced by some percentage suggests that EPA's 

reference is to baseline data, but would that require recalculation of the state goal every time an 

EGU changed flow RATA methods. The commenters stated that the altering of data collected 

under Part 75 could have serious consequences and the commenters would object to use of such 

altered data for any other program. 

The commenters stated that EPA also does not provide a timeframe for this requirement; if EPA 

is suggesting that the compliance data - not baseline data - be altered, there would be no 

adjustment needed for data collected prior to implementation of the state plan, or for changes in 

methods made before 2012. The commenters stated that EPA has not provided any information 

to inform how it might calculate an adjustment factor; because the impact of a change in flow 

methods would be site specific, EPA presumably would have to require a comparison of flow 

data collected with the CEMS before and after the RATA, but that is hardly a concept that is 

sufficiently developed to allow for meaningful content. The commenters stated that in short, the 

two sentences of vague conceptual language in the TSD is not sufficient to inform commenters 

of the scope or impact of EPA's proposal and if EPA intends to pursue such a requirement, EPA 

must issue a rulemaking proposal that fully explains what kind of adjustment EPA is proposing 

and specifically how the percentage value would be determined.

Commenters stated that the second proposal to require a computation adjustment when an EGU 

changes RATA reference test methods is not explained in either Section VIII.D.9 of the 

preamble of the proposed rule or in the Part 75 Monitoring and Reporting Considerations 

Technical Support Document; the language in the TSD is very similar to the language in the 

proposed rule. The commenters stated that EPA needs to provide a more complete guidance 

document indicating how the adjustment factors will be developed and implemented.
72

Commenters stated that regarding the two possible adjustments to the Part 75 RATA 

requirements for steam EGU stack gas flow monitors that can affect reported CO2 emissions, the 

first possible adjustment would be to require use of the most accurate RATA reference method 

for specific stack configurations, while the second possible adjustment would be to require a 

computation adjustment when an EGU changes RATA reference methods. The commenters

stated that although the proposed adjustments are reasonable, EPA should continue to allow the 

source to choose among the current methods and procedure options; the current procedures are 

sufficient to ensure the data is accurate enough to meet the rule objectives.

Comment 3: Requiring the use of the most accurate RATA reference test methods for flow 

monitors, as expressed in Section VIII.D.9 of the preamble of the proposed rule, will 

unnecessarily increase costs if applied to all sources and for all tests.

Response 3 The final rule does not require any adjustment factors to be applied to the 

volumetric flow rate reference method data obtained during a RATA, when the reference method 

is different from the method used in the previous RATA(s). Based on the possible changes to 

volumetric flow data from year to year and recognizing that these changes are not necessarily 

on a calendar year basis but rather multiple methods could impact a single calendar year, EPA 

in the GHG Mitigation Measures TSD (Chapter 2, Section 2.6.6) addresses the issue of flow 

monitoring changes and their impact on the heat rate analysis used to determine the CO2 

reductions attributable to potential heat rate improvements at coal-fired EGUs. Also, the final 

rule places no restrictions on the reference method that may be used for the flow RATAs. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the proposal to require the use of the most accurate RATA reference test 

methods for flow monitors, as expressed in Section VIII.D.9 of the preamble of the proposed 

rule, will unnecessarily increase costs if applied to all sources and for all tests. The commenters

recommended that the requirement be changed to require only the use of the most accurate 

RATA reference test methods for flow monitors during initial testing.

The commenters referenced the following discussion in Section VIII.D.9 of the preamble and the 

"Part 75 Monitoring and Reporting Considerations" Technical Support Document: 

"However, we are seeking comment on two possible adjustments to the Part 75 

Relative Accuracy Test Audit (RATA) requirements for steam EGU stack gas flow 

monitors that can affect reported CO 2 emissions. The first possible adjustment 

would be to require use of the most accurate RATA reference method for specific 

stack configurations, while the second possible adjustment would be to require a 

computation adjustment when an EGU changes RATA reference methods. The 

rationale for these possible adjustments is described further in the Part 75 

Monitoring and Reporting Considerations TSD available in the docket."
73

The commenters explained that the current Acid Rain Program (40 CFR Part 75) allows a facility 

to use either standard reference Test Method 2, or Test Methods 2F, 2G, 2H and CTM-041 to 

measure the stack gas flow rate. The commenters stated that Test Method 2F and 2G enable the

tester to measure non-axial flow or cyclonic flow more accurately. The commenters stated that 

some stacks do have significant cyclonic flow, but most do not. The commenters stated that Test 

Methods 2F and 2G are much more complicated and expensive to conduct. The commenters

stated that using these methods on stacks without cyclonic flow will not increase the accuracy of 

the flow measurements, but will increase the cost of conducting the test. The commenters stated 

that Test Methods 2H and CTM-041 are used to measure the wall effect on circular and 

rectangular stacks. The commenters stated that the velocity in a stack decays or decreases as a 

measuring probe approaches the wall (i.e., the velocity at the wall has to be zero). The 

commenters stated that the rate of decay will be affected by the roughness of the stack wall. The 

commenters stated that Test Method 2H allows a facility to use a default wall effect factor in 

place of actually measuring the decay near the stack wall. The commenters stated that the use of 

a wall effect factor will reduce the overall net flow rate in the stack.

The commenters recommended that the use of Test Methods 2F and 2G not be required for all 

testing. The commenters suggested that a facility should be required to conduct an initial series 

of tests to determine if non-axial or cyclonic flow is present and if there is a benefit to using the 

more accurate methods over the standard Test Method 2. The commenters suggested that if the 

test data supports using the more accurate test methods, then require the facility to use them for 

subsequent testing. 

The commenters also recommended that the use of Test Method 2H and CTM-041 should also 

be optional, as it is today.

Comment 4: Eliminate the requirements to use "the most accurate RATA reference method for 

specific stack configurations" when performing tests on stack gas flow monitors, and use of a 

"computational adjustment" when an EGU changes RATA reference methods.

Response 4: The final rule does not require any adjustment factors to be applied to the 

volumetric flow rate reference method data obtained during a RATA, when the reference method 

is different from the method used in the previous RATA(s). Also, the final rule places no 

restrictions on the reference method that may be used for the flow RATAs. 

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA solicits comment on requiring use of what it calls "the most 

accurate RATA reference method for specific stack configurations" when performing tests on 

stack gas flow monitors, and use of a "computational adjustment" when an EGU changes RATA 

reference methods. The commenters requested that this requirement be eliminated. The 

commenters stated that currently approved methods for flow RATAs under Part 75 include 

Methods 2F, 2G, 2H, and conditional test method (CTM) 041. The commenters stated that in the 

Part 75 GHG Guideline TSD at 7-8, the EPA expresses concerns that allowing sources to use 

these alternative methods (and in particular allowing EGUs to change methods over time) could 
74

lead to inconsistencies between emissions or heat input values. To avoid this result, the 

commenters noted that the EPA solicits comment on whether it should require use of the more 

accurate methods, and whether it should develop adjustment factors for normalizing data when 

an EGU opts to use a different reference method to calibrate its stack flow monitor during a 

RATA. Although EPA must allow use of Methods 2F and 2H (or CTM-041), the commenters

suggested EPA should not require either one. The commenters stated that, although these 

methods can provide more accurate (and lower) stack flow measurements for certain EGUs, they 

also impose additional financial burdens. The commenters explained that the more accurate 

methods are typically conducted with an auto-probe system, and leasing a United Sciences "autoprobe" system could add $100,000 to a single flow RATA. The commenters stated that if the test 

is not done with an auto-probe, then the duration of the test will be extended and reduce the 

accuracy of the flow profile from a single test run. The commenters stated that EPA needs to 

consider the additional cost burdens for each unit if the more accurate test methods are 

mandated. 

The commenters noted that because of these flexibilities regarding use of optional reference 

methods used in flow RATAs, the EPA is considering two approaches to ensure consistent and 

accurate accounting of stack gas volumetric flow measurements, including (1) development of 

adjustment factors for normalizing data when the reference methods change (e.g., if a unit 

transitions from Method 2 to Method 2G when performing flow RATAs, a percentage reduction 

of baseline data could be applied) and (2) requiring use of the most accurate reference method 

taking into account the specific configuration of the stack.

The commenters stated that the EPA's proposed first correction would not work. The 

commenters noted that the percent of change from Method 2 to Method 2P (3-D test) or 2G (2-D 

test) is unit specific and is directly proportional to the amount of angular velocity in the stack 

(aka "cyclonic flow"). The commenters argued that if EPA applied this correction as stated, then 

a unit with no angular flow would see no improvement going to a 2-D or 3-D flow method, but 

would have to apply EPA's correction and result in over-reporting CO2 emissions (i.e. 

compensating for a flow reduction that did not occur). In addition, the commenters stated that a 

change in the flow RATA results could also be caused by increasing from the minimum number 

of traverse test points in a stack to a higher number of traverse points, or applying a wall factor 

correction (Method 2H). The commenters stated that it would be impractical to try and regulate 

an "anti-correction" to EGUs that increase their flow system accuracy, without taking a case-bycase approach, and even with a case-by-case approach, it would be hard to identify exactly how 

much difference was due to an adjustment of test methodology alone.

Comment 5: Allow the source to choose among the current methods and procedure options for 

conducting a Part 75 RATA.

Response 5: The final rule places no restrictions on the reference method that may be used for 

the flow RATAs. Also, the final rule does not require any adjustment factors to be applied to the 

volumetric flow rate reference method data obtained during a RATA, when the reference method 

is different from the method used in the previous RATA(s). 
75

The following are summaries of the specific public comments under this comment:

Commenters noted that EPA is seeking comment on two possible adjustments to the Part 75 

Relative Accuracy Test Audit (RATA) requirements for steam EGU stack gas flow monitors that 

can affect reported CO2 emissions. The commenters noted that the first possible adjustment 

would be to require use of the most accurate RATA reference method for specific stack 

configurations, while the second possible adjustment would be to require a computation 

adjustment when an EGU changes RATA reference methods. Commenters noted that the 

rationale for these possible adjustments is described further in the Part 75 Monitoring and 

Reporting Considerations TSD available in the docket. 

Commenters suggested that, although the proposed adjustments are reasonable, EPA should 

continue to allow the source to choose among the current methods and procedure options. The 

commenters stated that the current procedures are sufficient to ensure the data is accurate enough 

to meet the rule objectives.

Commenters stated that EPA did not define what "most accurate" means or who determines the 

"most accurate" RATA test method. The commenters contended that a requirement that leads to 

"most accurate" is unwise, indefensible, and will result in a never ending pursuit of "more 

accurate" equipment. The commenters stated that since CO2 is such a ubiquitous pollutant, and 

emitted in such large quantities, a "most accurate" standard is not necessary for purposes of 

determining CO2 emissions from point sources.

Commenters stated that EPA also did not specify who would be responsible for developing any 

"computation adjustment" when there is a change in test methods. The commenters believed it 

should be the states determining when and how an adjustment is applied. The commenters stated 

that if the EPA is truly worried that slight variances (e.g., that may show up when comparing 

flow numbers measured using the various allowed test methods) are skewing data a significant 

amount, then the EPA should adjust the approved test methods. The commenters noted that there 

are multiple flow measurement test methods that are defined as reference methods and available 

equally for use in Part 75 and for cap and trade programs. The commenters questioned why the 

addition of CO2 requires the use of even more accurate measurements. The commenters stated 

that the resolution of data that is seemingly being required would lead one to believe that no 

computational adjustments or standardized work conversions should be allowed because this 

could bias the data either high or low (depending on the particular emissions unit being 

monitored). The commenters questioned if extensive emission unit specific testing will be 

required to develop specific conversions and adjustments necessary for each subject emissions 

unit. The commenters stated that this topic needs more consideration by the EPA and an 

additional proposal. Aside from the judgment calls mentioned above as part of a reference 

method flow measurement that could potentially bias data one way or the other, the commenters

stated that the ability of both the reference method and the facility's monitoring systems to 

measure flow or CO2 accurately may also be dependent on many factors, some of which could 

vary from day to day. The commenters noted that these variances could be as simple as a change 

in the operator, and how the operator runs the emissions unit, while other factors could include 

barometric pressure, the amount of moisture in the fuel supply, and the ambient temperature.
76

Comment 6: EPA should provide a default Part 75 volumetric flow rate adjustment factor, but 

allow sources the flexibility of conducting optional reference method tests.

Response 6: The final rule places no restrictions on the reference method that may be used for 

the flow RATAs. Also, the final rule does not require any adjustment factors to be applied to the 

volumetric flow rate reference method data obtained during a RATA, when the reference method 

is different from the method used in the previous RATA(s). 

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA should provide a default Part 75 volumetric flow rate 

adjustment factor to affected 111(d) sources but also allow sources the flexibility of conducting 

optional reference method tests to more accurately determine wall/angular effects on volumetric 

flow rate. The commenters stated that the EPA should also publish supporting evidence for the 

default factor since the default volumetric flow rate adjustment factor since it will affect mass 

rate calculations of other pollutants.

7.5.9 Other

This section addresses comments received on other issues specific to 40 CFR Part 75.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics. 

Comment 1: Does not oppose CO2 CEMS but questions requirement to use CO2 CEMS rather 

than O2 CEMS 

Response 1: The final rulemaking does not prohibit any unit from utilizing an O2 concentration 

monitor from determining CO2 mass emissions in accordance with Part 75 provided that the unit 

does not use carbon separation. Regarding the exclusion of certain Part 75 monitoring 

procedures, the EPA has determined that the vast majority of the affected EGU’s currently utilize 

CEMs, as they are part of the Acid Rain Program, or the accepted monitoring methodologies in 

Appendices D and G for oil and gas fired units when determining CO2 mass emissions. 

Therefore it is not burdensome or unreasonable to require affected EGU’s to either utilize CEMs 

or Appendices D and G (specifically Equation G-4) to determine CO2 mass emissions. 

Furthermore, because the CO2 mass emissions data in this rulemaking are used for compliance 

determinations, rather than for purely informational purposes, the most accurate measurement 

methods available should be required.

The following are summaries of the specific public comments under this comment:

Commenters object to EPA not allowing the use of an O2 CEMS to obtain CO2 emissions.
77

Commenters stated that EPA proposes that states require existing EGUs that combust solid fuel 

(and to allow other existing EGUs) to monitor CO2 mass emissions using a CO2 concentration 

monitor, flow monitor, and (if applicable) a moisture monitoring system in accordance with Part 

75. Proposed subpart UUUU section 60.5805(a)(2)(i). The commenters stated that as an 

alternative, EPA proposes to allow EGUs that combust only liquid or gaseous fuel to determine 

CO2 mass emissions under the provision in Part 75, Appendix G section 2.3 that uses heat input 

determined under Part 75, Appendix D and a carbon-based F-factor to determine CO2 mass 

emissions. Id. at section 60.5805(a)(3). The commenters supported these options, but believe that 

EPA has unreasonably eliminated several other Part 75 options. 

The commenters stated they do not oppose requiring solid fuel-fired EGUs, or allowing other 

EGUs, to use CEMS; Part 75 and subpart Da already require solid fuel-fired units to use CEMS 

to determine compliance with other requirements. The commenters stated that they do not 

understand why EPA has specifically required use of a CO2 CEMS (and not allowed use of an 

O2 CEMS to obtain CO2) at an EGU that does not use carbon separation The commenters stated 

that both existing NSPS applicable to EGUs, subparts Da and KKKK, allow use of either a CO2 

concentration monitor or an O2 concentration monitor as the diluent monitor to calculate 

emissions in lbs per MMBtu; and, Part 75 explicitly allows use of an O2 concentration monitor 

to measure CO2 concentration to obtain CO2 mass emissions. The commenters stated that there 

is no valid reason not to allow both types of monitoring systems under this rule as well; although 

most coal-fired EGUs opt to use CO2 concentration monitors, there are valid reasons an EGU 

(particularly a gas- or oil- fired EGU) might prefer an O2 monitor. The commenters stated that 

oxygen analyzers generally cost less, are more stable, and are less affected by interferences (e.g., 

H2O and CO) that can impact CO2 measurements. The commenters stated that EPA could easily 

add an option for use of an O2 monitor simply by adding a reference to section 75.10(a)(3)(iii) in 

proposed subpart UUUU section 60.5805(a)(2). 

Commenters stated that EPA proposes that states require an affected EGU to monitor CO2 mass 

emissions by installing CO2 CEMS in order to directly measure CO2 concentrations in the

affected EGU's exhaust gas which are emitted into the atmosphere. The commenters believed

that EPA should not require the use of CO2 CEMS for affected facilities. The commenters stated 

that EPA also proposes that states require an affected EGU to install an exhaust gas flow rate 

monitoring system; if an affected EGU exclusively combusts liquid fuel and/or gaseous fuel, 

then the EGU, in the alternative, may determine CO2 mass emissions by using Equation G-4 in 

Appendix G to Part 75, which uses heat input determined under Part 75 Appendix D and a 

carbon-based F-factor to determine CO2 mass emissions. The commenters stated that while 

disputing EPA's legal authority for this proposal, they do not necessarily oppose EPA's proposed 

methods but is concerned that EPA has potentially eliminated other viable options. The 

commenters believed EPA should preserve the option to use O2 CEMS if desired. Commenters 

stated this option is already allowed under NSPS for subparts Da and KKKK. 

Commenters stated that the EPA is proposing the CO2 monitoring already conducted by most 

affected EGUs under 40 CFR Part 75, that is reported using the EPA's Emission Collection and 

Monitoring Plan System (ECMPS), would generally satisfy CO2 emission reporting 

requirements under this proposal. The commenters stated that the EPA may be over estimating 

the number of affected EGUs that may meet the monitoring requirements. The commenters
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stated that some of Ohio's combustion turbine stations do not have CO2 analyzers and are instead 

monitoring O2; this should be an adequate substitute for CO2 monitoring.

Comment 2: Wet vs dry basis

Response 2: In the final rule the Agency has added language that specifically allows sources to 

use Part 75 default moisture values and to petition the Administrator for site specific moisture 

values under 40 CFR 75.66. Regarding the use of an O2 monitor instead of a CO2 monitor, the 

final rule allows it provided that the unit does not use carbon separation.. 

The following are summaries of the specific public comments under this comment:

Commenters were concerned that EPA eliminated the option to use default moisture values.

Commenters stated that they were also concerned that the proposed language requiring EGUs 

that measure CO2 concentration on a dry basis to "install, certify, operate, maintain, and 

calibrate a continuous moisture monitoring system" under section 75.11(b), Proposed Subpart 

UUUU section 60.5805(a)(2)(i), could be interpreted as eliminating the option in section 

75.11(b)(1) to use appropriate default moisture values rather than installing and calibrating a 

monitoring device. The commenters stated that the Part 75 default moisture values for coal and 

wood were derived from the Agency's own evaluation of data in a May 26, 1999 rulemaking in 

which the Agency determined that they were sufficiently conservative to ensure no underreporting. The commenters stated that EPA approved the default moisture value for natural gas 

(boilers only) in (January 24) 2008 based on data submitted to EPA. The commenters stated that 

they can think of no reason why EPA would eliminate this option for existing units, and hope 

that the reference to installing and calibrating systems was not intended to eliminate use of the 

default values. 

The commenters stated that if the Agency has a reason for eliminating the O2 monitoring and 

moisture default value options for either coal-fired EGUs or liquid and gas-fired EGUs, EPA 

must issue a rulemaking proposal identifying that reason so that they can comment on the 

Agency's rationale. The commenters stated that because existing EGUs still will need to comply 

with the ARP, eliminating these options in state plans effectively eliminates them in Part 75.

Commenters stated that EPA also mentions the measurement of CO2 concentrations on a "dry 

basis" through installing, certifying, operating, maintaining, and calibrating a continuous 

moisture monitoring system; this language should not eliminate the option to measure CO2 

concentration on a "wet basis" under Part 75.

Comment 3: Use of laser devices to measure stacks

Response 3: The EPA agrees with the commenters and the final rule does not include a 

requirement to make measurements of stack dimensions using a laser device. The following are 

summaries of the specific public comments under this comment:
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Commenters stated that EPA proposes to require a laser device to measure the dimensions of 

each exhaust gas stack or duct at the flow monitor and the reference method sampling locations. 

The commenters stated that for circular stacks, measurements from at least three distinct 

locations need to be averaged; for rectangular stacks or ducts, each dimension must be measured 

from at least three distinct locations and averaged. The commenters stated that there is no 

mention, however, as to the conditions under which these measurements should be made; ducts 

and stacks expand and contract, and measurements can differ significantly between off-line and 

full-load periods and expansion rates can also vary based on ambient conditions. The 

commenters stated that it is unclear how requiring laser-device measurements would make data 

more accurate across the operating range of the unit as opposed to other methods of 

measurement (e.g., the use of a tape measure); there is still some inaccuracy when using laser 

measurements if such a measurement must be taken more than once. The commenters stated that 

without explanation as to how these requirements improve the measurement accuracy, EPA 

should not make these requirements mandatory. 

Commenters stated that for EGUs using CEMS, EPA proposes a new requirement to measure the 

dimensions of each stack or duct at the flow monitor and reference method sampling location 

using a laser device at "three or more distinct locations and average the results." Proposed 

subpart UUUU section 60.5805(a)(2)(iii). The commenters objected to this provision and stated 

that a requirement for a one-time measurement to establish stack diameter and area at one 

location using a laser device would not be unreasonable, if EPA had established that such 

devices are more accurate than other measurement methods and are not overly burdensome. The 

commenters stated that EPA's rulemaking record, however, contains no evidence that existing 

methods are not sufficiently accurate, and no evidence that laser devices would provide 

significantly more accurate results; as a result, it appears that the requirement imposes additional 

cost and burden with no corresponding benefit. The commenters stated that they also have 

concerns that measurements taken with a laser device while a unit is operating may be adversely 

affected by stack flow. The commenters stated that if EPA has evidence to support this proposed 

requirement, EPA should provide it. The commenters stated that in addition, the proposal to 

require a measurement at three "distinct" locations is not reasonable and may not be possible on 

some stacks; measurement at three "distinct" locations presumably would require three ports 

none of which are directly across from each other. The commenters stated that common 

configurations depending on stack diameter are to have two ports 90 degrees apart or four ports 

90 degrees degree apart, neither of which provides three distinct locations; in other words, most 

plants will have at most two distinct locations. The commenters stated that EPA must remove the 

requirement.

Comment 4: Reference of App D for units using CEMS

Response 4: The EPA agrees with the commenters and corrected this inadvertent mistake.

The following are summaries of the specific public comments under this comment:

Commenters stated that they do not understand EPA's proposed reference to compliance with 

Part 75, Appendix D for units using CEMS. The commenters stated that under Part 75, CEMS 
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certification requirements are in Appendix A, and ongoing QA/QC requirements are in Appendix 

B; Appendix D is the procedure for calculating heat input and mass emissions of SO2 for units 

without CEMS. The commenters recommended that EPA replace the reference to Appendices B 

and D with Appendices A and B.

Comment 5: Use of F-factors

Response 5: The final rule allows default and site specific f-Factors in accordance with 40 CFR 

Part 75. The final rule does not require oil and gas units to install stack gas flow monitors and 

allows the use of Part 75, Appendices D and G to calculate CO2 mass emission rate, using

Equation G-4.

The following are summaries of the specific public comments under this comment:

Commenters stated that they agree with EPA's proposal to allow liquid and gaseous fuel-fired 

EGUs to use the Appendix G in lieu of CEMS. Commenters stated requiring use of stack flow or 

diluent monitors on such EGUs would result in unnecessary additional construction, equipment, 

and implementation costs, and less accurate measurements of CO2 mass emissions. The 

commenters stated that they also agree with the proposal to allow, but not require, the use of sitespecific F-factors under equation G-4. Proposed subpart UUUU section 60.5805(a)(3)(ii). The 

commenters stated that Appendix F provides F-factors for most commonly used fuels and 

includes a procedure for annual determination of a site-specific F-factor for fuels that are not 

listed, or if a source wants to develop its own F-factor; however, the variability in commonly 

used fuels is not sufficient to warrant determination of a site-specific F-factor for all fuels. The 

commenters stated that to the extent there is small variability, it also is unlikely that variability 

would be captured in an annual determination. The commenters stated that EPA has relied on Ffactors identical to those in Part 75, Appendix F in NSPS compliance determinations since the 

mid-1970s; requiring development of a site-specific F-factor for commonly used fuels would be 

a waste of time and resources. The commenters stated that however, the option to develop such 

factors is necessary to account for the fact that EPA may not have developed a default factor for 

some fuels.

Comment 6: EPA should encourage states to include a provision allowing submission and 

approval of a petition for exemption of emissions that are de minimis from the compliance 

calculation, or for an alternative means of accounting for any resulting emissions from any 

integrated equipment that are not otherwise required to be monitored under an NSPS or 

otherwise accounted for in the primary equipment's monitoring.

Response 6: Affected sources are required to monitor their emissions using the provisions of 

Part 75. Any requests for alternative monitoring provisions would be addressed under the 

petition provisions of Part 75, however, in general, all emissions from a coal-fired unit (whether 

it be a conventional PC or an IGCC) should be monitored using CEMS.
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The following are summaries of the specific public comments under this comment:

Commenters stated that EPA proposes to define "steam generating unit" and "stationary 

combustion turbine" to include "any integrated equipment that provides electricity or useful 

thermal output" to the affected facility or auxiliary equipment. The commenters stated that when 

EPA proposed to include "integrated combustion turbines and fuel cells" in the definition of a 

post-May 3, 2011 steam generating unit in Subpart Da, EPA recognized that emissions from that 

equipment likely would not be exhausted through the primary boiler stack and, because the 

emissions would be relatively small, suggested that they be estimated rather than monitored. The 

commenters stated that the Agency also acknowledged that there likely were no such devices 

currently being used, but suggested that it hoped to promote their use. The commenters stated 

that their comments on that definition focused on its lack of clarity and usefulness, given the 

improbability that such equipment would be used in the near term. 

The commenters stated that although they continue to believe that there are few real world 

applications for such equipment, at least at fossil-fuel-fired utility boilers, they agree that if such 

equipment were used, continuous monitoring likely would not be warranted. The commenters

stated that such integrated equipment either has very few emissions, or operates very 

infrequently; the commenters also believed that given the uncertainty about their use, the Agency 

should not spend resources specifying monitoring requirements in the rule. The commenters

stated that as a result, they suggest that EPA encourage states to include a provision allowing 

submission and approval of a petition for exemption of emissions that are de minimis from the 

compliance calculation, or for an alternative means of accounting for any resulting emissions 

(e.g., a mass balance calculation or engineering estimate) from any integrated equipment that are 

not otherwise required to be monitored under an NSPS or otherwise accounted for in the primary 

equipment's monitoring (e.g., by venting the emissions into a stack with CEMS).

Comment 7: Supports use of any approved part 75 RATA methods 

Response 7: The final rule does not restrict the use of approved Part 75 stack gas volumetric 

flow rate methods.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA solicits comment on requiring the use of the most accurate RATA 

reference method for specific stack configurations. The commenters supported the use of any 

approved Part 75 method; approved methods for flow RATAs under Part 75 include Methods 2F, 

2G, 2H, and conditional test method. The commenters stated that EPA should not require any 

specific method, but continue to provide affected sources the option of using any method as 

currently included in Part 75.

Comment 8: Site specific monitoring plan 
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Response 8: In final rule EPA is requiring the reporting of hourly net energy output however; 

EPA is not requiring the equipment used to measure net energy output to be included in the 

electronic monitoring plan. The Agency is also not requiring the results of the QA/QC tests on 

such equipment to be reported electronically. Additionally, the EPA is not requiring any 

monitoring plans that have already been submitted in under part 75 to be reported again to the 

state or EPA if the monitoring plan has already been approved pursuant to part 75 requirements.

The following are summaries of the specific public comments under this comment:

Commenters stated that: EPA proposes to require preparation of a site-specific monitoring plan 

consistent with 40 C.F.R. section 75.53(g) and (h) and that each monitoring system . . . meet the 

applicable certification and quality assurance procedures in section 75.20 and Appendices B and 

D to part 75; EPA also is considering requiring that the Part 75 monitoring plan include the 

reporting of equipment used to measure net electric output (and net energy output for CHP units) 

in an EGU's monitoring plan under Part 75; and EPA also is considering requiring the reporting 

of the results of any new QA/QC test on equipment used to measure net electric or energy output 

to ECMPS. The commenters stated that it is not clear whether EPA is proposing that Part 75 be 

revised to simply provide a mechanism for such reporting in the event a state chooses to require 

or allow it, or whether EPA is suggesting that all source reporting under Part 75 be required to 

report this information.

Comment 9: Monitoring, recordkeeping, reporting requirements in state plans

Response 9: In the final rule the EPA is requiring states to include monitoring that is no less 

stringent than those in the applicable Part 75 provisions and the final rule reflects this. Also, in 

the final rule EPA is not requiring the use of a laser device to make stack measurements. The 

EPA agrees with the commenters that any duplication of testing or monitoring is unnecessary 

thus the final rule requires the CO2 monitoring and reporting provisions of Part 75 which are 

already being followed by the majority of affected EGUs. Therefore the data must be used to 

determine compliance with the §111(d) rule, except for substitute data when the State elects to 

set rate-based standards. Also any data for monitoring plans that has already been submitted does 

not need to be resubmitted so long as the monitoring plan is up to date with respect to the latest 

submittal in ECMPS. In the final rule EPA is reducing the recordkeeping requirements for EGUs 

from 10 years to 5 years as to require records be retained longer than the interim steps required in 

the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that section 60.5805, What applicable monitoring, recordkeeping, and 

reporting requirements do they need to include in their state plan for affected EGUs, repeats 

many requirements already included within Part 75 and makes some unexplained adjustments 

from the criteria in Part 75. The commenters suggested that EPA need only reference the existing 

Part 75 requirements that should be included rather than modifying them for this rule. The 

commenters stated that the changes proposed only provide an additional burden on the sources to 

supply EPA the same information calculated in a different way and having a different value; 
83

EPA then has the burden of either adding new data fields to its existing database for Part 75 or 

explaining why the each affected EGU is reporting two different values for emitted CO2. 

The commenters stated that if EPA wishes to make the changes to Part 75 monitoring approaches 

proposed here and in the proposed amendments to part 60 subparts Da and KKKK, EPA should 

make those changes to Part 75. The commenters provided comments on the following sections:

60.5805(a)(1) If the affected EGU already has a monitoring plan meeting the requirements of 

Part 75, this language implies that it needs to develop and submit a new plan. Is this a correct 

interpretation? If an affected EGU already has the required monitoring plan and it has been 

approved, why would the EGU need to resubmit a monitoring plan? We suggest the text be 

modified to require a new monitoring plan only if the state plan makes the EGU subject to Part 

75 requirements or physical changes at the EGU make it impossible to utilize the existing 

monitoring plan.60.5805(a)(2)(iii) Why does EPA require the stacks to be re-measured with a 

laser measuring device? Will this improve the accuracy of the emissions calculations? In our 

view any improvement in the accuracy of the cross-sectional area of the stack is overwhelmed by 

the much lower accuracy in the rest of the stack measurements. We suggest not finalizing this 

requirement.

60.5805(a)(2)(iv) Again, EPA is proposing an adjustment to the monitoring requirements in Part 

75 without modifying Part 75. We suggest EPA not make this change if for no other reason than 

to avoid explaining how the same source can have two different CO2 emission rates in the same 

database.60.5820 Definitions. EPA is proposing a number of new definitions, most of which are 

appropriate for the use of this rule. We do have a concern about EPA's proposal to use a different 

definition for standard conditions than is used in the rest of Part 60. The change to the use of a," 

standard atmospheric temperature and pressure" (SATP) adds another new variation that will 

result in yet another difference in the depiction of emissions from these sources from historical 

data. For consistency, we suggest that EPA retain the use of standard conditions as defined in 

CFR 60.2 for emissions quantification rather than using a new standard, SATP, which has not yet 

been used to standardize emissions from EGUs

Commenters stated that they oppose the proposed 10-year record retention period for all of the 

supporting information, unless the EPA can show a special need as required under the Paperwork 

Reduction Act regulations. The commenters stated that to the extent the EPA or a state intends to 

audit the accuracy of a certified report by reference to supporting information, the EPA should 

do so within a reasonable period of time (e.g., 3 years); absent an audit, the data have little or no 

usefulness. The commenters stated that Part 75 has a 3-year record retention requirement, and the 

EPA has not provided any information to suggest that has been inadequate; given the EPA's 

proposed reliance on Part 75 monitoring, compliance with Part 75 recordkeeping should be 

sufficient for approval of a state plan. The commenters also opposed the proposed on-site 

retention requirement if it means that retention of electronic records that can be accessed "onsite" 

(even if they are physically located offsite) would not be adequate. The commenters stated that 

many of the records to be retained are recorded only in electronic form and, depending upon the 

facility's management practices, may be retained at a central location in order to facilitate 

backups and other services. The commenters stated that as long as the facility can access the 

information onsite, there is no reason for it to be located there in a paper hardcopy form.
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Comment 10: Bias adjustment 

Response 10: In the final rule EPA has clarified that the use of Part 75 substitute data will be 

required for States opting to comply with a mass goal, but is prohibited for states opting to 

demonstrate compliance with a rate based goal. In the final rule EPA is requiring the use of 

CEMS for coal fired EGUs and allowing the use Appendices D and G (specifically, Equation G4) for oil and gas fired EGUs. The Agency believes that other Part 75 methods for determining 

CO2 mass emission rates (i.e., Equation G-1 in Appendix G or the low mass emissions (LME) 

methodology in §75.19) lack sufficient quality-assurance and are not appropriate for use in this 

rule. The required compliance mechanisms required under this rule are different than those 

required under part 75 thus the EPA believes that deviating from the current methodology is 

appropriate when addressing the compliance calculations required under the final rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that they support EPA's proposal that states rely on Part 75 monitoring 

procedures, without bias adjustment, but objects to the proposed elimination of one of those 

options and imposition of additional requirements for existing units. The commenters stated that 

the EPA has provided no justification for requiring states to impose on EGUs monitoring that is 

different from, let alone more stringent than, Part 75. The commenters also objected to the 

Agency's failure to make clear that use of Part 75 missing data substitution procedures is not 

appropriate in compliance calculations.

Comment 11: Supports flexible monitoring options 

Response 11: The Agency is requiring monitoring no less stringent than that required in the

Acid Rain Program’s part 75 monitoring procedures in order to standardize the reporting and 

ensure that all EGU’s are held to the same data quality standards. The GHG Reporting Program 

requires EGU’s that report to the ARP to use the same reported values under Part 75 for Part 98 

reporting and this action is consistent with that approach. Therefore, for the purposes of this rule 

parts of the part 60 monitoring procedures are not required and applicable.

The following are summaries of the specific public comments under this comment:

Commenters stated that they support the option of using any 40 C.F.R. Part 60 and 75 methods 

for monitoring and calculating CO2 mass emissions and that monitoring and reporting under the 

proposed standards should be as flexible as the existing requirements under parts 60 and 75, 

including the ability to use Part 75 Appendix D and G methodologies. The commenters stated 

that this flexibility is consistent with the mandatory GHG Reporting Program (GHGRP) which 

allows all EGUs subject to the Acid Rain Program to follow any Part 75 method for determining 

CO2 mass emissions.
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Comment 12: Monitoring and reporting issues 

Response 12: In the final rule EPA is relying on the use of Part 75 CEMS and Appendices D 

and G (specifically Equation G-4) and is not allowing the use of other monitoring 

methodologies, as they are not appropriate for this rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that in some instances, EPA is proposing to require that states impose new 

requirements, some of which could increase burden and stringency beyond existing requirements 

once state plans are implemented. The commenters stated that they support EPA's proposal that 

states rely on Part 75 monitoring procedures but object to the proposed elimination of one of 

those options and imposition of additional requirements for existing units; EPA has provided no 

justification for requiring states to impose on EGU s monitoring that is different from, let alone 

more stringent than, Part 75. The commenters stated that, in addition, they are concerned about 

the Agency's failure to make clear that use of Part 75 missing data substitution procedures is not 

appropriate in compliance calculations as was done in the proposed GHG NSPS for new and for 

modified and reconstructed sources under CAA Section 111 (b) and request that EPA provide the 

same clarification in the final rule.

Comment 13: Support use of gross electric output 

Response 13: The EPA thanks the commenters for their support in making use of existing CO2 

measured and reported emissions from Part 75 programs. The EPA appreciates the commenters’ 

suggestion that market drivers will incentivize improvements in EGU efficiency thereby 

narrowing the gap between net generation and gross generation, however monitoring gross 

generation does not allow an EGU who successfully closes this gap to take advantage of EE 

credits for their action(s). The EPA understands that this presents a new paradigm in regard to 

electrical output monitoring and reporting and we recognize the complexities presented by 

commenters, such as common systems using generation from multiple units present new 

concerns for reporting unit specific values. Ecen so, we find this to be a necessary step in order 

to reliably provide an avenue to track, bank, and take advantage of EE credits; especially those 

resulting from early actions during years 2013 until state plans are finalized, as well as those 

intended as Building Block 1 actions as part of the planning. Because improvements in the 

efficiency of these devices represent opportunities to reduce carbon intensity at existing affected 

EGUs that would not be captured in measurements of emissions per gross MWh, goals are 

expressed in terms of net generation. As noted by some commenters, EGUs have familiarity and 

in some places already have in place equipment necessary to collect and report hourly net 

generation. A discussion of this topic can be found in the final rule preamble section VI.C.(b). 

There are many flexibility options provided for in the final rule that give states and regional 

planning groups several options to choose from when assembling their plans, and the ability to 

track EE advances on a per EGU basis, account for early actions that create EE credits and bank 

these credits account for several options in this rule that we feel are essential to providing many 

of these flexibilities and therefore we disagree with the commenters assertion that arriving at a 
86

net generation basis for monitoring and reporting removes flexibilities from state and regional 

planning options. 

In addition, Congress provided EPA with the authority to determine if a plan is satisfactory and

we interpret this as including provisions for adequate monitoring. Because a net and gross 

number have different emission effects it is well within our authority to require that monitoring 

and reporting be done consistent with our BSER determination. We disagree with commenter 

that we lack the ability to consider connected equipment in setting or determining compliance 

with an emission limitation (see CH. 1 of RTC responding to comment on the “boiler island”)

The following are summaries of the specific public comments under this comment:

Commenters stated that they support the use of gross energy output in the CO2 emission rate 

calculation as gross output provides the most direct and consistent measurement of CO2 

emissions. The commenters stated that EPA's proposal to calculate CO2 emissions using net 

energy output is inconsistent with other rulemakings and challenging for facilities to accurately 

measure; in addition, the commenters supported the option of using any 40 C.F.R. Part 60 and 75 

methods for monitoring and calculating CO2 mass emissions. The commenters stated EPA 

should not mandate a specific method, but continue to provide options for affected sources as 

discussed below.

The commenters stated that EPA has proposed that compliant CO2 emission rates be determined 

on a net basis, which is inconsistent with the approach that EPA has taken in other recent 

rulemakings that seek to regulate CO2 from EGUs. The commenters supported the use of gross 

energy output in the CO2 emission rate calculation, as EPA proposed in the January 2014 NSPS 

Proposal and in the June 2014 modified and reconstructed proposed standards (MRPS) for 

subpart KKKK sources. The commenters stated that in the existing source guidelines and 

Subpart Da of the June 2014 MRPS Proposal for Subpart Da sources, however, EPA proposed to 

regulate CO2 emissions on a net basis; the commenters reiterated its comments on the January 

2014 NSPS Proposal and the June 2014 MRPS. The commenters stated that they strongly 

support the use of gross energy output in the CO2 emission rate calculation rather than an unduly 

complex net output calculation.

Commenters stated that the use of gross energy output allows the plant operator to account for 

electrical, mechanical, and thermal energy use by the plant, giving operators the needed 

flexibility to design overall systems in the most efficient and economic manner; gross MWh 

output is straightforward, simple, consistent, directly measured, and already reported to EPA for 

other purposes as required by 40 C.F.R. Part 75. The commenters stated that furthermore, market 

drivers will continue to ensure that power producers operate efficiently because utilities have a 

strong incentive to ensure the gap between gross and net output is as small as possible, 

maximizing the return on investment. The commenters stated that in considering gross energy 

output, EPA should recognize that a generating unit's gross energy output is comprised of 

electrical, mechanical, and thermal energy uses.

Commenters stated that a gross energy output-based standard that incorporates useful thermal 

energy would encourage the use of waste heat produced during the energy conversion process 

and that by allowing for the incorporation of waste heat and steam as a compliance option 
87

(increased gross MWh output with no additional CO2 emissions), a gross energy output-based 

standard, which recognizes electrical, mechanical, and thermal energy uses, would allow 

operators to respond to market drivers and to make choices with respect to the quality of the 

waste heat and steam they produce, and, thus, likely increasing the overall utilization of the 

energy.

Commenters stated that in contrast, net MWh output is facility-specific and challenging to 

accurately calculate; for example, many facilities have transformers that support multiple units at 

the facility, making unit-level reporting difficult. The commenters stated that more important, 

station electric services may come from other outside sources to supply lighting, well pumps, and 

other ancillary loads; and some station services are dedicated per unit, while other station 

services may be measured at a facility level. The commenters stated that examples of facilitywide equipment that often serve more than one unit include coal handling equipment such as 

unloaders and conveyors, electric fire pumps, cooling tower makeup pumps, and pollution 

control equipment (e.g., FGD and baghouses); accurately measuring and reporting all of these 

sources would require complex calculations and would naturally lead to variations among 

affected sources and inconsistencies in both reporting CO2 emission rates and compliance.

Commenters stated that the Proposed Guidelines for affected sources should include monitoring 

and reporting based on gross MWh rather than net MWh for the following reasons: First, because 

Congress assigned the states with primary authority for implementing the 111(d) guidelines, the 

EPA has no authority to establish these specific monitoring requirements. The requirement to 

report net MWh is not consistent with how the affected source is defined, and places a regulatory 

burden on equipment and processes that are outside the boundaries of the affected source. While 

it is true that power generating facilities are typically equipped with devices to measure and 

report auxiliary power use (to provide appropriate FERC accounting of energy production and 

supply), the EPA's assertion that its proposed monitoring and reporting requirements will not be 

burdensome is incorrect. Adding a requirement to monitor auxiliary electrical usage will subject 

many more plant metering systems to additional procedural and paperwork requirements, and 

therefore will subject these non-affected sources to compliance obligations which are not 

authorized by the CAA. The EPA can no more require monitoring under Proposed subpart 

UUUU section 60.5805 for non-affected sources at a facility that includes affected EGUs than it 

could require other non-affected sources (such as nuclear power plants, renewable power 

facilities, or even residential home electrical usage, which are all included in various parts of the 

EPA's proposed Building Blocks) to install and maintain specific electrical metering devices. 

States should retain the flexibility to determine how they will implement the proposed 

guidelines, and that flexibility will include whether the state should require specific monitoring 

and reporting from facilities or entities that are not otherwise affected sources under the terms of 

40 CFR 60.

Comment 14: Do not require CO2 CEMS exclusively; preserve option to use O2 CEMS; 

maintain option to measure CO2 concentration on a wet basis 

Response 14: In the final rule EPA is allowing the use of Part 75 Appendices D and G

(specifically, Equation G-4) for oil and gas fired EGUs. In the final rule no additional changes 
88

are required to be made to the Part 75 monitoring plan. EPA has added language that 

specifically allows sources to use Part 75 default moisture values and to petition the 

Administrator for site specific moisture values under 40 CFR 75.66. The EPA is specific in the 

final rule that the monitoring plans submitted under part 75 are sufficient and if those monitoring 

plans have already been submitted they do not need to be resubmitted unless required by a State.

The following are summaries of the specific public comments under this comment:

Commenters stated that they support the option to use Equations in Appendix G of Code of 

Federal Regulations Part 75 (Part 75) as an alternative to installing CEMS for EGUs that burn 

exclusively gaseous or liquid fuels.

Commenters that they have no opposition to the monitoring plan requirement but would like 

EPA to clearly state that a plan meeting Part 75 requirements is also deemed to meet the 

proposal's monitoring plan requirements; such coordination between the New Source 

Performance Standards and Part 75 emissions monitoring programs is essential to avoid 

duplication and imposition of potential inconsistent requirements.

Commenters stated that they are concerned that the proposed language requiring EGUs that 

measure CO2 concentration on a dry basis to install a continuous moisture monitoring system 

could be interpreted as eliminating the option in section 75.11 (b)(1) to use appropriate default 

moisture values rather than installing and calibrating a monitoring device. The commenters

stated that the Part 75 default moisture values for coal and wood were derived from the Agency's 

own evaluation of data in a 1999 rulemaking and EPA approved the default moisture value for 

natural gas (boilers only) in 2008.The commenters stated that in addition, section 75.11(b)(2) 

allows the use of a moisture look up table, based upon a psychrometric chart, for saturated gas 

streams following a wet FGD system as an allowable moisture monitoring method. The 

commenters requested that EPA clarify that the reference to installing and calibrating systems 

was not intended to eliminate these default values and options.

Comment 15: Compliance plan 

Response 15: We agree with the commenters and the final rule provides a “state measures” 

type plan that must include a backstop provision – triggered if, during the interim period, the 

state plan fails to achieve the emission reduction trajectory identified in the plan or if, during the 

final phase, the state plan fails to meet the final CO2 emission performance rates or state CO2 

emission goal – that would impose enforceable obligations on the affected EGUs adequate to 

meet the state’s goal when fully implemented. The final rule also includes provisions for tracking 

progress and enacting corrective measures for certain emission standards plan if the CO2 

emission performance rates or applicable state rate-based CO2 goal are not achieved, corrective 

measures would need to be implemented, as described in section VIII.F.3.

The following are summaries of the specific public comments under this comment:
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Commenters stated that they support the EPA's proposal that a report and corrective measures 

would be required if actual emissions (or emissions rates) fall short of planned levels by more 

than 10 percent starting in 2022. The commenters stated that , also, if a state fails to meet its 

goals, either in the interim period or final goal, they support requiring additional actions and a 

modified compliance plan to make up for the emissions performance deficiency. The 

commenters also supported the proposal that state plans include contingencies if the enforceable 

emissions limits on EGUs in and of themselves do not achieve the required emissions 

performance level. The commenters recommended that the EPA should consider requiring an 

additional compliance plan submittal in 2025 to ensure states will meet the goals in 2030 as well 

as to establish initial plans for meeting goals beyond 2030.

Comment 16: Requirement to use a laser device to measure the dimensions of each exhaust gas 

stack or duct is unnecessarily burdensome and will require installing additional sampling ports 

that will not be used for any other purpose.

Response 16: The EPA is not finalizing in this rulemaking any requirements to use a laser or 

other device to make stack diameter measurements which are then used to determine stack gas 

volumetric flow rates.

The following are summaries of the specific public comments under this comment:

Commenters stated that the state plan monitoring requirements for measuring CO2 emissions in 

proposed 40 CFR 60.5805(a)(2)(ii) include a requirement to use a laser device to measure the 

dimensions of each exhaust gas stack or duct. The commenters stated that this requirement is 

unnecessarily burdensome and will require installing additional sampling ports that will not be 

used for any other purpose.

The commenters referred to the monitoring requirements are included in proposed 40 CFR 

60.5805(a)(2)(iii): 

"An affected EGU must use a laser device to measure the dimensions of each 

exhaust gas stack or duct at the flow monitor and the reference method sampling 

locations prior to the initial setup (characterization) of the flow monitor. For 

circular stacks, an affected EGU must measure the diameter at three or more 

distinct locations and average the results. For rectangular stacks or ducts, an 

affected EGU must measure each dimension (i.e., depth and width) at three or 

more distinct locations and average the results. If the flow rate monitor or 

reference method sampling site is relocated, an affected EGU must repeat these 

measurements at the new location."

The commenters stated that the proposed rule requires an affected EGU to use a laser device to 

measure the stack dimensions at three or more distinct locations and average the results, but most 

large diameter stacks have four or more ports, with two ports located directly opposite from each 

other and perpendicular to the other set in the case of four ports. The commenters explained that 

would only give two distinct locations, besides the fact that one would be shooting across the 
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stack directly into the other port if they are located exactly on the same diameter. The 

commenters stated that an affected EGU would have to install two or more additional sampling 

ports for the flow monitor and one or more sampling ports for the reference method sampling 

system to get measurements at three or more distinct locations. The commenters stated that these 

additional sampling ports would not be used again at these locations. The commenters

recommended the requirement to measure the dimensions of circular stacks at three or more 

distinct locations be removed from the proposed rules, and that an affected EGU use existing 

sampling and monitoring ports to determine the stack or duct dimensions.

Comment 17: EPA should require direct CEMS monitoring of CO2 at all units reporting CO2 

emissions under the CPP.

Response 17: In the final rule, EPA is requiring the use of CEMS to directly measure CO2 mass 

emission rate and allows the use of Appendices D and G (specifically Equation G-4) for oil and 

gas fired units. EPA believes that because these methods must meet stringent Part 75 accuracy 

and quality assurance requirements, they are appropriate for this rule.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should require direct CEMS monitoring of CO2 emissions. The 

commenters noted that the EPA proposes to allow facilities to determine compliance with an 

applicable standard by either monitoring emissions directly or by estimating emissions based on 

fuel consumption. [Proposed 40 CFR 60.5535, 60.5540]. The commenters stated that it appears 

that EPA inadvertently omitted a third provision relating to using fuel consumption to estimate 

emissions because proposed 40 CFR 60.5535(c) refers the option of "determin[ing] . . . CO2 

mass emissions are by monitoring fuel combusted in the affected EGU and periodic fuel 

sampling as allowed under 40 CFR 60.5525(c)(2)," but the proposal does not contain a section 

60.5525(c)(2). The commenters stated that direct monitoring of emissions, especially using 

CEMS, is generally more accurate than estimations of emissions using fuel consumption, as EPA 

has previously acknowledged. The commenters stated that virtually all existing coal-fired plants 

already use CEMS to comply with existing reporting requirements under the Clean Air Act's 

Acid Rain Program and Greenhouse Gas Reporting Rules. Accordingly, the commenters noted 

that requiring coal plants to use CEMS for the Clean Power Plan will improve reporting accuracy 

while imposing little (if any) additional burden on industry. The commenters urged the EPA to 

require CEMS not only at coal plants, but at all units reporting CO2 emissions under the CPP. 

The commenters stated that the value of CEMS data is illustrated by analysis of plants for which 

EPA has both CEMS and fuel-based emission estimates. The commenters stated that power 

plants within the Clean Air Act's Acid Rain Program report CO2 emissions to the EPA, and 

essentially all, if not all, coal-fired plants do so using CEMS, while most oil- and gas-fired plants 

use site-specific emissions calculations. The commenters noted that the Energy Information 

Administration (EIA) also calculates emissions for these plants, but uses fuel consumption data 

rather than the CEMS information. The commenters stated that these parallel data sets allowed 

U.S. Geological Survey scientists to compare measured and estimated emissions for 2,900 plants, 

including the 828 plants that report using CEMS measurements (which are almost entirely coal 
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plants). The commenters noted that the researchers found significant divergences between the 

two data sets, and that overall the fuel consumption data provided an average emission rate 

estimate 4.6 percent lower than the CEMS data. The commenters stated that this result masks 

even greater divergences in estimates at individual plants. The commenters stated that this 

discrepancy is likely due to the inherent inaccuracy of fuel sampling for coal plants. The 

commenters stated samples are typically taken from different parts of the fuel pile, and the 

calculations do not take into account environmental conditions at the time of fuel use, such as 

wet or frozen coal. 

As for natural gas, the commenters stated that the EPA's fuel sampling procedures include a 

determination of the relationship between fuel flow and load for the unit. The commenters stated 

that this requires the operator to measure the fuel consumption and generation of the unit on an 

hourly basis for 168 hours, then to calculate the average fuel consumption per unit of generation. 

However, the commenters noted that the EPA's procedure allows a source to exclude as "nonrepresentative" any hour in which the unit is "ramping up or down" (defined as a variation in 

load of greater than 15 percent) or is operating at low load (defined as any hour in which the load 

is in the lower 25 percent of the units normal range of operation). The commenters argued that 

the effect of this procedure is to exempt periods of low or changing load from regulation. The 

commenters stated that, as EPA has previously recognized, emission rates are ordinarily higher 

during these periods of operation than during steady-state, near full-load conditions. The 

commenters stated that since the excess CO2 generated under these conditions contributes to 

climate change and can be reduced by minimizing low load and ramping activities, these 

emissions should be included in determining the unit's emissions. 

Comment 18: Monitoring O2 should be an adequate substitute for CO2 monitoring.

Response 18: The final rule allows EGUs of any type (i.e. boiler, turbines) that are equipped 

with O2 and stack gas volumetric flow monitors to determine a CO2 mass emission rate in 

accordance with Part 75, except for units that utilize carbon separation. 

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA is proposing the CO2 monitoring already conducted by most 

affected EGUs under 40 CFR Part 75, that is reported using the EPA's Emission Collection and 

Monitoring Plan System (ECMPS), would generally satisfy CO2 emission reporting requirements 

under this proposal. The commenters stated that the EPA may be over estimating the number of 

affected EGUs that may meet the monitoring requirements because some of Ohio's combustion 

turbine stations do not have CO2 analyzers and are instead monitoring O2. The commenters

stated that this should be an adequate substitute for CO2 monitoring.
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7.6 GREENHOUSE GAS REPORTING PROGRAM

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with the Greenhouse Gas Reporting Program.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: Streamline the apparently duplicative reporting requirements for 40 CFR Part 75 

and 40 CFR Part 98.

Response 1: The EPA is already considering the streamlining of emissions reporting for all air 

emissions reported to the EPA, including the requirements cited. The EPA’s ongoing EEnterprise initiative has scoped out a future streamlined reporting approach called Combined Air 

Emissions Reporting. The scoping phase is complete and the EPA is moving forward to identify 

implementation approaches. This effort will eliminate the duplicative reporting of the type that 

the commenters recommend. More information on this project can be found at 

http://www2.epa.gov/e-enterprise/e-enterprise-projects-spotlight. 

The following are summaries of the specific public comments under this comment:

In regards to monitoring, recordkeeping and reporting, commenters questioned the relationship 

between the proposed rule and the annual GHG emissions reporting provisions under 40 CFR 

Part 98. The commenters stated that most affected sources currently report GHG emissions to the 

EPA quarterly pursuant to 40 CFR Part 75 and annually via 40 CFR Part 98. The commenters

asked whether EPA is considering streamlining the apparently duplicative reporting requirements 

for the same emissions.

7.7 OTHER EPA RULES

This section addresses comments received on interactions of the EGU GHG Emission Guidelines 

with other EPA rules.

Commenters have raised a number of issues related to this subsection which are organized by 

topics (comments) below. Responses are provided for these topics.

Comment 1: EPA should provide relief for new electricity use driven solely by compliance 

requirements from other EPA rules.

Response 1: Since the EPA has not yet promulgated final effluent limit guidelines (proposed on 

June 7, 2013; 78 FR 34432), it is not certain what the final limits and requirements will be. This 
93

is also the case for other rules that have not yet been promulgated. The agency recognizes, 

though, that there are numerous demands on states, cities and towns, communities, and utilities, 

and, in this final rule, we are providing more time for planning, consultation and decision making 

in the formulation of state plans and in EGUs’ choices of compliance strategies. The final 

emission guidelines also provide states and utilities with the latitude to consider a broader range 

of options to achieve the required reductions while addressing concerns about ratepayer impacts 

and stranded assets. It is the state that will determine how, in its plan, to comply with the final 

emission guidelines, and the state will be able to take into consideration its specific 

circumstances when choosing from numerous measures, including measures that are not part of 

the EPA’s determination of the BSER. 

The following are summaries of the specific public comments under this comment:

Commenters stated EPA should provide relief for new electricity use driven solely by 

compliance requirements from other EPA rules. Commenters stated that additional consumption 

of electric power due to EPA rules should not be allowed to count against electric power savings 

achieved in other parts of the state. 

Commenters stated that EPA failed to take into account the impact of its own rulemaking in 

other media on its proposed rules. The commenters gave as an example, new regulations from 

the Office of Water requiring mandatory reductions in the amount and level of mercury 

contained in wastewater effluent, which will require over 360 cities and towns in Missouri over 

the next five years to eliminate their use of lagoons for wastewater treatment and instead install 

mechanical plants. The commenters stated that the mechanical plants will require substantial 

amounts of electricity because they must operate 24 hours per day, 365 days per year and 

complying with caps on electric consumption, much less reductions of 9.91percent, by 2030 will 

be impossible for these communities. The commenters stated that EPA's rules are actually the 

proximate cause of increases in CO2 emissions and the failure of these communities to be able to 

comply. The commenters suggested that EPA modify the proposed guidelines to require the EPA 

to calculate the added electrical consumption by state for each final rule, and allow the state 

environmental agency to take the equivalent amount of CO2 as a deduction for its emission 

limits.

Comment 2: Increased number of nonattainment areas 

Response 2: As pointed out by the commenters, a potential effect of the final emission 

guidelines may be increased utilization of emissions units located in nonattainment areas and the 

commenters express concern with this resulting in an increased number of nonattainment areas. 

As outlined in the final Clean Power Plan, states and sources have continued obligations to meet 

all other CAA requirements addressing conventional pollutants. Because the CAA envisions 

control of these other pollutants as a continuous process (through provisions such as periodic 

review of the NAAQS and residual risk requirements under the MACT program), the EPA 

believes that the Clean Power Plan provides an opportunity for states to consider strategies for 
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meeting future CAA planning obligations as they develop their plans under this rulemaking. 

Multi-pollutant strategies that incorporate criteria pollutant reductions over the planning horizons 

specific to particular states, jointly with strategies for reducing CO2 emissions from affected 

EGUs needed to meet Clean Power Plan requirements over the time horizon of this rule, may 

accomplish greater environmental results with lower long-term costs. Such strategies may also 

provide opportunities for states, communities, and affected facilities to consider the most 

effective means of meeting these obligations while limiting or eliminating localized emission 

increases that would otherwise affect air quality. Furthermore, this type of multi-pollutant 

approach has been suggested by states and sources in past rulemakings as a tool to determine the 

best system of emission reductions. The EPA recommends that states consider such strategies in 

consultation with their communities, affected facilities, and other stakeholders as they develop 

their 111(d) state plans.

In addition to the use of multi-pollutant strategies, we expect that units increasing utilization as a 

result of the final emissions guidelines to be mostly unmodified EGUs - in particular high 

efficiency gas-fired EGUs - with relatively low GHG emissions per unit of electrical output. 

These plants may operate more hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized/and or regional rather than global as 

is the case with GHG emissions. Changes in utilization already occur in response to energy 

demands and evolving energy sources. Increased utilization of solid fossil fuel-fired units 

generally would not increase peak concentrations of PM2.5, NOx, or ozone around such EGUs 

to levels higher than those that are already occurring because peak hourly or daily emissions 

generally would not change; however, increased utilization may make periods of relatively high 

concentrations more frequent. It should be noted that the gas-fired sources likely to be dispatched 

more frequently have very low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA requirements that directly address 

the conventional pollutants, including federal emission standards, rules included in state 

implementation plans, and conditions in title V operating permits, in addition to the guidelines in 

this final rulemaking. Therefore, we believe that local (or regional) air quality for these 

pollutants is not likely to be significantly affected. 

Regarding the commenters expressed concern with the potential impact proposed revisions to the 

ozone NAAQS could have on state planning efforts and affected entities’ ability to comply with 

any potentially new requirements associated with a revised ozone NAAQS and those related to 

the 111(d) emissions guidelines, we note that it is premature to speculate about the outcome of 

the ozone NAAQS review and how a more stringent ozone NAAQS may impact sources of 

ozone precursor emissions, including EGUs. We believe the planning and compliance 

timeframes that would follow from a revised ozone NAAQS and the timeframes we are 

finalizing today for submittal of the CAA section 111(d) state plans will allow considerable time 

for coordination by states in the development of their respective plans, as needed. As stated in 

the proposal, the EPA is prepared to work with states to assist them in coordinating their efforts 

across these planning processes.

The following are summaries of the specific public comments under this comment:

Commenters stated that, in addition, the Proposed Rule will require ramping up generation from 

facilities that are located in current nonattainment areas, which would violate NAAQS 
95

requirements and as EPA revises the NAAQS, the number of nonattainment areas will grow, 

causing even greater problems.

Commenters stated that one concern that is not fully addressed in the PACE report is the 

expected difficulty in permitting new natural gas EGUs given the expected strengthening of the 

NAAQS for ozone. The commenters stated that according to modeling, a NAAQS in the range of 

65-70 parts per billion would likely put at least the eastern portion of Pima County in 

nonattainment for the ozone standard. The commenters stated that much of the new natural gas 

generation needed to replace the coal that is retired will need to be located in eastern Pima 

County; permitting a stationary source in a nonattainment area require the acquisition of 

emission offsets, but being newly designated, there will not be a developed offset market to draw 

from. The commenters stated that developing offsets on a project specific basis, assuming there 

are cost effective offsets available, will take considerably more time; this would further strain 

efforts to maintain reserve margin and system reliability in general.

Comment 3: Other rules that impose restriction on EGU's ability to improve HRI

Response 3: The EPA recognizes that there are a number of regulatory requirements that have 

recently become applicable or will become applicable to EGUs in the coming years and as a 

result has made adjustments to the compliance schedule for the Clean Power Plan. In response to 

commenters concerns with compliance timelines and possible uncertainty, the final emissions 

guidelines compliance period start date has been moved from 2020 to 2022. We believe that this 

additional time provides an opportunity for states and EGUs to consider strategies for meeting 

these CAA obligations as states develop their plans and affected EGUs work on their compliance 

strategies. Multi-pollutant strategies that incorporate criteria pollutant reductions over the 

planning horizons specific to particular states, jointly with strategies for reducing CO2 emissions 

from affected EGUs needed to meet Clean Power Plan requirements over the time horizon of this 

rule, may accomplish greater environmental results with lower long-term costs. Such strategies 

may also provide opportunities for states and affected facilities to consider the most effective 

means of meeting these obligations while limiting or eliminating localized emission increases. 

Furthermore, this type of multi-pollutant approach has been suggested by states and sources in 

past rulemakings as a tool to determine the best system of emission reductions.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA is simultaneously proposing/implementing a variety of EGU rules 

and this uncertainty significantly affects the decisions a small utility must make. The 

commenters recommended the compliance time tables reflect the tremendous amount of 

regulatory uncertainty we are currently facing; additionally, the lack of prioritization of the 

regulations being proposed by the EPA will lead to additional costs for our ratepayers.

Comment 4: Methane emissions from NG production and distribution
96

Response 4: Methane is a potent greenhouse gas and is also a contributor to ground level ozone, 

so cutting methane emissions also reduces ground level ozone.

On April 17, 2012, the EPA issued final regulations to reduce the emissions of volatile organic 

compounds (VOCs), some of which are hazardous air pollutants, establishing, among other 

things, the first federal air pollution standards for natural gas wells that are hydraulically

fractured, along with requirements for other sources, such as compressors, that were not

previously regulated at the federal level. Although these regulations targeted VOCs, they also 

reduced methane emissions substantially. The EPA estimates that, when fully implemented in 

2015, the 2012 rules will decrease methane equivalent to 33 million tons of carbon pollution per 

year. Going forward, the EPA will deploy a carefully selected combination of policy tools to 

maximize cost-effective methane and VOC reductions from the oil and gas sector.

The Climate Action Plan Methane Strategy 

(https://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014-

03-28_final.pdf), issued in March 2014, lays out a comprehensive interagency strategy to cut 

emissions of methane. The document summarizes the sources of methane and trends in

emissions; sets forth a plan to reduce both domestic and international methane emissions through 

incentive-based programs and the Administration’s existing authorities; and, outlines the 

Administration’s efforts to improve measurement of these emissions. This strategy also

highlights examples of technologies and industry-led best practices that are already helping to

cut methane emissions. The Administration is pursuing a targeted strategy that builds on progress 

to date and takes steps to further cut methane emissions from a number of key sources: landfills, 

coal mines, agriculture, and oil and gas. For oil and gas sources, in particular, in the fall of 2014, 

the EPA will determine how best to pursue further methane reductions from these sources. If the 

EPA decides to develop additional regulations, it will complete those regulations by the end of 

2016. 

The final emission guidelines are designed to build on and reinforce actions already being taken

by states, cities and towns, and utilities to move toward cleaner generation of electric power. 

Each state will have the opportunity to take advantage of a wide variety of strategies for reducing 

CO2 emissions from affected EGUs.

The following are summaries of the specific public comments under this comment:

Commenters recommended that EPA also act to regulate other GHG, including methane, black 

carbon and ozone.

Commenters stated that while the States support transitional increased use of natural gas rather 

than coal and oil as an interim step toward decarbonizing the national power sector, it is vitally 

important that, as this Proposed Rule moves forward, EPA takes concrete action to regulate 

methane emissions from the oil and gas sector. Commenters stated the need for this action is 

underscored by EPA's analysis that the shift in generation from higher-emitting steam EGUs to 

lower-emitting NGCC units results in an increase in natural gas production and price. 

The commenters stated that scientific research regarding the climate benefits of natural gas over 

other fossil fuels is ongoing, and the analysis is dependent on a variety of factors, such as the 
97

type of gas, for instance, conventional versus shale gas; methods of extraction and production; 

and volume of fugitive emissions (leakage) in production, transmission and distribution systems. 

The commenters urged EPA to be cautious with respect to assumptions that power plant fuel 

switching to natural gas or shifting dispatch from coal- and oil-fired units to NGCC plants 

necessarily will result in substantially lower greenhouse gas emissions. The commenters stated 

that recent studies suggest that, when methane leaks from gas production, transmission, and 

distribution are taken into account, the climate benefit of natural gas as a substitute for coal- and 

oil-fired power is diminished significantly, at least for some period. The commenters stated that a 

recent meta-study analyzing 20 years of earlier bottom-up (source-level) studies with top-down 

(atmospheric) studies found that although robust climate benefits result from NGCC's 

displacement of coal-powered generation, efforts to accurately assess, and thereby control, 

methane leakage from natural gas production, transportation, and power generation are 

inadequate. The commenters stated that the study found that some types of bottom-up 

measurements consistently underestimate actual measured values while top-down studies based 

on atmospheric concentrations suggest that leakage rates are significantly higher that current 

EPA estimates. The commenters stated that the revolutionary development of shale gas and tight 

oil reservoirs through horizontal drilling and hydraulic fracturing may upend other estimates, and 

novel applications of remote sensing technology estimate that current inventories of fugitive 

emissions for producing regions where these technologies are used may be significantly 

underestimated. The commenters stated that while techniques for determining fugitive emissions 

will continue to be refined and estimates improved, the science is clear that fugitive emissions 

are significant.

The commenters stated that EPA should harmonize its climate change regulatory goals when it

proposes revisions to its oil and natural gas well rules in late 2014 and correct current 

deficiencies in monitoring, assessing, and regulating methane emissions from oil and gas 

operations. The commenters stated that to ensure the greatest greenhouse gas emission reduction 

benefit is achieved, EPA must regulate oil and gas sector production, transmission, and 

distribution system methane leaks at the same time it advances the Proposed Rule. The 

commenters stated that as a number of studies have shown, abatement of methane emissions in 

the oil and gas sector is among the least-cost global methane emissions reduction strategies 

available. The commenters stated that, finally, EPA should consider the significant risk that 

incentivizing substantial long term investment in gas infrastructure would displace renewables 

development, the wide-scale deployment of which is likely necessary to enable the U.S. to 

achieve an 80 percent reduction of greenhouse gases from 2005 levels by 2050.

Comment 5: NAAQS and Regional Haze Programs Impacts on CPP

Response 5: Regarding the commenters expressed concern with the potential impact proposed 

revisions to the ozone NAAQS could have on state planning efforts and affected entities’ ability 

to comply with any potentially new requirements associated with a revised ozone NAAQS and 

those related to the 111(d) emissions guidelines, we note that it is premature to speculate about 

the outcome of the ozone NAAQS review and how a more stringent ozone NAAQS may impact 

sources of ozone precursor emissions, including EGUs. We believe the planning and compliance 

timeframes that would follow from a revised ozone NAAQS and the timeframes we are 
98

finalizing today for submittal of the CAA section 111(d) state plans will allow considerable time 

for coordination by states in the development of their respective plans, as needed. As stated in 

the proposal, the EPA is prepared to work with states to assist them in coordinating their efforts 

across these planning processes.

The EPA appreciates the commenters’ suggestion that implementation and compliance with 

other CAA programs can contribute to compliance with the Clean Power Plan requirements. The 

EPA agrees that there are opportunities for co-benefits related to compliance with other CAA 

obligations that can impact a source’s ability to also comply with CPP requirements. For 

example, under regional haze SIPs, states establish interim goals, referred to as reasonable 

progress goals, for visibility improvement. In setting these goals, states may include the visibility 

improvement co-benefits resulting from emission reductions from other regulatory programs. 

Any planned reductions for the CPP that will yield significant visibility improvement can be 

factored into the states’ strategies for setting their reasonable progress goals.

With respect to the requirements under the regional haze program, the commenters point out the 

possibility of approved settlements that establish retirement dates for resources during the CPP 

compliance period and how this may affect the feasibility of these agreements. The EPA 

acknowledges the possibility that some Regional Haze related settlement agreements or SIP 

requirements on sources have the potential for stranded assets or a need to make adjustments to 

them as a result of state 111(d) plans. For these sources, states have the option of developing 

BART alternatives that replace control requirements that would otherwise result in stranded 

assets at a particular EGU with the aggregate emission reductions that will result from 

retirements, fuel switching, reduced utilization, or lesser controls at multiple EGUs. In addition, 

and as discussed in the preamble, the EPA has adjusted the compliance period for the final CPP 

from 2020 to 2022 in part to provide an opportunity for states and affected EGUs to do 

coordinated planning that considers multipollutant strategies and other CAA obligations and 

requirements such as those under the Regional Haze program. The EPA will continue to work 

with states to explore options for integrating compliance requirements across multiple regulatory 

programs, as warranted.

The following are summaries of the specific public comments under this comment:

Commenters expressed concern over the interaction of the CPP and NAAQS and Regional Haze 

Programs.

Commenters stated that the proposal and its basis and purpose are completely devoid of any 

mention of the ozone NAAQS, due to be published the same day comments are due on the 

section 111(d) proposal. The commenters stated that the OAQPS August 2014 Policy 

Assessment finds the current standard insufficiently protective and recommends a more stringent 

standard in the range of 60 to 70 ppb, which would have a material impact on the sources subject 

to the proposed section 111(d) rules. The commenters stated that a more stringent ozone standard 

would impact the timing and permitting obstacles to construction of new NGCC capacity 

necessary to replace dispatchable coal-fired capacity required to reduce utilization or retire as a 

result of the proposed section 111(d) rules and other EPA requirements, including the MATS 

rule. The commenters stated that a more stringent ozone standard would impose resource 

demands on states required to develop implementation plans, at the same time they must address 
99

the proposed Clean Power Plan; also, a more stringent ozone standard could complicate the 

states' obligations under proposed 40 CFR[Section]60.5740(a)(6), to demonstrate that each 

emission standard in the state's [Section]111(d) plan is "non-duplicative" with respect to an 

affected entity (i.e., will reductions in CO2 emissions or electricity demand resulting from 

compliance with revised ozone standards be deemed "non-duplicative"?) and would complicate 

States' evaluations of the optimum mix of "building blocks" for achieving the mandatory section 

111(d) "state goals." The commenters stated that only EPA knows the nature of its proposed 

revisions to the ozone standard, and the interactions between a more stringent ozone standard 

and its section 111(d) proposal; it is for EPA to address in the first instance the implications of a 

revised ozone standard on the proposed section 111(d) rules.

Commenters stated that EPA can contribute to state compliance with the CPP's CO2 targets by 

promptly and consistently implementing the recently revised NAAQS for ozone, SO2 and 

PM2.5. The commenters stated that ensuring compliance with the new NAAQS standards is 

likely to reduce CO2 emissions as coal plants are de-rated or retired as part of a NAAQS 

compliance strategy. The commenters stated that EPA can further implement the CPP by 

enforcing the regional haze rule, which has already produced co-benefits to the CPP by shifting 

generation sources from large CO2 emitters like coal-fired power plants to sources such as 

natural gas turbines and renewables. The commenters identified 25 coal-fired EGU's that have 

been, or will be soon, retired as a result (in whole or in part) of the regional haze rule thereby 

reducing EGU emissions of CO2 by over 52 million tons a year, independent of the CPP. The 

commenters stated that the next regional haze update is due in 2018 and EPA should ensure that 

states revise their regional haze SIPs to include significant pollutant reduction for coal plants that 

are contributing to visibility impairment as part of the long-term strategy to meet visibility 

improvement requirements. 

Commenters stated that the proposed rule is premature both in the context of ongoing 

international negotiations for a global climate agreement in Paris in 2015, and the likelihood of a 

more stringent domestic ozone standard requiring retrofits of SCRs or additional closures of 

coal-based generating plants. 

Commenters stated that EPA's proposed approach to setting the interim goals does not recognize 

current or future EPA approved settlements under the Regional Haze Rule that involve 

established retirement dates for resources during the 2020-2029 window; in many instances, 

EPA is reviewing or has approved Regional Haze settlements in which the owner or operator of 

an EGU agrees to cease operation of a coal-fueled resource by a date certain. The commenters

stated that these settlements are often the result of years of extensive negotiations and carefully 

examined emissions reduction findings and customer cost impacts. The commenters stated that 

EPA's interim goals have the potential to effectively nullify these agreements and require the 

retirement or displacement of those resources by 2020.

Commenters stated that state plans should address how their activities affect the attainment of 

NAAQS in neighboring states. Commenters stated the CAA's good neighbor provision provides 

a specific basis for taking the effect of emissions on one's neighbors into account in a planning 

process.
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Comment 6: Direct and Indirect Impacts of EPA follow-on rules for other industries

Response 6: Commenters all seem to be concerned that this rule in combination with other 

recently promulgated rules will adversely impact the availability and reliability of electricity at 

least in part because the will impose requirements on coal-fired power plants. The utility power 

sector is undergoing major changes toward a cleaner electric generation fleet, and the imposition 

of regulations by EPA is only one of them, as commenters correctly noted. Changing relative 

fuel prices, falling renewable energy prices and flattening demand growth are also have a large 

impact on the industry. These however do not necessarily have an adverse effect on reliability as 

newer cleaner generation become available to replace older more polluting generation, and as 

more efficient use of generation enhances reliability. As EPA explained in the preamble to the 

final rule, the electricity system has features that ensure that electricity system reliability will be 

maintained. EPA’s regulations for this sector, have also been designed to assure that they will 

not interfere with the maintenance of reliability. In the final CPP, for example the long planning 

and implementation timeline, the flexibility given to states to design a plan that suits the state’s 

power sector, the availability of a market mechanism, and the provision for a reliability safety 

valve, all support the maintenance of electric reliability. In addition, EPA, along with DOE and 

FERC will monitor the implementation of the CPP just as we have MATS to assure that 

reliability is not affected. 

Commenters seemed to be particularly concerned that MATS will cause a reliability problem but 

the MATS deadline has passed for all but those plants that received an extra year for compliance. 

EPA along with FERC and DOE have been monitoring compliance and we have not seen 

reliability problems. Nor do we see problems on the horizon that cannot be addressed within 

normal processes as we approach the final deadline next April. 

The following are summaries of the specific public comments under this comment:

Commenters stated that the agency is committed to a number of follow-on rules that will impact 

the commenters twice, both as electricity customers and also as industries next in line for 

subsequent EPA rules. The commenters stated that the substance, process and ultimate outcome 

of the initial proposed regulations on power plants are certain to influence the regulations that 

will be subsequently proposed. Commenters stated that regulations, including the MATS, the 

Cross State Air Pollution Rule, coal combustion residuals, and Clean Water Act section 316(b) 

cooling water intake structures, will impact our industry directly; however, they will also impact 

us indirectly because of their effect on coal-fired utilities, which threatens the availability and 

reliability of electricity to large industrial customers like steel. The commenters stated that in 

addition to the economic impacts of these collective regulations on our sector and the electric 

sector, the CPP will necessitate fundamental changes necessary to the production and 

distribution infrastructure.

Commenters stated that overall, market forces - especially lower natural gas prices - have 

gradually contributed to the transformation of a cleaner electric generation fleet as some coal 

units have been replaced by natural gas units. The commenters stated that the MATS rule has 

contributed to this trend, although at a faster pace than preferred. The commenters stated that 

they remain very concerned about the reliability implications of MATS, especially in the 

Midwest during the summer of 2016. The commenters stated that adding new carbon dioxide 
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compliance obligations on top of MATS creates a complex regulatory environment, the 

implications of which are not yet understood. 

Commenters suggested that an ANPR would allow for notice and public comment from 

impacted stakeholders, as well as a source-category specific endangerment determination for 

GHG emissions. Commenters continued, stating that while EPA should not proceed with 

standards of performance for other source categories, it must make assurances that other sources 

are not at risk of being regulated by the EGU standards and then again for section 111 standards 

for their own source category. Commenters stated that EPA should include a provision in the 

final rule that exempts any facility that is part of a state compliance plan for EGUs under the 

CPP from any requirements under a future 111 regulation for that source category, and at a 

minimum, EPA should ensure that there is a crediting mechanism to guard against the potential 

double-regulation of other source categories.

Comment 7: CPP may trigger NEPA

Response 7: The agency recognizes that there are numerous demands on states, cities and towns, 

communities, and utilities, and, in this final rule, we are providing more time for planning, 

consultation and decision making in the formulation of state plans and in EGUs’ choices of 

compliance strategies. The final emission guidelines also provide states and utilities with the 

latitude to consider a broader range of options to achieve the required reductions while 

addressing concerns about ratepayer impacts and stranded assets. It is the state that will 

determine how, in its plan, to comply with the final emission guidelines, and the state will be 

able to take into consideration its specific circumstances when choosing from numerous 

measures, including measures that are not part of the EPA’s determination of the BSER. 

Commenters noted that a fair number of coal-fired plants have retired and that the CPP would 

cause more to retire. There are a number of coal-fired plants that have retired in the past few 

years. Most of these retirements have been driven by the vast changes in the electricity market,

including changes in relative fuel costs, the increasing economic viability of renewables, and the 

slowed growth in demand for electricity as the country becomes more efficient in its use of 

electricity. Our analyses indicate that 27 GW to 38 GW of coal-fired capacity may become 

uneconomic to maintain by 2030 due to implementation of the final emission guidelines.

The following are summaries of the specific public comments under this comment:

Commenters stated that the EPA did not take into consideration the requirements of the National 

Environmental Policy Act (NEPA) and delays required under that federal law in establishing 

timelines for implementation of the rule. The commenters stated that they, like many rural 

electric cooperatives, borrow capital from the U.S. Department of Agriculture Rural Utility 

Service (RUS). Commenters stated that projects by an RUS Borrower can be determined to be a 

major federal action under the NEPA and require additional studies and delays to projects 

required to meet the plan. Commenters stated the CPP should conduct a state by state study to 

determine the time required to finance, permit, construct and commission new NGCC 
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generation, pipeline infrastructure and/or transmission projects to meet building block 2 and take 

that into consideration when establishing interim goals.

Commenters stated that any pipelines or transmission lines that cross the federal lands must 

comply with NEPA and depending on the length of a transmission line or pipeline, and 

depending on the impact, this process could last for years. The commenters stated that there is 

also the possibility that a proposed line may be delayed in court battles or contested hearings 

regarding the impact to both federal and state lands. The commenters stated that the EPA's 

assumptions regarding NGCC dispatch did not adequately take into account the lack of natural 

gas infrastructure in the states or the timeline and process it would take to build sufficient 

pipeline capacity to make the EPA assumptions correct.

Commenters stated that by 2015, as sources comply with the federal Mercury Air Toxics rule 

and other environmental regulations, a total of 18 units, totaling 2,819 MW, accounted for nearly 

one-fifth of West Virginia's generating capacity will have shutdown.

Commenters stated that some stakeholders have mistakenly suggested that compliance with the 

proposed regulation, as currently drafted, might be largely achieved through fuel conversions or 

generation retirements that are already planned as a result of the EPA's MATS rule. The 

commenters stated that EPA is aware that its own modeling shows that the proposed regulation 

would cause many unplanned retirements of coal units to occur in Virginia, and throughout the 

country. 

Comment 8: The assumptions the EPA makes in the proposed rule fail to take into consideration 

other environmental regulations.

Response 8: With respect to the comments related to BART requirements under the regional 

haze program, the commenters raise a concern with the impact of this regulation on the cost 

effectiveness analysis conducted as part of a BART determination under the regional haze 

program. In particular, the commenters ask EPA to ensure that compliance with the CPP does 

not result in stranded investment in BART pollution controls. As discussed in the preamble and

elsewhere in this document, the EPA acknowledges the possibility that some regional haze 

requirements on sources have the potential for stranded assets or a need to make adjustments to 

them as a result of state 111(d) plans. For these sources, states have the option of developing 

BART alternatives that replace control requirements that would otherwise result in stranded 

assets at a particular EGU with the aggregate emission reductions that will result from 

retirements, fuel switching, reduced utilization, or lesser controls at multiple EGUs. In addition, 

the EPA has adjusted the compliance period for the final CPP from 2020 to 2022 in part to 

provide an opportunity for states and affected EGUs to do coordinated planning that considers 

multipollutant strategies and other CAA obligations and requirements such as those under the 

Regional Haze program. The EPA will continue to work with states to explore options for 

integrating compliance requirements across multiple regulatory programs, as warranted.
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In addition, the EPA disagrees that the Clean Power Plan would necessarily result in reduced 

utilization at existing coal-fired EGUs for the following reasons: (1) many coal-fired EGUs are 

expected to retire between 2012 and 2020, reducing the remaining capacity of existing coal-fired 

EGUs during the interim and full compliance periods; (2) EPA modeling of electricity generation 

in 2030 indicate that the remaining coal-fired EGUs will have higher annual capacity factors than 

the 884 coal-fired EGUs in 2012 – the baseline for the agency’s heat rate improvement analyses; 

and (3) states have flexibility when developing their state plans and would be able to choose 

policies that would not have detrimental impacts on emissions of traditional pollutants . In any 

case, the EPA expects that the EGUs and associated pollution controls will be operated 

appropriately to meet their regulatory requirements.

The following are summaries of the specific public comments under this comment:

Commenters stated that regulatory uncertainty has adversely affected the sulfur dioxide cap-andtrade credits program. The commenters stated that market prices of credits were firm until 2008 

but started falling after that when the market lost confidence in the program. To illustrate the 

uncertainty in just one part of the regulatory program, the commenters included a table showing 

the allocation of EPA's auction of SO2 credits. The commenters stated that the additional 

combined uncertainties of the various other regulatory programs only serve to compound the 

difficulties for the commenters in planning its environmental compliance strategy.

Commenters stated that they are joint-owners of two coal-fired power plants that are subject to 

the Regional Haze program of the CAA and that are subject to best available retrofit technology 

(BART) determinations for the purpose of reducing visibility impairing pollutants in Class I 

areas; a key consideration is the cost-effectiveness of the control technology and assumes a high 

utilization of the BART eligible source and the investment is amortized over the source's 

remaining useful life. The commenters stated that the proposal is at odds with the fundamental 

assumption that BART eligible sources continued to be highly utilized and emit visibilityimpairing pollutants and creates serious uncertainty as to remaining useful life factor when 

conducting BART determinations. The commenters provided an analysis of the impact of the 

proposed rule on a BART cost-effectiveness analysis assuming a lower utilization of this plant to 

comply with the proposal. The commenters stated that in its analysis, the cost effectiveness of 

the installation of a SCR for NOx would be 1,955 tons/yr, increasing the cost/ ton from $9,072/ 

ton to $11,921/ton. The commenters stated that this example highlights the uncertainty caused by 

this proposal, as state regulators are put in the untenable position of trying to create a range of 

potential cost impacts when doing BART determinations due to the uncertainty surrounding the 

future utilization of these units to comply with the proposal. The commenters stated that BART 

eligible sources should not be required to install costly BART controls when compliance with the 

CPP will likely undermine the cost-effectiveness of those BART controls. The commenters

stated that EPA needs to revisit the interplay between 111(d) and BART determinations currently 

being implemented at facilities or being considered by state air regulators to ensure compliance 

with the CPP does not result in stranded investment in BART pollution controls.

Commenters stated that they are concerned that EPA is undertaking a piecemeal approach to 

address emissions that lacks cohesion (e.g., Grand Canyon Trust visibility issues, new standards 

impacting regional visibility issues, regulation of CO2 for new plants, retroactive application of 
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new rules for CO2 for existing plants and recently announced notification that EPA will 

introduce new Ozone emission standards) and that public utility compliance with such an 

approach is expensive and the associated costs will be passed on to ratepayers. The commenters

stated that their utility ratepayers and ratepayers of other states appear to be ever at risk of EPA 

implementing yet another higher standard. The commenters stated that they believe that it is fair 

and appropriate to grandfather compliance relative to new standards; absent this, it is necessary, 

at a minimum, to provide sufficient credit to utilities, their respective ratepayers and the State for 

past undertakings and investments, incurred by the utility and paid for by consumers, that have 

improved air quality and that also have the effect of reducing emissions. The commenters stated 

that they should receive credit for the benefits already attained by doing the right thing and the 

improvement costs incurred by utilities and currently being paid for by ratepayers needs to be 

recognized by the EPA if its proposed rule is adopted and implemented.

Commenters stated that there are likely other provisions in the CAA that have "absurd results" 

when it is used to regulate CO2 or other greenhouse gases; consistent with the CAA, those 

provisions should all be identified and "tailored" to provide for the greatest opportunity to avoid 

unintended or negative consequences should this program for EGUs be implemented under 

Section 111 (d) of the CAA.

Commenter stated that a detrimental consequence of reducing utilization at baseload coal plants 

will be an increase in emissions of traditional air pollutants. The commenters stated that 

equipment used to limit these emissions often requires that threshold conditions such as 

minimum temperature be reached before the equipment can be operated or before optimum 

effectiveness can be realized.

Comment 9: Shifting pollutants from one media to another

Response 9: The EPA agrees with commenters that some pollution controls can result in a 

cross-media transfer of pollutants. The coal combustion residuals rule, and the soon to be

finalizing a rule to revise the effluent limitations guidelines and standards for the steam electric 

power generating industry help to address these cross-media issues. These rules assure that

discharges of toxic and other pollutants to waters of the United States and to ground water are 

well controlled.

The following are summaries of the specific public comments under this comment:

Commenters stated their concern for transferring pollutants from the air to the land and water, 

such as the contamination of the Dan River in North Carolina where Duke Energy ash ponds 

contaminated the river. The commenters stated that by cleaning up the energy industry, not only 

will it reduce carbon emissions but it will have a wide-reaching impact into other areas of 

environmental protection; and added right now we have strengthened the Clean Air Act at the 

expense of our rivers. The commenters recommended that not only should we strengthen our 

Clean Air Act and our regulations for emissions, but we also need to strengthen our Clean Water 

Act so that we don't just move the problem from one part of our environment to another.
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Comment 10: Agriculture, land use and forest carbon incentive programs

Response 10: In the final rule, State plans may accommodate emission budget trading programs 

that may include out-of-sector GHG offsets, which we are finalizing as an option under the state 

measures plan type. See Section VIII.C.3 of the final rule preamble of the CPP.

The following are summaries of the specific public comments under this comment:

Commenters stated that they support other potential forms of state-run agriculture, land use, and 

forest carbon mechanisms that function differently from offset markets but achieve comparable 

performance in terms of quantifiable and demonstrable emissions benefits. The commenters

stated that these additional mechanisms could provide states with enhanced flexibility in working 

with landowners and other mitigation project developers; some of these potential incentives 

mechanisms, such as a state-run carbon bank or state-run incentive program, could be partially or 

entirely funded through revenues generated by state compliance mechanisms within a state 

improvement plan (SIP). The commenters stated that state-led agriculture, land use, and forest 

carbon incentive programs also offer an effective mechanism to leverage revenues associated 

with 111(d) compliance actions toward further carbon benefits beyond EPA targets. The 

commenters stated that this will support progress toward the United States' international 

leadership in the climate change arena, including the newly announced national-level carbon 

goals for 2025 incorporated in the US-China climate agreement and other future international 

obligations.

Comment 11: Implementation of BART at the Navajo Generating Station will ensure 

compliance with proposed standards under Clean Power Plan

Response 11: The EPA appreciates the commenters’ support.

The following are summaries of the specific public comments under this comment:

Commenters stated that they concur with the EPA's determination in the supplemental proposal 

to the Clean Power Plan that Indian Country, specifically Navajo Generating Station will meet 

the proposed carbon standards of the Clean Power Plan through compliance with the NGS best 

available retrofit technology provisions of the Clean Air Act and the regional Haze Rule.

Comment 12: Significant cost associated with BART rulemaking and its implementation

Response 12: This comment is outside the scope of the final rule which established emission 

performance rates for individual EGU, including EGU located in Indian country, and mass- and 

rate-based performance goals for various geographic areas, including areas of Indian country 

containing EGU, and the framework for subsequent state, tribal and federal plans implementing 

the final Emission Guidelines (EG). EPA notes, however, that costs associated with the BART 

rulemaking process and the implementation of the BART final rule for Navajo Generating 

Station (NGS) are fully discussed in the Regulatory Impact Analysis (RIA) prepared in 
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conjunction with that rule which can be found in the rulemaking docket for the rule. EPA further 

notes that it will remain cognizant of the commenters’ concerns regarding possible carbon off-set 

credits in assessing any proposed tribal or federal implementation plan (should EPA find it 

necessary or appropriate to establish such a plan) implementing the final EG and that the 

commenters will have the opportunity to comment further on that issue in conjunction with any 

such rulemaking. With regard to commenters’ comment concerning the pending lawsuit 

challenging the BART final rule, EPA notes that it is defending that rule and further notes that 

the BART final rule and the final Clean Power Plan are separate and distinct rulemakings. EPA 

remains fully cognizant of the importance of NGS in the context of federally guaranteed water 

delivery.

The following are summaries of the specific public comments under this comment:

Commenters stated that it is important for EPA to recognize that the BART rulemaking process 

and the implementation of the BART final rule for the Navajo Generating Station has and will 

continue to have significant cost implications for the commenters’ community. The commenters

stated that there are two additional issues that the community urges the EPA to address in its 

final rule: First, the EPA should ensure that carbon off-set credits are allocated among NGS's 

owners in a way that avoids any increase in the cost of NGS power; and second, concerning the 

pending lawsuit challenging the BART final rule, the commenters believed that the EPA must 

allow adequate flexibility in the final rule to address the possibility that the Court overturns 

EPA's BART rule. The commenters stated that the community appreciates EPA's recognition that 

compliance with the clean power plan rule at NGS, unlike at the other power plants in Indian 

Country affects not only the tribe where the plant is located, but many other tribes, such as the 

community that rely on the NGS for federally guaranteed water delivery.

7.8 Other

This section addresses comments received on other topics relevant to this chapter. Commenters 

have raised a number of issues related to this subsection which are organized by topics 

(comments) below. Responses are provided for these topics.

Comment 1: Avoid creating disincentives for electric vehicles 

Response 1: The final rule provides states with the ability to use both a rate-based or mass-based 

plan approach. Plan approaches are addressed in the preamble to the final rule in section VIII.C. 

The EPA disagrees with the assumption of the commenters that growth in electricity demand 

cannot also be accommodated under a mass-based plan approach, and that accommodation of 

load growth requires adjustment of state mass-based CO2 goals for affected EGUs. The EPA 

notes that under both rate-based and mass-based plan approaches, CO2 emission reductions can 

be achieved while accommodating growth in electricity demand. Both rate-based and mass-based 

state CO2 goals apply to CO2 emissions from existing affected EGUs. Electricity load growth 
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can be accommodated through a mix of electricity generation from affected EGUs, low- and 

non-emitting non-affected EGUs (including new fossil fuel-fired EGUs subject to CAA section 

111(b)), and reductions in electricity demand through demand-side EE improvements.

The EPA also notes that increased deployment of electric vehicles (EVs), while increasing 

electricity load, can also help states meet the emission guidelines, under both rate-based and 

mass-based plan approaches. The EPA notes that EVs can be used as a distributed electric 

generating technology, where EVs docked at a charging station can be used to discharge 

electricity to the grid. For example, docked EVs, especially groups of EVs such as fleet vehicles, 

can be used as an electric generation source during peak demand periods – periods where higheremitting fossil fuel-fired EGUs are typically dispatched to meet peak demand. The EPA is aware 

of technologies in the commercial demonstration phase that would provide such capability for 

docked EVs. The use of energy storage in a state plan is discussed in section VIII.K.1.a.(5) of the 

preamble to the final rule, and the EPA notes in that section that the use of energy storage 

technologies can facilitate greater grid penetration of intermittent RE generating technologies.

The following are summaries of the specific public comments under this comment:

Commenters stated that EPA should ensure that implementation of standards for electricity 

generation does not unintentionally create disincentives for states that are deploying plug-in 

electric vehicles, a critically important strategy for reducing global warming emission from the 

transportation sector. The commenters stated that under the mass-based approach as proposed, 

the standards could result in a disincentive for states from encouraging greater electric vehicle 

deployment which would lead to higher electricity demand and therefor greater emissions in the 

electricity sector. The commenters recommended that EPA consider modifications to the 

proposed standards to avoid creating disincentives to greater electrification in the transportation 

sector; allowing for an adjustment to the mass-based emissions target to reflect the actual 

electricity demand from transportation electrification, should it differ from what is already 

assumed in a states projected baseline, would avoid discouraging states from supporting greater 

EV deployment. The commenters stated that ultimately, the power plant standards should be EV 

neutral, and avoid an outcome where emissions benefits of EVs are counted in both the power 

plant rule and the vehicle standards.