1 TABLE OF CONTENTS

CHAPTER 7 INTERACTIO NS WITH OTHER EPA P ROG RAMS AND RULES

............ 2
7.1 EGU NSPS

- New

................................ ................................ ................................ .................... 2
7.2 EGU NSPS

- Modified and Reconstructed

................................ ................................ ........... 7
7.3 New Sou rce 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

................................ ................................ ................................ ................................ .... 1062 CH APTER 7 INTERACTIONS WITH OTHER
EPA PROGRAMS AND RUL ES

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: EG U 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 Langu age 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 orga nized by topics (comments) below. Responses are provided for these topics.

Comment 1: W hile 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

.3 Response 1 : Th e EPA disagrees with the commenters assertions based on our analyses of low

and 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 suppo rting 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

- f ired 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 l ikely 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 assert ed 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 Renewabl e 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 speci fic public comments under this comment:

Commenter s 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 commenter s stated that in order for EPA to demonstrate the achievability of the
standa rd, 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 af fect the achievability of the
standard. The commenter s stated that a review of the supporting documentation indicates that EPA has identified and considered some, but not all, relevant variables when proposing an4 emissions standard for NGCC units; in parti cular, 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 commenter s stated that witho ut such consideration, EPA's analysis cannot be said to be reasonable, nor can the resulting emissions standard be deemed achievable.

Commenter s stated that the overall impact of cycling is to reduce overall emissions because fossil units are being used l ess, 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 commenter s stated that in these cases, while the emissions increases due to cycling m ay 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 ba sed units would serve to punish, rather than reward, those units that are required to undergo more frequent cycling to
accommodate renewable resour ces. The commenter s stated that EPA should not penalize practices that foster the emissions benefits associat ed with increased operation of variable,
renewable resources. The comm enter s 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

Respon se 3: B ecause 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 provisi ons for startup and shutdown events.

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

Commenter s stated that the proposed standards must accommodate lower utilization rates and more frequent periods of startup and shutdown. T he commenter s 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 exa mple, the final industrial boiler MACT rule and the MATS rule), EPA has di fferentiated between startup and shutdown (SS) periods and periods of normal operation, providing work practice standards to minimize emissions during SS periods.

As commenter s ha ve s commented on past rules, the Agency's rationale for imposing numeric
emi ssions limits during SS periods instead of work practice standards appears to be based on incorrect, overly broad assumptions about utility operations. The commenter s 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 commenter s stated that it is not correct to assume that the majority of natural gas

- based units operate at high capacity factors5 all of the time, which would corresp ond 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 commenter s stated that in fact, the NG TSD notes that the

mean annu al 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 design ed and built. The

commenter s 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 n ature and fails to account for the future operational characteristics of new NGCCs in accommodating increasing amounts of intermittent renewables and distributed generation. The commenter s 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

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

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

The commenter s 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. Th e

commenter s 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 nonco mpliance, 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 commenter s stated that such practices would risk distorting electricity markets and not p roducing a least

- cost outcome for consumers.

Comme nt 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 (t he 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 tha t 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 j ust 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 generat ion 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:6 Commenter s stated that EPA should consider the impacts of the NSP S for EGUs; specifically the NSPS effectively prevents replacement of retiring coal

- fired EGUs with new supercritical or
ultra

- supercritical plants. The commenter s stated that despite a 2013 Congressional Research Service report observation that an advance d 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 e missions 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

c apture and sequestration (CCS) add

- on systems. The commenter s stated that they will not be built because CCS would negate their efficiency benefits and render them economically
infeasible.

The commenter s stated that the net effect of the CPP and NSPS is t o 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 commenter s stated that a sig nificant 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 prec lude replacement of these retiring units
with new er, more efficient units. The commenter s 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 EP A 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 well

establish ed 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 s ection 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, 2014.7 Commenter s stated that their newest, cleanest unit does n ot and cannot come close to meeting the 1,100 lb/MWh limit for new plants. The commenter s 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 commenter s 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 marke t 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 RECONST RUCTED

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 und ertake 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 N SPS modification and limit cost

effective 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 increas e 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 have8 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
smal l 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 an d 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 respe ct 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 :

C ommenters 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

commenter s urged the Agency to clarify that not only traditional pollution control projects qualify for the exclusion, but also physical or operation al 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 ke ep 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 u nit's best
annual heat rate.

Comment 3 : Cre dit 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 wou ld not become a modified EGU and would therefor get credit for the decrease in its emissions in9 complying with an emission standard or state measure. Additionally, that decrease in emissions would be reflected in the States overall average or cumulative s um of emissions.

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

Commenter s 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 commenter s 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 re ason, the proposed standards will not result in any significant emission reductions, costs, or quantified benefits in the period of analysis.

7.3 NEW SOURCE REVIE W (NSR)

This section addresses comments received on interactions of the EGU GHG Emission Gui delines 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 : Commenter s requested clarification f rom EPA as to how a state plan could protect
a source from triggering NSR regulations.

Response 1 : Commenter s ’ assertions regarding what they per ceive 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) complianc e 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 sta te 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 devel opment 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 expect ed 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.10 Regarding commenter s ’ 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 authorit y to create such exemptions from the NSR rules. In addition, commenter s ’ 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. Commenter s ’ 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 mat ter 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 discu ssed 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 resul ting 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, wh ile 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 req uirement to limit or completely avoid any sources from triggering these requirements. T he 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 s ummaries of the specific public comments under this comment:

Commenter s 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.
Commenter s sai d 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. Commenter s said NSR requirements could cost a utility hundre ds11 of millions of dollars, both to comply with BACT requirements and potentially for other costs and penalties. Commenter s 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. Commenter s 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 ..." Commenter s said these suggestions are merely more variations on EPA's theme to force fossil fuel units to reduce utilization and generation.
Commenter s said not onl y 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.

Commenter s 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. Commenter s said the appropriate solution, in commente r s ' 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 s hall not be deemed to trigger NSR. Commenter s 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 antici pated by the utility had the project(s) been completed.

Commenter s stated that it is not clear what EPA's intentions are. Commenter s said that to the extent that EPA is suggesting that a state could lawfully force a source to subject itself to NSR requirem ents by requiring compliance with the section 111(d) plan, commenter s object.
Commenter s said nowhere in the proposed CO2 guidelines has the EPA analyzed the significance, cost and economic impact that such a nationwide program would have.
Commenter s 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 amo unt 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 t hat 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 havi ng 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

t est 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 could12 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 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 le vels 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 s hould 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 b oiler would, without questi on, 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 c oal

- 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 plan t 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 th e 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
modificat ion 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 t hat 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 define d in the NSR regulations, believes that such sources would be able to increase their utilization without the need for a NSR permit.13 Regarding the comment that the EPA instead of states conduct an analysis consistent with the NSR regulatory requirements th at 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 d o 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 p ollutants, 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 fol lowing are summaries of the specific public comments under this comment:

C ommenters stated that actions necessary to comply with state guidelines have the potential to trigger NSR. The commenters recommend ed that EPA exempt sources from NSR as they comply with 111(d) guidelines or provide an expedited permitting path.

Commenter s 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 G HG reduction requirements should not force further reductions in criteria pollutants.

Commenter s 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 commenter s 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.

C ommenters recommended the following regulatory language to avoid triggeri ng 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 the14 method of operation for purposes of establishing a major modification under 40 CFR section 52.21(b)(2)(i).

C ommenters 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 physi cal 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 so urce 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 streamli ne 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.

Commenter s 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 commenter s recommended that the EP A 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 plan s. The commenter s recommended adding language that excludes projects undertaken pursuant to a state Section 111(d) plan from the definition of "major modification." The commenter s stated that another approach would be to handle physical or operational chan ges 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 increa se of any regulated NSR pollutant would not trigger NSR permitting requirements. The commenter s 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 o f achieving a state goal under Section 111(d), the source may trigger NSR permitting requirements. The commenter s 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 t aken synthetic minor restrictions to avoid NSR and increasing utilization may impact the status of these units and trigger NSR. The commenter s stated that as such, it should not be assumed that these units can meet or exceed a 70 percent utilization rate w ithout the removal of certain permit
restrictions.

Commenter s stated that implementation of the proposed rule's building block 1 is likely to trigger NSR requirements. The commenter s recommended that EPA develop alternative screening methods for an expedit ed, streamlined NSR process designed to ensure that any criteria pollutant increase would not interfere with the attainment of NAAQS. The commenter s stated that these screening tools can confirm that well

- controlled sources and sources with net
emissions i ncreases of criteria pollutants below levels that would interfere with attainment have satisfied NSR requirements. The commenter s stated that EPA could also find that compliance with Section 111(d) standards satisfies applicable PSD and BACT requirements f or 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 Commenter s stated that even the seemingly already

- available NGCC c apacity for re

- dispatching
needs further consideration. The commenter s 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 c hange in the method of operation. The commenter s 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 br oad interpretation of the major modification definition. The commenter s 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 commenter s stated that none would appear applicable to a NGCC which requires a project either related to or unrelated to the re

- dispatching. The commenter s stated that with no major modification exemption appearing to be applica ble, 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 commenter s 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.

Commenter s stated that unless NGCC facilit ies 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 commenter s stated that the Afton Generating Station is permitted to o perate 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 commenter s stated that for this assumption to be a possib ility, 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 ope rating costs. The commenter s 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. Commenter s stated that EPA needs to be conscious of any possible constrain ts regarding dispatch of less CO2 emitting units. The commenter s 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 energ y 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.

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

s ection 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

p erformance in their s ection 111(d) plan, the source's emissions would not increase in a way that triggers NSR requirements. The commenter s agree d with EPA that such an analysis would be appropriate but does not agree that the analysis should be left up to the states. The commenter s
state d 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 commenter s stated that , for example, it is unclear whether EPA intends that16 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 avoi d NSR for their heat rate improvement projects. The commenter s stated that EPA should undertake the analysis and make the determination that sources in compliance with their standards of performance in their s ection 111(d) plans would not trigger NSR requi rements. The commenter s 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 ana lysis 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 s ection 111(d) performance standards or even enforcement actions brought by EPA.

Commenter s state d 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 b een 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 S O2. 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 ap ply 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 require d 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 st ate 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 mad e 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 CO 2 emission performance rate milestone to obtain NSR per mits. 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 suf ficient 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 wha t 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 decrease d
emissions of CO 2 , the EPA believes it is unlikely that sources will be required to get a PSD permit for increases in CO 2

. 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 CO 2

. 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 ex isting 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 BA CT floor for existing EGUs

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

C ommenters 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.

Commenter s stated that EPA failed to consider NSR constraints on achieving heat rate improvemen ts at coal

- fired EGUs. The commenter s 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 applic ability determination from the state before undertaking the project, which likely would significantly delay installation of the improvements. The commenter s stated that EPA did not take potential NSR permitting
costs or limitations into account in establis hing 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 commenter s recommended that EPA ensure in the final r ule that current NSR policies do not discourage EGUs from undertaking heat rate improvement projects.

Commenter s 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 t he guidelines is incorrect. The

commenter s stated that the increased output and utilization associated with an efficiency

improvement 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 commenter s 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 commenter s stated that as a result, if the facility operated at a relatively low capac ity factor, and the future potential emissions are based on a higher capacity factor, the NSR significant emission levels could easily be triggered. The commenter s 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.

Commenter s stated that projects will be reviewed for compliance wi th 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 commenter s stated that every efficiency project will require review and application of the demand growth exclusion. The

commenter s 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 se t out in the plan. The commenter s 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 commenter s 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 b oth units are operated at an 80 percent capacity fact or prior
to the rule's effective date. Commenters stated i f 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 o ne solution would be, theore tically, 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 i t is not clear that the generation shift would qualify as demand growth. Commenters stated w hile the environmental benefits of this action are clear, NSR should also not be applicable to this project.

Commenter s stated that NSR is triggered by an annual i ncrease in emission mass (tons per year), which may occur with increased operations after an efficiency improvement project. The

commenter s stated that because EPA considers NSPS as the floor in determining a BACT emission limit for an existing unit modifi cation 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 commenter s stated that the modified and reconstructed NSPS emission limit (a 2% efficiency impr ovement 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 commenter s stated that as control technology becomes available, it is
conceivable that a BACT cou ld 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 commenter s stated that, even if EPA did not follow its traditional regulatory
int erpretation 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. The19 commenter s recommended that before finalizing this rule, EPA must directly addr ess the NSR issue by exempting all projects and demand growth due to re

- dispatch undertaken to meet the requirements of this rule.

Commenter s 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

commenter s 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 expect ed to deploy CCS, which, as discussed above in this testimony, would render the project economically unviable. The commenter s stated that even in the absence of finalization of the 111(b) rule, EPA's NSR requirements create perverse environmental incentive s, and can actually impede the deployment of newer and more efficient technologies.

Commenter s 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 regulate d pollutants and trigger NSR requirements if there is a significant increase of any one regulated pollutant under the CAA.
The commenter s stated that to create the regulatory environment necessary for existing sources to timely and economically meet the pr oposed heat rate improvements, EPA must exempt such projects from NSR. The commenter s 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 commenter s 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

commenter s 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 commenter s stated, in practice
EPA has allowed sou rces to use this demand growth exclusion narrowly, especially in circumstances where a source has changed fuels. The commenter s 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, und er EPA's current interpretation of its NSR rules, will likely trigger NSR permitting requirements for affected
sources. The commenter s stated that, thus, the goal of the proposal contravenes the existing promulgated NSR rules that are already being enforce d by EPA in that it will increase demand
for some electrons

- the product

- that were formerly generated by coal. The commenter s stated that additionally, states must prepare a SIP that will likely require increased utilization due to demand growth for les s

- intensive carbon generated energy. The commenter s 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 commenter s stated that EPA should

a lso 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 intensiv e unit should be exempted. The commenter s 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 a20 matter of law

- trigger NSR permitting requirements, we re commend that EPA categorically exclude such projects from NSR permitting requirements.

Commenter s stated that unlike NSPS, NSR rules do not contain an applicability exemption for pollution control projects and, for this reason, NSR has represented a substa ntial impediment to broad implementation of otherwise feasible, cost

- effective efficiency upgrade projects. The

commenter s 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 approve d, and what new permit conditions may be attached, including their potential costs. The commenter s 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 commenter s stated that finalizing a section 111(d) rule without including regulatory changes that address NS R 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).

Commenter s stated that EPA is underestimating NSR's impacts on sources and over

- estimating the ability of states to allow sources to avoid NSR. The commenter s stated that EPA's assumption that HRI changes would infrequently trigger NSR because of state fl exibility is
incorrect. The commenter s 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 commenter s 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 commenter s 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 NS R for our sources. The commenter s 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 commenter s 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 equi pment, 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.

Commenter s stated that regarding EPA's request for c omment 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 commenter s stated that they believe this rule should exempt any source from NSR that undertakes a change21 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.

Comment er s 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

commenter s stated that in their case the high pressure and intermediate pr essure (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 commenter s ' experience suggests that NS R 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 conten tious 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 throug h 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 tha t 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 there fore 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 p ermit 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 u ltimately 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

re quirements. 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 commente rs 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 not22 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 stat ed 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 mo dification 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 rem iniscent 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 commen ters stated that EPA's request for comments regarding the appropriateness of a categorical exemption from NSR for projects undertaken to comply with the p roposed r ule is disingenuous. The commenters stated that it is telling that this, a legal issue plainl y turning on the clarity of statutory language and on congressional intent, is nowhere raised in the l egal

m emorandum prepared by EPA, the express purpose of which is to provide background for the legal issues discussed in the preamble for the proposed rul e. 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 hav e been consistently rejected by the courts.

Commenter s 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 addit ional requirements that may accompany implementation of the proposed BSER. Referring to a table of NSR enforcement cases over HRI measures, the

commenter s stated there has historically been much confusion as to whether and what efficiency projects and prac tices trigger NSR. The commenter s 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 pote ntially trigger NSR, the commenter s 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 f or 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 commenter s 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

commenter s stated that the failure to provid e guidance in this area puts states in a difficult23 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 commenter s 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 no t subject the source to NSR. The commenter s stated that given the history of the NSR enforcement initiative, the commenter s 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.

Commenter s stated that owners of coal

- fired plants may refrain from making improvemen ts 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 commenter s 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 commenter s stated that the finances of power generating companies require that any large expenditure be justified, create a return on investment, or both.
The commenter s stated tha t 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 eco nomically attractive for smaller and/or older units with a few or
unk nown years of remaining projected lifetime.

Commenter s 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, w hich 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 o f future costs and other barriers.

C ommenters stated that although EPA does not foresee m any circumstances where projects that are required to achieve heat rate improvements at co al power plants trigger NSR, past experience
demonstrates that coal

- fired EGU s may face lawsuits from citizen groups, states or even EPA if they fail to obtain NSR permits prior to making efficiency improvements. Commenters stated

e ven when citizen suits lack merit, they often delay the implementation of efficiency improvement proj ects, 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 comm enters 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 Commenter s stated that the EPA acknowledges and quickly dismisses the potential NSR implications associated with the heat rate improvements required by Building Block 1. The

commenter s stated that the projects that EPA contemplates for heat rate improvements from the S&L Report and EPA's GHG Abatement TSD include upgrad es 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 pump s, flue gas conditioning systems, neural network optimization systems, selective catalytic reduction systems, system controls, and electrostatic precipitators.
The commenter s stated that EPA and citizens have brought NSR enforcement actions against
utiliti es 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 impor tant to maintaining and improving the efficiency of coal

- fired EGUs in the GHG Abatement Measures TSD.)

Commenter s cited clarifications from Sargent & Lundy regarding their 2009 study. The

commenter s stated that one of the clarifications was that many of t he options for HRI listed in the 2009 S&L Report have triggered New Source Review actions by EPA and others.

Commenter s stated that EPA identifies several heat rate improvement methods but ignores the
fact that several of these methods have been identif ied as NSR violations in enforcement cases brought by EPA, states, and citizen groups. The commenter s 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 commenter s 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 bes t, disingenuous.

Commenter s 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 commenter s recommended that EPA issue new NSR guidance that heat rate improvement p rojects are not the type of projects that should trigger NSR requirements.

C ommenters 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 init iative 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 comm enters 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 implementing25 building block 1 that do not project an increase in emissions as a result of an equi pment upgrade will face the ongoing threat of NSR litigation years after their projects.

Commenter s 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.

Commenter s stated that a clear statement in the final guidelines that any upgrades necessary to achieve efficiency improvements at existing c oal

- 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.

Commenter s stated t hat the final rule should establish an NSR accounting methodology to allow for HRI projects to be completed without triggering NSR requirements. The commenter s stated that the 10 major (over 500 MW) coal

- fired power units in Georgia not currently slated fo r 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 commenter s 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

commenter s 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 N SR review. The commenter s 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 commenter s recommended that because NSR rules will r estrict 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.

Commenter s 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 commenter s 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 commenter s stated that EPA should provide a specific NSR exemption for efficiency improvement proje cts, or at a minimum include in its analysis the negative impacts and costs of NSR issues on reasonably achievable efficiency improvement actions.

Commenter s stated that EPA has failed to address significant NSR issues presented by the Proposed Guidelines. The commenter s 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 commenter s 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 the26 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 t rigger NSR.

Commenter s 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 commenter s 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. Commenter s stated that during that same period, EPA and citizens have targeted almost 600 other projects as violating NSR and are provided in
an attachmen t 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 commenter s stated that these projects consist of " like

- kind replacement of worn existing component s," 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).

Commenter s stated that the upgrade projects identified in 2009 Sargent & Lundy report and the
GH G Abatement Measures TSD have been targeted by EPA and citizen plaintiffs as triggering the NSR provisions of the CAA. The commenter s stated that EPA issued an applicability determination for a turbine upgrade at Detroit Edison's Monroe Plant in 1999 citin g 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 commenter s 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 commenter s stated that, moreover, efficiency improvement s 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 p articular year. The commenter s 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 commenter s stated that t he 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

commenter s stated that EPA's own r ecognition 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 commenter s 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 efficien cy 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 commenter s 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 leas t implicitly acknowledged. Because EPA's justification of the state emission goals relies on the ability of sources to implement efficiency improvement27 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 commenter s stated that EPA's failure to account for the potential cost of NSR, and NSR uncertainty, for Building Block 1 projects in the Proposed Guide lines is arbitrary and capricious.

Commenter s 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 stri ct 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
incr easing parasitic load. The commenter s 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 he at rate improvements are generally outweighed by the new auxiliary load. The commenter s 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 h eat rate on average in order to comply with the Proposed Guidelines.

Commenter s 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 operat ing constraints that limit the ability of the utility to deploy the improved power plant. The

commenter s stated that this is not a practical solution to a recognized barrier to implementing the measures on which EPA based building block 1.

Commenter s state d 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.

Commenter s 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 commenter s 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

commenter s 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
ef

ficiency improvement project. The commenter s 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.

Commenter s stated that over 400 specific efficiency improvement projects of the type described in the S&L repo rt 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 or28 environmental advocacy groups alleging violations of the NSR permitting program for fa iling to obtain a permit prior to undertaking equipment replacement or other heat rate improvement projects at EGUs. The commenter s stated that those NOV s 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 enforce ment 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.

Commenter s 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

commenter s 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. T he

commenter s 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.

Commenter s 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 commenter s 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 crite ria pollutants for which they already have permits. The commenter s 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 improveme nt is actually possible.

Commenter s stated that a major modification, under the CAA, excludes routine maintenance, repair and replacement. The commenter s 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 commenter s stated that some court case decisions have agreed with EPA on the non

- rout ine activities however some courts case decisions have not; some of these modifications could be necessary to improve a plant's heat rate.

Commenter s stated that the proposed regulation goes on to say that if the emissions associated with unit's changes e xceeds the thresholds in the NSR regulations, the changes would trigger
NSR. The commenter s 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 commenter s 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 commenter s stated that29 assuming a 10 ppm increase in CO this typical 500 MW unit having a hea t 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.

Commenter s stated that the NSR risk cannot be defined at this time especially as it relates to operating time. The commen ter s 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 effic ient it could change its position on the dispatch curve and there could be a NSR violation.

Commenter s 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 NS R violations and EPA is not the sole entity challenging utilities. The commenter s 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 n ever finalized. The commenter s provided two examples (WEPCo and Duke Energy) of court cases that underlie current NSR policy interpretations.

Commenter s 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 commenter s stated that regarding item (a), increase of sp ecific 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 commenter s 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 commenter s stated that Bl ock 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.

Commenter s 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 commenter s 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 l onger period of time. The commenter s 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.

Commenter s st ated 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 comment er s 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 new30 permit conditions may be attached, including their potential costs. The commenter s 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 per mit application, creating a difficult do

- loop for permit seekers. The commenter s 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 commenter s stated that finalizing a 111(d) rule without including regulatory changes that address NSR applicability would significantly unde rmine the ability of EGUs to comply the proposed guidelines.

Commenter s 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 commenter s stated that the time required for permitting modifications to existing CGS and subsequent challenges to permits and non

governmental organizations litigation creates regulatory uncertainty and discourages changes to meet the requirements of the proposed rule. The commenter s 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 ene rgy 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 th e feasibility of the application of Building Block 1 (heat rate improvements) in the
BSER. The EPA acknowledge s that the costs associated with obtaining a NSR permit were not
included in the cost analysis included with the proposal. As discussed in the pr eamble 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 an alysis 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 stat e plan requirements that can include flexibilities and specifically designed requirement to li mit 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 emiss ions of NOx or SO 2

. A s 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 avoid s affected EGUs from triggering N SR. 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:

Commenter s stated that if modifications are likely to trigger NSR, the additional cos t 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.

Comm enter s 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 commenter s stated that complying with NSR entails signific ant 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.

Commenter s estimated that the r emaining coal

- fired EGUs would be forced to operate at capacity factors less than 20 percent to achieve the proposed C O 2 reduction goal for Pennsylvania. The commenter s 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 commenter s stated that in the event one of these EGUs retir es, 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 commente r s 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 C lean Power Plan would cause the expeditious retirement of existing coal

- fired EGUs through the imposition of the existing NSR program.

Commenter s stated that EPA overestimated the cost savings of heat rate improvement. The

commenter s stated that in its co st 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 co ntrols. The commenter s 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 t hat reductions associated with
HRI measures can be achiev ed 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 th eir 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 un its 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, a s described in the preamble, states are not required to follow the application of BSER as EPA did to develop state goals and have g reat 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 gener ation needed resulting in emissions reductions and potentially lower need for increased generation from units that have permit limits such as those cited by the commenter s . Finally, in response to numerous comments, the EPA has extended the interim perform ance 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:

Commenter s stated that some existing NGCC units currently have permits that limit their generation, which were taken to avo id NSR permitting requirements or, in some cases, for
economic reasons. The commenter s 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.

Commenter s stated that it is highly unlikely that the permit revision process, locating of any required emissions offsets, and the design and installat ion of control technology could be accomplished by 2020. The commenter s 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, in cluding air quality analyses and control technology evaluations.
The commenter s 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.
Comm enters 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 commenter s stated that, perhaps more importantly, the owner of a "synthetic minor" NGCC may not w ant 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 NSR33 Response 6 : The final emiss ions 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

t riggering 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 g reat flexibilit y 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 phys ical 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 a mounts 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:

C ommenters 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; a nd 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 rem ain 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 optio n 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 re view

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 r esult of complying with the 111(d) state plan. The commenter s 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. T he 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) and34 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 commenter s request clarification on why EPA expects that improvements in efficiency at affected EGUs would not frequently trigger NSR permitting. The modelin g 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 e nsure 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, stat es 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 dis patch. 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:

Commenter s stated that as a means of demonstrating compliance with NSR, they support an approach that allows states the flexibility to: estimate the amount of generati on 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 emiss ion 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

commenter s recommended that EPA finalize this approach or provide an alternative approach that clearly allows HRI projects to be completed without triggering NSR requirements.

Commenter s 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 commenter s 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 commenter s ha ve suggested, attempting to pre

- determine whether certain activities or business practices would trigger NSR. Rather, in t he 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 requi rements 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:

Commenter s stated that EPA's proposal to predeterm ine 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

t o 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 wo uld 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 threshol ds. 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 c omments under this comment:

C ommenters objected to sources' efforts to comply with 111(d) guidelines being excused from
NSR.

Commenter s stated that actions taken by a facility to comply with its obligations under Section 111(d) should not be excused from N SR 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 program36 for 1 11(d). Commenters stated n ew equipment must continue to meet Best Available Control Technology and provide offsets when required to contribute to clean air goals.

Commenter s 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 commenter s recognize d that modifications to exist ing 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 m any 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 furt her degraded.

Commenter s , 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 1 0 : The EPA proposal is in conflict with new source performance standards and new
source review

Respons e 1 0 : The commenter s 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 ap plication 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 indep endent 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 th e 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, th e commenter s ’ 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

commenter s that there is a conflict between 111(d) and NSR.37 The following are summaries of the specific public comm ents under this comment:

Commenter s stated that new generation units, or modifications to existing units, require compliance with BACT under the new source performance standards. The commenter s stated that EPA's proposed emission limits for new generation units of 1,000

- 1,100 lbs C O 2/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 commenter s stated that this is beyond any reasonable approa ch 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 commenter s stated that 111(d), however, applies only to stationary sources other
th an new sources and is not available to regulate existing plants which are required to comply
with new source review. The commenter s 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 commenter s stated that if the emissions increase associate d with the unit's changes exceeds the thresholds in the NSR regulation, the change would trigger NSR. The commenter s stated that 111(d) can't apply to new sources (modified sources are new sources), so the application of building blocks to existing units m ay 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
emission s 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 wit hin 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 electri c 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

- fire d 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 disco urages natural gas co

- firing projects38 Response 11 : We agree with the commenter s 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 fina l emissions guidelines. The commenter s cite to a Region III letter regarding the treatment of emissions increases at the Northampton Generating Company and the potential for the use of co

firing to trigger NSR as an example for why it would not be appropr iate to consider co

- firing in the goal setting. As the commenter s 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, includin g 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 technique s 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 comm ents under this comment:

Commenter s 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

commenter s stated that based on EPA's current guidance, co

- firing cannot be undertaken at most
coal

- fired EGUs without triggering NSR. The commenter s 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 referre d to as the demand growth exclusion). The commenter s 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 examp le, 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 u se 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 commenter s stated that, further, the Northampton Guidance indicates that all post

- project emissions would be co nsidered 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 commenter s 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 commenter s stated that such a consequence w ill discourage companies from undertaking natural gas co

- firing projects at their coal

- fired units. The commenter s stated that given the risk that co

- firing will trigger NSR or require units undertaking such projects to limit their future utilization, it i s not appropriate to consider co

- firing in the computation of the emission rate goals. The commenter s recommended that before considering this option, EPA should evaluate the costs associated with obtaining an NSR permit for co

- firing, including the potent ial 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 o n 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 expandi ng 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 commenter s 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 guidelin es 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 publ ic comments under this comment:

C ommenters responded to EPA's request for comments on options to avoid triggering NSR.

Commenter s stated that the potential options proposed by EPA to avoid CPP projects triggering NSR are too tenuous to consistently implem ent 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 commenter s 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 l ikely 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 l ess

- carbon intensive energy sources when40 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 emissi on 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.

Commenter s 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 commenter s stated that the key reason to invest i n 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 reco ver 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. T he commenter s 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

commenter s stat ed 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 commenter s 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, a s members of regional transmission organizations, do not possess. The commenter s 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 lo west variable operating costs are generally dispatched first, and plants with higher variable operating costs are brought on line sequentially as electricity demand
increases. The commenter s stated that it is unclear how the requirements of the proposed

gu idelines 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.

C ommenters 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 EG Us 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 emis sions. 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 i mprove 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 modifica tion 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 nett ing, 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 cu rrent 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 i n its rule preamble, however, the commenter s believe d 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 chan ges 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 associa ted 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.

Commenter s commented on two issues for which EPA requested comments: (1) the leve l 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' act ions to comply with plan requirements would not subject those sources to NSR. The commenter s stated that the most straightforward way for states to address these issues is to include in their plans source

- specific42 limits on affected sources' emissions or o perations that are sufficiently rigorous to ensure the sources will not generate enough emissions to trigger NSR. The commenter s 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.

Commenter s stated that beyond such source

- specific limits in state plans, however, states cannot lawfully or rationally include in their plans generic provisi ons 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 commenter s refer red 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).

Commenter s stated that EPA fails to identify any way that states could reliably assure that providing flexible compliance options would fo reclose specific sources from taking actions that would trigger NSR. The commenter s 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 commenter s stated that finally, to the extent th at 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 emiss ion limits based on best available control technology. The commenter s 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 endem ic in the aging U.S fleet. The commenter s 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 Co ngress in 1970 under the expectation that existing units would soon retire and no longer emit at unnecessarily high levels. The commenter s stated that nothing in the Act prevents older, grandfathered units from upgrading and improving the performance of th ose 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 commenter s stated that exempting sources from NSR would encoura ge 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 commenter s stated that
it would al so 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 seve rely disrupted by the NSR exemption that has been suggested.

Commenter s stated that EPA's proffe red solutions for avoiding NSR

- adjusting demand side measures or increasing reliance on renewable energy to reduce future emissions of an affected
source that m ay 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 commenter s stated43 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 commenter s 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 in crease system reliability.

Commenter s 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 commenter s 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 uni ts, even though these options will reduce emissions per megawatt of electricity produced.

Commenter s 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 commenter s 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 outco me is highly uncertain and unlikely to encourage needed upfront investment in EGU upgrades.

Commenter s 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 emitti ng generation. The

commenter s 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 emissi ons 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 t he 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 respons e to the Tribal and Territorial supplemental proposal, commenter s stated that EPA's assumed improvement in heat rate overlooks the potential for triggering NSR and associated Best Available Control Technology requirements. The commenter s stated that any mo dification, 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; heat

rate 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 commenter s 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 commenter s stated that absent such legislative reform of the NSR program, c ompanies must be v ery 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 appreciate s 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 positiv e, 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 w e lack the authority to create such exemptions from the NSR rules.

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

Commenter s stated that the increase in CCNG units on which building block #2 is based, at least
in the short

- term, is exceedingly optimistic. The commenter s 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, unti l 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 limitation s

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 th at 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 techniqu es 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 u nder 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 stat e environmental agency as they develop their 111(d) state plan.

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

C ommenters stated that, in setting state goals, EPA failed to recognize existing permit limitations
that wou ld prevent a facility from reaching a 70 percent capacity utilization.

Commenter s 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 restr ict the operation of a particular NGCC facility. The commenter s 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 res ource may operate; an example of these types of restrictions follows. The commenter s 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 permits46 Response 2: The supportive commenter s 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 fo rth 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 af fected EGU that would be incorporated into a source’s permit.

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

Commenter s support ed EPA setting emission targets for each state using the proposed BSER,
and commends EPA's deter mination that BSER for existing EGUs recognizes the complex interactions of generation, renewable energy and demand side reductions in the power grid. The

commenter s commend ed EPA for providing states multiple options in designing their compliance plans th at can be tailored to ensure this reliability, as well as encouraging a multi

state 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, b ut without federal enforceability of each individual regulatory action or enforcement process.

The commenter s 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 commenter s 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 commenter s stated that the relevant chapter is Chapter 85 of Title 42, and encompasses the
entire Cle an 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 commenter s stated that consistent with Clean Air Act Section 504, EPA has defined applicabl e 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 commenter s stated that EPA has already explicitly concluded that requirements under Section 111( d) are applicable requirements. The commenter s 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 issua nce. The commenter s 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 bio genic 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 sco pe of this rule.47 The EPA has recently issued a memo describing it past actions and next steps on assessing biogenic CO 2 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 r elease the second draft of the Framework for Assessing Biogenic CO2 Emissions fr o m 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:

Commenter s 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 lifecycl e basis. The commenter s stated that renewable and carbon neutral fuels should be considered a part of a diverse energy supply portfolio. The commenter s stated that by not properly exempting biogenic CO2 emissions, the PSD and Title V Programs potentially c reate 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 commenter s 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 commenter s stated that one commonality between EPA's listed studies and other biomass studies researched is the conclusion that bioenergy produces GHG be nefits.
The commenter s 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 inventor ies. The commenter s stated that EPA's abrupt biomass policy shift in the Tailoring Rule is unsubstantiated. The commenter s stated that since EPA released the final Tailoring Rule, the Agency collaborated with the Department of Energy, the Department of Def ense, 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 targ ets. The commenter s 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.

Commenter s 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 urge d 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 t o 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 “complia nce 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

, t hus sources that ar e 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 commenter s 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 th at 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 wou ld 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 de signed 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 wi t h 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 appl icable 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:

Commenter s 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 commenter s stated that EPA has not made any proposed deter mination 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 commenter s 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 commenter s stated that applicability or non

- applicability of Title V permitting requirements a lso determines the enforcement mechanisms available to the states for section 111(d) plan requirements applicable to compliance entities, and illustrates the absurd49 results that would follow from making the state itself, other governmental entities, or non

emitting generators subject to the enforcement provisions of the Title V permitting program. The

commenter s 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 app lication 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 sour ce categories and can legitimately be subject to a 111(b)
standard.

Commenter s 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
"a

pplicable requirements" under Title V, s ection 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 implem entation plan.
The commenter s 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 commenter s 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

commenter s 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 commenter s stated that at least to the extent that 111(d) requi rements 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 commenter s ’ 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 Massachusett s 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 o f 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 applicabil ity. The Court also said that the EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs,

3 The EPA’s 2009 endangerment finding defines the air p ollution which may endanger public
health and welfare as the well

- mixed aggregate group of the following gases: CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).50 contain limitations on GHG emissions based on the application of BACT. The Supreme Court
decision effecti vely 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 specifical ly 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 appropria te 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 ob tain 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 th ey 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 summar ies of the specific public comments under this comment:

Commenter s 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) i n the PSD context or a major source in the Title V contex t" of the CAA, and so invalidated a rulemaking imposing PSD and Title V permitting requirements for GHG
emissions. The commenter s stated that the basis of the decision was that while the "Act

- wide"
d efinition 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 en ough to include carbon dioxide and the other GHGs EPA sought to regulate (CO2e). The commenter s 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 commenter s 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 thi s interpretation
under Chevron. The commenter s stated that it refused to do so because EPA's reinterpretation of51 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. T he 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 co nsiderations 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 commenter s 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 relate d to the costs of implementing any particular applicable requirements.

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

Commenter s stated that they disagree with U.S. EPA's proposal to exempt CO2 from the $/ton
Title V fees. The commenter s 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 commenter s st ated 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 commenter s referred to their comments on T itle 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).

Commenter s stated that EPA did not address the potential impact of the CPP on permitting fees as they relate to CO2 emissions. The comm enter s 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 commenter s 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 flexibili ty 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,
record keeping 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 wil l 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 co nflict 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 pu blic comments under this comment:

Commenter s 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 E GU's Title V permit, and made enforceable in that
manner. The commenter s 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 lan ds 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 responsi ble 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 of53 PSD permit applications when the EPA or a delegated agency issues a PSD permit. 4 The memo summarizes the permit pro cessing 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 decisi ons (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:

Commenter s 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 comm ents 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 Process ing 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

g eneration. 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 com ments 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 sta ndard 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. T he 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 perf ormance 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 faci lity, 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 re quiring the reporting of hourly net energy output . H owever; 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 equ ipment 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:

C ommenters opposed the proposed ANSI 2010 C12.20 equipment standards for various reasons
in cluding 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 standar d 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 o f 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 adherence55 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 equipmen t, EPA would need to revise its proposal to estimate and solicit input on the additional costs and burdens of such metering

Commenter s 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 commenter s 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 commenter s stated that measurement of unit

- specific net output can be complicated by the difficulty in measuring auxiliary energy consumption of numerous plant

specif ic devices and most plants do not have the internal electrical distribution system designed to distribute and measure internal usage on a unit basis.

Commenter s stated that requiring the use of ANSI Standard C12.20 instrumentation and calibration procedur es 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 requir ements.

Commenter s 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 commenter s a gree d 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 commenter s 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 str ingent 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.

Commenter s 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 commenter s stated that in addition, the specific requirement to apply ANSI Standard C12.20 to auxiliary power met ers is not justified because the incremental gain in accuracy would be inconsequential. The commenters stated a uxiliary power usage accounts for less than 10 percent of gross electric generation and a small improvement in accuracy will have an inconsequen tial impact on the reported net generation.

Commenter s 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 typ ically installed for gross measurements and is typically only specified for use in recently built power stations at the " point of sale " transfer point. The commenter s stated that if any parasitic loads were metered, that would be with a 0.5 class device. T he commenter s stated that only the point of sale meters undergo checks on any periodic basis, which is already specified by the regional transmission authority. The commenter s requested that EPA abandon requiring a 0.2 accuracy meter.56 Commenter s stated tha t, 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.

Commenter s 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 repla cing such meters is not insignificant. With respect to the monitoring of net electric output,

commenter s stated that EPA's proposal appears to be based on an assumption that net output would be determined using existing equipment and simple apportionment s chemes; the

commenter s agree d 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 g eneration.

Commenter s 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 suffic ient 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 commenter s 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 s uch testing would be significant. The commenter s 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.

Comme nter s 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 commenter s stated that Regional Transmission A uthorities 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 cal ibrated at all. The commenter s 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 topi cs (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 informatio n collection request regarding the

e quipment 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:

Commenter s 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 n on
- 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 p rovided 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 60.58 60 (a)(5)(i v ), which includes any useful thermal output of steam from a CHP unit. The

fin al 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 usef ul 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:

Commenter s responded to EPA's request for comment on the calculation of equivalent electrical energy for thermal output of fossil CHP installations. The commenter s 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 commenter s stated that the balancing of thermal loads and losses is complex and not amenable to a simple one approach fits all for mula. The commenter s 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 to58 the process sewer system. The commenter s recommended that if EPA plans to follow the proposed approach to calculating net energy output, there should be a secondary approach used i f the EGU/CHP facility does not wish to go through a plant

- specific thermodynamic analysis of the steam system.

Commenter s stated that, regarding EPA's request for comment on the measurement of useful thermal energy and quality assurance protocols, the com menter s 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 requir ements surely would be lost in the noise of the calculations and assumptions used to justify the percent credit for thermal output. The commenter s stated that identifying best practices may be well

- intended, but decisions on appropriate measures each
facil ity 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 be st mechanism to ensure an appropriate level of accuracy. The commenter s stated that steam supply systems are unique to each facility, and measurement technology decisions will consider many factors. The

commenter s stated that different types of meters, i nstruments, 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 ba rely at the saturation temperature. The commenter s 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 commenter s 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 on going 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 comm enter s 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 b e proposed for public comment before EPA can issue any final requirement.

C ommenter s 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 commenter s stated that although most flow meters probably would meet the ASME mass flow controller ("MFC") standards generally , the

commenter s 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 use d 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 issu es 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 generati on 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 S tate 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 signifi cant cost to install meters to measure net generation on this industry.

As stated in section VIII.F.1 of the preamble, t he EPA agrees with commenters that the reporting of net energy output via ECMPS is the preferred approach

. EPA recognizes that there a re 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 mu ltiple 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 Coll ection 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 a llow 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 quali ty 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 report60 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 emissio ns 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:

Co mmenter s 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 reco rding of hourly gross unit load), and 75.64(a)(2) (requiring reporting of recorded values). The commenter s stated that as a result, all existing EGUs already measure and record gross MWs for all generation. The

commenter s 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 suc h 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 commenter s 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.

Commenter s stated that a power generation facility with multiple units currently typically measures gross MWe from each electrical generator hourly, and sta tion 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 commenter s stated that design of power station electrical distribution, if metered and use d 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 u nits that add advanced pollution control projects for other regulatory compliance, which reduce available net load, would also become the highest CO2e/Net MW emitters.

Commenter s stated that they do not support adding net load reporting to ECMPS as an opt ion as it would require adding an " Electrical Monitoring Plan " to support the hourly data elements in
ECMPS. The commenter s stated that this would also trigger QA event reporting for the power61 transducers. The regional transmission authorities already requ ire 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.

Commenter s stated that if the monitoring of net elec tric 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 t he measurement of unit

- s pecific net output can be complicated by the difficulty in measuring auxiliary energy consumption of numerous plant

- specific devices. The commenter s 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 commenter s stated that if EPA were to require replacement of existing equipment to make it unit specific or to im pose 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.

C ommenter s stated that they support EPA's proposed approach to require that hour s with no gross generation or gross generation less than auxiliary loads be reported as zero rather than a negative value; furthermore, the commenter s request ed that EPA consider provisions in the standard to ensure that units that cycle are not unfairly p enalized. 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.

Commenter s 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

commenter s stated that 40 CFR 75 does not require monitori ng net energy output. The

commenter s 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 commenter s stated that usi ng 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 commenter s stated that reporting load under 40 CFR 75 to ECMPS is on a gross load ba sis 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 fi red 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 gen eration

Response 2 : As the commenter s 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 operates62 for only 30 minutes in the hour (0.5 hr), the hourly generati on is 50 megawatt hours. The final rule requires p artial 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 su mmaries of the specific public comments under this comment:

Commenter s stated that they are concerned that EPA has overlooked important details regarding how generation already is being reported. The commenter s stated that EPA has made clear in its
ECMPS R eporting 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 commenter s 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 commenter s stated that EPA's Proposed Guidelines, on the other hand, require calculation and use of actual electrical output for each
hour and use ful thermal energy relative to standard ambient temperature and pressure conditions.
The commenter s 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 suggest ed 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 CO 2 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
th ings, 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 CO 2 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 u nder this comment:

Commenter s 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 C ollection and Monitoring Plan System (ECMPS). The commenter s 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 reportin g requirements and ease the burden on affected EGUs. The63 commenter s stated that they also expect to use existing reporting mechanisms where possible to
allow non

- EGU affected entities to comply with reporting requirements.

The commenter s stated that exist ing 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
oth er applicable NSPS provisions or Part 75, should be submitted to the states for inclusion in annual reports to EPA. The commenter s 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 commenter s 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 usef ul 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:

Comm enter s 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 7 5; the suggested changes are reasonable and will help clarify an issue that has arisen with some of their NGCC plants. The commenter s 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

commenter s 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 commenter s
sta ted 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 commenter s in that we reject the notion that EGU’s functioning as cogeneration facilities should be exempted from compliance wi th 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 static64 portion of the overall energy output from the EG U. 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. A dditional monitoring of parameters needed to
calculate useful therma l 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 usef ul 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:

Commenter s stated that they do not support reporting both the electrical ge neration 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 commenter s stated that additiona lly, 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 co mments 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 commenter s 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 f inal 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 site

specific 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 respo ndents 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 net65 electricity, which is essential to en sure 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 requi ring 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 requirement s for watt meters in their state plan submissions.

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

Commenter s 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 commenter s stated that it appears that the references to Appendices B and D
are in correct and the sentence should read Appendices A and B.) The commenter s 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, t hey 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

commenter s stated that EGUs already have sufficient ince ntives 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 commenter s stated that they also believe that any increase in accuracy woul d 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: Regardin g 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 determini ng CO 2 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 CO 2 mass emissions. Furthermore, because the CO 2 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 is66 required, i.e., CO 2 emissions must be reported for al l 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:

Commenter s stated that according to EPA, monit oring 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

commenter s noted that the Propo sed 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 commenter s 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.

Th e commenter s 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 requir ements for existing units . The commenter s stated that the EPA ha s 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 commenter s 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

commenter s 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 pro cedures
cannot be used. The commenter s requested that the EPA provide the same clarification in the
final rule.

Commenter s stated that the final section 111 rules for carbon emissions from the power sector should ensure consistent monitoring and recordkeep ing 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 s ources 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 "f acility ", " affected source ", and
what constitutes a " reconstruction " because consistent rule definitions are especially important in the permitting process for stationary sources.

Comm enter s 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 proto cols 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 rule67 definitions among the various rules, such as the de finitions 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 fo r 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 appropria te . 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 doe s 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 (RATA s). The final rule also does not require the use of calibrated Type

- S pitot tube s 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 th e specific public comments under this comment:

Commenter s 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 commenter s 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 configu rations 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 commenter s 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 w ith 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 commenter s stated that in t he 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 comme nter s 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 calibr ate its stack flow monitor during a RATA. The commenter s stated that although EPA must allow use of Methods 2F and 2H (or CTM

- 041), EPA should not require either one. The commenter s stated that first, not all EGUs will obtain more accurate measurements usi ng 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 commenter s stated that alth ough 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 commenter s 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 commenter s stated that Method 2G is often performed using an auto

- probe, which can reduce testing time. The

commenter s stated that Part 75 allows use of Methods 2, 2F, 2G, 2H, and CTM

- 041 a nd 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.

Commenter s requested that EPA eliminate the most accurate RATA refer ence 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 commenter s stated that although EPA must allow use of Methods 2F and 2H (o r 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 commenter s stated that more accurate methods are typica lly 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 accur acy of the flow profile from a single test run. The commenter s stated that if the more accurate test methods are mandated, then EPA needs to consider the
additional cost burdens for each unit.

Commenter s stated that because of these flexibilities regardin g 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 commenter s stated that the first approach is the development of adjust ment 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

commenter s stat ed 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 commenter s 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

- reporting69 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 commenter s 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.

Commenter s 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 commenter s stated that first, not all EGUs will
obta in 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 f riction and although the methods can provide more accurate (and lower) stack flow measurements for other EGUs, they also impose additional burdens. The commenter s stated that any EGU concerned about overestimation of measured flow due to cyclonic flow con ditions, or wall effects, can opt to use either method; there is no basis, however, to require their use. The commenters stated t he 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 commenter s stated that Method 2G is often performed using an auto

- probe, which can reduce testing time. The commenter s stated that
EGUs shoul d 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.

Commenter s stated that, regarding the EPA's suggestion that it develop "adjustment fac tors" 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 commenter s 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 commenter s 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 f low RATA methods. The commenter s stated that the altering of data collected under Part 75 could have serious consequences and the commenter s would object to the use of such altered data for any other program. The commenter s stated that EPA also does not p rovide 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 be fore 2012. The commenter s 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.

Commenter s stated that in short, the two sentences of vague conceptual language in the P art 75 TSD is not sufficient to inform commenters of the scope or impact of the EPA's proposal and if70 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 specific ally how the percentage value would
be determined. The commenter s 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 co mmenter s recommended that the EPA not pursue this issue of adjustments to baseline
calculations.

Commenter s 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 com menter s 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 commenter s stated that because CO2 is such a ubiquitous pollutant, and emitted in such larg e quantities, a "most accurate" standard is not necessary for purposes of determining CO2 emissions from point sources. The commenter s 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 commenter s stated that it should be the states determining when and how an adjustment is applied. The commenter s 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 commenter s stated that because there are multiple flow measurement test methods that are defined as reference methods, and avail able equally for use in Part 75 and for cap and trade programs, the commenter s question ed why does the addition of CO2 require the use of even more accurate measurements. The commenter s stated that the resolution of data that is seemingly being required wo uld 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

commenter s asked will extensive e mission unit specific testing be required to develop specific conversions and adjustments necessary for each subject emissions unit. The commenter s stated that this topic needs more consideration by the EPA and an additional proposal. The commenter s 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 commenter s stated that these variances could be as s imple 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.

Commenter s stated that with regard to requiring a cert ain stack gas flow monitor RATA reference method, the commenter s ' preference is to continue to allow the affected EGU to make
that determination. The commenter s 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.

Commenter s stated that, regarding the alternative reference methods provided in Part 75 that are designed to reduce or remove over

- reporting o f 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 commenter s request ed that EPA retain them as options in71 the guideline rul es and not include them as requirements. The commenter s 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.

Com ment 2: Adjustment factor

Response 2 : The final rule does not require any adjust ment 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 previo us RATA(s)

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

Commenter s 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 suff icient information to comment on the reasonableness of such a requirement. The commenter s 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

- i s 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 commenter s stated that EPA's suggestion that dat a 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 commenter s stated that the altering of data collected
under Par t 75 could have serious consequences and the commenter s would object to use of such altered data for any other program.

The commenter s 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 commenter s stated that EPA has not provided any information
to inform how it m ight 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 commenter s 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 deter mined.

Commenter s 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 ver y similar to the language in the proposed rule. The commenter s stated that EPA needs to provide a more complete guidance document indicating how the adjustment factors will be developed and implemented.72 Commenter s stated that regarding the two possible adj ustments 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, whil e the second possible adjustment would be to require a computation adjustment when an EGU changes RATA reference methods. The commenter s stated that although the proposed adjustments are reasonable, EPA should continue to allow the source to choose among t he current methods and procedure options; the current procedures are sufficient to ensure the data is accurate enough to meet the rule objectives.

Commen t 3 : Requiring the use of the most accurate RATA reference test methods for flow monitors, as expresse d 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 referen ce 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 determ ine 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 commen ts under this comment:

Commenter s stated that t he 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 a pplied to all sources and for all tests. The commenter s 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 commenter s 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) requiremen ts 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 commenter s explai ned 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 commenter s stated that Test Method 2F and 2G enable the

tester to measure non

- axial flow or cyclonic flow more accurately. The commenter s stated that some stacks do have significant cyclonic flow, but most do not. The commenter s stated that Test Methods 2F and 2G are much more complicated and expensive to cond uct. The commenter s 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 commenter s stated
that Test Methods 2H and CTM

- 041 are used to measure the wall effect on circular and rectangular stacks. The commenter s 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

commenter s stated that the r ate of decay will be affected by the roughness of the stack wall. The

commenter s 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 commenter s stated that the u se of
a wall effect factor will reduce the overall net flow rate in the stack.

The commenter s recommended that the use of Test Methods 2F and 2G not be required for all testing. The commenter s suggested that a facility should be required to conduct an ini tial 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 commenter s suggested that if the test data supports using the more accurate test me thods, then require the facility to use them for subsequent testing.

The commenter s 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:

Commenter s 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 commenter s requested that this requirement be eliminated . The

commenter s stated that currently approved methods for fl ow RATAs under Part 75 include Methods 2F, 2G, 2H, and conditional test method (CTM) 041. The commenter s 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 particul ar allowing EGUs to change methods over time) could74 lead to inconsistencies between emissions or heat input values. To avoid this result, the

commenter s 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 m ethod to calibrate its stack flow monitor during a
RATA. Although EPA must allow use of Methods 2F and 2H (or CTM

- 041), the commenter s suggeste d EPA should not require either one . The commenter s stated that, although these methods can provide more accurate (and lower) stack flow measurements for certain EGUs, they also impose additional financial burdens. The commenter s explained that the more ac curate methods are typically conducted with an auto

- probe system, and leasing a United Sciences "auto

probe" system could add $100,000 to a single flow RATA . The commenter s stated that if the test
is not done with an auto

- probe, then the duration of the te st will be extended and reduce the accuracy of the flow profile from a single test run. The commenter s stated that EPA needs to
consider the additional cost burdens for each unit if the more accurate test methods are
mandated

.

The commenter s noted that be cause 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 adjustme nt 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 refer ence method taking into account the specific configuration of the stack.

The commenter s stated that the EPA's proposed first correction would not work . The

commenter s 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 commenter s 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 CO 2 emissions (i.e. compensating for a flow reduction that did not occur). In addition, the commenter s stated that a change in the flow RATA results could also be c aused 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 commenter s stated that it would be impractical to try and regulate
an "anti

- correcti on" to EGUs that increase their flow system accuracy, without taking a case

- by

case 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: Al low 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, t he final rule does not require an y 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:

C ommenters 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. T he 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 chang es RATA reference methods. Commenter s noted that the rationale for these possible adjustments is described further in the Part 75 Monitoring and Reporting Considerations TSD available in the docket.

Commenter s 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

commenter s stated that the current procedures are sufficient to ensure the data is accurate enough to meet the rule objective s.

Commenter s stated that EPA did not define what "most accurate" means or who determines the

" most accurate " RATA test method. The commenter s contended that a requirement that leads to

" most accurate " is unwise, indefensible, and will result in a never en ding pursuit of " more

accurate " equipment. The commenter s stated that since CO 2 is such a ubiquitous pollutant, and emitted in such large quantities, a " most accurate " standard is not necessary for purposes of determining CO 2 emissions from point sources.

Commenter s 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 commenter s believe d it should be the states determining when and how an adjustment is applied. The commenter s 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 approve d test methods. The commenter s 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 commenter s questioned why the
addition of CO 2 requ ires the use of even more accurate measurements. The commenter s 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 commenter s questioned if extensive emission unit specific testing will be required to develop specific conversions and adjustments necessary for each s ubject emissions
unit. The commenter s 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 w ay or the other, the commenter s stated that the ability of both the reference method and the facility's monitoring systems to
measure flow or CO 2 accurately may also be dependent on many factors, some of which could vary from day to day. The commenter s not ed 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:

Commenter s 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 con ducting optional reference method tests to more accurately determine wall/angular effects on volumetric
flow rate. The commenter s stated that the EPA should also publish supporting evidence for the default factor since the default volumetric flow rate adju stment 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 a n O 2 concentration monitor from determining CO 2 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 majorit y 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 CO 2 mass emissions.
Therefore it is not burdensome or un reasonable 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, rath er 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:

C ommenters object to EPA not allowing the use of an O2 CEMS to ob tain CO2 emissions.77 Commenter s 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 moistu re monitoring system in accordance with Part 75. Proposed s ubpart UUUU section 60.5805(a)(2)(i). The commenter s stated that as an alternative, EPA proposes to allow EGUs that combust only liquid or gaseous fuel to determine CO2 mass emissions under the pro vision 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 commenter s support ed these options, but believe that
EPA has unreasonably eliminated several other Part 75 options.

The commenter s stated they do not oppose requiring solid fuel

- fired EGUs, or allowing other EGUs, to use CEMS; Part 75 and s ubpart Da already require solid fuel

- fired units to use CEMS
to determine co mpliance with other requirements. The commenter s 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 commenter s stated

t hat 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 conc entration monitor
to measure CO2 concentration to obtain CO2 mass emissions. The commenter s 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 concentrati on monitors, there are valid reasons an EGU (particularly a gas

- or oil

- fired EGU) might prefer an O2 monitor. The commenter s 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 commenter s 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 s ubpart UUUU section 60.5805(a)(2).

Commenter s 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 commenter s believe d
that EPA should not re quire the use of CO2 CEMS for affected facilities. The commenter s 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 fu el, 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 commenter s sta ted 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

commenter s believe d EPA should preserve the option to use O2 CEMS if desired. Commenters
stated t his option is already allowed under NSPS for s ubparts Da and KKKK.

Commenter s 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 commenter s stated that the EPA may be over estimating the number of affected EGUs that may meet the monit oring requirements

. The commenter s78 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 f inal 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 mon itor, 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:

C ommenters were concerned that EPA eliminated the option to use default moisture values.

Commenter s 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 commenter s stated that the Par t 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 under

reporting. The commenter s stated th at EPA approved the default moisture value for natural gas (boilers only) in (January 24) 2008 based on data submitted to EPA. The commenter s 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 commenter s 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 commenter s stated that because existing EGUs still will need to comply with the ARP, eliminating these option s in state plans effectively eliminates them in Part 75.

Commenter s stated that EPA also mentions the measurement of CO2 concentrations on a "dry basis" through installing, certifying, operating, maintaining, and calibrating a continuous
moisture monitorin g 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 t he final rule does not include a

re quirement to make measurements of stack dimensions using a laser device. The following are summaries of the specific public comments under this comment:79 Commenter s 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 commenter s stated that for circular stacks, measurements from at least three distinct locations need to be averaged; for rectangular stacks or ducts, each dimension mus t be measured from at least three distinct locations and averaged. The commenter s 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 diffe r significantly between off

- line and
full

- load periods and expansion rates can also vary based on ambient conditions. The

commenter s 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 commenter s stated that without explanation as to how these requirements improve the measurement accuracy, EPA should not make these requirements mandatory.

Commenter s 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 r eference method sampling location using a laser device at "three or more distinct locations and average the results." Proposed

s ubpart UUUU section 60.5805(a)(2)(iii). The commenter s objected to this provision and stated that a requirement for a one

- time m easurement 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

commenter s stated t hat 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 addit ional cost and burden with no corresponding benefit. The commenter s 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 commenter s stated that if EPA has evi dence to support this proposed requirement, EPA should provide it. The commenter s 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 "d istinct" locations presumably would require three ports none of which are directly across from each other. The commenter s stated that common configurations depending on stack diameter are to have two ports 90 degrees apart or four ports 90 degrees degree a part, neither of which provides three distinct locations; in other words, most plants will have at most two distinct locations. The commenter s stated that EPA must remove the requirement.

Comment 4: Reference of App D for units using CEMS

Response 4: The EPA agrees with the commenter s and corrected this inadvertent mistake.

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

C ommenters stated that they do not understand EPA's proposed reference to compliance with Part 75, Appen dix D for units using CEMS. The commenter s stated that under Part 75, CEMS80 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 commenter s recommend ed 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 allow s 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 monitor s and

allow s the use of Part 75

, Appendices D and G to calculate CO2 mass emission rate

, using

E quation G

- 4.

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

Commenter s 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 r equiring use of stack flow or
diluent monitors on such EGUs would result in u nnecessary additional construction, equipment, and implementation costs, and less accurate measurements of CO2 mass emissions. The

commenter s stated that they also agree with the proposal to allow, but not require, the use of site

specific F

- factors under equation G

- 4. Proposed s ubpart UUUU section 60.5805(a)(3)(ii). The

commenter s 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

commenter s stated that to the extent there is small variability, i t also is unlikely that variability would be captured in an annual determination. The commenter s stated that EPA has relied on F

factors 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 commenter s 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

som e 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 result ing 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 the i r emissions using the provi sions 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 u sing CEMS.81 The following are summaries of the specific public comments under this comment:

Commenter s stated that EPA proposes to define "steam generating unit" and "stationary combustion turbine" to include "any integrated equipment that provides electric ity or useful thermal output" to the affected facility or auxiliary equipment. The commenter s 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

commenter s stated that th e Agency also acknowledged that there likely were no such devices currently being used, but suggested that it hoped to promote their use. The commenter s 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 commenter s 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 commenter s stated that such integrated equipment either has very few emissions, or operates very infrequently; the commenter s also believe d that given the uncertainty about their use, the Agency should not spend resources specifying monitoring requirements in the rule. The commenter s stated that as a result, they suggest that EPA encourage states to include a provision allowing submission and approval of a petition for exemp tion 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 req uired 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: T he fina l 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:

Commenter s stated that EPA solicits comment on requiring the use of the most accurate RATA
referen ce method for specific stack configurations. The commenter s support ed 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 commenter s stated that EPA should not r equire 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 plan82 Response 8: In final rule EPA is requiring the reporting of hourly net energy o utput 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. Additio nally, 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 o f the specific public comments under this comment:

Commenter s 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 ou tput 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 commenter s stated that it is no t 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 i nformation.

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 fina l rule reflects this. Also, i n the final rule EPA is not requiring the use of a laser device to make stack measurements. The EPA agrees with the commenter s that any duplication of testing or monitoring is unnecessary
thus the final rule requires the CO 2 m onitoring 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

- bas ed 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:

Commenter s stated that section 60.58 05, 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 P art 75. The commenter s suggested that EPA need only reference the existing Part 75 requirements that should be included rather than modifying them for this rule. The

commenter s stated that the changes proposed only provide an additional burden on the sourc es 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 differe nt values for emitted CO2.

The commenter s 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 commenter s 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 calcu lations? 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 propo sing 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 C O 2 emission rates in the same
database.6 0.5820 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. T he 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

Commenter s stated that they oppose the proposed 10

- year re cord 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 commenter s stated that to the extent the EPA or a state intends to audit the accuracy of a ce rtified 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 commenter s stated that Part 75 has a 3

- year record retention require ment, 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 commenter s also op posed 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 commenter s stated that many of the records to be retain ed 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 commenter s stated that as long as the facility can access the
info rmation onsite, there is no reason for it to be located there in a paper hardcopy form.84 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 S tates 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 G

4) 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:

Commenter s 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 commenter s stated that the EPA has provided no justification for requiring states to impose on EGUs monitoring that is different from, let alone more str ingent than, Part 75. The commenter s 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 p art 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 Report ing 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 pa rt 60 monitoring procedures are not required and applicable

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

Commenter s 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 commenter s stated that this flexibility is consis tent 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.85 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 u nder this comment:

Commenter s 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 commenter s s tated 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 requ iring states to impose on EGU s monitoring that is different from, let alone more stringent than, Part 75. The commenter s stated that, in addition, they are concerned about the Agency's failure to make clear that use of Part 75 missing data substitution pr ocedures 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: Sup port 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 in centivize 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 r eporting 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 fina lized, 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 measur ements 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 abili ty 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 a86 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 p ublic comments under this comment:

Commenter s 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 commenter s 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 commenter s support ed the option of using any 40 C.F.R. Part 60 and 75
methods for mo nitoring 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 commenter s stated that EPA has proposed that compliant CO2 emission ra tes 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 commenter s supported the use of gross energy output in the CO2 emission rate calculation, as E PA proposed in the January 2014 NSPS Proposal and in the June 2014 modified and reconstructed proposed s tandards (MRPS) for

s ubpart KKKK sources. The commenter s 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 commenter s reiterate d its comments on the January 2014 NSPS Proposal and the June 2014 MRPS. The commenter s stated that they strongly support the use of gross energy o utput in the CO2 emission rate calculation rather than an unduly complex net output calculation.

Commenter s stated that the use of gross energy output allows the plant operator to account for electrical, mechanical, and thermal energy use by the plant, giv ing 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. Pa rt 75. The commenter s 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 commenter s 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.

Commenter s stated that a gross energy ou tput

- 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 option87 (increased gross MWh o utput 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.

Commenter s stated that in contrast, net MWh output is facility

- specific and challenging to accurately calculate; for example, many facilities have transformer s that support multiple units at the facility, making unit

- level reporting difficult. The commenter s stated that more important, station electric services may come from other outside sources to supply lighting, well pumps, and other ancillary loads; and so me station services are dedicated per unit, while other station services may be measured at a facility level. The commenter s stated that examples of facility

wide equipment that often serve more than one unit include coal handling equipment such as
unloade rs 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.

Commenter s stated that the Proposed Guidelines for affected sources should include monitoring and reporting based on gross MWh rather than net MWh for the follo wing 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

rep ort 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 el ectrical 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 requ ire monitoring under Proposed s ubpart
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 ho me 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

g uidel ines, 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; p reserve 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 changes88 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 75.6 6. 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 o f the specific public comments under this comment:

Commenter s 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.

Commenter s 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 bet ween the New Source Performance Standards and Part 75 emissions monitoring programs is essential to avoid duplication and imposition of potential inconsistent requirements.

Commenter s 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 s ection 75.11 (b)(1) to use appropriate default moisture values rather than installing and calibrating a mon itoring device. The commenter s 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.T he commenter s 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

commenter s request ed 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 commenter s and the final rule provides a “state meas ures” 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 s ummaries of the specific public comments under this comment:89 Commenter s 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 1 0 percent starting in 2022. The commenter s 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

commenter s also support ed 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 commenter s 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 dimen sions 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:

Commenter s stated that the state plan monitoring requirem ents 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 commenter s stated that this requirement is unnecessarily burdensome and will require installing additional sampling ports that will not be used for any other purpose.

The commenter s 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 d imensions 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
d istinct 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 sampli ng site is relocated, an affected EGU must repeat these
measurements at the new location."

The commenter s 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 a verage 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 commenter s explained that would only give two distinct lo cations, besides the fact that one would be shooting across the90 stack directly into the other port if they are located exactly on the same diameter. The

commenter s 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 commenter s stated that these additional sampling ports would not be used again at these locations. The com menter s 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 dime nsions.

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 Appe ndices 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:

Commenter s stated that EPA should require direct CEMS monitoring of CO2 emissions

. The

commenter s noted that the EPA proposes to allow facilities to determine compliance with an applicable standard by either mo nitoring emissions directly or by estimating emissions based on fuel consumption. [Proposed 40 CFR 60.5535, 60.5540]. The commenter s stated that it appears that EPA inadvertently omitted a third provision relating to using fuel consumption to estimate
emis sions 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 commenter s 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 commenter s stated that virtu ally 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 commenter s 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 commenter s urged the EPA to require CEMS not only at coal plants, but at all units reporting CO2 emissions under the CPP

.

The commenter s 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 commenter s stated that power plants within the Clean Air Act's Acid Rain Program report CO2 emissions to the EPA, a nd 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 commenter s noted that the Energy Information Administration (EIA) also calculates emissions for these pla nts, but uses fuel consumption data
rather than the CEMS information. The commenter s 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 coal91 plants). The commenter s 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 commenter s stated that this result masks even greater divergences in estimates at individual plants. The commenter s stated that this discrepancy is likely due to the inherent inaccuracy of fuel sampling for coal p lants. The
commenters stated s amples 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 commenter s stated that the EPA's fuel sampling procedures include a determination of the relationship between fuel flow and load for the unit

. The commenter s stated that this requires the operator to measure the fuel consumption and generation of the unit on an
hourl y basis for 168 hours, then to calculate the average fuel consumption per unit of generation. However, the commenter s noted that the EPA's procedure allows a source to exclude as "non

representative" any hour in which the unit is "ramping up or down" (defi ned 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 commenter s argued that the effect of this procedure is to exem pt periods of low or changing load from regulation. The

commenter s 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

commenter s sta ted 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 Pa rt 75

, except for units that utilize carbon separation.

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

Commenter s stated that EPA is proposing the CO 2 monitoring already conducted by most
affected EGUs under 40 CFR Part 7 5, that is reported using the EPA's Emission Collection and Monitoring Plan System (ECMPS), would generally satisfy CO 2 emission reporting requirements under this proposal. The commenter s stated that the EPA may be over estimating the number of
affected EG Us that may meet the monitoring requirements because some of Ohio's combustion
turbine stations do not have CO 2 analyzers and are instead monitoring O 2 . The commenter s stated that this should be an adequate substitute for CO 2 monitoring

.92 7.6 GREENHOUSE G AS 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 E

Enterprise 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 commenter s recommend. More information on this project can be found at http://www2.epa.gov/e

- enterprise/e

- enterprise

- proje cts

- spotlight.

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

In regards to monitoring, recordkeeping and reporting, c ommenter s questioned the relationship between the proposed rule and the annual GHG emissions reporting p rovisions under 40 CFR
Part 98. The commenter s stated that most affected sources currently report GHG emissions to the EPA quarterly pursuant to 40 CFR Part 75 a nd annually via 40 CFR Part 98. The commenter s asked whether EPA is considering streamlining th e 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. This93 is also the case for other rules that have not yet been promulgated. The agency reco gnizes, 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’ choic es 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:

Commenter s stated EPA should provide relief for new electricity use driven solely by compliance requirements from other EPA rules. Co mmenter s 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.

Commenter s stated that EPA failed to take into account the impact of its own rulemaking in other media on its proposed rules . The commenter s 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 ci ties and towns in Missouri over the next five years to eliminate their use of lagoons for wastewater treatment and instead install mechanical plants. The commenter s stated that the mechanical plants will require substantial amounts of electricity because t hey 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 commenter s stated that EPA's rules are actually the proximate c ause of increases in CO2 emissions and the failure of these communities to be able to comply. The commenter s suggested that EPA modify the proposed guidelines to require the EPA to calculate the added electrical consumption by state for each final rule, an d 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

commenter s express concern with this resulting in an increased number of nonattainment areas. As outlined in the final Clean Power Plan, states and sources ha ve 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 r equirements under the MACT program), the EPA believes that the Clean Power Plan provides an opportunity for states to consider strategies for94 meeting future CAA planning obligations as they develop their plans under this rulemaking.
Multi

- pollutant strateg ies 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 ru le, 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 uni ts 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 durin g 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

g enerally 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, an d 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 t itle 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 t he 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 gu idelines, 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 wo uld 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:

Commenter s stated that, in addition, the Proposed Rule will require ramping up generation from facilities that are located in current nonattainment areas, which would violate NAAQS95 requirements and as EPA revises the NAAQS, the number of nonattainment areas will grow, causing even greater problem s.

Commenter s 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 commenter s 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 commenter s 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 commenter s 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 r ules 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 m ade 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 be lieve 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 incorp orate 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 accompl ish 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 emissi on 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 t his comment:

Commenter s 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

commenter s recommend ed the compliance time tables reflect the tr emendous 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 : M ethane emissions from NG production and distribution96 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 volat ile 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 Meth ane Strategy ( https://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014

- 03

- 28_final.pdf ), issued in Marc h 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 t o 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 em ission guidelines are designed to build on and reinforce actions al r eady 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
CO 2 emissions from affected EGUs.

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

C ommenters recommended that EPA also act to regulate other GHG

, including methane, black
carbon and ozone

.

Commenter s 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 concret e action to regulate methane emissions from the oil and gas sector. Commenters stated t he 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 commenter s 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 the97 type of gas, for inst ance, conventional versus shale gas; methods of extraction and production; and volume of fugitive emissions (leakage) in production, transmission and distribution systems.
The commenter s urge d 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 commenter s stated that recent studies suggest that, when methane leaks from gas p roduction, 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 commenter s stated that a
recent meta

- study analyzi ng 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 l eakage from natural gas production, transportation, and power generation are inadequate. The commenter s 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 commenter s stated that the revolutionary development of shale gas and tight oil reservoirs through horizontal drilling and hydraulic fracturing m ay 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 commenter s stated that wh ile techniques for determining fugitive emissions will continue to be refined and estimates improved, the science is clear that fugitive emissions are significant.

The commenter s 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 commenter s 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

commenter s stated that as a number of studies have shown, abat ement of methane emissions in the oil and gas sector is among the least

- cost global methane emissions reduction strategies
available. The commenter s stated that, finally, EPA should consider the significant risk that incentivizing substantial long term inv estment 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 requ irements 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 prec ursor emissions, including EGUs. We believe the planning and compliance timeframes that would follow from a revised ozone NAAQS and the timeframes we are98 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 commen ter s ’ 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 th at 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 re asonable 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 affe ct 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 st ate 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

re tirements, 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 com pliance requirements across multiple regulatory programs, as warranted.

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

C ommenters expressed concern over the interaction of the CPP and NAAQS and Regional Haze Programs.

Comme nter s 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 commenter s stated that the OAQPS August 2014 Policy
Asse ssment 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 commenter s 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) ru les and other EPA requirements, including the MATS
rule. The commenter s stated that a more stringent ozone standard would impose resource demands on states required to develop implementation plans, at the same time they must address99 the proposed Clean Powe r 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
affec ted 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 commenter s 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 ad dress in the first instance the implications of a revised ozone standard on the proposed section 111(d) rules.

Commenter s stated that EPA can contribute to state compliance with the CPP's CO2 targets by promptly and consistently implementing the recently r evised NAAQS for ozone, SO2 and
PM2.5. The commenter s 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 commenter s stated that E PA 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 renewabl es. The commenter s 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

comment er s 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

- ter m strategy to meet visibility improvement requirements.

Commenter s 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.

Commenter s stated that EPA's proposed approach to setting the interim goals does not recognize current or future EPA approved settlements under th e 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 commenter s stated that these settlements are often the result of years of extensive negotiations and carefully examined emissions reduction findings and customer cost impacts. The commenter s stated that
EPA's int erim goals have the potential to effectively nullify these agreements and require the retirement or displacement of those resources by 2020.

Commenter s stated that state plans should address how their activities affect the attainment of NAAQS in neighborin g states. Commenters stated t he 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.100 Comment 6 : Direct and Indirect Impacts of EPA follow

- on rules for other indus tries

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

- f ired 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 renewab le 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 secto r, 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 sp ecific public comments under this comment:

C ommenters stated that the agency is committed to a number of follow

- on rules that will impact
the commenter s 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. Commenter s 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 commenter s stated that in addition to the economic impacts of these collective regulations on our sector and the electric sector, the CPP will nec essitate fundamental changes necessary to the production and
distribution infrastructure.

Commenter s stated that overall, market forces

- especially lower natural gas prices

- have gradually contributed to the transformation of a cleaner electric generatio n fleet as some coal units have been replaced by natural gas units. The commenter s stated that the MATS rule has contributed to this trend, although at a faster pace than preferred. The commenter s stated that they remain very concerned about the reliabilit y implications of MATS, especially in the Midwest during the summer of 2016. The commenter s stated that adding new carbon dioxide101 compliance obligations on top of MATS creates a complex regulatory environment, the implications of which are not yet understo od.

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 EP A 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 t here 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 uti lities, and, i n 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 guideline s, 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 relat ive fuel costs, the increasing economic viability of renewables, and the slowed growth in demand for elec tricity 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

un economic to maintain by 2030 du e to implementation of the final emission guidelines.

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

Commenter s stated that the EPA did not take into consideration the requirements of the Nati onal Environmental Policy Act (NEPA) and delays required under that federal law in establishing timelines for implementation of the rule. The commenter s stated that they, like many rural electric cooperatives, borrow capital from the U.S. Department of Agr iculture 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 t he CP P should conduct a state by state study to determine the time required to finance, permit, construct and commission new NGCC102 generation, pipeline infrastructure and/or transmission projects to meet building block 2 and take
that into consideration when est ablishing interim goals.

Commenter s 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 commenter s 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 commenter s stated that the EPA's assumptions regarding N GCC 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.

Commenter s stated that by 2015, as s ources 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.

Commenter s stated that some stakeh olders 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

commenter s st ated 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 t ake 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 analy sis 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 strateg ies 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.103 In additio n, t he 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 base line 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 E PA 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:

Commenter s stated that regulatory uncertainty h as adversely affected the sulfur dioxide cap

- and

trade credits program. The commenter s 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 commenter s stated that the additional combined uncertainties of the various other regulatory programs only serve to compou nd the
difficulties for the commenter s in planning its environmental compliance strategy

.

Commenter s 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 avai lable 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 commenter s stated that the proposal is at odds with the fundamental assumption that BART eligible sources continued to be highly utilized and emit visibility

impairing pollutants and creates serious uncertainty as to remaining useful life factor when conducting BART determinations. The commenter s 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 commenter s 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 commenter s 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 thes e units to comply with the proposal. The commenter s 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 commenter s
st ated 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 pollu tion controls.

C ommenter s 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 CO 2 for new plants, retroactive application of104 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 assoc iated costs will be passed on to ratepayers. The commenter s stated that their utility ratepayers and ratepayers of other states appear to be ever at risk of EPA implementing yet another higher standard. The commenter s stated that they believe that it is fa ir 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 commenter s stated that they should receive credit for the benefits already attained by doing the right thing and the improvement cost s 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.

Commenter s 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 implement ed 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 em issions 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 ag rees with commenters that some pollution controls can result in a

cross

- media transfer of pollutants. T he coal combustion residuals rule, and the soon to be finalizing a rule to revise the effluent limitations guidelines and standards for the steam electri c 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 pu blic comments under this comment:

Commenter s 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 commenter s 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 ou r rivers. The commenter s 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 anoth er.1 05 Co mment 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 unde r 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:

Commenter s 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 commenter s stated that these additional mechanisms could provide state s 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 rev enues generated by state compliance mechanisms within a state improvement plan (SIP). The commenter s stated that state

- led agriculture, land use, and forest carbon incentive programs also offer an effective mechanism to leverage revenues associated
with 11 1(d) compliance actions toward further carbon benefits beyond EPA targets. The

commenter s stated that this will support progress toward the United States' international leadership in the climate change arena, including the newly announced national

- level c arbon 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

Respo nse 11 : The EPA appreciates the commenter s ’ 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 I ndian 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 : Sign ificant 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 cos ts 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 in106 conjunction with that rule which can be found in the ru lemaking 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 appropriat e 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 federall y guaranteed water delivery.

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

Commenter s 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 commenter s ’ community. The commenter s stated that there are two additional issues that the community urges the EPA to address in its final rule: First, the EPA s hould 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
allo w adequate flexibility in the final rule to address the possibility that the Court overturns
EPA's BART rule

. The c ommenter s 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 to pics 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

Res ponse 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 g rowth 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 pla n 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 growth107 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 th at 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

gen erating 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 higher

emitting 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 sta te 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 followi ng are summaries of the specific public comments under this comment:

Commenter s stated that EPA should ensure that implementation of standards for electricity generation does not unintentionally create disincentives for states that are deploying plug

- in
el ectric vehicles, a critically important strategy for reducing global warming emission from the transportation sector. The commenter s stated that under the mass

- based approach as proposed,
the standards could result in a disincentive for states from encoura ging greater electric vehicle deployment which would lead to higher electricity demand and therefor greater emissions in the electricity sector. The commenter s recommended that EPA consider modifications to the proposed standards to avoid creating disincen tives 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 st ates projected baseline, would avoid discouraging states from supporting greater EV deployment. The commenter s 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.