1 TABLE OF CONTENTS

CHAPTER 2 APPLICABIL ITY

................................ ................................ ................................ . 2 2.1 Overlap of Sections 111(b) and 111(d)

................................ ................................ ............ 3 2.2 Proposed Applicability vs. Broad Applicability

................................ ........................... 18 2.3 Applicability issues related to EGUs that fire biomass or ot her non

- fossil fuels

...... 32 2.4 Applicability issues related to combined heat and power (CHP)

............................... 36 2.5 Definition of Affected Source

................................ ................................ ......................... 54 2.6 Comments regarding subcategorization

................................ ................................ ....... 66 2.7 Other

................................ ................................ ................................ ................................ 762 CH APTER 2 APPLICABILITY

This chapter addresses public comments on the applicability provisions of the EPA's CAA section 111(d) guidelines for establishing standards for carbon emissions from existing EGUs as proposed on June 18, 2014 under 40 CFR p art 60 s ubpart UUUU. Consistent with paragraph 111(d ) ( 1 ) ( A) of the Act, the applicability guidelines for existing EGUs largely reflect the applicability provisions established under the New Source Performance Standards for EGUs promulgated at 40 CFR p art 60 s ubpart TTTT with one exception for simple cycle combustion turbines based on other fac tors , as allowed by paragraph 111(d ) ( 1 ) ( B) of the Act. This chapter addresses comments on the following categories, design criteria, and operating criteria that comprise the applicabilit y provisions of the guidelines:

• Overlap of section 111(b) and 111(d );

• Broad applicability approach ;

• Applicability issues related to EGUs that fire biomass or other non

- fossil fuels;

• Applicability issues related t o combined heat and power units;

• Definition of affect ed source;

• Subcategorization

• Other.

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 3 : GHG Mitigation Measures

• Chapter 4: State Goal Computation

• Chapter 5 : State Plan Considerations

• Chapter 6 : State Plans

• Chapter 7 : Interactions With Other EPA Programs and Rules

• Chapter 8 : Impacts and Cost Analysis

• Chapter 9: Statutory and Executive Orders3 • Chapter 10: Rule Language Corrections

2.1 OVERLAP OF S ECTIONS 111(B) AND 1 11(D)

This section addresses comments received on interactions of the EGU GHG Emission Guidelines with the EGU GHG NSPS regarding new , modified, or 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 : Section 111(b) applicability must be promulgated first, and the applicability criteria under sections 111(b) and (d) must be the same for new and existing sources. There were di fferences in the proposal preamble and rule text discussions that must be clarified

. Response 1: The 111(b) applicability includes all units (assuming they are new) that are included in the 111(d) applicability. See section IV.C of the final rule preamble of the CPP for discussion of the applicability relationship between sections 111(b) and (d) of the CAA.

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

C ommenter s stated that the concurrent rulemaking efforts undermine the goal of ensuring the owners or operators of an existing source have clear notice of and a chance to prepare for the application of a new regulatory scheme. C ommenter s stated that EPA's reliance on regulations that are not finalized also compromises stakeh olders' opportunity to comment on the proposed rule; because the section 111(b) rule for new sources has not been finalized, stakeholders cannot know with certainty which existing units will be affected by the section 111(d) proposal. Commenters stated thi s has been a particular challenge for Alaska. C ommenter s stated that, for example, EPA proposes different applicability criteria for existing and new steam generating units: a new steam generating unit would be covered by the 111(b) rule only if it was con structed for the purpose of supplying, and supplies a threshold amount of electric output; by comparison, and contrary to the intent articulated in the preamble, the proposed section 111 (d) rule omits the "and supplies" from the applicability criteria for existing EGUs. Commenters stated that if this disjuncture persists, EPA would be seeking to regulate existing sources under section 111(d) that would not be regulated as new sources under section 111(b).

Commenters stated that without a final 111(b) rule

, they cannot evaluate whether one of their coal units will be an " affected EGU ;" this information is critical to understanding the possible impact of the rule in Alaska for evaluating what concerns should be raised in their section 111(d)
comments.

Comme nters believed that paragraph 111(d ) ( 1 ) ( A ) ( ii) requires that the Agency must first propose a section 111(b) standard for all sources that meet the definition of "new source" under paragraph 111(a ) ( 2) to establish both the operative date necessary for d ifferentiating new4 sources from existing sources and the congruent scopes of applicability under paragraphs 111(b) and paragraph 111(d).

Commenters stated that the proposed applicability criteria for existing EGUs are unlawful because the proposed definiti on of "affected EGU" is broader in the rule proposed under section 111(d) authority than the proposed definition of affected EGU in the rule proposed under section 111(b) authority, and commenters believed that the applicability provisions for existing sou rces improperly include EGUs that qualify for exemption based on the proposed NSPS thresholds for use of fossil fuels and electricity sales. Commenters stated that the definition of " affected EGU " in the proposed guidelines must retain the exclusions for new subpart Da units proposed in January of 2014 (i.e., the " low fossil use criterion " and the " one

- third sales criterion ") because the preamble to the proposed guidelines invoked the NSPS applicability (79 FR 34854) and
commenters did not believe that the EPA provided any legal or technical rationale for altering the scope of what Subpart Da units qualify as " affected EGUs " in the proposal for existing

sources. Commenters cited CAA section 307(d) as requiring the Agency to provide a technical rationale for increasing the scope of sources subject to the 111(d) standard as compared to the scope of sources proposed for the NSPS, and commenters stated that if EPA adopts final emission guidelines, it should define " affected EGUs " to be consistent with the defini tions in the January 2014 NSPS Proposal. Commenters believed that the applicability criteria proposed in the January 8, 2014 proposal is preferable to the applicability proposed under the section 111(d) guideline because they believe d that a criteria based on actually supplying more than 219,000 MWh net is appropriate, in order to bring only the truly large units under the Rule.

Commenters believed that the Agency cannot lawfully finalize guidelines under section 111(d) without first re

- proposing the 111(b) standards for new sources with applicability criteria that are consistent across both the 111(b) and 111(d) proposals. Commenters stated that section 111(d) and 40 CFR 60.22 require the Agency to propose section 111(b) standards for the same types of

sour ces included in subsequent proposals under section 111(d). Similarly, commenters believe d that section 111(d) and 40 CFR 60.22 establish a prerequisite for the Agency to finalize section 111(b) standards for new sources prior to promulgating 111(d) standar ds for existing sources with identical applicability criteria.

Commenters stated that the proposed approach for using " Broad Applicability " criteria to apply no emission standard to a set of new sources under section 111(b) authority in order to increase
t he scope of existing sources that could be included in a standard issued under section 111(d) authority will not affect the scope of what existing EGUs may be eligible for regulation under section 111(d) because under section 111(d), a state plan may estab lish standards of performance only for " any existing source . . . to which a standard of performance under [section 111] would apply if such existing source were a new source ." Commenters believed that " no emission standard" is not a "standard of performan ce " as defined in section 111(a ) ( 1) because a

" standard of performance" is defined as a "requirement of continuous emission reduction."

Commenters stated that applicability under section 111(d) regulations should be clear and consistent with applicability provisions under section 111(b) regulations, and commenters opposed the differences included in the 111(d) proposal. Commenters stated that the various applicability provisions included in the three proposals issued under section 111 authority were ambigu ous and confusing, and commenters found it difficult to determine which sources should5 be included for capital and compliance planning by operators and states. Commenters stated that portions of the preamble stated that the rationale for applicability unde r 111(d) was the same as the rationale for new sources under section 111(b), but that the regulatory texts differed, and
commenters stated that the proposal included no justification or rationale for the differences. Commenters stated that the proposed 11 1(d) rule was inconsistent and unclear regarding in the definition of an affected EGU. Commenters agreed with the scope of applicability presented in section V.C of the section 111(d) preamble because this portion of the proposal described applicability of the 111(d) proposal consistently with the January 8, 2014 proposal under 111(b) as required by section 111(d ) ( 1 ) ( A ) ( ii). However, commenters opposed the proposed regulatory text at section 60.5795(b)(1) because this paragraph deviated from the January 8, 2014 applicability criteria, and commenters believe d that the proposed section 111(d) applicability criteria could be interpreted to mean that a biomass unit that only uses fossil fuel for startups is an affected EGU under section 111(d), and commenter s provided draft language for section 60.5795(b) that would ensure consistency between the section 111(b) proposed regulatory text, the section 111(d) regulatory text and Agency intentions stated in section V.C of the 111(d) proposal.

Commenters urged the EPA to correct inconsistencies across the three section 111 proposals.

Commenters believed that the differences in applicability under the section 111(b) and section 111(d) proposals for steam generating units and IGCC units were drafting errors and commenters requested that the final rule correct these drafting errors.

Commenters opposed the differences in the applicability criteria proposed for the section 111(d) as compared to the applicability criteria proposed for the section 111(b) rules, because
commenters believed that the statute requires the EPA to use the same applicability criteria for the 111(d) rule that is established in the precedent 111(b) rules.

Commenters specifically opposed the applicability criteria for Subpart Da units under the section 111(d) proposal because these applicability criteria are incons istent with the applicability criteria proposed for new sources under section 111(b) authority. Commenter s believed that the statutory language under section 111(d) includes a restriction that the regulated entity must be identical in the section 111(b) an d section 111(d) regulations.

Commenter s believed that changing the applicability criteria in the section 111(d) proposal also appears to change the applicability criteria of 111(b) regulations.

Commenter stated, the EPA proposes changes to applicability r equirements and emission standards would have implications for both new and existing requirements.

Commenter s requested that the EPA withdraw the section 111(d) proposal because commenters believed the prerequisite standards for new sources under section 1 11(b) did not constitute an NSPS as defined in section 111, and commenters believed that subsequent standards under 111(d) must have applicability criteria substantively identical to the criteria for new sources. Commenters believed that the proposed appli cability criteria for new sources are inconsistent with the definition of "standard of performance" in section 111(a) because the proposed standard for emissions of CO2 to the atmosphere does not apply to all components of the carbon capture6 and sequestrat ion technology determined by the EPA to be the best system of emission reduction (BSER). Commenters acknowledged that the proposed applicability criteria encompasses stationary source operations through capture of the CO2 produced from fossil

- fuel combusti on at the stationary source, but commenters believed that disposition of the captured CO2 after it leaves the stationary source is outside the scope of the proposed NSPS; commenters referred to omission of BSER components (with the potential to emit captur ed CO2 to the atmosphere) as a

" fatal flaw " in the proposed applicability criteria for these section 111 standards.

Commenters stated that the EPA has no authority to require the installation of equipment that is not within the scope of a " steam generating unit " because existing unit standards of performance under section 111(d) can only apply if the existing source were a new source, and the scope of a

" steam generating unit " must be examined by referring to the standard for new sources under subpart Da. C ommenters asserted that subpart Da limits the scope of a steam generating unit to

" any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam..." Commenters believed that this means that other equipment such as steam t urbines cannot directly or indirectly be considered when establishing BSER or a standard of performance. Commenter s cited support for their position from a November 25, 1986 EPA memorandum entitled, Interpretation of Reconstruction; the memorandum details what items of equipment are included in the scope of a new steam generating unit, and the memorandum includes a diagram clearly showing the scope of a steam generating unit. Commenters opposed the proposal's reliance on efficiency improvement projects that pertain to steam turbines because the diagram in the November 25, 1986 EPA memorandum does not encompass the steam turbine. Commenters also stated that EPA has improperly included many systems (or facilities) at EGUs that are not defined by the 1986 EPA m emo as part of the affected source. Commenters believed that the proposal's reliance on these out

- of

- scope facilities in the building block one analysis is inappropriate because the Act requires that section 111(d) standards must apply only to a source " t o which a standard of performance under this section would apply if such existing source were a new source."

Commenters stated that the final rule should resolve inconsistencies in the definition of affected

source between the definition of "affected source" in the preamble of the proposed rule and the definition of "affected source" in the proposed rule text because the definition of "affected

sourc e" in the preamble includes the criteria that an EGU combust fossil fuel for more than 10 percent of its total annual heat output, but proposed section 60.5795(b)(1) does not include this criteria for steam generating units. Commenters stated that this inc onsistency has generated confusion among RGGI states because the list of affected sources used to set individual state goals is inconsistent with the proposed definition. Commenters stated that if the proposed definition is included in the final rule, the list of affected sources will need to be broadened and the state goals must be amended accordingly. Commenters stated that this uncertainty made it challenging for affected states to submit complete and accurate
comments. Commenters stated that to remain c onsistent with the intent of the preamble, the rules proposed for new, modified, and reconstructed sources under 111(b) and the definition of

" affected source " as applied in the setting of state goals, the EPA should amend the definition of

" affected sourc e " in section 60.5795(b ) ( 1) to include the 10 percent fossil fuel requirement for steam generating units.7 Commenters stated that the final rule should correct inconsistencies in the definition of affected source because the definition of affected source i n the preamble to the proposed rule is different from the definition of affected source in the proposed rule text. Commenters stated that the definition of affected source in the preamble includes the criteria that an EGU combust fossil fuel for more than 10 percent of its total annual heat output, but proposed section 60.5795(b ) ( l) does not include this criteria for steam generating units. Commenters stated that this provision was critical to an EGU operating in his state and requested that the final rule definition include this 10 percent criteria

.

Comment 2: Support and opposition for dual applicability under sections 111(b) and 111 (d).

Response 2: The EPA agrees with commenters that 111(d) applicability should not include 111(b) units and the definition of affected unit in 111(d) final rule does not include 111(b) units.

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

Commenters stated that the only major departure would be the dual applicability of 111(b) new

so urce and 111(d) existing source standards, and commenters recognize d the legal intricacies of that distinction. Commenters stated that there are ways to accommodate this through appropriate definitions, opt

- in provi sions, or other creative means.

Commenter s stated that the proposal's reinterpretation of Section 111(d) is at odds with the Act, prior rulemakings, and prior interpretations because in the past sources subject to standards under section 111(b) were not also subject to standards under 111(d).

Com menters stated that the proposed compliance options under the section 111(d) proposed rule are unclear and requested that the EPA clarify and justify how power generation facilities permitted under its proposed carbon dioxide emission rule for new power pl ants would be treated for purposes of complying with its proposed rule for existing power plants.

Commenters stated that EPA should not require emissions from a 111(b)

- regulated facility to count against an emission limit (rate or mass

- based) for 111(d) co vered facilities as the two categories are mutually exclusive; a facility cannot be regulated under both statutory provisions. However, commenters stated the broad flexible construct EPA has conceived for this proposed 111 (d) rule provides no logical impe diment to providing states the options to (a) use the emission rates of 111(b) facilities to average down or take the place of emissions from existing 111(d) covered facilities; or (b) count 111(b) emission reductions over

- compliance toward emission reduct ions required by a mass

- based State plan.

Commenters stated that they disagree with EPA position that there is sufficient ambiguity in the CAA to allow EPA to require inclusion of these section 111(b) sources in a section 111(d) plan. Commenters stated tha t the CAA is clear that a modified source is treated as a new source, and that a new source is not an existing source. Commenters stated that clearly, an existing source is separate from a new source, and section 111(d) only applies to existing sources. Co mmenters8 request ed that EPA regulate new sources solely under section 111(b) and existing sources solely under section 111(d).

Commenters stated that when establishing state goals, the Agency must exclude sources that do not meet the applicability criteria proposed for new sources. Commenter s stated that for steam generating units and IGCC units, the 111(d) proposal eliminated proposed 111( b) applicability thresholds based on use of fossil fuels and electricity sales; commenters opposed elimination of these applicability criteria in the 111(d) proposal. Commenters stated that these proposed differences in 111(b) and 111(d) applicability crit eria resulted in the erroneous inclusion of certain EGUs when establishing the proposed goal for the State of Florida. Commenters stated that certain units that do not meet the proposed applicability criteria under the proposed section 111(b) applicability criteria should not have been included by the Agency when calculating the proposed section 111(d) goal for the State of Florida.

Commenters stated that inconsistencies between the applicability criteria proposed for new sources and the applicability crite ria proposed for existing sources resulted in inclusion of EGUs in calculation of the proposed goal for the State of Florida that, if new, would not be subject to the section 111(b) standard for new sources; commenters believed that inclusion of these unit s is inconsistent with the requirements of paragraph 111(d ) ( 1 ) ( A ) ( ii). Commenters stated that the Agency erroneously included in the proposed goal for the State of Florida EGUs with federally enforceable permit limits that fall below proposed 111(b) app licability thresholds, and
commenter s provided a listing of these units with a request that the Agency remove these EGUs from future goal calculations.

Commenters stated that the EPA has historically made a distinction between existing sources and

new sour ces in its rule making. Commenters said it is unclear why the EPA is attempting to regulate an existing source by both sections 111(b) and 111(d) of the Clean Air Act. Commenters said this essentially imposes a limit on a unit twice. Commenters suggested t hat the EPA should remain consistent with how it has issued regulations in the past.

Comment 3 : Support and opposition for modified and reconstructed sources to remain as section 111(d) existing sources.

Response 3: The EPA agrees with commenters that 11 1(d) applicability should not include 111(b) units and the definition of affected unit in 111(d) final rule does not include 111(b) units. See section VIII.D of the final rule preamble of the CPP for the EPA’s response to existing sources that undergo a modification.

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

Commenters found as problematic EPA's proposal that would result in modified and reconstructed sources also being subject to standards for existing sources; du al regulation.9 Commenters stated that the EPA provides no legal basis for requiring existing sources subject to section 111(d) to continue to be regulated under state plans under section 111(d), post modification or reconstruction, in addition to being su bject to requirements under section 111(b). The commenters also stated that the EPA's proposal does not explain what is meant by the phrase "subject to a state plan under section 111(d)," and the draft rule language in the technical support documents does not provide clarity on this issue or the dual applicability of section 111(b) and section 111(d). The commenters stated that the proposed rule does not explain how this concept integrates with current regulatory text in 40 CFR section 60.14 and section 60. 15 specifying that modified and reconstructed facilities become "affected facilities" if certain criteria are met. Commenters stated the EPA is proposing a "once in always in" rationale for units subject to section 111(d), which is contrary to the statute and to past section 111(d) actions. The commenters stated that, ironically, the EPA says in its proposal, that it should be noted at the outset that the EPA determined that reconstructions are a type of construction, and therefore subject to CAA Section 11 1(b), as part of the 1975 framework regulations, and the EPA is not

re

- opening that determination (79 FR 34981); yet, the EPA has taken the contradictory position that sources that are modified or reconstructed remain regulated under section 111(d). The

co mmenters stated that if Congress intended modified sources to remain under section 111(d), then there would have been no need to define "modification" in section 111(a) and set standards for modified sources in section 111(b), since modified sources are ju st existing sources that have undergone a physical change. The commenters stated that the EPA's departure from applying BSER to the emission source in formulating state goals under section 111(d) results in significantly different performance standards for modified or reconstructed sources compared to state goals, along with the impossibility of demonstrating compliance with the goals in state plans; for example, the EPA would not be able to assume existing turbines to be re

- dispatched up to 70 percent unde r Block 2 for the purposes of setting state goals under the proposed section 111(d) rule if these units ceased to be subject to section 111(d) upon reconstruction or modification. The commenters stated that, similarly, all existing coal

- fired EGUs could potentially be considered modified, depending upon the physical changes each unit implements to achieve Block 1 six percent heat rate improvement, thereby removing them from regulation under state plans formulated under section 111(d) and the fact that the EPA has proposed a schema for existing sources under this proposed section 111(d) rule that is dependent on a captive source population is not a rational basis for deviating from the plan language of the FCAA and established precedent regarding modificati on or reconstruction of sources subject to a section 111(d) state plan. The commenters stated that because the EPA has provided no rational basis to support this position, the EPA should withdraw its proposal regarding dual applicability under section 111 and modify proposed section 60.5795 to exclude modified or reconstructed sources consistent with prior section 111(d) rules.

Commenters stated that EPA should not attempt to regulate CO2 emissions for the same source under both section 111(b) and section 111(d) of the CAA. The commenters stated that considering how modified and reconstructed sources may already be drawn from the group of existing units that EPA has proposed to regulate for CO2 emissions under Section 111(d), they recommended that EPA simpl y exempt modified and reconstructed sources from CAA Section 111(b) regulation. The commenters s aid that states should retain the flexibility to exempt or assign regulatory applicability to modified and reconstructed sources for CO2 emissions and, if

neces sary, these state

- driven, flexible assignments could be proposed by the states in their 111(d) State Implementation Plans. The commenters stated that new NGCC or coal generating units10 regulated under Section 111(b) and subject to CO2 New Source Performance Standard requirements should not also be subject to regulation under Section 111(d) existing unit requirements.

Commenters stated that the 111(b) proposal for modified and reconstructed sources is in conflict with the Agency's 111(d) proposed guidelines. The commenters stated that generally, the strictness of the NSPS progresses with the strictest limit reserved for wholly new facilities; the next and lesser strict standard applies to reconstructed units; the next level of standard applies to those units t hat are modified to increase net emissions above significance thresholds; and the least strict standards are applied to existing units that continue to operate as designed, and, for which, the burden of installing new designs and controls to achieve lower emissions is the hardest to justify. The commenters stated that this is how the EPA has historically applied NSPS and new source review to emitting sources; but the EPA now turns that program on its head, most evident when comparing the proposed requiremen ts under 111(b) and the proposed guidelines under 111(d). The commenters stated that where one would expect to see the most stringent limits on brand new, yet

- to

- be

- constructed sources, in fact the lowest, most stringent limits are proposed for existing un its under 111(d), where existing utility boilers in states such as North Carolina or South Carolina will have to meet emission rates of 992 and 772 pounds per net megawatt hour of CO2, respectively, whereas, utility boilers yet to be constructed must meet a rate of 1,110 lbs./MWh

- net of CO2, and that with carbon capture and sequestration, while modified or reconstructed units would have to meet a maximum emission rate of 1,900 lbs./MWh

- net of CO2.

Commenters, stated in its 111(b) proposal the EPA states tha t rebuilding with the most efficient technology should be BSER for an affected unit (and yet it proposes an emission rate of 1,900 lbs . / MWh

- net), and admits that even smaller emission reductions are the best that can be hoped for with best operating pract ices and equipment upgrades; yet the least stringent emission rate proposed by the EPA under 111(d) is less than 1,800/MWh

- net. The commenters stated even more telling is that modified or reconstructed units would have to achieve efficiency improvements of 2 percent, while an existing utility boiler making no change would have to achieve an initial 6 percent improvement, as proposed by EPA in Block 1 of the agency's preferred option. The commenters stated that the EPA offers no reliable data to support the achievability of either a 2 percent or 6 percent improvement and provides no information regarding the durability of such an improvement and noted that many efficiency improvement measures begin to degrade as soon as they become operational; thus, CO2 redu ctions from efficiency improvement projects are real, but fleeting and cannot be counted on to provide lasting reductions.

Commenters stated that the EPA states in its 111(b) proposal that the most improvement an existing utility boiler can reasonably make is a 2 percent improvement, thereby undercutting the justification in its section 111(d) proposal for an initial 6 percent improvement for existing utility boilers.

Commenters stated that another puzzling part of the EPA's proposal is that a boiler may be subject to both 111(d) and 111(b). The commenters stated that under any other NSPS, a modified source would be required to meet a standard equal to or more stringent than an existing source, so no question arises about whether an existing source affected under NSPS guidelines must11 continue meeting those guidelines once it triggers section 111(b) as a modified source. The commenters continued that, however, by establishing a more stringent standard for covered existing units, the EPA must develop some ratio nale for continuing to subject an existing unit to the more stringent existing source standard even when it modifies the unit and triggers application of the lesser 111(b) standard. The commenters stated that all of these regulatory contortions are avoided if the EPA proposed a reasonable 111(d) standard. Commenters stated in effect, the EPA proposes two different best systems of emission reduction standards and attempts to apply them simultaneously to the same unit; thus, this part of the proposal is arbit rary, capricious, and exceeds the legal limits of the EPA's authority.

Commenters stated that the EPA cites K Mart Corp. v. Cartier, Inc., to support its approach of creating two separate systems of BSER and applying them to the same units simultaneously; however, K Mart is not a CAA case, and the fact that the best authority the EPA could find to justify its proposal is an unrelated case about trademarks and gray goods is an indication that this proposal is unprecedented and that the EPA has overstepped th e bounds of its authority.

Commenters stated that EPA's assertion that they can regulate existing sources that modify or reconstruct under both the existing source and new source provisions of section 111 because section 111 is silent on whether requiremen ts imposed under a 111(d) plan continue for a source that ceases to be an existing source because it modifies or reconstructs is incorrect. The commenters stated that 111 (a) definitions of new and existing sources are mutually exclusive and that once a mo dification or reconstruction commences, the existing source ceases to exist and a new source emerges; and, new sources are subject to regulation pursuant to 111(b) and 111(d) cannot apply to sources subject to section 111(b). Commenters stated the two poli cy reasons EPA sets forth to justify its proposed decision to subject new sources to both existing and new source regulatory requirements (see 79 FR 34904) would be resolved by withdrawing the proposed standards for modified and reconstructed EGUs; the EPA has discretion not to impose NSPS for modified or reconstructed units and by choosing not to do so in this instance, it would avoid the concerns it has raised. The commenters stated that State plans devised with the correct statutory interpretation in min d can include provisions to accommodate such changes; indeed, the EPA envisions many sources shutting down as a result of the proposed guidelines and, if state plans can accommodate units leaving the program through cessation of operations, there is no rea son why they cannot accommodate the transition of modified or reconstructed units from the existing source program to the section 111(b) program for new sources. The commenters stated that in addition, to the extent the EPA has designed a section 111(d) pr ogram that cannot function while adhering to the requirements of section 111(a)(2) and section 111(a)(6), it is the EPA's proposal, not the CAA, that must be revised.

Commenters stated that with regard to the EPA's concern that there could be an incentive for sources to modify or reconstruct to avoid their obligation under a CAA section 111(d) plan, for the reasons explained above, a source that undertakes a modification or undergoes reconstruction after the date of the proposal of the applicable NSPS has n o obligation under a section 111(d) plan; it could only have such obligation as a matter of state law at the state's discretion. The commenters stated that EPA cannot require states to regulate a unit as both a new and existing

source.12 Commenters disagree d with EPA's proposal to require existing EGUs to remain subject to state or federal section 111(d) plans even after they undergo a modification or reconstruction that triggers CO2 NSPS regulation under section 111(b); this is not necessary to achieve EPA' s CO2 emission reduction goals, and is contrary to the plain text of section 111. The commenters stated that as a matter of environmental policy, EPA should not discourage existing units from investing in modifications and reconstructions that result in re duced emission rates for pollutants, including CO2, and are also an important source of jobs. The commenters stated that units contemplating modification or reconstruction in the future may be discouraged by the prospect that they would need to meet both s tate section 111(d) plan requirements and federal standards of performance for modified sources. The commenters stated that EPA should clarify that modified and reconstructed units will cease to be subject to any section 111(d) plan to which they were
prev iously subject upon the commencement of modification or reconstruction. The commenters stated that such an interpretation would not necessarily compromise the integrity of state plans; although the removal of an existing unit from a state cap

- and

- trade or trading system might disturb certain aspects of a state program, such disturbances could easily be dealt with through administrative mechanisms that would not discourage modifications and reconstructions. The commenters stated that, rather than aggregate, state

- by

- state guidelines, the EPA could eliminate the possibility of disruption by issuing category

- specific, nationally applicable emission guidelines, as they have in the new and modified/reconstructed unit proposals with the result that the transition of a single EGU from existing status to modified or reconstructed status would have no effect on other existing units' compliance. The commenters stated that even under EPA's proposed goal

- setting approach, EPA could allow states to administratively adjust their state goals upon receiving notice that an existing unit has commenced modification. The commenters stated that the adjustment procedure could be codified in the state's approved plan, and therefore would not require a new federal rulemaking every ti me an existing unit decides to modify. The commenters stated that alternatively, under a cap

- and

- trade program, a state could automatically retire a predetermined quantity of allowances upon learning that a particular unit would exit the section 111(d) pro gram upon modification; such a change also would not require additional EPA rulemaking, but would avoid the possibility that cap

- and

- trade programs would have too much "hot air" to stimulate emission reductions as newly modified units exit the program. The commenters stated that there are many other ways that states and EPA could encourage modifications at existing units without disrupting the implementation of the existing source guidelines, aside from the approach EPA has proposed.

Commenters stated that, regarding EPA's proposal that an existing source subject to Section 111(d) will continue to be subject to those requirements even after it undertakes a modification or reconstruction and that this integrated system wide regulatory proposal would face seri ous implementation issues if affected sources were no longer subject to these plans, they do not agree with EPA's interpretation nor its extension to any existing source subject to any Section 111(d) plan.

Commenters stated that they also raised concerns under a co

- proposed option for modified sources regarding the EPA proposing the date for determining whether a unit is subject to a Section 111(d) plan is the date that the plan is initially submitted to the EPA; that is whether the modification occurs bef ore or after the promulgation of a section 111(d) plan. The commenters wished to reiterate their concerns with how these two section 111 plans will function together. The commenters stated that if alternative 2 of the modified proposal is promulgated by th e EPA13 then a modified source will be subject to one of the two limits if the modification occurs before they submits their plan; however, recognizing the time it takes for a plan to be developed, the commenters and sources would be working together and pla ns under section 111(d) may be well underfoot. The commenters stated that they have concerns that some changes that may be chosen by a utility necessary to comply with section 111(d) may trigger a modification or reconstruction under this rule. The comment ers stated that sources will be leery about making those changes, although they may be quite beneficial for the purpose of reducing CO2, if they know it will trigger the modify or reconstruct applicability. The commenters stated that the EPA has not thorou ghly investigated and resolved the implications regarding the integration of these two proposals. The commenters stated that the EPA must separate these proposals and develop traditional section 111 proposals that follow the intent of the CAA to address ex isting sources and also modified and reconstructed sources. The commenters stated that on the same date as this proposal, the EPA proposed requirements for modified and reconstructed units under section 111(b) and that they submitted comments regarding thi s proposal and have requested the EPA take into consideration the comments submitted under this proposal and under the modify/reconstruct proposal jointly with respect to both proposals due to the interconnected nature of the two proposed rules and the ove rlap in the comments.

Commenters stated that if any unit is converted from firing coal as its primary fuel to one that fires primarily natural gas, the conversion should be considered a modification for purposes of the carbon reduction program and the natu ral gas unit could therefore be regulated under section 111(b) rules rather than a state's section 111(d) emission guidelines.

Commenters opposed the proposal to treat modified and reconstructed sources as existing sources under paragraph 111(d) and charac terized this aspect of the proposal as arbitrary and capricious because commenters believe d that the Act requires more stringent standards for modified and reconstructed sources than for existing sources, but commenters believe d the proposed standards for existing sources are more stringent than the proposed standards for modified and reconstructed sources. Commenters stated that the proposed applicability provisions that would require modified and reconstructed sources to be classified as existing

sources is inconsistent with the enforcement posture that the EPA has taken under the new source review (NSR) program where modifications force a departure from the world of existing

sources.

Commenters asked if an EGU that is currently '" affected" (under the paragraph 111(d) standard for existing sources) were to commence modification or reconstruction prior to becoming subject to an applicable state plan, would EPA recalculate the state specific goal to reflect the absence of this no

- longer " affec ted " EGU?

Commenters stated that the final rule should not attempt to regulate CO2 emissions from the same source under both section 111(b) and section 111(d). Commenters recommended that the final rule simply exempt modified and reconstructed sources from applicability under section 111(b) regulations and allow states to retain the flexibility to exempt or assign regulatory applicability to modified and reconstructed sources as appropriate in their 111(d) plans. Similarly, commenter s stated that new source s regulated under 111(b) should not also be subject to regulation under Section 111(d).14 Commenters , air quality permitting authorit ies , opposed the proposed applicability provisions that would require an existing section 111(d) source to continue to be sub ject to state 111(d) standards even after it undertakes a modification or reconstruction

. Commenters acknowledged that this proposed "once

- in

- always

- in" policy is intended for compatibility with the proposed integrated system

- wide regulatory approach, but commenters did not agree with this "interpretation" nor its extension to any existing source subject to any section 111(d) plan.

The EPA should clarify that sources that modify or reconstruct prior to submission of a state plan are subject to section 111 (d). Commenter s stated EPA has clearly stated that sources that modify or reconstruct after becoming subject to a section 111(d) state plan remain subject to the state plan requirements, the Agency has not made it clear that sources modifying or reconstruc ting prior to submission of a state plan are subject to section 111(d) state plan requirements. Commenter s said although one part of the proposal suggests that all modifications and reconstructions are subject to section 111(d), another portion of the prop osal asserts that sources that modify or reconstruct after plan submission will continue to be subject to the plan. Commenter s said EPA should expressly provide that sources modifying or reconstructing after the proposal of its emission guidelines and prio r to state plan submission are still sources for which state plans must establish performance standards under section 111(d). Commenter s said these sources should be subject to 111(d) state plan because the existing source BSER remains the system that will ensure the greatest pollution reductions from these EGUs considering cost and other statutory factors. Commenter s said allowing such modified or reconstructed EGUs to exempt themselves from section 111(d) would potentially undermine the stringency of stat e plans by allowing "leakage" to modified or reconstructed sources. Commenter s said such an approach would potentially require the recalculation of state goals and disrupt the development of state plans, all of which are premised on securing reductions fro m EGUs that were "existing" as of January 8, 2014.

Comment 4: Appropriate date for designating new and existing sources.

Response 4: See section IV.D of the final rule preamble of the CPP for a discussion of the new source designation date.

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

Commenters stated that the agency cannot cite the January 8, 2014 proposal date as the paragraph 111(a ) ( 2) date of proposal for differentiating applicability of section 111 standards to ei ther new sources under paragraph 111(b) or existing sources under paragraph 111(d) because a federal court recently held in Nebraska v. EPA, 4:14

- CV

- 3006, (USDC Neb. Oct. 6, 2014) that BSER determinations cannot be based on projects funded with federal dol lars under the Energy Policy Act. Commenters also stated that the agency cannot cite the June 18, 2014 proposal date as the paragraph 111(a ) ( 2) date of proposal for differentiating applicability of section 111 standards to either new sources under paragra ph 111(b) or existing sources under paragraph 111(d) because the June 18 proposal applied only to a subset of the sources within the definition of " new source."15 Commenters stated that the Agency cannot cite the January 8, 2014 proposal as the paragraph 11 1(a)(2) date of proposal because the January 8, 2014 proposal for new sources did not constitute a system of emission reduction as required by paragraph 111(a)(1). Commenters stated that proposed standard for new sources does not constitute a system of emi ssion reduction because the proposed NSPS is void of federally enforceable requirements regarding the ultimate fate of the CO2 separated by EGUs for off

- site disposal. Commenters asserted that the Agency cannot utilize authority granted under paragraph 111 (d ) ( 1 ) ( A ) ( ii) to finalize a lawful section 111(d) guideline based on an unlawful, prerequisite proposal under section 111(b).

Commenters submitted proposed revisions to proposed Subpart UUUU (requiring states to include requirements in their plans for N GCC units that become affected EGUs upon proposal of a revised GHG NSPS) in their Appendix A, with additions indicated in underlined text and deletions indicated in strikethrough text. Proposed revisions to proposed 40 CFR 60.5740, 5795, and 5800 seek remo val of exemption for combustion turbines commencing construction on or before promulgation.

Comment 5: 111(b) units should not become 111(d) units in the future

.
Response 5: The final rule does not include 111(b) units as affected units under 111(d). Future applicability of 111(b) units is outside of the scope of the rulemaking.

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

Commenters stated EPA's final guidelines should clearly state that units built after the CO2 emission standards for new units were proposed and which are in compliance with those standards will not become 111(d) units at some point in the future. The commenters stated that States will submit compliance plans in 2016 that are designed to achieve the 2030 goal relative to the 2012 emission rate that EPA calculated for each state and it would be inconsistent with the CAA and unfair to states if EPA changed the goals (or determ ined that states were no longer making progress toward the goal emission rates) after compliance plans are approved to address new NGCC units that were built after January 8, 2014. The commenters stated that this would undermine state flexibility to use th ese units for compliance purposes; more importantly, this would undermine the certainty states and utilities need with respect to the final goals so that they confidently can invest resources to achieve them.

Comment 6 : EPA ignored the nexus between secti ons 111(b) and 111(d) by developing an independent approach for existing source standards.

Response 6: We disagree with these comments. Our approach under section 111(b) for the BSER does not constrain our approach under section 111(d), but in any event, c ontrary to commenters’ assertions we applied a separate BSER for steam generators (building blocks 1, 2, and 3) and for combustion turbines (building block 3). The fact that the unused capacity in16 existing NGCC units allows them to be part of the BSER for steam generators does not mean that we are combining the two subcategories in a way that is contrary to section 111(d) or, for that matter, inconsistent with our approach under the re

- proposal for the section 111(b) rule. As we discuss in the preamble, dis patch shifts from existing steam EGUs to existing natural gas

fired EGUs in the amounts we include in the BSER for steam EGUs are well

- established in the industry and thus are adequately demonstrated for purposes of determining the BSER. We explain in the preamble and Legal Memorandum why the section 111(b) and (d) have a different BSER and why the section 111(d) requirements cannot be said to be more stringent than the section 111(b) requirements.
The following are summaries of the specific public comments under this comment:

Commenters went on to say that EPA entirely ignored the nexus between sections 111(b) and 111(d) by developing an independent approach for existing source standards. Commenters said that section 111 dictates that standards of performan ce for existing sources under Section 111(d) should be a more limited and flexible version of the standards of performance established by EPA for new sources under Section 111(b). Commenters said, if finalized, the proposed rule would do the opposite and u nlawfully expand the scope of the existing source rule to new categories of sources while imposing standards of performance that are more stringent than those EPA has proposed for new sources. Commenters provided instances of the inconsistencies between th e section 111(b) and 111(d) proposals:

• Commenters stated that EPA unlawfully combines coal

- and natural gas

- fired EGUs into a single source category for purposes of determining the best system of emission reduction adequately demonstrated. Commenters said, EPA flatly rejected this approach in its proposed regulation of new sources under Section 111(b). Commenters said, when EPA first proposed standards of performance for GHG emissions from new fossil fuel

- fired EGUs on April 13, 2012, it combined coal

- fired EGUs and NGCC facilities into a single source category and, after conducting a single BSER analysis, proposed a standard of performance based on emissions levels with which NGCC facilities could "readily comply," but coal

fired EGUs could not. Fed. Reg. 2 2,392, 22,410 (Apr.13, 2012). Commenters said, EPA subsequently withdrew that proposal, 79 Fed. Reg. 1,352 (Jan. 8, 2014), and proposed separate standards for coal

- and natural gas

- fired EGUs, 79 Fed. Reg. at 1,432. Commenters said, EPA based this reversal on its determination that both coal

- and natural gas

- fired EGUs would be viable options for new generating capacity and that different control technologies would be relevant to each. Id. at 1,434. Commenters said, this approach appropriately recognized th at critical differences between coal

- and natural gas

- fired EGUs required distinct BSER analyses and different standards of performance. Commenters stated, here, in contrast, EPA has effectively ignored the differences between coal

- and natural gas

- fired E GUs and has aggregated these sources for the BSER analysis rather than subdividing them to determine BSER for each subcategory.17 • Commenters stated that in the proposed rule, EPA acts inconsistently with the Section 111(d) proposal by unlawfully ignoring the source

- specific nature of the systems of emission reduction evaluated by EPA in the section 111(b) proposal. Commenters said, instead, EPA relies on a BSER analysis that is focused primarily on emission reductions that are accomplished beyond the fence li ne of affected EGUs by other, unrelated "zero

- emission" nuclear and renewable energy sources. Commenters said, indeed, many of the reductions would be accomplished by consumers of electricity rather that generators.

• Commenters stated that EPA turns the fle xibility that should be afforded to existing sources on its head. Commenters said, as EPA explained when it promulgated implementing regulations for Section 111(d), "the degree of control reflected in EPA's emission guidelines will take into account the co sts of retrofitting existing facilities and thus will probably be less stringent than corresponding standards for new sources." 40 Fed. Reg. 53,340. Commenters said, however, the EPA now has proposed binding emissions guidelines that are more stringent tha n the standards of performance it has proposed for new sources under Section 111(b). Commenters pointed out that EPA has proposed binding State

- specific emissions targets for 30 States that are more stringent than the standard of performance for new coal

- f ired EGUs.

Commenters argued that EPA cannot impose more stringent standards on existing sources under section 111(d) than it has under section 111(b). Commenters argued that because both section 111(b) and section 111(d) point to the same definition of "s tandard of performance," which references the application of BSER, EPA should use the same approach to determining the BSER under both section 111(b) and section 111(d) but should provide more, not less, flexibility in the establishment of BSER for existin g sources. Commenters said that EPA even acknowledged that "the general principle (application of best adequately demonstrated control technology [now referred to as BSER], considering costs) will be the same in both cases," but "the degrees of control rep resented by [the existing source emission guidelines] will ordinarily be less stringent than those required by standards of performance for new sources." Commenters also noted that from Congress' original promulgation of CAA section 111(d), it was recogniz ed that certain limitations may apply to existing sources that might not exist for new sources and that because of the limitations on existing sources, “ more stringent requirements are imposed on new sources because engineering considerations allow for che aper and more effective pollution control when the effort is incorporated in the design and construction of the facility."

Commenters also said that EPA provides states the ability to deviate from emission guidelines when adopting emission standards for e xisting sources in various scenarios and that it would be unrealistic to assume that by providing this added flexibility for existing sources, EPA intended for the existing sources to be subject to more stringent standards than new sources.18 2.2 PROPOSED A PPLICABILITY VS. BROAD APPLICABILITY

This section addresses comments received on the proposed applicability criteria versus the broad applicability criteria

. 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 : Cover all fossil fuel fired units, and apply consistent applicability across all three section 111 EGU rules.

Response 1: The 111(b) applicability is consistent for all affected units. See section IV.A.1 of the NSPS preamble for a discussion of the broad applicability criteria for new, modified and reconstructed sources (steam generating units). See section s VIII.D and IX.A.3 of the 111(b) NSPS preamble for a discussion of the broad applicability criteria for new, modified and reconstructed sources (combustion turbines) . See section IV.D of the final rule preamble of the CPP for the EPA’s response on the broad applicability criteria for existing sources.

The following are summaries of specific pub lic comments under this comment:

Commenters believed that all fossil fuel

- fired EGUs in operation or that commenced construction as of January 8, 2014 should be considered affected units subject to the proposed rule, whether such units are own ed by merchant generators, investor

- owned electric utilities, public utilities or private cooperatives.

Commenter s , the air quality permitting authority for the State of Ohio, responded to the EPA's request for comments on "a multitude of additional change s" to the applicability criteria;
commenters stated that in combination with the proposed changes to applicability, commenters found it difficult to determine exactly what the EPA is proposing. Commenters stated that it was difficult to determine if propos ed applicability changes apply to modified and reconstructed sources, new sources, or existing sources. Commenters also stated that it was unclear if proposed revisions to applicability provisions were relevant to only GHG emissions or to all regulated pol lutants under Part 60. Commenters stated that it was difficult to determine if the proposed changes will apply to other section 111 categories, and that it was difficult for the State of Ohio
to grasp what the full impact of the changes will be. Commenters stated that it is imperative that the final rules for the three section 111 proposal reflect a clear, consistent, rational, and defensible set of applicability criteria across all three section 111 rules.

Commenter s referred to comments previously submitted for the 111(b) proposal that stated section 111 requires the EPA to develop achievable standards based on what is achievable at the time they are proposed. Commenters acknowledged that some of the options consider ed in the proposal may seem reasonable in theory but opposed inclusion of numerous applicability options because commenters believed proposed regulations with numerous options are inconsistent with the EPA's statutory obligation to demonstrate that the ass ociated standards are19 achievable for all the different sets of units implicit in each applicability option; commenter s cited the following case to support these concerns: Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433

- 34 (D.C. Cir. 1973). Commenters a sserted that the EPA cannot finalize any standards that the Agency cannot demonstrate are reasonable or standards for which EPA has not provided stakeholders sufficient opportunity for notice and meaningful comment.

Commenters recommended revisions to the criteria that a unit must be constructed for the purpose of selling and that the unit actually sells over one third of its potential electric output to the utility distribution system; commenters urged the EPA to include more uniform applicability criteria for steam units, IGCC units, and for combustion turbines across all three section 111 proposals. Commenters stated that the criteria that (1) the unit must be constructed for the purpose of selling and that (2) the unit actually sells over one third of it s potential electric output to the utility distribution system and that (3) the unit combusts fossil fuel for more than 10 percent of its heat input should apply also to steam generating units because this simplification can reduce compliance costs and ens ure that only those units that are actually intended to function as utility generating units are regulated under this section 111 category.

Comment 2: Consistent applicability with RGGI.

Response 2: See section IX.A. 1 and 3 of the NSPS preamble for a discussion of the broad applicability criteria for new, modified and reconstructed sources.

The following are summaries of the specific public comments under this comment :
Commenters stated that the final rule should change or clarify the differences in ap plicability under the proposed rule and under the Regional Greenhouse Gas Initiative (RGGI) because the RGGI states have indicated their intention to use RGGI as a compliance mechanism, and the final rule should ensure that compliance with the RGGI cap wil l satisfy states' 111(d) obligations if the RGGI cap reflects the combined states' targets. Commenters subsequently provided several differences between RGGI and proposed 111(d) applicability criteria. Commenters, transmission system operators, stated that currently RGGI does not regulate hydro

- electric imports from Canada and requested that the final guidelines allow transmission operators to continue to use hydro

- electricity imported from Canada.

Commenters supported use of RGGI as the compliance mechani sm for section 111(d) state plans, but commenters recommended that the EPA take specific action to facilitate the use of the RGGI paradigm. Commenters respectfully requested that the final rule include clarifications on how state plans should address diffe rences in applicability in the RGGI program versus applicability in the final rule. Commenters specifically mentioned that the RGGI program in New York applies to all units that exceed 25 MW but the 111(d) proposal had a number of other criteria that
must be considered to determine applicability. Commenters also asked that the final rule include clarifications on how state plans should address differences in RGGI's inclusion in the trading program versus exemption of new sources under the section 111 framew ork. Commenters expressed concerns that exempting new units from compliance under RGGI would create electricity market distortions that would become increasingly problematic as CO2 allowance20 prices rise; a new unit with a higher emissions rate may be chose n for economic dispatch over an older unit simply because the new unit would not be required to purchase CO2 allowances under the section 111 applicability framework. Commenters recommended that the final rule should specifically permit states to manage co mpliance for both new and existing units under a single emissions limitation program to avoid unintended incentives, while retaining discretion as to whether new units would be included in a state plan.

Commenters, transmission system operators serving th e RGGI states, requested that the final guideline address inconsistencies between proposed applicability under the federal guideline and the existing applicability provisions under RGGI because RGGI applies to all generators larger than 25 MW. Commenters b elieved these clarifications are needed in order for states to craft their section 111(d) plans. Commenters also stated that the treatment of new sources under RGGI is different than the proposed treatment of new sources under the section 111(d) proposal, and commenters were concerned that exempting new sources from section 111(d) plans will create electricity market distortions that would become increasingly problematic as the price of CO2 allowances rise because a new unit with a higher emissions rate may be chosen for economic dispatch over an older unit simply because the unit would not be required to purchase CO2 allowances. Commenters believed that the final federal guideline rule should allow states the option to either manage compliance for both new and existing units under a single trading program or under separate programs.

Commenters requested that the EPA consider inclusion of provisions in the final rule that should allow for a smoother translation of RGGI to a State Implementation Plan and a mor e aggressive climate pollution reduction target for New York. Commenters stated that Clean Power Plan only applies to existing power plants. In contrast, commenters noted that the carbon cap established through RGGI applies to all fossil

- fuel fired generat ors in the region, both existing and those yet to be constructed. Commenters suggested that the Clean Power Plan should be adjusted to make clear for states proposing to utilize a mass

- based system that system may allow for the inclusion of newly construct ed and repowered facilities.

Comment 3 : Base load fossil fuel heat input criterion and base load generator capacity criterion

. Response 3: See section IV.A of the 111(b) NSPS preamble for a discussion of the broad applicability criteria for new, modified and reconstructed sources (steam generating units). See section IX.A.3 of the NSPS preamble for a discussion of the broad applicability criteria for new, modified and reconstructed sources (combustion turbines) . See section IV.D of the final rule preamble of the CPP for the EPA’s response on the broad applicability

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

Commenters supported the proposed applicability of 250 MMBtu per hour fossil fuel heat input because this threshol d is identical to the applicability threshold for new, modified and reconstructed electric utility steam generating unit, as defined in 40 CFR 60.4Da. Commenters interpreted the proposed 73 MW applicability threshold as an electrical output threshold (rath er than a heat input threshold expressed in millions of Joules per second) and commenters21 supported establishing the applicability threshold so that the final rule only applies to units with a net rated capacity greater than 73 MW.

Commenters stated that f our 25 MW coal units, Hamilton (Units 7 and 8) and Orrville (Units 10 and 11), were improperly included in calculation of the State of Ohio's section 111(d) goal because these units do not have the physical ability to operate non

- stop at full nameplate cap acity for an entire year.

Commenters requested that the final rule clarify the difference between the 73 MW baseload rating applicability threshold for affected units in the regulatory text and the 25 MW nameplate capacity referenced in the Goal Computati on TSD at 27, n.1, 30.

Commenters , project based agenc ies that support the supply, transmission, and delivery of electricity to small towns, w ere concerned about the effect of the proposed rule on small power plants, economic growth, plant closures, and lack of credit for energy efficiency and renewable energy projects completed prior to the baseline year. Commenters stated that the final rule shou ld make clear that states can and ought to subcategorize effected EGU sources to address small municipal systems and small unit concerns. Commenters requested that the final rule set the affected EGU threshold at greater than 73 MW generating capacity and not 250 MMBtu/hr of heat input capacity. Commenters requested that the final rule include less than 10 MW existing hydro in goal calculations.

Commenters , community owned, not

- for

- profit utilit ies with two coal/petroleum coke/biomass

fired units and two na tural gas

- fired units

, requested that all EGUs under 100 MW capacity be exempted from the final federal guideline.

Commenters generally supported including operating criteria for determining whether the proposed Subpart KKKK standards would apply to new st ationary combustion turbines. Commenters remarked that operating criteria would help to insure that turbines that are used only infrequently or in emergencies, and therefore would have relatively minimal emissions, are not subject to the standards.

Commen t 4 : Electricity sales, percentage and total annual thresholds

.
Response 4: The final applicability criteria are not retrospective. See sections IX.A of the final rule preamble of the NSPS rulemaking for the EPA’s response to this comment.

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

Commenters , state air quality permitting authorit ies , opposed omission of the criteria for retrospective, actual electrical sales in the regulatory text for the proposed section 111(d) stand ard because omission of these criteria is inconsistent with the preamble language describing applicability for existing sources at 79 FR 34854 and also inconsistent with the proposed rule for new sources at 79 FR 1511. Commenters stated that this inconsist ency was even more apparent because the proposed applicability criteria for existing combustion turbines at 79 FR 3495422 continues to include the sales criteria proposed for new sources. Commenter s stated that the discrepancy would impact units in the state of Ohio and provided Hamilton Unit 9, ORIS 2917 as an example of an EGU that would be subject to the 111(d) rule as proposed but that would be excluded from the proposed section 111(d) rule if the sales criteria proposed for new sources was also included in existing source applicability criteria.

Commenters stated that the final rule should include a clearly worded exemption for steam units that are used for peaking cycles. Commenters stated that the preamble to the proposal included language that indicated peaking steam units would be exempt from 111(d) emissions standards, however commenters believed that the language in the proposed rule text was not consistent with the stated inten t (relevant to exemption of small steam units with very low capacity factors), and
commenters provided recommended revisions to the proposed regulatory text to make the regulatory text consistent with the intent stated by the Agency in the preamble at 79 F R 34854.

Commenters stated that there were inconsistencies between applicability criteria described in the preamble compared to the proposed regulatory text related to the 219,000 MWh sales threshold (preamble at 79 FR 34854 vs. regulatory text at 79 FR 34 954) because the preamble phrase, "was constructed for the purpose of supplying one

- third or more of its potential electric output and more than 219,000 MWh net

- electric output to a utility distribution system on an annual basis[,]" is inconsistent with th e regulatory text phrase, "has the potential to generate and supply at least 219,000 MWh per year[.]" Commenters noted that there are several units in Iowa there were identified as "likely affected units" in the proposal; however, these units have never s old more than 219,000 MWh in a calendar year and commenters cited two examples (Streeter Station Unit 7 and Muscatine Unit 7); commenters were concerned that these inconsistent descriptions of the proposed applicability criteria could adversely affect the goal calculation for Iowa. Commenters requested that the final rule clarify these applicability criteria so that states can easily determine which units are affected and which are not, and commenters specifically requested that the EPA work with IDNR when the applicability criteria are more clearly defined so that EPA's list of affected sources is accurately reflected when the state goal is calculated for the final rule.

Commenters stated that the EPA should clarify the actual sales criteria for affected EGUs because the proposed text in section 60.5795 (b ) ( l) does not include the "and supplies" language included in (b ) ( 2). Commenters stated that including "and supplies" would be consistent with EPA's intent to include an actual sales threshold in the "affected EGU" criteria for existing steam boilers.

Commenters supported setting a MWh limit for an affected unit, as discussed at page 34854 of the proposal if the final guidelines include an exemption for smaller coal units (<100 MW capacity) because these small units provide great value in meeting summer peak loads while the US transforms to an increased renewable energy portfolio and because these units help address reliability i ss ues, and commenters believed that these units will naturally retire over the next several decades as they reach the end of their useful lives and as additional technologies becomes available to address the reliability gaps between renewables and the curr ent energy demand.

Commenters recommended that the final rule should define a " small utility" using the same definition set forth at 16 USC 824(f): a rural cooperative that sells less than 4,000,000 megawatt hours of electricity per year.23 Commenters oppose d the proposed deletion of the net sales criterion because without this criterion, the 111(d) standard will apply to limited

- use oil

- fired units. Commenters stated that the final rule should create an exemption for limited

- use oil

- fired units similar to th e MATS rule's eight percent capacity factor exemption because these units only operate during emergency situations and are critical to grid stability. Commenters believe d a 111(d) exemption similar to the MATS exemption is reasonable and appropriate becaus e these units do not run frequently, and the MATS exemption recognized that these units would be retired instead of retrofitted with expensive control technologies. Similarly, commenters stated it is reasonable and appropriate to exempt these limited

- use o il

- fired units from section 111 regulations because there is no control technology retrofit that would address CO2 emissions from these units and heat rate improvements would prove ineffective given the limited operations of these units. Commenters
state d that it would be unworkable for states to attempt to address emissions from these units since the proposed section 111(d) building blocks do not have any impact on these units: heat rate improvements at coal units will not affect oil

- fired units; increased use of NGCC units will not displace generation from emergency

- use units; similarly increased renewables will not displace generation from emergency

- use units because they are not competing to serve the same load; finally, end

- use efficiency will not reduc e generation from these emergency

- use units because they only run during periods of customer demand that are immune to efficiency measures like after hurricanes or during an unexpected cold snaps. Commenters concluded that the proposed BSER for existing un its under section 111(d) is not the best system of emission reduction that has been adequately demonstrated for limited

- use oil

- fired units. Commenters also stated that it is inappropriate to apply the standard to limited

- use oil

- fired units because one or more of these units may not have been required by the system operator in 2012 when the baseline for each state was established.

Commenters stated, the EPA's proposed changes to the applicability requirements for subpart Da units should not subject limited

- use oil

- based units to regulation under CAA section 111(d).

Commenters stated, reliability

- critical, limited

- use oil

- based units should not be subject to numeric standards under CAA section 111(b) or (d).

Commenters opposed inclusion of 25 MW units in the proposed rule and goal setting calculations proposed for the State of Ohio because it is not feasible for these units to run 8,760 hours per year as implied in the EPA's assumption that the existing source standard will apply to these peaking units; comme nters disagreed with the EPA's contention that the 25 MW net sales criterion and the 219,000 MWh sales criterion are functionally the same.

Commenters stated that the proposed inclusion of units with 25 MW nameplate capacities is incorrect regardless of ho w the final rule amends the definition of affected source because the proposal inappropriately included units that are 25 MW nameplate capacity in the goal calculation for the State of Ohio. Commenters stated that it is not feasible for a 25 MW unit to
pr oduce 219,000 MWh per year because no unit has the physical ability to operate non

- stop at full nameplate capacity for an entire year without outages for routine maintenance. Specifically,
commenters stated that Hamilton Units 7 and 8 have operated at an a verage load factor of under 30 percent during the past two years, and the Orrville Units 10 and 11 have operated at an average load factor of under 50 percent during the past two years; the final rule should remove Hamilton Units 7 and 8 and Orrville Units 10 and 11 from Appendix 7 and recalculate Ohio's24 baseline and goal computation without the inclusion of these units. Similarly, commenters stated that Hamilton Unit 9, a 50.6 MW nameplate capacity unit, should be excluded from Ohio's baseline because has not sold more than 219,000 MWh in any year since and including USEPA's baseline year.

Commenters , state air quality permitting authorit ies , stated that the final guideline should not rely on an assumption that increased utilization could be exercised at non

- base load combined cycle units because North Carolina has two small NGCC facilities that do not operate as base load assets: one operate s as a peaking unit with a capacity factor less than 5 percent, and the other was originally designed as a CHP plant and operates with a capacity factor of less than 15 percent. Commenters stated that these types of facilities may not be able to sustain an annual operating load of 70 percent , and commenters requested that EPA modify the proposed guideline to exclude specific NGCC plants that operate below a specified threshold such as a 15 percent capacity factor on an annual or monthly basis.

Comment 5: G ross vs. net for determining electricity generation applicability.

Response 5: Net electric sales is appropriate for applicability purpose because it is a better measure than gross output of if the unit meets the general applicability size criterion. See s ection III.F of the NSPS preamble for a discussion of the use of gross versus net output for determining applicability. See section VI.C of the CPP preamble for this rulemaking for a discussion of the use of gross versus net output for determining applicab ility.

The following are summaries of the specific public comments under this comment :
Commenters supported using gross MWh criteria for determining applicability of the standard to stationary combustion turbines because gross MWh applicability criteria places the entire focus on the combustion turbine, not on sales to the grid and not on station service energy that may or may not be directly relevant to the combustion turbine; because gross MWh applicability criteria can utilize the same measurement loca tion used for compliance as proposed at section 60.4373(d); because gross MWh applicability criteria appear to match the intent of the example in the proposed " potential electric output " definition, which refers to a "35% efficient stationary combustion tu rbine" (the efficiency of the turbine itself, not efficiency based on sales to the electric grid).

Comment 6 : Support for and oppos ition to applicability to simple cycle turbines

Response 6: See section s IX.A and B of the final preamble for the NSPS rule making for the EPA’s response to this comment. Also, s ee section IV.D of the final rule preamble of the CPP for the EPA’s response to this comment.

The following are summaries of the specific public comments under this comment :25 Commenters stated that simple cycle units should be included in the regulation because there could be over utilization of these units (with exempt emissions) to provide generation without the associated emissions against the states' cap. Commenter s recomme nded that simple cycle units be included under the section 111 regulations to ensure all emissions from the power sector are managed for reductions.

Commenters stated that section 111 prohibits promulgation of standards that are based on assumptions abou t the future deployment of renewable energy or energy storage or increased demand response that could substitute for simple cycle capacity.

Commenters stated that simple

- cycle CTs should not be subject to standards that do not recognize the range of servi ces these units provide to the grid and because it is not technologically feasible for simple cycle units to continue to provide these services while achieving efficiencies equivalent to combined cycle units. Commenters stated that the energy supply protoc ols that ensure grid stability require that units held in the ready

- mode as "spinning and non

- spinning reserves" must be available within 10 minutes of dispatch and stated that NGCC units cannot satisfy this requirement and described a broad range of syste m operating scenarios that currently rely on the unique capabilities of simple cycle units including support for renewables. Commenters stated that renewables are an intermittent resource and that the only resources that can be reliably dispatched quickly enough to compensate for significant swings are simple

- cycle CTs and hydro. Commenters concluded that if EPA's goal is to foster the development of renewable energy, imposing strict limits on the main backup generating source (simple cycle CTs) may be coun terproductive.

Commenters stated that EPA proposes to include as an affected source existing NGSC units operating at a 33% or greater capacity factor and that are constructed for the purpose of supplying more than 219,000 MWh nonelectrical output to the g rid. Commenters cited reasons they set in their comments to EPA's proposed New and Modified Unit NSPS, and herein objecting to this inclusion of NGSC units as affected sources.

Commenters stated and concurred that EPA should exclude simple cycle turbines both from the category of affected EGUs and from EPA's emission reduction goal calculations (99 While EPA asserts that it has excluded from its goal computations any simple cycle turbines that failed to qualify as an affected EGU, at least some simple cycl e turbines do satisfy the applicability criteria and are included in the proposed rule. See 79 Fed. Reg. at 34,895 n.260) as it proposed to do in the initial April 2012 proposal for newly constructed fossil fuel

- fired EGUs. See 77 Fed. Reg. 22,392. Comment ers believed that treating simple cycle turbines as affected EGUs in the same manner as NGCC facilities is inconsistent with their role in supplying power, will needlessly subject owners and operators of simple cycle turbines to an unprecedented post hoc

a pplicability test, and will reduce the flexibility that States will need to cope with the dramatic increases in renewable power generation that will be required to meet EPA's emission reduction targets. Alternatively, commenters stated, if EPA is determine d to regulate CO2 emissions from existing simple cycle turbines, commenters requested that EPA adjust the emissions guidelines or emission reduction targets to reflect the emissions limits that can be achieved by existing simple cycle turbines, now and und er projected future conditions where increased renewable generation may require them to increase capacity.26 Commenters explained that simple cycle turbines play a fundamentally different role in energy generation than NGCC turbines. Commenters described how simple cycle turbines play a critical and unique role in providing peaking power and assuring grid reliabi lity, describing how those simple cycle turbines can cold start quickly, easily scale through loads, and start and stop several times per day. Commenters said this flexibility allows them to fill the unique role of providing
gap

- filling auxiliary power at times of high demand or when the grid is otherwise under stress. 79 Fed. Reg. at 34,968 ("The power output from these simple cycle combustion turbines can be easily ramped up and down making them ideal for "peaking" operations."). Commenters believed that no other form of power generation is capable of filling this role.

Commenters continues, stating that combined cycle turbines are designed for baseload or intermediate load power, meaning that they are very efficient and have a high utilization rate, and in contrast, simple cycle turbines provide peaking power, meaning that their hours of operation are unpredictable, and they rarely operate at full load, the most efficient operating mode. Commenters said the larger

- and increasing

- role that renewable po wer sources play requires significant support from simple cycle turbines, which can start

- up quickly to compensate for highly variable and often intermittent generation from solar and wind facilities. Commenters stated that these renewable energy facilitie s are subject to several factors beyond their control that impact their reliability, including, but not limited to fluctuating wind speeds, cloud cover, and even the approach of birds. Commenters said, as renewable energy takes on a larger share of power g eneration, the need for reliable and flexible simple cycle turbine operations will only increase. Commenters noted, indeed, the increased need for peaking power from simple cycle turbines may well be driven by this rulemaking, given EPA's focus on increase d renewable energy generation in Building Block 3. See 79 Fed. Reg. 34,866

- 70. Commenters stated that in the January 2014 proposal for newly constructed fossil fuel

- fired EGUs, EPA reversed course and eliminated the previously proposed exemption for simple cycle turbines out of an unfounded fear that they will be used for baseload or intermediate load generation. 79 Fed. Reg. at 1459. Commenters noted that this proposal includes the same applicability criteria for stationary combustion turbines as the Janua ry 2014 proposal. See 79 Fed. Reg. at 34,954 (proposed 40 C.F.R. section 5795(b ) ( 2)). Commenters stated that simple cycle turbines are simply not interchangeable with combined cycle turbines in this way. Commenters said, as EPA recognizes, the use of simp le cycle turbines for baseload power would involve much higher fuel and maintenance costs to generate the same amount of electricity as more efficient combined cycle turbines. Commenters stated, although no owner or operator would intend to run a simple cy cle turbine for baseload power generation, as explained in more detail below, the changing nature of America's electricity supply and the role of simple cycle turbines in providing power on an as

- needed basis may require more flexibility in the future. In light of these important differences between simple cycle and combined cycle turbines, commenters believed that EPA should reinstate the exclusion for simple cycle turbines that it originally proposed in April 2012.

Alternatively, it is commenters’ positi on that if EPA must regulate simple cycle turbines, it must establish separate and achievable standards of performance, adjusting the applicable emissions guidelines and emission reduction targets to fully account for the projected future usage of these fa cilities as well as the emission reductions that they can achieve in practice. First, commenters explained that simple cycle turbines may operate more frequently as renewable power generation increases amid baseload plant retirements. Commenters elaborated that EPA relies on data27 showing that only a small portion of simple cycle turbines met the proposed applicability criteria. See 79 Fed. Reg. at 34,895 n.260; see also 79 Fed. Reg. at 34,797 (asserting that only 0.2% of simple cycle turbines sold more than one

- third of their potential electric output to the grid over a three

- year averaging period). Commenters said, however, the data on which EPA relies dates back to 2000, 79 Fed. Reg. at 34,797, and does not account for the recent increases in renewable
pow er generation and projections that this reliance on renewable power will increase due to the retirement of coal plants due to existing EPA regulations or the changes in coal

- fired electricity generating capacity and renewable energy generating capacity tha t would occur if this rule were finalized. Commenters stated, although EPA projects that existing NGCC facilities can increase generating capacity, new NGCC plants will be needed to replace at least some of the retired baseload power cause by this proposed rule, MATS, and other regulations. Commenters stated that there is often a significant time lapse between planning and the actual start

- up of operations due to burdensome and time

- consuming State and federal regulations and lawsuits to block projects. Com menters said this means that grid reliability will likely become more variable due to the increased use of renewable power and the expected time lag in replacing retired coal

- fired electricity generation. Thus, commenters said it is likely that simple cycl e turbines will have to be utilized more frequently than they have been in the past, both to provide grid stability until adequate non

- renewable replacement baseload generation is in place and to accommodate increased reliance on intermittent renewable ene rgy. Commenters noted, although most forecasts view future electricity demand as being relatively stable, the sources used to meet that demand are already beginning to change. Therefore, commenters posited, if EPA is intent on regulating existing simple cy cle turbines, then it should do so in a way that accounts for the changes in operation that EPA's rules are likely to cause. Commenters remarked that EPA must establish a separate subcategory for simple cycle turbines, and in the event that EPA withdraws t he proposed rule and proceeds instead with source category

- specific, inside the fence line emissions guidelines, it must establish a separate subcategory for existing simple cycle turbines. Commenters said simple cycle turbines which operate at lower, less efficient loads and cannot use a heat recovery steam generator

- cannot meet the same emission limits as NGCC turbines. Commenters noted EPA asserted in the January 2014 proposal that "advanced simple cycle combustion turbines have a base load rating of 1, 150 lbs CO2/MWh ..." 79 Fed. Reg. at 1485 (emphasis added) (citing EIA's Advanced Energy Outlook 2013 report). Thus, commenters stated, even under the most efficient operating conditions, the best performing simple cycle turbines cannot achieve the emissio ns limits that EPA has previously proposed for all stationary combustion turbines. Commenters also stated, under the variable and less efficient conditions associated with the generation of peaking power, emissions will necessarily be higher. Further,

comm enters said given their role in providing peaking power, there are no technological advances that would allow simple cycle turbines to achieve the same emissions levels as NGCC turbines operating at or near full capacity. Commenters noted that combined cyc le turbines increase efficiency and reduce emissions by capturing exhaust heat from the gas turbine and using it to produce additional electricity from a steam turbine. But when the heat recovery system and steam turbine are not operating, commenters noted that the NGCC facility essentially operates as a simple cycle turbine with a corresponding loss in efficiency. Thus, commenters stated, as long as simple cycle turbines are relied upon to provide peaking power, they cannot meet standards of performance de signed for NGCC facilities. Commenters said if EPA determines that it is necessary to regulate simple cycle turbines under Section 111(d), it must account for these fundamental differences between simple cycle and NGCC turbines.28 Commenters asserted that Se ction 111 authorizes EPA to "distinguish among classes, types, and sizes within categories of new sources" when establishing standards of performance. 42 U.S.C. 7411(b ) ( 2). Commenters said Section 111(d) gives EPA and the States further authority to base an existing source's standard of performance on the source's remaining useful life and other relevant factors. 42 U.S.C. section 7411(d ) ( 1 ) ( B). Commenters stated, if simple cycle turbines are included as affected EGUs, EPA and the States could use this provision to establish different emissions guidelines and standards of performance for simple cycle turbines that reflect both the emission control technologies available to them and efficiency challenges associated with providing peaking power. Commenters said such an approach is fully consistent with Section 111(d) and would allow EPA to fully incorporate the different roles played by simple cycle and combined cycle turbines and the different emission reductions that can be achieved by each.

Commenters st ated that EPA should explicitly exclude simple cycle combustion turbines ("CTs") from regulation under the CPP to avoid confusion regarding the rule's reach, explaining that to be exempted from the Proposed Rule's affected source definition, a CT would hav e to be constructed for the purpose of supplying, and supply, less than one

- third of its potential electric output to the gird, and most CTs are not constructed to provide more than one

- third of their potential output to the grid because a NGCC unit is mor e economic than a CT unit expected to operate at or above a 33 percent capacity factor. Thus, commenters concluded, very few, if any, CTs should qualify as an "affected unit" under the Proposed Rule, and an explicit exemption or exclusion of CTs from the d efinition of affected sources would provide clarity regarding EPA's intent. Commenters added that such a clarification would avoid the confusing determinations of whether a CT was constructed for the purpose of supplying one

- third or more of its potential electric output to the grid and whether a CT could become an affected source due to increased utilization necessary to ensure grid integrity. Commenters continued, stating that explicitly exempting CTs is prudent because they are critical to the safe and r eliable operation of the electricity transmission grid. Commenters said their ability to come on

- line and ramp up to full energy production in ten minutes or less is often relied upon to balance out the variability in RE generation and to replace power if an intermediate or base load power plant trips off

- line. Commenters stated, while CTs historically have operated at low capacity factors, the generation paradigm shift the Proposed Rule would precipitate may change CT operations and capacity factors, espec ially in the potentially tumultuous early years of the CPP's implementation. Commenters stated, for continued safe and reliable electric service, it is imperative that EPA allow utilities and regional transmission operators to run CTs unfettered by the Pro posed Rule's provisions. Commenters added that should EPA decline to explicitly exempt CTs, clarification in a number of areas is necessary, including clarifying 1) how lower utilization CTs can demonstrate that they were not constructed to supply one

- thir d or more of their potential electric output and more than 219,000 MWh net

- electrical output to the grid; 2) whether a source that was not constructed to supply one

- third or more of its potential electricity output and more than 219,000 MWh net

- electrical output to the grid could become an affected source by subsequently supplying power to the grid in excess of these thresholds; 3) what constitutes an "affected source" with regard to several other source types; 4) the 73 MW base load rating threshold for af

fected units given its Goal Computation TSD references a 25 MW nameplate capacity threshold; and 5) clarify its treatment of under

- construction high utilization CTs, OG steam, and coal, noting these units could qualify as affected sources, but the Propose d Rule does not appear to include them in states' baselines.29 Commenters stated that EPA should explicitly exclude simple cycle turbines as it initially proposed to do in the CAA section 111(b) rulemaking because 1. Simple cycle turbines serve a completely different function than NGCC facilities and should not be regulated as part of the same source category, and 2. Simple cycle turbines cannot achieve the same level of CO2 emissions as NGCC facilities. Commenters offered alternatively, EPA must appropriatel y account for the higher emissions associated with simple cycle turbines in setting state emissions rate targets and to do so, EPA must also account for the increased demand for peaking power that will accompany the projected growth in projects for intermi ttent renewable energy sources such as wind and solar.

Commenters stated, section 111(b) standards for combustion turbines must be achievable at the time of proposal.

Commenters stated, simple

- cycle CTs should not be subject to section 111(b) standards th at do not recognize the range of services these units provide to the grid.

Commenters stated, consistent with EPA's statutory obligations, standards for new simple

- cycle CTs units must be achievable when proposed.

Commenters responded to the proposal's req uest for comments on whether the proposed net sales criteria is sufficient to account for the projected increase in simple cycle capacity factors attributable to state and local mandates for increased reliance on renewable generation. Commenters stated tha t it is unlikely that any stakeholder would have credible, reliable data on the extent to which simple

- cycle CTs will be used to support renewable generation in the future because any such analysis would be dependent on numerous state

specific assumptions about RPS standards and the future demand for electricity, future wholesale electric prices and the costs of new simple

- cycle CTs, among others. Commenters , an air quality permitting authority in a state with a 20 percent renewable portfolio standard, indi cated that the 33 percent capacity factor would not be sufficient for the category of generators (i.e., flexible generators) used in California to support renewable generation. Commenters divided generating assets used in California into three categories b ased on annual capacity factors: baseload (60 to 100 percent capacity factors); flexible (33 to 60 percent capacity factors); and peaker (below 33 percent capacity factors). Commenters stated that the flexible category encompassed simple cycle operations ( either during bypass of the HRSG on combined cycle units or on combustion turbines that can only operate in the simple cycle mode). Commenters described flexible generators as an emergent type of generating capacity integral to the increasing development o f renewable resources in California. Commenters stated that flexible EGUs share three primary characteristics: dispatch ability /load

- following, fast

- starting, and fast

- ramping. Commenters stated that to integrate renewable resources, the electricity syste m must have sufficient dispatch able EGUs that are available to respond to varying system needs when called upon. Commenters stated that since renewable resources can come on the system or drop from the system very quickly, the electricity system needs lar ge amounts (proportional to the RPS) of dispatch able EGUs that have fast start capability, that can ramp (up or down) very quickly, and that can turn down to lower output to maintain grid stability for dynamic demand and supply conditions. Commenters stat ed that EGUs that can come on

- line in 10 minutes or less are increasingly needed and acknowledged that EGUs that operate in this ready

- state manner are less thermally30 efficient, but that in combination with the renewable resources that they support provide system

wide emissions reductions.

Commenters stated that the most important assumption in a prospective analysis of the impacts of RPS on simple cycle operations may relate to the potential impacts of EPA's final GHG standards for new and existing natur al gas

- based units because these standards will be significant factors influencing which flexible gas

- based units are used to support renewables generation. Commenters explained that if states choose to increase utilization of existing NGCC units to comply with the state

- specific emission rate goals proposed in the 111(d) guidelines, it is likely that simple

- cycle CTs (both new and existing) would be needed to facilitate renewables integration; conversely, if EPA's final standards for new units under sectio n 111(b) place significant operating limits on simple

- cycle CTs, then existing CTs and existing NGCCs could play a larger role in renewables integration.

Commenters stated that the final rule should clarify that the heat recovery steam generator (HRSG) is part of the combustion turbine.

Comment 7 : Year to year changes in applicability determinations for turbines , and “ once in, always in”.

Response 7 : The final applicability does not use retrospective criteria. Therefore, units will not be moving in and out of applicability based on operating parameters. See section IX.A of the final preamble for the NSPS rulemaking for the EPA’s response to this commen t

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

Commenters stated that revisions and clarifications are needed on applicability requirements for gas turbines and treatment of these units when operations fluctuate across applicability thresholds. Commenters stated that the final rule should increase the applicability threshold for simple cycle turbines from 33 percent to 40 percent to accommodate increased reliance on renewables because system operators must maintain suff icient fast

- ramping resources at partial load to balance rapid or unexpected dips in supply from intermittent renewable generation. Commenters also stated that simple cycle CTs can provide this fast

- ramping capability and also provide important ancillary s ervices, including frequency regulation (smoothing minute

- to

minute generation and load variability to maintain voltage and system frequency), and load following (smoothing hour

- to

- hour generation and load variability).

Commenters stated that final rule should include procedure by which states can update their plans to allow simple cycle natural gas units to be added or removed from the plan, as appropriate because the proposed rule does not specify whether an initially exempted gas

- fired unit that increa ses its capacity factor above the applicability threshold (for example, due to significant re

- dispatch or increased electricity demand) must be included in an updated state plan

. Commenters stated the proposal does not specify whether a unit that was initi ally included, but that later reduces its capacity factor below the threshold must continue to meet the requirements of a state plan. Commenters recommended that the final rule should require states31 to update state plans at least every three years to revis e the set of units included in the plan in accordance with the final threshold.

Commenters stated that the final rule should clarify the applicability provisions for combustion turbines because the proposed rule did not clearly and consistently specify whi ch fossil

- fired units were affected sources. Commenters stated that the final rule should clarify that a combustion turbine must meet all four of the applicability criteria listed in proposed section 60.5795(b ) ( 2), and commenters stated that the final rul e should clarify that a source that was constructed to supply less than one

- third of its potential electricity output and less than 219,000 MWh net

- electrical output per year does not become an affected source by subsequently supplying power to the grid in excess of these thresholds. Commenters also requested that the final rule clarify that a stationary combustion turbine that exceeds both supply thresholds for a given 3

- year rolling average period, thus becoming an affected EGU, would cease to be an affec ted EGU if, in a later 3

- year rolling average period, output falls below these thresholds. Commenters also requested that the final rule clarify how lower utilization combustion turbines can demonstrate that they were not constructed to supply one

- third or more of their potential electric output and more than 219,000 MWh net

- electrical output to the grid.

Commenters stated that the EPA should also clarify that when a unit is de

- rated such that the potential electric output falls under the 25MW net capacity or 219,000MWh net output threshold, the unit no longer qualifies as an affected EGU. Commenters stated that this clarification is necessary to understand the proper regulatory treatment of a specific EGU operated by them (Healy Unit I), and commenters pro vided relevant applicability facts about Healy Unit I and other units in the commenters ’ fleet.

C ommenter s asked, since the definition of " affected EGU " excludes most simple cycle combustion turbines (SCCT) due to the limited amount of time that they oper ate, Has the EPA considered whether a non

- affected unit could become an affected unit (i.e., by operating above the 33 percent capacity factor making it subject to the 111(d) plan applicability criteria)? Commenters also asked, if the unit were re

- designat ed as affected, would EPA recalculate the
state

- specific goal?

Commenters also requested that the final federal guidelines provide applicability clarifications for situations where successive annual or triennial average capacity factors fluctuate across th e proposed applicability thresholds. Commenters asked how goals and plans would be affected by such applicability fluctuations. Commenters also stated that the final guidelines must include a mechanism for adjustments to state goals upon changes to the set of sources that meet established applicability criteria. Commenters , the permitting authority for the State of Vermont, stated that currently Vermont has no affected sources under the proposed applicability criteria, but that it is possible that an EGU in the state could meet the proposed applicability criteria in the future, and commenters requested that the EPA provide clarification on this situation in the final federal guidelines.

Commenters asked whether the preamble statement that the unit must actua lly sell at least 219,000 MWh per year is a once

- in

- always

- in test or whether discrete averaging periods could yield differing applicability results for this criteria.32 Comment 8 : Allow requests for federally enforceable permit limit on annual generation.

Response 8: The applicability in this final rule includes an exemption for CHP units subject to a permit restriction limiting electric sales. This exemption does not apply to electric only EGUs. See section III.C and IV.A of the final preamble for the NSP S rulemaking for the EPA’s response to this comment for steam generating boilers and IGCC , and section IX.D of the final preamble for the NSPS rulemaking for the EPA’s response to this comment for CHP.

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

Commenters requested that the EPA clarify whether an operator of an EGU can request a federally enforceable permit limit on annual generation to avoid applicability under the section 111(d) rule.

2. 3 APPLICABILITY ISSUES RELATED TO EGUS THAT FIRE BIOMASS OR OTHER NON

- FOSSIL FUELS

This section addresses comments received on applicability issues related to EGUs that fire biomass or other non

- fossil fuels

.

Commenters have raised a number of issues related to this subsection w hich are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Support for or opposition to including biomass units.

Response 1: See section III.D of the NSPS preamble for a discussion of biomass and other non

fossil fu els. See section IV.D of the final rule preamble of the CPP for the EPA’s discussion of biomass and other non

- fossil fuels.

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

Commenters w ere specifically concerned about how the inconsistency between the proposed section 111(b) rule's applicability and the proposed section 111(d) rule's criteria would make biomass

- fired units subject to CO2 regulations; commenters d id not believe that sources that primarily fire biogenic fuels should be subject to CO2 regulations, and commenters d i d not believe that the proposal contained any justification for introducing the inconsistency in the 111(d) rule and making biomass

- fired units subject to the 111(d) rule.

Commenters opposed the proposed removal of the ten percent fossil fuel criterion because without this exemption the 111(d) standard will apply to biomass

- fired units. Commenters stated that the impact of the proposed deletions on biomass units could not be fully assessed because33 the proposal did not describe how biomass units would be treated in state plans, and commenters recommended that the Agency issue a separate rulemaking that addresses all biomass issues holistically. Commenters expressed sever al concerns about the treatment of biomass

- fired units in the proposed rule with respect to applicability.

Commenters noted that the preamble of the proposed rule stated that applicability criteria would be the same under 111(d) regulations as applicabili ty criteria for new fossil fuel

- fired units; however, the proposed 111(d) rule fails to include the ten percent fossil fuel criterion. Commenters understood that units not primarily firing fossil fuels would be primarily firing biomass, and commenters obje cted to the proposal's failure to provide an exemption to certain biomass

- fired units. Commenters urged the Agency to reconsider deleting the ten percent fossil fuel criterion, and to maintain consistency in applicability criteria across the various unit t ypes and amongst all three proposed rules. Commenters opposed elimination of the ten percent fossil fuel exemption (included under the section 111(b) proposal) from the section 111(d) guidelines because commenters d id not believe that the 111(d) proposal i ncluded any rationale for removal of this exemption. Commenters also stated that the description of this criteria for boilers and IGCC units in the preamble differed from the proposed regulatory text.

Commenters stated that CO2 emissions from facilities th at burn biomass should be excluded from requirements for section 111(d) plans because such an exclusion will promote use of biomass and because operators that only burn a small portion of fossil fuel to facilitate use of biomass should not be burdened by c ompliance programs for section 111(d) plans. Commenter s stated that the proposal offered no justification for treating biomass

- fired units the same fossil

fuel

- fired EGUs and commenters stated that the final section 111(d) rule not apply to units that get less than 10 percent of their heat input from fossil fuels, on a three

- year average, consistent with the proposed section 111(b) standard for new units. Commenters stated that the final rule should exempt EGUs that primarily combust biomass and the final r ule should clearly state that biomass is not a fossil fuel, and that replacing generation from an affected fossil fuel

- fired EGU with generation from a biomass fuel

- fired EGU is a valid compliance mechanism.

Commenters stated that it is not appropriate to apply the section 111(d) guideline to EGUs that primarily burn biomass, and commenters believed the final rule should include an explicit exemption for such units. Commenters suggested use of the current subpart Da definition for "resource recovery unit" as one way to implement an exemption for biomass

- fired units, and
commenters recommended that the final guideline include an exemption from the CO2 standards for resource recovery units. Commenters also supported use of a three

- year rolling average when de termining whether an EGU is "fossil fuel

- fired." Commenters stated that biogenic CO2 emissions are distinct from fossil fuel CO2 emissions because biomass fuels are part of the natural carbon cycle and the carbon emitted from biomass

- fired EGUs is rapidly cycled between atmospheric and terrestrial carbon pools. Commenters stated that there is no basis for EPA to eliminate the 10 percent fossil fuel threshold and expand these source categories to include biomass energy facilities in a final rule and that any such action would be premature because EPA is still in the process of developing a policy for how, if at all, it will account for biogenic CO2 emissions from stationary sources in regulations designed to reduce atmospheric GHG concentrations.34 Commenters s tated, the EPA's proposed changes to the applicability requirements for subpart Da units should not subject biomass units to regulation under CAA section 111(d).

Commenter stated, the EPA should conduct a separate rulemaking that addresses how biomass unit s will be regulated.

Commenters stated, all power plants should be included in the Rule. Commenter s stated biomass incineration is not controlled at the level that it should be. Commenter s stated in their community, they have the Gainesville Renewable Ener gy Center that operates by burning woody biomass. Commenters said the CO2 released from this plant is 3 times more per kilowatt hour produced than the adjacent Deerhaven coal unit. Commenters concluded, any national policy should require more control of emissions from biomass incineration.

Commenters stated, the calculations and considerations reflected in the Proposed Rule must take into account the carbon dioxide emissions of all stationary sources generating electricity, including the burning of bioma ss, which can result in significant carbon emissions.

Commenters requested clarification of the definition of affected units with regard to the treatment of biomass

- fired units.

Commenters asked "Can you please provide clarification specific to the definit ion of affected facility (new or existing)." Commenters quoted Federal Register / Vol. 79, No. 117 / Wednesday June 18, 2014 Proposed Rules under affected sources, on page 34854 section V.C, as stating "An affected EGU is any fossil fuel

- fired EGU that was in operation or had commenced construction as of January 8, 2014, and is therefore an existing source for purposes of CAA Section 111, and that in all other respects would meet the applicability criteria for coverage under the proposed GHG standards for n ew fossil fuel

- fired EGUs (79 FR 1430; January 8, 2014). Commenters noted that the January 8, 2014 proposed GHG standards for new EGUs generally define an affected EGU as any boiler, integrated gasification combined cycle (IGCC), or combustion turbine (in either simple cycle or combined cycle configuration) that (1) is capable of combusting at least 250 million Btu per hour; (2) combusts fossil fuel for more than 10 percent of its total annual heat input (stationary combustion turbines have an additional cr iteria that they combust over 90 percent natural gas); (3) sells the greater of 219,000 MWh per year and one

- third of its potential electrical output to a utility distribution system; and (4) was not in operation or under construction as of January 8, 2014 (the date the proposed GHG standards of performance for new EGUs were published in the Federal Register). Commenters said the minimum fossil fuel consumption condition applies over any consecutive three

- year period (or as long as the unit has been in oper ation, if less)." Commenters read Section 60.5795 and stated Section 60.5795(b)(1) does not make any reference to the 10% fossil fuel annual total BTU input found in the Federal Register / Vol. 79, No. 117 / Wednesday June 18, 2014 Proposed Rules under aff ected sources on page 34854. If paragraph (b ) ( 1) is correct, commenters said a significant dilemma will be imposed on EGUs whose primary fuel source is biomass. Commenters said, for example, if the facility uses an oily rag to initiate combustion of the b iomass in their furnace or warms the unit up using any type/amount of fossil fuel, the biomass EGU becomes subject to the rule. Commenters said this also presents a dilemma to a state as it will impair the state's ability to meet both their interim and fin al #CO2/MWh goals. Commenters stated many states that would35 rely on the energy generated from biomass as an attribute towards their CO2 reduction goals will now need to count the lbs/MWh of CO2 generated from biomass combustion against their goals.

Commen t 2 : Include entire electric power system.

Response 2 : The EPA disagrees, the Clean Air Act does not provide the authority to regulate the electric power system but applies to individual stationary sources of air pollutants.

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

Commenters believe d that the applicability criteria for all of the final section 111 rules must be structured congruently to include renewable generating assets like wind turbines and solar panels because t hese assets are the key to reducing GHG emissions per MWh across the grid as a whole. Commenters suggested adding these renewable technologies to the scope of applicability as

" unaffected EGUs ." This will enable state programs that allow fossil fuel units to buy CO2 credits from operators of renewable generating assets.

Commenters supported the proposed view that the " source " (for the purposes of establishing the scope of applicability) is the entire electric power system, not just individual plant sites, because the bulk power system is a fully integrated installation of interconnected machines that all simultaneously deliver the same product. Commenters believe d it would be inappropriate to limit applicability of a national CO2 per megawatt standard to on ly a portion of the interconnected installation that produces the CO2 and delivers the megawatts. Commenters cited a study by the Union of Concerned Scientists that indicated unrestricted national trading of renewable energy credits is a cost effective met hod for funding the expansion of renewable generating capacity if all generators that produce electricity for sale are included within the source category established under section 111.

Comment 3 : Biomass units affected under the proposed rule.

Response 3: EPA agrees and has recategorized Hibbard as included in the CPP Final Rule baseline consistent with comment.

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

Commenters stated that the biomass units at Minnesota Power's M L Hibbard station met the definition of affected units in 2012 and were mistakenly not included in Minnesota's affected units' inventory. Commenters said that the EPA incorrectly excluded the Hibbard un its from its evaluation of affected units because they burn wood as a "primary fuel." Commenters stated even if the EPA finalizes rule language (referenced above) providing an exemption for steam generating units combusting fossil fuel for less than 10 per cent of their heat input during any three consecutive years, the units at Hibbard would not meet such an exemption, and should therefore be included in Minnesota's inventory of affected units and considered in Minnesota's36 goal calculation. Commenters descr ibed the relevant units and said that they evaluated the characteristics of this facility in order to determine if the EGUs become subject to the rule under the proposed definition of an affected unit. Commenters said that even with a revised rule definiti on to allow up to 10 percent of fossil fuel for startup and combustion stabilization,
commenters believed that fossil fuel emissions and generation for these units should be included in Minnesota's inventory of affected units, as they are burning fossil fu el in excess of the EPA's apparent intended exemption.

2. 4 APPLICABILITY ISSUES RELATED TO COMBINED HEAT AND POWER (CHP)

This section addresses comments received on applicability issues related to combined heat and power (CHP) units

.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Support for and opposition to inclusion of CHP and industrial CHP.

Response 1: As described See Sectio n III.D.2 of the 111(b) final rule, the industrial CHP exemption has been significantly expanded and is based permit restrictions limiting the amount of electricity that can be sold. The final exemption is based on considering both the primary purpose and the environmental benefit of the unit. Therefore, the allowable sales is based on the design efficiency of the CHP unit. Specifically, the industrial CHP exemption is based on permit limiting annual electric sales to the unit’s design efficiency multiplied by its potential electric output or 219,000 MWh, whichever is greater. This limits applicability to CHP units that sell a significant percentages of the potential electric output. See section III.F.2 of the 111(b) final rule for a discussion of thermal o utput crediting. See section IV.D of the final rule preamble of the CPP for the EPA’s response to this comment.
The following are summaries of the specific pub lic comments under this comment:

Commenters were concerned about the impact on combined heat an d power facilities. Commenters stated the 111(b) rule needs to be modified to avoid bringing industrial combined heat and power facilities into that rule, and this 111(d) rulemaking needs to reflect that as well.

Commenters stated that in AF& PA and AWC comments on the January 8, 2014 proposed NSPS for new EGUs and the June 18, 2014 proposed NSPS for modified and reconstructed EGUs, AF&PA and AWC explained the strong policy justifications for exempting industrial CHP units from the NSPS and fro m Section 111(d) guidelines.

Commenters stated that CHP units are subject to numerous federal and state environmental regulations that would provide a check against unconstrained on

- site emissions, including37 regulation of conventional pollutants under sec tion 111 of the Clean Air Act and regulation of CO2 under the Prevention of Significant Deterioration ("PSD") program. Commenters stated that moreover, EPA retains authority to directly regulate industrial boilers and other categories of existing sources o f CO2 emissions under section 111 sometime in the future if EPA determines that such emissions contribute to air pollution that endangers public health and welfare. Commenters stated that regulating CO2 emissions from industrial and institutional units in the context of a rule addressing utility EGUs would create significant complication and uncertainty if and when EPA issues rules specifically for CO2 emissions from those industrial and institutional units.

Commenters said that the most important way that the EPA can recognize the benefit of efficient CHP is to ensure that the applicability criteria for what is an "affected EGU" under the rule do not inadvertently sweep in industrial facilities that utilize CHP or WHP technology. Commenters agreed that the EPA should provide clear guidance to the states that compliance should not impose regulations on CHP/WHP facilities. Commenters explained that while excess electricity may be supplied to the grid, industrial CHP units are designed for the purpose of produc ing useful thermal and electric energy for the facility itself and the associated thermal host. Because they are not intended to provide a majority of their energy output to the public power grid, commenters stated that they should not be regulated under t his rule as commercial EGUs. Commenters added that the EPA should send a clear message to states that because compliance is measured with regard to the emission performance of affected EGUs, states should not force emission reductions from industrial CHP f acilities that are not the kind of electricity generating units that are the subject of this rulemaking.

Commenters stated that strong policy justifications exist to exempt industrial CHP units from the NSPS and Section 111(d) guidelines.

Commenters sugges ted that the EPA's role should be to help Maine and other states foster greater use of CHP technology . If requirements in a state's rules do end up being applied as part of the state's SIP to their units, commenters stated that their CHP units should be al lowed to use alternative apportionment procedures as documented in a monitoring program meeting quality assurance requirements.

Commenter s stated that the intent of the rule is to target the power sector, not to bring in unintended industries. Commenters s tated that the final rule should be crafted to clearly and transparently articulate the sector targeted and should exempt industrial co

- generation. Commenters stated that combined heat and power facilities capture and utilize heat that would otherwise be w asted from the production of electricity and therefore they require less fuel than an equivalent separate heat and power systems to produce the same amount of electricity. Commenters stated that by using less fuel CHPs reduce emissions of air pollutants

a nd emit significantly less CO2 emissions than conventional boilers.

Commenter s stated that cogeneration units ("Cogens") should not be regulated as Electricity Generating Units under the CPP. Commenters stated Cogens are one of the least carbon intensive and most energy efficient ways to produce reliable electricity and useful heat, and to reduce electricity demand on the grid, with a consequent reduction in Greenhouse Gas emissions ("GHG")

.38 Commenter s stated that EPA must fully recognize the benefits of c ombined heat and power in reducing GHG emissions in the energy sector. Commenters stated that combined heat and power facilities capture and utilize heat that would otherwise be wasted from the production of electricity; therefore they require less fuel th an equivalent separate heat and power systems to produce the same amount of electricity and by using less fuel, CHPs reduce emissions of air pollutants and emit significantly less CO2 emissions than conventional boilers.

Commenters stated that the 111(b) r ule needs to be finalized to avoid including industrial combined heat and power facilities at affected EGUs under that rule and this 111(d) rulemaking needs to reflect that as well.

Commenters requested that the EPA exempt combined heat and power (CHP) plants from applicability under the final rule and also requested that the final rule include the option for CHP plants to voluntarily opt into state compliance programs because these h igh

- efficiency technologies are consistent with the Administrator's objectives under the proposed rule and
commenters believed this policy will encourage future CHP projects. Commenters believed that an exclusion will reflect that industrial CHP units are fundamentally different from the fossil fuel

- fired EGUs subject of this rulemaking because their primary purpose is not to provide electricity to the grid, and because these units are typically customized to suit the needs of the industrial host. Commente rs stated that these variations among industrial CHP units make them particularly unsuitable for uniform nation

- wide BSER analyses and makes calculation of thermal energy equivalence (conversion to kWh) impractical for reporting and enforcement purposes;

c ommenters provided recommended regulatory text under section 60.5795 that would exempt CHP units and an alternative strategy for exclusion based on specific language for CHP units.

Commenter s urged the EPA to utilize two principles for incorporating CHP into section 111 rules: first, the rules should not inadvertently create disincentives to build or expand CHP; second, the rules should encourage expanded deployment of CHP technologies. Commen ters recommended that CHP facilities should not be explicitly regulated under the final rule, and
commenters requested that the EPA ensure that CHP facilities are not inadvertently subject to regulation under the final rule.

Commenter s believed that exemp tion of CHP will promote expansion of CHP and supported complete exemption of CHP units. However, commenters acknowledged that the Agency may not provide such an exemption in the final rule, and commenters also offered a secondary alternative that the fina l rule should include an additional applicability criterion for determining which CHP units are affected EGUs; commenters stated that the final rule should include an exclusion for highly efficient CHP units (units achieving over 60 percent design system

e fficiency (HHV)) as an additional applicability criterion in order to encourage operators of existing fossil

- fuel

- fired EGUs to add CHP technologies.

Commenter s believed that the final federal guideline should explicitly state that installation of CHP tec hnologies on existing EGUs is a federally approvable compliance strategy for state plans, but commenters did not believe that affected EGUs that install CHP for compliance purposes should become exempt.39 Commenter s supported an explicit exemption under the section 111(d) rule for combined heat and power (CHP) sources. Commenters also stated that if the final applicability provisions do not include an explicit exemption, then applicability should not include self

- consumed power and applicability should only i nclude power that is sold to the grid. Commenters stated that special credit under the rule is warranted for CHP sources because these sources are already combining two processes into an inherently efficient approach. In absence of a complete CHP exemption in the final rule, commenters believed the criteria for determining which CHP sources should be excluded from applicability are those sources that provide at least a 50 percent thermal energy to a host facility. Commenter s also stated that the Agency shou ld consider a 20 percent threshold consistent with the definition of net energy output, where units with at least 20 percent of the total gross energy output consists of useful thermal output on a rolling 3 year basis would not be considered an affected so urce.
Commenters argued that EPA should evaluate whether individual CHP units are affected sources subject to the 111(d) guidelines. Commenters explained that in addition to considering CHP facilities apart from NGCC units, EPA must also thoroughly assess whether the CHP units identified in the proposed rule even meet the definition of an affected source that is subject to the 111(d) guidelines. Commenters stated that several examples have been identified in the building block two calculations of certain CH P units that clearly do not meet the definition of "affected sources" subject to the proposed rule. Commenters stated that EPA's criteria for determining affected sources in the proposed rule is summarized as follows: The EPA is proposing that, for the emi ssion guidelines, an affected EGU is any fossil fuel

- fired EGU that was in operation or had commenced construction as of January 8, 2014, and is therefore an "existing source" for purposes of CAA section 111, and that in all other respects would meet the a pplicability criteria for coverage under the proposed GHG standards for new fossil fuel

- fired EGUs. (79 FR 1430; January 8, 2014). Commenters stated that the proposed 111(b) standards for new sources revised the "applicability criteria" in several ways for determining whether a facility is an affected source. Commenters said most relevant to combined heat and power facilities are revisions to (1) the averaging period used to assess applicability with the net electric output criterion, and (2) the exclusion of electric output consumed by the host industrial facility. Specifically, commenters noted that revisions in the averaging period are related to the applicability criteria that affected sources are those EGUs that are "constructed for the purpose of suppl ying more than 219,000 MWh... Net

- electrical output to the grid." Commenters stated, to evaluate this requirement, EPA notes that "We are also proposing to revise the averaging period for electric sales from an annual basis to a three

- year rolling average f or stationary combustion turbines." (27179 Fed. Reg. 1446. January 8, 2014. Commenters said, with respect to the definition of net electric output, EPA proposed adding the clause "of the thermal host facility or facilities." Commenters said, in describing the rationale for that revision, EPA notes: [O]ne potential issue that we have identified is inequitable applicability of third

- party CHP developers compared to CHP facilities owned by the facility using the thermal output from the CHP facility. The curren t definition of net electric output...is "the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis. Owners/operators of a CHP facility under common ownership as an adjacent facility using the thermal output from the CHP (i.e. the thermal host) can subtract out power purchased by the adjacent facility on an annual basis when determining applicability. However, third

- party CHP developers would not be able to benefit from the "minus purchased power on a c alendar basis" provision in the definition of net electric output when determining applicability since the CHP facility and the thermal host(s) are not under common40 ownership. We are therefore proposing to....make applicability consistent for both facility

- owned CHP and third

- party owned CHP. Commenters remarked that the applicable definitions in the 111(b) proposals for new sources and for modified and reconstructed sources incorporate these revisions. However, commenters noted that the 111(d) proposal sel ectively includes only the language related to using a three

- year average. Commenters provided a comparison of the definitions in each proposal. Commenters asserted that the proposed 111(d) guidelines fail to mention EPA's concern of the "inequitable appli cability of third

- party CHP developers compared to CHP facilities owned by the facility using the thermal output from the CHP facility." Further, commenters said even though EPA included the "rolling 3 year basis" in the definition, nothing has been found in the docket to suggest that EPA actually performed an analysis of 3 year averages to determine the applicability of individual CHP facilities. Commenters said multiple CHP facilities have been identified that appear to have been erroneously included in t he building block two calculations that otherwise would have been excluded had EPA properly considered all of the definitional revisions proposed in the 111(b) rulemakings. Commenters said, for example, EPA appears to have incorrectly included the Portside Energy CHP unit as an existing NGCC facility when performing the building block two calculations for the state of Indiana. Commenters noted that a review of the facility in context with how it is designed, where its located, and how its electric and therm al output is employed strongly suggests that the facility provides nearly all of its electricity to the "host facility" (not to a "utility distribution system"), and thus is not an affected source. Commenters mentioned a recent article about the facility

n oted that: Portside Energy's plant on the grounds of the U.S. Steel Midwest mill... provides most of the steel mill's electricity needs and all of its steam and hot water needs Commenters remarked that a sufficient number of similar examples were identifie d through a cursory review of other cogeneration facilities to suggest that the inclusion of CHP units within the building block two calculations for NGCC units is fundamentally flawed. Commenters said the end result is (1) that the 111(d) proposal is ille gally applicable to a broader suite of sources than those that are subject to 111(b) new source standards; (2) EPA's building block two calculations inaccurately include cogeneration sources that are not affected sources subject to the proposed requirement s; and (3) the corresponding state goal calculations, reliability assessments, and cost

benefit analysis are derived from inaccurate data. Commenters posited that if EPA intended to identify affected sources under 111(d) "that in all other respects would m eet the applicability criteria for coverage under the proposed [111(b)] standards," then EPA must adopt and apply that criteria in determining the applicability of existing co

- generation units to the proposed rule. Further, commenters added, co

- generation units are principally designed and operated to supply heat and power to a specific industrial or commercial process. Commenters concluded, stating that EPA must evaluate whether co

- generation units could even be redispatched at higher capacity factors if s uch increased utilization would significantly impact or jeopardize the ability of units to achieve their primary objective of providing heat and power to a host process.

Commenters urged the EPA to ensure that CHP facilities are not inadvertently subject t o regulation under this rule as "affected Electricity Generating Units," particularly excluding highly efficient CHP units that provide greater than 65 percent overall efficiency.

Commenter s commented that the higher energy efficiency of CHP systems compar ed to separate heat and power systems (e.g., central power plant for electricity and onsite boiler for thermal needs) translates to fewer emissions associated with electricity produced from CHP systems, which leads to reduced emissions from EGUs when CHP s ystems are used onsite at industrial41 facilities. For this reason, commenters expressed support for considering industrial CHP systems as a potential approach to avoid affected EGU emissions and also supported considering CHP systems that lie outside of the industrial sector, for exactly the same reasons.

Commenter s stated that CHP systems should not be categorized as affected units under the proposed rule. Commenters explained that industrial CHP facilities are used primarily for manufacturing applications to produce on

- site electricity and thermal energy and are not intended to replicate the role of utility generators, but the applicability criteria for the proposed rule risks qualifying some industrial CHP units as affected entities that must be addressed in state plans. Commenters added that industrial CHP units further the intent of the proposed rule by providing efficient and less carbon

- intensive electricity and thermal energy and also provide industrial market participants with an effective way to hedg e electricity costs. Commenters stated that, to ensure that these facilities are not defined as affected units, and to remove potential disincentives for the use of industrial CHP, EPA should clarify that affected units do not include units that produce si gnificant amounts of thermal energy.

Commenter s requested that EPA clarify the status of industrial cogeneration units that use fossil and other fuels to generate retail electricity in the final rule's definition of affected EGU and modify the baseline acc ordingly. Commenters stated that EPA's proposed definition of affected EGU in the rule text, section 60.5795, is unclear on the treatment of industrial cogeneration operations that use coal and other fuels to produce electricity and process steam. Commenters stated that the rule text can be read to include an industrial cogeneration as an affected facility. Commenters stated EPA included one NGCC industrial cogeneration facility in Washington in its listing of affected EGUs used for calculating the state goal. Commenters stated t his unit has historically reported to CAMD as an affected plant for the Acid Rain Program. Conversely,
commenters stated that the preamble and the spreadsheet determining affected EGUs indicate that industrial cogeneration u nits are not included in the rule, regardless of how much fossil fuel is used (unless the combustion units are natural gas combustion turbines). Commenters stated that t his lack of clarity provides ambiguity for at least one Washington facility (a Weyerhae user facility located in Longview, Washington)

. Commenters stated that EPA's proposals under section 111(b) to amend subpart D and KKKK provide clarity on the status of these types of plants. Commenters stated that t he proposed language for an affected EGU under this 111(d) proposal is not c lear on the status of industrial cogeneration facilities that generate electricity for retail sale.

Commenters requested that EPA clarify the status of industrial cogeneration units that use fossil and other fuels to ge nerate electricity for sale in the final rule's definition of affected EGUs. Commenters also requested that if this type of facility is included as an affected EGU, that these plants be included as cogeneration units with the baseline fossil emissions used to establish the final emission standards.

Commenters stated that the EPA is unclear in how Combined Heat and Power (CHP) facilities are treated and asked why the EPA didn’t provide clarity. Commenters asked when is a CHP facility considered " covered ?" If this is determined by sales criteria, at what date is the determination made? Can this determination change? If so, under what criteria?42 Comment 2 : Thermal output credit for CHP.

Response 2 : This final rule includes 100 percent credit for useful therm al output. See section III.F of the NSPS preamble for the EPA’s response to this comment. See section VIII.K of the final rule preamble of the CPP for the EPA’s response to this comment

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

Comments regarding thermal Credit for Affected CHP Units

Commenters stated that EPA should give full credit for the thermal output of any CHP units EPA does regulate.

Commenters urged the EPA to count 100 percent of useful thermal output tow ard gross energy output. Commenter s requested that the final rule include a clarification that the rule does not apply to CHP facilities that primarily produce thermal energy.

Commenters disagreed with EPA's proposal to allow only partial credit for therma l energy from CHP and advocated for 100 percent credit. Commenters stated that 100 percent credit is allowed in NSPS subpart KKKK for stationary combustion turbines. Commenters stated that the proposed requirement that limits CHP eligibility to systems wi th 20 percent gross useful energy output will alleviate any concerns about sham CHP projects.

Commenters stated the EPA should allow facilities to include 100 percent of useful thermal output in calculating emission rates in order to be consistent with th e treatment of useful thermal output in EPA's NSPS for combustion turbines in subpart KKKK; See 40 CFR 60.4420 (2014) (defining gross useful output as " For combined heat and power units, the gross useful work performed is the gross electrical or mechanical output plus the useful thermal output (i.e., thermal energy delivered to a process). ”

In response to the request for comment on a range of two

- thirds to 100 percent credit for useful thermal output from cogeneration plants and combined heat and power plan ts, commenters recommended that EPA allow full credit for useful thermal output towards compliance with the rule. Commenters recommended that EPA provide a compliance methodology that allows up to 100 percent credit for useful thermal output from these fa cilities where it can be demonstrated. Commenters stated that several Wisconsin facilities, including West Campus and Whitewater NGCCs, provide useful thermal energy for heating/cooling or industrial processes. Commenters stated that such facilities should be provided the opportunity to demonstrate up to 100% use of the thermal energy.

Commenters contended that it would not be appropriate for EPA to specify best practices for measurement of useful thermal energy and quality assurance protocols, given the un certainty in the proposal regarding the amount of credit that should be provided for whatever useful thermal energy is measured. Commenters argued that, since EPA is soliciting comment on allowing credit for 75 percent of measured thermal output, two

- third s or up to 100 percent, any gains that may be achieved in imposing additional measurement or quality assurance protocols would be lost in the noise of the policy assumption used to justify the final percent credit allowance.43 Commenters applauded the EPA fo r acknowledging the emission reducing potential of putting thermal output to productive use when calculating the emission rate of an affected EGU. However, commenters stated that by only allowing states to count 75 percent of that useful output, the Clean Power Plan unnecessarily limits the incentive to add or expand CHP at existing EGUs. Instead, commenters recommended that the EPA should include 100 percent of useful thermal output when calculating affected EGU emission rates

.

Commenters recommended that 100 percent of the thermal output of affected EGUs should be credited under Section 111(d)

. Commenters stated that EPA has asked for comment on " a range of two

- thirds to 100 percent credit for useful thermal output in the final rule to better align incentives with avoided emissions ." Commenters stated that no rationale was provided for "discounting" thermal output relative to electric or mechanical output. Commenters stated that only accounting for a portion of thermal output undermines and distorts the true efficiency profile of a CHP system and as a result may encourage facilities to underuse thermal energy for

non

- electric generating uses even if such uses would be more efficient. Commenters stated that in practice, most CHP systems are designed fo r optimum efficiency based on the thermal requirements for the connected heating or cooling loads. Commenters stated that legitimate concerns regarding potential "sham" CHP projects can be fully addressed with appropriate monitoring and a minimum thermal o utput requirement.

Commenters stated that EPA should provide a full thermal credit for affected CHP units

. Commenters stated that CHP's chief benefit is that it can produce heat and electricity from a single fuel source. Commenters stated that the propose d rule would credit all of the electricity produced from a CHP system, but only 75 percent of the useful thermal output. Commenters noted that the EPA invited comment on " a range of two

- thirds to 100 percent credit for useful thermal output in the final ru le to better align incentives with avoided emissions ." Commenters stated that to fully account for the benefits of CHP's EE, the rule should credit 100 percent of an affected facility's productively used CHP thermal output.

Commenters stated that there is precedent supporting a 100

- percent thermal credit . For instance, commenters noted that the EPA has recognized 100 percent of useful thermal output in the New Source Performance Standard (NSPS) for Stationary Combustion Turbines, and that a 100

- percent cre dit has likewise been applied in several states. Notably, commenters stated that the Proposed Stationary Combustion Turbine Rule favorably cites Texas' permit

- by

- rule regulation, which gives facilities 100

- percent credit for s team generation thermal output

. Commenters stated that they understand that it may be appropriate to discount thermal output where there are concerns that the thermal energy is not being accurately measured or properly used, but stated that such concerns do not exist here. Commenters no ted that the proposed rule includes strict monitoring requirements for CHP systems and these requirements should alleviate any concerns about so

- called "sham" CHP projects.

Commenters stated that this matter has important implications for state compliance plans. While only a handful of existing CHP and WHP systems are large enough to be directly affected by the CPP, commenters stated that the proposed rule offers states the flexibility to credit emission reductions from smaller units in their state plans. Commenters noted that states will look to EPA's treatment of thermal output from affected units as a guide for the appropriate treatment of44 these systems in their compliance plans and underlying policies (e.g., portfolio standards). Absent proper considera tion of their thermal output, commenters asserted that states will underestimate the emissions benefits of CHP units.

Commenters stated that full credit should be given for CHP (heat and mechanical energy). Commenters noted that EPA invites comments on a r ange of two

- thirds to 100 percent credit for useful thermal output in the final rule (79 FR 34914). Commenters stated that the proposed rule would credit all of the electricity produced from a CHP system, but only 75 percent of the useful thermal output. C ommenters stated that Maine's RGGI program now allows 100 percent credit for thermal output.

For their units, commenters stated that the total gross energy output includes useful thermal output (steam), in addition to gross electric energy output. Comment ers suggested that full thermal output credit for affected CHP units should continue to be allowed through a compliance demonstration (as is currently the case in Maine's regulations implementing RGGI). Without full energy output credit, commenters stated that CHP units would have no economic incentive to implement further measures to improve energy efficiency.

Commenters stated that thermal output can be monitored, measured, and recorded under a continuous monitoring program consistent with the requirement s for monitoring electrical output. Commenters stated these non

- billing meters can be included in a quality assurance, quality control program to produce accurate and reliable data. Commenters stated that thermal output is real and measurable, and it shoul d not be discounted when included within an accounting framework for CO2.

In the case of EGUs or CHP units producing both electric energy output and useful thermal output, commenters stated that the apportionment procedure should include a thermal

- to

- elect ric energy conversion calculation (MMBtu steam/condensate to MW

- h or MW

- h electricity to MMBtus), and CO2 emissions should be allocated directly based on total output. For example, commenters noted that if electrical output is 60 percent of the unit's tota l output of useful energy, 60 percent of the emitted CO2 should be allocated to electrical generation.

Commenter s stated that the thermal energy (steam from process or heating) should also be acknowledged in the carbon rates applied to CHP units.

Comment ers stated that EPA must correct errors in its methodology for calculating useful thermal output from CHP units. Commenter s stated that the proposed rule would credit all of the electricity produced by CHP systems, but only 75 percent of their useful ther mal output. EPA invites comment on "a range of two

- thirds to 100 percent credit for useful thermal output in the final rule to better align incentives with avoided emissions." While commenters we re gratified to see this thermal credit in the proposed rule, they d id not believe that thermal output should be discounted. Rather, commenters stated to properly account for the benefits of energy efficiency, the rule should credit 100 percent of a facility 's useful thermal output.

Commenters continue d that the characteristic that makes CHP both clean and efficient is its ability to produce both useful thermal and electric output simultaneously. Commenters stated t he system's environmental benefits will only be recognized if both of these products are considered

,45 and EPA recognizes this. Commenters stated that i n a 2012 white paper on methods for calculating CO2 savings from a CHP system, EPA determined, "To calculate the fuel and CO2 emissions savings of a C HP system, both electric and thermal outputs of the CH P system must be accounted for" , and that for this reason, it is important to consider both thermal and electric output when determining an affected unit's emission rate. Commenters stated t he proposed rule represents a good first step, but stops short of fully crediting system benefits. Commenters stated

a 2005 EPA memo examining thermal credits explained that "giving between 75 to 100 percent thermal credit for thermal output from CHP units most accura tely accounts for the environmental benefits of CHP." In the context of that rule (which addressed criteria pollutants, not CO2), commenters stated EPA found that 75 percent was appropriate since it represented the average equivalent input

- based emissions for the regulated pollutants (NOx, S O 2 and PM) based on interpolating then current input

- based New Source Performance Standards for industrial boilers and utility boilers.

Commenter s stated that this rationale does not apply to this rule, which is regulati ng CO2. Further, commenters stated, unlike with criteria air pollutants, there are no National Ambient Air Quality Standards for CO2. Moreover, commenters stated the memo acknowledges that "one could also argue that 100 percent credit for thermal output i s also appropriate." Commenters stated t here is precedent supporting a 100

- percent thermal credit. For instance, commenters stated EPA has recognized 100 percent of thermal output in the NSPS for Stationary Combustion Turbines. Commenters stated a 100

- perc ent credit has likewise been applied in several states. (EPA 2013) Notably, commenters stated, the Proposed Stationary Combustion Turbine Rule favorably cited Texas' permit

- by

- rule regulation, which gives facilities 100

- percent credit for

s team generation thermal output.

Commenters stated they understand that it may be appropriate to discount thermal output where there are concerns that the thermal energy is not being accurately measured or properly used , and that s uch concerns do not exist here. Commenter s stated t he proposed rule includes strict monitoring requirements for CHP systems. Commenters stated t hese requirements should help alleviate any concerns about so

- called "sham" CHP projects. Commenters stated EPA also seeks comment on whether EGUs produc ing both electric energy output and useful thermal output should report both electric and useful thermal output. As explained above, commenters stated, these units should report both thermal and electric output , and that t o do otherwise would minimize thei r measured and verified emissions benefits. Commenters stated t his matter has important implications for state compliance plans. While only a handful of existing CHP systems are affected by the Carbon Guidelines

, commenters stated the proposed rule offers states the flexibility to credit emission reductions from unaffected units in their compliance plans. Commenters said s tates may look to EPA's treatment of thermal output from affected units as a guide for the appropriate treatment of these systems in their compliance plans and underlying policies (e.g., portfolio standards). Commenters stated a bsent proper consideration of their thermal output, states will underestimate the emissions benefits of CHP units potentially leading to inv estments in other technologies, which may be more costly or less efficient or reliable in the long run.

Commenter s also mentioned that EPA's treatment of thermal output also has important policy implications beyond climate regulation. Congress is currentl y exploring options for comprehensive tax reform. Commenters stated i n December 2013, the Senate Finance46 Committee released a draft energy tax reform proposal, which provided a "technology neutral tax credit" for all clean

- energy technologies that are 25 p ercent cleaner than the grid average. Commenters stated g iven their carbon benefits, WHP and CHP should readily meet this test

however, the proposal was limited to electrical output. Using this approach, commenters stated, CHP would not be eligible for fa vorable tax treatment. Commenters stated a s tax reform moves forward, Congress will look to EPA for guidance. Commenter s conclude d that, by crediting 100 percent of thermal output in the Carbon Guidelines, EPA sends a signal to Congress that it should do t he same. Commenters stated EPA recognizes the relevance of such policy considerations. Commenters stated t he proposed rule seeks comment on the appropriate thermal credit "to better align incentives with avoided emissions." as noted above, commenters stat ed the Administration has supported numerous policies to encourage greater CHP deployment. Commenters stated p roviding a full

- 100 percent

- thermal credit would place the Carbon Guidelines squarely in line with these broader deployment goals.

Commenter s stated that EPA has asked for comment on "a range of two

- thirds to 100 percent credit for useful thermal output in the final rule to better align incentives with avoided emissions." Commenters stated that no rationale was provided for "discounting" thermal output relative to electric or mechanical output. Commenters stated that only accounting for a portion of thermal output undermines and distorts the true efficiency profile of a CHP system and as a result may encourage facilities to underuse thermal energ y for non

- electric generating uses even if such uses would be more efficient and in practice, most CHP systems are designed for optimum efficiency based on the thermal requirements for the connected heating or cooling loads.

Commenters stated that a 2005 E PA memo, prepared during development of NSPS, explained that "giving between 75 to 100 percent thermal credit for thermal output from CHP units most accurately accounts for the environmental benefits of CHP." Commenters stated that in the context of that r ule (which addressed criteria pollutants, not CO2), EPA found that 75 percent was appropriate since it represented the average equivalent input

- based emissions for the regulated pollutants (NOx, SO2 and PM) based on interpolating then current input

- based N ew Source Performance Standards for industrial boilers and utility boilers. Commenters stated that this rationale does not apply to this rule, which is regulating CO2 and further, the memo acknowledges that "one could also argue that 100 percent credit for thermal output is also appropriate."

Commenters stated that EPA has recognized 100 percent of thermal output in the NSPS for Stationary Combustion Turbines. Commenters stated that a 100 percent credit has likewise been applied in a number of states inc lu ding California and Texas. Commenters stated that notably, the Proposed Stationary Combustion Turbine Rule favorably cited Texas' permit

- by

- rule regulation, which gives facilities 100 percent credit for steam generation thermal output. Commenters stated th at legitimate concerns regarding potential "sham" CHP projects can be fully addressed with appropriate monitoring and a minimum thermal output requirement. Commenters recommended that 100 percent of the thermal output of affected EGUs be credited under Sec tion 111(d).47 Comment 3 : Calculations involving useful thermal output.

Response 3 : This final rule states that useful thermal output be measured relative to SATP conditions, See section V.C of the final rule preamble of the CPP for the EPA’s response to this
comment.

The following are summaries of the specific public comments under this comment :
Commenters addressed calculations involving useful thermal output.

In comments to the Modified/Reconstructed Unit Proposed Rule, commenters made a number of

re commendations regarding the extent to which the EPA permits facilities to account for useful thermal output and regarding the technical calculation of useful thermal output. Commenters stated that these recommendations are equally applicable to this propos ed rule and should inform the EPA's definition of net energy output and useful thermal output in the final rule. Commenters included the following recommendations :

• Useful thermal output should be defined relative to International Standard Organization tem perature and pressure rather than Standard Ambient Temperature and Pressure in order to be consistent with all other CAA emission standards;

• Fuel drying should not be included in the definition of useful thermal output; and

• Thermal output for CHP units sho uld be calculated based on the energy in the thermal output rather than based on the energy content of condensate return.

Comment 4: Net electrical output and purchased power for CHP.

Response 4: This final rule states net electric sales are used for applicability purposes because that is a better indication of the intent of the unit than gross sales or generation. The intent of this final rule is to covers EGUs and not industrial units. See section III.F of the NSPS pre amble for the EPA’s response to this comment. See section VIII.K of the final rule preamble of the CPP for the EPA’s response to this comment

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

Commenter s opposed proposed chan ges to applicability criteria for CHP facilities under the 111(d) proposal related to subtraction of purchased power when determining net

- electrical output for applicability purposes.

Commenters stated that due to ambiguous language in the current Proposal , it may be possible for state programs to impose obligations on entities other than EGUs to meet their emission limits; however, in the preamble to the Proposal, EPA indicates that it intends the Section 111(d) state plans to address those types of EGUs t hat are currently subject to the 40 CFR Part 60 Subparts Da and KKKK; and, will be covered in the proposed NSPS for GHG emissions from new, modified, and reconstructed EGUs. Commenters continued, stating that due to this48 inconsistency, the applicability pr ovisions of the Proposal must be clarified to be consistent with CAA Section 111(d) and more importantly to reflect the past judgments EPA has made about the appropriate scope of facilities to be regulated as EGUs. Commenters explained that in the proposed NSPS for new EGUs and for modified and reconstructed EGUs, EPA addresses the simultaneous purchase and sale issue through the definition of "net

- electric sales," similar to how it is dealt with in the existing NSPS. Commenters said, however, the Proposal does not contain a similar clear recognition that net

- electric sales at a CHP unit for purposes of Section 111(d) applicability should be the net sales after subtracting out any purchases of electricity necessary to run the thermal host. Commenters asserte d that there is no legal or practical basis for EPA not to treat the "cogeneration exclusion" any differently. Commenters believed EPA should include, in the applicability provisions of the final Section 111(d) guidelines, language similar to that in the d efinition of "net

- electric sales" in the proposed NSPS for new EGUs. Commenters added that requiring state Section 111(d) plans to include cogeneration steam generating units (who provide less than one third of their net potential electric output and more than 219,000 MWH to the grid) is inconsistent with the thinking behind EPA's identification of Best System of Emissions Reduction (BSER). Commenters stated that EPA's system

- based approach that looks to entities beyond the regulated facilities is not consi stent with this past precedent, incompatible with the statutory provisions, and ultimately results in the regulation of a wide range of entities that are not existing sources subject to Section 111(d). Commenters closed, stating it essentially expands Sect ion 111(d) plans beyond the types of units subject to the applicable NSPS, which is not a difference that CAA Section 111(d) allows.

Comment 5 : Transmission Line

- Loss Credit for Affected Units.

Response 5: The final rule on ly covers CHP units exporting a significant portion of power. While it is not possible to calculate the exact savings we concluded that 5 percent is an appropriate approximation

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

Commenters advocated that EPA clarify that line loss credits are allowed for both affected and unaffected CHP units, and that the 5 percent level of credit proposed by EPA should be 6 percent or more to better reflect average national T&D losses reported by EIA.

Commenter s addressed line

- loss credit for affected units which should reflect actual system losses. Commenters stated t he proposed rule appears to include a five

- percent line

- loss credit for affected CHP systems. For CHP facilities, commenters stated, net energy outp ut is defined as "the net electric or mechanical output from the affected facility divided by 0.95, plus 75 percent of the useful thermal output."

Commenters stated that there is no explanation for why output is "divided by 0.95"; however, the Carbon Poll ution Guidelines for New Stationary Sources (111 (b )) explicitly provided a 5 percent "line loss credit" for CHP systems "to account for a five percent avoided energy loss in the transmission of electricity." Commenters stated c onversations with EPA staff confirm that this credit is likewise reflected in the instant proposal. Commenters commend ed EPA for49 including this credit in the rule, as avoided line losses are one of the key benefits of distributed energy generation. Commenters believe d , however, that the proposed credit is inadequate. Commenters stated that o n average, actual line losses from conventional generation are higher than 5 percent, and thus CHP projects that avoid such losses warrant a higher credit. Commenters stated t he technical support d ocuments accompanying the rule repeatedly refer to line losses of 7 percent or higher. For instance, commenters stated, as part of the BSER methodology for energy efficiency, EPA applies a transmission and distributi on loss factor of 7.51 percent. Commente rs stated i n the Technical Support Document for State Plan Considerations, EPA notes that national average line losses are 7 percent. Commenters stated t he inconsistency between the technical support documents and the rule itself is inappropriate. Moreover

, commenters stated line losses come at a significant economic cost

, contributing to nearly $26 billion in foregone revenue in 2010 alone. Commenters stated t hese losses are even greater during peak hours. Commenters stated that i n fact, a 2011 report by t he Regulatory Assistance Project finds that a grid segment or area with average line losses of 7 percent could have marginal line losses of 20 percent during peak load. Commenters stated s tudies at Carnegie Mellon University and the Massachusetts Institute of Technology have shown that one megawatt

- hour (MWh ) of local generation, like CHP, can displace up to 1.47 MWh of central generation in some cases. Commenters stated t hese numbers imply the CHP benefit should be well above 5 percent where such lines

- los s benefits exist. In the 111 (b) proposal, commenters stated EPA asserted that 5 percent "represents a reasonable average amount for the avoided transmission and distribution losses for CHP facilities."

Commenter s stated that, in fact, a line

- loss credit of 7 or 7.5 percent would be more "reasonable." Commenters stated that t o do so, net electric output should be divided by 0 .93. EPA should further clarify that the credit applies to both CHP and WHP. Commenters stated t he proposed rule also provides that t he apparent line

- loss credit would apply whenever the useful thermal output is at least 20 percent of the total output. Commenters suggest ed that the rule add an efficiency standard to be consistent with the definition of qualifying CHP projects in the tax code. Commenters stated t his will help counter any concerns that may exist about "sham" CHP projects. Lastly, commenters stated, the final rule should eliminate any ambiguity surrounding the line

- loss credit , and that a s written, this credit only applies to a subset of existing CHP systems that are directly affected by the rule. Commenters said s tates will consider EPA's approach, however, w hen determining how to account for output from CHP systems in their compliance plans. For this reason, commenters stated EPA should elaborate on CHP's transmission and distribution benefits and encourage states to apply a similar line

- loss credit when acco unting for CHP and WHP installations at unaffected units. Commenters stated t hese benefits are consistent with EPA's stated interest in enhancing electric reliability.

Notwithstanding their request for a CHP exemption under the 111(d) rule, commenters supp orted the proposal for modified and reconstructed units to apply a discount for avoided electricity losses through transmission and recommended that a discount of seven percent (based on EIA data) be incorporated into any final section 111(d) rule.

Comment ers stated that EPA should adjust the compliance calculations to ac count for 7 or 7.5 percent avoided transmis sion losses by the use of CHP.50 Commenters added that if CHP is not recognized as a voluntary compliance measure, then the EPA should adjust the co mpliance calculations to account for 7 to 7.5 percent avoided
transm ission losses by the use of CHP . Commenter s also stated that the EPA needs to ensure that the language of the CO2 Section 111(d) plan requirements for existing EGUs retains the current
pro visions that are designed to limit the application of EGU NSPS to CHP units.

Commenter s stated that if the final rule does not include the requested exemption for industrial CHP units, the final rule should adjust the compliance calculations to account for 7 percent avoided transmission losses by the use of CHP.

Commenters supported the EPA proposal to allow CHP units an increase in produced electrical output to account for avoided transmission and distribution line losses. But rather than adopt a national average line loss credit, commenters advocated for use of average line losses for the state in which the CHP unit is located. Commenters pointed out that EIA currently has state

- by

state line losses through 2012 (State Electricity Profiles, May 1, 2014). Commenters stated if EPA decides to adopt a single national line loss credit, the proposed 5 percent level is too low and suggested using 7.51 percent to be consistent with the line loss estimate that EPA used in calculating BSER in the Goal Computation TSD. Commenters recommended that the line loss credit be 6 percent or more to better reflect average national T&D losses reported by EIA and that EP should allow line loss credits for non

- affected CHP units. Commenters stated that EPA has not explained w hy the net electric or mechanical output from the affected facility is divided by 0.95.

Comment 6 : Upgrade s to an existing unit to CHP.

Response 6: See section VIII.I of the final rule preamble of the CPP for the EPA’s response to this comment.

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

Commenter s requested that the EPA clarify the treatment of adding electric generation to existing fossil fueled boilers, incinerators, and industrial combustion units and use a mor e complex calculation for thermal output. Commenters stated that the EPA is unclear or silent on the value or treatment of adding electric generation to existing fossil fueled boilers, incinerators, and industrial combustion units. Specifically, on page 34 924, commenters noted that the EPA requests comment on the use of industrial combined heat and power (CHP) units as a potential way to avoid EGU emissions and if the answer depends on the circumstances based on the type of CHP involved.

Commenters stated that the EPA, using its model of a CHP facility, has focused on fossil fuel fired electric generating units that also produce thermal energy. Commenters stated that this approach shows up in the discussion at 79 FR 34914 and in the discussions on state pla n considerations and projecting EGU CO 2 . Commenters stated that this approach appears to match the reporting requirements in proposed 40 CFR 60.5805(c) but it is less clear whether this coordinates with the criteria to be an affected unit in 40 CFR 60.5795 (b).51 Commenters noted that the proposed definition of a CHP facility would exclude an existing industrial boiler or other combustion unit from consideration as an affected unit because it is not an electric generating unit. Commenters stated that this is i n contrast to the lack of clarity in the criteria to be an affected unit in proposed 40 CFR 60.5795(b). Commenters stated the affected unit criteria appear to include any cogeneration facility, regardless of whether it was built as an EGU with the added b enefit of using the waste heat from electricity production, or if it is an industrial cogeneration unit selling electricity. Commenters recommended that EPA make the criteria for an affected unit very clear to minimize future enforcement

.

Comment 7 : Voluntary opt

- in for CHP.

Response 7: See section VIII.G of the final preamble of the CPP for the EPA’s response to this

comment.

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

Commenters requested that EPA state unequivoca lly that CHP units operating at industrial facilities will not be subject to federal requirements associated with the 111(d) rule, unless industrial CHP operators elect to opt in or otherwise voluntarily participate in carbon reduction programs established as part of a SIP or FIP.

Commenters stated that further, as discussed in AF&PA and AWC comments and in the comments filed by the NAM coalition on those proposed rules and the Section 111(d) Proposal, if the final rule allows for outside

- the

- fenceline comp liance measures, EPA should explicitly recognize CHP as a voluntary compliance option under Section 111(d).

Commenter s stated that EPA should include industrial CHP as a resource in any Final Rule, and that CHP could create a meaningful way of meeting th e stringent CO2 emission reduction requirements. Commenter s stated that CHP facilities shouldn't be regulated under the CPP, but they should be recognized as potential contributors to carbon reduction goals on a voluntary basis.

Commenters stated that to the extent that CHP units can reduce GHG emissions more efficiently than affected EGUS, CHP unit should be allowed to voluntarily "opt

- in" to being covered under the 111(d) rule, so that they would not be within the scope of coverage of a future NSPS.

Com menter s stated that if the final rule does not include the requested exemption for industrial CHP units, the final rule should explicitly recognize CHP as a voluntary compliance option under Section 111(d).

Commenters stated that the federal guidelines sho uld use authority granted under CAA section 111(b ) ( 2) to establish a subcategory for CHP units to ensure state plans uniformly recognize the proven benefits of CHP technologies. Commenters stated that CHP facilities should be credited as a voluntary compl iance solution, and the federal guideline should delineate how state plans can credit CHP facilities for their voluntary participation in meeting state goals. Commenters believed that these measures can help ensure that reductions that have been provided o ver the52 years by existing CHP will be allowed to continue and commenters believed that CPP can drive significant expansion of CHP. Commenters believed that the final federal guidelines under section 111(d) should send a clear signal that the EPA will appro ve state plans that encourage the expansion of CHP as a means of reducing emissions from affected EGUs.

Commenter s asked for clarification on treatment of industrial CHP units.

Commenter s asserted that it is not EPA's intention to regulate industrial CHP units under this proposal, given the environmental benefits of CHP units and the government's affirmative steps to promote increased industrial distributed generation. While excess electricity may be sup plied to the grid, commenters noted that industrial CHP units are designed for the purpose of producing useful thermal and electric energy for the facility itself and the associated thermal host. Commenters argued that because CHP units are not intended to provide a majority of their energy output to the public power grid they should not be regulated under this rule as commercial EGUs. Commenters stated that if EPA proceeds to finalize emissions guidelines for existing fossil fuel

- fired EGUs, EPA should cle arly ensure that the applicability criteria for affected sources exclude CHP units from the industrial and manufacturing sectors

. Instead,
commenters suggested that EPA permit industrial CHP units to participate voluntarily alongside other energy sources t hat can reduce net GHG emissions. Commenters stated such exclusion would further incentivize the adoption and maintenance of efficient, reliable, and low

- emission distributed generation.

Commenter s supported the creation of a voluntary combined source cat egory structure that is available for affected entities participating in an emissions market, as this would facilitate flexibility in compliance, including regional approaches and trading.

Commenters commented that, while not currently regulated, the EPA m ay consider regulating CO2 emissions from non

- covered CHP sources because, in most cases, a facility installing CHP may increase onsite emissions while displacing a greater amount of emissions from the electric system. Commenters explained that the onsite increase could trigger additional or more

- stringent regulation through other current or future rulemakings, and that this uncertainty could be a significant deterrent to facility owners considering new CHP. Commenters added that, if a facility anticipates future regulation, it may perceive a disincentive to participate in a Clean Power Plan emissions

- reduction program in the near term, leaving readily deployable emissions reductions on the table. To address this issue, commenters proposed that the EPA shoul d allow a

non

- covered CHP system to voluntarily place itself under current power plant regulation, either under section 111(b) (for new sources) or 111(d) (for existing sources). Commenters noted that, by placing the CHP system under regulation, direct emi ssions from the CHP system should be excluded from site emissions that may in the future be regulated by the Agency.

In response to the EPA request for comment "on whether industrial combined heat and power approaches warrant consideration as a potential w ay to avoid affected EGU emissions," commenters said that such systems should be recognized as a potential compliance tool for EGUs. Commenters added that references to "industrial CHP" ignore the significant potential for CHP in institutional and commerci al sectors, particularly in systems serving universities, downtown areas, hospitals, military bases and other multi

- building settings.53 Commenter s recommended that applicability under the final rule should allow states to include CHP as a compliance measur e. Commenter s described five categories of CHP that should be creditable in state plans.

• Type 1. Existing power

- only EGUs that meet the final 111(d) regulatory applicability criteria that are converted to a CHP technologies should receive credit for emiss ion reductions in state plans;

• Type 2. Existing CHP EGUs that meet the final 111(d) regulatory applicability criteria that increase utilization above baseline or that switch to lower carbon fuels should receive credit towards compliance in state plans;

• Ty pe 3. Existing CHP EGUs that qualify for exemption (under the final 111(d) regulatory applicability criteria) that increase utilization above baseline should receive credit for emission reductions in state plans.

• Type 4. New CHP EGUs that meet the final 11 1(d) applicability criteria and the 111(b) applicability criteria should be creditable in state plans under section 111(d).

• Type 5. New CHP EGUs that qualify for exemption (under the final 111(d) regulatory applicability criteria) should be creditable in state plans under section 111(d).

Commenter s noted inconsistencies in discussions of non

- affected CHP units and suggested that EPA clarify in the final rule that emission reductions stemming from new and uprated CHP at

non

- affected units is an approvable c ompliance mechanism.

Commenter s noted that, in a number of places, the Proposed Rule acknowledges the emission reduction opportunities from voluntary action by non

- affected CHP and indicates that state plans that encourage that CHP would be approvable

. ( "[L]arge energy users might independently see additional energy efficiency opportunities or opportunities for self

- generation using options such as combined heat and power, ... and states can structure their plans to allow the CO2 reductions achieved at af fected EGUs through such actions to assist in reaching compliance ."); (" States may choose measures that would ease pressures on system reliability. Commenters stated that this is true for many demand

- side management approaches, including programs to encourage

... combined heat and power, which actually reduce demand for centrally generated power and thus relieve pressure on the grid ."). However, commenters noted that the Proposed Rule also contains language that suggests that non

- affected CHP may not be an approvable compliance strategy

. [ Id. at 34924 ] (" The agency requests comment on whether industrial combined heat and power approaches warrant consideration as a potential way to avoid affected EGU emissions ..."). Commenters stated that this inconsis tency has created significant uncertainty with regard to whether incremental generation from non

- affected CHP will be deemed an acceptable compliance strategy by EPA. Commenters stated that such uncertainty will impact financing and investment decisions fo r new CHP and result in reluctance among states to include policies to encourage CHP in state plans. Commenters suggested that EPA eliminate this uncertainty by sending a clear signal in the final Clean Power Plan that policies to account for and encourage54 voluntary actions that result in new and uprated CHP at facilities other than affected EGUs are approvable compliance tools in state plans

.

Commenter s asked for clarification on treatment of CHP units with respect to the definition of

" affected EGU ."

Co mmenter s acknowledged that EPA's definition of " affected EGU " does not, itself, determine whether a state will incorporate that unit into its compliance plan as an "affected entity ." However, commenters stated that the Clean Power Plan does propose to requ ire states to address all affected EGUs. [79 FR 34954, proposing Section 60.5795(a)] Commenters stated it is important that EPA provide states with sufficient flexibility to adopt policies that do not impose obstacles to existing CHP usage and that encour age new CHP at affected EGUs and other entities.

Commenters primarily recommended that EPA determine that CHP facilities are not " affected EGUs ," and that EPA should also make clear to the states that they need not mandate reductions of emissions at any C HP facilities in their compliance plans . However, commenters stated that if EPA insists on using the same applicability criteria for all three Section 111 rules, which potentially could make some CHP facilities into "affected EGUs," then commenters urged E PA to adopt its recommendations with respect to those criteria. By adopting the applicability criteria that commenters ha ve recommended in comments on the associated Section 111 rulemakings

including an exclusion for highly efficient CHP, commenters noted that EPA can provide states with that needed flexibility. In any event, commenters stated that EPA should make clear to states that if a unit is not an affected EGU, the unit's emissions will not factor into the "emission performance" of "affected EGUs" in the state

.

Commenters stated that nothing in EPA's rule should preclude the State of Maine from preserving the incentive for CO2 budget units that are combined heat and power (CHP) units at integrated manufacturing facilities . Commenters asserted that Maine should continue to promote and reward the operation of RGGI CO2 budget units that are CHP producers at integrated manufacturing facilities by using the CO2 allowances to offset behind

- the

- meter CO2 emissions. Commenters add ed that " Behind

- the

- meter CO2 emissions " means the difference between the total annual CO2 emissions from a CO2 budget unit that is a c ombined heat and power unit at an Integrated manufacturing facility and the annual CO2 emissions associated with the

n et electricity that is transmitted over the facilities of a Transmission and distribution utility from such a unit.

2. 5 DEFINITION OF AFFECT ED SOURCE

This section addresses comments received regarding the definition of affected source

.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.55 Comment 1: Ambiguity in the definition of affected source.

Response 1: The final rule clarifies that the only affecte d entities subject to regulation under 111(d) are those meeting the definition of affected EGUs . Non

- EGUs are not affected sources.

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

Commenters stated and concurred that EPA's proposed rule does not provide sufficient notice as to what entities may be included as affected entities, explaining that the plan EPA relies on affected entities, a category defined simply as an "entity with obl igations under this subpart for the purpose of meeting the emissions performance goal requirements in these emission guidelines." Commenters continued, (verbatim) affected entities have enforceable duties, duties that in some way reduce electric generation from existing fossil units, thereby reducing CO2 emissions from affected EGUs. Commenters said EPA notes in the preamble and in numerous TSDs that various entities may take actions that reflect reductions in affected EGU emissions. Commenters said, howeve r, EPA's definition of affected entities, while broad, is tied to the "enforcing measures" provision, Section 60.5780, which creates ambiguities as to what is or is not an acceptable affected entity. Further, commenters noted that the vague language does n ot adequately anticipate certain categories of projects that will occur. Commenters’ examples are described below. Commenters stated, by not specifying in the rule itself the type of projects that EPA would and would not accept

- as detailed in the rule's accompanying documents

- the rule itself creates ambiguity and fails to provide the flexibility that EPA wants and the certainty that states and sources require, opening up both the states and sources to unwarranted lawsuits. Commenters said, for example, EPA appears to allow new fossil

- fuel fired entities, with lower carbon intensity than affected EGUs, to be used for compliance. Commenters noted that these units would be built according to a Section 111(b) standard and be "exempt" from the affected EGU ca tegory. See Proposed 60 C.F.R. section 5800, 79 Fed. Reg. 34,954. Commenters stated that such a new or modified unit likely would replace an existing, higher intensity unit, or reduce output from an existing higher intensity unit. However, by not specifica lly listing replacement EGUs as affected entities and specifically exempting them from the affected EGU category, commenters asserted that EPA creates an impermissible ambiguity as to whether such units can be affected entities and whether they can be acco unted for in meeting state goals.

Commenters stated EPA defines EGU elsewhere in the EPA proposal but does not specify whether or not the owner of an EGU would count as an affected entity or an affected source for purposes of the definition of "emission s tandard." Commenters said an open question is whether or not a state could tax an owner of an EGU as an "affected entity" based upon fuel purchases for or emissions from "affected sources" that it owns. Given the significance of the interaction between the definition of affected EGU or source and other affected entities, commenters suggested that EPA should consider clarifying its view of these terms. See EPA, Carbon Pollution Plan for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg., 34954; 34956.56 Comment 2 : Support for and opposition to inclusion of small

- sized units and cooperatives.

Response 2 : The EPA does not prescribe how a state must meet the emission guidelines. That is, the emission guidelines do not require that sma ll electric cooperatives or small municipal power systems bear compliance burden. CAA section 111(d) creates a partnership between the EPA and the states under which the EPA establishes emission guidelines and the states take the lead on meeting them by cr eating plans that are consistent with the EPA emission guidelines. The final rule establishes the BSER specifically for affected sources in the form of subcategory

specific performance rates for affected EGUs instead of only setting goals for a state. Each state will determine whether to impose source

- by

- source limitations reflecting the BSER performance rates to each affected EGU or to adopt a state measures approach and meet either an equivalent statewide rate

- based goal or statewide mass

- based goal. A st ate choosing the state measures approach will have the option to place few or no requirements directly on affected EGUs. Specifically, the final guidelines are structured so that states are not required to use each and every one of the measures that the EP A determines constitute the BSER or to apply any one of those measures to the same extent that the EPA determines is achievable at reasonable cost on a national basis. Instead, in developing its plan, each state will have the flexibility to select the

meas ure or combination of measures it prefers in order to achieve the CO 2 performance rates for its affected EGUs or meet the equivalent statewide mass

- based CO 2 goal.

The EPA recognizes that each state has differing policy considerations

– including varying emission reduction opportunities and existing state programs and measures

– and that the characteristics of the electricity system in each state (e.g., utility regulatory structure, generation mix and electricity demand) also differ. The final rule gives s tates the flexibility to implement a broad range of approaches that recognize that the power sector is made up of a diverse range of companies that own and operate fossil fuel

- fired EGUs, including vertically integrated companies in regulated markets, ind ependent power producers, rural cooperatives and municipally

- owned utilities, all of which are likely to have different ranges of opportunities to reduce GHG emissions while facing different challenges in meeting these reductions. By expressing the applica tion of the final BSER as a source

- specific performance standard, and by providing a translation of that to statewide rate

- and mass

- based CO 2 goals based on each state’s particular mix of sources, the rule allows states the flexibility to determine how to achieve the CO 2 reductions (i.e., greater reductions from one building block and less from another, as well as the adoption of other measures that lower carbon intensity), and to adjust the timing in which reductions are achieved, in order to address key issues such as cost to consumers, electricity system reliability and the remaining useful life of existing generation assets.

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

Commenter s suggested that the EPA include additional guidance for state plans regarding enforceability of requirements that apply to EGUs that are not large enough to meet Title V thresholds because states should be allowed to include smaller EGUs in their plan to implement section 11 1(d) as long as the state

- level overall goal is met

.

Commenter s , small electric cooperative s in Colorado, urged the EPA to consider specific waivers or considerations that recognize cooperatives have smaller generating fleets and less flexibility than lar ge investor owned utilities because Colorado's electric co

- ops are not vertically57 integrated; this means that separate power companies generate and transmit (on high voltage lines to substations) the electric power ultimately distributed (from the substati ons) to the member

- customers of the cooperatives on the cooperative's low voltage lines. Commenters believed this vertical "disaggregation" distinguishes electric co

- ops from investor

- owned and municipally owned utilities because no electric distribution cooperative in Colorado owns enough generation capacity to supply its members' electric demands, and cooperatives must rely on long term all requirements contracts with wholesale suppliers for most if not all of their electric capacity. Commenters we re co ncerned that increased regulatory costs to the wholesale suppliers will necessarily be passed on to the distribution co

- ops and negatively impacting the

co

- ops' ability to provide reliable electric service at a reasonable rate. Commenters also believed th e proposal will result in the EPA usurping the authority of locally

- elected co

- op boards, working with their wholesale power suppliers, to determine the appropriate power supply mix in their states. Commenters also believed that the EPA should consider giv ing greater credit for the emission reductions Colorado cooperatives have achieved prior to the proposed 2012 baseline year, and commenters requested that EPA allow states to include all reduced

- carbon technologies in their section 111(d) state plans inclu ding additional resources that have the net effect of reducing greenhouse gas emissions.

Commenter s stated that the proposal did not adequately address the differences between large utilities and smaller utilities such as cooperatives, and commenter s belie ved the proposed rule disproportionately impacts smaller utilities with less generation, less diverse fleets, and electricity consumers with fewer financial resources. Commenters believed that these differences make achieving the proposed standard much mor e difficult for smaller utilities. Commenters stated that since many of these smaller utilities do not serve retail customers directly, it will be difficult to implement the beyond

- the

- fence energy efficiency measures. Commenters stated that many cooperati ves serve rural, impoverished counties, with mostly residential customers located in service territories where investor owned utilities have declined to provide services because the low density of electricity customers is not sufficiently profitable for th eir investors. Commenters provided Georgia as an example where 90 percent of cooperative customers are residential and many of those residential customers struggle to pay ever

- increasing power bills. Commenters stated that many cooperatives operate as not

- for

- profits and are required to minimize operational costs yet fulfill their obligation to deliver electricity, regardless of the demand imposed on their system. Commenters stated the propose rule is unprecedented because it will a ffect every aspect of the way electricity is generated, transmitted, distributed and sold nationwide and will disproportionally impact impoverished users of electricity. Commenters stated that cooperatives will have no choice but to pass on to impoverished customers the increased costs of service, unlike larger systems that can spread such costs over a larger, more diverse (and more affluent) customer base. Commenter s requested that the final federal guideline allow states to include conditional exemptions for small not

- for

- profit municipal utilities because these utilities operate under different regulatory structures with different financial constraints than the vast majority of the electric utility sector, and commenters believed that states will need th e flexibility to develop plans with differing levels of requirements tailored to specific utility models. Commenter s stated that several aspects of the proposed federal guideline will have significant impact on small municipal utilities and that certain sm all municipal utilities who own and operate new clean EGUs, like Dallman Unit 4, should be treated separately under state plans. Without provisions for a separate program or conditional exemption for financially constrained utilities, commenters58 believed t he federal guideline could have devastating impact on the small municipal utilities, cooperatives and customers.

Commenter s , operator s of rural electric cooperative s serving economically disadvantaged citizens, stated that the final rule must incorporate opportunities for addressing problems and issues that are distinct and specific to rural electric cooperatives because 40 CFR 60.24(f) requires federal guidelines to allow states to consider other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable. Commenters stated that the lbs. / MWh reduction goals in the proposal create insurmountable problems for rural electric cooperatives because rural ele ctric cooperatives typically have limited generation portfolios and rely heavily on coal

- fired generation for a predictable, deliverable, and low

- cost fuel. Commenters stated that rural cooperatives also face unique financing constraints with lender arrang ements that place rural electric cooperatives at a higher risk of stranding assets. Commenters stated that rural cooperatives typically have a minority share of EGU ownership (and associated leverage on planning decisions). Commenters stated that rural elec tric cooperatives generally serve parts of the state that are more economically disadvantaged and more sensitive to rate increases that follow state and federal mandates that render partially depreciated investments in existing generating assets un

- usable, and that require investments in new generating assets (both of which must be re

- paid by members). Commenter s stated that a cooperative has limited ability to achieve emissions reductions through demand

- side energy efficiency measures, and commenters

serve d members that live in two different regional transmission organizations; commenters stated that these constraints are significant administrative and operational challenges for compliance. Commenters believed that the compliance challenges faced by rural e lectric cooperatives are the reason Congress mandated that the federal guideline permit the states to consider other factors when the state applies a standard of performance to an existing source that has come under federal regulation pursuant to CAA secti on 111(d).

Commenter s stated that CAA section 111(d)(1) and 40 CFR 60.24 direct EPA to provide states with broad flexibility to determine the extent to which to apply standards of performance to particular sources and source categories. Commenters believed that this flexibility is particularly important for cooperatives and small utilities, which will face significant challenges in complying with any standard of performance based on the BSER that EPA has proposed. Commenters stated that preamble text acknow ledges the plight of many rural electric cooperatives with very small fleets and few options for compliance in competitive power markets, but commenters stated that the federally predetermined goals fail to give states the flexibility necessary to address the challenges facing rural electric cooperatives. Commenters stated that the proposed statewide emission reduction targets are based on unfounded assumptions about the availability of re

- dispatch, renewables, and demand reduction, and
commenters asserted that the proposed rule had no provisions for adjusting proposed targets if the underlying assumptions prove to be inconsistent with reliable and affordable service when applied to certain rural regions of the electricity grid. Commenters believed that the proposed rule is unlawful because the proposed state goals deprive the states of permissions granted to the states by Congress (under CAA section 111(d)(1)) to apply standards to rural cooperatives in a reasonable way. Commenters believed that th e Act mandates that the final federal guidelines must permit states to consider individual unit circumstances, including remaining unit useful life when the state applies section 111(d) standards to existing sources. Commenters stated that the59 final federa l guidelines should recognize that: (1) most rural electric cooperatives have extremely limited portfolios of generating assets and therefore that re

- dispatch to gas

- fired or renewable energy sources may not be available for many rural electric systems; (2 ) in many cases they rely on coal

- fired EGUs that may be able to make only minimal improvements in heat rate to achieve lower CO2 emission rates; (3) existing lessor financing arrangements and concerns about creating stranded assets through premature shutd own or curtailment would create significant adverse rate impacts for small rural electric cooperative members, and these existing debts will constrain the ability of cooperatives to incur additional investments for technologies that can comply with the pro posed standard; and (4) opportunities for additional demand

- side energy efficiency measures in rural areas are likely to be extremely limited due to the rural and largely residential nature of the membership. Commenters stated that the suggestion in the pr eamble that cooperatives build or contract for electric supply from lower

- emitting sources is unlikely to be practicable and will result in unreliable electric supply to rural customers at extraordinary rates. Commenters stated that many small investor

- own ed utilities also face the same challenges caused by limited generation portfolio, coal reliance, and widely dispersed, largely residential
customers.

Commenter s believed that the final rule can solve the problems proposed for small cooperatives and small utilities by strictly following the statutory mandate and by finalizing a federal guideline that permits the states to consider all factors relevant to establishing a state goal and subsequently applying the corresponding standards that reflect these facto rs and the remaining useful lives of the affected EGUs. Commenters urged the EPA to limit itself to its statutorily prescribed roles of: (1) defining the procedures under which the States will develop and submit their plans, and (2) identifying the best sy stem of emission reduction that EPA determines has been adequately demonstrated.

Commenter s stated that the extraordinary challenges and obstacles rural electric cooperatives (and other small utilities) would face in attempting to comply with the proposed emission guidelines demonstrate the need for state discretion to take these and other relevant considerations into account in determining the extent to which any standard of performance can be applied to cooperative

- owned units, whether individually or as a class.

Commenters d id not believe the proposal adequately addressed the differences between large utilities and smaller utilities like cooperatives. Commenter s , not

- for

- profit municipal utilit ies whose "affected units" emit less than 2.6 percent of Illi nois' total EGU emissions, indicated that state environmental and electricity regulations recognize the differences between not

- for

- profit cooperatives and investor owned utilities because they are exempt from the jurisdiction of the state's public utiliti es commission and also exempt from the state Renewable Portfolio Standard (RPS) established by state statute which is likely to be a major component of Illinois' section 111(d) plan. Commenter s emphasized that many Americans that depend on cooperatives to deliver their electricity are below the poverty line and commenters provided statistics for two counties within her cooperative's service territory where more than 40 percent of the electricity consumers were below the poverty line.

Commenter s , investor ow ned utilit ies , opposed special treatment of small municipally owned utilities and cooperatives because commenters believed that all load serving entities in a state should be subject to similar requirements in order to prevent placing undue hardships on60 in vestor

- owned utilities. Commenters recommended that the final guidel ine not include provisions for special treatment of rural cooperatives and small municipal utilities, but also stated that if the final guidelines do include such provisions, the final gui delines should also adjust
state targets. Commenters stated that her utility operates five EGUs that are partially owned by several municipal utilities or rural electric cooperatives, and commenters stated that joint ownership in a large generating unit i s often a low

- cost way for smaller utilities to provide load to their customers without the significant investment costs associated with constructing, operating and maintaining individual generating resources. Commenter s stated that ownership rights and re sponsibilities, including environmental compliance obligations, are governed by joint

- ownership agreements, and commenters opposed creating special classes of utilities in the final rule because commenters believed segregation into special classes will int erfere with existing, contractual, joint

- owner relationships. Commenter s believed the states are in a better position to decide on requirements for different types of utility companies than the federal government. Commenter s , utilit ies operator serving customers that live at or below the poverty line, believed that a comprehensive climate policy must include protection for low

- income customers from the economic impact of such regulation, for instance through an increase in earned income tax credits or through a rebate refund program.

Commenters stated they are the only municipal utility with generation in Illinois. Commenters requested the USEPA adjust its GHG Rule to provide guidance to states for the provision for small not

- for

- profit municipal utilities like CWLP, which meet the unique factors that distinguish them from other affected entities subject to the plan. Commenters explained that such guidance should expressly allow for states to consider the following options in state plans that the EPA would deem compliant with the CPP (verbatim): 1. Conditional Exemption: A state plan should be authorized to conditionally exempt a utility or unit based on specific findings at the state level that the integration of the utility or the unit w ould cause disproportionate financial hardship while not substantively aiding the state in meeting the goals of the CPP. 2. Subcategorization: Given EPA's novel approach to interpreting the entire electric system as the Best System of Emission Reductions ( BSER), the EPA should expressly clarify the ability of a state to subcategorize by utility type to better reflect the obligations that will accrue to each utility based on the assets it owns, its ownership structure, the authority of the state EPA to requi re actions, and how it engages in electric markets. 3. Alternative Compliance Mechanisms: EPA should expressly clarify that states may establish more than one compliance option with in a state such that utilities with different ownership structures, assets and obligations may choose to aid the state in meeting its obligations to comply with the CPP in the most efficient manner possible. Commenters recognized that the proposed rule allows a state to demonstrate "equivalency" using several tests. Commenters s aid, for example, the EPA specifically recognizes RPS as the type of state policy or program through which the GHG rule is "building on actions already underway in states and the power sector." ( At 34848.) Yet commenters believed the RPS examples given fro m other states or utilities are well below the 20% they have already achieved and is achieving at greater cost than estimated by EPA. Commenters stated, similarly, the savings of Arizona investor

- owned utilities are far below those achieved by commenters t hrough its own EE programs. Commenters' carbon intensity equation meets or exceeds what the U.S. EPA expects a utility or unit to achieve as a result of the GHG Rule. Commenters stated that for these reasons, they requested the U.S. EPA add to its equivale ncy options a state's authority to differentiate units or utilities through one of the mechanisms above.61 Commenters argued that EPA should make clear that states should take into account the challenges of small public power systems and units. Commenters al so argued that EPA should provide flexibility for states to address municipal utility challenges.

Comment 3 : Allow small units to opt

- in.

Response 3 : The EPA does not agree. Reduction in emissions from small power plants not covered by the rule and not connected to the grid do not result in emission reduction at affected EGUs and therefore cannot be used to meet the emission reduction requirements for affect ed EGUs.

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

Commente rs suggested that the final rule include applicability provisions that would allow sources that are otherwise below applicability thresholds or that are otherwise unaffected be allowed to opt

- in to the pool of sources that are subject to section 111 standa rds because this would enable states to encourage the operators of otherwise uncovered power plants to earn some type of credit by reducing emissions; for example, small, diesel generators in rural Alaska are not covered by the proposal since they are smal l and not connected to the state's electrical grid; however, some of these generators could be replaced by cleaner sources, such as small run

of

- the

- river hydroelectric projects.

Comment 4 : Commenters provide rationale s to support or oppose the combinati on of source categories into a single new subpart UUUU

. Response 4 : In this rule, the EPA is combining the steam generator and combustion turbine categories into a single category of fossil fuel

- fired electricity generating units for purposes of promulga ting emission guidelines for GHG emissions for existing sources . Combining the two categories is reasonable because they both provide the same product: electricity services. Moreover, combining them in this rule is consistent with our decision to combine t hem in the CAA section 111(b) rule for new, modified and reconstructed sources that accompanies this rule. In addition, many of the monitoring, reporting, and verification requirements are the same for both source categories, and, as discussed next, we are codifying all requirements in a single new subpart UUUU of the regulations; as a result, combining the two categories into a single category will reduce confusion. It should be noted that in this rule, we are not combining the two categories for purposes of standards of performance for other air pollutants. EPA also notes that

t h e affected unit for this final rule is a single combustion turbine engine and any associated heat recovery steam generator. The EPA notes that for 111(b) purposes, the definition o f the affected facility is often defined as a single source of emissions. We may consider expand ing the definition of the affected facility in future rulemakings.
The following are summaries of the specific public comments under this c omment:6 2 Commenters stated that EPA's proposal to combine two existing categories could be accommodated by allowing this approach in a state plan as provided flexibility, but without making it mandatory. Commenters explained that this approach would allow shifting or dispatch of resources within a system or category treated as a system: e.g., municipal electric utilities within a state. Commenters did not object to combining the categories, but questions how this could affect state goals, noting that state energy supplies from steam EGUs and combustion turbines are not homogenous among these two categories and vary even further from state to state. Commenters believed that if the USEPA allows the states full flexibility, then the state would be able to decide how to average emi ssions from these two categories in order to meet the required emission goals.

Commenters stated that in Subpart KKKK, when two stationary combustion turbines with heat recovery steam generators supply a common steam turbine and steam turbine electric gene rator, EPA should enable applicability and compliance for the two combustion turbines to be determined on a combined basis. Commenters explained that a very common current design for a combined cycle facility is to use two (or more) stationary combustion t urbines, each with a combustion turbine electric generator, and each with a heat recovery steam generator (HRSG) that may include a duct burner

- with the steam from each HRSG directed to a common steam turbine and steam turbine electric generator. Comment ers noted the design using two stationary combustion turbines is commonly called a "two

- on

- one" or "2X1" configuration. Commenters believed that EPA should provide an option, at the election of the owner/operator, for facility designs such as the "2X1" con figuration to determine applicability and to comply on a combined basis rather than by a combustion turbine by combustion turbine basis. Commenters explained that for "2X1" compliance, carbon dioxide emissions from both combustion turbines (and any duct bu rners) would be combined to determine total emissions. Commenters noted that gross MWH from the two combustion turbine electric generators and the common steam turbine electric generator would be combined to determine total gross MWH, and this option would remove the need to apportion gross MWH produced by the steam turbine electric generator to separate combustion turbines as proposed under rule section 60.4373(e). Commenters stated that compliance would be determined using the total CO2 emissions divided by the total gross MWH. Commenters stated that applicability criteria for a "2X1" configuration under proposed rule section 60.4305 would likewise be determined on a combined basis, doubling the actual electric output applicability threshold to reflect two combustion turbines.

Commenters stated they support the use of flexible compliance measures under 111(d), adding that if EPA concludes that combining the two existing source categories (fossil steam EGUs [Da] and combustion turbines [GG/KKKK]) into a sing le subpart (TTTT) for purposes of regulating existing sources under 111(d) would facilitate such flexibility, Commenters would support such a regulatory structure.

Commenters stated they support consolidating the two source categories of affected EGUs

co vered by the emission guidelines

- electric steam generating units and combustion turbines

- into one regulated source category for purposes of establishing carbon pollution standards for all EGUs, including the emission guidelines for existing EGUs as well as the performance standards for new, modified, and reconstructed EGUs. Commenters explained a consolidated source category would reflect the identical market functions served by all of the affected EGUs covered by EPA's proposed carbon pollution standar ds. Commenters stated that a single source category63 would also be consistent with the system

- based approach EPA has proposed, which has important elements that reduce emissions from existing EGUs as a whole rather than solely from EGUs utilizing particular fuels or generating technologies. Commenters stated that as a threshold

matter.

Commenters believed that EPA is therefore free to make reasonable revisions to the source category listings, including the consolidation of already

- listed source categories, without significant new findings. Commenters continued that the proposed consolidation of the source categories would be reasonable for at least three reasons. Commenters said, first, steam electric generating units and fossil fuel

- fired combustion turbine s broadly serve the same market functions. Commenters stated that not only do units in these source categories all generate electricity for wholesale, they also increasingly provide similar types of generating service. Commenters noted, in a climate of com petitive natural gas prices and relatively high coal prices, coal

- fired steam electric generating units now commonly provide intermediate or even peaking generation service rather than playing their traditional role as baseload

resources. Commenters stated as coal generation has declined, gas

- fired combustion turbines

- especially NGCC facilities

- have become intermediate or baseload resources rather than providing primarily peaking service. Commenters stated that combining these two source categories to r eflect their converging market functions, as we recommend, would be consistent with the categorization contemplated by Congress when it originally enacted section 111 in 1970. (417 The legislative history of the 1970 Clean Air Act indicates that Congress e xpected EPA would establish standards within broad functional categories of facilities. One representative, for example, stated that EPA "could establish uniform pollution control standards for the chemical, oil refining, foundries, food processing, and ce ment

- making industry, and other industries. . . . Every plant within the same group could be required to maintain the same high standards." 116 Cong. Rec. 19,218 (1970) (statement of Rep. Vanik).)

Commenters stated that it would also be consistent with th e history of these particular source categories; for example, in 2005, EPA transferred integrated gasification combined cycle (IGCC) facilities to the steam electric generating unit source category on the grounds that IGCC facilities serve the same functio n. (418 See 77 Fed. Reg. 22392, 22,411/1 (April 13, 2012).) Commenters stated it would be consistent with various other instances in which EPA has established broad categories encompassing multiple types of sources that serve the same function, even though those source categories may encompass facilities using disparate fuels and industrial processes. (419 For example, EPA designated a single NSPS for multiple copper smelting production methods as early as 1976. See 41 Fed. Reg. 2332

- 2333 (Jan. 15, 1976). S imilarly, EPA's rotary lime kiln source category includes units fueled by coal, natural gas, and oil. See 47 Fed. Reg. 38832, 38843 (Sept. 2, 1982); see also 40 C.F.R. Section 60.340(a), 60.342. And most recently, EPA included all Portland cement plants (e .g. "long wet," "long dry," "preheater," and "preheater with precalciner") in a single source category. 75 Fed Reg. 54970, 55,010

- 55,012, 55,015 (Sept. 9, 2010). This decision was ultimately held by the D.C. Circuit. See Portland Cement Association v. EPA, 665 F.3d 177, 190

- 93 (D.C. Cir. 2011).

Commenters noted, second, the consolidation of these two source categories would be consistent with the system

- based nature of the BSER that EPA has proposed in these emission guidelines. Importantly, commenters sta ted that the four building blocks in EPA's BSER are intended to64 function in concert to reduce emissions from all EGUs across the two source categories. Commenters stated that the effects of any individual building block on any one type of EGU, however, wil l depend upon power market dynamics. Commenters noted, for example, building blocks 3 and 4

- which involve shifting generation to zero

- carbon resources such as renewable energy and energy efficiency

- displace the need for both generation from fossil fuel

- fired combustion turbines and steam electric generating units. Commenters stated the extent to which these building blocks reduce generation from one or both types of EGUs, however, can vary by region of the country and even by season of the year. Comment ers noted that establishing a single source category for both steam electric generating units and fossil fuel

- fired combustion turbines would be consistent with the broad nature of the BSER that EPA has proposed, and simplify EPA's analysis by ensuring tha t all emission reductions from that BSER are attributed to one source category. Commenters said that a single source category would also be consistent with the nature of the power sector. Utilities and independent system operators make dispatch decisions f or the entire fleet of power plants without regard to whether those power plants are fueled by coal, natural gas, nuclear energy, or renewable resources.

Commenters stated that operating the grid in this way allows utilities to dispatch the least expensive available generating resources. Commenters noted that states and utilities may choose to consider compliance options for EPA's forthcoming 111(d) standards that follow similar principles, just as EPA's proposed system

- based BSER reflects the capability of the electric system to achieve overall reductions in carbon pollution by increasing output from lower and

zero

- emitting resources. Lastly, commenters noted that the adoption of a broad source category encompassing all affected EGUs would not preclude EPA from recognizing appropriate subcategories where needed to establish performance standards for new sources. (Nor, conversely, would the retention of separate source categories preclude the flexible system of emission reduction EPA has proposed for the two categories here, where emission reduction opportunities are assessed and compliance allowed to be achieved comprehensively across the two categories.) Commenters asserted, Section 111(b), of course, gives EPA broad discretion to "distinguish among classes, types, and sizes within categories of new sources" by establishing subcategories when prescribing standards for new sources. (420 42 USC

- 7411(b)(2).)

Commenters supported combining the two existing categories into a single category for purposes of carbo n emissions from existing affected EGUs and supports EPA's proposal to codify all of the proposed requirements for the affected EGUs in a new subpart, 40 CFR part 60 subpart UUUU. Commenters stated that combining the two categories would offer additional flexibility by facilitating implementation of carbon mitigation measures, such as emission trading among sources in both categories.

Commenters noted that EPA has revised, combined, or otherwise redistributed sources previously subject to different section 111(b) source categories, and such revision or combination of source categories is particularly appropriate where, as here, both source categories at issue serve the same basic function: to supply power to the grid from the combustion of fossil fuels. Com menters concluded, stating that against this backdrop, promulgation of emission guidelines for all existing fossil fuel

- fired EGUs under a single combined source category is both consistent with EPA's prior practice and permissible under the
statute.65 Comm enters stated that the separate standards of performance for fossil fuel

- fired steam generating boilers and fossil fuel

- fired combustion turbines made sense for regulation of criteria pollutants. Commenters noted, however, in the context of regulation of c arbon dioxide this separation is a historical artifact with no compelling purpose. Commenters stated that separate standards could potentially inhibit flexibility in shifting generation from more carbon

- intensive steam units to less carbon

- intensive NGCC u nits. Commenters believed EPA's 2014 proposal is good policy for both Section 111(b) and Section 111(d), and it would promote flexibility and facilitate emissions trading. Commenters concluded, stating that for purposes of CO2 regulation, they recommend th at fossil fuel

- fired steam generating boilers and fossil fuel

- fired combustion turbines should be combined into a single category.

Commenters supported combining the category of coal

- fired steam power plants and gas turbines (including combined cycle turb ines), 79 Fed. Reg. at 34,892. and believed it is appropriate because both coal

- fired steam power plants and NGCC power plants serve the same function of providing base

- load and intermediate load electricity, and a single category is also consistent with t he system

- based approach EPA has proposed, which has important elements that reduce emissions from existing EGUs as a whole rather than solely from EGUs utilizing particular fuels or generating technologies.
Commenters stated since they are not in favor of carbon averaging, they felt that the two existing categories, fossil fuel

- fired steam generating boilers and fossil fuel

- fired combustion turbines should be kept separate since one of the state benefits of combining both categories would be facilitating e missions trading among sources.

Commenters opposed the combining of the two existing categories for the affected EGUs into a single category, explaining that the NSPS industrial categories have always been defined by engineering design and function, and, therefore, the two respective categories for steam EGUs and NGCC units should remain separate for this reason.

Commenters stated that the California utilities support the EPA's proposal to combine the two source categories for purposes of regulating CO2 emissions in a new subpart UUUU. Commenters noted that as the EPA implies in the Proposed Rule, such an approach may enable the development of a more flexible program for existing sources under Section 111(d) by facilitating implementation of CO2 mitigatio n measures, such as shifting generation from higher to lower

- carbon intensity generation among existing sources (e.g., shifting from boilers to NGCC units) or facilitating emissions trading among sources. Commenters added that such flexibility should prese nt opportunities for reducing the cost of achieving emission reductions under 111(d) and offers, for example, researchers at Resources for the Future who have demonstrated that a given GHG abatement objective under 111(d) can be achieved at lower cost by l ooking across all fossil

- fuel units for abatement rather than only at coal units. (52 See Burtraw, Dallas and Woerman, Matt, Technology Flexibility and Stringency for Greenhouse Gas Regulations. RFF Working Paper, July 2013.)

Commenters stated that EPA cr eates this new source category

- the integrated electric grid

- treating the grid as if it is a "single emitting unit" for purposes of the CPP66 Commenters stated the EPA may regulate "industrial categories" that "cause or contribute significantly" to air po llution. 42 U.S.C. section 7411(b). Commenters said the EPA recognizes that greenhouse gas emissions contribute to global pollution and that no single source has the power to influence, alone, the pollution load that affects humanity. Commenters stated thi s is fundamentally different from any other pollutant regulated under the CAA, which may suggest why Congress did not directly tackle GHGs in at least 1990 if not earlier. Commenters said GHG is a matter for the State Department, not the EPA.

Commenters st ated this fundamental difference leads the EPA to the conclusion

- a correct one

- that individual fossil

- fired units, those traditionally regulated under Section 111, should not bear the burden of fixing a global problem. Commenters said but then the EPA starts to veer from this reality. Commenters stated the EPA creates this new source category

- the integrated electric grid

- treating the grid as if it is a "single emitting unit" for purposes of the CPP. Commenters said the EPA reasons that, as long as r eductions come from the generation or use of electricity, those reductions will fundamentally affect the nation's GHG pollution loading.

Commenters stated that earlier this year, they submitted comments regarding EPA's proposed new source performance stand ards for greenhouse gas emissions from the electric power sector (Docket Number EPA

- HQ

- OAR

- 201 3

- 0495). Commenters said their comments were attached as Appendix C. Commenters argued that EPA should combine coal and gas electric generating units (EGUs) into a single source category for purposes of those proposed standards. Commenters urged EPA to use its broad legal authority under section 111(b) to revise source category definitions and merge all EGUs subject to new and existing

- source greenhouse gas perfor mance standards into a single source category, and to do so in consistent fashion across the two rulemakings.

2.6 COMMENTS REGARDING S UBCATEGORIZATION

This section addresses comments received on subcategorization

.

Commenters have raised a number of issue s related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Subcategory for small public and cooperative utilities.

Response 1 : Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clean Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides that EPA will “specify different emission guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical locations, or similar factors make subcategorization appropriate.” There i s thus no requirement that the EPA establish additional subcategories under67 section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcateg ories of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utility steam generating units, and stationary combustion turbines. The EPA is not finalizing any further subcategories because it has determined that all affected EGUs can achieve the re levant performance standard set by applying the BSER to each of these two subcategories. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and r econstructed sources, which defines the same two subcategories. Further discussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.

The following are summaries of the sp ecific public comments under this c omment:

Commenters stated that based on the challenges faced by AEPCO and similarly

- situated small public and cooperative non

- profit utilities, they requested that EPA consider creating a separate category for "small publ ic and cooperative utilities" that provides relief to these small entities, ensuring their ability to continue providing basic services, while also providing for reasonable reductions in carbon emission rate and mass. Commenters explained that they believe that the category should be limited to public or cooperative entities that sell 4 million MWh or less of energy, consistent with the FERC definition. 16 USC 824(f). Commenters estimated that there are 23 cooperatives and 75 small public utilities that fit into this category based on 2012 data, and in order to qualify for relief, the small public or cooperative utility would need to demonstrate, applying EPA's building blocks only to its existing system resources, that: 1) One or more affected EGUs (a "non

- achieving unit") cannot meet the relevant state Interim Goal or Final Goal; AND 2) Such non

- achieving unit(s) make up 20% or more of the small public or cooperative utility's generating capacity; AND , 3) Shutting down the unit in 2020 (or 2030) would occu r prior to the end of the unit's remaining useful life; AND 4) The cost of building a replacement, NSPS

- compliant unit together with the cost of paying down debt on the existing

non

- achieving units, would be excessive. Commenters stated that in essence, th is test is meant to identify only those small public and cooperative utilities that are severely affected by the proposed Clean Power Plan both in terms of costs of compliance and loss of generation capacity required to serve member load. Commenters r eques ted EPA provide relief to small public and cooperative utilities. Commenters requested that "EPA consider creating a separate category for small public and cooperative utilities that provides relief to these small entities." Commenters looked at EPA, EIA a nd FERC databases and found 98 entities for the small public and cooperative utility alternative category which generate about 60,618,920 metric tons. If all of these units were in the cooperative utility alternative category and achieved an overall 15 per cent reduction then about 9,092,838 metric tons would be reduced. Commenters stated that compared to EPA's calculated 730,000,000 metric ton reduction, at most the leakage would be 1.2 percent of the total tonnage.

Commenters, operators of small, rural, co nsumer

- owned, public electric cooperative having a membership with one

- third of all members below the federal poverty line, respectfully requested that the final rule include a separate subcategory for small public and cooperative non

- profit utilities to e nsure that these small entities can continue to provide basic services to their members. Commenters explained how small, rural, member

- owned cooperatives cannot raise68 capital like traditional investor

- owned utilities, and commenters provided analyses indic ating the costs of compliance would drive up electricity rates by sixty to eighty percent; commenters asserted that such rate increases are un

- sustainable for members of the cooperative. Commenters provided analyses that indicated the prescribed federal ta rgets for states preclude sufficient flexibility in the proposed guidelines to allow any viable compliance options for ongoing operation of their only generating station. Commenters stated that the financial hardship imposed by the proposed rule will likel y force the cooperative to dissolve, leaving all the assets at the generating station as stranded assets. Commenters believed that the proposal will potentially have a similar effect on other small cooperative power plants, imposing extravagant costs and
p otentially jeopardizing the vital role of cooperatives in delivering power to rural America.

Commenters described their recommended applicability criteria for a new subcategory for small public and cooperative utilities that commenters believed should be included in the final rule:

1. Commenters stated that the EPA should use the same size threshold used by FERC, 4 million MWh or less in net electric sales; see 16 U.S.C. Section 824(f).

2. Commenters stated that one or more of the EGUs owned by the cooperative should be unable to meet the relevant state goals.

3. Commenters stated that shutting down the unit in 2020 or 2030 would result in shutting the unit down prior to the end of the remaining useful life.

4. Commenters stated that the cost of building a replaceme nt unit together with paying off the debt of stranded assets (non

- compliant units) should be excessive.

Commenters explained that their cooperative operates only one power generation facility, Apache Generating Station. Commenters described the constructi on and installation of the individual units at the station, and describes the units that may be "affected EGUs" subject to the proposed Section 111(d) requirements. Commenters described their limited financial capabilities and that their members are indepe ndent entities that make power and energy purchase decisions based on the best interest of their members. Commenters described their earnings position and internal financing capacity.

Commenters stated that the EPA's regulations governing the promulgation of the Guidelines for State Plans clearly give the EPA the authority to promulgate subcategories and the EPA has routinely exercised such authority under the general NSPS program. Section 60.22 provides in relevant part: "The Administrator will specify di fferent emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make sub

- categorization appropriate." Commenters cited 40 CFR 60.22(b ) ( 5).

Commenters stated, that in this case, the costs of control and financial limitations of the entities involved (small public or cooperative utilities, which are non

- profit) provide a strong basis for subcategorization and providi ng both a more relaxed limit (meeting the building blocks on the system only, with a target of reaching the State goals or 15 percent overall reduction, whichever is less) and a more relaxed time frame (providing a longer period to reach the overall reduct ion, up to but not to exceed the remaining useful life of the affected EGU).69 Commenters expressed concerns about applying the proposed rule to small municipal power plants and requested that the final rule allow states to subcategorize small units, and com menters requested that the final federal guideline allow states maximum flexibility to address municipal
power concerns.
Commenters stated that the proposal did not acknowledge the discretion of states to address unique circumstances of certain small utili ties, and commenters stated that the final rule should specifically address the ability of states to develop specific exceptions for dispersed communities (such as Native American communities) served by small utilities with limited options for providing el ectricity service to these remote communities. Commenters recommended that the final rule should define a "small utility" using the same definition set forth at 16 USC 824(f): a rural cooperative that sells less than 4,000,000 megawatt hours of electricity per year.
Commenters supported exemption of small public power cooperatives but stated that if the final guideline must apply to small public power cooperatives, the final rule should include a subcategory for small public and cooperative utilities define d as those with less than 4 million MWh of annual sales. Commenters cited another cooperatives estimate that the cost of complying with the proposal would increase electric costs to customers by 40 percent and commenters supported an alternative plan based on the proposed subcategory that would reduce this increase to under 10 percent, and commenters believed that the proposed subcategory for small public and cooperative utilities is consistent with Congress' goals for small entities in the Regulatory Flexi bility Act. Commenters stated EPA's legal analysis of the proposed Clean Power Plan rule suggests that States implementing this rule may have the authority to subcategorize sources to take into account costs, impacts and other factors. Commenters stated M MEA emphasizes that small public power systems and units, particularly systems with only one unit or a few units, are in a class of their own when it comes to challenges under this proposed rule. Commenters added EPA should thus make explicit and clear in its final rule that States should take this into account, and that States have authority to exclude small public power from the rules, allocate hardship credits to these units in the form of less stringent or more flexible standards, or otherwise provide flexibility and support to these units.

Comment 2 : Subcategory for unit’s combusting lignite coal.

Response 2 : Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clean Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides that EPA will “specify different emission guidelines . . . for different sizes, types , and classes of designated facilities when costs of control, physical limitations, geographical locations, or similar factors make subcategorization appropriate.” There is thus no requirement that the EPA establish additional subcategories under section 1 11(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcategories of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utility steam ge nerating units, and stationary combustion turbines. The EPA is not finalizing any further subcategories because it has70 determined that all affected EGUs can achieve the relevant performance standard set by applying the BSER to each of these two subcategori es. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and reconstructed sources, which defines the same two subcategories. Further discussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.

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

Commenters stated that sub

- categorization is necessary and appropriate for lignite

- mine

- mouth EGUs and other subcategories because sub

- categorization allows the Agency to address key characteristics of the various types EGUs. Commenters stated that the final rule should include a subcategory that reflects the unique physical, geographic, and financially related characteristics of lignite mines and mine mouth power plants because lignite has unique physical characteristics including a higher moisture content that makes it un

- economical to transport over long distances. Commenters stated that lignite

- fired EGUs are always constructed at or near a lignite mine. Commenters stated that establishing a subcategory for lignite units under the section 111(d) rule would be consistent with Agency determination s under the MATS rule. Commenters believed that any closure of a lignite

- fired EGU (to comply with a 111(d) state plan) may result in the permanent shutdown of the associated lignite mine, and commenters believed this result is inconsistent with the longst anding U.S. energy policy that has encouraged utilization of domestic lignite resources. Commenters stated that the shutdown of a lignite energy complex (i.e., a lignite mine and lignite

- fired EGU) compounds the effects of the closure and causes a dispropo rtionately greater impact on the regulated entity, the mining company and the local communities because of large losses of capital as stranded assets and foreclosed investments and the loss of technological advancements in clean coal technology at lignite

- fired EGUs supported by federal tax credits. Commenters also stated that closure of these facilities yields higher job loss totals; higher consumer energy bills due to accelerated cost recovery in regulated markets; and crippling local economic impacts.

Co mmenters stated that sub

- categorization of lignite

- mine

- mouth EGUs is also warranted because EGUs that use lignite routinely enter into long

- term fuel supply contracts to gain protection against fuel price volatility. Commenters stated that mine

- mouth plan ts throughout the country are parties to long

- term supply contracts whose maximum expiration dates range from 2016 to 2057 with a typical contract term ranging from 20

- 40 years. Commenters stated that these contracts were arranged prior to the date of prop osal and are unique to lignite mines and mine

- mouth plants, and commenters stated that sub

- categorization is warranted because the parties to these contracts have made significant investments of financial and human capital.

Commenters stated that the final rule should include a separate subcategory for lignite

- fired power plants that contemplates the unique characteristics of lignite

- fired EGUs and that reflects technological and operational differences when compared to traditional coal

- fired EGUs. Commente rs stated that a lignite subcategory should include more relaxed emissions limits because the physical and chemical characteristics of lignite yield a lower heating

- value than other types of coal, resulting in the need to combust additional fuel per megawa tt hour of electrical output. Commenters also stated that the physical and chemical composition of lignite also requires larger, more energy intensive, control technologies (compared to other coal

- fired71 units) with higher auxiliary loads and lower net elec trical output per million Btu of heat input. Commenters also stated that the final guidelines should include a separate subcategory for lignite

- fired EGUs because these units provide electricity to regions of the country that are not served by natural gas pipelines or alternative coal supplies. Commenters did not believe that the proposal properly considered the large regions of the United States that are dependent on lignite

fired generation. Commenters stated that without a subcategory for lignite

- fired E GUs, operators of existing lignite

- fired power plants may be required to shut down, forfeiting use of extremely valuable and affordable generating units, and such shutdowns would also require those units to forfeit access to domestic, plentiful, and afford able lignite. Commenters believed the proposed rule will terminate the ability of co

- located mine

- mouth plants to conduct modifications or reconstruction, as well as the ability to recover potentially sizable investments in their mines because of the limit ations placed on an operator's ability to maintain, expand, or add capacity to use these local, domestic, and sizeable fuel supplies.

Comment 3 : Subcategory for low

- emitting units.

Response 3 : Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clean Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides tha t EPA will “specify different emission guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical locations, or similar factors make subcategorization appropriate.” There is t hus no requirement that the EPA establish additional subcategories under section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcategori es of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utility steam generating units, and stationary combustion turbines. The EPA is not finalizing any further subcategories because it has determined that all affected EGUs can achieve the relev ant performance standard set by applying the BSER to each of these two subcategories. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and reco nstructed sources, which defines the same two subcategories. Further discussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.

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

Commenters stated that the final guideline should include a low

- emitting

- state subcategory with streamlined compliance requirements for states (like Idaho) that achieve low carbon intensities. Commenters believed the most straightforward way to recognize the success of states with low carbon emissions is to establish a minimum emissions performance goal (i.e., "minimum federal requirements") below which no additional reductions would be required. Commenters believed
t he legal mechanism for establishing a minimum goal is sub

- categorization which the Agency has historically used to address the wide variety of sources regulated under 111(d) and commenters noted that the 111(d) regulations were specifically amended to "mak e clear that the72 Administrator will specify different emission guidelines for different sizes, types, and classes of [existing sources] when costs of control, physical limitations, geographical location, and similar factors make sub

- categorization appropri ate." 40 Fed. Reg. 53340, 53341 (Nov. 17, 1975). Commenters believed that since EPA has created subcategories on a state

- wide basis, then the final rule should create an additional subcategory that would include any states with certain in

state generating characteristics (e.g., low existing emissions, no coal generation, 111(b) compliant gas generation, significant existing renewable generation) that provide assurance that carbon emissions will remain low. After establishing the low

- emitting

- state subcatego ry, commenters believed the final rule should then determine a separate BSER and establish an emission guideline with a specific emission threshold that could not be exceeded, rather than an emissions goal based upon application of the four building blocks ; states within this low emitter subcategory would not be required to comply with the full state performance plan requirements contemplated in the proposed rule, but instead would need to submit only a streamlined state plan that provided for continued com pliance with the threshold emissions rate. Commenters believed that this approach is consistent with the overall purposes of the proposed rule and allows a more equitable and cost

- effective result for states like Idaho with no in

- state coal generation and a demonstrated record of low carbon output because it avoids the economic inefficiencies associated with seeking to achieve marginal CO2 reductions from states with little or no fossil generation. Commenters proposed that the final guideline establish a lo w

- emitting

state subcategory that would include states that have no coal generation and attain emission rates below 550 lbs of CO2/MWh before or during the compliance period. Commenters stated that based on 2012 emissions data, only Idaho is below this thr eshold but that other states would be expected to achieve this threshold later in the compliance period and could modify state planning requirements when the goal was achieved, providing incentive to accelerate emissions reductions.

Comment 4: Subcategory for supercritical pulverized coal (SCPC) units.

Response 4: Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clea n Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides that EPA will “specify different emission guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical locations, or similar factors make subcategorization appropriate.” There is thus no requirement that the EPA establish additional subcategories under section 111(d) unless it finds that such subcategories are “a ppropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcategories of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utility steam generating units, and stationary combustion turbines. The EPA is not finalizing any further subcategories because it has determined that all affected EGUs can achieve the relevant performance standard set by applying the BSER to each of these two subcategories. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and reconstructed sources, which defines the same two subcategories.73 Further discussion of the EPA’s approach to subcategorization can be foun d in the preamble to the final rule for existing sources in sections V.A and V.B.

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

Commenters suggested newer, highly efficient supercritical pulverized coal (SCPC) units should be exempt from the section 111(d) rule or included in a separate subcategory that recognizes the newer SCPC technology as BSER for that subcategory because commenters believed it is unreasonable to make these highly efficient units subject to a standard t hat could require further capital investments for marginal efficiency improvements.

Commenters, the operator of a highly efficient supercritical coal

- fired boiler, expressed concerns that the section 111(d) rule could be used by state regulators to force h is plant to incur expensive modifications to make his plant even more efficient than it already is. Commenters did not think this is appropriate because his plant is already one of the most efficient plants in the country. Commenters noted that the propose d rule did not exempt highly efficient EGUs, and commenters suggested that the EPA evaluate the need for developing a standard of performance that would limit the possibility that additional reductions could be required at highly efficient units. Commenter s acknowledged that that EPA may view individual unit treatment as a state responsibility, but commenters believed there are many highly efficient units across the U.S. and that a consistent federal guideline is necessary to ensure that interstate power ma rkets are not unfairly tilted by inconsistent treatment of highly efficient units in state plans.

Comment 5 : EPA should revise its proposal to conform to previous rules, all of which support subcategorized, nationally applicable unit

- by

- unit standards ba sed on fuel and technology.

Response 5 : Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clean Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides that EPA will “specify different emission guidelines . . . for different sizes, types, and classes of designated facilities when costs of control, physical li mitations, geographical locations, or similar factors make subcategorization appropriate.” There is thus no requirement that the EPA establish additional subcategories under section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcategories of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utility steam generating units, and stationary combustion turbines. The EPA is not finali zing any further subcategories because it has determined that all affected EGUs can achieve the relevant performance standard set by applying the BSER to each of these two subcategories. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and reconstructed sources, which defines the same two subcategories. Further discussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.74 The following are summaries of the specific public comments under this comment:

Commenters stated the EPA's previous rules under section 111

- including those issued under section 111(d)

- support t he establishment of separate nationally applicable emission standards for EGUs based on technology, fuel type, and other relevant characteristics. Commenters said for example, in previous guidelines issued under section 111(d), the EPA has subcategorized a mong existing municipal solid waste combustors based on unit size and on the facility's aggregate combustion capability. Commenters stated the EPA has also established separate section 111 (d) guidelines based on the type of input that the stationary sourc e is designed to combust. Commenters said thus, the EPA's previous section 111(d) rules provide ample support for the proposition that the EPA must consider subcategorizing based on unit size, configuration, and fuel input. Commenters stated the EPA's sect ion 111(b) performance standards for EGUs including those proposed by the EPA in tandem with this Proposed Rule

- also uniformly support the need to subcategorize among existing sources based on fuel source, configuration, and perhaps other factors. Comment ers stated for example, requirements under NSPS categories Da (fossil

- fueled boilers) and KKKK (fossil

- fueled combustion turbines) have historically been separate, even for pollutants which both categories produce. Commenters stated likewise, the EPA's cur rent CO2 NSPS proposals for both new and modified sources differentiate among EGUs based on fuel source and heat rate.

Comment 6 : The focus of section 111 on individual sources requir es a highly subcategorized emission guidelines within a broad source category like existing fossil fuel

- fired EGUs.

Response 6 : Under 40 C.F.R. § 60.22(b)(5), the EPA retains discretion as to whether and how to subcategorize classes of facilities for purposes of setting emissions standards under section 111(d) of the Clean Air Act (which does not itself require that the EPA establish facility subcategories). Section 60.22(b ) ( 5) provides that EPA will “specify different emission guidelines . . . for different s izes, types, and classes of designated facilities when costs of control, physical limitations, geographical locations, or similar factors make subcategorization appropriate.” There is thus no requirement that the EPA establish additional subcategories unde r section 111(d) unless it finds that such subcategories are “appropriate.” In this rule the EPA has determined that it is appropriate to specify emission guidelines for two subcategories of existing fossil fuel

- fired EGUs: fossil fuel

- fired electric utili ty steam generating units, and stationary combustion turbines. The EPA is not finalizing any further subcategories because it has determined that all affected EGUs can achieve the relevant performance standard set by applying the BSER to each of these two subcategories. This approach is also consistent with the EPA’s approach in the final rule establishing standards of performance for greenhouse gas emissions from new, modified, and reconstructed sources, which defines the same two subcategories. Further di scussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.

The following are summaries of the specific public comments under this comment:75 Commenters stated that 40 CFR Part 60 Subpart B and the history of section 111 standards confirms a focus on individual sources, and commenters cited regulatory text from 40 CFR 60.22(b)(5) as requiring 111(d) proceedings to reflect highly subcategorized emission guidelines within a br oad source category like existing fossil fuel

- fired EGUs.

Comment 7 : Subcategorization by coal type.

Response 7 : This comment is generally consistent with the EPA’s approach for building block 1, but for the reasons discussed in the preamble, the additional reductions from building blocks 2 and 3 are available and important to obtain. We address our authority to subcategorize in the preamble.
The following are summaries of the specific public comments under this comment:

Commenters argued that EPA is expressly authorized to subcategorize among units by its own regulations. See 40 C.F.R. section 60.22(b ) ( 5). Commenters said an analysis of the CO 2 emissions characteristics of coal units by coal type could identify groups of "top

- performing" units wit h low emission rates, reflecting specific design, operating, and other engineering aspects of the units. Commenters noted that a statistical analysis could determine the average emission rate of a subset of top

- performing units, such as the top 75th or 90t h percentile. Commenters said measurement, which would represent an emission standard under Section 111(d) that reflects the "best system of emission reduction," could be applied to all units burning similar coal types (e.g., bituminous/sub

- bituminous and lignite) to determine an emission limit applicable to all units in a particular subcategory, with "outside

- the

- fence" compliance flexibility at states' discretion. Commenters stated that this standard in turn could be converted by states to a CO 2 tonnage

r eduction goal that could be met using a combination of inside

- the

- fence or outside

- the

- fence

measures.

Comment 8 : Subcategorization by age of facility.

Response 8 : The EPA disagrees with the comment that the final rule should include a subcategory based o n the age of the facilities it seeks to regulate. Further discussion of the EPA’s approach to subcategorization can be found in the preamble to the final rule for existing sources in sections V.A and V.B.
The following are summaries of the specific public comments under this comment:

Commenters stated that the final rule should include a subcategory based on the age of the facilities it seeks to regulate because the Act requires consideration of the remaining useful life in setting section 111(d) standards, and the commenters believed that the age of an EGU determines a number of factors that EPA considers when determining whether sub

- categorization is appropriate. The commenters stated that sub

- categorization could be used to encourage the operation of newe r, more efficient EGUs, and the commenters believed it is reasonable for the76 final rule to include a subcategory of EGUs constructed after 1978 (i.e., facilities constructed after the Power Plant and Industrial Fuel Use Act took effect) because such subcat egorization would largely eliminate the threat of facilities being forced to shut down prior to the end of their remaining useful lives.

2. 7 OTHER

This section addresses comments received on other topics relevant to this chapter.

Commenters have raised a number of issues related to this subsection which are organized by topics (comments) below. Responses are provided for these topics.

Comment 1 : Support for e xclusion of Integrated Gasification Combined Cycle units from implementing building block 1 requirements.

Response 1 : The EPA thanks the commenters.

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

Commenters supported the proposal to exclude Integrated Gasification Combined Cycle units from implementing building block 1 requirements for the reasons cited in the preamble to the proposed rule and the technical support documents.

Comment 2 : Inclusion of unit’s combusting coal refuse fuel

. Response 2 : This final rule does not include an exemption for coal refuse

- fired units. See section III.E of the final rule preamble of the NSPS for discussion of the use of coal refuse as fuel.

The following are summaries of the specific public comments under this c om ment:

Commenter s urged the EPA to provide an exemption for coal refuse

- fired units because,
commenters assert ed , EGUs that burn over 75 percent coal refuse on an annual basis have no net GHG emissions in the long term since unused coal refuse piles are con stantly burning due to their size and exposure to atmospheric oxygen. Commenters stated that there are multiple environmental benefits gained from remediating coal refuse piles and that exemption of EGUs firing coal refuse is consistent with Building Block 3. Commenter s , resident s that ha ve personally witnessed the benefits of remediating numerous legacy, abandoned waste

- coal sites around the ir states ’ coal fields, stated that EGUs that use waste

- coal should be exempted from the federal guidelines because u se of waste coal to generate and sale electricity has provided the funds necessary for the State of Pennsylvania to recover from their "number o ne environmental catastrophe."77 Commenters stated that the final rule should include a subcategory for EGUs that burn coal refuse in circulating fluidized bed (CFB) boilers because this unique technology was developed to accommodate use of fuels with widely disparate and variable characteristics and because reclamation of abandoned coal

- refuse piles (that otherwise a uto

- ignite and release GHGs with no beneficial heat recovery) has unique nonair quality health and environmental benefits that must be considered by the EPA and states under section 111(a)(1). Commenters stated that these EGUs must be located close to lega cy coal

- waste piles because it is not cost

- effective to ship the coal

- refuse which has a high weight percentage of inert material and a corresponding low energy density. Commenters stated that CAA section 111(d) authorized the EPA to promulgate federal gui delines for SIP

- like plans that establish state standards of performance for existing sources that meet the same applicability criteria (other than the date of construction or modification) established for new sources under section 111(b). Commenters stated that section 111(d) requires the EPA to permit each state to apply a standard of performance on a case

- by

- case basis to any particular existing source that considers, among other factors, remaining useful life. Commenters quoted the CAA section 111 (a)(1) definition of "standard of performance," and
commenters concluded that the sum of the statutory requirements under paragraphs 111(d) and 111(a)(1) requires federal and state authorities to consider, among other factors, (1) the degree of emission re ductions achievable at individual existing sources; (2) the cost of achieving reductions; (3) nonair quality health and environmental impacts; (4) energy requirements; and (5) the remaining useful life of the existing sources to which a standard would appl y. Based on these statutory requirements under section 111(d) and 111(a)(1), commenters believed that the EPA should establish a subcategory for coal refuse

- fired power plants under both the new and existing source rules. For existing coal refuse

- fired pow er plants, commenters believed that the plants should not be included in the BSER calculations or the state goals due to the variability of coal refuse quality and the lack of a coal refuse market (unlike commercially sold coal) and because coal refuse

- fir ed plants should be treated as carbon neutral. Commenters recommended that the final rule require existing coal refuse

- fired plants to meet work practice standards that require routine boiler tune

- ups to maintain efficiency in accordance with good engineer ing practices. Commenters stated that any standard issued under section 111(d) that would inhibit coal refuse

fired power plants from reclaiming abandoned mine sites would not be the best system available based on paragraph 111(a)(1) criteria for nonair qu ality impacts. Commenters also cited the factors listed under 40 CFR 60.22(b)(5) as supporting a set of different emissions guidelines for coal refuse CFB units, and commenters cited the definition of "emission limitation" in CAA section 302(k) to support a work practice standard for coal refuse CFB units.

Commenter s stated that the final rule should include a work practices standard for coal refuse CFB units that may include the following elements:

1. Inspect the burner and combustion controls.

2. Inspect the combustion process.

3. Observe damper operations as related to primary air, secondary air and cyclone performance.

4. Evaluate windbox pressures, bed pressures, and furnace differential pressure and air proportions.78 5. Make adjustments and perform repairs to dampe rs, actuators, controls and sensors where needed.

6. Inspect the system controlling the air

- to

- fuel ratio to ensure optimization of regulated emissions and energy efficiency.

7. Maintain pre /post documentation.

8. Periodic inspection of the balance of plant (e.g., the steam and condenser systems and turbines) to identify potential leaks or other conditions warranting maintenance, repairs or replacement.

9. Sources would prepare and submit to EPA or state permitting authorities annual reports as to implementation of t he work practice and related corrective measures.

Commenter s stated that from a CO2 emissions perspective, coal

- refuse fired units should be considered carbon neutral for the following reasons:

• Coal refuse

- fired units are limited to using coal refuse withi n a 100 mile radius of the plant.

• The coal refuse piles that provide the fuel for the plants have auto

- ignited and burned in the past; some are burning now, and if not used for fuel will burn (uncontrolled and unutilized) in the future.

• Reclamation and re

- vegetation of these sites allows the sites to become carbon sinks.

• Pennsylvania's Alternative Energy Program recognizes coal

- refuse as a renewable/alternative energy beneficial to the Commonwealth.

Commenters stated that EPA should ensure that the rule in cludes protections to ensure that states like Pennsylvania cannot exempt dirty energy sources under the plan's framework because these exemptions would severely undermine the purpose of the EPA plan. Commenters stated that PA Department of Protection is co nsidering exempting coal waste plants from the program, even though they emit large amounts of carbon pollution.

Commenters stated that PA describes coal waste as carbon neutral which is not true. Commenters explained that coal waste burning is a significa nt source of carbon in PA, and at its most efficient, coal waste emits as much CO2 as a conventional coal power plant, and many plants are not operating at maximum efficiency. Commenters noted that Pennsylvania's white paper (describing how they propose to meet CO2 limits) also describes coal waste as essentially carbon neutral, which not correct. Commenters said that of the 18 coal waste burners in the country, 14 are in Pennsylvania, and this is a source of carbon significant in Pennsylvania that the EPA must consider in developing its 111(d) criteria. Commenters closed, stating that at its most efficiency, coal waste emits as much carbon dioxide as a conventional coal power plant and many plants are not operating at a top efficiency.79 Comment 3 : Retired EGUs, Comment for Supplemental Proposal

- Tribal and Territories

Response 3 : Affected EGUs in areas of Indian country have to meet the emission performance rates or the goal for the specific area of Indian country. They are not treated differently from affected EGUs in states. We are not setting goals for any of the territories (or Alaska or Hawaii), so affected EGUs in the territories do not have to meet any requirements.

The following are summaries of the specific public comments unde r this c omment:

Commenter s supported all the building blocks proposed by the EPA and expansion of those building blocks to include retirements, natural gas co

- firing and retrofit CCS opportunities plus reduced utilization of certain designated facilities. Commenter s believed that use of these expanded building blocks should be used to calculate target rates for all jurisdic tions. Commenters believed that carbon capture and sequestration retrofit and new build opportunities are available in Indian country an d should be included in building block 1. Commenter s believed that the baseline from which reductions are measured should be reduced to reflect any EGU that is retired prior to the date of submission of a territorial or Indian country plan. Commenters beli eved that the federal guideline should only allow states to include EGU retirements that occur after the date of submission of their BSER determinations (i.e., the date of submission of their paragraph 111(d) state plans) because such a guideline will enco urage territories and tribes to submit their CPP compliance plans as early as is practicable. Commenter s believed that designated facilities that are no longer operating must either permanently retire, and relinquish their air permits or they must be inclu ded in the jurisdiction's section 111(d) plan, and
commenters discussed why they think the approach that EPA is taking with idled units on the U.S. Virgin Islands (that may still hold valid Title V air permits) is the wrong approach.

Comment 4 : Inclusion of Federal and state

- owned units.

Response 4 : The final rule does not provide an exemption from applicability based on ownership. Federal units are not exempt from the requirements of the rule.

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

Commenter s urged that the proposed standard be amended to include in its scope the regulation of existing government

- owned or operated power plants like the Capitol Power Plant. Commenter s stated that facility still occasionally burns c oal. Commenter s said please do not exempt Federal or any unused District of Columbia based facilities from this standard. Commenter s stated the C apitol should be required to comply with EPA regulations.

Comment 5 : Use of appropriate atmospheric lifetime for methane GWP.

Response 5 : A response is not required here as this comment is outside the scope of the rulemaking.80 The following are summaries of the specific public comments under this c omment:

Commenters cited a recent analysis (by the IPCC in its Fifth Assessment Report) that methane is 34 times more potent

- pound for pound

- than carbon dioxide as a greenhouse gas over one hundred years and 86 times more potent over twenty years

- the most cr itical timeframe for taking action to avoid climate catastrophe. Commenters stated that climate scientists agree that rising levels of greenhouse gas in the atmosphere are causing the Earth to rapidly approach critical tipping points, beyond which major ch anges are likely irreversible due to environmental feedbacks, such as the melting of sea ice or thawing of permafrost, which further accelerate climate change, and commenters believed this makes the powerful global warming potential (GWP) of methane over t he next two decades extremely damaging. Commenters disagreed with the analyses that supported the proposal because commenters believed the proposal's analyses discounted these effects by using an outdated GWP calculation for methane, and by focusing its

an alysis on the less

- important hundred year timeframe.

Commenters also stated the proposal ignored the greater impact of methane (compared to CO2) on a 10 year timeframe, and commenters stated that use of a 100 year GWP factor was inappropriate and that a 10 year GWP factor of 125 should be used.

Comment 6 : Final r ule should address emission s of methane

.
Response 6 : See section III.G of the final rule preamble of the NSPS for the EPA’s response to this comment.

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

Several commenters noted that the rule should include limits for emissions of methane.

Commenter s stated that methane, a greenhouse gas 86 times more potent than CO2 in the first 20 years after it is released into the at mosphere

, could undo the benefits of the coal

- to

- gas switch if it is not captured and controlled, and the tools currently exist to do this in a cost

- effective

manner.

Commenter s hoped that eventually the EPA will address methane emissions. Commenters state d additional EPA regulations are needed for the potent greenhouse gas, methane. Commenter s urged the EPA to finalize the proposed limit on carbon emissions as soon as possible, and then move on to additional protections needed to curb methane and other gre enhouse gas emissions. Commenter s stated that while they recognize d that the proposal is designed to address carbon emissions within the power sector, they strongly urge d the EPA to immediately draft rules that address methane. Commenter s stated it is an e xtremely dangerous and potent greenhouse gas that really need s a comprehensive plan if to avert catastrophic climate change.

Commenter s urge d folks on the issue of methane. Commenter s said methane is such a more potent greenhouse gas than carbon

, that lim its on methane are needed , or s ome plan to reduce methane is needed , because that is also fast tracking us on the path towards climate destruction.81 Commenters believed that additional regulations are necessary to complement use of building block 2; these c ommenters believed that the EPA must develop regulations to reduce fugitive emissions of methane from coal, oil, and natural gas production, transmission, and distribution systems. Commenters believed that building block 2 will accelerate development of na tural gas resources in the U.S. with potentially significant increases in GHG emissions as methane. Commenter s stated that natural gas developed from fractured rock is four to five times cheaper than most fuels and that producers have ample profit margins to cover the cost of adverse environmental impacts and mitigation of fugitives. Commenter s also cited studies indicating the high fugitive emission rates associated with fractured rock natural gas practices makes use of natural gas equivalent or worse than coal on a global warming potential basis.

Commenters stated that while they understand that focusing on carbon emissions from power plants is the Presidential mandate, focusing on carbon emissions to the exclusion of methane emissions is problematic. Com menters stated methane is also a potent greenhouse gas and it contributes to climate change. Commenter s stated that focusing on carbon alone is like checking your car's gas tank and ignoring the oil level when the check engine light is on. Commenters stated clean power must focus on both methane and carbon emissions. Commenters stated to the extent power pl ants use natural gas, and currently about 30 percent of our power plants already do, it is imperative that the EPA promulgate and enforce regulations to ensure that the best available control technologies are used to detect, prevent, and control methane le akage from power plants and related infrastructure.

Commenters believed there need to be EPA rules to address the incredibly potent greenhouse gas of methane. Commenters indicated that in Pittsburgh, they have an aging infrastructure that leaks methane, an d for every ton of CO2 the EPA rules prevent, and the equivalent amount of methane is 80 times more destructive in our atmosphere. Commenters stated rules on other greenhouse gases are a necessary next step.

Commenters were concerned that a project that their company completed after 2012 to capture and use vented methane from a coal mine will count as a carbon increase under the proposed rule.

Commenter s stated that the EPA cannot change a market based generating system by passing a rule because that woul d bust the basic principle of the market in Texas and that market forces may determine that the cheaper sources of electricity can no t displace gas or coal.

Comment 7 : F inal rule should address methane emissions from oil and gas production.

Response 7 : See section III.G of the final rule preamble of the NSPS for the EPA’s response to this comment. See section V

. D of the final rule preamble of the CPP for the EPA’s response to this comment.

The following are summaries of the specific public comments under this c omment:82 Numerous commenters indicated that the final rule should address methane emissions from oil and gas production.

Commenters opposed the proposal because of building block 2 and the heavy reliance on expanding the use of natural gas for electr icity generation. These commenters believe d that increasing the demand for natural gas will increase natural gas venting and fugitive emissions of methane from natural gas production, transmission, and distribution. These commenters believe d that the agenc y must simultaneously promulgate GHG standards for reducing natural gas venting and fugitive emissions from natural gas systems. Commenters stated that the proposal to designate natural gas and nuclear power as BSER is not based on a documented, internally consistent, or fair analysis because the proposal relies heavily on natural gas for carbon emission reductions. Commenters stated that the proposal was based only on industry data for venting and fugitive methane emissions, and the proposal ignores peer r eviewed literature that indicates much higher methane emissions from venting and fugitive sources.

Commenters opposed finalizing the proposed rule before the EPA also promulgates a standard for natural gas venting and fugitives because if the proposed rule was finalized large

- scale investments in new gas

- fired power plants would soon follow. Commenters we re concerned that further study by the EPA on fugitive emissions from fracking may indicate emissions are much higher than the estimates used for the propo sal, and commenters were concerned that curtailing fugitive emissions from fracking may be an intractable problem. Given these concerns,
commenters stated that the Agency will not be in a position to reverse course and require the newly constructed gas pla nts to retire. For these reasons, commenters believed that fugitive emissions associated with shale gas must be addressed in the proposed rule.

Commenter s , regional network s of grassroots community organizations, stated that the proposed rule encourages fu el

- shifting from coal to natural gas without considering the significant environmental, public health, economic, and societal harms related to the extraction of natural
gas. Commenters stated that gas development today

, which often involves the dangerous p rocess of horizontal high

- volume hydraulic fracturing ("fracking")

, is largely unregulated and enjoys broad exemptions from landmark environmental laws, including the Clean Air Act, the Safe Drinking Water Act, and laws regulating hazardous wastes. Comment ers stated that the proposed federal guidelines under CAA section 111(d) go to great lengths to describe the benefits of reducing coal consumption, but the proposed guidelines fail to evaluate the negative consequences of increased natural gas production a nd related infrastructure, including air and water contamination, unsafe waste disposal, earthquakes, ecological impacts, and damage to roads, property, and communities caused by the boom

- bust cycle inherent to extractive industry. Commenters also submitte d a recently assembled compendium of fully

- cited reports, studies, and articles compiled by Concerned Health Professionals of New York, which describe the many risks and harms of fracking, including its impact on climate change.

Commenter s believed that t he proposed rule's endorsement of natural gas as a strategy for combating climate change is fundamentally flawed and not supported by science. Commenters disagree d with the proposal's characterization of natural gas as "clean" because commenters believed t hat the best science shows that systemic venting and leakage of methane that occurs during extraction, processing, and transport, along with carbon dioxide released during its combustion, substantially or completely offsets the benefits that natural gas

- fi red generation has83 over coal

- fired generation with respect to climate change. Commenters recommended that the entire supply chain for gas development should be considered as a single process in analyses published to support the final federal guidelines for state plans.

Commenters stated that the environmental concerns regarding the use of fracked natural gas are numerous and deserve the agency's attention in conjunction with adoption of these guidelines. Commenters stated that if the goal is to reduce green house gas emissions, then the expected increase in emissions of methane associated with production, transmission, and burning of fracked gas must be fully accounted for, and if the goal is to achieve a healthier environment, then the increase in air and wa ter pollution associated with the production, transmission, and burning of fracked gas must be accounted for and remedied. Commenters provided a link to a compendium of the scientific, medical, and media findings that demonstrate the risk and harms of fra cking.

Commenters stated that it is crucial that methane pollution from natural gas production and transport be accounted for and reduced as part of an overall strategy to reduce carbon emissions and combat climate change, and President Obama has committed to taking action on methane as part of his Climate Action Plan. Commenters stated that it is vital that EPA, along with its sister agency the Department of Interior's Bureau of Land Management, move forward with strong rulemaking to limit methane pollutio n from new and existing sources of natural gas and oil production on both public and private lands; otherwise, emissions reductions from use of natural gas at power plants may not be realized.

Commenters stated the proposed rule for existing power plants i s only a first step in fulfilling our obligation to protect the health of our residents while meeting the challenge of climate change. Commenters urged the EPA to continue to take action in regulation of methane emissions as prescribed in the Climate Actio n Plan from March 2014 Strategy to Reduce Methane Emissions. Commenters stated that according to the IPCC, methane as a greenhouse gas is more than 80 times potent as carbon dioxide over a 20

- year period. Commenters stated that wellheads, pipes, valves, pr essures, and even abandoned wells are releasing increasing volumes of methane into our atmosphere. Commenters stated that about 30 percent of all methane emissions are derived from natural gas and petroleum systems. Commenters stated that best practices an d appropriate regulation must be enacted and enforced to reduce this greenhouse
gas. Commenters stated the EPA must assume responsibility for setting the standards to minimize the risk.

Commenters provided comments pertaining to promoting natural gas as a clean alternative to coal in the Clean Power Plan. Commenters stated that by not including limits on methane emissions as well, the EPA is diluting its efforts to reduce global warming. Commenters noted methane is more potent greenhouse gas than carbon. C ommenters stated that when total lifecycle methane emissions from fracked natural gas are included, burning natural gas is equivalent to burning coal in terms of global warming. Commenters stated the EPA has underestimated methane emissions significantly. Commenters stated methane, like carbon, is a greenhouse
gas. Commenters indicated it is a more potent greenhouse gas than carbon, 100 percent more potent because of the way it works in the atmosphere over a 20

- year period. Commenters stated fracking for na tural gas results in releasing unburned methane at all stages of the fracking
process. Commenters stated that experts tell them that if total methane emissions throughout the84 lifecycle of fracked natural gas reached three percent and has a fuel that is eq ual to burning coal in terms of global warming. Commenters indicated the most conservative average for methane released during the lifecycle of fracking is 5 percent to 7 percent, well above the 3 percent. Commenter s stated the EPA's own study entitled "Im provements needed and EPA Efforts to Address Methane Emissions from Natural Gas Distribution Pipelines," issued on July 25, 2014, cautions that methane emissions from pipelines have been grossly underestimated. Commenter s noted a study entitled "Methane Le akage from North American Natural Gas Systems," published in the February 14, 2014, issue of the Journal of Science synthesizes diverse findings for more than 200 studies ranging in scope from local gas processing plants to total emissions from the US and Canada. Commenters quoted the article, "People who go out and actually measure methane pretty consistently find more emissions than we expect," says the lead author, Adam Brandt. Commenter s also quoted, "Atmospheric tests covering the entire country indic ating emissions around 50 percent more than the EPA estimates," said Brandt, and that is a moderate estimate. Commenters stated the EPA estimates are based on voluntary reporting of methane emissions from the natural gas industry.

Commenters stated that it is important that the EPA include the release of all greenhouse gas emissions, not just carbon dioxide in its regulations. Commenters stated methane gas, released by high

- volume horizontal hydro

- fracking is 80 times more potent a greenhouse gas than carbo n dioxide in the first 20 years of its release to the atmosphere. Commenters stated NASA scientists have found that methane may actually have as much as 105 times more potency than CO2 in the same period. Commenters stated the EPA, however, has been using a much shorter 100

- year time frame and, thereby, calculates the effect of methane as only 20 to 25 times more potent than carbon dioxide. Commenters stated due to the potency of methane, any leakage of the gas of more than two percent makes it a more dange rous greenhouse gas than carbon dioxide. Commenters stated studies by NOAA of methane leakage from high

- volume horizontal drilling for gas in the western U.S. shows annual leakage of between 2.3 percent and 17 percent from drilling and venting along pipeli nes, compressor stations, and storage facilities. Commenters indicated the fracking industry itself admits that some 5 to 7 percent of its high volume wells leak in the first year of their drilling, and that after 30 years, up to 35 percent of its wells le ak methane. Commenters stated that a recent study from the magazine Science, finds that the EPA has seriously underestimated the release of methane from fracking. Commenter s indicated that to define methane gas obtained from high

- volume, high

- pressure hyd ro

- fracked wells as clean energy is erroneous.

Commenters cited a study by Robert W. Howarth entitled "A Bridge to Nowhere: Methane Emissions and the Greenhouse Gas Footprint of Natural Gas" published in Energy Science & Engineering in April 2014 (availabl e at http://onlinelibrary.wiley.com/doi/10.1002/ese3.35/pdf). Commenters stated that measurements by the NOAA and several other independent analyses indicate that at least 3 percent and potentially more than 7 percent of methane from natural gas is lost t o the atmosphere prior to burning

- far exceeding EPA estimates. Commenters stated that based on the most recent IPCC 20

- year GWP for methane, a leakage rate of 2.8 percent or higher actually causes natural gas to be more damaging than coal as a driver of climate change.

Commenter s cited a study by Robert Howers, et al, from 2011 that concluded fugitive emissions and production losses of methane from natural gas fractured rock production practices have a85 higher climate change impact than coal

- fired combusti on. Commenters stated that the EPA has ignored this study and other studies that reached similar conclusions. Commenter s stated that the problem with looking at the 100

- year time period instead of the 20

- year time period was summed up in an article by Joe Ron aptly titled, By the Time Natural Gas has a Net Climate Benefit, You Will Likely Be Dead and the Climate Ruined.

C ommenters stated that a full review of available data indicates that the level of emission reductions achievable by the proposed federal guideline may be negated by the greenhouse gas impacts of expanding natural gas production and associated venting. Commenter s stated that the final rule should include accurate calculations of the expected increases in GHG emissions from the natural gas se ctor from implementing building block 2) corrected for the GWP of methane over a period of 10 years to ensure the switch from coal to natural gas will have the intended effect on climate change. Commenters also stated that the leak rates assumed in the pro posal for natural gas systems are incorrect based on atmospheric measurements taken by NOAA in 2012. Commenter s stated that the measurements by NOAA indicated leak rates ranged from 4 to 18 percent in various regions compared to the 2.5 percent leak rate u sed for proposal. Commenter s also referenced a series of articles by two Cornell professors, Dr. Tony Agrafia and Dr. Robert Howorth that corroborated the leak rates published by NOAA.

Commenter s stated that only EGUs that can show they burn natural gas t hat is supplied by production, transmission, and distribution systems with a leak rate of less than half a percent should be allowed to displace coal units under building block 2. Commenters stated that the Environmental Defense Fund and the University of Texas have shown that a leak rate of less than half a percent is achievable when natural gas systems are properly operated.

Commenter s supported the use of building block 1 in the proposal and stated that greater reductions of carbon emissions at coal plan ts are available if power plants simply match the lowest emission rate actually achieved by the plant over the past decade.

Commenter s stated total lifecycle emissions from methane gas

- fired plants must be addressed. Commenter s said, methane is a greenhou se gas even more potent than carbon. Commenter s said, the rule does not address total lifecycle emissions from methane gas

- fired plants, including leakage during production, processing and transmission, emissions flaring at gas wells, and energy consumed i n production and transport of liquefied natural gas. Commenter s said, researchers found methane leak rates of 100 to 1,000 times greater than the EPA estimates at well pads in Pennsylvania, and the EPA's office of the Inspector General just issued a report citing the Agency's failures to manage methane leaks from pipelines.

Commenter s state d that while natural gas is seen as a bridge fuel by the Obama administration, in a State horribly wrecked by hydraulic fracturing, Pennsylvanians know it is not the answ er

. Commenter s stated methane escapes from natural gas drilling have a significantly greater global warming in the short term than carbon dioxide, according to NASA.

Commenter s state d , if the goal is to reduce greenhouse gas emissions, then the expected increase in emissions of methane associated with production, transmission, and burning of fracked gas must be fully accounted for.86 Commenter s call ed upon the EPA to properly calculate the greenhouse effect of methane gas over a reasonable timeline, as well as to measure the release of methane from the high

- volume horizontal drilling technology. Commenter s indic a ted this will permit the establishment of CO2 equivalents for released methane and to accurately calculate the greenhouse gas effects of fracked met hane. Commenter s stated proper steps must then be taken to control methane release and, if necessary, actually to ban high

- volume hydro

- fracking.

Commenters, graduate students, urged the EPA to impose an immediate moratorium on additional drilling for oil and natural gas in Colorado because their colleagues at the university have empirical evidence that methane emissions are 60 percent higher than assumed for the proposal. Commenters believed the moratorium should stay in place until we have the science tha t proves beyond a doubt that it is safe.

Commenter s state d a range of studies have shown high level of methane leaks from gas drilling and fracking operations, undermining the notion that natural gas is a climate solution or a transition fuel. Commenter s n oted that major studies have concluded that early work by the EPA greatly underestimated the impacts of methane and natural gas drilling on the climate.

Commenter s stated that the EPA's estimate for methane contribution to climate change is too low. Commen ter s indicated the EPA has significantly underestimated emission rates of methane from active gas fields, and has underestimated the warming potential of methane. Commenter s noted the EPA must account for increases in the amount of methane emissions from g as

- fired power plants which result from coal

- fired power plants converting the gas or from new gas

powered plants. Commenter s stated the EPA's estimates for methane contribution to climate change still lag far behind scientific consensus, which deemphasize s the impact that the natural gas sector will have on climate change. Commenter s stated a recent study published in the National Academy of Sciences found that emissions rates of methane from active gas fields were 1,000 times higher than EPA estimates. C ommenter s stated the IPCC recently reported that methane is 86 times more potent at warming our planet than carbon over a 20

- year time period, while research by a NASA scientist shows that methane is 105 times more potent when including aerosol effects. Co mmenter s noted the EPA's global warming potential of 25 is inadequate for studying regulations. Commenter s indicated the lifecycle emissions from the gas industry may already be worse for the climate than coal. Commenter s stated methane emissions will inc rease if plants switch to natural gas when methane emissions from active gas fields are considered. Commenter s stated the EPA should also set methane emission reduction targets for oil and gas industry. Commenter s stated that in addition, the EPA must move quickly on setting ambitious methane reduction targets or regulations for the oil and gas industry.

Commenter s stated that the EPA has to step up and directly regulate methane, both from oil and gas and coproducing wells, during gas production, during gas processing, and during transport on new and existing wells.

Commenter s stated that the Clean Power Plan will n ot solve climate change in i solation. Commenter s indicated that as a nation, we will have to tackle methane leaks from oil and gas.87 Commenter s stated, if you know anything about fracking, the government has given their state [PA] over as a sacrifice zone to the natural gas industry, and commenters hope d at some point [EPA] will also regulate methane, which is a much more powerful gas than CO2.

Commenter s state d , one

- hundred miles away they are developing an oil field at an amazing pace in the Bakken Region of North Dakota and Montana. Commenter s indicated there is natural gas that is a by

- product and is simply being flared and wasted. Commenter s stated we should salva ge all the natural gas now being wasted. Commenter s st ated methane emissions are a greenhouse gas that must be looked at in addition to carbon dioxide. Commenter s indicated it is critical that the BLM's proposal to limit flaring and venting of methane and the EPA's methane pollution standards move forward. Co mmenter s noted that otherwise

, switching from coal to natural gas could make climate change worse, not better. Commenter s stated even with better controls on methane, though, promoting natural gas is not a good solution to climate change; energy efficiency and renewable energy are much better.

Commenter s stated that EPA should account for carbon dioxide equivalents, not just CO2 in order to encompass other greenhouse gases that are emitted from the extraction, storage, transport and generation components o f fuel combustion. Commenters cited, as an example, methane emissions that can be released during natural gas extraction and transport.

Commenter s urge d the EPA to act quickly to release meaningful standards for methane, particularly extraction of methane.

Commenter s state d that without including limits on methane emissions, the EPA will be leaving out a massively important source of greenhouse gas emissions. Commenter s note d that other witnesses have testified that methane has a severe impact on greenhous e gas versus carbon dioxide on the 20

- year term. Commenter s thought methane leakage, especially at the point of extraction is a major concern.

Commenter s state d the International Energy Agency tells us that two

- thirds of proven fossil fuel reserves must be kept in the ground to prevent potential catastrophic consequences. Commenter s noted this includes natural gas and oil. Commenter s stated about one

- third of the total U.S. methane emissions are responsible for greenhouse gas emissions [sic]. Commenter s add ed the new unconventional gas wells are also emitting toxins like benzene, and radon that are then sent through compressor stations and pipelines. Commenter s stated that several studies have shown that overall, methane emissions are considerably higher tha n official inventories report.

Commenter s stated that without sensible health based regulations for the unconventional, natural gas industry, the economic and health benefits of the proposed rule will be undone and create potentially equally daunting chall enges for future Pennsylvanians. Commenter s indicated the EPA and Pennsylvania DEP should (1) require best available technology for capturing unintended methane emissions, green completions and close wastewater systems; (2) create systems and enforcement f rom monitoring of well bore integrity; (3) weigh out health protective, well permitting guidelines; (4) enforcement authority and resources for state and local agencies to oversee this emerging industry; (5) transparency around reduced water components and disposal systems; and (6) a prospective epidemiological investigation of potential health effects which are to date unknown and under investigated.88 Commenters believed that replacing coal with natural gas is not a valid solution to climate change and the only long

- term solution is for the U.S. to rapidly develop renewable energy systems that will quickly free us from dependence on all fossil fuels. Commenters believed this approach makes both environmental and economic sense. Commenters believed the final rule should reflect the potential for using renewables. Commenters opposed regulating methane losses in a later federal regulatory action (separate from the current 111(d) action) because the proposed 111(d) rule could lead states to ignore the potential c limate benefits of renewables and to make decisions about long

- term investments in electricity generation based only on combustion emissions. Commenters believed states may make poor choices in their 111(d) plans if they are not presented with all the fact s about methane losses. Commenters noted that the proposal's Regulatory Impact Analysis (RIA) indicated the rule would boost the amount of additional electricity generation from natural gas by nearly ten times the gain projected for renewables before 2020. Commenters believed that by accelerating EGU investments in natural gas in the near

- term, the plan could tip the scales toward fossil fuels for decades to come, and
commenters believed that once gas

- fired plants are in operation, there will be less incent ive for utilities to reinvest in renewables because the capital outlay for gas infrastructure will have already occurred.

Commenters requested that the EPA protect us against harmful methane and fracking. Commenter s stated natural gas is not the answer; cl ean, renewable energy is the answer.

Commenters stated that the nation needs to dedicate substantial resources to the research and development of technology to store energy generated from wind and solar on a large scale in order to move past the fossil fue l age.

Comment 8 : Innovative projects for converting methane to electricity.

Response 8 : EPA does not agree th e BSER should include measures that reduce non

- carbon dioxide greenhouse gas emissions. BSER measures reflect those strategies and measures that reduce emissions at the affected source.
The following are summaries of the specific public comments under this c omment:

Co mmenters stated that the final rule should be more flexible and allow the use of technologies to reduce other greenhouse gas emissions that are more potent than CO2. Commenters believe d the use of a carbon dioxide equivalent should be allowed in the develo pment of the state plans such as allowing programs for controlling fugitive methane emissions from landfills and confinement feeding operations, then using the captured methane to produce electricity.

Commenter s , state air quality permitting authorit ies , s tated that the proposed federal guideline hinders technological innovation by not providing adequate flexibility, credit, or incentives for. Commenters stated that under the New Source Performance Standard and Emission Guidelines programs, the EPA must est ablish emission standards (consistent with the definition under section 111(a)(1) based on the Best System of Emission Reduction and must consider whether such a standard promotes the development of technology (consistent with Sierra Club v. Costle89 (D.C. C ir. 1981)). Commenters stated that the proposed federal guidelines do not allow states to take credit for non

- carbon dioxide greenhouse gas emission reductions, making it more difficult for states to invest in new emission control technologies and stifling technological innovation. Commenters requested that the final rule allow state 111(d) plans to take credit for non

- carbon dioxide greenhouse gas emission reductions that reduce electricity demand. Commenters provided the following example: collection of m ethane from landfill gas and livestock operations for use in combustion engines to generate electricity. Commenters stated that Nebraska's potential for methane capture is vast because the state had 6.4 million cattle and 3 million hogs in 2012, ranking 2nd and 6th in the nation, respectively. Commenters stated that Nebraska currently has one methane capture and combus tion system at a livestock operation which provides 80 kilowatts of installed electricity capacity and reduces methane emissions by 107 metric tons/year (2,228 metric tons carbon dioxide

- equivalent per year). Commenters stated that utilities and livestock operations in Nebraska have expressed interest in deploying additional methane capture and combustion systems, but cannot justify their high capital costs without adequate credit for GHG emission reductions under the Clean Power Plan. Commenters stated tha t since the global

warming potential of methane and other non

- carbon dioxide greenhouse gasses is many times greater than carbon dioxide, allowing states to take credit for reducing these emissions would increase flexibility in state plans, reduce the burd en on regulated sources, and bolster the emission reduction goals of EPA's Clean Power Plan. Commenters requested that the final federal guideline allow these types of innovative projects as compliance options in state plans.

Comment 9 : Supply chain LNG p rojects

Response 9 : As explained in section VIII of the preamble, the EPA is not finalizing the proposed portfolio approach and any comments on that proposed approach to 111(d) state plan design are therefore moot. Instead, the EPA is finalizing an option to submit a “state measures” plan type, under which a mass CO 2 emission goal may be partially or entirely achieved through state measures that impose requirements on entities other than affected EGUs that are not included in the federally enforceable 111(d ) state plan, provided the state submits standards of performance for CO 2 emissions from affected EGUs in the form of a federally enforceable “backstop” that would be triggered if the state measures fail to achieve the required CO 2 emission performance lev el. Under a state measures plan, the backstop emission standards constitute the standards of performance required by section 111(d), and the state plan provides for the implementation and enforcement of such standards of performance by specifying the trigg er mechanism and conditions under which the backstop emission standards apply to affected EGUs. Upon EPA approval of a state measures plan under section 111(d), the backstop emission standards become federally enforceable requirements, which EPA and citize ns may enforce against affected EGUs under section 113 and section 304.

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

Commenter s noted that there are a number of concurrent, ongoing efforts to bring natural gas to Fairbanks that may be compromised by the application of the CPP rule. As an example,
commenter s noted that the State of Alaska is investing approximately $350 million dol lars through the Interior Energy Project to bring liquefied natural gas (LNG) into Fairbanks by 2016.90 Commenters stated the work on this "supply chain" project includes construction of a North Slope LNG plant, securing long range transport contracts, incre asing community LNG storage capacity, expanding the existing limited natural gas distribution system in Fairbanks and starting a new distribution utility in the outlying area. Commenters noted that an important aspect of this effort would be engaging poten tial large anchor consumers of natural gas to purchase the LNG from this project. Commenters stated that converting from liquid fuels to cost

- effective natural gas for local electrical generation would help to solidify the economics of the natural gas proj ect, thus helping to ensure that cleaner burning fuel would also be available for distribution for space heating through a local utility. Commenters noted that delivering natural gas to Fairbanks and converting electric generation from liquid fuels would a lso reduce carbon emissions.

However, commenters noted that these extraordinary efforts would not qualify for inclusion in any state plan under this proposed rule. First, commenter s noted that these projects are not measures that could be "enforceable" or that should be subject to citizen suits. Second,
commenter s noted that many of the generators that may be affected by the arrival of natural gas in Fairbanks are diesel or naphtha units not covered by the rule. Third, to the extent these e fforts focus on space heating, commenter s noted that those measures would not reduce emissions at

" affected EGUs " and would not be credited to the state.

Commenters argued that, as with the retirement of the Healy coal units, disrupting Alaska's plans to bring natural gas to Fairbanks may have the irrational result of contributing to air quality problems. Commenters stated a portion of the Fairbanks North Star Borough, including the cities of Fairbanks and North Pole, is designated as a fine particulate matter nonattainmen t area.

Commenters noted that space heating from wood, coal, and fuel oil all contribute to the issue. Commenters stated one of the challenges in reducing PM2.5 air pollution in these communities is a lack of available, affordable, cleaner

- burning natural gas in the community. Commenters noted that the increasing cost of electricity in this region has contributed to a significant increase in the use of wood burning stoves for space heating, increasing both particulate and carbon emissions as residents try d esperately to lower their overall monthly energy costs. Commenters argued that EPA's proposed rule would only further increase energy costs. By contrast, commenters noted that projects already being assessed in Alaska could have substantial benefits to the state and national economy while simultaneously reducing carbon emissions.

Comment 10 : Include natural gas

- fired reciprocating internal combustion engines under the final rule.

Response 10 : The EPA did not propose to include reciprocating internal combustion engines in the rule. In addition the majority of reciprocating internal combustion engines are smaller than 25 MW and would not be covered by the rule.

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

Commenters, air quality permitting authorities, recommended that the final federal guidelines should alter the proposed applicability criteria to allow states the option to include natural gas

-91 fired reciprocati ng internal combustion engines (RICE) in their state plans because this permitting authority has recently permitted several electric generating facilities (each with approximately 100 MW capacity) that are powered by sets of natural gas

- fired RICE. Comment ers stated that the estimated CO2 emission rate for these EGUs is less than 1,100 lbs/MWh which is significantly lower than the nominal goal of 1,499 lbs/MWh proposed for the State of Kansas in the year 2030. Commenters also recommended that states opting to include natural gas

- fired RICE in their state plans should be exempted from the requirement to install CO2 CEMS and that the final rule allow these sources to monitor CO2 emissions based on an approved mass balance.