From: Higgins, Cortney [mailto:Cortney_Higgins@omb.eop.gov] 

Sent: Wednesday, April 30, 2014 8:24 PM 

To: Wayland, Robertj 

Cc: Elman, Barry 

Subject: Interagency Comments on RIN 2060-AR33 (Preamble) 

Hi Bob, 

Attached are the “high level” interagency comments on the preamble. You will also be receiving 

comments on the RIA and TSDs, as well as line edits on the documents in redline. You should get 

all of them this week. As requested, I’ll be sending them over as they are compiled. 

Please let me know if you have any questions. 

Regards, 

Cortney 

 

________________________________________________ 

Cortney Higgins, PhD 

Policy Analyst 

OMB/OIRA/NRE 

202.395.7856 

chiggins@omb.eop.gov 

<< Interagency Comments under EO 12886 on RIN 2060_AR33_04302014.docx >> 
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The interagency reviewers recognize the tremendous effort that EPA has undertaken and appreciate the effort

as wells as the outreach program that they’ve undertaken.  Below are interagency comments, grouped by topic

area.  

Preamble

BSER

Building Blocks 1 and 2.  Can EPA take comment on, and provide analysis for, an approach that that

incorporates building blocks 1 and 2 only?  This will enable us and the public to understand the effects of the

parts of the rule that are most closely related to plant operations.  This would be in addition to the two lead

options, which considers building blocks 1 through 4.  Additionally, for such an approach, has EPA analyzed or

considered the costs and benefits of a tradeable permit system?

System Utilization. Has EPA considered using the term “limit utilization” rather than “reduce utilization” (see

p 115 for an example) throughout the document when providing an explanation and justification for the building

blocks approach.    

Scope. The four building block approach includes both “inside the fenceline” and “outside the fenceline” blocks

to reduce CO2 emissions from power plants.  Is there anything that prohibits EPA from adding other building

blocks, particularly those that would seek to reduce electricity demand in other sectors, such as the

manufacturing sector?  If reductions in non‐residential sectors are already included in building block four (EE),

please clarify. 

Severability. While EPA has explained that the building blocks are severable, the lack of analysis providing

costs and benefits of each building block may make it harder for the public, and possibly the court, to

understand how they are severable.  Could EPA provide analysis of each of the building blocks in order to

support their claim?  

Market Mechanism. Has EPA considered proposing a BSER that includes a tradeable performance standard or

cap and trade approach?  Some commenters note that a cap and trade system for mercury was finalized under

CAA 111(d) (known as CAMR), and it included trading between new and existing sources.  The commenters

understand that CAMR was overturned by the courts due to EPA improperly delisting the category under CAA

Section 112, but that the court never reached issues about the trading program.  Has EPA considered such an

approach? 

Upper Bound on Cost‐Effectiveness.  What is the maximum cost/ton CO2 reduced that EPA would consider

as “cost‐effective” for determining BSER?  How do each of the estimated costs (per ton) for the building blocks

compare to this amount?   

Building Block 1

Methodology. For the quantitative analysis of potential heat rate improvements, has EPA considered a

broader multivariate regression approach, using continuous variables, or other statistical techniques, to control

for variation including and beyond temperature and capacity factor?  For example, the current analysis does not

appear to control for power plant type or whether plants are dispatched for baseload or load following.  Absent

such a change in methodology, we recommend that EPA clarify the choice of independent variables, address

potential collinearity effects among them), and explain why certain other independent variables were omitted.  
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EPA’s estimate that only half of the potential heat rate improvements they identified would be feasible also

requires justification.

Methodology. EPA’s assessment of this potential relies on one S&L 2009 study and EPA’s analysis of efficiency

upgrades on only 2 out of 16 plants.  Are additional data available on upgrades at individual facilities?  We

suggest an econometric study such as "Regulating Greenhouse Gases from Coal Power Plants under the Clean

Air Act" by Linn et al, Journal of the Association of Environmental and Resource Economists 2014 (forthcoming;

also available as Resources for the Future discussion paper RFF DP 13‐05).  If EPA can find no further data or

analysis, EPA should consider discussing data limitations, justifying why the methodology used presents a

reliable estimate of existing practice, and soliciting additional data for the final rule. 

Costing. The costs from upgrades come for the Sargent & Lundy study, but it’s not clear what the costs of the

best practices are and where they come from – please clarify. 

Heat Rate Impact due to Cycling.  As EPA observes in the GHG Abatement Measures TSD chapter covering

heat rates (Chapter 2), the additional ramping and cycling caused by reducing the capacity factor of (baseload)

coal plants, could negatively impact heat rates and threaten attainment of the expected plant heat rate

improvements anticipated by building block 1.  EPA should clarify in the relevant section of the preamble the

extent to which these interactions are already included in the 6% heat rate target put forward in the context of

building block 1.  If EPA did not consider the impact of building block 2 or increased ramping and cycling caused

by reductions in demand, we recommend that EPA extend the lower range of heat rate improvements to 2% to

account for dispatch changes due to the rule.

Biomass co‐firing.  For purposes of compliance, how will emissions from biomass (co‐firing) be counted?  If

this is something that will be addressed in a subsequent determination (e.g. applicable to the GHG Tailoring

Rule), will EPA explain that in the proposal’s preamble?   

Commenters recommend further consideration of biomass co‐firing as a building block or part of a building

block for BSER, consistent with an all‐of‐the‐above approach.  In certain regions of the country, waste and

residue‐based biomass could be available at costs of less than $3/MMBTU.  Interagency commenters are happy

to work with EPA on this issue.

Additionally, as indicated in comments on the RIA, while EPA acknowledges that they have yet to determine

what the appropriate emission factors might be for categories of biomass, by selecting to weight biomass in a

similar manner to coal (195 lbs/MMBtu), EPA has severely limited the least‐cost optimization of the IPM model

and introduced an artificial barrier to allowing the model to select co‐firing of renewable biofuels as well as a full

transition to biofuels.

Also, EPA has explained to the interagency reviewers that concurrent efforts to develop EPA’s position on

lifecycle emissions from biomass have not concluded, thus precluding clear language on this topic in this

proposed rule. We would like clarification on whether EPA intends to develop clear language on the treatment

of biomass emissions in time for the final rule, or alternatively for supplemental guidance for state plans.

CCS. While EPA is not proposing to include CCS as part of BSER, in light of the 2030 deadline, CCS (especially in

conjunction with CO2‐EOR), could be an available compliance option for states to include in their

implementation plans if they choose to do so.  We recommend that EPA include a request for comment on what

guidance would be helpful for EPA to offer to states that wish to include this option in their state plans.
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Fuel Switching as part of BSER. Fuel switching is one of a relatively few emissions reduction strategies that

are “within the fence line” and aligned with the more traditional applications of the CAA. As noted in the

preamble, fuel switching may indeed be economical for some coal EGUs—particularly those with access to

natural gas. While nationwide fuel switching may not meet a reasonable cost‐effectiveness test, a smaller

amount of fuel switching may (this line of reasoning is applicable to renewable energy as well—an 80% RPS

would be cost‐prohibitive at this time but a 20% RPS may not be). Indeed, EPA notes in the preamble that the

largest cost driver is the difference in fuel cost between coal and natural gas. Yet this cost driver is also at the

heart of building block 2. A similar argument and line of reasoning could be used to suggest incremental new

hydropower should also be included in the BSER.  Under the draft proposed rule, fuel switching is not included in

the BSER. However, EPA solicits comment on whether it should be included. We would emphasize the

importance of soliciting comment here due to the issues outline above.

Building Block 2

Supplementing Discussion of Increased NGCC Use.  As EPA notes (p. 243‐4), one source of information that

could give a better indication of unit availability might be NERC data on planned and forced outages and

resulting availability factors. EPA should consider pulling forward this discussion into the relevant section on this

building block.

On p. 121 EPA states, “The EPA also examined the technical capability of the natural gas supply and delivery

system to provide increased quantities of natural gas and the capability of the electricity transmission system to

accommodate shifting generation patterns. [...]”  We request more detail about this analysis.  

On p. 122 EPA states, “The second reason supporting our view that gas and electric system infrastructure would

be capable of supporting increased NGCC unit utilization rates is the flexibility of the emission guidelines. [...]The

third reason supporting a conclusion regarding the adequacy of infrastructure is that pipeline and transmission

planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand capacity.”  

EPA should more carefully explain this and emphasize how proposed flexibilities in the rule would address this

concern.  

Re‐dispatching potential. Many commenters support EPA’s decision to request comment on NGCC capacity

factors of 75% and ask the following.  Is it possible for EPA to analyze scenarios where existing NGCCs are

allowed to reach higher capacity factors, specifically 75 percent, 80 percent, and 85 percent.  The current

proposal limits NGCC output from existing plants to a maximum capacity factor of 70 percent; however, NGCCs

are typically designed to run as baseload facilities, with capacity factors routinely exceeding 90 percent when

market conditions warrant that level of output.  Historic data may be misleading, as utilization rates may were a

function of gas prices, and the gas price outlook has changed in recent years.  EPA should specifically solicit

comments on each of these levels, not just 75 percent, and should invite comments on other levels that

stakeholders feel are appropriate as well.   

Interstate re‐dispatching potential. For the BSER determination, the proposal currently limits the analysis of

achievable re‐dispatch to EGUs within a single state boundary and asks for comment on relaxing that restriction.  

In order to bolster the fact base and seek more robust comments, EPA should include in the supporting

documents its analysis if redispatching across state lines in order to improve the quality of comments on this

issue. 

Increased Price.  On p. 128 EPA states, “which is well within the range of historic natural gas price variability.”  

This does not provide very much information, given large historical natural gas price variability. A comparison to

current or projected future prices would be more helpful. 
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Upstream GHG Emissions from Natural Gas The RIA indicates that EPA considered composite, system‐wide

GHG emissions, but that consideration is not evident in the Preamble.  As a result, we suggest that in the

Preamble, EPA separately discuss the upstream greenhouse gas emissions (including methane) from natural gas

production and distribution, natural gas flaring, and coal. 

Declining Use of New NGCC. EPA’s analysis shows that new NGCC capacity is reduced by between 26 and 35

GW in 2030 compared to the base case.  Has the commenter interpreted that correctly?  How does EPA arrive at

that estimate?

Building Block 3

New NGCC. Please clarify why EPA does not include new natural gas units to replace existing coal fired units at

the same facility in the calculation of potential carbon reductions.  Can states choose to use this approach to

meet state targets?

New NGCC potential.		The NGCC industry has added over 15 GW of capacity annually since 2000 and between

5 and 8 GW of new capacity in more recent years.  Yet EPA did not include new NGCC capacity in the BSER while

nearly all other forms of new generation were included. Has EPA considered including the construction of new

NGCC capacity in the BSER?  Can EPA explain why it has not been included?  Significant emissions reductions

have been obtained in recent years through construction of new NGCC units and it is reasonable to expect this

trend to continue particularly in the context of a power plant rule.   

If EPA were to consider this, one option would be to use historical data—an approach consistent with EPA’s

reliance on historic efficiency performance among top states in setting standards for all states under its current

approach to BSER. Specifically, on average 15 GW of NGCC were built every year from 2000‐2013, providing one

estimate of the minimum readily achievable pace of new construction.  Commenters suggest EPA include in the

documents analysis of scenarios that include 15GW of annual new NGCC construction through 2030 to help

inform commenters.

If EPA is not developing a specific alternative that accounts for new NGCC construction as part of the BSER

determination, we suggest expanding the existing request for comment to ask commenters to recommend

specific methods for establishing the level of NGCC that could be reflected in a BSER determination and perhaps

suggest some alternative methodologies that EPA is already considering.

Available RE Levels.  One commenter understands EPA’s rationale for using existing state RPSs to set state

target levels but notes that RPSs are not necessarily a good indicator of the full technical or economic potential

of renewable energy in a given state or region. While state RPSs may reflect best practices by some states, the

proposed RE targets in EPA’s proposed rule appear relatively easy to meet without taking into account any

external costs associated with CO2.  As such, they may have little impact on CO2 emissions compared with BAU.  

On a national level, DOE analysis suggests that existing RPSs lead to about 9% RE deployment in 2029.  Requiring

states to meet the max of their own RPS and the regional average, leads to about 15% in 2029. A DOE estimate

of market potential (without any new policies) would lead to a worst case of 16% but up to 30% in other

cases.  The approach proposed by EPA would result in only 13% RE penetration by 2030.   

The proposed renewable targets could be strengthened in states in the North Central and West regions.  

Forthcoming NREL analysis examines likely renewable energy deployment under various scenarios, none of

which consider the impacts of this proposed rule.  Under NREL’s worst case for renewable energy – low fossil
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fuel prices and low electricity demand and no improvement in renewable energy technology costs – collective

renewable energy deployment in 2029 in the North Central and West regions exceeds that of the proposed

rule’s combined target for the states in those regions.  In other words – even under conservative assumptions,

without additional policy, NREL’s model projects more renewable energy deployment in those two regions than

is included in the building block.  The commenter also notes that the proposed renewable energy target for

these two regions is less than would be achieved if every state in these regions achieved their existing

renewable energy goals in 2029.  

  

Using more aggressive assumptions – higher fuel prices and meeting DOE  renewable energy cost targets –

NREL’s model projects far greater renewable energy deployment in 2029 in the West (more than 50% of total

electricity generation), and regional numbers that exceed EPA’s targets in the North Central, Northeast and

South Central regions.  Again, this does not consider full economic potential (including the GHG externality),

which would lead to significantly greater renewable electricity generation.

Renewables methodology.  EPA should consider soliciting comment on alternative approaches for estimating

available reductions from new renewable energy generation.  One possibility would be benchmarking based on

fastest observed historical pace of deployment in each region and opportunities to account for state‐specific

constraints.  A couple of other approaches, which could be complementary, are discussed below.

EPA’s calculations of states’ potential for renewable energy appear to be missing a reasonable criterion:

geographic potential.  The geographical potential for renewable development as has been defined in numerous

studies (e.g., NREL's renewable energy potential: http://www.nrel.gov/gis/re_potential.html).  For example, EPA’s

approach allows AZ in 2030 to have a target renewable contribution of 3%, while NM, NV, and OR, states in the

same region as AZ, have proposed targets of 16%, 19% and 21%, respectively.  We suggest EPA add renewable

potential as a criterion to require additional effort from states that have not taken action to date.

In calculating this component of the BSER, EPA relies on estimates developed and legislated by states as proxies

instead of actually making its own expert assessment in consultation with DOE and FERC, despite EPA’s legal

argument that authority to set BSER is EPA’s and not the states’. We suggest EPA take comment on this specific

issue. Proposed language:

“EPA invites comment on whether existing state renewable portfolio standards are good proxies for renewable

energy development potential that is technically feasible and not unreasonably costly, or if EPA should make its

own assessment based on the best information available.”

Another commenter points out that using state RPSs as proxies may not be the best approach for determining

renewables potential, as it forces EPA to break the country into regions in a very broad‐brush way that may or

may not adequately account for state‐to‐state variation in available resources. For example, there appears to be

little justification for assigning Mississippi the same target as North Carolina but not as Louisiana or Arkansas.

The preamble lacks (to this reviewer) information explaining how EPA grouped states is actually a reasonable

approximation of state‐by‐state variations in renewable energy development potential within technical and

economic constraints.  Moreover, EPA’s approach applies (seemingly arbitrarily) North Carolina’s target to

Hawaii and Alaska (along with the entire Southeast), which could underscore concerns about lack of

methodological rigor. We suggest EPA take comment on this specific issue. Proposed language:

“EPA invites comment on whether the proposed regional groups are a reasonable reflection of regional

variations in renewable energy development potential that is technically feasible and not unreasonably costly,

and on potential alternatives for taking into account these variations in the computation of the BSER.”
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Using state RPSs as proxies adds an additional complexity in that it forces EPA either to use 2012 total

generation data for targets that are actually designed for 2020 (this is the proposed approach), or to peg targets

to projections of total generation (not currently proposed). In the methodology for calculating aggregate

renewable energy levels for each region for 2029 and beyond, the average state 2020 RPS requirements are

multiplied by total 2012 generation in the region. Given these 2020 RPS requirements are for renewable energy

generation as a portion of total generation in 2020, multiplying these regional averages by 2012 generation, and

then using the products as targets for 2029, has the effect of arbitrarily reducing the emissions reductions

associated with BSER relative to what states are actively demonstrating is feasible. If EPA made its own

assessment of renewable energy development potential (MWhs/yr) on a state‐by‐state basis, it would not be

necessary to peg targets to either past or projected total generation. 

For the purposes of clearly explaining and justifying the current proposal, we suggest EPA provide a clear

rationale in the preamble for pegging states’ 2020 targets to 2012 total generation, and using the resulting

targets for 2029 state goals.  In discussion, EPA has suggested it is simpler and less uncertain to use 2012

observed generation instead of projections for 2020. That justification may not withstand scrutiny as EPA is

willing to use generation projections in building block four.  Moreover, the states themselves have been willing

to take on the uncertainty of projections for 2020 total generation in setting their own targets. Accordingly, in

addition to providing the rationale for this methodology, we suggest EPA take comment on this specific issue.

Proposed language:

“EPA invites comment on the proposed methodology for calculating regional renewable energy targets,

including whether average state standards for 2020 should be multiplied by total 2012 generation to arrive at

targets for 2029, or whether average state standards for 2020 should instead be multiplied by projected total

2020 generation, or projected total 2029 generation, to arrive at targets for 2029.”  

New and Existing Treatment.  On p. 205 EPA states “We estimated the total quantities of new renewable

capacity and new or preserved nuclear capacity that would be made available in each state under “best

practices” approaches to renewable and nuclear capacity, and we estimated the MWh generation from this

incremental low‐ or zero‐carbon generating capacity based on historic utilization rates for units of the same

types.”  Please clarify whether this includes generation from existing capacity. State targets and language

throughout indicate that new generation from existing capacity might have been included, as well as existing

generation from existing capacity. Please also clarify throughout the document, for all forms of generation and

capacity, whether you are referring to increased generation from existing capacity and/or only generation from

new capacity. Use of the word “capacity” as shorthand for building block 3 is consistently unclear.

Existing nuclear. EPA should consider providing additional explanation to clarify why the preservation of

existing “at risk” nuclear generation is another means of achieving the ultimate goal of reducing emissions for

affected sources (existing fossil EGUs).  EPA may want to consider seeking comment on this particular legal

argument, if they aren’t already.  Additionally, it is difficult to use a set of license renewal applications not‐yet‐

filed as a fully suitable proxy for at‐risk nuclear capacity. EPA may want to consider alternative approaches, and

commenters would be happy to provide technical information related to the consideration of such approaches. 

Additional nuclear not considered. A number of nuclear facilities have economic uprate potential, as

demonstrated by uprate applications that were filed with the NRC or announced as forthcoming. Approximately

1.5 GWe of additional capacity had been actively pursued, though only 827 MW of that is pending at the NRC

with 290 MW actively moving through the process. While many of these modifications were placed on hold due

to market conditions, particularly low natural gas prices, a significant subset would likely provide a cost‐effective

abatement opportunity when used to displace more carbon‐intensive forms of generation. Other opportunities
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beyond those announced may also be cost‐effective. In addition, within the 2030 timeframe, there will be

additional opportunities for new nuclear power plant deployment that could be considered.

DOE currently has 7 applications for new nuclear power loan guarantees totaling 15.4 GW of new capacity, and

DOE is currently supporting licensing study of two small modular reactor designs that could have initial

deployment as early as the middle of next decade. EPA could reach out to DOE to assess these potential sources

of reductions and how they might be incorporated into a building block for BSER.

Other commenters share that there are currently 10 operating reactors for which the utility has not yet

submitted an application for a license renewal to extend operation to 60 years.  However, the utilities for 9 of

these reactors have provided letters of intent indicating that they plan to submit applications.  One of those

applications is scheduled to be submitted this month.  By using capacity data from the NRC Information Digest

(NUREG‐1350), we determined that those units for which applications for license renewal have not yet been

submitted represent 12% (rather than 8%) of the total existing U.S. nuclear generating capacity (35.2 GWth of

the total 304.4 GWth).  The table at the end of this document summarizes the Information Digest data.  

EPA is silent on subsequent license renewal—renewal beyond 60 years of operation.  It is our understanding

that the industry plans to begin filing applications to request up to 80 years of operation in 2018.

New Nuclear. With respect to new units, EPA identifies five new nuclear EGUs that are currently under

construction: Watts Bar 2 in Tennessee, Vogtle 3‐4 in Georgia, and Summer 2‐3 in South Carolina.  EPA is

proposing that the emission reductions achievable at fossil fuel‐fired sources due to the generation that would

be provided by these nuclear units under construction be factored into the state emission performance goal

through Building Block 3, effectively making them more stringent.  The inclusion of the five new nuclear units

that EPA has identified account for an inordinate amount of the goals that EPA is proposing for those states.

Should construction be delayed past 2020, it would present serious compliance issues for the states. As these

new units do come on‐line, the inclusion of all generation from these units in the state goal is problematic as any

prolonged outage would almost guarantee that any state relying on carbon‐free nuclear generation to meet its

annual carbon goal would fail to meet that goal. A better policy design would be to categorize these units as

existing in Building Block 3.

Incentives for clean generation.  Can EPA please explain or clarify to us the apparent different treatment of

clean generation in its approach for setting BSER and determining compliance.  It seems that the current

approach imposes different incentives for different forms of clean generation.  In particular, the denominator of

the equation used to determine state‐specific emission rates includes the following treatment:

 100% of existing non‐hydro RE and 100% of new non‐hydro RE

 0% of existing hydro and 100% of new hydro (for compliance, not BSER)

 8% of existing nuclear and 100% of new nuclear

 100% of existing NGCC and 0% of new NGCC

 0% of existing EE and 100% of new EE

 0% of new CCS

Other RE. State RPSs can exclude several types of renewable energy generation categories, including

hydropower, behind the meter renewables, and renewable electricity generated at or for federal facilities.  To

the extent that some classes of hydropower are not already included in individual state RPSs, the potential to

improve existing facilities or add new hydropower could be understated.  Distributed generation of renewable

energy is not automatically counted towards compliance with RPS requirements in some states, like California.  
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In 2013, the United States installed a record 1.9 gigawatts of distributed solar, so it may be important to capture

these additions in state targets.  Finally, Federal agencies are required to use renewable energy sources to meet

a percentage of their facility electricity needs from renewable energy sources, and are prohibited from using the

associated renewable energy credits to comply with state RPSs.  We suggest EPA consider methods and/or seek

comment to incorporate these aspects of the renewable electricity landscape into BSER.

Distributed Solar Energy.  For the demand‐side energy efficiency measures, please clarify how distributed

solar generation will be considered, and if states may use distributed solar generation to meet the overall state

targets.  We ask EPA to include a discussion in the Preamble regarding the environmental and distribution

system tradeoffs of centralized solar energy generation (supply side) versus distributed solar generation

(demand side).  .  Distributed solar generation on residential, commercial, institutional and industrial facilities

has much lower requirements for transmission and distribution systems and much lower environmental impacts

for wildlife habitat, scenic views, night skies and other impacts near national parks than new centralized solar

generation.

Hydropower.  We request clarification that hydropower generation in a state qualifies for meeting the RE

targets.  We hope this will be clearly stated in the Preamble and elsewhere as appropriate.  Hydropower is the

Nation’s most available, reliable, affordable, and sustainable energy source.  We recognize that historic

hydroelectric power does not qualify for RE credit under many state RPSs.  We also recognize that the state RPSs

have a variety of approaches to new hydro, but it is very important to recognize that almost all states count it as

an RE in some respect.  We believe it may be acceptable to generally use state RPS requirements, but would like

some clear support for the proposition that all new hydropower generation – either increased output at existing

facilities, or new hydropower generation – should be counted by a state for meeting its RE targets.  Where a

state counts pre‐existing hydro to meet its RE targets, that should also be permitted under the rule.

New Hydropower. Some commenters are concerned that footnote 82 (page 134), which addresses

hydropower, is too broad and imprecise.  Rather than excluding the “bulk of hydropower” as the footnote

states, it seems more accurate to specify that “historic hydropower is generally excluded from the calculation

adopted by many states” in their respective RPSs.  More importantly, as currently located, the footnote modifies

the introductory clause of the sentence in the text explaining that “[t]he best practices scenario for each state

consists of growing annual levels of RE generation.”  All new hydropower should be counted in the growing

levels of RE generation contemplated by this part of the sentence.  If the footnote is necessary, it seems better

located where the text references “the state’s historic RE generation.”  In short, we suggest moving the footnote

and modifying it to be clear that new hydropower is included and encouraged in the approach.

Clarification of Hydropower in the TSD. We have also reviewed Chapter 4 of the TSD and have some

questions about how hydro is discussed.  Those questions and comments are indicated in a forthcoming redline

of Chapter 4.  Almost all of the comments are on pages 3 and 4 of that Chapter.  We note in particular that the

chapter and many of the supporting tables and other materials stress that the RE discussion is about “non‐

hydro” RE.  We are concerned that the continuing, frequent qualifier of “non‐hydro” where RE is mentioned will

confuse and mislead the public about the fact that new hydro RE can be used to calculate RE progress by the

states, and is encouraged.  Rather than the frequent mentions of “non‐hydro” RE, we suggest that the “non‐

hydro” qualifier be dropped wherever it appears, and that Chapter 4 of the TSD simply contain a clear

description of how hydro is proposed to be handled under the rule.  Other references to RE in the rule and

supporting materials could then be footnoted with a reference to that discussion where it is important or

necessary to understand how hydro is being handled.   
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On p. 142, EPA states, “The EPA believes that since the decisions to construct these units were made prior to

this proposal, it is reasonable to view the incremental cost associated with the CO2 emission reductions available

from completion of these units as zero for purposes of setting states’ CO2 reduction goals.”  While viewing the

costs as zero may be true in a narrow sense, to the extent that these projects predate the rule, part of the

rationale for proceeding with these projects was the premise that greenhouse gas reductions may be required in

the future. We recommend EPA clarify this language.  

Equity Among States. We are concerned that the discrepancy across states in the same region could be a

future source of tension over the implementation of the rule.  Also, the rule presents an opportunity to spur

those states that are lagging in moving towards a new energy future.  It is not clear how these goals were set

and if there is a minimum renewable requirement for states that have not implemented renewable goals to

date. 

Contributions from Federal and Tribal Lands.  Please explain how EPA accounts for contributions from

Federal lands in RE targets.  And from Tribal lands?  Furthermore, we ask EPA to work with land management

agencies to verify this data.  Please clarify if states should/can take credit for renewable energy projects

permitted on Federal lands.

Renewable Energy Goals on Federal Lands. Given the focus of the Climate Action Plan and significant

investments across the Federal Government in support of clean energy projects, the EPA's exclusive reliance on

an aggregation of RPS is striking.  The effect of this proposed rule appears to be strong support for NGCC and

nuclear EGUs, which may effectively drive investment away from renewable EGUs that would have less

environmental impact and greater GHG benefits.  Some commenters suggest that EPA seek public comment on

alternative means of establishing the renewable energy goals of Building Block 3, specifically referring the public

to the DOI/DOE Solar Energy PEIS Appendix D (Update to Summary of Regional Initiatives and State Plans for

Solar Energy) and Appendix E (Update to Methods for Estimating Reasonably Foreseeable

Development Scenarios for Solar Energy Development).   

Building Block 4		

EE cost estimates.  Can EPA please explain to us the source of their cost estimates for EE measures at 1.5%?  

The estimates on p. 160 (roughly $71 to $88 per MWh) seem high and inconsistent with many studies that assert

relatively low EE costs.

A recent LBNL report examines cost of saved energy from a program administrator perspective

(http://emp.lbl.gov/sites/all/files/cost-of-saved-energy-for-ee-programs.pdf). It finds the national program

administrator levelized cost of saved energy for electric efficiency programs (based on 2009‐2011 data) is

$21/MWh.  Detailed information on program administrator costs for the Northeast is available through the

NEEP Regional Energy Efficiency Database (http://www.neep-reed.org/Focus.aspx).

Total resource cost for efficiency includes both program administrator cost and participant costs.  DOE has

completed recent analysis of participant costs and the analysis finds, based on available data, that the ratio of

participant costs to administrator costs for electric programs is approximately 1:1.  

A forthcoming report from NREL and LBNL summarizes data on the direct costs of state RPS policies and could

be a useful reference to add to the discussion on p. 140 of RPS‐driven RE deployment.
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Additional EE.  According to the Northeast and Mid‐Atlantic Energy Efficiency Partnership’s Regional Energy

Efficiency Database of Northeast and Mid‐Atlantic states, Massachusetts and Vermont were already achieving

more than 2% savings of state retail electricity sales in 2012, due exclusively to utility run efficiency programs.  

This level excludes savings that occur from a number of other efficiency measures including:

 State adoption and compliance with building energy codes, which saved an estimated 1.1% of national

electricity retail sales in 2012, despite inconsistent state adoption and compliance efforts, according to

analysis by the Pacific Northwest National Laboratory

(https://www.energycodes.gov/sites/default/files/documents/BenefitsReport_Final_March20142.pdf);   

 Non‐utility run efficiency projects, which was a ~$6 billion industry in 2013, according to a recent report

by LBNL (http://emp.lbl.gov/publications/current-size-and-remaining-market-potential-us-energy-servicecompany-industry); and

 State appliance and equipment standards, which can achieve energy savings when not preempted by

Federal standards.  

EE Level for the South Central and SE Regions. The RPS methodology is problematic for the South Central

and Southeast regions, each of which contains only one state with an RPS. This does not reflect a lack of

technical or economic potential in those regions.  EPA should solicit comment on a more robust way to

determine the EE levels for these states.  

Additional Analysis of EE and RE.  A commenter suggests that a techno‐economic analysis of renewable

energy costs and availability on a state by state basis (taking into account system constraints, including reliability

constraints) may reveal significant cost‐effective renewable energy potential not revealed in the approach used

in the proposal. The commenter suggests that DOE could provide existing deployment data and renewable

energy cost and resource estimates that could inform this analysis. The commenter recommends EPA take

comment on using this alternate, techno‐economic approach.

More Stringent Targets.  EPA could also strengthen its targets while continuing to rely on existing RPS targets

in several ways:  most notably by retaining the more aggressive RPS targets that already exist in states that

exceed the maximum renewable energy generation target identified by EPA in the proposed rule; and by

assuming that all states in a region can achieve the average existing RPS target for a region by 2029.  We suggest

EPA take comment on maintaining more aggressive annual energy efficiency targets in states already achieving

greater than 1.5% annual incremental savings rates.

On p. 296 EPA states, “However, measurement approaches vary by state based on multiple factors, including the

measure and program type being evaluated, the level and nature of regulatory oversight, the degree of state

and utility experience with these measures and programs, and the overall magnitude of program impacts.”  

Some variation is evident in energy efficiency EM&V (though it has been reduced in recent years), but less

variation is evident in RE programs where generation output can be clearly measured. Commenters suggests

separate discussions of EE and RE EM&V.

EE EM&V options. In the State Plan Considerations TSD (p. 52), EPA presents options for EM&V requirements

and guidance for state plans. One of these options would allow states to establish their own EM&V protocols.  

The commenters suggest that this is a risky option under a rate‐based approach.  For rate‐based approaches,

they recommend the proposal require strong national EM&V standards for efficiency, drawing from DOE’s

uniform methods and other state of the art approaches.  On the other hand, for mass‐based approaches, we

recommend that EPA allow states to use their own EM&V for efficiency.
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Baseline. How do states come up with baselines for EE?  Is the baseline 2012 EE?

State Plans

Enforceability.  Standards based on emissions reductions due to actions outside the fence line raise significant

questions about legal responsibility.  If the justification for considering the entire system rests on the idea of

reduced utilization, then the emitting sources are being treated as if utilization were a simple business decision,

based on marginal cost and price.  But as EPA acknowledges, the utilization of individual units is frequently

outside the control of the operator itself, subject to overlapping regulatory and contractual constraints. If a unit

exceeds a permitted level of emissions because of dispatch, can States develop plans that protect these units

from citizen suits and Clean Air Act fines for following other regulatory and contractual requirements?  We have

heard anecdotes of units being required to dispatch for emergency situations, only to be liable for CAA fines.

What does enforceable mean in the context of a plan where the State is the responsible party? Does a State

waive sovereign immunity to 3rd party suits by submitting a plan that makes them responsible?  Can a State be

fined under the CAA?

Earlier compliance. Can EPA request comment on earlier compliance deadlines (prior to 2020), such as by

2018 for single‐state plans and 2019 for multi‐state plans?

Encouraging early/timely plan submission.		Is EPA considering or taking comment on incentives to

encourage early or timely submission of state or regional plans?  For example:

 Enabling states that submit complete plans in 2016 to build early emission reductions (prior to 2020)

into their compliance demonstration, either through mass‐based crediting for early action or extending

the averaging period for rate‐based emission reductions to include 2019 or 2018, perhaps paired with

some modest reduction in annual average targets.

 Provide early submitters of complete plans with other flexibilities, such as allowing them flexibility in

defining EM&V for efficiency programs.

Locking in Early Commitments.  Are additional options available – or is EPA seeking comment on potential

options – to lock in binding/enforceable commitments for emission reductions as part of the initial plan

submission in 2016 for states that request a one or two year extension?

Recognizing that at least some states lack certain legal authorities to implement their preferred approach to

meeting the 111d guidelines, are there certain core legal authorities (for example, to implement federal CAA

NSPS requirements or to regulate utilities) that most states already have that would enable them to achieve

some level of emission reductions from affected EGUs?  Could EPA please describe those common

authorities?  Could those authorities be the basis for requiring states to include binding requirements on

affected facilities as part of their initial plan submission, even if these would not meet the state’s target on their

own or would be a backstop rather than the primary mechanism for the state’s expected compliance?

In order to receive a two‐year extension from the 2016 plan deadline, what will states have to provide (in 2016

and 2017) to demonstrate that they are actually committed to completing a regional plan?  Is EPA taking

comment on an alternative approach of having states provide a state‐specific plan (or partial plan with at least

some enforceable measures) that would serve as a backstop in case a regional plan is not completed by 2018?

Cost Effectiveness.		To what extent do states have to demonstrate their plans are cost-effective? 

Trading. p. 93:  Can fossil‐fuel fired steam generating boilers and combustion turbines trade without having

these put into a single category?
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Evaluation.  In order to facilitate evaluation of the proposal by stakeholders and other states, we recommend

being more clear in the preamble and TSDs about how compliance with the state targets would be evaluated by

EPA, including states that chose either a rate‐based or mass‐based compliance approach.  If possible, an

equation (like the equation in the target‐setting TSD) would be helpful.

Approval.  To be approvable, does a final state plan need to have performance standards already in place

(including promulgated state regulations)?  Please explain.

Eligible means of emission reduction. At the top of p.90, second paragraph, EPA states that sources may

rely on any means of emission reduction, regardless of whether the EPA identifies measures as part of BSER.  

Our understanding is that, while means of emission reduction need not be part of EPA’s BSER, they must be part

of the relevant state’s plan. Is this correct? If so, EPA might consider revising this paragraph to state that caveat

clearly. We propose the following replacement: “To comply with the applicable standards of performance,

sources may rely on any means of emission reduction outlined in the relevant state plan, regardless of whether

the EPA identifies those measures as part of BSER.”

Multi‐state collaboration. We support EPA’s proposal to provide states with an additional year to submit

SIPs if they do so as part of a multi‐state plan.  We recommend that EPA solicit comments on other possible

mechanisms for fostering multi‐state cooperation. 

New NGCC. On p. 294 EPA states, “Credits or adjustment might represent avoided MWh of electric generation

or avoided tons of CO2 emissions.”  Has EPA considered adding to this a discussion of  how states should

incorporate new NGCC into a rate‐based program given that other sections seem to indicate that this is an

option, consistent with an all‐of‐the‐above approach. 

Extra‐State Reductions. On p. 302 EPA states, “The EPA is also proposing that, for renewable energy

measures, consistent with existing state RPS policies, a state could take into account all of the CO2 emission

reductions from renewable energy measures implemented by the state, whether they occur in the state and/or

in other states.” The approach for crediting out‐of‐state RE and EE is inconsistent as proposed.  Please explain. In

addition, please clarify what “implemented by the state” means in this context. 

Interstate trading.  We request clarification on whether the proposed rule permits inter‐state trading

(including between states that are not part of a shared multi‐state plan) for carbon emissions reductions from

permissible sources (e.g., renewable energy, energy efficiency, heat rate improvements, fuel switching,

CCS...etc.). The descriptions of the building blocks appear to make no mention of such trading outside of states

that are party to a shared multi‐state plan. However, on p. 302 of the preamble, EPA proposes permitting a state

to count emissions reductions from renewable energy measures implemented by the state in other states. It is

unclear whether this includes measures implemented in states that are not party to a shared multi‐state plan, or

whether this flexibility is extended to the other building blocks as well.  If EPA is indeed proposing this flexibility

for renewable energy, we suggest EPA make clear note of this earlier in the preamble, where building block

three is first described in detail. EPA should also provide clarification on what constitutes a renewable energy

measure “implemented by the state” if it occurs in another state.

One possible approach is this proposed language: “EPA invites comment on whether states should be permitted

to implement and receive credit for any emissions reduction measure implemented in another state—including

redispatch, new generation, and energy efficiency—even if the measure is implemented outside of a multi‐state

plan.”
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Projecting Emissions Performance. On p. 304 EPA states, “In general, as with projections used to

determine a mass‐based goal, projections of emission performance under a state plan could be conducted using

historical data and parameters for estimating the future impact of individual state programs and measures.

Alternatively, a projection could include modeling, such as use of a capacity planning and dispatch model.”  It

would be useful to describe which approaches are acceptable to promote a consistent basis for projecting

emissions performance.

Guidance for quantification, monitoring, and verification of RE and demand‐side EE measure.  EPA

requests comment on p.297 of the preamble on whether EPA should establish good practice guidance for states

in this area. We would emphasize the importance of soliciting comment here. For the purposes of facilitating

state plan development, ensuring submitted state plans are approvable, ensuring state emissions reductions

actions and reporting are reasonably consistent across states, and ensuring state emissions reductions are real,

it would be essential to provide such guidance to the states. Achieving these objectives is also essential for

managing the administrative burden on EPA and the states of implementing this rule. Best practices in

quantification, monitoring, and verification of carbon emissions reductions—e.g., the use of third parties,

adherence to protocols that ensure consistency and avoid double‐counting, and rigorous quantification methods

that take into account the full life cycle of energy generation and ensure the “additionality” of credited

measures—are well‐established for each of the building blocks in regional and international carbon markets.  

We also suggest soliciting comment specifically on the treatment of biomass, energy efficiency, and double‐

counting in this guidance, in light of the fact that biomass may or may not represent carbon emissions

reductions depending on the fuel source, demand‐side energy efficiency measures could attempt to claim

reductions that in fact are not “real” when compared to a realistic baseline, and interstate trades of emissions

reduction measures could complicate efforts to avoid double counting. Specifically, we suggest the following

language: “EPA invites comment on how to treat lifecycle emissions from biomass and emissions reductions

from energy efficiency measures in this guidance quantification, monitoring, and verification. EPA also invites

comment on how to structure quantification, monitoring, and verification standards to avoid double counting of

emissions reductions, especially for reductions resulting from interstate trades.”  

Contingencies in State Plans. States will be required to submit compliance plans for each affected entity.

Assuming that a State uses building blocks in a manner described in the Goal Computation TSD, a commenter is

concerned with the compliance and economic risk associated with reductions from new and lower (or no)

carbon generation. Some of the technologies e.g., nuclear units and gas plants, produce large amounts energy

that will be the basis for compliance in state programs. Any prolonged outage would almost guarantee that any

state would not meet its annual carbon goal.  Likewise, the amount of re‐dispatch from coal to gas (up to a point

at which the NGCC units achieve a utilization rate of 70%) is premised on the notion that gas prices remain

stable and do not rise precipitously for unforeseen reasons. A utilization rate of 70% at a time of high gas prices

would force a utility to generate using NGCC even though NGCC generation would be very low in the economic

dispatch order at such a time.   To avoid these undesirable accounts, we suggest that the guideline allow States

to incorporate relief mechanisms for such contingencies in their 111(d) plans. 

State Goals

Explanation in Preamble.  It would also be helpful for the equation for setting rate‐based state targets (BSER)

to be included in the preamble (not just the TSD).
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Equity. We recognize that these analyses are complex, and suggest that the best way to address them would

be through a face‐to‐face discussion with EPA staff familiar with the math details and spreadsheet on state goal

setting. We have particular interest in:

 Building Block 2, ReDispatch, and differential impacts on certain states, particularly those with a mix of 

coal and gas generation, compared to those states with primarily coal or primarily gas generation. 

 Building Block 3, Renewable Energy (RE), looking at both: 

a. The concept of the regional averaging formula for setting state goals, vis‐à‐vis the opportunity to

validate against a wind/solar/geothermal resource base for each state; along with the decision

to reduce some state goals below those already declared by individual states.

b. The differential impact on certain states driven by the 2012 base year total state power

purchase multiplied by the RE goal, and the effect on a small number of states from high 2012

base year levels of hydro and renewable generation on their 2020/30 RE goals.

 The cumulative effect on a small number of states of the Building Block 2 and 3 goal setting procedures

under 1. and 2. above.       

Retirements. Should announced retirements and/or plants currently under construction be taken into

account? Planned coal plant unit retirements are not discussed (p. 199) in terms of how they are considered or

not considered in the calculation of the state goals, nor are they addressed in terms of a state’s achievement of

the state goal through the state plan.

Methodology. On page 201 EPA states, “If the generation data for the NGCC group in a state developed in Step

1 showed average annual utilization below 70 percent of those units’ maximum possible output, and the

generation data developed in Step 1 also included generation from the coal‐fired steam or oil/gas‐fired steam

EGU groups in that state, the generation and emissions figures for the NGCC group were increased, and the

generation and emissions figures for the coal‐fired and oil/gas‐fired steam EGU groups from Step 2 were

proportionately decreased ... “  Why were both coal and NG steam units proportionately decreased? The

approach most suited for this application would prioritize abatement from the most cost‐effective actions first,

which would presumably back out generation from coal before generation from other steam units.

Mass –Based Calculations.  The objective of the rule is to secure real GHG emission reductions, which also

yields park protection benefits.  To realize this objective, some commenters suggest a mass based approach is

preferable to an output‐weighted rate‐based approach.  A mass based approach is straight‐forward and

accomplishes real emission reduction even in the face of increases in generation capacity.  This approach would

track the net benefit of all state measures in reducing greenhouse gas emissions from existing EGUs.  The mass

goal has been demonstrated effective through the Regional Greenhouse Gas Initiative (RGGI) program and is

consistent with the acid rain trading program and subsequent emissions trading programs that are tracked

through EPA’s Clean Air Markets Database.  For these reasons, we believe the mass based approach will provide

the clarity (and leverage EPA’s experience) to allow for better enforcement of state plans.  On the contrary, a

rate‐based approach is more complicated and requires considerable calculation of factors to be added or

subtracted from the state generation pool.  Greenhouse gas emissions are not limited in a rate‐based approach;

if generation increases, greenhouse gases can increase.  We believe the rate‐based approach will create

enforcement challenges because of the complexity of accounting.   

Importers. The justification for a reduction only for states that are net importers (p. 203) is unclear given that

flows of electricity vary, and a state may be a net importer for part of the year, day or minute, and a net

exporter at other times. Commenters would like to consult with EPA about the broad set of issues related to

accounting for imports and exports.
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Goal Computation. Can EPA explain why they used a simple average (p. 204) rather than a generation

weighted average?  Is it because projections are not used in applying the building blocks? Given the likely

growth in generation (once EE is added to the denominator), this averaging procedure may undervalue goals in

the later years.

Alternative Procedure for Goal Computation.  On p. 205, EPA states, “[W]e specifically request comment

on the following alternative procedure: in Steps 4 and 5, should we estimate the quantity of generation

reductions and associated emission reductions at the state’s affected EGUs that would be achieved through

application of these building blocks and then, in Step 6, subtract these emission reduction quantities from the

numerator of the adjusted emission rate equation (instead of computing the quantities of generation that would

be produced by new low‐carbon capacity and avoided by demand‐side energy efficiency and then adding those

generation quantities to the denominator of the adjusted emission rate equation)?”  The value of this

alternative procedure, which is more complicated, should be further explained and examined.  

Reliability

Guidance. To fully realize the benefits of flexibility to address potential reliability concerns, we recommend

that EPA provide non‐binding guidance to states that their plans take advantage of available flexibilities, such as

multi‐year averaging of emissions and others suggested by the building blocks themselves, to accommodate the

possibility that the operation of more carbon‐intensive generation may be required to address system changes

and events in order to enhance system reliability. Additionally, we recommend that EPA provide non‐binding

guidance to states that they consult with the relevant regional transmission organization, independent system

operator, or relevant power system planning authority when developing their implementation plans. 

Offsets

Statement of Support for Offsets. Some commenters would like EPA to include a general statement in the 

Preamble and in the regulatory section (and elsewhere, as appropriate) that offsets are allowable so long as they 

are surplus, verifiable, enforceable, and permanent. Allowing for offsets is a means to provide an incentive at 

existing EGUs, among other facilities, to reduce CO2 beyond levels that will be required in order to generate 

excess emission reductions that could be traded as offsets. Furthermore, we ask EPA to recognize specifically 

RGGI and CA offset programs as eligible. This additional text would be consistent with the Presidential 

Memorandum that asked for this rule and directed EPA to, “develop approaches that allow the use of marketbased instruments, performance standards, and other regulatory flexibilities.” We believe it is advantageous to 

allow for the use offsets to comply with targets to capture economic efficiencies. This is also particularly 

important to Interior’s work under the Climate Action Plan. 

Fifth Building Block recognizing Offsets. We request that EPA solicit public comment concerning the 

development of a 5th Building Block with regard to offsets and market-based systems. We ask that the questions 

be framed in such a manner to provide support and logical outgrowth of a Building Block 5 for offset programs in 

the final rule. We note that certain TSD documents (such as “Projecting EGU CO2 Performance in State Plans”) 

will need to be revised to support the potential for including offsets in the final rule. 

Impacts on Small Entities and Rural Facilities

Heat Rate Improvement.  The commenter requests that EPA clarify the extent to which it considered

disproportionate cost impacts to small entities in setting heat rate improvement goals. The commenter suggests
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EPA request comment on the technical feasibility for small entities of the proposed heat rate improvements,

given the factors discussed below.  

Heat rate improvement figures are based on variability within each facility, then aggregated by some rule of

thumb.  This method would seem to disadvantage older units by placing them on par with new units for the

availability of improvements, It would also seem to disadvantage older units that have been (1) retrofitted with

pollution control equipment that creates a higher parasitic load than pollution controls designed into the

original unit, and (2) will experience greater variability in utilization (and thus combustion and heat rate

efficiency) due to change in dispatch, which are likely to favor larger, more efficient units.  Standards imposed

on individual facilities should be based on a BSER applied to that facility, rather than a general estimate of what

is possible across the entire fleet.    

Building blocks 2‐4. These building blocks place small municipalities and coops at a significant disadvantage,

and a BSER based on these building blocks, as described in the state‐by‐state analysis, appears to put states with

greater numbers of these small entities at a disadvantage.  Small entities in the power generation sector

typically have strong and directly relationships with the distribution channels.  In the case of coops, the

generator coop is owned by the distribution coops it serves. In the case of municipalities, generation and

distribution are typically vertically integrated.  These relationships make changes in dispatch particularly

harmful, since they must decrease utilization of the unit they own and purchase other power elsewhere on the

grid.  This is particularly harmful for those entities that have taken loans, set prices, or sought regulatory

approvals based on past levels of utilization.  These small entities often lack the access to capital or physical

space to make significant investments in alternative sources of energy.  For example, it is difficult to imagine

small municipalities making the size investment necessary to build new NGCC or the space necessary to install

major wind or solar facilities on their own.  If EPA decides that the BSER emission guidelines must be imposed on

regulated sources rather than on a state's portfolio, small entities will be have less ability to mitigate their

emissions 'beyond the fenceline' and will be disproportionately purchasers of 'credits.' As such, the program

would be transfer of resources from small generators to large distribution and/or generation conglomerates.  

Impacts on Rural Cooperatives.  Rural Electric Cooperatives and their customer bases in rural America could

potentially face disproportionately high costs associated with compliance with the rule. RECs currently generate

about 70% of their baseload power from coal. Some RECs have limited flexibility to dispatch other sources. Rural

electric customers already pay a little over $.02 per kilowatt hour more than the average American for

electricity. High energy costs in low income areas are especially pronounced across much of the REC service

area. About 1/3 of the RUS loan portfolio presently services coal generation. States with rural areas will require

additional flexibility to meet compliance given potentially substantial rate increases and debt service challenges.

While States have flexibility to craft solutions that avoid these disproportionate impacts in the current draft of

the rule, RECs lack the political voice of IOUs to shape State implementation plans. EPA should explore

mechanisms to create flexibility for States that may be faced with additional hardships in meeting compliance

and should create assurances that rural electric providers and customers have adequate participation in the

development of State implementation plans.  

Other		

Terminology.  The Rule should consistently use the term greenhouse gas, rather than carbon dioxide  

The rule text uses the terms greenhouse gases (GHG) and carbon dioxide (CO2) interchangeably. The rule should

use the term greenhouse gas, or CO2 equivalent, consistently and only refer to CO2 when specifically

referencing that pollutant. This confusion starts in the first paragraph of the Purpose on page 12 and continues

throughout the document.  
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The language in the rule should be consistent with the Endangerment Finding – which refers to the increasing

concentrations of GHG in the atmosphere to be the pollutant that endangers public health or welfare. The

language of the rule should consistently use the term greenhouse gases and also refer to the concentration of

these gases in atmosphere when referring to endangerment.  

Endangerment Finding: The Administrator finds that the current and projected concentrations of the six key well‐

mixed greenhouse gases — carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons

(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6) — in the atmosphere threaten the public health

and welfare of current and future generations.  

Cause or Contribute Finding: The Administrator finds that the combined emissions of these well‐mixed

greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas

pollution which threatens public health and welfare.  

From the Endangerment Finding:  

(1) These six greenhouse gas share common properties regarding their climate effects; (2) these six greenhouse

gases have been estimated to be the primary cause of human‐induced climate change, are the best understood

drivers of climate change, and are expected to remain the key driver of future climate change; (3) these six

greenhouse gases are the common focus of climate change science research and policy analyses and discussions;

(4) using the combined mix of these gases as the definition (versus an individual gas‐by‐gas approach) is

consistent with the science, because risks and impacts associated with greenhouse gas‐induced climate change

are not assessed on an individual gas approach; and (5) using the combined mix of these gases is consistent with

past EPA practice, where separate substances from different sources, but with common properties, may be

treated as a class (e.g., oxides of nitrogen).

Employment Effects. EPA estimates that Option 1 will be responsible for more lost jobs in support of natural

gas than job losses related to coal.  Is that consistent with relative merits of each fuel and of the President’s

approach to coal and gas?  Also, in the preamble discussion of benefits/costs (around p. 341), EPA should

consider including some discussion of the positive economic impacts of greater deployment of

renewables/EE/nuclear, including jobs. .

Territories. Through the Energy Development in Island Nations project, DOE worked with the U.S. Virgin

Islands to determine cost‐effective renewable energy and energy efficiency potential. In most cases, the

potential is higher than on the mainland due to higher energy costs.  EPA may find this work helpful in

determining BSER for these areas.

Tribes.  EPA should clarify whether the EGUs mentioned (p. 220‐221) are the only ones that might reasonably

be affected by this action or future related actions. For example, would the natural gas‐fired plant on Ft. Mojave

reservation in Arizona be in scope for this or future related actions? Second, EPA should clarify the language

about what will and will not be required by tribes at this time. The last sentence, in particular (“EPA must

establish a plan for affected EGUs on tribal lands”) appears to conflict with the earlier language (“the agency is

not proposing specific goals for tribes with affected EGUs in this action at this time”). To the extent that any

sources on tribal lands are affected, EPA should explain the relevant details, including the process by which

standards would be set. Finally, clarification in this section should be carried over to relevant TSD sections.

General:The United States has a trust responsibility with tribes.  EPA states that three coal fired power

plants operate on tribal lands, and if tribes decline to develop tribal plans to address greenhouse gas emissions

from these facilities, then EPA will develop Federal plans.  How will the Federal plans reconcile with State GHG

plans?  What is the timeframe for action applicable to tribal power plants?

NGS and CAP: Commenters request assurance that the proposed rule does not upset the recent

settlement entered by the Navajo Generating Station ("NGS") stakeholders that addresses the need for emission

reductions at this facility to protect visibility at Class I areas while also factoring in tribal considerations.  We
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understand that EPA is in communication with the NGS Technical Working Group (TWG) on this matter, and we

hope that you take their concerns seriously, and are very mindful of the NGS situation.  We expect the NGS TWG

will submit public comments on this rule.   

We would expect EPA to hear from tribes directly about their concerns with the rule, but we note in particular

that NGS and 4 Corners together support the majority of the Navajo Nation's economy as well as lots of high‐

paying jobs for the tribe's members.  NGS also provides a large portion of the Hopi Tribe's income.  We ask EPA

to remain cognizant that many tribes are dependent on the Central Arizona Project (CAP) water that is pumped

by NGS.  These tribes are directly affected by the energy costs of CAP water, which right now are low based on

low‐cost NGS power.

NSR: We request that EPA clarify the intent for New Source Review (NSR), which is a critical component of the

Clean Air Act’s approach for avoiding degradation of air quality across the country.  This protection needs to

remain intact.  In the proposed rule, it appears that EPA may be allowing states to exempt sources from NSR.  

The confusing language is on pages 318‐320 of the Preamble, where EPA suggests that states could avoid

triggering NSR requirements for greenhouse gas emissions by limiting generation of lower carbon fuels to levels

that would assure greenhouse gas emissions are below the NSR threshold.  We ask EPA to make clear in this

section that NSR applies to criteria pollutants (e.g., sulfur dioxide, nitrogen oxides, and fine particles) as well as

greenhouse gases, and that states would need to avoid triggering existing NSR requirements for both criteria

pollutants and greenhouse gases or follow existing NSR requirements.

Climate science and impacts. Information presented on the impacts of climate change should reflect the

most recent, published (and cited) information available and should not state the case for human endangerment

beyond that which can be attributed to an established and credible source. Citations for the science or published

analyses used to illustrate or describe the impacts of climate change, for the purposes of this rule, should be the

most up to date information available. In particular, discussion of the 2009 Endangerment Finding may include a

description of the climate change impacts that were considered, but further description or illustration of these

impacts should clearly be cited to the most up to date published and citable information available, not to 2009

information, unless 2009 information is the most up‐to‐date information available on a particular impact. EPA

may consider noting the IPCC 2014 report on Impacts, Adaptation and Vulnerability that covers many of the

impacts considered in the Finding.

Peer Review: To what extent is the literature cited in this rule and TSDs peer‐reviewed?  

Geographic Hot Spots. Efforts to reduce the proportion of generation load from traditional coal‐fired power

plants will reduce emissions of criteria pollutants as well as reduce greenhouse gas emissions.  Because climatic

impacts occur on regional and global scales, the geographic location of carbon dioxide emissions reductions can

be flexible.  However, we caution EPA to consider that shifting generation load could create geographic “hot

spots” where emissions of criteria pollutants could increase from facilities near Class I national parks and

wilderness areas and increase acid deposition, ozone, or regional haze in these protected areas.  To avoid

geographic “hot spots,” states would need to track emissions of criteria pollutants, as well as greenhouse gases,

and evaluate impacts where emissions increases due to shifting generation could trigger NSR.

Federalism.  It may be worthwhile reconsidering the applicability of the Federalism Executive Order, especially

in light of the issues raised in the State Plan Consideration TSD.  States will be responsible for regulating a new

pollutant and crafting an entirely new regulatory scheme to respond to the broad guidelines provided by EPA.  

Most will require new legislation and the re‐issuance of CAA permits for every EGU.  Most will require new

resources.  As States are the directly regulated entity, it is unclear how Federalism is not implicated.
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