From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov> 

Sent: Sunday, July 26, 2015 7:04 PM 

To: Vasu, Amy; Culligan, Kevin; Harvey, Reid 

Cc: Szabo, Aaron; Grossman, Andrea 

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- EPA Clean Power 

Plan draft final rule 7/23 RLSO version 

Attached please find a summary of interagency comments under EO 12866 and 13563 on the 

latest version of the EPA draft Clean Power Plan final rule. 

 

Thanks and please let me know if you have any questions. 

Nathan 

<< SummaryofinteragencycommentsunderEO12866_13563_EO 12866_CPP 2060 AR33 

Final_2015_7_26.docx >> 

<< SummaryofinteragencycommentsunderEO12866_13563_EO 12866_CPP 2060 AR33 

Final_2015_7_26_7pm.docx >> 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

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General Comments

1. Reviewer requests the opportunity to see the rest of the Technical Support Documents including

the Greenhouse Gas Mitigation Measures Technical Support Document and New Source

Complements to Mass Goals Technical Support Document.

2. Reviewer requests the opportunity to talk with EPA about the math in step 7 of the goal

computation and associated text justification included starting on page 891 RLSO.  

3. State measures rate plans. Reviewer notes that EPA has been deleting the State Rate plans as

viable options in many instances. The reviewer noticed the concept in the text on the top of P.

31 (and did not understand why), but way later on in the preamble on state plans there is a

regular deletion of the "rate" clause from what had been "State rate and mass based plans". It

happens many times, and the reviewer cannot figure out why, especially since rate‐based plans

are the original state option concept (albeit not preferred). Reviewer recommends that EPA

reconcile these inconsistencies.  

4. Merged state rates. Reviewer notes that it is not clear if cooperating rate‐based states need to

merge their rates, or can just link ERCs for trading. Reviewer notes that the preamble seems to

say the states can either merge or trade without merging. The reg text seems to say the states

all have to submit linked plans that are similar. Are these texts compatible ‐ is the necessary

state "similarity" related to unit ERC definition?

5. Awaiting EPA's thoughts on language that could encourage states to preserve marginally

economic merchant nuclear. EPA had mooted a requirement in the mid‐course state reports.

Specific Comments

1. Reviewer notes that a common definition for “equivalent” regarding emission performance and

goals would be useful throughout the preamble.

2. Page 97 RLSO: Reviewer questions if the Mt is intended to be MMT. Current text reads: “Those

states that take advantage of this option will be eligible to receive from the EPA a limited

number of matching allowances or ERCs, up to a total limit for all states that represents the

equivalent of 300 Mt of CO2 emissions.”

3. Page 97 RLSO: Reviewer requests clarification as to what states are allowed to do with the

allowances/ERCs they receive from EPA for early action.

4. Page 97 RLSO: In the discussion on Early Action, the reviewer noticed a number of pieces of

information that need to be provided in either the preamble or the forthcoming guidance. 1)

How is it shown that RE benefits a low income community? 2) What is the definition of a low

income community?  

5. Page 97 RLSO:  

Reviewer recommends that the value for early action is only one ERC or allowance per MWh of

zero emitting generation or efficiency.  Reviewer recommends that early action eligibility is

technology neutral so that all types of zero‐emitting generation are eligible, all types of
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renewable energy, energy efficiency, new nuclear, and nuclear uprates. Reviewer recommends

that half of credits come out of the existing state targets rather than being additive to state

targets. Reviewer recommends EPA consider some type of interstate transfer opportunity.  

Reviewer recommends that, in order to limit credits going to projects that are already

underway, credit could start when final plans are submitted or approved, rather than when the

rule is released. Projects that will be built in 2016, for example, are already underway.

6. Page 399 RLSO: Reviewer notes that portions of the discussion of new natural gas combined

cycle (NGCC) units are factually incorrect. Reviewer is available to discuss.   

Reviewer recommends revising the section as follows:

“(iii) Generation from new NGCC units.

                “New NGCC units –‐ that is, units that had not commenced construction as of January

8, 2014, the date of publication of the proposed CO2 standards of performance for new EGUs

under section 111(b) –‐ are not subject to the standards of performance that will be established

for existing sources under section 111(d) plans based on the BSER determined in this final rule.

In the June 2014 proposed emission guidelines for existing EGUs, the EPA solicited comment on

whether to include this measure in the BSER. Commenters raised numerous concerns opined

both in support of and against including new NGCC capacity in the BSER, and after consideration

of the comments, we are not including replacement of generation from affected EGUs through

the construction of new NGCC capacity in the BSER. Because no clear consensus emerged on

this question, EPA decided to defer consideration of new NGCC as part of this rule, but may

consider it in subsequent revisions.”  In this section, we discuss the reasons for our approach.

                The EPA did not include reduced generation from affected EGUs achieved through

construction and operation of new NGCC capacity in the proposed BSER because we expected

that the CO2 emission reductions achieved through such actions would, on average, be more

costly than CO2 emission reductions achieved through the proposed BSER measures. Our

determination not to include new construction and operation of new NGCC capacity in the BSER

in this final rule rests primarily on achievable magnitude of emission reductions rather than

costs.

                Unlike emission reductions achieved through the use of any of the building blocks,

emission reductions achieved through the use of new NGCC capacity require the construction of

additional CO2‐emitting generating capacity, a consequence that is inconsistent with the long‐

term need to continue reducing CO2 emissions beyond the reductions that will be achieved

through this rule. New generating assets are planned and built for long lifetimes –‐ frequently 40

years or more –‐that are likely longer than the expected remaining lifetimes of the steam EGUs

whose CO2 emissions would initially be displaced be the generation from the new NGCC units.

The new capacity is likely to continue to emit CO2 throughout these longer lifetimes, absent

decisions to retire the units before the end of their planned lifetimes or to install CCS technology
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in the future at substantial additional cost. Because of the likelihood of CO2 emissions for

decades, the overall net emission reductions achievable through the construction and operation

of new NGCC are less than for the measures including in the BSER, such as increased generation

at existing NGCC capacity, which would be expected to reach the end of its useful life sooner

than new NGCC capacity, or construction and operation of zero‐emitting RE generating capacity.

We view the production of long‐term CO2 emissions that otherwise would not be created as

inconsistent with the BSER requirement that we consider the magnitude of emissions reductions

that can be achieved. For this reason, we are not including replacement of generation from

affected EGUs through the construction and operation of new NGCC capacity in the final BSER.

                Commenters raised a concern with the interrelation of section 111(b) and section

111(d). New NGCC capacity is distinguished from the other non‐BSER measures discussed above

by the fact that its CO2 emissions would be subject to the CO2 standards for new EGUs being

established under section 111(b). Section 111 creates an express distinction between the

sources subject to section 111(b) and the sources subject to section 111(d), and commenters

expressed concern that to allow section 111(b) sources to play a direct role in setting the BSER

under section 111(d) would be inconsistent with congressional intent to treat the two sets of

sources separately. Section VIII of this preamble includes a discussion of ways to address new

NGCC capacity in the context of different types of section 111(d) plans.

7. Page 440 RLSO: Reviewer suggests changing “by 2030” to “in 2030.” Current text reads: “We

note that taken together, the modifications yield emission reductions requirements that

commence more gradually than the proposed goals but are projected to produce greater

emission reductions overall by 2030.1

”

8. Page 445 RLSO:  Reviewer recommends striking the egregious nuclear language.   

Reviewer recommends that EPA strike this language: “and that the inclusion of the generation in

the goals is premature because the units’ actual completion dates could be delayed.” Watts Bar

2 is on schedule for commercial operation within the year (June 2016). Both Vogle and Summer

are on schedule to be operational by 2020. Vogle is backed by a DOE loan guarantee which

demonstrates the Administrations’ confidence that the plant will meet its construction schedule

Reviewer recommends that EPA strike this language: “... we also acknowledge that, in contrast

to RE generating technology, investments in new nuclear units tend to be very large and

“lumpy” and have historically been susceptible to delays that increase costs . Also, there is no

clear trend demonstrating increased construction of new nuclear capacity. We view these

factors as distinguishing the under‐construction nuclear units from RE generating capacity,

indicating that the new nuclear capacity is of higher cost and therefore less appropriate for

inclusion in the BSER.” The current trend is that 5 units are under construction demonstrating

                                                            

1 For the proposed rule, the EPA projected total CO2 emission reductions from 2005 levels of 29% in 2025 and 30% in 2030. For

the final rule, the EPA projects total CO2 emissions reductions from 2005 levels of 28% in 2025 and 32% in 2030. See Regulatory

Impact Analysis for the CPP Proposed Rule, Table 3‐6, and Regulatory Impact Analysis for the CPP Final Rule, Table 3‐6, available

in the docket.
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5.5GW with additional units under consideration including site characterization activities at two

sites for SMR deployment in the mid 2020’s.

EPA should realize that it is basing this assessment on first of a kind plants and therefore

claiming that nuclear plants show a trend of being over cost and delayed is inappropriate.

9. Page 445 RLSO:  Section VIII.K.1.a.(8) is mentioned in the nuclear section but it appears to only

address NGCC and RE.               

10. Page 481/482 RLSO: Reviewer suggests striking this sentence about BB3 for Alaska, Hawaii, and

Puerto Rico because RE potential data for those states is available: “In addition, at present we

lack the data to quantify the emissions reductions available from building block 3 in these

isolated areas using the same methodology used for the contiguous portions of the U.S.”

11. Page 516 RLSO: Current text reads “Lower wholesale power prices would make further RE

deployment less competitive against generation from existing emitting sources; this dynamic

puts upward pressure on the cost of achieving CO2 reductions through increased RE

deployment.”

Reviewer recommends noting that lower wholesale prices will also reduce the cost of electricity

to consumers: “Lower wholesale power prices would make further RE deployment less

competitive against generation from existing emitting sources; while this dynamic will reduce

the cost of electricity to consumers, it may also put upward pressure on the cost of achieving

CO2 reductions through increased RE deployment.”

12. Page 850 RLSO: Reviewer recommends the following edit for accuracy. “The EPA has determined

that the statewide rate‐based and mass‐based CO2 goals are expressions of the emission

performance rates equivalent to application of the emission performance rates to affected EGUs

within a state when the technology specific share of existing fossil EGUs is the same as in 2012.”  

13. Page 857 RLSO: Reviewer suggests adding back “adjusted 2012” to describe the baseline data in

footnote 739as the adjective is correct and needed for clarity. “However, as discussed here and

in the next section, in order to provide maximum flexibility to states, the EPA averages these

two emission rates together for each state using their adjusted 2012 baseline generation share

to arrive at a single statewide emission performance goal.”  

14. Page 827 RLSO: Reviewer suggest the edit to make the report title correct: “In addition to wind

and solar technologies, the EPA evaluated hydropower deployment potential based on the

latest cost and performance data from NREL’s Renewable Energy Economic Potential study. “

15. Page 828 RLSO: Current text reads: “Commenters detailed several issues with applying the

benchmark development rate, including that it limits future performance to historical levels of

development...”

Reviewer notes that this same criticism could be levied against the final BB3

methodology.  Reviewer recommends striking the clause.  

16. Page 830 RLSO: Reviewer notes that it’s not clear why the values in Table 9 have been revised

downward from the previous version of the preamble.  

17. Page 834 RLSO: Current text read: “As such, applying the 30 percent constraints at the IPM sub‐

region level provides a high degree of assurance that the RE capacity deployment pattern

projected by the model would not incur significant grid integration costs.”

While this is true, reviewer recommends maintaining previous language referring to this

constraint as conservative.  It is indeed highly conservative. Reviewer suggests adding this

language “As such, applying the 30 percent constraints at the IPM sub‐region level *is a very
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conservative constraint and* provides a high degree of assurance that the RE capacity

deployment pattern projected by the model would not incur significant grid integration costs."

18. Page 870 RLSO: Reviewer recommends the following edit because using a different data year

wouldn’t change the total NGCC, but would change the incremental NGCC used in the next step

to come to the final tech specific rates. Reviewer believes that the first sentence in this quote

gets EPA’s point across, but the second should be deleted because it could create confusion

about how changing the data year would affect the rate goals.  “Therefore, a different data year

may change a baseline data point, but it would not change the ending point total potential

NGCC generation for quantifying the emission performance rates in these circumstances.  As a

consequence the lower amount of NGCC generation in the baseline would be offset by a larger

NGCC incremental potential in the building block to get back to the same total potential NGCC

generation level.”

19. Page 888: Reviewer recommends the following edit.  “In other words, the regional NGCC

capacity factor was only assumed to reach 75 percent if there was sufficient higher‐emitting

fossil steam generation that it could replace after step five.”

20. Page 888‐889 RLSO: Reviewer recommends the following edits because the latest version of the

Goal Computation TSD does not introduce the intensity rate equations until Step 7.   

“The increase in NGCC generation in the NGCC denominator at this step compared to the post‐

building block 3 level was matched by an equal decrease in fossil steam generation in the steam

denominator reflecting the 1 for 1 MWh hour replacement. In parallel, the emissions from NGCC

numerator was were increased by emissions corresponding to the baseline NGCC emissions rate

times the additional generation post‐building block 3, and the emissions from steam numerator

were decreased by the fossil steam emissions rate times the displaced generation.  At this point,

the equations generation and emission levels for both steam and NGCC reflect the final

distribution of generation between them the subcategories that comprises BSER.  But the

compliance emission rates in step seven must account for CO2 emissions and generation from

substituted renewable and gas generation that comprise building blocks 2 and 3, to reflect and

enable the emission reductions achievable under the best system of emission reduction, and

ensure that the shared implementation of BSER by steam and NGCC generation is reflected in

the compliance rates. This is addressed in step seven.”   

21. Page 889‐893 RLSO: Reviewer recommends the following edits to strengthen and clarify the

explanation of step seven. Review did not think the “second” and “third” were used

appropriately for what they were descripting and recommends EPA review.

“For building block two, a similar mechanism is used needed....   

Second As discussed above, it is beneficial that the baseline from which compliance emission

rates are derived be transparent and based on observable historic data.  ...   

In Section VIII, we discuss methods for creating ERCs for implementing shifting of generation

from steam to NGCC, and this discussion illustrates the value of relying on an observable and

concrete baseline. In that section we suggest that incentivizing and facilitating the purchase of

ERCs as a compliance option for steam units could be implemented through the use of a factor

that creates an increment a fraction of an allowable credit for each hour that an NGCC operates.  

This factor is derived from the actual incremental generation of NGCC post‐building block two,

relative to the 2012 baseline.  While a different factor could be derived from the hypothetical

intermediate baseline resulting from the pro rata application of zero emissions generation to

NGCC in building block three ( by transferring the full amount of NGCC emissions and generation
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replacing steam generation in building block 2), EPA believes that grounding baselines in

concrete historical data (such as those used to derive the 2012 baseline) is both more

transparent and easier to understand in a way that is more useful to states and utilities, in

contrast to the practical challenges of relying on a calculated baseline that corresponds to an

interim step within the performance rate calculation. As long as the crediting framework for

creating ERCs is consistent with the amount of gas emissions and generation that is transferred

to the coal rate, either this the chosen option or the option of transferring the entire quantity of

gas emissions and generation that occurred in block 2 to the coal rate would provide an

incentive for the power market to implement the shift in generation from coal to gas from

building block 2.

ThirdAlso as discussed above, it is important that the compliance equations reflect the BSER pro

rata allocation of renewable energy to fossil steam and NGCC generation.  The first approach to

define the quantity of NGCC generation and emissions to be averaged into the steam rate would

require the steam rate to take into account the total additional NGCC capacity that results from

the application of building block 3 before building block 2 has been applied.  This approach

would reflect in the compliance rate for steam units a greater share of the implementation of

building block 3 than is consistent with the pro rata methodology for building block 3 that

comprises the BSER. Ensuring that compliance emission rates for both steam and gas units

reflect the emission reduction potential of building block 3 is integral to the building block 3

methodology and also recognizes that application of building block three on a pro‐rata basis was

intended to achieve emission reductions from both NGCC and fossil steam commensurate with

their emissions reduction opportunities.

If the EPA were to use the increment of NGCC emissions and generation derived at the

intermediary step after the application of building block three, rather than the increment

relative to the 2012 baseline, the effect would be to largely re‐assign to fossil steam the

potential for increased NGCC generation due the building block three generation shift.”

22. Page 921‐922 RLSO: Reviewer recommends the following edit for accuracy.  “Consequently, the

statewide goals are equivalent to the CO2 emission performance rates when the technology

specific share of existing fossil EGUs is the same as in 2012  and are thus an equivalent

expression of the BSER.”

23. Page 922 RLSO: Reviewer recommends the following edit for clarity.  “The starting place for

quantifying mass‐based statewide CO2 emission performance goals are the emissions directly

represented in the numerator of the statewide rate‐based CO2 emission performance goals.”

24. Page 923‐924 RLSO: Reviewer recommends the following edit for accuracy and clarity. “Due to

the nature of the emission performance rate methodology, which selects the highest regional

value for each source category as the CO2 emission performance rate, there are cost‐effective

lower‐emitting generation opportunities quantified under the building blocks that are not

necessary for affected EGUs in the Western and Texas interconnects to demonstrate compliance

at historical generation levels. The EPA recognizes that these lower‐emitting generation

opportunities are available to affected EGUs at a national level as a means to increase their own

output (and, as a result, their own emissions) while maintaining the relevant emission

performance rate.”    

25. Page 928 RLSO: Reviewer recommends the following edit for accuracy and clarity.
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“Rate‐based goals minimize leakage relative to mass‐based goals that do not address leakage

because under a rate‐based state goal, similar to the subcategory‐specific emission performance

rates, existing lower‐emitting affected EGUs,”

26. Pg. 970 RLSO:  Current text reads? “Allowances or ERCs awarded by the EPA pursuant to this

program may be used for compliance by an affected EGU with its emission standards and are

fully transferrable prior to such use.” Does EPA mean that these ERCs are fully transferrable

within the state in which they are awarded, or across state lines, meaning that trades could

result in more than 300 million tons of emissions being allowed as a result of the program?  

Reviewer suggests clarifying that the “ERCs are fully transferrable within the state to which they

were awarded”.

27. Page 971 RLSO: Reviewer recommends clarifying the requirement of a demonstration:

“Specifically, the state must demonstrate in its plan that it has a mechanism in place that

enables issuance of ERCs or allowances from the state to parties effectuating reductions in 2020

and 2021 in a manner that would have no impact on the emission performance of affected EGUs

required to meet rate‐based or mass‐based emission standards during the compliance

periods.2

”  

Reviewer recommends further clarifying: 1) whether or not states are only responsible for

demonstrating that stringency is maintained with respect to the allowances/ERCs issued by the

state, and not those provided on a matching basis by EPA, and 2) amend footnote 788 to include

an example of how a state with a rate‐based target could meet this demonstration, to

complement the existing example of how the demonstration could be done in a mass state.

Possible text: “Under a rate‐based implementation, a state could elect to participate in the

Clean Energy Incentive Program, and set targets for the three interim step periods that, after

the ERCs awarded under the program were accounted for, could be demonstrated to meet the

interim target.”  

28. Page 982‐984 RLSO: For the bullets starting on page 983:

Bullet 1 – Reviewer recommends clarifying what cap is acceptable for the unaffected units in

this case.

Bullet 2 – Reviewer recommends that it would be much clearer if the output based set‐aside

(and RE set‐ aside) was mentioned. It was difficult at first to figure out how bullet 1 and 2

differed in their treatment of affected sources.

Bullet 3 – Reviewer recommends the following edit for clarity. “Establishing federally

enforceable rate‐based CO2 emission standards at a single level that applies for all affected

EGUs, consistent with the state rate‐based CO2 goal for affected EGUs in the emission

guidelines. This approach provides for interstate emission trading, through a multi‐state plan

where the states in a multi‐state plan combine their rates into a single joint rate.”

29. Pages 995 & 999 RLSO: Reviewer recommends clarifying in the section with the description of

emission standard mass‐based plans how “(1) Mass‐based emission standard applied to individual

affected EGUs” on page 997 differed from “(3) Mass‐based emission standards based on

operational or other standards” on page 1001. They seemed similar or the same to the reviewer.

                                                            

2 For example, under a mass-based implementation, the state plan could include 

a set-aside of allowances from an emissions budget that itself reflects the 

state goals. Allocation of those allowances to parties effectuating 

reductions in 2020 and 2021 would have no impact on the total emissions 

budget, which sets the total allowable emissions in the compliance periods.
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Does option (3) include option (1) for some units and option (2) for other units?

30. Page 1293 RLSO: Reviewer recommends providing more guidance regarding the 48‐hour

notification requirement for RSV events, especially whether notification would be required in

anticipation of a possible RSV event but where it is not yet known whether the triggering event

would warrant use of an RSV (e.g., it may take longer than 48 hours to determine the length of

an outage recovery and the impact thereon emissions/compliance). Reviewer also recommends

clarifying what's required for a "full description" under the initial/48 hour notice vs the 7 day

follow‐up "full description". Note that any changes in response to this comment may also need

to be reflected in the reg text on Pg. 1871 (redline version).

31. Page 1351 RLSO: Generally, reviewer supports EPA providing mass budgets that include new

fossil EGUs. However, reviewer requests the opportunity to comment on the methodology used

to arrive at these budgets and to review the and New Source Complements to Mass Goals

Technical Support Document.

32. Page 1353 & 1355 RLSO: Reviewer recommends the following edits. The first line edit is to make

it clear that both types of allocation strategies are needed. The reviewer notes that the mention

of the 2nd set‐aside on page 1365 says RE and EE isincluded in the federal plan, which issupported

by DOE. However, the reference to the same set‐aside on page 1355 says that only RE is included

in the federal plan set‐aside, but states could include EE in an alternative set‐aside if they wanted.

Reviewer recommends including EE and nuclear in the federal plan set‐aside. At a minimum,

reviewer recommends including nuclear as an option states may choose.  

Page 1353 “The EPA is proposing the inclusion of that two allocation strategies be

included as part of the mass‐based approach in the proposed federal plan and model rule:

updating output‐based allocations for existing NGCC and allowance set‐asides that target RE, and

demand‐side EE, and new and up‐rated nuclear units.”  

Page 1355 “The other allocation strategy included as part of the mass‐based approach in

the proposed federal plan and model rule is a set‐aside of allowances to be allocated to providers

of incremental RE. A set‐aside can also be allocated to providers of demand‐side EE, new or up‐

rated nuclear, or a combination of the three. to both RE and demand‐side EE.”

33. Page 1358 RLSO: “However, without a better understanding of the different mechanisms that

states may ultimately choose to meet the emission guidelines, and how different requirements

in different states may interact, the EPA cannot project every potential differential incentive

that could lead to a loss of CO2 emission reductions. Therefore, once program implementation

begins, the EPA will assess how emission performance across states may be affected by the

interaction of different regulatory structures implemented through state plans. Based upon

that evaluation, the EPA will determine whether there are potential concerns and what course

of action may be appropriate to remedy such concerns.” Reviewer strongly supports the

inclusion of this language, and recommends clarifying if this assessment will be part of the 8‐

year updating process as authorized under the Clean Air Act.  

34. Pg. 1374 RLSO:  Section title appears to be inconsistent with text as edited; reviewer

recommends changing section title from “Links among emission budget trading programs that

only include affected EGUs” to “Links among emission budget trading programs that only

include affected EGUs or affected EGUs and applicable new fossil fired EGUs.”  

35. Page 1390 RLSO: Reviewer suggests removing these sentences on 1390: “As a result, the MWh

accounting method addresses interstate effects, because it inherently accounts for how

generation replacement and CO2 emission reduction impacts may cross state borders... Instead,

this accounting method is indifferent to avoided CO2 emission rates and creates the same
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number of zero‐emitting credits or adjustment for each MWh of energy generation or savings,

wherever they occur.” Reviewer notes these sentences may do more harm than good in calling

attention to the potential disparity between assumed emissions reductions from BSER and a

MWh‐only accounting approach applied uniformly across the range of target rates that entities

may be using for compliance, highlighting the potential detachment between a measured MWh

of savings and actual emissions avoided.

36. 36. Page 1399 RLSO: Reviewer suggests making the following edit to footnote 965 for clarity, or

if this is not what is meant, providing further clarification:

“As used here, a measure is “tied to a state plan” if it is issued an ERC under approved

procedures in a rate‐based emission standards plan, or represents quantified and verified MWh

energy generation or energy savings achieved by an approved state measure in a state measures

plan.”

37. Page 1452 RLSO: Reviewer recommends clarifying the following sentences because in the

current version it sounds as if only NGCC generation below 2012 levels generates ERCs using this

equation, but all NGCC generation should create ERCs in this manner plus there should be a way

of accounting for ERCs due to building block 2 replacing fossil steam which is what EPA requires

states to propose an accounting method for or to use the method that is in the final model rule.

“For an affected NGCC stationary combustion turbine, the following equation provides a required

accounting method for the non‐incremental generating ERCs based on operation expected:(EPA

could add a footnote here if they think it is needed to make it clear that NGCC generation from

BB2 that displaces steam generation also can create ERCs using a different accounting

mechanism.)

ERCs = total NGCC reported MWh x ((NGCC CO2 emission standard – NGCC reported CO2

emission rate)/ NGCC CO2 emission standard)

According to this equation, ERC issuance is assessed based on the difference between the

CO2 emission rate limit for the NGCC unit and the reported CO2 emission rate of the affected

NGCC unit. In other words, affected NGCC stationary combustion turbines earn ERCs for non‐

incremental all generation when they perform at an emission rate better than the reference rate

for stationary combustion turbines, similarly to how affected steam units can earn ERCs.”  

38. Page 1453 RLSO: “A state plan that provides for the use of ERCs issued based on incremental

affected NGCC generation must provide a required calculation method that allows for issuance of

ERCs based on the ability of incremental generation from affected stationary combustion turbines

to substitute for generation from affected steam generating units (as represented in building

block 2), while also respecting the fact that affected stationary combustion turbines must also

meet an assigned CO2 emission rate limit for the entirety of its MWh energy output. This

accounting method must reflect the application of the BSER, as described in section V, and the

accounting method must not create incentivesto rearrange dispatch between existing NGCC units

to generate additional ERCs without changing the overall level of NGCC generation.”

39. Page 1528‐30 RLSO: Reviewer recommends that the “ready for interstate trading” options listed

on pages 1528‐30 must restate, for clarity, that these options are only possible for states that

have adopted the subcategory emissions standards, as described on 1526‐27.  

40. Page 1555‐56: Current text read: “The incentive to target the location of zero‐emitting

generation or energy savings between states based on variation in its emission reduction value

has been minimized by the fact that states participating in rate‐based interstate trading must
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adopt the same emission performance rates or rate‐based state goals.” Reviewer recommends

adding a clause at the end to refer to the section where these restrictions appear, as reviewer

was unable to locate a specific section where these two options for interstate trading were

clearly established.  

41. Page 1881 RLSO: Reviewer notes that two definitions appear to be missing on page

1881:“Compliance Period means...”

“Demand‐side energy efficiency means...

42. Page 1896 RLSO: Reviewer recommends double checking the calculation of Georgia’s mass goal.  
Summary	of	Interagency	Working	Comments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Review.

*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

6560-50

EO 12866_CPP 2060 AR33 Final_20150724 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[EPA-HQ-OAR-2013-0602; FRL-XXXX-XX-OAR]

RIN 2060-AR33 

Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: In this action, the Environmental Protection Agency 

(EPA) is establishing final emission guidelines for states to 

follow in developing plans to reduce greenhouse gas emissions 

from existing fossil fuel-fired electric generating units 

(EGUs). Specifically, the EPA is establishing: 1) state-specific 

carbon dioxide (CO2) goals reflecting CO2 emission performance 

rates based on the best system of emission reduction (BSER) for 

two subcategories of existing fossil fuel-fired EGUs, fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, and 2) guidelines for the 

development, submittal and implementation of state plans that 

establish emission standards or other measures to implement the 

CO2 emission performance rates. This final rule will continue 

Deleted: , U.S. territories, and tribes

Deleted: carbon dioxide (CO2) 

Deleted: of performance 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 2 of 1544

progress already underway in the U.S. to reduce CO2 emissions 

from the utility power sector. 

DATES: The final rule is effective on [INSERT THE DATE 60 DAYS 

AFTER PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: Docket. The EPA has established a docket for this 

action under Docket No. EPA–HQ–OAR–2013-0602. All documents in 

the docket are listed in the http://www.regulations.gov index. 

Although listed in the index, some information is not publicly 

available (e.g., confidential business information (CBI) or 

other information for which disclosure is restricted by 

statute). Certain other material, such as copyrighted material, 

will be publicly available only in hard copy. Publicly available 

docket materials are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 

Center, EPA WJC West Building, Room 3334, 1301 Constitution 

Ave., NW, Washington, DC. The Public Reading Room is open from 

8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal 

holidays. The telephone number for the Public Reading Room is 

(202) 566-1744, and the telephone number for the Air Docket is 

(202) 566-1742. For additional information about the EPA’s 

public docket, visit the EPA Docket Center homepage at 

http://www2.epa.gov/dockets.

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Page 3 of 1544

World Wide Web. In addition to being available in the 

docket, an electronic copy of this final rule will be available 

on the World Wide Web (WWW). Following signature, a copy of this 

final rule will be posted at the following address: 

http://www2.epa.gov/cleanpowerplan/. A number of documents 

relevant to this rulemaking, including technical support 

documents, a legal memorandum, and the regulatory impact 

analysis, are also available at 

http://www.epa.gov/cleanpowerplan/. These and other related 

documents are also available for inspection and copying in the 

EPA docket for this rulemaking. 

FOR FURTHER INFORMATION CONTACT: Ms. Amy Vasu, Sector Policies 

and Programs Division (D205-01), U.S. EPA, Research Triangle 

Park, NC 27711; telephone number (919) 541-0107, facsimile 

number (919) 541-4991; email address: vasu.amy@epa.gov or Mr. 

Colin Boswell, Measurements Policy Group (D243-05), Sector 

Policies and Programs Division, U.S. EPA, Research Triangle 

Park, NC 27711; telephone number (919) 541-2034, facsimile 

number (919) 541-4991; email address: boswell.colin@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Acronyms. A number of acronyms and chemical symbols are 

used in this preamble. While this may not be an exhaustive list, 

to ease the reading of this preamble and for reference purposes, 
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Page 4 of 1544

the following terms and acronyms are defined as follows: 

ACEEE American Council for an Energy Efficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and Congress of 

Industrial Organizations 

ASTM American Society for Testing of Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CEMS Continuous Emissions Monitoring System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE U.S. Department of Energy 

ECMPS Emissions Collection and Monitoring Plan System 

EERS Energy Efficiency Resource Standard 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EM&V Evaluation, Measurement and Verification 

EO Executive Order 

EPA Environmental Protection Agency 

FERC Federal Energy Regulatory Commission 

ERC Emission Rate Credit 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt 

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

LBNL Lawrence Berkeley National Laboratory 

MMBtu Million British Thermal Units 

MW Megawatt 

MWh Megawatt-hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

Commissioners 

NAS National Academy of Sciences 

Commented [A1]: ? 
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NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

OMB Office of Management and Budget 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission Organization 

SBA Small Business Administration 

SBC System Benefits Charge 

SCC Social Cost of Carbon 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

Tg Teragram (one trillion (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate 

Change 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. General Information 

A. Executive Summary 

B. Organization and Approach for this Final Rule 

II. Background 

A. Climate Change Impacts from GHG Emissions 

B. GHG Emissions from Fossil Fuel-Fired EGUs 

C. The Utility Power Sector 

D. Challenges in Controlling Carbon Dioxide Emissions 

E. Clean Air Act Regulations for Power Plants 

Deleted: 
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F. Congressional Awareness of Climate Change 

G. International Agreements and Actions 

H. Statutory and Regulatory Requirements 

I. Legislative and Regulatory Background for CAA Section 111 

J. Clean Power Plan Proposal and Supplemental Proposal 

K. Stakeholder Outreach and Consultations 

L. Comments on the Proposal 

III. Rule Requirements and Legal Basis

A. Summary of Rule Requirements 

B. Summary of Legal Basis 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Categories

A. EPA’s Authority under CAA Section 111(d)

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority 

C. Authority to Regulate EGUs 

D. Definition of Affected Sources 

E. Combined Categories and Codification in the Code of Federal 

Regulations 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

A. The Best System of Emission Reduction (BSER) 

B. Legal Discussion of Certain Aspects of the BSER 

C. Building Block 1—Efficiency Improvements at Affected Coal- 

 Fired Steam EGUs 

D. Building Block 2—Generation Shifts Among Affected EGUs 

E. Building Block 3—Renewable Generating Capacity 

VI. Subcategory-Specific CO2 Emission Performance Rates 

A. Overview 

B. Emission Performance Rate Requirements 

C. Form of the Emission Performance Rates 

VII. Statewide CO2 Goals 

A. Overview 

B. Translating Subcategory-Specific Emission Performance Rates 

to Statewide CO2 Emission Performance Goals 

VIII. State Plans 

A. Overview 

B. Timeline for State Plan Performance and Provisions to 

Encourage Early Action 

C. State Plan Approaches 

D. State Plan Components and Approvability Criteria 

E. State Plan Submittal and Approval Process and Timing 

F. State Plan Performance Demonstrations 

G. Additional Considerations for State Plans 

H. Resources for States to Consider in Developing Plans 

I. Considerations for CO2 Emission Reduction 

 Measures that Occur at Affected EGUs 

Deleted: ’

Deleted: ic

Deleted: E

Deleted: F

Deleted: G

Deleted: H

Deleted: I

Deleted: J

Deleted: Source 

Deleted: C

Deleted: Source C
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Page 7 of 1544

J. Additional Considerations and Requirements for Mass-Based 

State Plans 

K. Additional Considerations and Requirements for Rate-Based 

State Plans 

J. Treatment of Interstate Effects and Leakage 

IX. Community and Environmental Justice Considerations 

A. Proximity Analysis 

B. Community Engagement in State Plan Development 

C. Providing Communities with Access to Additional Resources 

D. Federal Programs and Resources Available to Communities 

E. Multi-pollutant Planning and Co-pollutants

F. Assessing Impacts of State Plan Implementation

G. EPA Continued Engagement 

X. Interactions with Other EPA Programs and Rules 

A. Implications for the NSR Program 

B. Implications for the Title V Program 

C. Interactions with Other EPA Rules 

XI. Impacts of this Action 

A. What are the air impacts? 

B. Endangered Species Act 

C. What are the energy impacts? 

D. What are the compliance costs? 

E. What are the economic and employment impacts? 

F. What are the benefits of the proposed action? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments 

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

XIII. Statutory Authority 

Deleted: <#>Title VI¶

Deleted: Key Changes from Proposal
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Page 8 of 1544

I. General Information 

A. Executive Summary 

1. Introduction 

This final rule is a significant step forward in reducing 

greenhouse gas emissions in the United States. In this action, 

the EPA is establishing for the first time emission guidelines 

for existing power plants. These final emission guidelines will 

lead to significant CO2 emission reductions from the utility 

power sector that will help protect human health and the 

environment from the impacts of climate change, while advancing 

clean energy innovation, development and deployment. This rule 

establishes the foundation of a long-term clean energy policy 

that will ensure the reliability of our electric system, 

maintain affordability for consumers, and establish the U.S. as 

a leader in addressing climate change. This final rule is the 

result of unprecedented outreach and engagement with states, 

tribes, utilities, and other stakeholders, with stakeholders 

providing more than 4.3 million comments on the proposed rule. 

In this final rule, we have addressed the comments and concerns 

of states and other stakeholders while staying consistent with 

the law. As a result, we have followed through on our commitment 

to issue a plan that is fair, flexible and builds momentum for 

Deleted: and Purpose of the Regulatory Action

Deleted: .
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 9 of 1544

the transition to a clean energy future that is already well 

under way in the utility power sector. 

Under the authority of Clean Air Act (CAA) section 111(d), 

the EPA is establishing CO2 emission guidelines for existing 

fossil fuel-fired electric generating units (EGUs) – the Clean 

Power Plan. These final guidelines, when fully implemented, will 

achieve significant reductions in CO2 emissions by 2030, while

offering states and utilities substantial flexibility and 

latitude in achieving these reductions. In this final rule, the 

EPA is formulating a CO2 emission performance rate for each of 

two subcategories of fossil fuel-fired EGUs -- fossil fuel-fired 

electric steam generating units and stationary combustion 

turbines – that expresses the “best system of emissions 

reduction ... adequately demonstrated” (BSER) for CO2 from the 

power sector.1 The EPA is also establishing state-specific ratebased and mass-based goals that reflect the subcategory-specific 

 

1 Under CAA section 111(d), pursuant to 40 CFR 60. 22(b)(5), 

states must establish, in their state plans, emission standards 

that reflect the degree of emission limitation achievable 

through the application of the “best system of emission 

reduction” that, taking into account the cost of achieving such 

reduction and any non-air quality health and environmental 

impacts and energy requirements, the Administrator determines 

has been adequately demonstrated (i.e., the BSER). Under CAA 

section 111(a)(1) and (d), the EPA is authorized to determine 

the BSER and to calculate the amount of emission reduction 

achievable through applying the BSER. The state is authorized to 

identify the emission standard or standards that reflect that 

amount of emission reduction.

Deleted: As in the proposal, t

Deleted: . At the same time, the guidelines

Deleted: has established
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 10 of 1544

CO2 emission performance rates and each state’s mix of affected 

EGUs. The guidelines also provide for the development, submittal 

and implementation of state plans that implement the BSER – 

again, expressed as CO2 emission performance rates, either 

directly by means of source-specific emission standards or other 

requirements, or through measures that achieve equivalent CO2

reductions from the same group of EGUs. 

States with one or more affected EGUs will be required to 

develop and implement plans that set emission standards for 

affected EGUs.2,3 These emission standards may incorporate the 

subcategory-specific CO2 emission performance rates set by the 

 

2

 In the case of a tribe that has one or more affected EGUs in its area of Indian country, the tribe has the opportunity, 

but not the obligation, to establish a CO2 emission standard for each affected EGU located in its area of Indian 

country and a CAA section 111(d) plan for its area of Indian country. If the tribe chooses to establish its own plan, it

must seek and obtain authority from the EPA to do so pursuant to 40 CFR 49.9. If it chooses not to seek this 

authority, the EPA has the responsibility to determine whether it is necessary or appropriate, in order to protect air 

quality, to establish a CAA section 111(d) plan for an area of Indian country where affected EGUs are located. 3 The CAA section 111(d) emission guidelines that the EPA is 

promulgating in this action apply to only the 48 contiguous 

states and any Indian tribe that has been approved by the EPA 

pursuant to 40 CFR 49.9 as eligible to develop and implement a 

CAA section 111(d) plan. Because Vermont and the District of 

Columbia do not have affected EGUs, they will not be required to 

submit a state plan. Because certain aspects of the rationale 

underlying the BSER do not apply to areas that have electric 

grids that are isolated from the 48 contiguous states and 

because the EPA lacks appropriate information to quantify the 

BSER for the two non-contiguous states with otherwise affected 

EGUs (Alaska and Hawaii) and the two U.S. territories with 

otherwise affected EGUs (Guam and Puerto Rico), these emission 

guidelines do not apply to those areas at this time, and those 

areas will not be required to submit state plans consistent with 

the schedule required by this final action.

Deleted: of performance 

Commented [A2]: Font in the footnote 2 

Deleted: , U.S. territories, and tribes

Deleted: with one or more affected EGUs will 

be required to develop and implement plans 

that set emission standards for affected EGUs.

These standards must be equal to the 

subcategory-specific CO2 emission performance 

rates set by EPA or, in the alternative, set 

at levels that ensure that their affected 

EGUs, individually, in aggregate, or in 

combination with other measures undertaken by 

the state

Deleted: A state plan must be developed by a 

state, the District of Columbia, a U.S. 

territory, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as 

eligible to develop and implement a CAA 

section 111(d) plan if it has one or more 

affected EGUs in its jurisdiction 

Deleted: EPA first determines whether 

development of a CO2 emission standard and a 

section 111(d) plan is appropriate and 

necessary. If so, 

Deleted: EPA determines that such a plan is 

necessary or appropriate

Deleted: 

Deleted: s

Deleted: s

Deleted: sources 

Deleted: unless a tribe on whose lands an 

affected source (or sources) is located seeks 

and obtains authority from the EPA to develop 

and implement a CAA section 111(d) plan, 

pursuant to the 40 CFR 49.9

Deleted: ¶

Deleted: 50 

Deleted: , the District of Columbia, U.S. 

territories,

Deleted: In this preamble, in instances where 

these governments are not specifically listed, 

the term “state” is used to represent them. 

Deleted: we are not finalizing 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 11 of 1544

EPA or, in the alternative, may be set at levels that ensure 

that the state’s affected EGUs, individually, in aggregate, or 

in combination with other measures undertaken by the state 

achieve the equivalent of the interim and final CO2 emission 

performance rates between 2022 and 2029 and by 2030, 

respectively. State plans must also: 1) ensure that emission 

reductions from the affected EGUs begin no later than 2022, 2) 

show how goals for the interim and final periods will be met, 3) 

ensure that, during the period from 2022 to 2029, affected EGUs 

in the state collectively meet the equivalent of the interim 

subcategory-specific CO2 emission performance rates, and 4) 

provide for periodic state-level demonstrations prior to and 

during the 2022-2029 period that will ensure that required CO2

emission reductions are being accomplished and that no increases

in emissions relative to each state’s planned emission reduction 

trajectory are occurring. A Clean Energy Incentive Program will 

provide opportunities for investments in renewable energy and 

energy efficiency that deliver results in 2020 and 2021. The 

plans must be submitted to the EPA in 2016, though an extension 

to 2018 is available to allow for the completion of stakeholder 

and administrative processes. 

The EPA is promulgating 1) subcategory-specific CO2

emission performance rates, 2) state rate-based goals, and 

Deleted: and

Deleted: . The EPA recognizes that successfully 

in achieving reductions byeginning in 2022 

will require implementing actions by states 

and utilities that lead to some CO2 emission 

reductions prior to 2022. ThereforeTo provide 

that public with assurance that such actions 

are being undertaken in a timely way, the EPA 

is requiring states to demonstrate that they 

are taking actions that will ensure that 

emission reductions from affected EGUs begin 

no later than 2022. 

Deleted: P

Deleted: inadvertent 

Deleted: has translated

Deleted: the source 

Deleted: intoas 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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3) state mass-based CO2 goals that represent the equivalent 

of each state’s rate-based goal. This will facilitate 

states’ choices in developing their plans, particularly for 

those seeking to adopt mass-based allowance trading 

programs or other statewide policy measures as well as, or 

instead of, source-specific requirements. 

In this summary, we discuss the purpose of this rule, the 

major provisions of the final rule, the context for the 

rulemaking, key changes from the proposal, the estimated CO2

emission reductions, and the costs and benefits expected to 

result from full implementation of this final action. Greater 

detail is provided in the body of this preamble, the regulatory 

impacts analysis (RIA), the response to comments documents, and 

various technical support documents and memoranda addressing 

specific topics. 

2. Purpose of this rule 

The purpose of this rule is to protect human health and the 

environment by reducing CO2 emissions from fossil fuel-fired 

power plants in the U.S. These plants are by far the largest 

domestic stationary source of emissions of carbon dioxide (CO2), 

the most prevalent of the group of air pollutant greenhouse 

gases (GHG) that the EPA has determined endangers public health 

and welfare through its contribution to climate change. This 

Deleted: is also promulgating equivalent 

Deleted: -level

Deleted: rate-based and m

Deleted: e

Deleted: in order to maximize the range of 

Deleted: including the 

Deleted: ion of

Deleted: application of

Deleted: m

Deleted: , that states will have in 

developing their plans.

Deleted: the 

Deleted: key changes from the proposal, the 

context for the rulemaking, 

Deleted: CAA section 111(d) 

Deleted: address

Deleted: because they 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 13 of 1544

rule establishes for the first time emission guidelines for 

existing power plants. These guidelines will lead to significant 

reductions in CO2 emissions, result in cleaner generation from 

the existing power plant fleet, and support continued 

investments by the industry in cleaner power generation to 

ensure reliable, affordable electricity now and into the future. 

Concurrent with this action, the EPA is also issuing a 

final rule that establishes CO2 emission standards of performance 

for new, modified, and reconstructed power plants. Together, 

these rules will reduce CO2 emissions by a substantial amount 

while ensuring that the utility power sector in the U.S. can 

continue to supply reliable and affordable electricity to all 

Americans using a diverse fuel supply. As with past EPA rules 

addressing air pollution from the utility power sector, these 

guidelines have been designed with a clear recognition of the 

unique features of this sector. Specifically, the agency 

recognizes that utilities provide an essential public service 

and are regulated and managed in ways unlike any other 

industrial activity. In providing assurances that the emission 

reductions required by this rule can be achieved without 

compromising continued reliable, affordable electricity, this 

final rule fully accounts for the critical service that 

utilities provide. 

Deleted: that

Deleted: . At the same time, these emission 

guidelines will 

Deleted: will

Deleted: e

Deleted: while reducing CO2 emissions by a 

substantial amount

Deleted: T

Deleted: entirely 

Deleted: almost 

Deleted: for 

Deleted: T

Deleted: takes that into

Commented [A3]: insert 

Deleted: in providing assurances for continued 

reliable, affordable electricity
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Page 14 of 1544

As with past rules under CAA section 111, this rule relies 

on proven technologies and measures to set achievable emission 

performance rates that will lead to cost-effective pollutant 

emission reductions, in this case CO2 emission reductions at 

power plants, across the country. In fact, the emission 

guidelines reflect strategies, technologies and approaches 

already in widespread use by utilities and states. The vast 

preponderance of the input we received from stakeholders is 

supportive of this conclusion. 

States will play a key role in ensuring that emission 

reductions are achieved at a reasonable cost. The experience of 

states in this regard is especially important because CAA 

section 111(d) relies on the well-established state-EPA 

partnership to accomplish the required CO2 emission reductions. 

States will have the flexibility to choose from a range of plan 

approaches and measures, including numerous measures beyond 

those considered in setting the CO2 emission performance rates, 

and this final rule allows and encourages states to adopt the 

most effective set of solutions for their circumstances, taking 

account of cost and other considerations. This rulemaking, which 

will be implemented through the state-EPA partnership, is a 

significant step that will reduce air pollution, in this case 

GHG emissions, in the U.S. At the same time, the final rule 

Deleted: Like 

Deleted: approaches 

Deleted: standards 

Deleted: CO2

Deleted: CAA section 111(d) itself relies on a 

state-EPA partnership to accomplish the 

required CO2 emission reductions. 

Deleted: choose effective, lower 

Deleted: solutions

Deleted: that 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 15 of 1544

greatly facilitates flexibility for EGUs by establishing a basis 

for states to set trading-based emission standards and 

compliance strategies. The rule establishes this basis by 

including both uniform emission performance rates for the two 

subcategories of sources and also state-by-state rate- and massbased goals.

This final rule is a significant step forward in 

implementing the President’s Climate Action Plan.4 To address the 

far-reaching harmful consequences and real economic costs of 

climate change, the President’s Climate Action Plan details a 

broad array of actions to reduce GHG emissions that contribute 

to climate change and its harmful impacts on public health and 

the environment. Climate change is already occurring in this 

country, affecting the health, economic well-being and quality 

of life of Americans across the country, and especially those in 

the most vulnerable communities. This CAA section 111(d) 

rulemaking to reduce GHG emissions from existing power plants, 

and the concurrent CAA section 111(b) rulemaking to reduce GHG 

emissions from new, modified, and reconstructed power plants, 

implement one of the strategies of the Climate Action Plan. 

 

4 The President’s Climate Action Plan, June 2013. 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf 

Deleted: sourceDeleted: y

Deleted: , and thus establishing in the rule 

itself the basis for emissions trading, the 

final rule greatly facilitates flexibility for 

EGUs by way of trading-based standards of 

performance and compliance strategies
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Nationwide, by 2030, this final CAA section 111(d) existing 

source rule will achieve CO2 emission reductions from the utility 

power sector of approximately [X] percent from CO2 emission 

levels in 2005. 

The EPA projects that these reductions, along with 

reductions in other air pollutants resulting directly from this 

rule, will result in net climate and health benefits of $[X] 

billion to $[X] billion. At the same time, coal and natural gas 

will remain the two leading sources of electricity generation in 

the U.S., with coal providing about [X] percent of the projected 

generation and natural gas providing about [X] percent of the 

projected generation. 

3. Summary of major provisions 

a. Overview. The fundamental goal of this rule is to reduce 

harmful emissions of CO2 from fossil fuel-fired EGUs in 

accordance with the requirements of the Clean Air Act. The June 

2014 proposal for this rule was designed to meet this 

overarching goal while accommodating two important objectives. 

The first was to establish guidelines that reflect both the 

unique interconnected and interdependent manner in which the 

power system operates and the actions, strategies, and policies 

states and utilities have already been undertaking that are 

resulting in CO2 emission reductions. The second objective was to 

Commented [A4]: 32? 

Deleted: , to which

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Commented [A5]: ? 

Commented [A6]: ? 

Deleted: reflected 

Deleted: over-riding

Deleted: :

Deleted: ,

Deleted: shape the standards set for EGUs to 

Deleted: measures

Deleted: underway across states and the utility 

sector 

Deleted: s

Deleted: , and

Deleted: ,
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 17 of 1544

provide states and utilities with broad flexibility and choice 

in meeting those requirements in order to minimize costs to 

ratepayers and to ensure the reliability of electricity supply. 

In this final rule, the EPA has focused on changes that, in 

addition to being responsive to the critical concerns and 

priorities of stakeholders, more fully accomplish these 

objectives. 

While there are notable revisions from the emission 

guidelines we proposed in June 2014, the proposed guidelines 

remain the foundation of this final rule. These final guidelines 

build on the progress already under way to reduce the carbon 

intensity of power generation in the U.S., especially through 

the lowest carbon-intensive technology, while reflecting the 

unique interconnected and interdependent system within which 

EGUs operate. Thus, the BSER, as determined in these guidelines, 

incorporates a range of CO2-reducing actions, while at the same 

time adhering to the fundamental approach the EPA has relied on 

for decades in implementing section 111 of the Clean Air Act. 

Equally important, these guidelines offer states and owners 

and operators of EGUs broad flexibility and latitude in 

complying with their obligations. Because affordability and 

electricity system reliability are of paramount importance, the 

rule provides states and utilities with time for planning and 

Deleted: maximum flexibility, control and 

choice in meeting their compliance obligations

Deleted: comment

Deleted: two crucial 

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Deleted: are

Deleted: First, t

Deleted: United States (

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Deleted: Second, these guidelines

Deleted: 

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Deleted: continues to 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 18 of 1544

investment, which is instrumental to ensuring both manageable 

costs and system reliability, as well as to facilitating clean 

energy innovation. The final rule continues to express the CO2

emission reduction requirements in terms of state goals

reflecting the particular mix of power generation in each state, 

and it continues to provide until 2030, fifteen years from the 

date of this final rule, for states and sources to achieve the 

CO2 reductions, which numerous commenters, including most 

sources, states and energy agencies, indicated was a reasonable 

timeframe. The final guidelines also continue to provide an 

option where programs beyond those directly limiting power plant 

emission rates can be used for compliance (i.e., policies, 

programs and other measures). The final rule also continues to 

allow, but not require, multi-state approaches. Finally, EPA 

took care to ensure that states could craft their own emissions 

reduction trajectories in meeting the interim goals included in 

this final rule.

b. Opportunities for states. As stated above, the final 

guidelines are designed to build on and reinforce progress by 

states, cities and towns, and companies on a growing variety of 

sustainable strategies to reduce power sector CO2 emissions.

States, in their CAA section 111(d) plans, will be able to rely 

on, and extend, programs they may already have created to 

Deleted: – indeed, provides more time -

Deleted: and

Deleted: a 

Deleted: that 

Deleted: s

Deleted: affecting 

Deleted: does 

Deleted: Because, a

Deleted: ,

Deleted: s

Deleted: in their CAA section 111(d) plans 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 19 of 1544

address emissions of air pollutants, and in particular CO2, from

the utility power sector or to address the sector from an 

overall perspective. Those states committed to Integrated 

Resource Planning (IRP) will be able to establish their CO2

reduction plans within that framework, while states with a more 

deregulated power sector system will be able to develop CO2

reduction plans within that specific framework. Each state will 

have the opportunity to take advantage of a wide variety of 

strategies for reducing CO2 emissions from affected EGUs, 

including demand-side energy efficiency programs and mass-based 

trading, which some suggested in their comments. The EPA and 

other federal entities, including the U.S. Department of Energy 

(DOE), the Federal Energy Regulatory Commission (FERC) and the 

U.S. Department of Agriculture, among others, are committed to 

sharing expertise with interested states as they develop and 

implement their plans. 

States will be able to address the economic interests of 

their utilities and ratepayers by using the flexibilities in 

this final action to reduce costs to consumers, minimize 

stranded assets, and spur private investments in renewable 

energy and energy efficiency technologies and businesses. They 

may also, if they choose, work with other states on multi-state 

approaches that reflect the regional structure of electricity 

Deleted: pollution,

Deleted: emissions

Deleted: in

Deleted: their power

Deleted: : 1) 

Deleted: ; and 2)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 20 of 1544

operating systems that exists in most parts of the country and 

is critical to ensuring a reliable supply of affordable energy. 

The final rule gives states the flexibility to implement a broad 

range of approaches that recognize that the utility power sector 

is made up of a diverse range of companies of various sizes that 

own and operate fossil fuel-fired EGUs, including vertically 

integrated companies in regulated markets, independent power 

producers, rural cooperatives and municipally-owned utilities, 

some of which are likely to have more direct access than others 

to certain types of GHG emission reduction opportunities, but 

all of which have a wide range of opportunities to achieve 

reductions or acquire clean generation. 

Again, with features that facilitate mass-based and/or 

interstate trading, the final guidelines also empower affected 

EGUs to pursue a broad range of choices for compliance and for 

integrating compliance action with the full range of their 

investments and operations.

c. Main elements. This final rule comprises two main elements: 

1) state-specific CO2 goals, expressed as both emission rates and 

as mass, that reflect the state’s fleet-weighted aggregate of 

two subcategory-specific CO2 emission performance rates resulting 

from application of the BSER to the two subcategories of 

affected EGUs; and 2) guidelines for the development, submittal 

Deleted: in adding

Deleted: has

Deleted: three 

Deleted: numerical

Deleted: source 

Deleted: , which can be adopted by states as 

emission standards of performance for their 

EGUs (which standards, in turn, can 

incorporate emissions trading); 2) 

tailoredstate-specific state-level CO2 goals 

that are translated fromexpress the weighted 

aggregate of these emission performance rates 

based on each state’s fleet, 

Deleted: 3
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 21 of 1544

and implementation of state plans that implement those BSER 

emission performance rates either through emission standards for 

affected EGUs, or through measures that achieve the equivalent, 

in aggregate, of those rates as defined and expressed in the 

form of the state goals. 

In this final action, the EPA is setting emission 

performance rates, phased in over the period from 2022 

through 2030, for two subcategories of affected fossil 

fuel-fired EGUs – fossil fuel-fired electric utility steamgenerating units and stationary combustion turbines. These 

rates, applied to each state’s particular mix of fossil 

fuel-fired EGUs, generate the state’s carbon intensity goal 

for 2030 (and interim rates for the period 2022-2029). Each 

state will determine whether to apply these to each 

affected EGU or to take an alternative approach and meet 

either an equivalent statewide rate-based goal or statewide 

mass-based goal. The EPA does not prescribe how a state 

must meet the emission guidelines, but if a state chooses 

to take the path of meeting a state goal, these final 

guidelines identify the methods that a state can or, in 

some cases, must, use to demonstrate that the combination 

of measures and standards that the state adopts meets its 

state-level CO2 goals. While the EPA accomplishes the phaseDeleted: directly

Deleted: of performance 

Deleted: determinedthat equivalent is 

Deleted: by 

Deleted: 5

Deleted: on a yearly basis 

Deleted: 9-year

Deleted: between

Deleted: and

Deleted: s

Deleted: do 

Deleted: which 

Deleted: does 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 22 of 1544

in of the interim goal by way of annual emission 

performance rates, states and EGUs may meet their 

respective emission reduction obligations “on average” over 

that period following whatever emission reduction 

trajectory they determine to pursue over that period.

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 implementing 

them by establishing emission standards or creating plans 

that are consistent with the EPA emission guidelines. The 

EPA recognizes that each state has differing policy 

considerations – including varying regional 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 

and generation mix) also differ. Therefore, as in the 

proposal, each state will have the latitude to design a 

program to meet source-category specific emission 

performance rates or the equivalent statewide rate- or 

mass-based goal in a manner that reflects its particular 

circumstances and energy and environmental policy 

objectives. Each state can do so on its own, or a state can 

collaborate with other states and/or tribal governments on 

Deleted: yearly

Deleted: of

Deleted: s
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 23 of 1544

multi-state plans, or states can include in their plans the 

trading tools that EGUs can use to realize additional 

opportunities for cost savings while continuing to operate 

across the interstate system through which electricity is 

produced. A state would also have the option of adopting 

the model rules for either a rate- or a mass-based program 

that the EPA is proposing concurrently with this action.6

To facilitate the state planning process, this final 

rule establishes guidelines for the development, submittal, 

and implementation of state plans. The final rule describes 

the components of a state plan, the additional latitude 

states have in developing strategies to meet the emission 

guidelines, and the options they have in the timing of 

submittal of their plans. This final rule also gives states 

considerable flexibility with respect to the timeframes for 

plan development and implementation, as well as the choice 

of emission reduction measures. The final rule provides up 

to fifteen years for full implementation of all emission 

reduction measures, with incremental steps for planning and 

then for demonstration of CO2 reductions that will ensure 

that progress is being made in achieving CO2 emission 

 

6 The EPA’s proposed CAA section 111(d) federal plan and model 

rules for existing fossil fuel-fired EGUs are being published 

concurrently with this final rule. 

Deleted: –

Deleted: In effect, a state could 

incorporate in its plan the substance of the 

federal plan EPA is proposing concurrently 

with this action and thus “opt in to” the 

federal plan or of becoming subject to the 

EPA’s federal plan. ¶

, also being proposed concurrent with this 

action.

Deleted: is 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 24 of 1544

reductions. States will be able to choose from a wide range 

of emission reduction measures, including measures that are 

not part of the BSER, as discussed in detail in section 

VIII.G of this preamble. 

d. Determining the BSER. In issuing this final rulemaking, 

the EPA is implementing statutory provisions that have been in 

place since Congress first enacted the CAA in 1970 and that have 

been implemented pursuant to regulations promulgated in 1975 and 

followed in numerous subsequent CAA section 111 rulemakings. 

These requirements call on the EPA to develop emission 

guidelines that reflect the EPA’s determination of the “best 

system of emission reduction... adequately demonstrated” (BSER)

for states to follow in formulating plans to establish emission 

standards to implement the BSER. 

As the EPA has done in making BSER determinations in 

previous CAA section 111 rulemakings, for this final BSER 

determination the agency considered the types of strategies that 

states and owners and operators of EGUs are already employing to 

reduce the covered pollutant (in this case, CO2) from affected 

sources (in this case, fossil fuel-fired EGUs).7 

 

7 The final emission guidelines for landfill gas emissions from 

municipal solid waste landfills, published on March 12, 1996 and 

amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 

respectively) are one example, as they allow either of two 

Deleted: ation of

Deleted: I

Deleted: implement 

Deleted: ing

Deleted: achieve emission reductions consistent 

with

Deleted: In following the provisions, the EPA 

is finalizing a BSER based on strategies 

currently being used by states and companies 

to reduce CO2 emissions from EGUs as the 

“best” approaches (e.g., ,on-site efficiency 

improvements, shifting to lower-emitting and 

zero-emitting generation).

Deleted: ,
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 25 of 1544

In this final action, the agency has determined that the 

BSER comprises the first three of the four proposed “building 

blocks,” with certain refinements to the three building blocks. 

The three building blocks are: 

1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units for 

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from zeroemitting generating units for reduced generation from 

affected fossil fuel-fired generating units. 

These three building blocks are approaches that are 

available to all affected EGUs, either through direct 

investment or operational shifts or through emissions 

trading where states, which must establish emission 

standards for affected EGUs, do so by incorporating 

 

approaches for controlling landfill gas – by recovering the gas as 

a fuel, for sale, and removing from the premises, or by 

destroying the organic content of the gas on the premises using 

a control device. Recovering the gas as a fuel source was a 

practice already being used by some affected sources prior to 

promulgation of the rulemaking. 

Deleted: ,

Deleted: The three building blocks – on-site 

efficiency improvements, generation shifts to 

existing gas, and use of renewable energy – 

are all approaches that are available to all 

affected EGUs either through direct investment 

or operational shifts or through emissions 

trading where states establish standards of 

performance that incorporate emissions 

trading. In addition, emission trading is also 

available. Theat states can establish 

standards of performance that incorporate 

emissions trading, along with the widely 

demonstrated availability of the trading of 

emission rate credits or mass allowances as a 

mechanism to facilitate achievement by any 

individual EGU or group of EGUs of the 

emission reductions available from each of the 

building blocks, as well as to reduce costs, 

supports this approach. Any affected EGU can 

achieve the equivalent of shifting generation 

to NGCC units, per building block 2, or of RE 

generation, per building block 3, by using the 

acquisition of a credit or allowance as the 

medium for investment in zero-emitting 

generation provided by RE facilities.

Deleted: The CAA, as interpreted by the courts, 

identifies several factors for the EPA to 

consider in a BSER determination. These 

include technical feasibility, costs, size of 

emission reductions and technology (e.g., 

whether the system promotes the 

implementationdeplymentdeployment and further 

development of technology). In determining the 

BSER for this industrial sector, the EPA 

considered the reductions achievable through 

measures that reduce CO2 emissions from 

existing fossil fuel-fired EGUs either by (1) 

reducing the CO2 emission rate at those units 

or (2) reducing the units’ CO2 emission total 

to the extent that generation can be shifted 

from higher-emitting fossil fuel-fired EGUs to 

lower- or zero-emitting options. ¶

As the EPA has done in making BSER 

determinations in previous CAA section 111(d) 

rulemakings, the agency considered the types 

of strategies that states and owners and 

operators of EGUs are already employing to 

reduce the covered pollutant (in this case, 

CO2) from affected sources (in this case, 

fossil fuel-fired EGUs).8 ¶

To determine the BSER for reducing CO2

emissions at affected EGUs and to establish 

the emission guidelines that reflect the BSER, 

the EPA considered numerous measures that can 

and are being implemented to improve emission 

rates and to reduce or limit mass CO2

emissions from fossil fuel-fired EGUs. These 

measures encompass two basic approaches: 1) 

reducing the carbon intensity of certain 

affected EGUs by improving the efficiency of 

their operations, and 2) addressing affected 

EGUs’ mass emissions by varying their 

generation levels. For the second approach, we 

relied on the standard statutory and 

regulatory considerations that provide the 

basis for any BSER determination in examining, 

in this case, the extent to which that ... [1]
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 26 of 1544

emissions trading.9 The building blocks and the BSER 

determination are described in detail in section V of this 

preamble. 

e. CO2 state-level goals and subcategory-specific emission 

performance rate.

(1) Final CO2 goals and emission performance rates. 

In this action, the EPA is establishing CO2 emission 

performance rates for two subcategories of affected EGUs -- 

fossil fuel-fired electric utility steam generating units and 

stationary combustion turbines. For fossil fuel-fired steam 

generating units, we are finalizing an emission performance rate 

of 1,305 lbCO2/MWh. For stationary combustion turbines, we are 

finalizing an emission performance rate of 771 lbCO2/MWh. As we 

did at proposal, for each state, we are also promulgating ratebased CO2 goals that are the weighted aggregate of the emission 

performance rates for the state’s EGUs. To ensure that states 

and sources can choose additional alternatives in meeting their 

obligations, the EPA is also promulgating each state’s goal 

 

9 The EPA notes that, in quantifying the emission reductions that 

are achievable through application of the BSER, some building 

blocks will apply to some, but not all, affected EGUs. 

Specifically, building block 1 will apply to affected coal-fired 

steam EGUs, building block 2 will apply to all affected steam 

EGUs (both coal-fired and oil/gas-fired), and building block 3 

will apply to all affected EGUs. 

Deleted: S

Deleted: As explained in that section, the EPA 

evaluated each of the building blocks 

individually against the BSER factors. The EPA 

found that each of the building blocks 

independently merits consideration as part of 

the BSER because, at the identified level of 

stringency, it is achievable by individual 

sources and by the source category, it will 

result in meaningful emission reductions at 

reasonable cost, and it satisfies the other 

BSER factors. (For reasons discussed in 

Section V.A.3 of this preamble, the EPA 

determined not to finalize the inclusion of 

demand-side EE, which was discussed as a 

fourth potential building block in the June 

18, 2014 proposal, as a component of the 

BSER.)¶

The EPA also evaluated combinations of the 

three building blocks against the BSER factors 

in making its determination. The EPA 

determined that the combination of all three 

building blocks is the BSER.,. taking into 

account the fact that the widely demonstrated 

availability of the trading of emission rate 

credits or mass allowances can enable any 

given EGU to achieve its emission reduction 

obligations (i.e., if an EGU should choose not 

to meet its obligations simply by limiting its 

own operations, it could rely on the 

interconnected function of the electricity 

system to effectuate replacement generation 

from new clean generation or from shifting ... [2]

Deleted: source category-specific emission 

performance rates and 

Deleted: . 

Deleted: emission performance rates and 

Deleted: CO2 emission performance rates for two 

subcategories of affected EGUs-- fossil fuel- ... [3]

Deleted: 290

Deleted: of CO2

Deleted: 80

Deleted: of CO2

Deleted: have 

Deleted: set forth a

Deleted: is

Deleted: se

Deleted: the

Deleted: So long as the state’s plan is 

designed and implemented to meet that goal, ... [4]

Deleted: look

Deleted: to 

Deleted: . To that end, To continue to provide 

the flexibility inherent in the proposal’s ... [5]

Deleted: in this final rule, 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 27 of 1544

expressed as a CO2 mass goal. The inclusion of mass-based goals, 

along with information provided in the proposed federal plan and 

model rules that are being issued concurrently with this rule, 

paves the way for states to implement mass-based trading, as 

some states have requested. 

Affected EGUs, individually, in aggregate, or in 

combination with other measures undertaken by the state, 

must achieve the equivalent of the CO2 emission performance 

rates, expressed via the state-specific rate- and massbased goals, by 2030. 

(2) Interim CO2 emission performance rates and statespecific goals. 

The best system of emission reduction includes both the 

measures for reducing CO2 emissions and the timeframe over which 

they can be implemented. In this final action, the EPA is 

establishing an eight-year interim period, beginning in 2022 

instead of 2020, over which to achieve the full required 

reductions to meet the CO2 performance rates, a commencement date

more than six years from [INSERT THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], the date of this rulemaking. This eight-year 

interim period from 2022 through 2029 is separated into three 

steps, 2022-2024, 2025-2027, and 2028-2029, each associated with 

its own interim CO2 emission performance rates. The interim steps 

Deleted: limit that represents the equivalent 

of the state’s rate-based goal

Deleted: the EPA has translated the source 

category-specific CO2 emission performance 

rates into equivalent statewide rate-based and 

mass-based CO2 goals and is providing those in 

Section VII of this preamble.

Deleted: Thanks to t

Deleted: the

Deleted: -equivalent

Deleted: – 

Deleted: F

Deleted: P

Deleted: M

Deleted: R

Deleted: also

Deleted: – we believe we have 

Deleted: d

Deleted: As discussed earlier in this section 

and further in Section VIII, the full range of 

features, including the source-category 

performance rates, encompassed in the this 

final rule make interstate trading options 

readily available to EGUs by means other than 

extensively negotiated interstate agreements. 

Deleted: – expressed via the state rate- or 

mass-based goals – 

Deleted: Importantly, by expressing the 

application of the final BSER as source 

category-specific CO2 emission performance 

rates, and by providing a translation of 

those performance rates to statewide rateand mass-based CO2 goals, the rule allows 

states the flexibility to determine how to 

achieve the CO2 reductions (i.e., greater 

reductions from one building block and 

lessfewer 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. 

Deleted: level

Deleted: The EPA recognizes that, with many 

measures, states can achieve CO2 emission 

reductions in the short-term, in certain 

circumstances, such as those for which 

instrumental infrastructure and/or programs 

are already in place. For other measures, such ... [6]

Deleted: -

Deleted: and this begins in 2022,

Deleted: These steps respond to many comments 

we received requesting a more graduated ... [7]
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 28 of 1544

are presented both in terms of emission performance rates for 

the two subcategories of affected EGUs and in terms of state 

goals, expressed both as a rate and as a mass. A state may adopt 

emission standards for its sources that are identical to these 

interim emission performance rates or, alternatively, adapt 

these steps to accommodate the timing of expected reductions, as 

long as the state’s interim goal is met over the eight-year 

period. 

f. State plans.11

In this action, the EPA is establishing final 

guidelines for states to follow in developing, submitting 

and implementing their plans. In developing plans, states 

will need to choose the type of plan they will develop. 

They will also need to include required plan components in 

their plan submittals, meet plan submittal deadlines, 

 

11 The CAA section 111(d) emission guidelines apply to the 50 

states, the District of Columbia, U.S. territories, and any 

Indian tribe that has been approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and implement a CAA section 

111(d) plan. In this preamble, in instances where these 

governments are not specifically listed, the term “state” is 

used to represent them. Because Vermont and the District of 

Columbia do not have affected EGUs, they will not be required to 

submit a state plan. Because the EPA lacks appropriate 

information to quantify the BSER for the two non-contiguous 

states with affected EGUs (Alaska and Hawaii) and the two U.S. 

territories with affected EGUs (Guam and Puerto Rico), we are 

not finalizing emission performance rates in those areas at this 

time, and those areas will not be required to submit state plans 

until we do.

Deleted: . Al

Deleted: under this final the rule alsothe 

state retains a state’s the ability to 

Deleted: as appropriate 

Commented [A7]: Is there, or was there ever, an 8 year 

averaging alternative? 

Deleted: A state can take advantage of this 

timing in the design of its program by using 

relevant combinations of building blocks, as 

well as averaging over the interim period, to 

achieve required CO2 reductions in a manner 

and on a schedule that provides for 

electricity system reliability, avoids the 

creation of stranded assets and bears a 

reasonable cost. In short, to use the parlance 

of numerous state and stakeholder discussions, 

states can determine their own respective 

emission reduction trajectories or “glide 

paths”.¶

We believe that this approach for achieving 

CO2 reductions over time responds both to the 

needs of an effectively implemented program 

and to the persuasive arguments presented by 

stakeholders regarding balancing the 

simultaneous need for both flexibility and 

certainty about what will constitute an 

approvable state plan. We likewise believe 

that this approach also represents a 

reasonable balance between two competing 

objectives grounded in CAA section 111(d) - a 

need for rigor and consistency in calculating 

emission reductions reflecting the BSER and a 

need to provide the states with flexibility in 

establishing and implementing the emission 

standards or measures that reflect those 

emission reductions. The importance of this 

balance is heightened by the fact that the 

operations of the electricity system itself 

rely on the flexibility made available and 

achieved through shifting generation between 

and among multiple interconnected EGUs, demand 

management and demand-side energy efficiency. 

This approach recognizes that state plans for 

emission reductions can, and must, be 

consistent with a vibrant and growing economy 

and the ample supply of reliable, affordable 

electricity needed to support that economy. It 

further reflects the growing trend, as 

exemplified by many state and local clean 

energy policies and programs, to shift energy 

production away from carbon-intensive fuels to 

a modern, more sustainable system that puts 

greater reliance on renewable energy, energy 

efficiency and other low-carbon energy 

options.

Deleted: also 

Deleted: ¶

 A state plan must be developed by a state, 

the District of Columbia, a U.S. territory, 

and any Indian tribe that has been approved by 

the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) 

plan if it has one or more affected EGUs in 

its jurisdiction. The District of Columbia 

does not have any affected EGUs and, ... [8]
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 29 of 1544

achieve the required CO2 emission reductions over time, and 

provide for monitoring and periodic reporting of progress. 

As with the BSER determination, stakeholder comments have 

provided both data and recommendations to which these final 

guidelines are responsive. 

(1) Plan approaches. 

To comply with these emission guidelines, a state will have 

to ensure, in its plan, that the emission standards it 

establishes for its sources individually, in aggregate, or in 

combination with other measures undertaken by the state, 

represent the equivalent of the subcategory-specific CO2 emission 

performance rates. This final rule includes several options for 

state plans, as discussed in the proposal and in many of the 

comments we received. 

First, in the final rule, states may establish emission 

standards for their affected EGUs that mirror the uniform 

emission performance rates for the two subcategories of sources 

included in this final rule. They may also pursue alternative 

approaches that adopt either the rate-based goal promulgated for 

the state or the alternative mass-based goal promulgated for the 

state. It is for the purpose of providing states with these 

choices that the EPA is providing state-specific rate-based and 

mass-based goals equivalent to the emission performance rates 

Deleted: source 

Deleted: types of flexibilities

Deleted: under 

Deleted: of performance 

Deleted: e

Deleted: source 

Deleted: y

Deleted: a

Deleted: F

Deleted: is

Deleted: ,

Deleted: statewide 

Deleted: goals 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 30 of 1544

that the EPA is establishing for the two subcategories of fossil 

fuel-fired EGUs. A detailed explanation of rate- and mass-based 

goals is provided in section VII of this preamble and in a TSD.12

In developing its plan, each state and eligible tribe electing 

to submit a plan will need to choose whether it will include CO2

emission performance rates, statewide rate-based goals, or 

statewide mass-based goals. 

The second major set of options provided in the final rule 

includes the types of measures included in the state plans. A 

state will be able to choose to establish emission standards for 

its affected EGUs, thus placing all of the requirements directly 

on its affected EGUs, which we refer to as the “emission 

standards approach.” Alternatively, a state can adopt a “state 

measures approach,” which would include state-enforceable 

measures that may apply to affected EGUs and other entities, 

with some or no federally enforceable emission standards for 

affected EGUs. With a state measures approach, the plan must 

also include a contingent backstop of federally enforceable 

emission standards for affected EGUs that fully meet the 

emission guidelines and that would be triggered if the plan 

failed to achieve the required emission reductions on schedule. 

 

12 The CO2 Emission Performance Rate and Goal Computation TSD for 

the CPP Final Rule, available in the docket for this rulemaking. 

Deleted: , U.S. territory,

Deleted: flexibility

Deleted: relates

Deleted: to 

Deleted: of performance 

Deleted: e

Deleted: g

Deleted: c
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 31 of 1544

A state would have the option of basing its backstop emission 

standards on the model rule that the EPA is proposing today. A 

state that adopts a state measures approach must use its mass CO2

emission goal as the metric for demonstrating plan performance; 

however, the state could still choose to impose rate-based 

standards on its affected EGUs or implement a rate-based trading 

program. 

The final rule requires that the state plan submittal 

include a timeline with all of the programmatic milestone steps 

the state will take between the time of the state plan submittal 

and the year 2022 to ensure that the plan is effective as of 

2022. States must submit a report to the EPA in 2021 that 

demonstrates that the state has met the programmatic milestone 

steps that the state indicated it would take during the period 

from the submittal of the final plan through the end of 2020, 

and that the state is on track to implement the approved state 

plan as of January 1, 2022.

The plan must also include a process for reporting on plan 

implementation, progress toward achieving CO2 emission 

reductions, and implementation of corrective actions, if 

necessary. Beginning January 1, 2025, and then January 1, 2028, 

January 1, 2030, and then every two calendar years thereafter, 

the state will be required to compare emission levels achieved 

Deleted: federal plan, using the federal plan 

regulations as a 

Deleted: 

Commented [A8]: I don’t understand this. I thought that state 

rate measures was lead state option? 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 32 of 1544

by affected EGUs in the state with the emission levels projected 

in the state plan and report the results of that comparison to 

the EPA by July 1 of those calendar years. 

Plans for states with existing programs, such as those 

being implemented in California and the RGGI states, will 

be approvable provided that, when plans are submitted, they 

demonstrate that when the plans are fully implemented, 

affected EGUs achieve all of the emission reductions 

required by the guidelines during the interim and final 

periods for affected EGUs in their states. A state plan 

that uses one of the model rules, which the EPA is 

proposing concurrently with this action, will be 

presumptively approvable. The plan guidelines provide the 

states with the ability to achieve the full reductions over 

a multi-year period, through a variety of reduction 

strategies, using state-specific or multi-state approaches 

that can be achieved on either a rate or mass basis. They 

also address several key policy considerations that states 

can be expected to contemplate in developing their plans.

State plan approaches and plan guidelines are explained 

further in section VIII of this preamble. 

(2) State plan components and approvability criteria. 

Deleted: in

Deleted: se

Deleted: those states’ sources that are 

affected per these guidelines

Deleted: 

Deleted: S
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The EPA’s implementing regulations provide certain basic 

elements required for state plans submitted pursuant to CAA 

section 111(d).13 In the proposal, the EPA identified certain 

additional elements that should be contained in state plans. In 

this final action, in response to comments, the EPA is making 

several revisions to the components required in a state plan 

submittal and is also incorporating the approvability criteria 

into the list of components required in a state plan submittal. 

In addition, we have organized the state plan components to 

reflect: 1) components required for all state plan submittals; 

2) additional components required for the emission standards 

approach; and 3) additional components required for the state 

measures approach. 

All state plans must include the following components: 

 Description of the plan 

 Identification of state CO2 interim period goal (for 

2022-2029), interim steps (interim step goal 1 for 

2022-2024; interim step goal 2 for 2025-2027; interim 

step goal 3 for 2028-2029) and final CO2 emission goal 

of 2030 and beyond 

 Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal14

 State recordkeeping and reporting requirements 

 Certification of hearing on state plan 

 

13 40 CFR 60.23

14 A state that chooses to set emission standards that are 

identical to the emission performance rates for both the interim 

period and in 2030 and beyond need not identify interim state 

goals nor include a separate demonstration that its plan will 

achieve the state goals. 

Deleted: 40 CFR 60.23

Deleted: .

Deleted: revised 
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 Supporting documentation 

 

Also, in submitting state plans, states must provide 

documentation demonstrating that they have considered electric 

system reliability in developing their plans. 

Further, in this final rule, the EPA is requiring states to 

demonstrate how they are meaningfully engaging stakeholders,

including low-income communities, communities of color, and 

indigenous populations living near power plants and otherwise 

potentially affected by the state’s plan. We refer to these 

communities generally as “overburdened,” to encompass those 

communities that are central to our concern about environmental 

justice. In their plan submittals, states must describe their 

engagement with their stakeholders, including overburdened 

communities. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard will result in 

reductions that are quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

Commented [A9]: Recall that the state plans will have to 

address leakage and nuclear losses, as well. 

Deleted: that 

Deleted: actively 

Deleted: all 

Deleted: potentially affected

Deleted: and minority 

Deleted: communities 

Deleted: ’

Deleted: s

Deleted: initial and final 

Deleted: and complete plan submittal, 

Deleted: will have to

Deleted: provide a summary of how they are 

engaging with all 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure will result in reductions that are 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 

(3) Timing and process for state plan submittal and review. 

Because of the compelling need for actions to begin the steps 

necessary to reduce GHG emissions from EGUs, the EPA proposed 

that states submit their plans within 13 months of the date of 

this final rule and that reductions begin in 2020. Commenters, 

especially states, have provided compelling information about 

the steps needed to develop and put in place all of the 

components needed for a final state plan. The EPA accepts these 

comments, which we believe support: retaining the requirement 

that initial plans be submitted without additional delay and 

offering extensions that provide up to a full three years for 

submittal of final state plans. Specifically, the final rule 

requires each state to submit a plan by September 6, 2016. Since 

some states may need more than one year to complete all of the 

actions needed for their final state plans, including technical 

work, state legislative and rulemaking activities, a robust 

public participation process, coordination with third parties, 

Deleted: that it will take longer than the 

agency initially anticipated to adjust 

investments and achieve interim CO2

reductions. Commenters, especially states, 

have also provided further information 

Deleted: agrees with

Deleted: i) extending the start date of the 

compliance period from 2020 to 2022, andii) 

Deleted: ,

Deleted: while

Deleted: iii) 

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Deleted: August 

Deleted: 31
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coordination among states involved in multi-state plans, and

consultation with reliability entities, the EPA is allowing an 

optional two-phased submittal process for state plans. Each 

state will be required to submit a plan by September 6, 2016, 

that contains certain required components. If a state needs 

additional time to submit a final plan, then the state may 

submit an initial plan by September 6, 2016, that documents the 

reasons the state needs more time and includes commitments to 

concrete steps that will ensure that the state will submit a 

final plan by no later than September 6, 2018. To be approvable, 

the initial plan submittal must include information on all 

components of a final plan submittal, including identifying 

which components are not complete. The initial plan must include 

specific components, including a justification for seeking an 

extension, a description of the plan approach, a commitment to 

maintain existing measures that limit CO2 emissions, progress to 

date in developing a final plan, a comprehensive roadmap of the 

path to completion including specific steps the state, sources 

or other entities will be implementing in order to meet the 

initial compliance requirements beginning in 2022, demonstration 

of opportunity for public comment on the submittal and a summary 

of the state’s response to any significant public comment, and a 

description of the community engagement they have undertaken 

Deleted: and 

Deleted: as well as

Deleted: August 31

Deleted: August 31

Deleted: August 31

Deleted: the EPA is finalizing that 

Deleted: address 

Deleted: and 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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thus far and the means by which they intend to involve 

communities and other stakeholders in the development of their 

final plan, as described in section VIII.E of this preamble. As 

further described in this preamble, the EPA is establishing a 

Clean Energy Incentive Program (CEIP) in order to promote early 

action. States may participate in the CEIP at their option. In 

order to do so, a state must include in its initial submittal a 

non-binding statement of intent to participate in the CEIP.

If the initial submittal includes those components and if 

the EPA does not notify the state that the initial submittal 

does not contain the required components, then, within [60] days 

of the submittal [or by no later than November 5, 2016], the 

extension of time to submit a final plan will be deemed granted. 

A state will then have until the date included in its extension 

request, which could be no later than September 6, 2018, to 

submit a final plan. The EPA will also be working with states 

during the period after they make their initial submittals and 

provide states with any necessary information and assistance 

during the 60-day period. Further, states participating in a 

multi-state plan may submit a single joint plan on behalf of all 

of the participating states. 

States and tribes that do not have any affected EGUs in 

their jurisdictional boundaries may provide emission rate 

Deleted: on the approvability of the initial 

plan

Deleted: S

Deleted: 

Deleted: and a

Deleted: August 31

Deleted: , 

Deleted: U.S. territories, and tribes 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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credits (ERCs) to adjust CO2 emissions, provided they are 

connected to the continental U.S. grid and meet other 

requirements for eligibility. There are certain limitations and 

restrictions for generating ERCs, and these, as well as 

associated requirements, are explained in section VIII of this 

preamble.

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given the diverse 

approaches states may take to meet the CO2 emission 

performance rates or equivalent statewide goals in the 

emission guidelines, the EPA is extending the period for 

EPA review and approval or disapproval of plans from the 

four-month period provided in the EPA implementing 

regulations to a twelve-month period. This timeline will 

provide adequate time for the EPA to review plans and 

follow notice-and-comment rulemaking procedures to ensure 

an opportunity for public comment. The EPA, especially 

through our regional offices, will be available to work 

with states as they develop their plans, in order to make 

review of submitted plans more straightforward and to 

minimize the chances of unexpected issues that could slow 

down approval of state plans. 

(4) Timing for implementing the CO2 emission guidelines. 

Deleted: participate in emission trading 

programs (e.g., as providers of emission rate 

credits, to adjust CO2 emission rates for 

affected EGUs). 

Deleted: that 

Deleted: that provide
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 The EPA recognizes that the measures states and utilities 

have been and will be taking to reduce CO2 emissions from 

existing EGUs can take time to implement. We carefully reviewed 

information submitted to us regarding the feasible timing of 

various measures and identifying concerns that the required CO2

emission reductions could not be achieved as early as 2020 

without compromising electric system reliability, imposing 

unnecessary costs on ratepayers, and requiring investments in 

more carbon-intensive generation, while diverting investment in 

cleaner technologies. The record is compelling. To respond to 

these concerns and to reflect the period of time required for 

state plan development and submittal by states, review and 

approval by the EPA, and implementation of approved plans by 

states and affected EGUs, the EPA is determining in this final 

rule that affected EGUs will be required to begin to make 

reductions by 2022, instead of 2020, as proposed, and meet the 

final CO2 emission performance rates or equivalent statewide 

goals by no later than 2030. The EPA is establishing an eightyear interim period that begins in 2022 and goes through 2029, 

and which is separated into three steps, 2022-2024, 2025-2027, 

and 2028-2029, each associated with its own interim goal. 

Affected EGUs must meet each of the interim period step 1, 2, 

and 3 CO2 emission performance rates, or, following the emissions 

Deleted: affordability

Deleted: Based on a careful review of the 

comments and other material in the record
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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reduction trajectory designed by the state itself, must meet the 

equivalent statewide interim period goals, on average, that a 

state may establish over the 8-year period from 2022-2029. The 

CAA section 111(d) plan must include those specific 

requirements. Affected EGUs must also achieve the final CO2 

performance rates or the equivalent statewide goal by 2030 and 

maintain that level subsequently. This approach reflects 

adjustments to the timeframe over which reductions must be 

achieved that mirror the determination of the final BSER, which 

incorporates the phasing in of the BSER measures in keeping with 

the achievability of those measures. The agency believes that 

this approach for timing is reasonable and appropriate, is 

consistent with many of the comments we received, and will best 

support the optimization of overall CO2 reductions. 

The EPA recognizes that successfully achieving reductions 

by 2022 will be facilitated by actions and investments that 

yield CO2 emission reductions prior to 2022. The final guidelines 

include provisions to encourage early actions. States will be 

able to take advantage of the impacts of early investments that 

occur prior to the beginning of a plan performance period. Under 

a mass-based plan, those impacts will be reflected in reductions 

in the reported CO2 emissions of affected EGUs during the plan 

performance period. Under a rate-based plan, states may 

Deleted: The final rule requires that the state 

plan submittal include a timeline with all of 

the programmatic milestone steps the state 

will take between the time of the state plan 

submittal and the year 2022 to ensure that the 

plan is effective as of 2022. States must 

submit a report to the EPA in 2021 that 

demonstrates that the state has met the 

programmatic milestone steps that the state 

indicated it would take during the period from 

the submittal of the final plan through the 

end of 2020, and that the state is on track to 

implement the approved state plan as of 

January 1, 2022.¶
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recognize early actions implemented after 2012 by crediting MWh 

of electricity generation and savings that are achieved by those 

measures during the interim and final plan performance periods. 

 In addition, to encourage early investments in RE and 

demand-side EE, the EPA is establishing the Clean Energy 

Incentive Program (CEIP) as part of the emission guidelines and 

proposed federal plan. Through this program, states will have 

the opportunity to award allowances and ERCs to qualified 

providers that make early investments in RE and demand-side EE 

projects that benefit low-income ratepayers and communities. 

Those states that take advantage of this option will be eligible 

to receive from the EPA matching allowances or ERCs, up to a 

total for all states that represents the equivalent of 300 

million short tons of CO2 emissions. 

 By no later than December 20, 2015, the EPA will issue 

guidance, a notice of data availability or a supplemental 

proposal intended to address implementation of the Clean Energy 

Incentive Program. Prior to doing so, the EPA will engage states 

and stakeholders to gather additional information concerning 

implementation of the program and to solicit information about 

the concerns, interests and priorities of states, utilities, and 

other stakeholders. 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Further discussion of timing and provisions to encourage 

early action is presented in Section VIII.G of this preamble. 

(5) Community and environmental justice considerations. 

Climate change is an environmental justice issue. Lowincome communities and communities of color already overburdened 

by pollution are disproportionately affected by climate change 

and are less resilient than others to adapt to or recover from 

climate-change impacts. While this rule will provide broad 

benefits to communities across the nation by reducing greenhouse 

gas emissions, it will be particularly beneficial to populations 

that are disproportionately vulnerable to the impacts of climate 

change and air pollution. 

Conventional pollutants emitted by power plants, such as 

particulate matter, SO2, HAPs, and NOx, will also be reduced as 

the plants reduce their carbon emissions. These pollutants can 

have significant adverse local and regional health impacts. The 

EPA analyzed the communities in closest proximity to power 

plants and found that they include a higher percentage of 

communities of color and low-income communities than national 

averages. We thus expect an important co-benefit of this rule to 

be a reduction in the adverse health impacts of air pollution on 

these low-income communities and communities of color. As 

mentioned earlier, we refer to these communities generally as 

Deleted: Measures that a state takes prior to 

2022, or programs already in place by 2022, 

that result in CO2 emission reductions during 

the 2022-2029 period will contribute toward 

meeting both the interim and final CO2

emission performance rates. Thus, states with 

currently existing programs and policies, and 

states that put in place new programs and 

policies early, will be better positioned to 

achieve the goals. RE generating capacity and 

demand-side EE measures that are installed 

after 2012 will be eligible for use in 

adjusting a CO2 emission performance rate. ¶

Many commenters expressed concerns that 

regulatory mechanisms that states put in place 

to reduce CO2 emissions could inadvertently 

create unwanted effects that could lead to 

increases in CO2 emissions from EGUs. In the 

final rule, we have put in place safeguards 

against this, including provisions for states 

to provide periodic demonstrations that, at 

the state level, CO2 emission reductions are 

being achieved. ¶

Deleted: with

Deleted: populations because they lack 

resources adequate 

Deleted: T

Deleted: and 

Deleted: particularly 

Deleted: Moving the utility power sector toward 

cleaner generation and more energy efficiency 

is expected to reduce costs to ratepayers 

overall, which will benefit low-income 

ratepayers.

Deleted: Emissions of c

Deleted: , and HAPs,

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Deleted: power

Deleted: 

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Deleted: minority communities, 

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Deleted: and indigenous populations which 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 43 of 1544

“overburdened,” to denote those communities central to 

environmental justice considerations. 

While pollution will be cut from power plants overall, 

there may be some relatively small number of plants whose 

operation and corresponding emissions increase, as energy 

providers balance energy production across their fleets to 

comply with state plans. These plants are likely to be the 

highest-efficiency natural gas-fired units, which have 

correspondingly low carbon emissions and are also characterized 

by low emissions of the conventional pollutants that contribute 

to adverse health effects in nearby communities and regionally. 

The EPA strongly encourages states to evaluate the effects of 

their plans on overburdened communities and to take the steps 

necessary to ensure that all communities benefit from the 

implementation of this rule. In order to identify whether state 

plans are causing any adverse impacts on overburdened 

communities, mindful that substantial reductions may be 

accompanied by potential localized increases, the EPA intends to 

perform an assessment of the implementation of this rule to 

determine whether it and other air quality rules are leading to 

improved air quality in all areas or whether there are localized 

impacts that need to be addressed. 

Deleted: 

Deleted: individual

Deleted: will assess the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Effective engagement between states and affected 

communities is critical to the development of state plans. The 

EPA encourages states to identify communities that may be 

currently experiencing adverse, disproportionate impacts of 

climate change and air pollution, how state plan designs may 

affect them, and how to most effectively reach out to them. This 

final rule requires that states include in their initial plans a 

description of how they engaged with overburdened communities as 

they developed their initial plans, as well as the means by 

which they intend to involve communities and other stakeholders 

as they develop their final plans. The EPA will provide training 

and other resources for states and communities to facilitate 

meaningful engagement. 

In addition to the benefits for overburdened communities 

from reducing climate change impacts and effects of conventional 

pollutant emissions, this rule will also help communities by 

moving the utility industry toward cleaner generation and 

greater energy efficiency. The federal government is committed 

to ensuring that all communities share in these benefits. 

The EPA also encourages states to consider how they may 

incorporate approaches already used by other states to help lowincome communities share in the investments in infrastructure, 

job creation, and other benefits that EE and RE programs 

Deleted: analyze

Deleted: their 

Deleted: to determine who 

Deleted: currently

Deleted: the 

Deleted: y

Deleted: engagement they have undertaken 

Deleted: during development of 

Deleted: seir initial

Deleted: overburdened

Deleted: In this final rule, the EPA is taking 

steps to ensure that this rulemaking does not 

have any potential disproportionate, adverse 

health effects and environmental effects on 

overburdened communities. To provide 

information fundamental to ensuring that this 

rulemaking does not have disproportionate 

adverse impacts on overburdened communities, 

the EPA has conducted a proximity analysis for 

this rulemaking. Additionally, the EPA is 

encouraging states to conduct analyses of 

their own when developing their plans. The EPA 

is requiring states to demonstrate that they 

are actively engaging with a diverse range of 

stakeholders, including overburdened 

communities, as part of their public 

participation process. In their initial plan 

submittal, states will have to provide a 

summary of how they have been engaging with 

community stakeholders and how they intend to 

meaningfully engage with community 

stakeholders during the additional time (if an 

extension is granted) for development of the 

final plan. For the final plan submittal, 

states must provide meaningful opportunities 

for engagement with the public, including 

overburdened communities, during the final 

plan development process, pursuant to the 

public participation requirements of the 

implementing regulations. This engagement 

could include topics such as potential 

localized impacts and how the state will 

assess impacts of their plan on overburdened 

communities, among others. ¶

Deleted: -

Deleted: will also help communities

Deleted: [Placeholder for federal government 

resources and programs for communities and for ... [9]

Deleted: is 

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Deleted: , in developing their plans, to use 

state models that 

Deleted: populations

Deleted: access 

Deleted: benefits of EE, RE, and
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 45 of 1544

provide, have access to financial assistance programs, and 

minimize any adverse impacts that their plans could have on 

communities. 

Community and environmental justice considerations are 

discussed further in section IX of this preamble.

(6) Addressing employment concerns. 

In addition, the EPA encourages states in designing their 

state plans to consider the effects of their plans on employment 

and overall economic development to assure that the 

opportunities for economic growth and jobs that the plans offer 

are manifest. To the extent possible, states should try to 

assure that communities that can be expected to experience job 

losses can also take advantage of the opportunities for job 

growth or otherwise transition to healthy, sustainable economic 

growth. 

(7) Electric system reliability. 

In no small part thanks to the comments we received and our 

extensive consultation with key agencies responsible for 

reliability, including FERC and DOE, among others, along with 

EPA’s longstanding principles in setting emission standards for 

the utility power sector, these guidelines reflect the paramount 

importance of ensuring electric system reliability. The input we 

received on this issue focused heavily on the extent of the 

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Deleted: also consider, and 

Deleted: ,

Deleted: , including impacts on jobsemployment

Deleted: The EPA will also provide information 

resources for affected communities and states 

on existing federal, state, and local and 

other financial assistance programs available 

to communities.

Deleted: S

Deleted: below

Deleted: –

Deleted: s

Deleted: , in no small part thanks to the 

comments we received and our extensive 

consultation with key agencies responsible for 

reliability, including FERC and DOE, among 

others.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 46 of 1544

reductions required at the beginning of the interim period, 

proposed as 2020. We are addressing these concerns in large part 

by moving the first date for mandatory reductions under the 

program from 2020 to 2022 and significantly adjusting the 

interim goals so that they provide a less abrupt initial 

reduction expectation. This, in turn, will provide states and 

utilities with a great deal more latitude in determining their 

emission reduction trajectories over the interim period. As a 

result, there will be more time for planning, consultation and 

decision making in the formulation of state plans and in EGUs’ 

choice of compliance strategies, all within the existing 

extensive structure of energy planning at the state and regional 

levels. These adjustments in the interim goals are supported by 

the information in the record concerning the time needed to 

develop and implement reductions under the BSER. In addition, 

the various forms of flexibility retained and enhanced in this 

final rule, including opportunities for trading within and 

between states, and other multi-state compliance approaches, 

will further support electric system reliability. In addition, 

numerous commenters urged us to include, as part of the plan 

development or approval process, input from review by energy 

regulatory agencies and reliability entities. In the final rule, 

we are requiring that each state demonstrate in its final state 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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plan submittal that it has considered reliability issues in 

developing its plan. 

The final guidelines address electric system reliability in 

several additional ways. We recognize that issues may arise 

during the implementation of the guidelines that may warrant 

adjustments to a state’s plan in order to maintain electric 

system reliability. The final guidelines make clear that states 

have the ability to propose amendments to approved plans in the 

event that unanticipated and significant reliability challenges 

arise. And, as a final element of reliability assurance, the 

rule also provides for a reliability safety valve for individual 

sources where there is a conflict between the requirements the 

state plan imposes on a specific affected EGU and the 

maintenance of electric system reliability in the face of an 

extraordinary, unanticipated, potentially catastrophic event. 

We anticipate that these situations will be extremely rare 

because the states have the flexibility to craft requirements 

for their EGUs that will provide long averaging periods and/or 

compliance mechanisms, such as trading, whose inherent 

flexibility will make it unlikely that an individual unit will 

find itself in this kind of situation. As one example, under 

compliance regimes that allow individual EGUs to establish 

compliance through the acquisition and holding of allowances or 

Deleted: , which it can do, for example, by 

consulting with relevant ISOs/RTOs or other 

planning authorities

Deleted: 

Deleted: 

Deleted: due to 

Deleted: that are 

Deleted: to put

Deleted: Specifically,

Deleted: which
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ERCs equal to their emissions, an EGU’s need to continue to 

operate – and emit – for the purposes of ensuring system 

reliability will not put the EGU into non-compliance, provided, 

of course, it obtains the needed allowances or credits in a 

timely fashion. We, nevertheless, agree with many commenters 

that it is prudent to provide an electric system reliability 

safety valve as a precaution. In addition, the EPA, DOE and FERC 

have agreed to coordinate their efforts, at the federal level,

to help ensure continued reliable electricity generation and 

transmission during the implementation of the final rule. The 

three agencies have set out a memorandum that reflects their 

joint understanding of how they will work together to monitor 

implementation, share information, and to resolve any 

difficulties that may be encountered. 

As a result of the many features of this final rule that 

provide states and affected EGUs with meaningful time and 

decision making latitude, we believe that the comprehensive 

safeguards already in place in the U.S. to ensure electric 

system reliability will continue to operate effectively as 

affected EGUs reduce their CO2 emissions under this program. 

(8) Outreach and resources for stakeholders. 

 To provide states, U.S. territories, tribes, utilities, 

communities, and other interested stakeholders with 
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Page 49 of 1544

understanding about the rule requirements, and to provide 

efficiencies where possible and reduce the cost and 

administrative burden, the EPA will continue to work with 

states, tribes, territories, and stakeholders to provide 

information and address questions about the final rule. Outreach 

will include opportunities for states and tribes to participate 

in briefings, teleconferences, and meetings about the final 

rule. The EPA’s ten regional offices will continue to be the 

entry point for states, tribes and territories to ask technical 

and policy questions. The agency will host (or partner with 

appropriate groups to co-host) a number of webinars about 

various components of the final rule; these webinars are planned 

for the first two months after the final rule is issued. The EPA 

will also offer consultations with tribal governments. The EPA 

will continue outreach throughout the plan development and 

submittal process. The EPA will use information from this 

outreach process to inform the training and other tools that 

will be of most use to the state, tribes, and territories that 

are implementing the final rule. 

The EPA has worked with communities, states, tribes and 

relevant associations to develop an extensive training plan that 

will continue in the months after the Clean Power Plan is 

finalized. The EPA has assembled resources from a variety of 

Deleted: officials
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sources to create a comprehensive training curriculum for those 

implementing this rule. Recorded presentations from the EPA, DOE 

and other federal entities will be available for communities, 

states, and others involved in composing and participating in 

the development of state plans. This curriculum is available 

online at EPA’s Air Pollution Training Institute. 

The EPA also expects to issue guidance on specific topics. 

As guidance documents, tools, templates and other resources 

become available, the EPA, in consultation with DOE and other 

federal agencies, will continue to make these resources 

available via a dedicated website.15 

We intend to continue to work actively with states and 

tribes, as appropriate, to provide information and technical 

support that will be helpful to them in developing and 

implementing their plans. 

Additional detail on aspects of the final rule is 

included in several technical support documents (TSDs) and 

memoranda that are available in the rulemaking docket. 

4. Key changes from proposal 

a. Overview and highlights. The June 2014 proposal for the rule 

was designed to meet the fundamental goal of reducing harmful 

emissions of CO2 from fossil fuel-fired EGUs in a manner 

 

15 www.epa.gov/cleanpowerplantoolbox. 

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consistent with the CAA requirements, while accommodating two 

important objectives. The first objective was to establish 

guidelines that reflect both the manner in which the power 

system operates and the actions and measures already underway 

across states and the utility power sector that are resulting in 

CO2 emission reductions. The second objective was to provide 

states and utilities maximum flexibility, control and choice in 

meeting their compliance obligations. In this final rule, the 

EPA has focused on changes that, in addition to being responsive 

to the critical concerns and priorities of stakeholders, more 

fully accomplish these two crucial objectives. 

To achieve these objectives, the June 2014 proposal 

featured several important elements: the building block approach 

for the BSER; state-specific, rather than source-specific goals; 

a 10-year interim goal that could be met “on average” over the 

10-year period between 2020 and 2029; and a “portfolio” option 

for state plans. These features were intended either to capture, 

in the emission guidelines, emission reduction measures already 

in widespread use or to maximize the range of choices that 

states and utilities could select in order to achieve their 

emission limitations at low cost while ensuring electric system 

reliability. In this final rule, we are retaining the key design 

elements of the proposal and making certain adjustments to 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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respond to a variety of very constructive comments on ways that 

will implement the CAA section 111(d) requirements efficiently 

and effectively. 

The building block approach is a key feature of the 

proposal that we are retaining in the final rule, but have 

refined to include only the first three building blocks and to 

reflect implementation of the measures encompassed in the 

building blocks on a broad regional grid-level. In the proposal, 

we expressed the emission limitation requirements reflecting the 

BSER in terms of the state goals in order to provide states with 

maximum flexibility and latitude. We viewed this as an important 

feature because each state has its own energy profile and statespecific policies and needs relative to the production and use 

of electricity. In the final rule, we extend that flexibility 

significantly in direct response to comments from states and 

utilities. The final rule establishes source-level emission 

performance rates for the source subcategories, while retaining 

state-level rate- and mass-based goals. One of the key messages 

conveyed by state and utility commenters was that the final rule 

should make it easier for states to adopt mass-based programs 

and for utilities accustomed to operating across broad multistate grids to be able to avail themselves of more “ready-made” 

emissions trading regimes. The inclusion of both of these new 

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was intended to capture both the unique 

interconnected nature of the utility power 

sector and the set of actions, strategies and 

programs that are already under way at the 

state and utility level that have been 

resulting in CO2 emission reductions.

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 53 of 1544

features – mass-based state goals in addition to rate-based 

goals, and source-level emission performance rates for the two 

subcategories of sources – is intended to make it easier for 

states and utilities to achieve these outcomes. 

Many stakeholders conveyed to the EPA that the proposal’s 

interim goals for the 2020-2029 period were designed in a way 

that defeated the EPA’s objective of allowing states and 

utilities to shape their emission reduction trajectories. They 

pointed out that, in many cases, the timing and stringency of 

the states’ interim goals could require actions that could 

result in high costs, threaten electric system reliability or 

hinder the deployment of renewable technology. In response, the 

EPA has revised the interim goals in two critical ways. First, 

mandatory reductions begin in 2022 rather than 2020; second, in 

keeping with the BSER, emission reduction requirements are 

phased in more gradually over the interim period. These changes 

will allow states and utilities to delineate their own emission 

reduction trajectories so as to minimize costs and foster 

broader deployment of renewable energy technologies. The value 

of these changes is demonstrated by our analysis of the final 

rule, which shows lower program costs, especially in the early 

years of the interim period, and greater renewable energy 

deployment, relative to the analysis of the proposed rule. At 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 54 of 1544

the same time, this re-design of the interim goals, together 

with refinements we have made to state plan requirements and the 

inclusion of a reliability safety valve, provide states, 

utilities and other entities with the ability to continue to 

guarantee system reliability. 

b. Outreach, engagement and comment record. This final rule is 

the product of one of the most extensive and long-running public 

engagement processes the EPA has ever conducted, starting in the 

summer of 2013, prior to proposal, and continuing through 

December 2014, when the public comment period ended, and 

continuing beyond that with consultations and meetings with 

stakeholders. The result of this extensive consultation was

millions of comments from stakeholders, which we have carefully 

considered over the past several months. The EPA gained crucial 

insights from the more than 4 million comments that the agency 

received on the proposal and on notices leading to this final 

rulemaking. Comments were provided by stakeholders that include 

state environmental and energy officials, tribal officials, 

public utility commissioners, system operators, owners and 

operators of every type of power generating facility, other 

industry representatives, labor leaders, public health leaders, 

public interest advocates, community and faith leaders, and 

members of the public. 

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broad request for comment on all elements of 

the proposal, the EPA received many thoughtful 

comments. The final guidelines continue to 

embrace the basic approach of the proposal, 

but they also incorporate significant changes 

that respond directly to the comments, 

requests and concerns of states and other 

stakeholders, while better serving the 

critical objectives of the basic approach of 

the proposal.

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 55 of 1544

The insights gained from public comments contributed to the 

development of final emission guidelines that build on the 

proposal and the alternatives on which we sought comment. The 

modifications incorporated in the final guidelines are directly 

responsive to the comments we received from the many and diverse 

stakeholders. The improved guidelines reflect information and 

ideas that states and utilities provided to us about both the 

best approach to establishing CO2 emission reduction requirements 

for EGUs and the most effective ways to create true flexibility 

for states and utilities in meeting these requirements. These 

final rules also reflect the results of EPA’s robust 

consultation with federal, state and regional energy agencies 

and authorities, to ensure that the actions sources will take to 

reduce GHG emissions will not compromise electric system 

reliability or affordability of the U.S. electricity supply. 

Input and assistance from FERC and DOE have been particularly 

important in shaping these final guidelines. At the same time, 

input from community-based and environmental justice 

organizations, who provided thoughtful comments about the 

potential impacts of this rule on pollution levels in 

overburdened communities and economic impacts, including utility 

rates in low-income communities, is also reflected in this rule. 

The final rule also reflects our response to concerns raised by 

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of the information and input the EPA gleaned 

from its extensive outreach process and from 

the comment record. 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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labor leaders regarding the potential effects on workers and 

communities of the transition away from higher-emitting power 

generation to lower- and zero-emitting power generation.

c. Additional information. The most significant changes in 

these final guidelines are: 1) mandatory emission reductions 

beginning in 2022 instead of 2020 and a gradual application of 

the BSER over the 2022-2029 interim period, such that a state 

has substantial latitude in selecting its own emission reduction 

trajectory or “glide path” over that period, 2) a revised BSER 

determination that focuses on narrower generation options that 

do not include demand-side energy efficiency measures and that 

includes refinements to the building blocks, more complete 

incorporation in the BSER of the realities of electricity 

operations over the three regional Interconnections, and up-todate information about the cost and availability of clean 

generation options, 3) the formulation of source-specific CO2

emission performance rates that are uniform across the two 

fossil fuel-fired subcategories covered in these guidelines, as 

well as rate- and mass-based state goals, to facilitate emission 

trading, including interstate trading and, in particular, massbased trading, 4) a variation on the proposal’s “portfolio” 

option for state plans – called here the “state measures” 

approach - that continues to provide states flexibility while 

Deleted: At proposal, the EPA made it clear 

that our intent was two-fold – first, to 

establish CO2 emission reduction requirements 

that relied both on the distinctive nature of 

the electricity system in which affected EGUs 

operate and on the actions, strategies and 

policies states and utilities have already 

been undertaking, and, second, to provide 

states and utilities with broad flexibility 

and choice in meeting those requirements in 

order to minimize costs to ratepayers and to 

ensure the reliability of electricity supply. 

Thus, in our thorough examination of the 

comment record and of information received 

during the engagement process, we paid 

particular attention to information and 

suggestions that addressed ways to ensure that 

this final rule succeeds in fulfilling the 

dual objectives of the proposal. ¶

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traditionaldetermination, a focus on a 

narrower generation options only and not 

fromthat do not include demand-side energy 

efficiencies, 4

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BSER reflecting of the realities of 

electricity operations over the three regional 

Interconnections, as well as up-to-date 

information about the cost and availability of 

clean generation options, 56)

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are uniform across the two fossil fuel-fired 

subcategories covered in these guidelines, 67)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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ensuring that all state plans have federally enforceable 

measures as a backstop, 5) additional, more flexible options for 

states and utilities to adopt multi-state compliance strategies, 

6) an extension of up to two years available to all states for 

submittal of their final compliance plans following submittal of 

an initial plan in 2016, 7) provisions to encourage actions that 

achieve early reductions, including a Clean Energy Incentive 

Program, 8) a combination of provisions expressly designed to 

ensure electric system reliability, 9) the addition of 

employment considerations for states in plan development, and 

10) the expansion of considerations and programs for 

overburdened communities. 

We provide summary explanations in the following paragraphs 

and more detailed explanations of all of these changes in later 

sections of this preamble and associated documents. 

(1) Mandatory Reductions Beginning in 2022 and a Gradual 

Glide Path. 

The proposal’s mandatory emission reductions beginning in 

2020 and the trajectory of emission reduction requirements in 

the interim period were both the subjects of significant 

comment. Earlier this year, FERC conducted a series of technical 

conferences comprising one national session and three regional 

sessions. The information provided by workshop participants 

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of compelling information and analysis 

provided to the EPA via the comment record – 

and by the work of, and consultation with, 

other federal agencies, notably FERC and DOE. 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 58 of 1544

echoed much of the material that had been submitted to the 

comment record for this rulemaking. On May 15, 2015, the FERC 

Commissioners, drawing upon information highlighted at the 

technical conferences, transmitted to the EPA some suggestions 

for the final rule. In addition, via comments, states, 

utilities, and reliability entities asked us to ensure adequate 

time for them to implement strategies to achieve CO2 reductions. 

They expressed concern that, in the proposal, at least some 

states would be required to reduce emissions in 2020 to levels 

that would require abrupt shifts in generation in ways that 

raised concerns about impacts to electric system reliability and

ratepayer bills, as well as about stranded assets. To many 

commenters, the proposal’s requirement for CO2 emission 

reductions beginning in 2020, together with the stringency of 

the interim CO2 goal, posed significant reliability implications, 

in particular. In this final rule, the agency is addressing 

these concerns, in part, by adjusting the compliance timeframe 

from a 10-year interim period that begins in 2020 to an 8-year 

interim period that begins in 2022, and by refining the approach 

for meeting interim CO2 emission performance rates to be a glide 

path separated into three steps, 2022-2024, 2025-2027, and 2028-

2029, that is also achievable “on average” over the 8-year 

interim period. In response to the concerns of commenters that 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the proposal’s 10-year interim target failed to afford 

sufficient flexibility, the final guidelines’ approach will 

provide states with realistic options for customizing their 

emission reduction trajectories. Of equal importance, the 

approach provides more time for planning, consultation and 

decision making in the formulation of state plans and in EGUs’ 

choices of compliance strategies. Both FERC’s May 15, 2015 

letter and the comment record, as well as other information 

sources, made it clear that providing sufficient time for 

planning and implementation was essential to ensuring electric 

system reliability. 

The final guidelines’ approach to the interim emission 

performance rates is the result of the application of the 

measures constituting the BSER in a more gradual way, reflecting 

stakeholder comments and information about the appropriate 

period of time over which those measures can be deployed 

consistent with the BSER factors of cost and feasibility. In 

addition to facilitating reliable system operations, these 

changes provide states and utilities with the latitude to 

consider a broader range of options to achieve the required 

reductions while addressing concerns about ratepayer impacts and 

stranded assets. 

(2) Revised BSER determination.

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 Commenters urged the EPA to confine its BSER determination 

to actions that involve what they characterized as more

“traditional” generation. While some stakeholders recognized 

demand-side EE as being an integral part of the electricity 

system, with many of the characteristics of more traditional 

generating resources, other stakeholders did not. Though demandside EE shares many of the most salient characteristics of what 

some regard as more traditional generation, and is treated as 

functionally interchangeable with other forms of generation for 

planning and operational purposes, the broad range of comments 

on this topic illustrates how much the role of demand-side 

resources is changing and how the opportunities for generating 

companies to use demand-side resources varies more than the 

other building blocks. For example, a broad range of types of 

generation owners including vertically integrated utilities, 

municipalities, cooperatives and independent power producers own 

or contract for renewable energy, but only a handful of 

independent power producers are currently providing demand-side 

resources like demand-side EE. In view of this, since the BSER 

must serve as the foundation of the emission guidelines, the EPA 

has not included demand-side EE as part of the final BSER 

determination. Thus, neither the final guidelines’ BSER 

determination nor the emission performance rates for the two 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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subcategories of affected EGUs take into account demand-side EE. 

However, many commenters also urged the EPA to allow states and 

sources to rely on demand-side EE as an element of their 

compliance strategies, as energy efficiency measures are in 

widespread use across the country and provide energy savings 

that reduce emissions, lower electric bills, and lead to 

positive investments and job creation. We agree, and the final 

guidelines provide ample latitude for states and utilities to 

rely on demand-side EE in meeting emission reduction 

requirements. 

In response to stakeholder comments on the first three 

building blocks and considerable data in the record, the EPA has 

made refinements to the building blocks, and these are reflected 

in the final BSER. Refinements include adoption of a modified 

approach to quantification of the renewable energy component, 

exclusion of the proposed nuclear generation components, and 

adoption of a consistent regionalized approach to quantification 

of all three building blocks. The agency also recognizes the 

important functional relationship between the period of time 

over which measures are deployed and the stringency of emission 

limitations those measures can achieve in a practical and 

reasonable cost way. Therefore, the final BSER also reflects 

adjustments to the stringency of the building blocks, after 
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consideration of more and less stringent levels, and refinements 

to the timeframe over which reductions must be achieved. 

Sections V.C through V.E of this preamble provide further 

information on the refinements made to the building blocks and 

the rationale for doing so. 

Commenters pointed out – and practical experience confirms 

– what is widely known: that the utility power sector operates 

over regional interconnections that are not constrained by state 

borders. Across a variety of issues raised in the proposal, many 

commenters urged that the EPA take that reality into account in 

developing this final rule. Consequently, the BSER 

determination itself (as well as a number of new compliance 

features included in this final rule) and the resulting 

subcategory-specific emission performance rates take into 

account the grid-level operations of the source category. 

The final guidelines’ BSER determination also takes into 

account recent reductions in the cost of clean energy 

technology, as well as projections of continuing cost 

reductions, and continuing increases in RE deployment. We also 

updated the underlying analysis with the most recent Energy 

Information Administration (EIA) projections that show lower 

growth in electricity demand between 2020 and 2030 than 

previously projected. In keeping with these recent EIA 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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projections, we expect the final guidelines will be more 

conducive to compliance, consistent with a strategy that allows 

for the cleanest power generation and greater CO2 reductions in 

2030 than the proposal. With a date of 2022, instead of 2020, as 

proposed, for mandatory CO2 emission reductions to begin, the 

final guidelines reflect that the additional time aligns with 

the adoption of lower-cost clean technology and, thus, its 

incorporation in the BSER at higher levels. At the same time, 

the 2022-2029 interim period will more easily allow for 

companies to take advantage of improved clean energy 

technologies as potential least cost options. 

(3) Uniform Emission Performance Rates. 

Some stakeholders commented that the proposal’s approach of 

expressing the BSER in terms of state-specific goals deviated 

from the requirements of CAA section 111 and from previous new 

source performance standards (NSPS). The effect, they stated, 

was that the proposal created de facto emission standards for 

all affected EGUs but that these de facto standards varied 

widely depending on the state in which a given EGU happened to 

be located. Instead, these and other commenters stated, section 

111 requires that EPA establish the BSER specifically for 

affected sources, rather than by means of merely setting statespecific goals, and that these standards be uniform. Still other 

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comments on a range of topics related to the 

best system of emission reduction (BSER), the 

agency has revised its determination of the 

BSER. In this final action, the agency has 

determined that the BSER comprises the first 

three of the four proposed building blocks 

identified at proposal, with certain 

refinements to the three building blocks.¶

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commenters observed that the effect of the approach taken in the 

proposal of applying the BSER to each state’s fleet was to put a 

greater burden of reductions on lower-emitting or less carbonintensive states and a lesser emission reduction burden on 

sources and states that were higher-emitting or more carbonintensive. This, they argued, was both inequitable and at odds 

with the way in which NSPS have been applied in the past, where 

the higher-emitting sources have made the greater and more costeffective reductions, while lower-emitting sources, whose 

reduction opportunities tend to be less cost-effective, have 

been required to make fewer reductions to meet the applicable 

standard. 

At the same time, state and utility commenters expressed 

concern that relying on state-specific goals and state-by-state 

planning could introduce complexity into the otherwise seamless 

integrated operation of affected EGUs across the multi-state 

grids on which system operators, states and utilities currently 

rely and intend to continue to rely. Accordingly, they 

recommended that the final guidelines facilitate emissions 

trading, in particular interstate trading, which would enable 

EGU operators to integrate compliance with CO2 emissions 

limitations with facility and grid-level operations. These sets 

of comments intersected at the point at which they focused on 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the fact that it is at the source level at which the standard is 

set for NSPS and at the source level at which compliance must be 

achieved. 

The EPA carefully considered these comments and while we 

believe that the approach we took at proposal was well-founded 

and reflected a number of important considerations, we have 

concluded that there is a way to address these concerns while 

expanding upon the advantages offered by the proposal. 

Accordingly, the final guidelines formulate uniform rates for 

the two subcategories of sources – an approach that is valuable 

for creating greater equity between and among utilities and 

states with widely varying emission levels and for expanding the 

flexibility of the program, especially in ways that have been 

identified as important to utilities and states. Specifically, 

the final guidelines express the BSER by means of performancebased CO2 emission rates that are uniform across each of two 

subcategories – fossil fuel-fired electric steam generating 

units and stationary combustion turbines – for the affected EGUs 

covered by the guidelines. The rates are determined, in part, by 

applying the methodology identified in the Notice of Data 

Availability published on October 30, 2014, which was based on 

the proposal’s building block approach. The final guidelines 

also maintain the approach adopted in the proposal of 

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establishing state-level goals; in the final rule, those goals 

are equal to the weighted aggregate of the two emission 

performance rates as applied to the EGUs in each state in the 

base year 2012. 

This approach rectifies what would have been an 

inefficient, unintended outcome of putting the greater reduction 

burden on lower-emitting sources and states while exempting 

higher-emitting sources and states. Expressing the BSER by means 

of these rates also augments the range of options for both 

states and EGUs for securing needed flexibility. In addition, 

the latitude for state plans and EGU compliance created by the 

inclusion of state goals as the means of expressing state 

obligations, states also may comply with these guidelines by 

adopting these emission performance rates as emission standards

that apply to the affected EGUs in their jurisdiction. Such an 

approach would lend itself to the ready establishment of intrastate and interstate trading, with the uniform rate-based 

standards of performance established for each EGU as the basis 

for such trading. At the same time, as at proposal, each state 

also has the option of complying with these guidelines by 

adopting a plan that takes a different approach to setting 

standards of performance for its EGUs and/or by applying 

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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complementary or alternative measures to meet the state goal set 

by these guidelines – as either a rate or a mass total. 

During the outreach process and through comments, a number 

of state officials and other stakeholders expressed concern that 

the EPA’s approach at proposal necessitated or represented a 

significant intrusion into state-level energy policy-making, 

drawing the EPA well beyond the bounds of its CAA authority and 

expertise. In fact, these final guidelines are entirely 

respectful of the EPA’s responsibility and authority to regulate 

sources of air pollution. Instead, by establishing and operating 

through uniform performance rates for the two subcategories of 

sources that can be applied by states at the individual source 

level and that can readily be implemented through emission 

standards that incorporate emissions trading, these final 

guidelines align with the approach Congress and the EPA have 

consistently taken to regulating emissions from this and other 

industrial sectors, namely setting source-level, source 

category-wide standards that individual sources can meet through 

a variety of technologies and measures. 

We emphasize, at the same time, that while the final 

guidelines express the BSER by means of source-level CO2 emission 

performance rates, as well as state-level goals, as at proposal, 

each state will have a goal reflecting its particular mix of 

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equivalent emission reductions as determined 

by 

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sources, and the final guidelines retain the flexibility 

inherent in the proposal’s state-specific goals approach (and, 

as discussed in section VIII of this preamble, enhanced in 

various ways). Thus, in keeping with the proposal’s flexibility, 

states may choose to adopt either the emission performance rates 

as emission standards for their sources, set different but, in 

the aggregate, equivalent rates, or fulfill their obligations by 

meeting their respective individual state goals. 

(4) State Plan Approaches. 

Commenters expressed support for the objectives served by 

the “portfolio” option in the state plan approaches included at 

proposal, but many raised concerns about its legality, with 

respect, in particular, to the Clean Air Act’s enforceability 

requirements. Some of these commenters identified a “state 

commitment approach” with backstop measures as a variation of 

the “portfolio” approach that would retain the benefits of the 

“portfolio” approach while resolving legal and enforceability 

concerns. In this final rule, in response to stakeholder 

comments on the portfolio approach and alternative approaches, 

the EPA is finalizing two approaches, a source-based “emission 

standards” approach, and a “state measures” approach. Through 

the latter, states may adopt a portfolio of policies and 

programs, which would not need to be federally enforceable, but 

Deleted: S

Deleted: for states

Deleted: for those 

Deleted: that 

Deleted: not 

Deleted: individually tailored state

Deleted: The final guidelines continue to 

define state planning and implementation 

obligations through state goals. For the final 

guidelines, we have calculated state goals by 

translating the subcategory-specific CO2

emission performance rates into equivalent 

statewide rate-based and mass-based CO2 goals. 

Deleted: Measures

Deleted: or the state plan approaches included 

at proposal, c

Deleted: b

Deleted: also

Deleted: – again, also expressed in the form 

of state goal in addition to source-specific 

performance rates
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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they would be required to include federally enforceable backstop 

measures applicable to each affected EGU in the event that the 

measures included in the state plan failed to achieve the state 

plan’s emissions reduction trajectory. Under these guidelines, 

then, states implement the BSER through standards of performance 

incorporating the uniform performance rates or alternative but 

in the aggregate equivalent rates, or they can adopt plans that 

achieve in aggregate the equivalent of the subcategory-specific 

CO2 emission performance rates by relying on a combination with 

other measures undertaken by the state that complement sourcespecific requirements or, save for the contingent backstop 

requirement, supplant them entirely. This revision provides 

consistency in the treatment of sources while still providing 

maximum flexibility for states to design their plans around 

reduction approaches that best suit their policy objectives. 

(5) Emission Trading Programs. 

Many state and utility commenters supported the use of 

mass-based and rate-based emission trading programs in state 

plans, including interstate emission trading programs, and 

either pointed out obstacles to establishing such programs or 

suggested approaches that would enhance states’ and utilities’ 

ability to create and participate in such programs.

Deleted: To comply with

Deleted: set 

Deleted: ensure that implementation of the 

emission standards established for their 

affected EGUs, either individually, in 

aggregate, or

Deleted: in 

Commented [A10]: This is one heck of a sentence. Can it be 

broken up, or use of semicolons, i. ii, iii, etc.? 

Deleted: , achieve the equivalent of the 

subcategory-specific CO2 emission performance 

rates

Deleted: tailoring required CO2 reductions to 

individual states and will either have to
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 70 of 1544

Through a combination of features retained from the 

proposal and changes made to the proposal, these final 

guidelines provide states and utilities with a panoply of tools 

that greatly facilitate their putting in place and participating 

in emissions trading programs. These include: 1) expressing BSER 

in uniform emission performance rates that states may rely on in 

setting emission standards for affected EGUs such that EGUs 

operating under such standards readily qualify to trade with 

affected EGUs in states that adopt the same approach, 2) 

promulgating state mass goals so that states can move quickly to 

establish mass-based programs such that their affected EGUs 

readily qualify to trade with affected EGUs in states that adopt 

the same approach, and 3) providing the EPA resources and 

capacity to create a tracking system to support state emissions 

trading programs.

(6) Extension of Plan Submittal Date. 

Stakeholders, particularly states, provided compelling 

information establishing that it could take longer than the 

agency initially anticipated for the states to develop and 

submit their required plans. While the approach at proposal 

reflected the EPA’s conclusion that it was essential to the 

environmental and economic purposes of this rulemaking that 

utilities and states establish the path towards emissions 

Deleted: 

Deleted: of performance t

Deleted: are all but automatically

Deleted: ied

Deleted: ing

Deleted: or its mass-based equivalent

Deleted: that represent the equivalent of each 

state’s rate-based goal 

Deleted: are all but automatically qualified

Deleted: o 

Deleted: 

Deleted: ¶

The EPA also received a number of comments 

from states and stakeholders about the value 

of EPA support in developing and/or 

administering tracking systems to support 

state administration of rate-based and massbased emission trading programs. In this final

rule, as we proposed, states may use trading 

or other multi-unit compliance approaches and 

technologies or strategies that are not 

explicitly mentioned in any of the three 

building blocks as part of their overall 

plans, as long as they achieve the required 

emission reductions from affected fossil fuelfired EGUs. In addition, in response to 

concerns from states and power companies that 

the need for up-front interstate cooperation 

in developing multi-state plans could inhibit 

the development of interstate programs that 

could lower cost, the final rule provides 

additional options to allow individual EGUs to 

use creditable out-of-state reductions to 

achieve required CO2 reductions, without the 

need for up-front interstate agreements. The 

EPA is committed to working with states to 

provide support for tracking of emissions and 

allowances or credits, to help implement 

multi-state trading or other multi-unit 

compliance approaches. ¶

Deleted: will 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 71 of 1544

reductions as early as possible, we recognize commenters’ 

concerns. To strike the proper balance, the EPA has developed a 

revised state plan submittal schedule. The EPA is requiring 

states to submit an initial plan 13 months after signature (by 

September 6, 2016), to assure that states begin to address the 

urgent needs for reductions quickly, and is providing until 

September 6, 2018, for states to submit a final plan, if an 

extension until that date is justified, to address the concern 

that a submitting state needs more time to develop comprehensive 

plans that reflect the full range of the state’s and its 

stakeholders’ interests.

(7) Provisions to Encourage Early Action. 

 Many commenters supported providing incentives for states 

and utilities to deploy CO2-reducing investments, such as RE and 

demand-side EE measures, as early as possible. The EPA 

recognizes the value of such early actions, and in this final 

rule is establishing a state-federal Clean Energy Incentive 

Program to reward investment in certain RE and demand-side EE 

projects that commence construction after the effective date of 

this rule and that generate MWh or reduce end-use energy demand 

during 2020 and 2021. Specifically, states may draw allowances 

or ERCs from their interim goals and allocate to eligible 

projects allowances or ERCs equivalent to each MWh generated or 

Deleted: fully 

Deleted: August 31

Deleted: August 31

Deleted: 

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Deleted: investment

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Deleted: target
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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avoided. For each allowance or ERC allocated to such projects, 

the EPA will provide the state with an allowance or ERC that the 

state may allocate to additional projects or may use to 

supplement its allocation to those projects on whose basis the 

EPA provides the matching allocation. Those states that take 

advantage of this option will be eligible to receive from the 

EPA a limited number of matching allowances or ERCs, up to a 

total limit for all states that represents the equivalent of 300 

Mt of CO2 emissions. 

 For a state to be eligible for an award of allowances or 

ERCs from the EPA, it must demonstrate that the allowances or 

ERCs will be awarded to projects that either generate metered 

MWh from wind or solar resources or result in quantified and 

verified avoided generation through demand-side EE. 

In addition, in order to drive investments in 

RE and demand-side EE that directly benefit low-income 

ratepayers and communities, the EPA will offer an additional 

incentive to states that encourage these types of investments. 

Upon demonstration by a state that a project benefitting a lowincome community has generated quantified and verified MWh 

achieved in 2020 or 2021, the state will not be required to 

award to that project ERCs or allowances from its own interim 

target. Rather, the EPA will provide the entirety of the award, 

Deleted: The number of matching allowances or 

ERCs that EPA will make available to states in 

total will not exceed the amount that 

represents the equivalent of 300 Mt of CO2

emissions. 

Deleted: :

Deleted: ¶

G

Deleted: m

Deleted: ;

Deleted: ¶

R

Deleted: ; andirectly benefit overburdened 

ratepayers or communities.16

Deleted: n
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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equal to double the number of ERCs or allowances it would have 

awarded to an eligible project not focused on low-income 

ratepayers. 

 The EPA will address design and implementation details of 

the Clean Energy Incentive Program in a future action.Prior to 

doing so, the EPA will engage states and stakeholders to gather 

additional information concerning implementation of this program 

and to solicit information about the concerns, interests and 

priorities of states, utilities, and other stakeholders. 

(8) Provisions for Electric System Reliability. 

A number of commenters stressed the importance of final 

guidelines that addressed the need to ensure that EGUs could 

meet their emission reduction requirements without being 

compelled to take actions that would undermine electric system 

reliability. As noted above, the EPA has consulted extensively 

with federal, regional and state energy agencies, utilities and 

many others about reliability concerns and ways to address them. 

The final guidelines support electric system reliability in a 

number of ways, some inherent in the improvements made in the 

program’s design and some through specific provisions we have 

included in the final rule. Most important are the two key

changes we made to the interim goal: establishing 2022, instead 

of 2020, as the date that mandatory emission reductions begin

Deleted: r

Deleted: ¶

By no later than December 20, 2015, EPA will 

issue guidance, a notice of data availability 

or a supplemental proposal intended to address 

implementation of the clean energy investment 

program. Before

Deleted: topics

Deleted: and the public

Commented [A11]: Can EPA provide any guidance to the 

interangecy group on how this incentive program will be 

incentivizing additive actions, beyond the large level of RE that is 

planned anyway? Is this where the 300M tons came from -- to get 

more than what is already planned? 

Deleted: 7

Deleted: the 

Deleted: ing

Deleted: s

Deleted: program would not 

Deleted: eing

Deleted: requirements 

Deleted: , perhaps,

Deleted: of the 

Deleted: periodtarget

Deleted: 

Deleted: from 2020 to

Deleted: of the 

Deleted: s

Deleted: mandate
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 74 of 1544

and phasing in, over the eight-year period, emission performance 

rates such that the level of stringency of the emission 

performance rates in 2022-2024 is significantly less than that 

for the years 2028 and 2029. Since states and utilities need 

only to meet their interim goal “on average” over the 8-year 

period, these changes provide them with a great deal of latitude 

in determining for themselves their emission reduction 

trajectory – and they have additional time to do so. As a 

result, the final guidelines provide the ingredients that 

commenters, reliability entities and expert agencies told the 

EPA were essential to ensuring electric system reliability: time 

and flexibility sufficient to allow for planning, implementation 

and the integration of actions needed to address reliability 

while achieving the required emissions reductions. 

In addition, the final guidelines add a requirement, based 

on substantial input from experts in the energy field, for 

states to demonstrate that they have considered electric system 

reliability in developing their state plans. The final rule also

offers additional opportunities that support electric system 

reliability, including opportunities for trading within and 

between states. The final guidelines also make clear that states 

can adjust their plans in the event that reliability challenges 

arise that need to be remedied by amending the state plan. In 

Deleted: the adjustments to the interim period 

glide path

Deleted: the 

Deleted: uniform

Deleted: Since s

Deleted: , as at proposal, 

Deleted: s

Deleted: . 

Deleted: require 

Deleted: to 

Deleted: and have consulted with state utility 

agencies and/or regional planning authorities

Deleted: also retains flexibilities presented 

in the proposal and

Deleted: including 

Deleted: , and other multi-state compliance 

approaches that will further support electric 

system reliability

Deleted: 

Deleted: se

Deleted: further provide

Deleted: with the option of proposing 

amendments to approved
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 75 of 1544

addition, the final rule includes a reliability safety valve to 

address situations where, because of an unanticipated 

catastrophic event, there is a conflict between the requirements 

imposed on an affected unit and the maintenance of reliability. 

(9) Approaches for Addressing Employment Concerns. 

Some commenters brought to our attention the concerns of 

workers, their families and communities that the shift toward 

lower-carbon electricity generation that the final rule 

encourages will cause harm to communities that are dependent on 

coal. Others had concerns about whether new jobs created as a 

result of actions taken pursuant to the final rule will allow 

for overall economic development. In the final rule, the EPA 

encourages states, in designing their state plans, to consider 

the effects of their plans on employment and overall economic 

development to assure that the opportunities for economic growth 

and jobs that the plans offer are manifest. We also identify 

federal programs, including the Partnership for Opportunity and 

Workforce and Economic Revitalization (POWER) Initiative17 and a 

joint initiative of the Department of Commerce, Department of 

Labor (DOL), Small Business Administration, and the Appalachian 

 

17 http://www.eda.gov/power/.

Deleted: T

Deleted: also 

Deleted: (8)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Regional Commission,18 whose mission is to assist communities 

affected by changes in the coal industry and the utility power 

sector. 

(10) Community and Environmental Justice Considerations. 

Many community leaders, environmental justice advocates, 

faith-based organizations and others commented that the benefits 

of this rule must be shared broadly across society and that 

undue burdens should not be imposed on low-income ratepayers. We

agree. The federal government is taking significant steps to 

help low-income families and individuals gain access to RE and 

demand-side EE through new initiatives involving, for example, 

increasing solar energy systems in federally subsidized homes 

and supporting solar systems for others with low incomes. The 

final rule ensures that bill-lowering measures such as demandside EE continue to be a major compliance option. In addition to 

carbon reduction benefits, we expect significant near- and longterm public health benefits in communities as conventional air 

pollutants are reduced along with GHGs. However, some 

stakeholders expressed concerns about the possibility of 

localized increases in emissions from some power plants as the 

utility industry complies with state plans, in particular in 

 

18 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 

Deleted: Stakeholders requested that the 

program not impose undue burdens on 

Deleted: share this concern

Deleted: , and t

Deleted: ensuringe opportunities for low-income 

communities, and communities of color, and 

indigenous populationsminor, particularly 

citizens those experiencing disproportionate 

impacts of climate change and air pollution, 

who could be impacted by decisions, to 

continue to participate in decision making, we 

are taking steps to ensure that states 

effectively are actively engageing with 

communities as part of their public 

participation process during in the 

formulation of state plan developments. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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communities already disproportionately affected by air 

pollution. This rule sets expectations for states to engage with 

communities as they develop their plans, so that impacts on 

these communities is considered as plans are designed. The EPA 

commits, once implementation is under way, to assess the impacts 

of this rule. Likewise, we encourage states to evaluate the 

effects of their plans to ensure that there are no 

disproportionate adverse impacts on their communities. 

5. Additional context for this final rule

a. Climate change impacts. This final rule is an important step 

in an essential series of long-term actions that are achieving

and must continue to achieve the GHG emission reductions needed 

to address the serious threat of climate change, and constitutes 

a major commitment – and international leadership-by-doing – on 

the part of the U.S., one of the world’s largest GHG emitters. 

GHG pollution threatens the American public by leading to 

damaging and long-lasting changes in our climate that can have a 

range of severe negative effects on human health and the 

environment. CO2 is the primary GHG pollutant, accounting for 

nearly three-quarters of global GHG emissions19 and 82 percent of 

 

19 Intergovernmental Panel on Climate Change (IPCC) report, 

“Contribution of Working Group I to the Fourth Assessment Report 

of the Intergovernmental Panel on Climate Change,” 

Deleted: We also note that the substantial 

reductions in a range of air pollutants that 

will occur along with the GHG reductions are 

expected to result in significant near-term 

public health benefits in communities, in 

addition to the longer term benefits resulting 

from the reductions in GHGs. Once 

implementation is under way, the EPA will 

assess the effects of implementing this and 

other air quality rules, and we encourage 

states to evaluate the impacts of their plans 

on their most vulnerable communities.

Deleted: (9) Resources and Outreach. ¶

In their comments, many states identified the 

need for the EPA to maintain regular 

contact/forums with states throughout the 

implementation process and to provide training 

and guidance, including guidance on RE and EE 

emission measurement and verification (EM&V). 

To provide state and local governments and 

other stakeholders, including communities, 

with an understanding of the rule 

requirements, and to provide efficiencies 

where possible and reduce the cost and 

administrative burden, the EPA will continue 

outreach throughout the plan development and 

submittal process. Outreach will include 

opportunities for states to participate in 

briefings, teleconferences, and meetings about 

the final rule. The EPA’s 10 regional offices 

will continue to be the entry point for 

states, tribes and territories to raise 

technical and policy questions. The agency 

will host or co-host a number of webinars 

about various components of the final rule 

currently planned for the first two months 

after the final rule is issued. The EPA will 

use information from this outreach process to 

inform the training and other tools that will 

be of most use to the states, tribes, and 

territories that are implementing the final 

rule, and also to inform the training for 

citizens, including members of communities 

already experiencing disproportionate effects 

of climate change and air pollution and those 

that may be affected by state plansthat could 

be impacted, to support their participation in 

the state plan development process. The EPA 

also expects to issue guidance on specific 

topics. As guidance documents, tools, 

templates and other resources become 

available, the EPA, in consultation with the 

U.S. Department of Energy and other federal ... [10]

Deleted: 3

Deleted: C

Deleted: making

Deleted: toward expanding the unfolding 

ensemble

Deleted: acheive

Deleted: interational

Deleted: United States

Deleted: by 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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U.S. GHG emissions.20 The May 2014 report of the National Climate 

Assessment21 concluded that climate change impacts are already 

manifesting themselves and imposing losses and costs. The report 

documents increases in extreme weather and climate events in 

recent decades, with resulting damage and disruption to human 

well-being, infrastructure, ecosystems, and agriculture, and 

projects continued increases in impacts across a wide range of 

communities, sectors, and ecosystems. New scientific assessments 

since 2009, when the EPA determined that GHGs pose a threat to 

human health and the environment (the “Endangerment Finding”), 

highlight the urgency of addressing the rising concentration of 

CO2 in the atmosphere. Certain groups, including children, the 

elderly, and the poor, are most vulnerable to climate-related 

effects. Recent studies also find that certain communities, 

including low-income communities and some communities of color 

(more specifically, populations defined jointly by ethnic/racial 

characteristics and geographic location), are disproportionately 

affected by certain climate change related impacts — including 

 

2007. Available at 

http://epa.gov/climatechange/ghgemissions/global.html 

20 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

21 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment, May 

2014. Available at http://nca2014.globalchange.gov/. 

Deleted: populations 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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heat waves, degraded air quality, and extreme weather events – 

which are associated with increased deaths, illnesses, and 

economic challenges. Studies also find that climate change poses 

particular threats to the health, wellbeing, and ways of life of 

indigenous peoples in the United States. 

b. The utility power sector. One of the strategies of the 

President’s Climate Action Plan is to reduce CO2 emissions from 

power plants.22 This is because fossil fuel-fired EGUs are by far 

the largest emitters of GHGs, primarily in the form of CO2. Among 

stationary sources in the U.S. and among fossil fuel-fired EGUs, 

coal-fired units are by far the largest emitters of GHGs. To 

accomplish the goal of reducing CO2 emissions from power plants, 

President Obama issued a Presidential Memorandum23 that 

recognized the importance of significant and prompt action. The 

Memorandum directed the EPA to complete carbon pollution 

standards, regulations or guidelines, as appropriate, for new, 

modified, reconstructed and existing power plants, and in doing 

so to build on state leadership in moving toward a cleaner power 

sector. In this action and the concurrent CAA section 111(b) 

 

22 The President’s Climate Action Plan, June 2013. 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf

23 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards 

Deleted: ,

Deleted: a

Deleted: ,

Deleted: this 

Deleted: ,

Deleted: , calls for a wide range of 

activities, including 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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rule, the EPA is finalizing regulations to reduce GHG emissions 

from fossil fuel-fired EGUs. This CAA section 111(d) action 

builds on actions states and utilities are already taking to 

move toward cleaner generation of electric power. 

The utility power sector is unlike other industrial 

sectors. In other sectors, sources effectively operate 

independently and on a local-site scale, with control of their 

physical operations resting in the hands of their respective 

owners and operators. Pollution control standards, which focus 

on each source in a non-utility industrial source category, have 

reflected the standalone character of individual source 

investment decision-making and operations. 

In stark contrast, the utility power sector comprises a 

unique system of electricity resources, including the EGUs 

affected under these guidelines, that operate in a complex and 

interconnected grid where electricity generally flows freely 

(e.g., portions of the system cannot be easily isolated through 

the use of switches or valves as can be done in other networked 

systems like trains and pipeline systems). That grid is 

physically interconnected and operated on an integrated basis 

across large regions. In this interconnected system, system 

operators, whose decisions, protocols, and actions, to a 

significant extent, dictate the operations of individual EGUs 

Deleted: any 

Deleted: all 

Deleted: .

Deleted: While their level of activity and 

operations may be affected by the laws of 

supply and demand and thus can vary in 

response to market conditions over time, 

Deleted: s

Deleted: entirely 

Deleted: -

Deleted: 

Deleted: T

Deleted: some
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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and large ensembles of EGUs, must reliably balance supply and 

demand using available generation and demand-side resources, 

including energy efficiency, demand response and a wide range of 

low- and zero-emitting sources. These resources are managed to 

meet the system needs in a reliable and efficient manner. Each 

aspect of this interconnected system is highly regulated and 

coordinated, with supply and demand constantly being balanced to 

meet system needs. Each step of the process from the electric 

generator to the end user is highly regulated by multiple 

entities working in coordination and considering overall system 

reliability. For example, in an ISO or RTO with a 

centralized, organized capacity market, electric generators are 

paid to be available to run when needed, must bid into energy 

markets, must respond to dispatch instructions, and must have 

permission to schedule maintenance. The ISO/RTO dispatches 

resources in a way that maintains electric system reliability. 

The approach we take in the final guidelines is consistent

with the interconnected, interdependent and highly regulated 

nature of the utility power sector, the daily operation of 

affected EGUs within this framework, and the critical role of 

utilities in providing reliable, affordable electricity at all 

times and in all places within this complex, regulated system. 

Thus, not only do these guidelines put a premium on providing as 

Deleted: electric generators who are required 

to respond to the system operator's dispatch 

instructions

Deleted: in tune

Deleted: with both 

Deleted: electricity supply and demand are 

reliably balanced using available generation 

and demand-side resources, including energy 

efficiency, demand response and a wide range 

of low- and zero-emitting sources which are 

all managed to meet the system needs in a 

reliable and efficient manner. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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much flexibility and latitude as possible for states and 

utilities, they also recognize that a given EGU’s operations are 

determined by the availability and use of other generation 

resources to which it is physically connected and by the 

collective operating regime that integrates that individual 

EGU’s activity with other resources across the grid.

In this integrated system, numerous entities have both the 

capability and the responsibility to maintain a reliable 

electric system. FERC, DOE, state public utility commissions, 

independent system operators (ISOs), regional transmission 

organizations (RTOs), other planning authorities, and the North 

American Electric Reliability Corporation (NERC), all contribute 

to ensuring the reliability of the electric system in the U.S. 

Critical to this function are dispatch tools, applied primarily 

by RTOs, ISOs, and balancing authorities, that operate such that 

actions taken or costs incurred at one source directly affect or 

cause actions to occur at other sources. Generation, outages, 

and transmission changes in one part of the synchronous grid can 

affect the entire interconnected grid.24 The interconnection is 

such that “[i]f a generator is lost in New York City, its effect 

is felt in Georgia, Florida, Minneapolis, St. Louis, and New 

 

24 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010).

Deleted: approach the setting of standards for 

the source category in a way that reflects the 

very great extent to which 

Deleted: any

Deleted: actual 

Deleted: directly 

Deleted: that EGU

Deleted: connected not only physically, but, at 

the same time,

Deleted: that of a host of

Deleted: of which the individual EGU is but a 

constituent element
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Orleans.”25 The U.S. Supreme Court has explicitly recognized the 

interconnected nature of the electricity grid.26 

The uniqueness of the utility power sector inevitably 

affects the way in which environmental regulations are designed. 

When the EPA promulgates environmental regulations that affect 

the utility power sector, as we have done numerous times over 

the past four decades, we do so with the awareness of the 

importance of the efficient and continuous, uninterrupted 

operation of the interconnected electricity system in which EGUs 

participate. We also keep in mind the unique product that this 

 

25 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 160 (2d ed. 2010). 26 Federal Power Comm’n v. Florida Power & Light Co., 404 U.S. 

453, at 460 (1972) (quoting a Federal Power Commission hearing 

examiner, "`If a housewife in Atlanta on the Georgia system 

turns on a light, every generator on Florida’s system almost 

instantly is caused to produce some quantity of additional 

electric energy which serves to maintain the balance in the 

interconnected system between generation and load.’”) (citation 

omitted). See also New York v. FERC, 535 U.S. 1, at 7-8 (2002) 

(stating that “any electricity that enters the grid immediately 

becomes a part of a vast pool of energy that is constantly 

moving in interstate commerce.”) (citation omitted). In Federal 

Power Comm’n v. Southern California Edison Co., 376 U.S. 205 

(1964), the Supreme Court found that a sale for resale of 

electricity from Southern California Edison to the City of 

Colton, which took place solely in California, was under Federal 

Power Commission jurisdiction because some of the electricity 

that Southern California Edison marketed came from out of state. 

The Supreme Court stated that, “`federal jurisdiction was to 

follow the flow of electric energy, an engineering and 

scientific, rather than a legalistic or governmental, test.’” 

Id. at 210, quoting Connecticut Light & Power Co. v. Federal 

Power Commission, 324 U.S. 515, 529 (1945) (emphasis omitted). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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interconnected system provides – electricity services – and the 

critical role of this sector to the U.S. economy and to the 

fundamental well-being of all Americans. 

In the context of environmental regulation, Congress, the 

EPA and the states all have recognized – as we do in these final 

guidelines – that electricity production takes place, at least 

to some extent, interchangeably between and among multiple 

generation facilities and different types of generation. This is

evidenced in the enactment or promulgation of pollution 

reduction programs, such as Title IV of the CAA, the NOx SIP 

Call, the Cross-State Air Pollution Rule (CSAPR), and the 

Regional Greenhouse Gas Initiative (RGGI). As these actions 

show, both Congress and the EPA have consistently tailored 

legislation and regulations affecting the utility power sector 

to its unique characteristics. For example, in Title IV of the 

Clean Air Act Amendments of 1990, Congress established a 

pollution reduction program specifically for fossil fuel-fired 

EGUs and designed the SO2 portion of that program with express 

recognition of the sector’s ability to shift generation among 

various EGUs, which enabled pollution reduction by increasing 

reliance on renewable energy and demand-side energy efficiency. 

Similarly, in the NOX SIP Call, the Clean Air Interstate Rule 

(CAIR), and CSAPR, the EPA established pollution reduction 

Deleted: guidelness

Deleted: , as
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 85 of 1544

programs focused on fossil fuel-fired EGUs and designed those 

programs with express recognition of the sector’s ability to 

shift generation among various EGUs. In this action, we continue 

that approach. Both the subcategory-specific emission 

performance rates, and the pathways offered to achieve them, 

reflect and are tailored to the unique characteristics of the 

utility power sector. 

The way that power is produced, distributed and used in the 

United States is already changing as a result of advancements in 

innovative power sector technologies and in the availability and 

cost of low-carbon fuel, renewable energy and energy efficient 

demand-side technologies, as well as economic conditions. These 

changes are taking place at a time when the average age of the 

coal-fired generating fleet is approaching that at which 

utilities and states undertake significant new investments to 

address aging assets. In 2025, the average age of the coal-fired 

generating fleet is projected to be 49 years old, and 20 percent 

of those units would be more than 60 years old if they remain in 

operation at that time. Therefore, even in the absence of 

additional environmental regulation, states and utilities can be 

expected to be, and already are, making plans for and investing 

in the next generation of power production, simply because of 

the need to take account of the age of current assets and 

Deleted: source 

Deleted: ,

Deleted: ,

Deleted: When the EPA evaluated this sector for 

development of this rulemaking, we found that, 

across the nation, many states, cities and 

towns, and owners and operators of EGUs have 

shown leadership in creating and implementing 

policies and programs that reduce CO2

emissions from the utility power sector while 

achieving other economic, environmental and 

energy benefits. Some of these activities, 

such as market-based programs and GHG 

performance standards, directly require CO2

emission reductions from EGUs. Others reduce 

CO2 emissions by increasing the use of lower 

and zero CO2 emission alternatives such as 

renewable generation. For example, many states 

have adopted renewable portfolio standards 

(RPS). In other cases, utilities have chosen 

to construct renewable generation, at least in 

part, to reduce CO2 emissions. These 

approaches take advantage of cost-effective 

opportunities for improving the efficiency of 

fossil fuel-fired EGUs and using loweremitting generation across the electricity 

system’s interconnecting grid to reduce 

emissions from fossil fuel-fired EGUs. ¶

Deleted: ing

Deleted: ,

Deleted: ,

Deleted: they
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 86 of 1544

infrastructure. Thus, many outside analyses and studies already 

project that, even in the absence of environmental regulation, 

anywhere from $X to $Y billion must and will be invested in the 

utility power sector between now and 2030. These guidelines will 

help ensure that, as those necessary investments are being made, 

they are integrated with the need to address GHG pollution from 

the sector. 

At the same time, owners/operators of affected EGUs are 

already pursuing the types of measures contemplated in this 

rule. Out of 404 entities identified as owners or operators of 

affected EGUs, representing ownership of 82 percent of the total 

capacity of the affected EGUs, 178 already own RE generating 

capacity in addition to fossil fuel-fired generating 

capacity. In fact, these entities already own aggregate amounts 

of RE generating capacity equal to 25 percent of the aggregate 

amounts of their affected EGU capacity.27 In addition, funding 

for utility energy efficiency programs has been growing rapidly, 

increasing from $1.6 billion in 2006 to $6.3 billion in 2013. 

The final guidelines are based on, and reinforce, the 

actions already being taken by states and utilities to upgrade 

aging electricity infrastructure with 21st century technologies. 

 

27 SNL Energy. Data used with permission. Accessed on June 9, 

2015.

Deleted: o

Commented [A12]: ? 

Deleted: is

Deleted: unavoidable

Deleted: O

Deleted: 417 

Deleted: 84

Deleted: 191 

Deleted: 

Deleted: 21
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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The guidelines will ensure that these trends continue in ways 

that are consistent with the long-term planning and investment 

processes already used in the utility power sector. This final 

rule provides flexibility for states to build upon their 

progress, and the progress of cities and towns, in addressing 

GHGs, and minimizes additional requirements for existing 

programs where possible. It also allows states to pursue 

policies to reduce carbon pollution that: 1) continue to rely on 

a diverse set of energy resources; 2) ensure electric system 

reliability; 3) provide affordable electricity; 4) recognize 

investments that states and power companies are already making; 

and 5) tailor plans to meet their respective energy, 

environmental and economic needs and goals, and those of their 

local communities. Thus, the final guidelines will achieve 

meaningful CO2 emission reductions while maintaining the 

reliability and affordability of electricity in the U.S. 

6. Projected national-level emission reductions 

Under the final guidelines, the EPA projects annual CO2

reductions of 22 to 23 percent below 2005 levels in 2020, 

28 to 29 percent below 2005 levels in 2025, and 32 percent 

below 2005 levels in 2030. These guidelines will also 

result in important reductions in emissions of criteria air 

pollutants, including sulfur dioxide (SO2), nitrogen oxides 

Deleted: and also increase the momentum due to 

the imperative posed by climate change impacts

Deleted: ¶

c. CAA section 111(d) requirements. Concurrent 

with this CAA section 111(d) action, the EPA 

is finalizing “standards of performance” for 

CO2 emissions from new, modified, and 

reconstructed fossil fuel-fired EGUs under CAA 

section 111(b). When the EPA establishes CAA 

section 111(b) new source performance 

standards (NSPS), the EPA is also required, 

under CAA section 111(d)(1), to prescribe 

regulations for states to submit plans 

regulating existing sources in that source 

category for any air pollutant that is not 

regulated under the CAA section 109 

requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous 

air pollutants (HAP). CO2 qualifies as such an 

air pollutant. Unlike the CAA section 111(b) 

requirements that the EPA establishes and that 

apply directly to new, modified, or 

reconstructed sources, under CAA section 

111(d), states must develop and submit plans 

to the EPA in which the state establishes 

emission standards for the affected sources. ¶

Under CAA section 111(d),28 states must 

establish, in their state plans, emission 

standards that reflect the degree of emission 

limitation achievable through the application 

of the “best system of emission reduction” 

that, taking into account the cost of 

achieving such reduction and any non-air 

quality health and environmental impacts and 

energy requirements, the Administrator 

determines has been adequately demonstrated 

(BSER).29 Consistent with CAA section 111(d), 

the EPA is establishing CO2 emission 

performance rates for two categories of 

affected EGUs that reflect the EPA’s 

calculation of the emission limitation that 

sources in each of the two categories can 

achieve through the application of the BSER. 

States may comply by adopting these emission 

performance rates as their standards of 

performance they set for their affected 

sources emission standards. States may use ... [11]

Deleted: The final guidelines are structured 

so that states are not required to use each 

and every one of the measures that the EPA 

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 ... [12]

Deleted: 5

Deleted: [X}

Deleted: [X}

Deleted: [X]

Deleted: Under the final guidelines, the EPA 

projects annual CO2 reductions of [X} 

percent below 2005 levels in 2020, [X} 

percent below 2005 levels in 2025, and [X] 

percent below 2005 levels in 2030. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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(NOX), and directly emitted fine particulate matter (PM2.5). 

A thorough discussion of the EPA’s analysis is presented in 

Section XI.A of this preamble and in Chapter 3 of the 

Regulatory Impact Analysis (RIA) included in the docket for 

this rulemaking. 

7. Costs and benefits 

Actions taken to comply with the final guidelines will 

reduce emissions of CO2 and other air pollutants, including 

SO2, NOX, and directly emitted PM2.5 from the utility power 

sector. States will make the ultimate determination as to 

how the emission guidelines are implemented. Thus, all 

costs and benefits reported for this action are 

illustrative estimates. The illustrative costs and benefits 

are based upon compliance approaches that reflect a range 

of measures consisting of improved operations at EGUs, 

dispatching lower-emitting EGUs and zero-emitting energy 

sources, and increasing levels of end-use energy 

efficiency. 

Because of the range of choices available to states 

and the lack of a priori knowledge about the specific 

choices states will make in response to the final goals, 

the RIA for this final action presents two scenarios 

designed to achieve these goals, which we term the “rateDeleted: 6
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Page 89 of 1544

based” illustrative plan approach and the “mass-based” 

illustrative plan approach.

In summary, we estimate the total combined climate benefits 

and health co-benefits for the rate-based approach to be $3.5 to 

$4.6 billion in 2020, $18 to $28 billion in 2025, and $34 to $54 

billion in 2030 (3 percent discount rate, 2011$). Total combined 

climate benefits and health co-benefits for the mass-based 

approach are estimated to be $5.3 to $8.1 billion in 2020, $19 

to $29 billion in 2025, and $32 to $48 billion in 2030 (3 

percent discount rate, 2011$). A summary of the emission 

reductions and monetized benefits estimated for this rule at all 

discount rates is provided in Tables [X] through [X] of this 

preamble. 

The annual compliance costs are estimated using the 

Integrated Planning Model (IPM) and include demand-side energy 

efficiency program and participant costs as well as monitoring, 

reporting and recordkeeping costs. In 2020, total compliance 

costs of the final guidelines are approximately $2.5 billion 

(2011$) under the rate-based approach and $1.4 billion (2011$) 

under the mass-based approach. In 2025, total compliance costs 

of the final guidelines are approximately $1.0 billion (2011$) 

under the rate-based approach and $3.0 billion (2011$) under the 

mass-based approach. In 2030, total compliance costs of the 

Commented [A13]: ? 

Deleted: The EPA estimates that, in 2020, the 

final guidelines will yield monetized climate 

benefits of approximately $[X] billion (2011$) 

using a 3 percent discount rate (model 

average) relative to the 2020 base case (Table 

1).30 The air pollution health co-benefits 

associated with reducing exposure to ambient 

PM2.5 and ozone through emission reductions of 

precursor pollutants in 20205 relative to the 

2020 base case are estimated to be $[X] 

billion to $[X] billion using a 3 percent 

discount rate and $[X] billion to $[X] billion 

(2011$) using a 7 percent discount rate.¶

In 2025, the final guidelines will yield 

monetized climate benefits of approximately 

$[X] billion (2011$) using a 3 percent 

discount rate (model average) relative to the 

2025 base case (Table 1). The air pollution 

health co-benefits in 2025 relative to the 

2025 base case are estimated to be $[X] 

billion to $[X] billion using a 3 percent 

discount rate and $[X] billion to $[X] billion 

(2011$) using a 7 percent discount rate. ¶

In 2030, the EPA estimates the final 

guidelines will yield monetized climate 

benefits of approximately $[X] billion (2011$) 

using a 3 percent discount rate (model 

average) relative to the 2030. The air 

pollution health co-benefits in 2030 relative 

to the 2030 base case are estimated to be $[X] 

billion to $[X] billion using a 3 percent 

discount rate and $[X] billion to $[X] billion 

(2011$) using a 7 percent discount rate. ¶

Deleted: [X]

Deleted: total compliance costs of the final 

guidelines are approximately $[X] billion 

(2011$)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 90 of 1544

final guidelines are approximately $8.4 billion (2011$) under 

the rate-based approach and $5.1 billion (2011$) under the massbased approach.

The quantified net benefits (the difference between monetized 

benefits and compliance costs) in 2020 are estimated to range 

from $1.0 billion to $2.1 billion (2011$) using a 3 percent 

discount rate (model average) under the rate-based approach and 

from $3.9 billion to $6.7 billion (2011$) using a 3 percent 

discount rate (model average) under the mass-based approach. In 

2025, the quantified net benefits (the difference between 

monetized benefits and compliance costs) in 2025 are estimated 

to range from $17 billion to $27 billion (2011$) using a 3 

percent discount rate (model average) under the rate-based 

approach and from $16 billion to $26 billion (2011$) using a 3 

percent discount rate (model average) under the mass-based 

approach. In 2030, the quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2030 are 

estimated to range from $26 billion to $45 billion (2011$) using 

a 3 percent discount rate (model average) under the rate-based 

approach and from $26 billion to $43 billion (2011$) using a 3 

percent discount rate (model average) under the mass-based 

approach.

Deleted: total compliance costs of the final 

guidelines are approximately $[X] billion 

(2011$). 

Deleted: [X]

Deleted: [X]

Deleted: [X]

Deleted: [X]

Deleted: [X]

Deleted: [X]

Deleted: ¶
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Table 1. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025, and 

2030a Under the Rate-Based Illustrative Plan Approach [Billions 

of 2011$]

Rate-based Approach, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $2.8 

Air pollution health 

co-benefits c $0.70 to $1.8 $0.64 to $1.7 

Total Compliance 

Costs d $2.5 $2.5 

Net Monetized 

Benefits e $1.0 to $2.1 $1.0 to $2.0 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Rate-based Approach, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $10 

Air pollution health 

co-benefits c $7.4 to $18 $6.7 to $16 

Total Compliance 

Costs d $1.0 $1.0 

Net Monetized 

Benefits e $17 to $27 $16 to $25 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Visibility impairment 

Rate-based Approach, 2030 

Climate benefits b $20 

Air pollution health 

co-benefits c $14 to $34 $13 to $31 

Total Compliance 

Costs d $8.4 $8.4 

Net Monetized 

Benefits e $26 to $45 $25 to $43 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated for a 3 percent discount rate, however we 

emphasize the importance and value of considering the full range 

of SC-CO2 values. As shown in the RIA, climate benefits are also 

estimated using the other three SC-CO2 estimates (model average 

at 2.5 percent discount rate, 3 percent, and 5 percent; 95th

percentile at 3 percent). The SC-CO2 estimates are year-specific 

and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

Deleted: Final Guidelines, 2020 ... [13]

Deleted: %
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5%. This 

estimate includes monitoring, recordkeeping, and reporting costs 

and demand-side energy efficiency program and participant costs. e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

Table 2. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030a

Under the Mass-Based Illustrative Plan Approach [Billions of 

2011$] 

Mass-based Approach, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $3.3 

Air pollution health 

co-benefits c $2.0 to $4.8 $1.8 to $4.4 

Total Compliance 

Costs d $1.4 $1.4 

Net Monetized 

Benefits e $3.9 to $6.7 $3.7 to $6.3 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Mass-based Approach, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $12 

Air pollution health 

co-benefits c $7.1 to $17 $6.5 to $16 

Deleted: 

Deleted: X
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Total Compliance 

Costs d $3.0 $3.0 

Net Monetized 

Benefits e $16 to $26 $15 to $24 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Mass-based Approach, 2030 

Climate benefits b $20 

Air pollution health 

co-benefits c $12 to $28 $11 to $26 

Total Compliance 

Costs d $5.1 $5.1 

Net Monetized 

Benefits e $26 to $43 $25 to $40 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate, however 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA 

could not monetize. Due to current data and modeling 

limitations, our estimates of the benefits from reducing CO2

emissions do not include important impacts like ocean 

acidification or potential tipping points in natural or 

managed ecosystems. The unquantified benefits also include 

climate benefits from reducing emissions of non-CO2

greenhouse gases (e.g., nitrous oxide and methane)31 and co-

 

31 Although CO2 is the predominant greenhouse gas released by the 

power sector, electricity generating units also emit small 

amounts of nitrous oxide and methane. For more detail about 

power sector emissions, see RIA Chapter 2 and the U.S. 

Greenhouse Gas Reporting Program’s power sector summary, 

http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm

l.
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benefits from reducing direct exposure to SO2, NOX, and 

hazardous air pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

We project employment gains and losses relative to 

base case for different types of labor, including 

construction, plant operation and maintenance, coal and 

natural gas production, and demand-side energy efficiency. 

In 2030, we project, for coal and natural gas generation, a 

net decrease in job-years of about 31,000 under the ratebased approach and 34,000 under the mass-based approach32

for construction, plant operation and maintenance, and a 

gain of 52,000 to 83,000 jobs in the demand-side energy 

efficiency sector under either approach. Actual employment 

impacts will depend upon measures taken by states in their 

state plans and the specific actions sources take to 

comply. 

Based upon the foregoing, it is clear that the monetized 

benefits of this rule are substantial and far outweigh the 

costs. 

 

32 A job-year is not an individual job; rather, a job-year is the 

amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2025 may 

represent 20 full-time jobs or 40 half-time jobs. 

Deleted: 

Deleted: [X]

Deleted: 

Deleted: net change of [X] job-years

Deleted: and coal and natural gas 

Deleted: [X]

Commented [A14]: This paragraph was not clear, and led of 

with “net” loss which is bad optically when in fact overall there 

looks to be a gain. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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B. Organization and Approach for this Rule 

This final rule establishes the EPA’s emission guidelines 

for states to follow in developing plans to reduce CO2 emissions 

from the utility power sector. Section II of this preamble 

provides background information on climate change impacts from 

GHG emissions, GHG emissions from fossil fuel-fired EGUs, the 

utility power sector, the CAA section 111(d) requirements, EPA 

actions prior to this final action, outreach and consultations, 

and the number and extent of comments received. In Section III 

of the preamble, we present a summary of the rule requirements 

and the legal basis for these. Section IV explains the EPA 

authority to regulate CO2 and EGUs, identifies affected EGUs, and 

describes the proposed treatment of source categories. Section V 

describes the agency’s determination of the BSER using three 

building blocks and our key considerations in making the 

determination. Section VI provides the subcategory-specific 

emission performance rates, and Section VII provides equivalent 

statewide rate-based and mass-based goals. Section VIII then 

describes state plan approaches and the requirements, and 

flexibilities, for state plans, followed by Section IX, in which 

considerations for communities are described. Interactions 

between this final rule and other EPA programs and rules are 

discussed in Section X. Impacts of the proposed action are then 

Deleted: source 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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described in Section XI, followed by a discussion of statutory 

and executive order reviews in Section XII and the statutory 

authority for this action in Section XIII. 

We note that this rulemaking is being promulgated 

concurrently with related rulemakings: the final new source 

performance standards (NSPS) for CO2 emissions from newly 

constructed, modified, and reconstructed EGUs [INSERT THE 

FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE RULE], 

which is being promulgated under CAA section 111(b), and the 

proposed federal plan and model rules. These rulemakings have

their own rulemaking dockets. 

II. Background 

In this section, we discuss climate change impacts from GHG 

emissions, both on public health and public welfare. We also 

present information about GHG emissions from fossil fuel-fired 

EGUs, the challenges associated with controlling carbon dioxide 

emisions, the uniqueness of the utility power sector, and 

drecent and continuing trends and transitions in the utility 

power sector. In addition, we briefly describe CAA regulations 

for power plants, provide highlights of Congressional awareness 

of climate change and international agreements and actions, and 

summarize statutory and regulatory requirements relevant to this 

rulemaking. In addition, we provide background information on 

Deleted: a 

Deleted: ,

Deleted: is

Deleted: s

Deleted: its

Deleted: explain 

Deleted: uniqueness 

Deleted: of 

Deleted: escribe 

Deleted: this 

Deleted: the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the EPA’s June 18, 2014 Clean Power Plan proposal, the November 

4, 2014 supplemental proposal, and other actions associated with 

this rulemaking,33 followed by information on stakeholder 

outreach and consultations and the comments that the EPA 

received prior to issuing this final rulemaking. 

A. Climate Change Impacts from GHG Emissions 

According to the National Research Council, “Emissions 

of CO2 from the burning of fossil fuels have ushered in a 

new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere 

is long lived, it can effectively lock Earth and future 

generations into a range of impacts, some of which could 

become very severe. Therefore, emission reduction choices 

made today matter in determining impacts experienced not 

just over the next few decades, but in the coming centuries 

and millennia.”34 

In 2009, based on a large body of robust and compelling 

scientific evidence, the EPA Administrator issued the 

 

33 The EPA also published in the Federal Register a notice of 

data availability (79 FR 64543; November 8, 2014) and a notice 

on the translation of emission rate-based CO2 goals to mass-based 

equivalents (79 FR 67406; November 13, 2014). 

34 National Research Council, Climate Stabilization Targets, p.3. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Endangerment Finding under CAA section 202(a)(1).35 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

levels unprecedented in human history—may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., especially on the 

highest ozone days and in the largest metropolitan areas with 

the worst ozone problems, and thereby increase the risk of 

 

35 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496 (Dec. 15, 2009) (“Endangerment Finding”).

Deleted: including 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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morbidity and mortality. Climate change is also expected to 

cause more intense hurricanes and more frequent and intense 

storms and heavy precipitation, with impacts on other areas of 

public health, such as the potential for increased deaths, 

injuries, infectious and waterborne diseases, and stress-related 

disorders. Children, the elderly, and the poor are among the 

most vulnerable to these climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding 

Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

GHGs, climate changes are expected to place large areas of the 

country at serious risk of reduced water supplies, increased 

water pollution, and increased occurrence of extreme events such 

as floods and droughts. Coastal areas are expected to face a 

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

storm and flooding damage to property, or even loss of land due 

to inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand. 

Extreme weather from climate change threatens energy, 
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transportation, and water resource infrastructure. Climate 

change may also exacerbate ongoing environmental pressures in 

certain settlements, particularly in Alaskan indigenous 

communities, and is very likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S. 

3. New scientific assessments and observations 

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

the climate has continued to change, with new records being set 

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 

These assessments, from the Intergovernmental Panel on Climate 
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Change (IPCC), the U.S. Global Change Research Program (USGCRP), 

and the National Research Council (NRC), include: IPCC’s 2012 

Special Report on Managing the Risks of Extreme Events and 

Disasters to Advance Climate Change Adaptation (SREX) and the 

2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 

National Climate Assessment, Climate Change Impacts in the 

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A 

National Strategy to Meet the Challenges of a Changing Ocean

(Ocean Acidification), 2011 Report on Climate Stabilization 

Targets: Emissions, Concentrations, and Impacts over Decades to 

Millennia (Climate Stabilization Targets), 2011 National 

Security Implications for U.S. Naval Forces (National Security 

Implications), 2011 Understanding Earth’s Deep Past: Lessons for 

Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea 

Level Rise for the Coasts of California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate and Social Stress: 

Implications for Security Analysis (Climate and Social Stress), 

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these recent assessments in 

keeping with the same approach outlined in Section VIII.A of the 

2009 Endangerment Finding, which was to rely primarily upon the 

major assessments by the USGCRP, the IPCC, and the NRC of the 
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National Academies to provide the technical and scientific 

information to inform the Administrator’s judgment regarding the 

question of whether GHGs endanger public health and welfare. 

These assessments addressed the scientific issues that the EPA 

was required to examine, were comprehensive in their coverage of 

the GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. 

The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 

now and in the future. The NCA3 indicates that human health in 

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

health, and illnesses transmitted by food, water, and diseasecarriers such as mosquitoes and ticks.” The most recent 

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 

the allergenic pollen season for ragweed, and that increased CO2

by itself can elevate production of plant-based allergens. 
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The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the United States 

through impacts such as reduced access to traditional foods, 

decreased water quality, and increasing exposure to health and 

safety hazards. The IPCC AR5 finds that climate change-induced 

warming in the Arctic and resultant changes in environment 

(e.g., permafrost thaw, effects on traditional food sources) 

have significant impacts, observed now and projected, on the 

health and well-being of Arctic residents, especially indigenous 

peoples. Small, remote, predominantly-indigenous communities are 

especially vulnerable given their “strong dependence on the 

environment for food, culture, and way of life; their political 

and economic marginalization; existing social, health, and 

poverty disparities; as well as their frequent close proximity 

to exposed locations along ocean, lake, or river shorelines.”36 

In addition, increasing temperatures and loss of Arctic sea ice 

 

36 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, Cambridge, p. 1581. 
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increases the risk of drowning for those engaged in traditional 

hunting and fishing. 

 The NCA3 concludes that children’s unique physiology and 

developing bodies contribute to making them particularly 

vulnerable to climate change. Impacts on children are expected 

from heat waves, air pollution, infectious and waterborne 

illnesses, and mental health effects resulting from extreme 

weather events. The IPCC AR5 indicates that children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. The IPCC finds that additional health concerns may arise 

in low income households, especially those with children, if 

climate change reduces food availability and increases prices, 

leading to food insecurity within households. 

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events. 

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

and to more severe consequences from infectious and waterborne 

diseases. Limited mobility among older adults can also increase 

health risks associated with extreme weather and floods. 
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The new assessments also confirm and strengthen the 

conclusion that GHGs endanger public welfare, and emphasize the 

urgency of reducing GHG emissions due to their projections that 

show GHG concentrations climbing to ever-increasing levels in 

the absence of mitigation. The NRC assessment Understanding 

Earth’s Deep Past projected that, without a reduction in 

emissions, CO2 concentrations by the end of the century would 

increase to levels that the Earth has not experienced for more 

than 30 million years.37 In fact, that assessment stated that 

“the magnitude and rate of the present greenhouse gas increase 

place the climate system in what could be one of the most severe 

increases in radiative forcing of the global climate system in 

Earth history.”38 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds: as stated in the NRC assessment 

Understanding Earth’s Deep Past, “As Earth continues to warm, it 

may be approaching a critical climate threshold beyond which 

rapid and potentially permanent—at least on a human timescale—

changes not anticipated by climate models tuned to modern 

conditions may occur.” The NRC Abrupt Impacts report analyzed 

the threat of species extinction as an example of an 

 

37 National Research Council, Understanding Earth’s Deep Past, p. 

1.

38 Id., p.138.
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irreversible impact that is expected to be exacerbated by 

climate change. Species at most risk include those whose 

migration potential is limited, whether because they live on 

mountaintops or fragmented habitats with barriers to movement, 

or because climatic conditions are changing more rapidly than 

the species can move or adapt. While the NRC determined that it 

is not presently possible to place exact probabilities on the 

added contribution of climate change to extinction, they did 

find that there was substantial risk that impacts from climate 

change could, within a few decades, drop the populations in many 

species below sustainable levels thereby committing the species 

to extinction. Species within tropical and subtropical 

rainforests such as the Amazon and species living in coral reef 

ecosystems were identified by the NRC as being particularly 

vulnerable to extinction over the next 30 to 80 years, as were 

species in high latitude and high elevation regions. Moreover, 

due to the time lags inherent in the Earth’s climate, the NRC 

Climate Stabilization Targets assessment notes that the full 

warming from any given concentration of CO2 reached will not be 

fully realized for several centuries, underscoring that emission 

activities today carry with them climate commitments far into 

the future. 
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Future temperature changes will depend on what emission 

path the world follows. In its high emission scenario, the IPCC 

AR5 projects that global temperatures by the end of the century 

will likely be 2.6 °C to 4.8 °C (4.7 to 8.6 °F) warmer than 

today. Temperatures on land and in northern latitudes will 

likely warm even faster than the global average. However, 

according to the NCA3, significant reductions in emissions would 

lead to noticeably less future warming beyond mid-century, and 

therefore less impact to public health and welfare. 

While rainfall may only see small globally and annually 

averaged changes, there are expected to be substantial shifts in 

where and when that precipitation falls. According to the NCA3, 

regions closer to the poles will see more precipitation, while 

the dry subtropics are expected to expand (colloquially, this 

has been summarized as wet areas getting wetter and dry regions 

getting drier). In particular, the NCA3 notes that the western 

U.S., and especially the Southwest, is expected to become drier. 

This projection is consistent with the recent observed drought 

trend in the West. At the time of publication of the NCA, even 

before the last 2 years of extreme drought in California, tree 

ring data was already indicating that the region might be 

experiencing its driest period in 800 years. Similarly, the NCA3 

projects that heavy downpours are expected to increase in many 
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regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 

in regions such as the Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 

grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 out of 10 summers would be 

warmer than all but the 5 percent of warmest summers today, 

leading to increased frequency, duration, and intensity of heat 

waves. Extrapolations by the NCA also indicate that Arctic sea 

ice in summer may essentially disappear by mid-century. 

Retreating snow and ice, and emissions of carbon dioxide and 

methane released from thawing permafrost, will also amplify 

future warming. 

Since the 2009 Endangerment Finding, the USGCRP NCA3, and 

multiple NRC assessments have projected future rates of sea 

level rise that are 40 percent larger to more than twice as 

large as the previous estimates from the 2007 IPCC 4th Assessment 

Report due in part to improved understanding of the future rate 

of melt of the Antarctic and Greenland Ice sheets. The NRC Sea 

Level Rise assessment projects a global sea level rise of 0.5 to 

1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security 

Implications assessment suggests that “the Department of the 
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Navy should expect roughly 0.4 to 2 meters [1.3 to 6.6 feet] 

global average sea-level rise by 2100,”39 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3°C 

will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

the global total depending on various factors: the east coast of 

the U.S. in particular is expected to see higher rates of sea 

level rise than the global average. For comparison, the NCA3 

states that “five million Americans and hundreds of billions of 

dollars of property are located in areas that are less than four 

feet above the local high-tide level,” and the NCA3 finds that 

“[c]oastal infrastructure, including roads, rail lines, energy 

infrastructure, airports, port facilities, and military bases, 

are increasingly at risk from sea level rise and damaging storm 

surges.”40 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after greenhouse gas 

concentrations have stabilized (though more slowly than it would 

 

39 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28. 40 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 9. 
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have otherwise). Additionally, there is a threshold temperature 

above which the Greenland ice sheet will be committed to 

inevitable melting: according to the NCA, some recent research 

has suggested that even present day carbon dioxide levels could 

be sufficient to exceed that threshold. 

In general, climate change impacts are expected to be 

unevenly distributed across different regions of the United 

States and have a greater impact on certain populations, such as 

indigenous peoples and the poor. The NCA3 finds climate change 

impacts such as the rapid pace of temperature rise, coastal 

erosion and inundation related to sea level rise and storms, ice 

and snow melt, and permafrost thaw are affecting indigenous 

people in the United States. Particularly in Alaska, critical 

infrastructure and traditional livelihoods are threatened by 

climate change and, “[i]n parts of Alaska, Louisiana, the 

Pacific Islands, and other coastal locations, climate change 

impacts (through erosion and inundation) are so severe that some 

communities are already relocating from historical homelands to 

which their traditions and cultural identities are tied.”41 The 

IPCC AR5 notes, “Climate-related hazards exacerbate other 

 

41 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 17. 
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stressors, often with negative outcomes for livelihoods, 

especially for people living in poverty (high confidence). 

Climate-related hazards affect poor people’s lives directly 

through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”42 

Carbon dioxide in particular has unique impacts on ocean 

ecosystems. The NRC Climate Stabilization Targets assessment 

found that coral bleaching will increase due both to warming and 

ocean acidification. Ocean surface waters have already become 

30% more acidic over the past 250 years due to absorption of CO2

from the atmosphere. According to the NCA3, this acidification 

will reduce the ability of organisms such as corals, krill, 

oysters, clams, and crabs to survive, grow, and reproduce. The 

NRC Understanding Earth's Deep Past assessment notes four of the 

five major coral reef crises of the past 500 million years were 

caused by acidification and warming that followed GHG increases 

of similar magnitude to the emissions increases expected over 

 

42 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796. 
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the next hundred years. The NRC Abrupt Impacts assessment 

specifically highlighted similarities between the projections 

for future acidification and warming and the extinction at the 

end of the Permian which resulted in the loss of an estimated 90 

percent of known species. Similarly, the NRC Ocean Acidification 

assessment finds that “[t]he chemistry of the ocean is changing 

at an unprecedented rate and magnitude due to anthropogenic 

carbon dioxide emissions; the rate of change exceeds any known 

to have occurred for at least the past hundreds of thousands of 

years.”43 The assessment notes that the full range of 

consequences is still unknown, but the risks “threaten coral 

reefs, fisheries, protected species, and other natural resources 

of value to society.”44 

Events outside the United States, as also pointed out in 

the 2009 Endangerment Finding, will also have relevant 

consequences. The NRC Climate and Social Stress assessment 

concluded that it is prudent to expect that some climate events 

“will produce consequences that exceed the capacity of the 

affected societies or global systems to manage and that have 

global security implications serious enough to compel 

 

43 NRC, 2010: Ocean Acidification: A National Strategy to Meet 

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5. 

44 Ibid. 

Deleted: 
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international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

addressing changing security needs in the Arctic as sea ice 

retreats. 

In addition to future impacts, the NCA3 emphasizes that 

climate change driven by human emissions of GHGs is already 

happening now and it is happening in the United States. 

According to the IPCC AR5 and the NCA3, there are a number of 

climate-related changes that have been observed recently, and 

these changes are projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is 

extremely likely (>95% probability) that human influence was the 

dominant cause of the observed warming since the mid-20th

century, and likely (>66% probability) that human influence has 

more than doubled the probability of occurrence of heat waves in 

some locations. In the Northern Hemisphere, the last 30 years 

were likely the warmest 30 year period of the last 1400 years. 

U.S. average temperatures have similarly increased by 1.3 to 1.9 

degrees F since 1895, with most of that increase occurring since 

1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 

2010. Contributing to this rise was the warming of the oceans 
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and melting of land ice. It is likely that 275 gigatons per year 

of ice melted from land glaciers (not including ice sheets) 

since 1993, and that the rate of loss of ice from the Greenland 

and Antarctic ice sheets increased substantially in recent 

years, to 215 gigatons per year and 147 gigatons per year 

respectively since 2002. For context, 360 gigatons of ice melt 

is sufficient to cause global sea levels to rise 1 mm. Annual 

mean Arctic sea ice has been declining at 3.5 to 4.1 percent per 

decade, and Northern Hemisphere snow cover extent has decreased 

at about 1.6 percent per decade for March and 11.7 percent per 

decade for June. Permafrost temperatures have increased in most 

regions since the 1980s, by up to 3 °C (5.4 °F) in parts of 

Northern Alaska. Winter storm frequency and intensity have both 

increased in the Northern Hemisphere. The NCA3 states that the 

increases in the severity or frequency of some types of extreme 

weather and climate events in recent decades can affect energy 

production and delivery, causing supply disruptions, and 

compromise other essential infrastructure such as water and 

transportation systems. 

In addition to the changes documented in the assessment 

literature, there have been other climate milestones of note. In 

2009, the year of the Endangerment Finding, the average 

concentration of CO2 as measured on top of Mauna Loa was 387 
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parts per million, far above preindustrial concentrations of 

about 280 parts per million.45 The average concentration in 2013, 

the last full year before this rule was proposed, was 396 parts 

per million. The average concentration in 2014 was 399 parts per 

million. And the monthly concentration in April of 2014 was 401 

parts per million, the first time a monthly average has exceeded 

400 parts per million since record keeping began at Mauna Loa in 

1958, and for at least the past 800,000 years.46 Arctic sea ice 

has continued to decline, with September of 2012 marking a new 

record low in terms of Arctic sea ice extent, 40 percent below 

the 1979-2000 median. Sea level has continued to rise at a rate 

of 3.2 mm per year (1.3 inches/decade) since satellite 

observations started in 1993, more than twice the average rate 

of rise in the 20th century prior to 1993.47 And 2014 was the 

warmest year globally in the modern global surface temperature 

record, going back to 1880; this now means 19 of the 20 warmest 

years have occurred in the past 20 years, and except for 1998, 

the ten warmest years on record have occurred since 2002.48 The 

 

45ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx

t

46 http://www.esrl.noaa.gov/gmd/ccgg/trends/

47 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate 

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238. 

48 http://www.ncdc.noaa.gov/sotc/global/2014/13 
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first months of 2015 have also been some of the warmest on 

record. 

These assessments and observed changes make it clear that 

reducing emissions of GHGs across the globe is necessary in 

order to avoid the worst impacts of climate change, and 

underscore the urgency of reducing emissions now. The NRC 

Committee on America’s Climate Choices listed a number of 

reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”49 For 

example: 

 The faster emissions are reduced, the lower the risks 

posed by climate change. Delays in reducing emissions 

could commit the planet to a wide range of adverse 

impacts, especially if the sensitivity of the climate to 

greenhouse gases is on the higher end of the estimated 

range. 

 Waiting for unacceptable impacts to occur before taking 

action is imprudent because the effects of greenhouse gas 

emissions do not fully manifest themselves for decades 

and, once manifest, many of these changes will persist 

for hundreds or even thousands of years. 

 In the committee’s judgment, the risks associated with 

doing business as usual are a much greater concern than 

the risks associated with engaging in strong response 

efforts. 

4. Observed and Projected U.S. Regional Changes 

 

49 NRC, 2011: America’s Climate Choices, The National Academies 

Press. 
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The NCA3 assessed the climate impacts in 8 regions of the 

United States, noting that changes in physical climate 

parameters such as temperatures, precipitation, and sea ice 

retreat were already having impacts on forests, water supplies, 

ecosystems, flooding, heat waves, and air quality. Moreover, the 

NCA3 found that future warming is projected to be much larger 

than recent observed variations in temperature, with 

precipitation likely to increase in the northern states, 

decrease in the southern states, and with the heaviest 

precipitation events projected to increase everywhere. 

In the Northeast, temperatures increased almost 2 °F from 

1895 to 2011, precipitation increased by about 5 inches (10%), 

and sea level rise of about a foot has led to an increase in 

coastal flooding. The 70% increase in the amount of rainfall 

falling in the 1% of the most intense events is a larger 

increase in extreme precipitation than experienced in any other 

US region. 

In the future, if emissions continue increasing, the 

Northeast is expected to experience 4.5 to 10 °F of warming by 

the 2080s. This will lead to more heat waves, coastal and river 

flooding, and intense precipitation events. The southern portion 

of the region is projected to see 60 additional days per year 

above 90 °F by mid-century. Sea levels in the Northeast are 
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expected to increase faster than the global average because of 

subsidence, and changing ocean currents may further increase the 

rate of sea level rise. Specific vulnerabilities highlighted by 

the NCA include large urban populations particularly vulnerable 

to climate-related heat waves and poor air quality episodes, 

prevalence of climate sensitive vector-borne diseases like Lyme 

and West Nile Virus, usage of combined sewer systems that may 

lead to untreated water being released into local water bodies 

after climate-related heavy precipitation events, and 1.6 

million people living within the 100-year coastal flood zone who 

are expected to experience more frequent floods due to sea level 

rise and tropical-storm induced storm-surge. The NCA also 

highlighted infrastructure vulnerable to inundation in coastal 

metropolitan areas, potential agricultural impacts from 

increased rain in the spring delaying planting or damaging crops 

or increased heat in the summer leading to decreased yields and 

increased water demand, and shifts in ecosystems leading to 

declines in iconic species in some regions, such as cod and 

lobster south of Cape Cod. 

In the Southeast, average annual temperature during the 

last century cycled between warm and cool periods. A warm peak 

occurred during the 1930s and 1940s followed by a cool period 

and temperatures then increased again from 1970 to the present 
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by an average of 2°F. There have been increasing numbers of days 

above 95°F and nights above 75°F, and decreasing numbers of 

extremely cold days since 1970. Daily and five-day rainfall 

intensities have also increased, and summers have been either 

increasingly dry or extremely wet. Louisiana has already lost 

1,880 square miles of land in the last 80 years due to sea level 

rise and other contributing factors. 

The Southeast is exceptionally vulnerable to sea level 

rise, extreme heat events, hurricanes, and decreased water 

availability. Major consequences of further warming include 

significant increases in the number of hot days (95°F or above) 

and decreases in freezing events, as well as exacerbated groundlevel ozone in urban areas. Although projected warming for some 

parts of the region by the year 2100 are generally smaller than 

for other regions of the United States, projected warming for 

interior states of the region are larger than coastal regions by 

1°F to 2°F. Projections further suggest that globally there will 

be fewer tropical storms, but that they will be more intense, 

with more Category 4 and 5 storms. The NCA identified New 

Orleans, Miami, Tampa, Charleston, and Virginia Beach as being 

specific cities that are at risk due to sea level rise, with 

homes and infrastructure increasingly prone to flooding. 

Additional impacts of sea level rise are expected for coastal 
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highways, wetlands, fresh water supplies, and energy 

infrastructure. 

In the Northwest, temperatures increased by about 1.3oF 

between 1895 and 2011. A small average increase in precipitation 

was observed over this time period. However, warming 

temperatures have caused increased rainfall relative to 

snowfall, which has altered water availability from snowpack 

across parts of the region. Snowpack in the Northwest is an 

important freshwater source for the region. More precipitation 

falling as rain instead of snow has reduced the snowpack, and 

warmer springs have corresponded to earlier snowpack melting and 

reduced streamflows during summer months. Drier conditions have 

increased the extent of wildfires in the region.

Average annual temperatures are projected to increase by 

3.3oF to 9.7oF by the end of the century (depending on future 

global greenhouse gas emissions), with the greatest warming is 

expected during the summer. Continued increases in global 

greenhouse gas emissions are projected to result in up to a 30% 

decrease in summer precipitation. Earlier snowpack melt and 

lower summer stream flows are expected by the end of the century 

and will affect drinking water supplies, agriculture, 

ecosystems, and hydropower production. Warmer waters are 

expected to increase disease and mortality in important fish 
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species, including Chinook and sockeye salmon. Ocean 

acidification also threatens species such as oysters, with the 

Northwest coastal waters already being some of the most 

acidified worldwide due to coastal upwelling and other local 

factors. Forest pests are expected to spread and wildfires burn 

larger areas. Other high-elevation ecosystems are projected to 

be lost because they can no longer survive the climatic 

conditions. Low lying coastal areas, including the cities of 

Seattle and Olympia, will experience heightened risks of sea 

level rise, erosion, seawater inundation and damage to 

infrastructure and coastal ecosystems. 

In Alaska, temperatures have changed faster than anywhere

else in the United States. Annual temperatures increased by 

about 3 °F in the past 60 years. Warming in the winter has been 

even greater, rising by an average of 6 °F. Arctic sea ice is 

thinning and shrinking in area, with the summer minimum ice 

extent now covering only half the area it did when satellite 

records began in 1979. Glaciers in Alaska are melting at some of 

the fastest rates on Earth. Permafrost soils are also warming 

and beginning to thaw. Drier conditions have contributed to more 

large wildfires in the last 10 years than in any previous decade 

since the 1940s, when recordkeeping began. Climate change 
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impacts are harming the health, safety and livelihoods of Native 

Alaskan communities. 

By the end of this century, continued increases in 

greenhouse gas emissions are expected to increase temperatures 

by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10

°F in the interior, and by 6 to 8 °F across the rest of the 

state. These increases will exacerbate ongoing arctic sea ice 

loss, glacial melt, permafrost thaw and increased wildfire, and 

threaten humans, ecosystems, and infrastructure. Precipitation 

is expected to increase to varying degrees across the state, 

however warmer air temperatures and a longer growing season are 

expected to result in drier conditions. Native Alaskans are 

expected to experience declines in economically, nutritionally, 

and culturally important wildlife and plant species. Health 

threats will also increase, including loss of clean water, 

saltwater intrusion, sewage contamination from thawing 

permafrost, and northward extension of diseases. Wildfires will 

increasingly pose threats to human health as a result of smoke 

and direct contact. Areas underlain by ice-rich permafrost 

across the state are likely to experience ground subsidence and 

extensive damage to infrastructure as the permafrost thaws. 

Important ecosystems will continue to be affected. Surface 

waters and wetlands that are drying provide breeding habitat for 
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millions of waterfowl and shorebirds that winter in the lower 48 

states. Warmer ocean temperatures, acidification, and declining 

sea ice will contribute to changes in the location and 

availability of commercially and culturally important marine 

fish. 

In the Southwest, temperatures are now about 2 °F higher 

than the past century, and are already the warmest that region 

has experienced in at least 600 years. The NCA notes that there 

is evidence that climate-change induced warming on top of recent 

drought has influenced tree mortality, wildfire frequency and 

area, and forest insect outbreaks. Sea levels have risen about 7 

or 8 inches in this region, contributing to inundation of 

Highway 101 and backup of seawater into sewage systems in the 

San Francisco area. 

Projections indicate that the Southwest will warm an 

additional 5.5 to 9.5 °F over the next century if emissions 

continue to increase. Winter snowpack in the Southwest is 

projected to decline (consistent with the record lows from this 

past winter), reducing the reliability of surface water supplies 

for cities, agriculture, cooling for power plants, and 

ecosystems. Sea level rise along the California coast will 

worsen coastal erosion, increase flooding risk for coastal 

highways, bridges, and low-lying airports, pose a threat to 
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groundwater supplies in coastal cities such as Los Angeles, and 

increase vulnerability to floods for hundreds of thousands of 

residents in coastal areas. Climate change will also have 

impacts on the high-value specialty crops grown in the region as 

a drier climate will increase demands for irrigation, more 

frequent heat waves will reduce yields, and decreased winter 

chills may impair fruit and nut production for trees in 

California. Increased drought, higher temperatures, and bark 

beetle outbreaks are likely to contribute to continued increases 

in wildfires. The highly urbanized population of the Southwest 

is vulnerable to heat waves and water supply disruptions, which 

can be exacerbated in cases where high use of air conditioning 

triggers energy system failures. 

The rate of warming in the Midwest has markedly accelerated 

over the past few decades. Temperatures rose by more than 1.5 °F 

from 1900 to 2010, but between 1980 and 2010 the rate of warming 

was three times faster than from 1900 through 2010. 

Precipitation generally increased over the last century, with 

much of the increase driven by intensification of the heaviest 

rainfalls. Several types of extreme weather events in the 

Midwest (e.g., heat waves and flooding) have already increased 

in frequency and/or intensity due to climate change.
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In the future, if emissions continue increasing, the 

Midwest is expected to experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. Though projections of 

changes in total precipitation vary across the regions, more 

precipitation is expected to fall in the form of heavy downpours 

across the entire region, leading to an increase in flooding. 

Specific vulnerabilities highlighted by the NCA include longterm decreases in agricultural productivity, changes in the 

composition of the region’s forests, increased public health 

threats from heat waves and degraded air and water quality, 

negative impacts on transportation and other infrastructure 

associated with extreme rainfall events and flooding, and risks 

to the Great Lakes including shifts in invasive species, 

increases in harmful algal blooms, and declining beach health. 

High temperatures (more than 100 °F in the Southern Plains 

and more than 95 °F in the Northern Plains) are projected to 

occur much more frequently by mid-century. Increases in extreme 

heat will increase heat stress for residents, energy demand for 

air conditioning, and water losses. North Dakota’s increase in 

annual temperatures over the past 130 years is the fastest in 

the contiguous U.S., mainly driven by warming winters. Specific 

vulnerabilities highlighted by the NCA include increased demand 

for water and energy, changes to crop growth cycles and 
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agricultural practices, and negative impacts on local plant and 

animal species from habitat fragmentation, wildfires, and 

changes in the timing of flowering or pest patterns. Communities 

that are already the most vulnerable to weather and climate 

extremes will be stressed even further by more frequent extreme 

events occurring within an already highly variable climate 

system. 

In Hawaii, other Pacific islands, and the Caribbean, rising 

air and ocean temperatures, shifting rainfall patterns, changing 

frequencies and intensities of storms and drought, decreasing 

baseflow in streams, rising sea levels, and changing ocean 

chemistry will affect ecosystems on land and in the oceans, as 

well as local communities, livelihoods, and cultures. Low 

islands are particularly at risk. 

Rising sea levels, coupled with high water levels caused by 

tropical and extra-tropical storms, will incrementally increase 

coastal flooding and erosion, damaging coastal ecosystems, 

infrastructure, and agriculture, and negatively affecting 

tourism. Ocean temperatures in the Pacific region exhibit strong 

year-to-year and decadal fluctuations, but since the 1950s, they 

have exhibited a warming trend, with temperatures from the 

surface to a depth of 660 feet rising by as much as 3.6°F. As a 

result of current sea level rise, the coastline of Puerto Rico 
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around Rincón is being eroded at a rate of 3.3 feet per year. 

Freshwater supplies are already constrained and will become more 

limited on many islands. Saltwater intrusion associated with sea 

level rise will reduce the quantity and quality of freshwater in 

coastal aquifers, especially on low islands. In areas where 

precipitation does not increase, freshwater supplies will be 

adversely affected as air temperature rises. 

Warmer oceans are leading to increased coral bleaching 

events and disease outbreaks in coral reefs, as well as changed 

distribution patterns of tuna fisheries. Ocean acidification 

will reduce coral growth and health. Warming and acidification, 

combined with existing stresses, will strongly affect coral reef 

fish communities. For Hawaii and the Pacific islands, future sea 

surface temperatures are projected to increase 2.3°F by 2055 and 

4.7°F by 2090 under a scenario that assumes continued increases 

in emissions. Ocean acidification is also taking place in the 

region, which adds to ecosystem stress from increasing 

temperatures. Ocean acidity has increased by about 30% since the 

pre-industrial era and is projected to further increase by 37% 

to 50% from present levels by 2100. 

The NCA also discussed impacts that occur along the coasts 

and in the oceans adjacent to many regions, and noted that other 
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impacts occur across regions and landscapes in ways that do not 

follow political boundaries. 

B. GHG Emissions from Fossil Fuel-fired EGUs50

Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2, and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. 

This section describes the amounts of these emissions and places 

these amounts in the context of the U.S. Inventory of Greenhouse 

Gas Emissions and Sinks51 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program52 (GHGRP) that 

requires emitting facilities over threshold amounts of GHGs to 

report their emissions to the EPA annually. Using data from the 

GHGRP, this section also places emissions from fossil fuel-fired 

 

50 The emission data presented in this section of the preamble 

(Section II.B) are in metric tons, in keeping with reporting 

requirements for the GHGRP and the U.S. GHG Inventory. Note that 

the mass-based state goals presented in section VII of this 

preamble, and discussed elsewhere in this preamble, are 

presented in short tons.

51 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2013”, Report EPA 430-R-15-004, United States Environmental 

Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

52 U.S. EPA Greenhouse Gas Reporting Program Dataset, see 

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html
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EGUs in the context of the total emissions reported to the GHGRP 

from facilities in the other largest-emitting industries. 

The EPA prepares the official U.S. GHG Inventory to comply 

with commitments under the United Nations Framework Convention 

on Climate Change (UNFCCC). This inventory, which includes 

recent trends, is organized by industrial sectors. It provides 

the information in Table 2 below, which presents total U.S. 

anthropogenic emissions and sinks53 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013. 

Table 2. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))54

SECTOR 1990 2005 2013 

Energy55 5,290.5 6,273.6 5,636.6

Industrial Processes 

and Product Use 342.1 367.4 359.1

Agriculture 448.7 494.5 515.7

Land Use, Land-Use 

Change and Forestry 13.8 25.5 23.3 

Waste 206.0 189.2 138.3

Total Emissions 6,301.1 7,350.2 6,673.0

 

53 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide.

54 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 

55 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel 

combustion and fugitive fuel emissions. 
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Land Use, Land-Use 

Change and Forestry 

(Sinks) (775.8) (911.9) (881.7)

Net Emissions (Sources 

and Sinks) 5,525.2 6,438.3 5,791.2

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.3 percent of total 

2013 GHG emissions.56 In 2013, fossil fuel combustion by the 

utility power sector –- entities that burn fossil fuel and whose 

primary business is the generation of electricity –- accounted 

for 38.3 percent of all energy-related CO2 emissions.57 Table 3 

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005 and 2013. 

Table 3. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)58

 

56 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

57 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 

58 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

GHG EMISSIONS 1990 2005 2013 
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In addition to preparing the official U.S. GHG Inventory to 

present comprehensive total U.S. greenhouse gas emissions and 

comply with commitments under the UNFCCC, the EPA collects 

detailed GHG emissions data from the largest emitting facilities 

in the U.S. through its Greenhouse Gas Reporting Program 

(GHGRP). Data collected by the GHGRP from large stationary 

sources in the industrial sector show that the utility power 

sector emits far greater CO2 emissions than any other industrial 

sector. Table 4 below presents total GHG emissions in 2013 for 

the largest emitting industrial sectors as reported to the 

GHGRP. As shown in Table 3 and Table 4, respectively, CO2

emissions from fossil fuel-fired EGUs are nearly three times as 

large as the total reported GHG emissions from the next ten 

largest emitting industrial sectors in the GHGRP database 

combined. 

Table 4. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)59

 

59 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 

18, 2014. http://ghgdata.epa.gov/ghgp/main.do. 

Total CO2 from fossil fuelfired EGUs 1,820.8 2,400.9 2,039.8

 - from coal 1,547.6 1,983.8 1,575.0

 - from natural gas 175.3 318.8 441.9

 - from petroleum 97.5 97.9 22.4
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C. Challenges in Controlling Carbon Dioxide Emissions 

Carbon dioxide is a unique air pollutant and controlling it 

presents unique challenges. CO2 is emitted in enormous 

quantities, and those quantities, coupled with the fact that CO2

is relatively unreactive, make it much more difficult to mitigate 

by measures or technologies that are typically utilized within 

an existing power plant. Measures that may be used to limit CO2

emissions would include efficiency improvements, which have 

thermodynamic limitations and carbon capture and sequestration 

(CCS), which is energy resource intensive. 

Unlike other air pollutants which are results of trace 

impurities in the fuel, products of incomplete or inefficient 

combustion, or combustion byproducts, CO2 is an inherent product 

of clean, efficient combustion of fossil fuels, and therefore is 

an unavoidable product generated in enormous quantities, far 

Industrial Sector 2013

Petroleum Refineries 176.7 

Onshore Oil & Gas Production 94.8

Municipal Solid Waste Landfills 93.0 

Iron & Steel Production 84.2 

Cement Production 62.8

Natural Gas Processing Plants 59.0

Petrochemical Production 52.7

Hydrogen Production 41.9

Underground Coal Mines 39.8

Food Processing Facilities 30.8
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greater than any other air pollutant.60 In fact, CO2 is emitted 

in far greater quantities than all other air pollutants 

combined. Total emissions of all non-greenhouse gas (GHG) air 

pollutants in the U.S., from all sources, in 2013, were 121 

million metric tons.61,62 As noted above, total emissions of CO2

 

60 Lackner et al., “Comparative Impacts of Fossil Fuels and 

Alternative Energy Sources”, Issues in Environmental Science and 

Technology (2010). 

61 This includes NAAQS and HAPs, based on the following table: 

Table X. 

Pollutant 2013 tons 

(million short tons) Reference 

CO 69.758 

Trends file 

(http://www.epa.gov/ttn

chie1/trends/) 

NOX 13.072 “ 

PM10 20.651 “ 

SO2 5.098 “ 

VOC 17.471 “ 

NH3 4.221 “ 

HAPS 3.641 

2011 NEI version 2 

(http://www.epa.gov/ttn

/chief/net/2011inventor

y.html) 

Total 133.912 

It should be noted that PM2.5 is included in the amounts for PM10. 

Lead, another NAAQS pollutant, is emitted in the amounts of 

approximately 1,000 tons per year, and, in light of that 

relatively small quantity, was excluded from this analysis. 

Ammonia (NH3) is included because it is a precursor to PM2.5

secondary formation. Note that one short ton is equivalent to 

0.907185 metric ton. 

62 In addition, emissions of non-CO2 GHGs totaled 1.168 billion 

metric tons of carbon-dioxide equivalents (CO2e) in 2013. See 

Table ES-2, Executive Summary, 1990-2013 Inventory of U.S. 

Greenhouse Gas Emissions and Sinks. 
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from coal-fired power plants alone – the largest stationary 

source emitter -- were 1.575 billion metric tons in that year,63

and total emissions of CO2 from all sources were 5.5 billion 

metric tons.64,65 Carbon makes up the majority of the mass of coal 

and other fossil fuels, and for every ton of carbon burned, more 

 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHGInventory-2015-Chapter-Executive-Summary.pdf 

This includes emissions of methane, nitrous oxide, and 

fluorinated GHGs (hydrofluorocarbons, perfluorocarbons, sulfur 

hexafluoride, and nitrogen trifluoride). In the total, the 

emissions of each non-CO2 GHG have been translated from metric 

tons of that gas into metric tons of CO2e by multiplying the 

metric tons of the gas by the global warming potential (GWP) of 

the gas. (The GWP of a gas is a measure of the ability of one 

kilogram of that gas to trap heat in earth’s atmosphere compared 

to one kilogram of CO2.) 63 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

64 U.S. EPA, Greenhouse Gas Inventory Data Explorer, 

http://www.epa.gov/climatechange/ghgemissions/inventoryexplorer/

#allsectors/allgas/gas/current65 As another point of comparison, 

except for carbon dioxide, SO2 and NOx are the largest air 

pollutant emissions from coal-fired power plants. Over the past 

decade, U.S. power plants have emitted more than 200 times as 

much CO2 as they have emitted SO2 and NOx. See de Gouw et al., 

“Reduced emissions of CO2, NOx, and SO2 from U.S. power plants 

owing to switch from coal to natural gas with combined cycle 

technology,” Earth’s Future (2014).

65 As another point of comparison, except for carbon dioxide, 

SO2 and NOx are the largest air pollutant emissions from coalfired power plants. Over the past decade, U.S. power plants have 

emitted more than 200 times as much CO2 as they have emitted SO2

and NOx. See de Gouw et al., “Reduced emissions of CO2, NOx, and 

SO2 from U.S. power plants owing to switch from coal to natural 

gas with combined cycle technology,” Earth’s Future (2014).

Deleted: ¶
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than 3 tons of CO2 is produced.66 In addition, unlike many of the 

other air pollutants that react with sunlight or chemicals in 

the atmosphere, or are rained out or deposited on surfaces, CO2

is relatively unreactive and difficult to remove directly from 

the atmosphere.67,68

CO2’s huge quantities and lack of reactivity make it 

challenging to remove from the smokestack. Retrofitted equipment 

is required to capture the CO2 before transporting it to a 

storage site. However, the scale of infrastructure required to 

directly mitigate CO2 emissions from existing EGUs through CCS 

can be quite large and difficult to integrate into the existing 

fossil fuel infrastructure. These CCS techniques are discussed 

in more depth elsewhere in the preamble for this rule and for 

the section 111(b) rule for new sources that accompanies this 

rule. 

The properties of CO2 can be contrasted with those of a 

number of other pollutants which have more accessible mitigation 

options. For example, the NAAQS pollutants – which generally are 

 

66 Each atom of carbon in the fuel combines with 2 atoms of 

oxygen in the air. 

67 Seinfeld J. and Pandis S., Atmospheric Chemistry and Physics: 

From Air Pollution to Climate Change (1998). 

68 The fact that CO2 is unreactive means that it is primarily 

removed from the atmosphere by dissolving in oceans or by being 

converted into biomass by plants. Herzog, H., “Scaling up carbon 

dioxide capture and storage: From megatons to gigatons”, Energy 

Economics (2011). 
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emitted in the largest quantities of any of the other air 

pollutants, except for CO2 – each have more accessible mitigation 

options. Sulfur dioxide (SO2) is the result of a contaminant in 

the fuel, and, as a result, it can be reduced by using lowsulfur coal or by using flue-gas desulfurization (FGD) 

technologies. Emissions of nitrogen oxides (NOx) can be mitigated 

relatively easily using combustion control techniques (e.g., 

low-NOx burners) and by using downstream controls such as 

selective catalytic reduction (SCR) and selective non-catalytic 

reduction (SNCR) technologies. Particulate matter (PM) can be 

effectively mitigated using fabric filters, PM scrubbers, or 

electrostatic precipitators. Lead is part of particulate matter 

emissions and is controlled through the same devices. Carbon 

monoxide and VOCs are the products of incomplete combustion and 

can therefore be abated by more efficient combustion conditions, 

and can also be destroyed in the smokestack by the use of 

oxidation catalysts which complete the combustion process. Many 

air toxics are VOCs, such as polyaromatic hydrocarbons, and 

therefore can be abated in the same ways just described. But in 

every case, these pollutants can be controlled at the source 

much more readily than CO2 primarily because of the comparatively 

lower quantities that are produced, and also due to other 

attributes such as relatively greater reactivity and solubility.
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D. The Utility Power Sector 

1. A brief history 

The modern American electricity system is one of the 

greatest engineering achievements of the past 100 years. Since 

the invention of the incandescent light bulb in the 1870s,69

electricity has become one of the major foundations for modern 

American life. Beginning with the first power station in New 

York City in 1882, each power station initially served a 

discrete set of consumers, resulting in small and localized 

electricity systems.70 During the early 1900s, smaller systems 

consolidated, allowing generation resources to be shared over 

larger areas. Interconnecting systems have reduced generation 

investment costs and improved reliability.71 Local and state 

governments initially regulated these growing electricity 

 

69 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, at 1 (2011), available at 

http://www.raponline.org/document/download/id/645. 

70 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 2-4 (2d ed. 2010). 71 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 5-6 (2d ed. 2010). Investment in 

electric generation is extremely capital intensive, with 

generation potentially accounting for 65 percent of customer 

costs. If these costs can be spread to more customers, then 

this can reduce the amount that each individual customer pays. 

Federal Energy Regulatory Commission, Energy Primer: A Handbook 

of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 
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systems with federal regulation coming later in response to 

public concerns about rising electricity costs.72 

Initially, states had broad authority to regulate public 

utilities, but gradually federal regulation increased. In 1920, 

Congress passed the Federal Water Power Act, creating the 

Federal Power Commission (FPC) and providing for the licensing 

of hydroelectric facilities on U.S. government lands and 

navigable waters of the U.S.73 During this time period, the U.S. 

Supreme Court found that state authority to regulate public 

utilities is limited, holding that the Commerce Clause does not 

allow state regulation to directly burden interstate commerce.74

For example, in Public Utilities Commission of Rhode Island v. 

Attleboro Steam & Electric Company, Rhode Island sought to 

regulate the electricity rates that a Rhode Island generator was 

charging to a company in Massachusetts that resold the 

electricity to Attleboro, Massachusetts.75 The Supreme Court 

found that Rhode Island’s regulation was impermissible because 

 

72 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). 

73 The FPC became an independent Commission in 1930. United 

States Government Manual 1945: First Edition, at 486, available 

at http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html. 74 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

5 (2002) (citation omitted).

75 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83 (1927).
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it imposed a "direct burden upon interstate commerce."76 The 

Supreme Court held that this kind of interstate transaction was 

not subject to state regulation. However, because Congress had 

not yet passed legislation to make these types of transactions 

subject to federal regulation, this became known as the 

"Attleboro gap" in regulation. In 1935, Congress passed the 

Federal Power Act (FPA), giving the FPC jurisdiction over “the 

transmission of electric energy in interstate commerce" and "the 

sale of electric energy at wholesale in interstate commerce."77

Under FPA section 205, the FPC was tasked with ensuring that 

rates for jurisdictional services are just, reasonable, and not 

unduly discriminatory or preferential.78 FPA section 206 

authorized the FPC to determine, after a hearing upon its own 

motion or in response to a complaint filed at the Commission, 

whether jurisdictional rates are just, reasonable, and not 

unduly discriminatory or preferential.79 In 1938, Congress passed 

the Natural Gas Act (NGA), giving the FPC jurisdiction over the 

transmission or sale of natural gas in interstate commerce.80 The 

 

76 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83, 89 (1927).

77 16 U.S.C. § 824(b)(1). 

78 16 U.S.C. § 824d. 

79 16 U.S.C. § 824e. 

80 Energy Information Administration, Natural Gas Act of 1938, 

available at 
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NGA also gave the FPC the jurisdiction to “grant certificates 

allowing construction and operation of facilities used in 

interstate gas transmission and authorizing the provision of 

services.”81 In 1977, the FPC became FERC after Congress passed 

the Department of Energy Organization Act. 

By the 1930s, regulated electric utilities that provided 

the major components of the electrical system - generation, 

transmission, and distribution - were common.82 These regulated 

monopolies are referred to as vertically-integrated utilities. 

As utilities built larger and larger electric generation 

plants, the cost per unit to generate electricity decreased.83 

However, these larger plants were extremely capital intensive 

for any one company to fund.84 Some neighboring utilities solved 

this issue by agreeing to share electricity reserves when 

 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html. 

81 Energy Information Administration, Natural Gas Act of 1938, 

available at 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html. 

82 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/(last visited Mar. 9, 2015).

83 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

84 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
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needed.85 These utilities began building larger transmission 

lines to deliver power in times when large generators 

experienced outages.86 Eventually, some utilities that were in 

reserve sharing agreements formed electric power pools to 

balance electric load over a larger area. Participating 

utilities gave control over scheduling and dispatch of their 

electric generation units to a system operator.87 Some power 

pools evolved into today’s regional transmission organizations 

(RTOs) and independent system operators (ISOs). 

In the past, electric utilities generally operated as state 

regulated monopolies, supplying end-use customers with 

generation, distribution, and transmission service.88 However, 

the ability of electric utilities to operate as natural 

monopolies came with consumer protection safeguards.89 “In 

 

85 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.

86 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.

87 Shively, B, Ferrare, J, Understanding Today’s Electricity 

Business, Enerdynamics, at 94 (2012). 88 Maryland Department of Natural Resources, Maryland Power 

Plants and the Environment: A Review of the Impacts of Power 

Plants and Transmission Lines on Maryland’s Natural Resources, 

at 2-5 (2006). 

89 Pacific Power, Utility Regulation, at 1, available at

https://www.pacificpower.net/content/dam/pacific_power/doc/About

_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf. 
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exchange for a franchised, monopoly service area, utilities 

accept an obligation to serve – meaning there must be adequate 

supply to meet customers’ needs regardless of the cost.”90 Under 

this obligation to serve, the utility agreed to provide service 

to any customer located within its service jurisdiction. 

On both a federal and state level, competition has entered 

the electricity sector to varying degrees in the last few 

decades.91 In the early 1990s, some states began to consider 

allowing competition to enter retail electric service.92 Federal 

and state efforts to allow competition in the electric utility 

industry have resulted in independent power producers (IPPs)93

 

90 Pacific Power, Utility Regulation, at 1, available at

https://www.pacificpower.net/content/dam/pacific_power/doc/About

_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf. 

91 For example, in 1978, Congress passed the Public Utilities 

Regulatory Policies Act (PURPA) which allowed non-utility owned 

power plants to sell electricity. Burn, An Energy Journal, The 

Electricity Grid: A History, available at 

http://burnanenergyjournal.com/the-electric-grid-a-history/ 

(last visited Mar. 9, 2015). PURPA, the Energy Policy Act of 

1992 (EPAct 1992), and the Energy Policy Act of 2005 (EPAct 

2005) “promoted competition by lowering entry barriers and 

increasing transmission access.” The Electric Energy Market 

Competition Task Force, Report to Congress on Competition in 

Wholesale and Retail Markets for Electric Energy, at 2, 

available at http://www.ferc.gov/legal/fed-sta/ene-polact/epact-final-rpt.pdf (last visited Mar. 20, 2015). 

92 The Electric Energy Market Competition Task Force, Report to 

Congress on Competition in Wholesale and Retail Markets for 

Electric Energy, at 2, available at

http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-finalrpt.pdf (last visited Mar. 20, 2015). 

93 These entities are also referred to as merchant generators. 
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producing approximately 37 percent of net generation in 2013.94

Electric utilities in some states remain vertically integrated 

without retail competition from IPPs. Today, there are over 

3,000 public, private, and cooperative utilities in the United 

States.95 These utilities include both investor-owned utilities96

and consumer-owned utilities.97 

Over time, the grid slowly evolved into a complex, 

interconnected transmission system that allows electric 

generators to produce electricity that is then fed onto 

transmission lines at high voltages.98 These larger transmission 

 

94 Energy Information Administration, Electric Power Annual, 

Table 1.1 Total Electric Power Summary Statistics, 2013 and 2012

(2015), available at

http://www.eia.gov/electricity/annual/html/epa_01_01.html. 

95 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, at 9 (2011), available at 

http://www.raponline.org/document/download/id/645. 

96 Investor-owned utilities are private companies that are 

financed by a combination of shareholder equity and bondholder 

debt. Regulatory Assistance Project (RAP), Electricity 

Regulation in the US: A Guide, at 9 (2011), available at 

http://www.raponline.org/document/download/id/645. 

97 Consumer-owned utilities include municipal utilities, public 

utility districts, cooperatives, and a variety of other entities 

such as irrigation districts. Regulatory Assistance Project 

(RAP), Electricity Regulation in the US: A Guide, at 9-10 

(2011), available at 

http://www.raponline.org/document/download/id/645. 

98 Peter Fox-Penner, Electric Utility Restructuring: A Guide to 

the Competitive Era, Public Utility Reports, Inc., at 5, 34 

(1997). “The extent of the power system’s short-run physical 

interdependence is remarkable, if not entirely unique. No other 

large, multi-stage industry is required to keep every single 

producer in a region – whether or not owned by the same company 
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lines are able to access generation that is located more 

remotely, with transmission lines crossing many miles, including 

state borders.99 Closer to end users, electricity is transformed 

into a lower voltage that is transported across localized 

transmission lines to homes and businesses.100 Localized 

transmission lines make up the distribution system. These three 

components of the electricity system - generation, transmission, 

 

– in immediate synchronization with all other producers.” Id. at 

34. “At an early date, those providing electric power recognized 

that peak use for one system often occurred at a different time 

from peak use in other systems. They also recognized that 

equipment failures occurred at different times in various 

systems. Analyses showed significant economic benefits from 

interconnecting systems to provide mutual assistance; the 

investment required for generating capacity could be reduced and 

reliability could be improved. This lead [sic] to the 

development of local, then regional, and subsequently three 

transmission grids that covered the United States and parts of 

Canada.” Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 5-6 (2d ed. 2010). 99 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). Because of the ease and 

low cost of converting voltages in an alternating current (AC) 

system from one level to another, the bulk power system is 

predominantly an AC system rather than a direct current (DC) 

system. In an AC system, electricity cannot be controlled like a 

gas or liquid by utilizing a valve in a pipe. Instead, absent 

the presence of expensive control devices, electricity flows 

freely along all available paths, according to the laws of 

physics. U.S.-Canada Power System Outage Task Force, Final 

Report on the August 14, 2003 Blackout in the United States and 

Canada: Causes and Recommendations, at 6 (Apr. 2004), available 

at http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf.

100 Peter Fox-Penner, Electric Utility Restructuring: A Guide to 

the Competitive Era, Public Utility Reports, Inc., at 5 (1997). 
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and distribution - are closely related and must work in 

coordination to deliver electricity from the point of generation 

to the point of consumption. This interconnectedness is a 

fundamental aspect of the nation’s electricity system, requiring 

a complicated integration of all components of the system to 

balance supply and demand and a federal, state, and local 

regulatory network to oversee the physically interconnected 

network. Facilities planned and constructed in one segment can 

impact facilities and operations in other segments and vice 

versa. 

The North American electric grid has developed into a 

large, interconnected system.101 Electricity from a diverse set 

of generation resources such as natural gas, nuclear, coal, and 

renewables is distributed over high-voltage transmission lines 

divided across the continental United States into three 

synchronous interconnections – the Eastern Interconnection, 

Western Interconnection, and the Texas Interconnection.102 These 

 

101 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 5 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 

102 Regulatory Assistance Project (RAP), Electricity Regulation 

in the US: A Guide, 2011, at 1, available at

http://www.raponline.org/document/download/id/645. 
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three synchronous systems each act like a single machine.103

Diverse resources generate electricity that is transmitted and 

distributed through a complex system of interconnected 

components to industrial, business, and residential consumers. 

Unlike other industries where sources make operational decisions 

independently, the utility power sector is unique in that 

electricity system resources operate in a complex, 

interconnected grid system that is physically interconnected and 

operated on an integrated basis across large regions. 

 

103 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). In an amicus brief to 

the Supreme Court, a group of electrical engineers, economists, 

and physicists specializing in electricity explained, “Energy is 

transmitted, not electrons. Energy transmission is accomplished 

through the propagation of an electromagnetic wave. The 

electrons merely oscillate in place, but the energy – the 

electromagnetic wave – moves at the speed of light. The 

energized electrons making the lightbulb in a house glow are not 

the same electrons that were induced to oscillate in the 

generator back at the power plant. . . . Energy flowing onto a 

power network or grid energizes the entire grid, and consumers 

then draw undifferentiated energy from that grid. A networked 

grid flexes, and electric current flows, in conformity with 

physical laws, and those laws do not notice, let alone conform 

to, political boundaries. . . . The path taken by electric 

energy is the path of least resistance . . . or, more 

accurately, the paths of least resistance. . . . If a generator 

on the grid increases its output, the current flowing from the 

generator on all paths on the grid increases. These increases 

affect the energy flowing into each point in the network, which 

in turn leads to compensating and corresponding changes in the 

energy flows out of each point.” Brief Amicus Curiae of 

Electrical Engineers, Energy Economists and Physicists in 

Support of Respondents at 2, 8-9, 11, New York v. FERC, 535 U.S. 

1 (2001) (No. 00-568).
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Additionally, a federal, state, and local regulatory network 

oversees policies and practices that are applied to how the 

system is designed and operates. In this interconnected system, 

system operators must ensure that the amount of electricity 

available is precisely matched with the amount needed in real 

time. System operators have a number of resources potentially 

available to meet electricity demand, including electricity 

generated by electric generation units such as coal, nuclear, 

renewables, and natural gas, as well as demand-side resources104, 

such as energy efficiency105 and demand response.106 Generation, 

outages, and transmission changes in one part of the synchronous 

 

104 “Measures using demand-side resources comprise actions taken 

on the customer’s side of the meter to change the amount and/or 

timing of electricity use in ways that will provide benefits to 

the electricity supply system.” David Crossley, Regulatory 

Assistance Project (RAP), Effective Mechanisms to Increase the 

Use of Demand-Side Resources, at 9 (2013), available at

www.raponline.org. 

105 Energy efficiency is using less energy to provide the same or 

greater level of service. Demand-side energy efficiency refers 

to an extensive array of technologies, practices and measures 

that are applied throughout all sectors of the economy to reduce 

energy demand while providing the same, and sometimes better, 

level and quality of service. 

106 Demand response involves “[c]hanges in electric usage by 

demand-side resources from their normal consumption patterns in 

response to changes in the price of electricity over time, or to 

incentive payments designed to induce lower electricity use at 

times of high wholesale market prices or when system reliability 

is jeopardized.” Federal Energy Regulatory Commission, Reports 

on Demand Response & Advanced Metering, (Dec. 23, 2014), 

available at http://www.ferc.gov/industries/electric/indusact/demand-response/dem-res-adv-metering.asp. 
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grid can affect the entire interconnected grid.107 The 

interconnection is such that “[i]f a generator is lost in New 

York City, its affect is felt in Georgia, Florida, Minneapolis, 

St. Louis, and New Orleans.”108 The U.S. Supreme Court has 

similarly recognized the interconnected nature of the 

electricity grid.109 

Today, federal, state, and local entities regulate 

electricity providers.110 Overlaid on the physical electricity 

 

107 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). 108 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 160 (2d ed. 2010). 109 Federal Power Comm’n v. Florida Power & Light Co., 404 U.S. 

453, at 460 (1972) (quoting a Federal Power Commission hearing 

examiner, "`If a housewife in Atlanta on the Georgia system 

turns on a light, every generator on Florida’s system almost 

instantly is caused to produce some quantity of additional 

electric energy which serves to maintain the balance in the 

interconnected system between generation and load.’”) (citation 

omitted). See also New York v. FERC, 535 U.S. 1, at 7 (2002) 

(stating that “any electricity that enters the grid immediately 

becomes a part of a vast pool of energy that is constantly 

moving in interstate commerce.”) (citation omitted). In Federal 

Power Comm’n v. Southern California Edison Co., 376 U.S. 205 

(1964), the Supreme Court found that a sale for resale of 

electricity from Southern California Edison to the City of 

Colton, which took place solely in California, was under Federal 

Power Commission jurisdiction because some of the electricity 

that Southern California Edison marketed came from out of state. 

The Supreme Court stated that, “`federal jurisdiction was to 

follow the flow of electric energy, an engineering and 

scientific, rather than a legalistic or governmental, test.’” 

Id. at 210 (quoting Connecticut Light & Power Co. v. Federal 

Power Commission, 324 U.S. 515, 529 (1945) (emphasis omitted)). 110 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010).
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network is a regulatory network that has developed over the last 

century or more. This regulatory network “plays a vital role in 

the functioning of all other networks, sometimes providing 

specific rules for functioning while at other times providing 

restraints within which their operation must be conducted.”111 

This unique regulatory network results in an electricity grid 

that is both physically interconnected and connected through a 

network of regulation on the local, state, and federal levels. 

This regulation seeks to reconcile the fact that electricity is 

a public good with the fact that facilities providing that 

electricity are privately owned.112 While this regulation began 

on the state and local levels, federal regulation of the 

electricity system increased over time. With the passage of the 

EPAct 1992 and the EPAct 2005, the federal government’s role in 

electricity regulation greatly increased.113 “The role of the 

regulator now includes support for the development of open and 

fair wholesale electric markets, ensuring equal access to the 

 

111 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 213 (2d ed. 2010). 112 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 213 (2d ed. 2010). 113 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010).
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transmission system and more hands-on oversight and control of 

the planning and operating rules for the industry.”114 

2. Electric system dispatch 

System operators typically dispatch the electric system 

through a process known as Security Constrained Economic 

Dispatch.115 Security Constrained Economic Dispatch has two 

components – economic generation of generation facilities and 

ensuring that the electric system remains reliable.116

Electricity demand varies across geography and time in response 

to numerous conditions, such that electric generators are 

constantly responding to changes in the most reliable and costeffective manner possible. The cost of operating electric 

generation varies based on a number of factors, such as fuel and 

generator efficiency. 

 

114 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010). 115 Economic Dispatch: Concepts, Practices and Issues, FERC Staff 

Presentation to the Joint Board for the Study of Economic 

Dispatch, Palm Springs, California (Nov. 13, 2005). 

116 Federal Energy Regulatory Commission, Security Constrained 

Economic Dispatch: Definitions, Practices, Issues and 

Recommendations: A Report to Congress (July 31, 2006). The 

Energy Policy Act of 2005 defined economic dispatch as “the 

operation of generation facilities to produce energy at the 

lowest cost to reliably serve consumers, recognizing any 

operational limits of generation and transmission facilities.” 

Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 

(2005), section 1234(b). 
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 The decision to dispatch any particular electric generator 

depends upon the relative operating cost, or marginal cost, of 

generating electricity to meet the last increment of electric 

demand. Fuel is one common variable cost – especially for 

fossil-fueled generators. Coal plants will often have 

considerable variable costs associated with running pollution 

controls.117 Renewables, hydroelectric, and nuclear have little 

to no variable costs. If electricity demand decreases or 

additional generation becomes available on the system, this 

impacts how the system operator will dispatch the system. EGUs 

using technologies with relatively low variable costs, such as 

nuclear units and RE, are for economic reasons generally 

operated at their maximum output whenever they are available. 

When lower cost units are available to run, higher variable cost 

units, such as fossil-fuel generators, are generally the first 

to be displaced. 

 In states with cost-of-service regulation of verticallyintegrated utilities, the utilities themselves form the 

balancing authorities who determine dispatch based upon the 

lowest marginal cost. These utilities sometimes arrange to buy 

and sell electricity with other balancing authorities. RTOs and 

 

117 Variable costs also include costs associated with operation 

and maintenance and costs of operating a pollution control 

and/or emission allowance charges. 
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ISOs coordinate, control, and monitor electricity transmission 

systems to ensure cost-effective and reliable delivery of power, 

and they are independent from market participants. 

3. Reliability considerations 

The reliability of the electric system has long been a 

focus of the electric industry and regulators. Industry 

developed a voluntary organization in the early 1960s that 

assisted with bulk power system coordination in the U.S. and 

Canada.118 In 1965, the northeastern U.S. and southeastern 

Ontario, Canada experienced the largest power blackout to date, 

impacting 30 million people.119 In response to the 1965 blackout 

and a Federal Power Commission recommendation,120 industry 

developed the National Electric Reliability Council (NERC) and 

nine reliability councils. The organization later became known 

as the North American Electric Reliability Council to recognize 

 

118 North American Electric Reliability Corporation, History of 

NERC, at 1 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 

119 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 39 (2012), available at

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

120 The Federal Power Commission, a precursor to FERC, 

recommended “the formation of a council on power coordination 

made up of representatives from each of the nation’s regional 

coordinating organizations, to exchange and disseminate 

information and to review, discuss and assist in resolving 

interregional coordination matters.” North American Electric 

Reliability Corporation, History of NERC, at 1 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 
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Canada’s participation.121 The North American Electric 

Reliability Council became the North American Electric 

Reliability Corporation in 2007.122 

In August 2003, North America experienced its worst 

blackout to date creating an outage in the Midwest, Northeast, 

and Ontario, Canada.123 This blackout was massive in scale 

impacting an area with an estimated 50 million people and 61,800 

megawatts of electric load.124 The U.S. and Canada formed a joint 

task force to investigate the causes of the blackout and made 

recommendations to avoid similar outages in the future. One of 

the task force’s major recommendations was that the U.S. 

 

121 North American Electric Reliability Corporation, History of 

NERC, at 2 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

122 North American Electric Reliability Corporation, History of 

NERC, at 4 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

123 North American Electric Reliability Corporation, History of 

NERC, at 3 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

124 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 1 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. The outage impacted areas 

within Ohio, Michigan, Pennsylvania, New York, Vermont, 

Massachusetts, Connecticut, New Jersey, and the Canadian 

province of Ontario. Id. 
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Congress should pass legislation making electric reliability 

standards mandatory and enforceable.125

Congress responded to this recommendation in EPAct 2005, 

adding a new section 215 to the Federal Power Act making 

reliability standards mandatory and enforceable and authorizing 

the creation of a new Electric Reliability Organization (ERO). 

Under this new system, FERC certifies an entity as the ERO. The 

ERO develops reliability standards, which are subject to FERC 

review and approval. Once FERC approves reliability standards 

the ERO may enforce those standards or FERC can do so 

independently.126 In 2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as the ERO.127 “NERC develops 

and enforces Reliability Standards; monitors the Bulk-Power 

System; assesses adequacy annually via a 10-year forecast and 

 

125 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 2 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 126 Mandatory Reliability Standards for the Bulk-Power System, 

Order No. 693, 118 FERC ¶ 61,218, at P 3 (2007) (citing 16 

U.S.C. 824o(e)(3)). 

127 Rules Concerning Certification of the Electric Reliability 

Organization; and Procedures for the Establishment, Approval, 

and Enforcement of Electric Reliability Standards, Order No. 

672, 114 FERC ¶ 61,104 (2006). 
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winter and summer forecasts; audits owners, operators and users 

for preparedness; and educates and trains industry personnel.”128

The United States, Canada, and part of Mexico are divided 

up into eight reliability regional entities.129 These regional 

entities include Florida Reliability Coordinating Council 

(FRCC), Midwest Reliability Organization (MRO), Northeast Power 

Coordinating Council (NPCC), Reliability First Corporation 

(RFC), SERC Reliability Corporation (SERC), Southwest Power 

Pool, RE (SPP), Texas Reliability Entity (TRE), and Western 

Electricity Coordinating Council (WECC).130 Regional entity 

members come from all segments of the electric industry.131 NERC 

delegates authority, with FERC approval, to these regional 

entities to enforce reliability standards, both national and 

 

128 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 2 (Aug. 2013), available at

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 

129 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 49-50 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

130 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 50 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

131 North American Electric Reliability Corporation, Key Players, 

available at

http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx 

(last visited Mar. 12, 2015). “The members of the regional 

entities come from all segments of the electric industry: 

investor-owned utilities; federal power agencies; rural electric 

cooperatives; state, municipal and provincial utilities; 

independent power producers; power marketers; and end-use 

customers.” Id. 
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regional reliability standards, and engage in other standardsrelated duties delegated to them by NERC.132 NERC ensures that 

there is a consistency of application of delegated functions 

with appropriate regional flexibility.133 NERC divides the 

country into assessment areas and annually analyzes the 

reliability, adequacy, and associated risks that may affect the 

upcoming summer, winter, and long-term, 10-year period. Multiple 

other entities such as FERC, the Department of Energy, state 

public utility commissions, ISOs/RTOs134, and other planning 

 

132 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 

For example, a regional entity may propose reliability 

standards, including regional variances or regional reliability 

standards required to maintain and enhance electric service 

reliability, adequacy, and security in the region. See, e.g.,

Amended and Restated Delegation Agreement Between North American 

Reliability Corporation and Midwest Reliability Organization, 

Bylaws of the Midwest Reliability Organization, Inc., Section 

2.2 (2012), available at

http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agr

eements%20DL/MRO_RDA_Effective_20130612.pdf. 

133 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.

134 ISOs/RTOs plan for system needs by “effectively managing the 

load forecasting, transmission planning, and system and resource 

planning functions.” For example, the New York Independent 

System Operator (NYISO) conducts reliability planning studies, 

which “are used to assess current reliability needs based on 

user trends and historical energy use.” NYISO, Planning Studies, 

available at

http://www.nyiso.com/public/markets_operations/services/planning

/planning_studies/index.jsp. See also PJM, Reliability 

Assessments, available at https://www.pjm.com/planning/rtep-
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authorities also consider the reliability of the electric 

system. There are numerous remedies that can be utilized to 

solve a potential reliability problem, including long-term 

planning, transmission system upgrades, installation of new 

generating capacity, demand response, and other demand side 

actions. 

4. Modern electric system trends 

 Today, the electricity sector is undergoing a period of 

intense change. Fossil fuels – such as coal, natural gas, and 

oil – have historically provided a large percentage of 

electricity in the U.S., along with nuclear power, with smaller 

amounts provided by other types of generation, including 

renewables such as wind, solar, and hydroelectric power. Coal 

provided the largest percentage of the fossil fuel generation.135

In recent years, the nation has seen a sizeable increase in 

renewable generation such as wind and solar, as well as a shift 

 

development/reliability-assessments.aspx (stating that the PJM 

“Regional Transmission Expansion Planning (RTEP) process 

includes the development of periodic reliability assessments to 

address specific system reliability issues in addition to the 

ongoing expansion planning process for the interconnection 

process of generation and merchant transmission.”). 

135 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

Deleted: nuclear, and 
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from coal to natural gas.136 In 2013, fossil fuels supplied 67 

percent of U.S. electricity,137 but the amount of renewable 

generation capacity continued to grow.138 From 2007 to 2014, use 

of lower- and zero-carbon energy sources such as wind and solar 

grew, while other major energy sources such as coal and 

petroleum generally experienced declines.139 Renewable 

electricity generation, including from large hydro-electric 

projects, grew from 8 percent to 13 percent over that time 

 

136 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, release data April 25, 2014, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

137 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, release data April 25, 2014, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

138 Based on Table 6.3 (New Utility Scale Generating Units by 

Operating Company, Plant, Month, and Year) of the U.S. Energy 

Information Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable energy sources: 

solar, wind, hydro, geothermal, landfill gas, and biomass. 

Available at: http:// 

www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_0

3. 

139 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015).
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period.140 Between 2000 and 2013, approximately 90 percent of new 

power generation capacity built in the U.S. came in the form of 

natural gas or renewable energy facilities.141 In 2015, the U.S. 

Energy Information Administration (EIA) projected the need for 

28.4 GW of additional base load or intermediate load generation 

capacity through 2020.142 The vast majority of this new electric 

capacity (20.4 GW) is already under development (under 

construction or in advanced planning), with approximately 0.7 GW 

of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 

14.2 GW of new NGCC capacity already in development. 

While the change in the resource mix has accelerated in 

recent years, wind, solar, other renewables, and energy 

efficiency resources have been reliably participating in the 

electric sector for a number of years. This rapid development of 

non-fossil fuel resources is occurring as much of the existing 

 

140 Bloomberg New Energy Finance and the Business Council for 

Sustainable Energy, 2015 Factbook: Sustainable Energy in 

America, at 16 (2015), available at

http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20Am

erica%20Factbook.pdf. Bloomberg gave projections for 2014 

values, accounting for seasonality, based on latest monthly 

values from EIA (data available through October 2014). 

141 Energy Information Administration, Electricity: Form EIA-860 

detailed data (Feb. 17, 2015), available at

http://www.eia.gov/electricity/data/eia860/. 

142 EIA, Annual Energy Outlook for 2015 with Projections to 2040, 

Final Release, available at

http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEO 

numbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.
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power generation fleet in the U.S. is aging and in need of 

modernization and replacement. In 2025, the average age of the 

coal-fired generating fleet is projected to be 49 years old, and 

20 percent of those units would be more than 60 years old if 

they remain in operation at that time. In its 2013 Report Card 

for America’s Infrastructure, the American Society for Civil 

Engineers noted that “America relies on an aging electrical grid 

and pipeline distribution systems, some of which originated in 

the 1880s.”144 While there has been an increased investment in 

electric transmission infrastructure since 2005, the report also 

found that “ongoing permitting issues, weather events, and 

limited maintenance have contributed to an increasing number of 

failures and power interruptions.”145 However, innovative 

technologies have increasingly entered the electric energy 

space, helping to provide new answers to how to meet the 

electricity needs of the nation. These new technologies can 

enable the nation to answer not just questions as to how to 

reliably meet electricity demand, but also how to meet 

 

144 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 

145 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 

Deleted: For example, the average age of U.S. 

coal steam units in 2015 is 45.143
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electricity demand reliably and cost-effectively with the lowest 

possible emissions and the greatest efficiency. 

Natural gas has a long history of meeting electricity 

demand in the U.S., with a rapidly growing role as domestic 

supplies of natural gas have dramatically increased. Natural gas 

net generation increased by approximately 32 percent between 

2005 and 2014.146 In 2014, natural gas accounted for 

approximately 27 percent of net generation.147 EIA projects that 

this demand growth will continue with its Annual Energy Outlook 

2015 (AEO 2015) Reference case forecasting that natural gas will 

produce 31 percent of U.S. electric generation in 2040.148 

Renewable sources of electric generation also have a 

history of meeting electricity demand in the United States and 

 

146 U.S. Energy Information Administration (EIA), Electric Power 

Monthly: Table 1.1 Net Generation by Energy Source: Total (All 

Sectors), 2005-February 2015 (2015), available at

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e

pmt_1_1 (last visited May 26, 2015). 

147 Id. 148 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2015 with Projections to 2040, at 24-25 (2015), 

available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. According 

to the EIA, the reference case assumes, “Real gross domestic 

product (GDP) grows at an average annual rate of 2.4% from 2013 

to 2040, under the assumption that current laws and regulations 

remain generally unchanged throughout the projection period. 

North Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 

dollars) in 2040.” Id. at 1. The EIA provides complete 

projection tables for the reference case in Appendix A of its 

report. 
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are expected to have an increasing role going forward. A series 

of energy crises provided the impetus for renewable energy 

development in the early 1970s. The OPEC oil embargo in 1973 and 

oil crisis of 1979 caused oil price spikes, more frequent energy 

shortages, and significantly affected the national and global 

economy. In 1978, partly in response to fuel security concerns, 

Congress passed the Public Utilities Regulatory Policies Act 

(PURPA) which required local electric utilities to buy power 

from qualifying facilities (QFs).149 QFs were either cogeneration 

facilities150 or small generation resources that use renewables 

such as wind, solar, biomass, geothermal, or hydroelectric power 

as their primary fuels.151 Through PURPA, Congress supported the 

development of more renewable energy generation in the U.S. 

States have also taken a significant lead in requiring the 

development of renewable resources. In particular, a number of 

states have adopted renewable portfolio standards (RPS). As of 

 

149 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010). 150 Cogeneration facilities utilize a single source of fuel to 

produce both electricity and another form of energy such as heat 

or steam. Casazza, J. and Delea, F., Understanding Electric 

Power Systems, IEEE Press, at 220-221 (2d ed. 2010). 151 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010). 
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2013, 29 states and the District of Columbia have enforceable 

RPS or similar laws.152 

Use of RE continues to grow rapidly in the U.S. In 2013, 

electricity generated from renewable technologies, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity, up from 9 percent in 2005.153 In 2013, U.S. nonhydro RE capacity for the total electric power industry exceeded 

80,000 MW, reflecting a fivefold increase in just 15 years.154 In 

particular, there has been substantial growth in the wind and 

photovoltaic (PV) markets in the past decade. Since 2009, U.S. 

wind generation has tripled and solar generation has grown 

twenty-fold.155 

 

152 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2014 with Projections to 2040, at LR-5 (2014), available 

at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf (last 

visited May 26, 2015). 

153 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2014) and Energy Information 

Administration, Monthly Energy Review, May 2015, Table 7.2b, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 

154 Non-hydro RE capacity for the total electric power industry 

was more than 16,000 megawatts (MW) in 1998. Energy Information 

Administration, 1990-2013 Existing Nameplate and Net Summer 

Capacity by Energy Source Producer Type and State (EIA-860), 

available at http://www.eia.gov/electricity/data/state/. 155 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 
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 The global market for RE is projected to grow to $460 

billion per year by 2030.156 RE growth is further encouraged by 

the significant amount of existing natural resources that can 

support RE production in the United States.157 In the Energy 

Information Administration’s Annual Energy Outlook 2015, RE 

generation grows substantially from 2013 to 2040 in the 

reference case and all alternative cases.158 In the reference 

case, RE generation increases by more than 70 percent from 2013 

to 2040 and accounts for over one-third of new generation 

capacity.159

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and energy efficiency to the 

forefront of U.S. energy policy.160 This trend continued in the 

 

156 “Global Renewable Energy Market Outlook.” Bloomberg New Energy 

Finance (Nov. 16, 2011), available at 

http://bnef.com/WhitePapers/download/53.

157 Lopez et al., NREL, ‘‘U.S. Renewable Energy 

Technical Potentials: A GIS-Based Analysis,’’ (July 2012).

158 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at 25 (2014), available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 

159 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2015), available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last 

visited May 27, 2015).

160 Edison Electric Institute, Making a Business of Energy 

Efficiency: Sustainable Business Models for Utilities, at 1 

(2007), available at

http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation

/Documents/Making_Business_Energy_Efficiency.pdf. Congress 

passed legislation in the 1970s that jumpstarted energy 
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early 1990s. Energy efficiency has been utilized to meet energy 

demand to varying levels since that time. As of April 2014, 25 

states161 have “enacted long-term (3+ years), binding energy 

savings targets, or energy efficiency resource standards 

(EERS).”162 Funding for energy efficiency programs has grown 

rapidly in recent years, with budgets for electric efficiency 

programs totaling $5.9 billion in 2012.163 

 Advancements and innovation in power sector technologies 

provide the opportunity to address CO2 emission levels at 

 

efficiency in the U.S. For example, President Ford signed the 

Energy Policy and Conservation Act (EPCA) of 1975 – the first 

law on the issue. EPCA authorized the Federal Energy 

Administration (FEA) to “develop energy conservation contingency 

plans, established vehicle fuel economy standards, and 

authorized the creation of efficiency standards for major 

household appliances.” Alliance to Save Energy, History of 

Energy Efficiency, at 6 (2013) (citing Anders, “The Federal 

Energy Administration,” 5; Energy Policy and Conservation Act, 

S. 622, 94th Cong. (1975-1976)), available at

https://www.ase.org/sites/ase.org/files/resources/Media%20browse

r/ee_commission_history_report_2-1-13.pdf. 

161 American Council for an Energy-Efficient Economy, State 

Energy Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE 

did not include Indiana (EERS eliminated), Delaware (EERS 

pending), Florida (programs funded at levels far below what is 

necessary to meet targets), Utah, or Virginia (voluntary 

standards) in its calculation. 

162 American Council for an Energy-Efficient Economy, State 

Energy Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. 

163 American Council for an Energy-Efficient Economy, The 2013 

State Energy Efficiency Scorecard, at 17 (Nov. 2013), available 

at

http://aceee.org/sites/default/files/publications/researchreport

s/e13k.pdf. 
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affected power plants while at the same time improving the 

overall power system in the U.S. by lowering the carbon 

intensity of power generation, and ensuring a reliable supply of 

power at a reasonable cost. 

E. Clean Air Act Regulations for Power Plants 

In this section, we provide a general description of major 

CAA regulations for power plants. We refer to these in later 

sections of this preamble. 

1. Title IV Acid Rain Program 

The EPA’s Acid Rain Program, established in 1990 under 

Title IV of the CAA, addresses the presence of acidic compounds 

and their precursors (i.e., SO2 and NOx), in the atmosphere by 

targeting “the principal sources” of these pollutants through an 

SO2 cap-and-trade program for fossil-fuel fired power plants and 

through a technology based NOx emission limit for certain utility 

boilers. Altogether, Title IV was designed to achieve reductions 

of ten million tons of annual SO2 emissions, and, in combination 

with other provisions of the CAA, two million tons of annual NOx

emissions.164 

 The SO2 cap-and-trade program was implemented in two phases. 

The first phase, beginning in 1995, targeted one-hundred and ten 

named power plants, including specific generator units at each 

 

164 42 U.S.C. § 7651(b). 

Deleted: D
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plant, requiring the plants to reduce their cumulative emissions 

to a specific level.165 Under certain conditions, the owner or 

operator of a named power plant could reassign an affected 

unit’s reduction requirement to another unit and/or request an 

extension of two years for meeting the requirement.166 Congress 

also established an energy conservation and renewable energy 

reserve from which up to 300,000 allowances could be allocated 

for qualified energy conservation measures or qualified 

renewable energy.167 

The second phase, beginning in 2000, expanded coverage to 

more than 2,000 generating units and set a national cap at 8.90 

million tons.168 Generally, allowances were allocated at a rate 

of 1.2 lbs./mmBtu multiplied by the unit’s baseline and divided 

by 2000.169 However, bonus allowances could be awarded to certain 

units. 

Title IV also required the EPA to hold or sponsor annual 

auctions and sales of allowances for a small portion of the 

total allowances allocated each year. This ensured that some 

 

165 42 U.S.C. § 7651c (Table A). 166 42 U.S.C. § 7651c(b) and (d). 167 42 U.S.C. § 7651c(f) and (g). 168 U.S. Dept. of Energy, Energy Information Administration, “The 

Effects of Title IV of the Clean Air Act Amendments of 1990 on 

Electric Utilities: An Update,” p. vii. (March 1997). 

169 See 42 U.S.C. § 7651d. 
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allowances would be directly available for new sources, 

including independent power production facilities.170 

The provisions of the EPA’s Acid Rain Program are 

implemented through permits issued under the EPA’s Title V 

Operating Permit Program.171 In accordance with Title IV, 

moreover, each Title V permit application must include a 

compliance plan for the affected source that details how that 

source expects to meet the requirements of Title IV.172 

2. Transport rulemakings 

CAA section 110(a)(2)(D)(i)(I), the “Good Neighbor 

Provision,” requires state implementation plans (SIPs) to 

prohibit emissions that “contribute significantly to 

nonattainment . . . or interfere with maintenance” of the NAAQS 

in any other state.173 If the EPA finds that a state has failed 

to submit an approvable SIP, the EPA must issue a federal 

 

170 42 U.S.C. § 7651o. 171 42 U.S.C. § 7651g. 172 Such plans may simply state that the owner or operator 

expects to hold sufficient allowances or, in the case of 

alternative compliance methods, must provide a “comprehensive 

description of the schedule and means by which the unit will 

rely on one or more alternative methods of compliance in the 

manner and time authorized under [Title IV].” 42 U.S.C. § 

7651g(b). 

173 42 U.S.C. § 7410(a)(2)(D)(i)(I). 
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implementation plan (FIP) to prohibit those emissions “at any 

time” within the next two years.174

In three major rulemakings—the NOx SIP Call,175 the Clean 

Air Interstate Rule (CAIR),176 and the Cross State Air Pollution 

Rule (CSAPR)177—the EPA has attempted delineate the scope of the 

Good Neighbor Provision. These rulemakings have several features 

in common. Although the Good Neighbor Provision does not speak 

specifically about EGUs, in all three rulemakings, the EPA set 

state emission “budgets” for upwind states based in part on 

emissions reductions achievable by EGUs through application of 

cost-effective controls. Each rule also adopted a phased 

approach to reducing emissions with both interim and final 

goals. 

a. NOx SIP Call. In 1998, the EPA promulgated the NOx SIP Call, 

which required 23 upwind states to reduce emissions of NOx that 

would impact downwind areas with ozone problems. The EPA 

determined emission reduction requirements based on reductions 

achievable through “highly cost-effective” controls—i.e., 

controls that would cost on average no more than $2,000 per ton 

 

174 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 

1600–01 (2014) (citing 42 U.S.C. § 7410(c)). 

175 63 FR 57356 (Oct. 27, 1998). 176 70 FR 25162 (May 12, 2005). 177 76 FR 48208 (Aug. 8, 2011). 
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of emissions reduced.178 The EPA determined that a uniform 

emission rate on large EGUs coupled with a cap-and-trade program 

was one such set of highly cost-effective controls.179 

Accordingly, the EPA established an interstate cap-and-trade 

program—the NOx Budget Trading Program—as a mechanism for states 

to reduce emissions from EGUs and other sources in a highly 

cost-effective manner. The D.C. Circuit upheld the NOx SIP Call 

in most significant respects, including its use of costs to 

apportion emission reduction responsibilities.180 

b. Clean Air Interstate Rule (CAIR). In 2005, the EPA 

promulgated CAIR, which required 28 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

on “controls that are known to be highly cost effective for 

EGUs.”181 The EPA established cap-and-trade programs for sources 

of NOx and SO2 in states that chose to participate in the trading 

programs via their SIPs and for states ultimately subject to a 

 

178 63 FR at 57377–78. 179 63 FR at 57377–78. In addition to EGUs, the NOx SIP Call also 

set budgets based on highly cost-effective emission reductions 

from certain other large sources. Id. 180 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). 181 70 FR at 25163. 
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FIP.182 As relevant here, the D.C. Circuit remanded CAIR in North 

Carolina v. EPA due to in part the structure of its interstate 

trading provisions and the way in which EPA applied the costeffective standard, but kept the rule in place while the EPA 

developed an acceptable substitute.183

c. Cross-state Air Pollution Rule (CSAPR). In 2011, the EPA 

promulgated CSAPR, which required 27 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

in part on the reductions achievable at certain cost thresholds 

by EGUs in each state, with certain provisions developed to 

account for the need to ensure reliability of the electric 

generating system.184 In the same action establishing these 

emission reduction requirements, the EPA promulgated FIPs that 

subjected states to trading programs developed to achieve the 

necessary reductions within each state.185 The U.S. Supreme Court 

 

182 70 FR at 25273–75; 71 FR 25328 (April 28, 2006). 183 531 F.3d 896, 917–22 (D.C. Cir. 2008), modified on rehearing 

550 F.3d 1176, 1178 (D.C. Cir. 2008). 

184 76 FR at 48270. The EPA adopted this approach in part to 

comport with the D.C. Circuit’s opinion in North Carolina v. EPA 

remanding CAIR. Id. at 48270–71. 185 76 FR at 48209–16. 
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upheld the EPA’s use of cost to set emission reduction 

requirements, as well as its authority to issue the FIPs.186 

3. Clean Air Mercury Rule 

On March 15, 2005, the EPA issued a rule to control mercury 

(Hg) emissions from new and existing fossil fuel-fired power 

plants under CAA section 111(b) and (d). The rule, known as the 

Clean Air Mercury Rule (CAMR), established, in relevant part, a 

nationwide cap-and-trade program under CAA section 111(d), which 

was designed to complement the cap-and-trade program for SO2 and 

NOx emissions under the Clean Air Interstate Rule (CAIR), 

discussed above.187 Though CAMR was later vacated by the D.C. 

Circuit on account of the EPA’s flawed CAA section 112 delisting 

rule, the court declined to reach the merits of the EPA’s 

interpretation of CAA section 111(d).188 Accordingly, CAMR 

continues to be an informative model for a cap-and-trade program 

under CAA section 111(d). 

The cap-and-trade program in CAMR was designed to take 

effect in two phases: in 2010, the cap was set at 38 tons per 

year, and in 2018, the cap would be lowered to 15 tons per year. 

The Phase I cap was set at a level reflecting the co-benefits of 

 

186 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 

(2014).

187 See 70 F.R. 28606 (May 18, 2005). 188 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). 
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CAIR as determined through economic and environmental 

modeling.189 For the more stringent Phase II cap, the EPA 

projected that sources would “install SCR [selective catalytic 

reduction] to meet their SO2 and NOx requirements and take 

additional steps to address the remaining Hg reduction 

requirements under CAA section 111, including adding Hg-specific 

control technologies (model applies ACI [activated carbon 

injection]), additional scrubbers and SCR, dispatch changes, and 

coal switching.”190 

To accompany the nationwide emissions cap, the EPA also 

assigned a statewide emissions budget for mercury. Pursuant to 

CAA section 111(d), states would be required to submit plans to 

the EPA “detailing the controls that will be implemented to meet 

its specified budget for reductions from coal-fired Utility 

Units.”191 Of course, states were “not required to adopt and 

implement” the emission trading program, “but they [were] 

 

189 70 F.R. 28606, at 28617. The EPA’s projections under CAIR 

showed a significant number of affected sources would install 

scrubbers for SO2 and selective catalytic reduction for NOx on 

coal-fired power plants, which had the co-benefit of capturing 

mercury emissions. Id. at 28619. 190 70 F.R. 28606, at 28619. 191 70 F.R. 28606, at 28621. 
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required to be in compliance with their statewide Hg emission 

budget.”192 

4. Mercury Air Toxics Rule 

On February 16, 2012, the EPA issued the MATS rule (77 FR 

9304) to reduce emissions of toxic air pollutants from new and 

existing coal- and oil-fired EGUs. The MATS rule will reduce 

emissions of heavy metals, including mercury, arsenic, chromium, 

and nickel; and acid gases, including hydrochloric acid and 

hydrofluoric acid. These toxic air pollutants, also known as 

hazardous air pollutants or air toxics, are known to cause, or 

suspected of causing, damage nervous system damage, cancer, and 

other serious health effects. The MATS rule will also reduce SO2

and fine particle pollution, which will reduce particle 

concentrations in the air and prevent thousands of premature 

deaths and tens of thousands of heart attacks, bronchitis cases 

and asthma episodes. 

New or reconstructed EGUs (i.e., sources that commence 

construction or reconstruction after May 3, 2011) subject to the 

MATS rule are required to comply by April 16, 2012 or upon 

startup, whichever is later. 

 

192 70 F.R. 28606, at 28621. That said, states could “require 

reductions beyond those required by the [s]tate budget.” Id. at 

28621. 
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Existing sources subject to the MATS rule were required to 

begin meeting the rule’s requirements on April 16, 2015. 

Controls that will achieve the MATS performance standards are 

being installed on many units. Certain units, especially those 

that operate infrequently, may be considered not worth investing 

in given today’s electricity market, and are closing. The final 

MATS rule provided a foundation on which states and other 

permitting authorities could rely in granting an additional, 

fourth year for compliance provided for by the CAA. States 

report that these fourth year extensions are being granted. In 

addition, the EPA issued an enforcement policy that provides a 

clear pathway for reliability-critical units to receive an 

administrative order that includes a compliance schedule of up 

to an additional year, if it is needed to ensure electricity 

reliability.

Following promulgation of the MATS rule, industry, states 

and environmental organizations challenged many aspects of the 

EPA's threshold determination that regulation of EGUs is 

"appropriate and necessary" and the final standards regulating 

hazardous air pollutants from EGUs. The U.S. Court of Appeals 

for the D.C. Circuit upheld all aspects of the MATS rule. White 

Stallion Energy Center v. EPA, 748 F.3d 1222 (D.C. Cir. 

2014). In Michigan v. EPA, case no. 14-46, the U.S. Supreme 
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Court reversed the D.C. Circuit decision upholding the MATS 

rule, finding that EPA erred by not considering cost when 

determining that regulation of EGUs was "appropriate" pursuant 

to section 112(n)(1). The Supreme Court considered only the 

narrow question of cost and did not review the other holdings 

of the D.C. Circuit, nor did the Supreme Court vacate the MATS 

rule. 

5. Regional Haze Rule 

Under CAA section 169A, Congress “declare[d] as a national 

goal the prevention of any future, and the remedying of any 

existing, impairment of visibility” in national parks and 

wilderness areas that results from anthropogenic emissions.193 To 

achieve this goal, Congress directed the EPA to promulgate 

regulations directing states to submit SIPs that “contain such 

emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress toward meeting the 

national goal . . . .”194 One such measure that Congress deemed 

necessary to make reasonable progress was a requirement that 

certain older stationary sources that cause or contribute to 

visibility impairment “procure, install, and operate, as 

expeditiously as practicable . . . the best available retrofit 

 

193 42 U.S.C. § 7491(a)(1). 194 42 U.S.C. § 7491(b)(2). 
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technology,” more commonly referred to as BART.195 When 

determining BART for large fossil-fuel fired utility power 

plants, Congress required states to adhere to guidelines to be 

promulgated by the EPA.196 As with other SIP-based programs, the 

EPA is required to issue a FIP within two years if a state fails 

to submit a regional haze SIP or if the EPA disapproves such SIP 

in whole or in part.197

 In 1999, the EPA promulgated the Regional Haze Rule to 

satisfy Congress’ mandate that EPA promulgate regulations 

directing states to address visibility impairment.198 Among other 

things, the Regional Haze Rule allows states to satisfy the 

Act’s BART requirement either by adopting source-specific 

emission limitations or by adopting alternatives, such as 

emissions-trading programs, that achieve greater reasonable 

progress than would source-specific BART.199 The Ninth Circuit 

and D.C. Circuit have both upheld the EPA’s interpretation that 

CAA section 169A(b)(2) allows for BART alternatives in lieu of 

source-specific BART.200 In 2005, the EPA promulgated BART 

 

195 42 U.S.C. § 7491(b)(2)(A). 196 42 U.S.C. § 7491(b)(2). 197 42 U.S.C. §§ 7410(c); 7491(b)(2)(A). 198 64 Fed. Reg. 35,714 (July 1, 1999) (codified at 40 C.F.R. §§ 

51.308-309). 

199 40 C.F.R. § 51.308(e)(1) & (2). 200 See Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 (D.C. 

Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 
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Guidelines to assist states in determining which sources are 

subject to BART and what emission limitations to impose at those 

sources.201

 The Regional Haze Rule set a goal of achieving natural 

visibility conditions by 2064 and requires states to revise 

their regional haze SIPs every ten years.202 The first planning 

period, which ends in 2018, focused heavily on the BART 

requirement. States (or the EPA in the case of FIPs) made 

numerous source-specific BART determinations, and developed 

several BART alternatives, for utility power plants. For the 

next planning period, states will need to determine whether 

additional controls are necessary at these plants (and others 

that were not subject to BART) in order to make reasonable 

progress towards the national visibility goal.203

F. Congressional Awareness of Climate Change in the Context of 

the Clean Air Act Amendments204 

 

2005); Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 

1993). 

201 70 Fed. Reg. 39,104 (July 6, 2005) (codified at 40 C.F.R. pt. 

51, app. Y). 

202 See 40 C.F.R. §§ 51.308(d)(1)(i)(B), (f). 203 See 42 U.S.C. § 7491(b)(2); 40 C.F.R. § 51.308(d)(3). 204 The following discussion is not meant to be exhaustive. There 

are many other instances outside the context of the CAA, before 

and after 1970, when Congress discussed or was presented with 

evidence on climate change.

Deleted: E

Deleted: Early Evidence of 

Deleted: ic

Deleted: CAA 

Deleted: ; indeed, t

Deleted: , including 

Deleted: where 
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During its deliberations on the 1970 Clean Air Act 

Amendments, Congress learned that ongoing pollution, including 

from manmade carbon dioxide, could “threaten irreversible 

atmospheric and climatic changes.”205 At that time, Congress 

heard the views of scientists that carbon dioxide emissions 

tended to increase global temperatures, but that there was 

uncertainty as to the extent to which those increases would be 

offset by the decreases in temperatures brought about by 

emissions of particulates. President Nixon’s Council on 

Environmental Quality (CEQ) reported that “the addition of 

particulates and carbon dioxide in the atmosphere could have 

dramatic and long-term effects on world climate.”206 The CEQ’s 

First Annual Report, which was transmitted to Congress, devoted 

a chapter to “Man’s Inadvertent Modification of Weather and 

Climate.”207 Moreover, Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service, testified 

 

205 Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 349.

206 Council on Environmental Quality, “The First Annual Report of 

the Council on Environmental Quality,” p. 110 (Aug. 1970) 

(recognizing also that “[man] can increase the carbon dioxide 

content of the atmosphere by burning fossil fuels” and 

postulating that an increase in the earth’s average temperature 

by about 2o to 3o F “could in a period of decades, lead to the 

start of substantial melting of ice caps and flooding of coastal 

regions.”). 

207 Council on Environmental Quality, “The First Annual Report of 

the Council on Environmental Quality,” p. 93-104 (Aug. 1970) 

Deleted: As early as 

Deleted: Likewise,

Deleted: In fact, t

Deleted: n entire

Deleted: even
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before the House Subcommittee on Public Health that “the carbon 

dioxide balance might result in the heating up of the atmosphere 

whereas the reduction of the radiant energy through particulate 

matter released to the atmosphere might cause reduction in 

radiation that reaches the earth.”208 Administrator Johnson 

explained that the Nixon Administration was “concerned ... that 

neither of these things happen” and that they were “watching 

carefully the kind of prognosis, the kind of calculations that 

the scientists make to look at the continuous balance between 

heat and cooling of the total earth’s atmosphere.”209 He 

concluded that “[w]hat we are trying to do, however, in terms of 

our air pollution effort should have a very salutary effect on 

either of these.”210

 

208 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 

209 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 

210 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 
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Scientific reports on climatic change continued to gain 

traction in Congress through the mid-1970s, including while 

Congress was considering the 1977 CAA Amendments. However, 

uncertainty continued as to whether the increased warming 

brought about by carbon dioxide emissions would be offset by 

cooling brought about by particulate emissions.211 Congress 

ordered, as part of the 1977 CAA Amendments, the National 

Oceanic and Atmospheric Administration to research and monitor 

the stratosphere “for the purpose of early detection of changes 

in the stratosphere and climatic effects of such changes.”212 

Between the 1977 and 1990 Clean Air Act Amendments, 

scientific uncertainty yielded to the predominant view that 

global warming “was likely to dominate on time scales that would 

 

211 For instance, while scientists, such as Stephen Schneider of 

the National Center for Atmospheric Research, testified that 

“manmade pollutants will affect the climate,” they believed that 

we would “see a general cooling of the Earth’s atmosphere.” Rep. 

Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA 

Legis. Hist. at 6477. Additionally, the Department of 

Transportation’s climatic impact assessment program and the 

Climatic Impact Committee of the National Research Council, 

National Academies of Science and Engineering both reported that 

“warming or cooling” could occur. Id. at 6476. See also Sen. 

Bumpers, Sen. Debates on S. 3219 (August 3, 1976), 1977 CAA 

Legis. Hist. at 5368 (inserting “Summary of Statements Received 

[in the Subcommittee on the Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of Chronic 

Pollution” into the record, which noted that “there is near 

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”). 

212 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728. 

Deleted: it was reported that science remained 

inconclusive as to the specific warming or 

cooling trends.

Deleted: In deference to that uncertainty, 

Deleted: By 1990 (if not by 1979), 

Deleted: appeared to 
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be significant to human societies.”213 In fact, as part of the 

1990 Clean Air Act Amendments, Congress specifically required 

the EPA to collect data on carbon dioxide emissions –- the most 

significant of the greenhouse gases -- from all sources subject 

to the newly enacted operating permit program under Title V.215

Although Congress did not require the EPA to take immediate 

action to address climate change, Congress did identify certain 

tools that were particularly helpful in addressing climate 

change in the utility power sector. The Senate report discussing 

the acid rain provisions of Title IV noted that some of the 

measures that would reduce coal-fired power plant emissions of 

the precursors to acid rain would also reduce those facilities’ 

emissions of carbon dioxide. The report stated: 

Energy efficiency is a crucial tool for controlling 

the emissions of carbon dioxide, the gas chiefly 

responsible for the intensification of the atmospheric 

‘greenhouse effect.’ In the last several years, the 

Committee has received extensive scientific testimony 

that increases in the human-caused emissions of carbon 

dioxide and other greenhouse gases will lead to 

catastrophic shocks in the global climate system. 

Accordingly, new title IV shapes an acid rain 

reduction policy that encourages energy efficiency and 

 

213 Peterson, Thomas C., William M. Connolley, and John Fleck, 

“The Myth of the 1970s Global Cooling Scientific Consensus,” 

Bulletin of the American Meteorological Society, p. 1326 

(September 2008), available at 

http://journals.ametsoc.org/doi/pdf/10.1175/2008BAMS2370.1. 

215 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 

Deleted: Nevertheless, some reports continued 

to present contrary views; thus, Congress 

perceived that “[s]cientists have disagreed 

about the scope and magnitude of global 

climate change from manmade air pollution, and 

much of that disagreement stems from lack of 

necessary data to assess the impact these 

emissions may have on the Earth’s climate.”214

Accordingly, i

Deleted: CAA 

Deleted: Congress explained that the CO2 data 

collection requirement “helps fill this 

information gap” and would “give us a head 

start if and when we need to take steps to 

reduce our carbon dioxide emissions.”216

Deleted: For instance, t

Deleted: “[e]

Deleted: ”
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other policies aimed at controlling greenhouse 

gases.217

Similarly, Title IV provisions to encourage renewable energy 

were justified because “renewables not only significantly 

curtail sulfur dioxide emissions, but they emit little or no 

nitrogen oxides and carbon dioxide”.218 

G. International Agreements and Actions 

In this final rule, the United States is taking action to 

limit GHGs from one of its largest emission sources. Climate 

change is a global problem, and the United States is not alone 

in taking action to address it. The United Nations Framework 

Convention on Climate Change (UNFCCC)219 is the international 

treaty under which countries (called “Parties”) cooperatively 

consider what can be done to limit anthropogenic climate 

change220 and adapt to climate change impacts. Currently, there 

 

217 Sen. Chaffe, Sen. Debate on S. 1630 (Jan. 24, 1990), 1990 CAA 

Legis. Hist. at 8662. 

218 Additional Views of Rep. Markey and Rep. Moorhead, H.R. Rep. 

No. 101-490, at 674 (May 17, 1990). 

219 http://unfccc.int/2860.php 220 Article 2, Objective, The ultimate objective of this 

Convention and any related legal instruments that the Conference 

of the Parties may adopt is to achieve, in accordance with the 

relevant provisions of the Convention, stabilization of 

greenhouse gas concentrations in the atmosphere at a level that 

would prevent dangerous anthropogenic interference with the 

climate system. Such a level should be achieved within a time 

frame sufficient to allow ecosystems to adapt naturally to 

climate change, to ensure that food production is not threatened 

and to enable economic development to proceed in a sustainable 

Deleted: Both of these measures had also been 

identified as effective and available 

technologies and strategies for reducing SO2

to address acid rain.

Deleted: F
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are 195 Parties to the UNFCCC, including the United States. The 

Conference of the Parties (COP) meets annually and is currently 

considering commitments countries can make to limit emissions 

after 2020. The 2015 COP will be in Paris and is expected to 

represent an historic step for climate change mitigation. The 

Parties to the UNFCC will meet to establish a climate agreement 

that applies to all countries and focuses on reducing greenhouse 

gas emissions. Such an outcome would send a beneficial signal to 

the markets and civil society about global action to address 

climate change. 

Many countries have announced their intended post-2020 

commitments already, and other countries are expected to do so 

before December. In April 2015, the United States announced its 

commitment to reduce GHG emissions 26-28% below 2005 levels by 

2025.221

 As Parties to both the UNFCCC and the Kyoto Protocol222, the 

European Union (EU) and member countries have taken aggressive 

 

manner. 

http://unfccc.int/files/essential_background/convention/backgrou

nd/application/pdf/convention_text_with_annexes_english_for_post

ing.pdf 

221 United States Cover Note to Intended Nationally Determined 

Contribution (INDC). Available online at:

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Un

ited%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and%

20Accompanying%20Information.pdf

222 http://unfccc.int/kyoto_protocol/items/2830.php 

Deleted: ,

Deleted: countries 

Deleted: there or beforehand
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action to reduce GHG emissions.223 EU initiatives to reduce 

greenhouse gas emissions include the EU Emissions Trading 

System, legislation to increase the adoption of renewable energy 

sources, strengthened energy efficiency targets, vehicle 

emission standards, and support for the development of CCS 

technology for use by the power sector and other industrial 

sources. In 2009, the EU announced its “20-20-20 targets,” 

including a 20% reduction in GHG emissions from 1990 levels by 

2020, an increase of 20% in the share of energy consumption 

produced by renewable resources, and a 20% improvement in energy 

efficiency. In March 2015, the EU announced its commitment to 

reduce domestic GHG emissions by at least 40% from 1990 levels 

by 2030.

 Recently, China has also agreed to take action to address 

climate change. In November 2014, in a joint announcement by 

President Obama and China’s President Xi, China pledged to 

curtail GHG emissions, with emissions peaking in 2030 and then 

declining thereafter, and to increase the share of energy from 

non-carbon sources (solar, wind, hydropower, nuclear) to 20 

percent by 2030. 

Mexico is committed to reduce unconditionally 25% of its 

emissions of greenhouse gases and short lived climate pollutants 

 

223 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm 
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(below business as usual) for the year 2030. This commitment 

implies a 22 percent reduction of GHG emissions and a 51 percent 

reduction of black carbon emissions. 

Brazil has reduced its net CO2 emissions more than any other 

country through a historic effort to slow forest loss. The 

deforestation rate in Brazil in 2014 was roughly 75% below the 

average for 1996 to 2005.224   

Together, countries that have already announced their 

intended post-2020 commitments, including the U.S., China, 

European Union, Mexico, Russian Federation and Brazil, make up a 

large majority of global emissions. 

President Obama’s Climate Action Plan contains a number of 

policies and programs that are intended to cut carbon pollution 

that causes climate change and affects public health. The Clean 

Power Plan is a key component of the plan, addressing the 

nation’s largest source of emissions in a comprehensive manner. 

Collectively, these policies will help spark business 

innovation, result in cleaner forms of energy, create jobs, and 

cut dependence on foreign oil. They also demonstrate to the rest 

of the world that the United States is contributing its share of 

 

224 http://www.nature.com/news/stopping-deforestation-battle-forthe-amazon-1.17223 
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the global effort that is needed to address climate change.225 

This demonstration encourages other major economies to take on 

similar contributions, which is critical given the global impact 

of greenhouse gas emissions. The State Department Special Envoy 

for Climate Change Todd Stern, the lead U.S. climate change 

negotiator, noted the connection between domestic and 

international action to address climate change in his speech in 

New Haven, CT on October 14, 2014: 

“This mobilization of American effort matters. Enormously. It 

matters because the United States is the biggest economy and 

largest historic emitter of greenhouse gases. Because, here, 

as in so many areas, we feel a responsibility to lead. And 

because here, as in so many areas, we find that American 

commitment is indispensable to effective international action. 

And make no mistake – other countries see what we are doing 

and are taking note. As I travel the world and meet with my 

counterparts, the palpable engagement of President Obama and 

his team has put us in a stronger, more credible position than 

ever before.” 

This final rule demonstrates to other countries that the 

United States is taking action to limit GHG emissions from its 

largest emission sources, in line with our international 

commitments. The impact of GHGs is global, and U.S. action to 

 

225 President Obama stated, in announcing the Climate Action 

Plan: 

“The actions I’ve announced today should send a strong 

signal to the world that America intends to take bold 

action to reduce carbon pollution. We will continue to lead 

by the power of our example, because that’s what the United 

States of America has always done.” President Obama, 

Climate Action Plan speech, Georgetown University, 2013. 
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reduce GHG emissions complements and encourages ongoing programs 

and efforts in other countries.

H. Legislative and Regulatory Background for CAA Section 111 

In the final days of December 1970, Congress enacted 

sweeping changes to the Air Quality Act of 1967 to confront an 

“environmental crisis.”226 The Air Quality Act—which expanded 

federal air pollution control efforts after the enactment of the 

Clean Air Act of 1963—prioritized the adoption of ambient air 

standards but failed to target stationary sources of air 

pollution. As a result, “[c]ities up and down the east coast 

were living under clouds of smoke and daily air pollution 

alerts.”227 In fact, “[o]ver 200 million tons of contaminants ... 

spilled into the air” each year.228 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”229 

For the most part, Congress gave EPA and the states 

flexible tools to implement the CAA. This is best exhibited by 

the newly enacted programs regulating stationary sources. For 

 

226 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. 

227 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

228 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. These pollutants fell into five main 

classes of pollutants: carbon monoxide, particulates, sulfur 

oxides, hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. 

at 244. 

229 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

Deleted: G
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these sources, Congress crafted a three-legged regime upon which 

the regulation of stationary sources was intended to sit. 

The first prong—CAA sections 107 to 110—addressed what are 

commonly referred to as criteria pollutants, “the presence of 

which in the ambient air results from numerous or diverse mobile 

or stationary sources” and are determined to have “an adverse 

effect on public health or welfare”.230 Under these provisions, 

states would have the primary responsibility for assuring air 

quality within their entire geographic area but would submit 

plans to the Administrator for “implementation, maintenance, and 

enforcement” of national ambient air quality standards. These 

plans would include “emission limitations, schedules, and 

timetables for compliance ... and such other measures as may be 

necessary to insure attainment and maintenance” of the national 

ambient air quality standards.231

The second prong—CAA section 111—addressed pollutants on a 

source category-wide basis. Under CAA section 111(b), the EPA 

lists source categories which “contribute significantly to air 

 

230 “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 

Stat. 1676, 1678 (Dec. 31, 1970). The “adverse effect” criterion 

was later amended to refer to pollutants “which may reasonably 

be anticipated to endanger public health or welfare”. See 42 

U.S.C. § 7408(a)(1)(A). Similar language is also used under the 

current CAA section 111. See 42 U.S.C. § 7411(b)(1)(A). 231 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680. 

Deleted: -

Deleted: For new sources in a listed source 

category, 

Deleted: established “standards of performance” 

for pollutants 
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pollution which causes or contributes to the endangerment of 

public health or welfare,” And then establishes “standards of 

performance” for the new sources in the listed category.232 For 

existing sources in a listed source category, CAA section 111(d) 

set out procedures for the establishment of federally 

enforceable “emission standards” of any pollutant not otherwise 

controlled under the CAA’s SIP provisions or CAA section 112. 

Lastly, the third prong—CAA section 112—addressed hazardous 

air pollutants through the establishment of national “emission 

standards” at a level which “provides an ample margin of safety 

to protect the public health”.233 All new or modified sources of 

any hazardous air pollutant would be required to meet these 

emission standards. Existing sources were required to meet the 

same standards or would be shut down unless they obtained a 

temporary EPA waiver or Presidential exemption.234

At its inception, CAA section 111 was intended to bear a 

significant weight under this three-legged regime. Indeed, by 

1977, the EPA had promulgated six times as many performance 

standards under CAA section 111 than emission standards under 

CAA section 112.235 That said, states, including Texas and New 

 

232 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684. 233 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 234 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 235 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 

Deleted: []

Deleted: .
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Jersey, levied “substantial criticisms” against the EPA for not 

moving rapidly enough.236 Accordingly, the 1977 CAA Amendments 

were designed to “provide a greater role for the [s]tates in 

standards setting under the [CAA],” “protect [s]tates from 

‘environmental blackmail’ as they attempt to regulate mobile and 

competitive industries,” and lastly “provide a check on the 

Administrator’s inaction or failure to control emissions 

adequately.”237

At bottom, CAA section 111 rests on the definition of a 

standard of performance under CAA section 111(a)(1), which reads 

nearly the same now as it did when it was first adopted in the 

1970 CAA Amendments. In 1970, Congress defined standard of 

performance—a term which had not previously appeared in the CAA—

as 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction) 

the Administrator determines has been adequately 

demonstrated.238

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

 

236 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 237 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 238 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 
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definition.239 As presently defined, the term applies to the 

regulation of new and existing sources under CAA sections 111(b) 

and (d).240 

The level of control reflected in the definition is 

generally referred to as the “best system of emission 

reduction,” or the BSER. The BSER, however, is not further 

defined, and only appeared after conference between the House 

and Senate in late 1970, and was neither discussed in the 

conference report nor openly debated in either chamber. 

Nevertheless, the originating bills from both houses shed light 

on its construction. 

The BSER grew out of proposed language in two bills, which, 

for the first time, targeted air pollution from stationary 

sources. The House bill sought to establish national emission 

standards to “prevent and control ... emissions [of nonhazardous pollutants] to the fullest extent compatible with the 

 

239 “Clean Air Act Amendments of 1990,” Pub. L. 101-549, § 403, 

104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the 

obligation to account for “any nonair quality health and 

environmental impact and energy requirements” that was added in 

1977). 

240 As CAA section 111(d) was originally adopted, state plans 

would have established “emission standards” instead of 

“standards of performance.” This distinction was later abandoned 

in 1977 and the same term is used in both CAA sections 111(b) 

and (d). 
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available technology and economic feasibility”.241 The House also 

proposed to prohibit the construction or operation of new 

sources of “extremely hazardous” pollutants.242 The Senate bill, 

on the other hand, authorized “Federal standards of 

performance,” which would “reflect the greatest degree of 

emission control which the Secretary [later, the Administrator] 

determines to be achievable through application of the latest 

available control technology, processes, operating methods, or 

other alternatives.”243 The Senate also would have authorized 

“national emission standards” for hazardous air pollution and 

other “selected air pollution agents.”244

After conference, CAA section 111 emerged as one of the 

CAA’s three programs for regulating stationary sources. In 

defining the newly formed “standards of performance,” Congress 

appeared to merge the various “means of preventing and 

controlling air pollution” under the Senate bill with the 

 

241 H.R. 17255, 91st Cong. § 5 (1970). 242 H.R. 17255, 91st Cong. § 5 (1970). 243 S. 4358, 91st Cong. § 6 (1970) (emphasis added). The breadth 

of the Senate bill is further emphasized in the conference 

report, which explains that a standard of performance “refers to 

the degree of emission control which can be achieved through 

process changes, operation changes, direct emission control, or 

other methods” and also includes “other means of preventing or 

controlling air pollution.” S. Rep. No. 91-1196, at 15-16 (Sept. 

17, 1970). 

244 S. 4358, 91st Cong. § 6 (1970). 
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consideration of costs that was central to the House bill into 

the BSER. At the time, however, this definition only applied to 

new sources under CAA section 111(b). 

To regulate existing sources, Congress collapsed section 

114 of the Senate bill into CAA section 111(d).245 Section 114 of 

the Senate bill established emission standards for “selected air 

pollution agents,” and was intended to bridge the gap between 

criteria pollutants and hazardous air pollutants. As proposed, 

the Senate identified fourteen substances for regulation under 

section 114 and only four substances for regulation under Senate 

bill 4358, section 115, the predecessor of CAA section 112.246 

As adopted, CAA section 111(d) requires states to submit 

plans to the Administrator establishing “emission standards” for 

certain existing sources of air pollutants that were not 

otherwise regulated as criteria pollutants or hazardous air 

pollutants. This ensured that there would be “no gaps in control 

activities pertaining to stationary source emissions that pose 

any significant danger to public health or welfare.”247 

 

245 The House bill did not provide for the direct regulation of 

existing sources. 

246 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970). 247 S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing the 

relationship between sections 114 (addressing emission standards 

for “selected air pollution agents”) and 115 (addressing 

hazardous air pollutants) of the Senate bill). 
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The term “emission standards,” however, was not expressly 

defined in the 1970 CAA Amendments (save for purposes of citizen 

suit enforcement) even though the term was also used under the 

CAA’s SIP provisions and CAA section 112.248 That said, under the 

newly enacted “ambient air quality and emission standards” 

sections, Congress directed the EPA to provide states with 

information “on air pollution control techniques,” including 

data on “available technology and alternative methods of 

prevention and control of air pollution” and on “alternative 

fuels, processes, and operating methods which will result in 

elimination or significant reduction of emissions.”249 Similarly, 

the Administrator would “issue information on pollution control 

techniques for air pollutants” in conjunction with establishing 

emission standards under CAA section 112. However, analogous 

text is absent from CAA section 111(d). 

After the enactment of the 1970 CAA Amendments, the EPA 

proposed standards of performance for an “initial list of five 

stationary source categories which contribute significantly to 

air pollution” in August 1971.250 The first category listed was 

 

248 See “Clean Air Act Amendments of 1970,” § 12, 84 Stat. at 

1706. 

249 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679. 250 “Standards of Performance for New Stationary Sources: 

Proposed Standards for Five Categories,” 36 F.R. 15704 (Aug. 17, 

1971). See “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 
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for fossil-fuel fired steam generators, for which EPA proposed 

and finalized standards for particulate matter, sulfur dioxide, 

and nitrogen oxides.251 

Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).252 These regulations were 

finalized in November 1975, and provided for the publication of 

emission guidelines.253 The first emissions guidelines were 

proposed in May 1976 and finalized in March 1977.254

Despite these first steps taken under CAA sections 111(b) 

and (d), Congress revisited the CAA in 1977 to address growing 

concerns with the nation’s response to the 1973 oil embargo 

(noted above), to respond to new environmental problems such as 

stratospheric ozone depletion, and to resolve other issues 

associated with implementing the 1970 CAA Amendments.255 Most 

 

1684 (requiring the Administrator to publish a list of 

categories of stationary sources within 90 days of the enactment 

of the 1970 CAA Amendments). 

251 36 F.R. at 15704-706; and “Standards of Performance for New 

Stationary Sources,” 36 F.R. 24876, 24879 (Dec. 23, 1971). 

252 See “State Plans for the Control of Existing Facilities,” 39 

F.R. 36102 (Oct. 7, 1974). 

253 See “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 F.R. 53340 (Nov. 17, 1975). 

254 See “Phosphate Fertilizer Plants; Draft Guideline Document; 

Availability,” 41 F.R. 19585(May 12, 1976); and “Phosphate 

Fertilizer Plants; Final Guideline Document Availability,” 42 

F.R. 12022 (Mar. 1, 1977) 

255 For example, Congress recognized that many air pollutants had 

not been regulated despite “mounting evidence” that these 

pollutants “are associated with serious health hazards”. H.R. 
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notably, an increase in coal use as a result of the oil crisis 

meant that “vigorous and effective control” of air emissions was 

“even more urgent.”256 Thus, to curb the projected surge in air 

emissions, Congress enacted several new provisions to the CAA. 

These new provisions include the prevention of significant 

deterioration (PSD) program, visibility protections, and 

requirements for nonattainment areas.257 

Congress also made significant changes to CAA section 111. 

For example, Congress amended the definition of a standard of 

performance (including by requiring the consideration of “nonair 

quality health and environmental impact and energy 

 

Rep. No. 94-1175, 22 (May, 15, 1976). Because EPA “failed to 

promulgate regulations to institute adequate control measures,” 

Congress ordered EPA to regulate four specific pollutants that 

had “been found to be cancer-causing or cancer-promoting”. Id.

at 23. This directive, reflected in CAA section 122, 

specifically added radioactive pollutants, cadmium, arsenic, and 

polycyclic organic matter “under the various provisions of the 

Clean Air Act and allows their regulation as criteria pollutants 

under ambient air quality standards, as hazardous air 

pollutants, or under new source performance standards, as 

appropriate.” H.R. Conf. Rep. No. 95-564, 142 (Aug. 3, 1977), 

1977 CAA Legis. Hist. at 522. At the same time, Congress made 

sure that these commands would have no effect on the 

Administrator’s discretion to address “any substance (whether or 

not enumerated [under CAA section 122(a))” under CAA sections 

108, 112, or 111. 42 U.S.C. § 7422(b). 

256 See Statement of EPA Administrator Costle, S. Hearings on S. 

272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 

30, 1977), 1977 CAA Legis. Hist. at 3532. 

257 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 

127-129, 91 Stat. 685 (Aug. 7, 1977). 
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requirements”), authorized alternative (e.g., work practice or 

design) standards in limited circumstances, provided states with 

authority to petition the Administrator for new or revised (and 

more stringent) standards, and imposed a strict regulatory 

schedule for establishing standards of performance for 

categories of major stationary sources that had not yet been 

listed.258

The 1977 definition for a standard of performance required 

“all new sources to meet emission standards based on the 

reductions achievable through the use of the ‘best technological 

system of continuous emission reduction.’”259 For fossil-fuel 

fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.260 Together, this 

was designed to “force new sources to burn high-sulfur fuel thus 

freeing low-sulfur fuel for use in existing sources where it is 

 

258 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697. 259 H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 

separately defined “technological system of continuous emission 

reduction” as “(A) a technological process for production or 

operation by any source which is inherently low-polluting or 

nonpolluting, or (B) technological system for continuous 

reduction of the pollution generated by a source before such 

pollution is emitted into the ambient air, including 

precombustion cleaning or treatment of fuels.” “Clean Air Act 

Amendments of 1977,” § 109, 91 Stat. at 700; see also 42 U.S.C. 

§ 7411(a)(7). 

260 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700. 
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harder to control emissions and where low-sulfur fuel is needed 

for compliance.”261

Congress also clarified that with respect to CAA section 

111(d), standards of performance (now applicable in lieu of 

emission standards) “would be based on the best available means 

(not necessarily technological)”.262 This was intended to 

distinguish existing source standards from new source standards, 

for which “the requirement for [the BSER] has been more narrowly 

redefined as best technological system of continuous emission 

reduction.”263 Additionally, Congress clarified that states could 

consider “the remaining useful life” of a source when applying a 

standard of performance to a particular existing source.264 

In the twenty years since the 1970 CAA Amendments and in 

spite of the refinements of the 1977 CAA Amendments, “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”265 Indeed, in 1988, 

President George Bush said that “‘progress has not come quickly 

 

261 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 F.R. 33580, 33581-82 (June 

11, 1979). 

262 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 263 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 

264 This concept was already reflected in the EPA’s CAA section 

111(d) implementing regulations under 40 C.F.R. § 60.24(f). See 

40 F.R. 53340, 53347 (Nov. 17, 1975). 

265 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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enough and much remains to be done.’”266 This time, with the 1990 

CAA Amendments, Congress substantially overhauled the CAA. In 

particular, Congress again added to the NAAQS program, 

completely revised CAA section 112, added a new title to target 

existing fossil fuel-fired stationary sources and address 

growing concerns with acid rain, imported an operating permit 

modeled off the Clean Water Act, and established a phase out of 

certain ozone depleting substances. 

All told, however, there was minimal debate on changes to 

CAA section 111. In fact, the only discussion centered on the 

repeal of the percentage reduction requirement, which became 

seen as unduly restrictive. Accordingly, Congress reverted the 

definition of “standard of performance” to the definition agreed 

to in the 1970 CAA Amendments, but retained the requirement to 

consider nonair quality environmental impacts and energy 

requirements added in 1977.267 However, the repeal would only 

apply so long as the SO2 cap under CAA section 403(e) of the 

newly established acid rain program remained in effect.268

Lastly, Congress instructed the EPA to revise its new source 

 

266 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 267 Congress also updated the regulatory schedule that was added 

in the 1977 CAA Amendments to reflect the newly enacted 1990 CAA 

Amendments. See “Clean Air Act Amendments of 1990,” § 108, 104 

Stat. 2467. 

268 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631. 
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performance standards for SO2 emissions from fossil fuel-fired 

power plants but required that the revised emission rate be no 

less stringent than before.269

I. Statutory and Regulatory Requirements 

Clean Air Act section 111, which Congress enacted as part 

of the 1970 Clean Air Act Amendments, establishes mechanisms for 

controlling emissions of air pollutants from stationary sources. 

This provision requires the EPA to promulgate a list of 

categories of stationary sources that the Administrator, in his 

or her judgment, finds “causes, or contributes significantly to, 

air pollution which may reasonably be anticipated to endanger 

public health or welfare.”270 The EPA has listed more than 60 

stationary source categories under this provision.271 Once the 

EPA lists a source category, the EPA must, under CAA section 

111(b)(1)(B), establish “standards of performance” for emissions 

of air pollutants from new sources in the source categories.272

These standards are known as new source performance standards 

(NSPS), and they are national requirements that apply directly 

to the sources subject to them. 

 

269 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631. 270 CAA §111(b)(1)(A). 271 See 40 CFR 60 subparts Cb – OOOO. 272 CAA §111(b)(1)(B), 111(a)(1). 

Deleted: H
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When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to prescribe regulations for states to submit 

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

(HAP). CAA section 111(d)’s mechanism for regulating existing 

sources differs from the one that CAA section 111(b) provides 

for new sources because CAA section 111(d) contemplates states 

submitting plans that establish “standards of performance” for 

the affected sources and that contain other measures to 

implement and enforce those standards. 

“Standards of performance” are defined under CAA section 

111(a)(1) as standards for emissions that reflect the emission 

limitation achievable from the “best system of emission 

reduction,” considering costs and other factors, that 

“the Administrator determines has been adequately demonstrated.” 

CAA section 111(d)(1) grants states the authority, in applying a 

standard of performance to a particular source, to take into 

account the source’s remaining useful life or other factors. 

Under CAA section 111(d), a state must submit its plan to the 

EPA for approval, and the EPA must approve the state plan if it 
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is “satisfactory.”273 If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for that state.274 Once a state receives the 

EPA’s approval of its plan, the provisions in the plan become 

federally enforceable against the entity responsible for 

noncompliance, in the same manner as the provisions of an 

approved SIP under the Act. 

Section 302(d) of the CAA defines the term “state” to 

include the Commonwealth of Puerto Rico, the Virgin Islands, 

Guam, American Samoa and the Commonwealth of the Northern 

Mariana Islands. While 40 CFR part 60 contains a separate 

definition of “state” at § 60.2, this definition expands on, 

rather than narrows, the definition in section 302(d) of the 

CAA. The introductory language to 40 CFR 60.2 provides: “The 

terms in this part are defined in the Act or in this section as 

follows.” Section 60.2 defines “State” as “all non-Federal 

authorities, including local agencies, interstate associations, 

and State-wide programs that have been delegated authority to 

implement: (1) the provisions of this part and/or (2) the permit 

program established under part 70 of this chapter. The term 

State shall have its conventional meaning where clear from the 

 

273 CAA section 111(d)(2)(A). 274 CAA section 111(d)(2)(A). 
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context.” The EPA believes that the last sentence refers to the 

conventional meaning of “state” under the CAA. Thus, the EPA 

believes the term “state” as used in the emission guidelines is 

most reasonably interpreted as including the meaning ascribed to 

that term in section 302(d) of the CAA, which expressly includes 

U.S. territories. 

Section 301(d)(A) of the CAA recognizes that the American 

Indian tribes are sovereign Nations and authorizes the EPA to 

“treat tribes as States under this Act”. The Tribal Authority 

Rule (63 Federal Register 7254, February 12, 1998) identifies 

that EPA will treat tribes in a manner similar to states for all 

of the CAA provisions with the exception of, among other things, 

specific plan submittal and implementation deadlines under the 

CAA. As a result, though they operate as part of the 

interconnected system of electricity production and 

distribution, affected EGUs located in Indian country would not 

be encompassed within a state’s CAA section 111(d) plan. 

Instead, an Indian tribe with one or more affected EGUs located 

in its area of Indian country275 will have the opportunity, but 

 

275 The EPA is aware of at least four affected sources located in 

Indian Country: two on Navajo lands – the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands – the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility.
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not the obligation, to apply for eligibility to develop and 

implement a CAA section 111(d) plan. The Indian tribe would need 

to be approved by the EPA as eligible to develop and implement a 

CAA section 111(d) plan following the procedure set forth in 40 

CFR part 49. Once a tribe is approved as eligible for that 

purpose, it would be treated in the same manner as a state, and 

references in the emission guidelines to states would refer 

equally to the tribe. The EPA notes that, while tribes have the 

opportunity to apply for eligibility to administer CAA programs, 

they are not required to do so. Further, the EPA has established 

procedures in 40 CFR part 49 (see particularly 40 CFR 49.7(c)) 

that permit eligible tribes to request approval of reasonably 

severable partial program elements. Those procedures are 

applicable here. 

In these final emission guidelines, the term “state” 

encompasses the 50 states and the District of Columbia, U.S. 

territories, and any Indian tribe that has been approved by the 

EPA pursuant to 40 CFR 49.9 as to develop and implement a CAA 

section 111(d) plan. 

Deleted: Although the EPA believes the current 

emission guidelines are sufficiently 

inclusive, the EPA is amending the 

applicability provision of the emission 

guidelines slightly to avoid any doubt that 

the guidelines apply to U.S. territories with 

affected EGUs and to any Indian tribe that has 

been approved by the EPA as eligible to 

develop and implement a plan. ¶
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The EPA issued regulations implementing CAA section 111(d) 

in 1975,276 and has revised them in the years since.277 (We refer 

to the regulations generally as the implementing regulations.) 

These regulations provide that, in promulgating requirements for 

sources under CAA section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish 

binding requirements that states must address when they develop 

their plans.278 The implementing regulations also establish 

timetables for state and EPA action: states must submit state 

plans within 9 months of the EPA’s issuance of the guidelines,279

and the EPA must take final action on the state plans within 4 

months of the due date for those plans,280 although the EPA has 

authority to extend those deadlines.281 In this rulemaking, the 

EPA is following the requirements of the implementing 

 

276 “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

277 The most recent amendment was in 77 Fed. Reg. 9304 (Feb. 16, 

2012). 

278 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emissions guidelines” – instead of emissions 

limitations – to make clear that guidelines would not be binding 

requirements applicable to the sources, but instead are 

“criteria for judging the adequacy of State plans.” 40 Fed. Reg. 

at 53,343. 

279 40 CFR 60.23(a)(1). 280 40 CFR 60.27(b). 281 See 40 CFR 60.27(a). 
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regulations, and is not re-opening them, except that the EPA is 

extending the timetables, as described below. 

Over the last forty years, under CAA section 111(d), the 

agency has regulated four pollutants from five source categories 

(i.e., sulfuric acid plants (acid mist), phosphate fertilizer 

plants (fluorides), primary aluminum plants (fluorides), Kraft 

pulp plants (total reduced sulfur), and municipal solid waste 

landfills (landfill gases)).282 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.283 The agency has not 

previously regulated CO2 or any other greenhouse gas under CAA 

section 111(d). 

The EPA’s previous CAA section 111(d) actions were 

necessarily geared toward the pollutants and industries 

regulated. Similarly, in this rulemaking, in defining CAA 

 

282 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

283 See, e.g., “Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15,372 

(Mar. 21, 2011). 
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section 111(d) emission guidelines for the states and 

determining the BSER, the EPA believes that taking into account 

the particular characteristics of carbon pollution, the 

interconnected nature of the power sector and the manner in 

which EGUs are currently operated is warranted. Specifically, 

the operators themselves treat increments of generation as 

interchangeable between and among sources in a way that creates 

options for relying on varying utilization levels, lowering 

carbon generation, and reducing demand as components of the 

overall method for reducing CO2 emissions. Doing so results in a 

broader, forward-thinking approach to the design of programs to 

yield critical CO2 reductions that improve the overall power 

system by lowering the carbon intensity of power generation, 

while offering continued reliability and cost-effectiveness. 

These opportunities exist in the utility power sector in ways 

that were not relevant or available for other industries for 

which the EPA has established CAA section 111(d) emission 

guidelines.284

 

284 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 
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In this action, the EPA is promulgating emission guidelines 

for states to follow in developing their CAA section 111(d) 

plans to reduce emissions of CO2 from the utility power sector. 

J. Clean Power Plan Proposal and Supplemental Proposal 

On June 18, 2014, the EPA proposed emission guidelines for 

states to follow in developing plans to address greenhouse gas 

(GHG) emissions from existing fossil fuel-fired electric 

generating units (EGUs). Specifically, the EPA proposed ratebased goals for carbon dioxide (CO2) emissions for each state 

with existing fossil fuel-fired EGUs, as well as guidelines for 

plans to achieve those goals. On November 4, 2014, the EPA 

published a supplemental proposal that proposed emission ratebased goals for CO2 emissions for U.S. territories and areas of 

Indian country with existing fossil fuel-fired EGUs. In the 

supplemental proposal, the EPA also solicited comment on 

authorizing jurisdictions (including any states, territories and 

areas of Indian country) without existing fossil fuel-fired EGUs 

subject to the proposed emission guidelines to partner with 

jurisdictions (including any states) that do have existing 

fossil fuel-fired EGUs subject to the proposed emission 

guidelines in developing multi-jurisdictional plans. The EPA 

 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

Deleted: , U.S. territories, and tribes

Deleted: I
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also solicited comment on the treatment of renewable energy, 

demand-side energy efficiency and other new low- or non-emitting 

electricity generation across international boundaries in a 

state plan. 

The EPA also issued two notices after the June 18, 2014 

proposal. On October 30, 2014, the EPA published a notice of 

data availability (NODA) in which the agency provided additional 

information on several topics raised by stakeholders and 

solicited comment on the information presented. The notice 

covered three topic areas: 1) the emission reduction compliance 

trajectories created by the interim goal for 2020 to 2029, 2) 

certain aspects of the building block methodology, and 3) the 

way state-specific CO2 goals are calculated. 

In a separate action, the EPA published a notice regarding 

potential methods for determining the mass that is equivalent to 

an emission rate-based CO2 goal (79 FR 67406; November 13, 2014). 

With the notice, the EPA also made available, in the docket for 

this rulemaking, a technical support document (TSD) that 

provided two examples of how a state, U.S. territory or tribe 

could translate a rate-based CO2 goal to total metric tons of CO2

(a mass-based equivalent). 

K. Stakeholder Outreach and Consultations Deleted: J
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Following the direction in the Presidential Memorandum to 

the Administrator (June 25, 2013),285 the EPA engaged in 

extensive and vigorous outreach to stakeholders and the general 

public at every stage of development of this rule. Our outreach 

has included direct engagement with the energy and environment 

officials in states, tribes, and a full range of stakeholders 

including leaders in the utility power sector, labor leaders, 

non-governmental organizations, other federal agencies, other 

experts, community groups and members of the public. The EPA 

participated in more than 300 meetings before the rule was 

proposed and more than 300 after the proposal. 

Throughout the rulemaking process, the agency has 

encouraged, organized, and participated in hundreds of meetings 

about CAA section 111(d) and reducing carbon pollution from 

existing power plants. The agency’s outreach prior to proposal, 

as well as during the public comment period, was designed to 

solicit policy ideas,286 concerns, and technical information. The 

 

285 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards. 

286 The EPA received more than 2,000 emails offering input into 

the development of these guidelines through email and a webbased form. These emails and other materials provided to the EPA 

are posted on line as part of a non-regulatory docket, EPA 

Docket ID No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. 
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agency received 4.3 million comments about all aspects of the 

proposed rule and thousands of people participated in the 

agency’s public hearings, webinars, listening sessions,287

teleconferences and meetings held all across the country. 

Our engagement has brought together a variety of states and 

stakeholders to discuss a wide range of issues related to the 

utility power sector and the development of emission guidelines 

under CAA section 111(d). The meetings were attended by the EPA 

Regional Administrators, other senior managers and staff who 

have been instrumental in the development of the rule and will 

play key roles in developing and implementing it. 

This outreach process has produced a wealth of information 

which has informed this rule significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialogue with states and stakeholders will continue 

after the rule is finalized. The EPA recognizes the importance 

of working with all stakeholders, and in particular with the 

states, to ensure a clear and common understanding of the role 

the states will play in addressing carbon pollution from power 

plants. We firmly believe that our outreach has resulted in a 

 

287 Summaries of the 11 public listening sessions in 2013 are 

available at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020. 
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more workable rule that will achieve the statutory goals and has 

enhanced the likelihood of timely and successful achievement of 

the carbon reduction goals, given the critical importance and 

urgency of the concrete action. 

The EPA has given stakeholder comments careful 

consideration and, as a result, this final rule includes 

features that are responsive to many stakeholder concerns. 

1. Public hearings 

More than 2,700 people attended the public hearings 

sessions held in Atlanta, Denver, Pittsburgh, and Washington, 

DC. More than 1,300 people spoke at the public hearings. 

Additionally, about 100 people attended the public hearing held 

in Phoenix, Arizona, on the November 4, 2014 supplemental 

proposal. Speakers at the public hearings included Members of 

Congress, other public officials, industry representatives, 

faith-based organizations, unions, environmental groups, 

community groups, students, public health groups, energy groups, 

academia and concerned citizens. 

Participants shared a range of perspectives. Many were 

concerned with the impacts of climate change on their health and 

on future generations, others were worried about the impact of 

regulations on the economy. Their support for the agency’s 

efforts varied. 
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2. State officials 

Since fall 2013, the agency has provided multiple 

opportunities for the states to inform this rulemaking. 

Administrator McCarthy has engaged with governors from states 

with a variety of interests in the rulemaking. Other senior 

agency officials have engaged with every branch and major agency 

of state government - including state legislators, attorneys 

general, state energy, environment, and utility officials, and 

governors' staff. 

On several occasions, state environmental commissioners met 

with senior agency officials to provide comments on the Clean 

Power Plan. The EPA organized, encouraged and attended meetings 

with states to discuss multi-state planning efforts. States have 

come together with several collaborative groups to discuss ways 

to work together to make the Clean Power Plan more affordable. 

The EPA has participated in and supported the states in these 

discussions. Because of the interconnectedness of the power 

sector, and the fact that electricity generated at power plants 

crosses state lines; states, utilities and ratepayers may 

benefit from states working together to implement the 

requirements of this rulemaking. The meetings provided state 

leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 
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directors, opportunities to engage with the EPA officials. In 

addition, the states submitted public comments from several 

agencies within each state. The wealth of comments and input 

from states was important in developing the final rulemaking. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 

experience in reducing carbon pollution from power plants. The 

EPA reached out to all 50 states to engage with both 

environmental and energy departments at all levels of 

government. As an example, a three-part webinar series in 

June/July 2014 for the states and tribes offered an interactive 

format for technical staff at the EPA and in the states/tribes 

to exchange ideas and ask clarifying question. The webinars were 

then posted online so other stakeholders could view them. A few 

weeks after the postings, the EPA organized follow-up conference 

calls with stakeholder groups. Also, the EPA hosted scores of 

technical meetings between states and the EPA in the weeks and 

months after the rule was proposed. 

Additionally, the EPA organized “hub” calls; these 

teleconferences brought all of the states in a given EPA region 

together to discuss technical and interstate aspects of the 

proposal. These exchanges helped provide the stakeholders with 

the information they needed to comment on the proposal 
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effectively. The EPA also held a series of webinars with state 

environmental associations and their members on a series of 

technical issues. 

The agency has collected policy papers and comment letters 

from states with overarching energy goals and technical details 

on the states’ utility power sector. EPA leadership and staff 

also participated in webinars and meetings with state and tribal 

officials hosted by collaborative groups and trade associations. 

After the comment period closed, and based on our meetings over 

the last year, as well as written comments on the proposal and 

NODA, the EPA analyzed information about data errors that needed 

to be addressed for the final rule. In February and March 2015, 

we reached out to particular states to clarify ambiguous or 

unclear information that was submitted to the EPA related to 

NEEDS and eGRID data. The EPA contacted particular states to 

clarify the technical comments or concerns to ensure that any 

changes we make are accurate and appropriate. 

To help prepare for implementation of this rule, the agency 

initiated several outreach activities to assist with state 

planning efforts. The agency participated in meetings organized 

by the National Association of State Energy Officials (NASEO), 

the National Association of Regulatory Utility Commissioners 

(NARUC), and the National Association of Clean Air Agencies 

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(NACAA) (the “3N” groups). Meeting participants discussed issues 

related to energy efficiency and renewable energy. 

To help state officials prepare for the planning process 

that will take place in the states, the EPA presented a webinar 

on February 24, 2015. This webinar provided an update on 

training plans and further connection with states in the 

implementation process. Forty-nine states, the District of 

Columbia, and 14 tribes were represented at this webinar. The 

EPA is developing a state plan electronic collection system to 

receive, track, and store state submittals of plans and reports. 

The EPA plans to use an integrated project team to solicit 

stakeholder input on the system during development. The team 

membership, including state representatives, will bring together 

the business and technology skills required to construct a 

successful product and promote transparency in the EPA’s 

implementation of the rule. 

To help identify training needs for the final Clean Power 

Plan, the agency reached out to a number of state and local 

organizations such as the Central State Air Resources Agencies 

and other such regional air agencies. The EPA’s outreach on 

training has included sharing the plans with the states and 

incorporating changes to the training topics based on the 

states’ needs. The EPA training plan includes a wide variety of 
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topics such as basic training on the electric power sector as 

well as specific pollution control strategies to reduce carbon 

emissions from power plants. In particular, the states requested 

training on how to use programs such as combined heat and power, 

energy efficiency and renewable energy to reduce carbon 

emissions. The EPA will continue to work with states to tailor 

training activities to their needs. 

The agency has engaged, and will continue to engage with 

states, territories, Washington, D.C., and tribes after the 

rulemaking process and throughout implementation. 

3. Tribal officials 

 The EPA conducted significant outreach to and consultation 

with tribes. Tribes are not required to, but may, develop or 

adopt Clean Air Act programs. The EPA is aware of four 

facilities with affected EGUs located in Indian country: the 

South Point Energy Center, in Fort Mojave Indian country, 

geographically located within Arizona; the Navajo Generating 

Station, in Navajo Indian country, geographically located within 

Arizona; the Four Corners Power Plant, in Navajo Indian country, 

geographically located within New Mexico; and the Bonanza Power 

Plant, in Ute Indian country, geographically located within 

Utah. The EPA offered consultation to the leaders of the tribes 

on whose lands these facilities are located as well as all of 
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the federally recognized tribes to ensure that they had the 

opportunity to have meaningful and timely input into this rule. 

Section III (“Stakeholder Outreach and Conclusions”) of the June 

18, 2014 proposal documents the EPA’s extensive outreach efforts 

to tribal officials prior to that proposal, including an 

informational webinar, outreach meeting, teleconferences with 

tribal officials and the National Tribal Air Association (NTAA), 

and letters offering consultation. Additional outreach to tribal 

officials conducted by the EPA prior to the November 4, 2014 

supplemental proposal is discussed in Section II.D (“Additional 

Outreach and Consultation”) of the supplemental proposal. The 

additional outreach for the supplemental proposal included 

consultations with all three tribes that have affected EGUs on 

their lands, as well as several other tribes that requested 

consultation, and also additional teleconferences with the NTAA. 

After issuing the supplemental proposal, the EPA offered an 

additional consultation to the leaders of all federally 

recognized tribes. The EPA held an informational meeting open to 

all tribes and also held consultations with the Navajo Nation, 

Fort McDowell Yavapai Nation, Fort Mojave Tribe, Ak-Chin Indian 

Community, and Hope Tribe on November 18, 2014. The EPA held a 

consultation with the Ute Tribe of the Uintah and Ouray 

Reservation on December 16, 2014, and a consultation with the 
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Gila River Indian Community on January 15, 2015. The EPA held a 

public hearing on the supplemental proposal on November 19, 

2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an 

additional consultation with the Navajo Nation. 

 Tribes were interested in the impact of this rule on other 

ongoing regulatory actions at the affected EGUs, such as 

permitting or requirements for the best available retrofit 

technology (BART). Tribes also noted that it was important to 

allow renewable energy projects on tribal lands to contribute 

toward meeting state goals. Some tribes indicated an interest in 

being involved in the development of implementation plans for 

areas of Indian country. Additional detail regarding the EPA’s 

outreach to tribes and comments and recommendations from tribes 

can be found in Section X.F of this preamble. 

4. U.S. territories 

The EPA has met with individual U.S. territories and 

affected EGUs in U.S. territories during the rulemaking process. 

On July 22, 2014, the EPA met with representatives from the 

Puerto Rico Environmental Quality Board, the Puerto Rico 

Electric Power Authority, the Governor’s Office, and the Office 

of Energy, Puerto Rico. On September 8, 2014, the EPA held a 

meeting with representatives from the Guam Environmental 

Protection Agency (GEPA) and the Guam Power Authority and, on 
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February 18, 2015, the EPA met again with representatives from 

GEPA. 

5. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in many one-on-one and 

national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the rule 

is on the utility power sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the utility power sector. The agency has 

also met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

have expertise in renewable energy and energy efficiency. Other 

meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries, 

to help understand the issues related to large industrial users 

of electricity. 

6. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations to discuss all aspects of the 

proposed guidelines. We have met with all types of companies 
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that produce electricity, including private utilities or 

investor owned utilities. Public utilities and cooperative 

utilities were also part of in-depth conversations about CAA 

section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 

7. Electricity grid operators 

The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

regional offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

8. Representatives from community and non-governmental 

organizations 
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Agency officials engaged with community groups representing 

low-income communities, and faith-based groups, among others, 

during the outreach effort. In response to a request from 

communities, the EPA held a day-long training on the Clean Power 

Plan on October 30, 2014, in Washington D.C. At this meeting, 

the EPA met with a number of environmental groups to provide 

information on how the agency plans on reducing carbon pollution 

from existing power plants using CAA section 111(d). 

Many environmental organizations discussed the need for 

reducing carbon pollution. Meetings were technical, policy and 

legal in nature and many groups discussed specific state 

policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. Many members of 

faith communities attended the four public hearings. 

 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 
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reducing electricity prices for consumers through energy 

efficiency and low-cost carbon reductions. 

 In winter/spring 2015, EPA continued to offer webinars and 

teleconferences for community groups on the rulemaking. 

9. Environmental Justice Organizations 

Agency officials engaged with environmental justice groups 

representing communities of color, low-income communities and 

others during the outreach effort. Agency officials also engaged 

with the EPA’s National Environmental Justice Advisory Council 

(NEJAC) members in September 2013. The NEJAC is composed of 

stakeholders, including environmental justice leaders and other 

leaders from state and local government and the private sector. 

Additionally, the agency conducted a community call on February 

26, 2015, and on February 27, 2015, the EPA conducted a follow 

up webinar for participants in an October 30, 2014 training 

session. The EPA also held a webinar for communities on the 

Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 

2015. 

During the EPA’s extensive outreach conducted before and 

after proposal, the EPA has heard a variety of issues raised by 

environmental justice communities. Communities expressed the 

desire for the agency to conduct an environmental justice (EJ) 

analysis and to require that states in the development of their 
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state plans conduct one as well. Additionally, they asked that 

the agency require that states engage with communities in the 

development of their state plans and that the agency conduct 

meaningful involvement with communities, throughout the whole 

rulemaking process, including the implementation phase. 

Furthermore, communities stressed the importance of low-income 

and communities of color receiving the benefits of this 

rulemaking and being protected from being adversely impacted by 

this rulemaking. 

The purpose of this rule is to substantially reduce 

emissions of CO2, a key contributor to climate change, which 

adversely and disproportionally affects vulnerable and 

disadvantaged communities in the US and throughout the world. 

In addition, the rule will result in substantial reductions of 

conventional air pollutants, providing immediate public health 

benefits to the communities where the facilities are located and 

for many miles around. The EPA is committed to ensuring that all 

Americans benefit from the public health and other benefits that 

this rule will bring. Further discussion of the impacts of this 

rule on communities and actions that the EPA is taking to 

address concerns cited by communities is available in Sections 

IX and XII.J of this preamble. 

10. Labor 
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Senior agency officials met with a number of labor union 

representatives about reducing carbon pollution using CAA 

section 111(d). Those unions included: the United Mine Workers 

of America; the Sheet Metal, Air, Rail and Transportation Union 

(SMART); the International Brotherhood of Boilermakers, Iron 

Ship Builders, Blacksmiths, Forgers and Helpers (IBB); United 

Association of Journeymen and Apprentices of the Plumbing and 

Pipe Fitting Industry of the United States and Canada; the 

International Brotherhood of Electrical Workers (IBEW): and the 

Utility Workers Union of America. In addition, agency leaders 

met with the Presidents of several unions and the President of 

the American Federation of Labor-Congress of Industrial 

Organizations (AFL-CIO) at the AFL-CIO headquarters. 

EPA officials attended meetings sponsored by labor unions 

to give presentations and engage in discussions about reducing 

carbon pollution using CAA section 111(d). These included 

meetings sponsored by the IBB and the IBEW. 

11. Other federal agencies and independent agencies 

Throughout the development of the rulemaking, the EPA 

consulted with other federal agencies with relevant expertise. 

For example, the EPA met with managers from the U.S. Department 

of Agriculture’s (USDA’s) Rural Utility Service to discuss the 

rule and potential effects on affected EGUs in rural areas and 
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how USDA programs could interact with affected EGUs during rule 

implementation. 

The U.S. Department of Energy (DOE) was a frequent source 

of expertise and advice on the proposed and final rule. EPA 

management and staff had numerous meetings with management and 

staff at DOE on a range of topics, including the effectiveness 

and costs of energy generation technologies, and energy 

efficiency. 

DOE provided technical assistance relating to RE and 

demand-side EE, including RE and demand-side EE cost and 

performance data and, for RE, information on the feasibility of 

deploying and reliably integrating increased RE generation. 

Further, EPA and DOE staff discussed emission measurement and 

verification (EM&V) strategies. 

 The EPA also consulted with DOE on electric reliability 

issues. EPA staff and managers met and spoke with DOE staff and 

managers throughout the development of the proposed and final 

rules on topic related to electric system reliability. 

 EPA officials worked closely with DOE and Federal Energy 

Regulatory Commission (FERC) officials to ensure, to the 

greatest extent possible, that actions taken by states and 

affected EGUs to comply with the final rule mitigate potential 

electric system reliability issues. Senior EPA officials met 
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with each of the FERC Commissioners and EPA staff had frequent 

contact with FERC staff throughout the development the rule. 

FERC held four technical conferences to discuss implications of 

compliance approaches to the rule for electric reliability. EPA 

staff attended the four conferences and EPA leadership spoke at 

all of them. The EPA, DOE, and FERC will continue to work 

together to ensure electric grid reliability in the development 

and implementation of state plans. 

L. Comments on the Proposal 

The Administrator signed the proposed emission guidelines 

on June 2, 2014, and, on the same day, the EPA made this version 

available to the public at http://www.epa.gov/cleanpowerplan/.

The 120-day public comment period on the proposal began on June 

18, 2014, the day of publication of the proposal in the Federal 

Register. On September 18, 2014, in response to requests from 

stakeholders, the EPA extended the comment period by 45 days, to 

December 1, 2014, giving stakeholders over 165 days to review 

and comment upon the proposal. Stakeholders also had the 

opportunity to comment on the NODA, as well as the notice and 

TSD regarding potential methods for determining the mass that is 

equivalent to an emission rate-based CO2 goal, through December 

1, 2014. The EPA offered a separate 45-day comment period for 

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the November 4, 2014 supplemental proposal, and that comment 

period closed on December 19, 2014. 

The EPA received more than 4.2 million comments on the 

proposed carbon pollution emission guidelines from a range of 

stakeholders that included, including state environmental and 

energy officials, local government officials, tribal officials, 

public utility commissioners, system operators, utilities, 

public interest advocates, and members of the public. The agency 

received comments on many aspects of the proposal and many 

suggestions for changes that would address issues of concern. 

III. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

The EPA is establishing emission guidelines for states to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction ... adequately demonstrated” 

(BSER) and include source category-specific CO2 emission 

performance rates, state-specific goals, requirements for state 

plan components, and requirements for the process and timing for 

state plan submittal and compliance. 

Under CAA section 111(d), the states must establish 

standards of performance that reflect the degree of emission 
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limitation achievable through the application of the “best 

system of emission reduction” that, taking into account the cost 

of achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 

The EPA has determined that the BSER is the combination of 

emission rate improvements and limitations on overall emissions 

at affected EGUs that can be accomplished through any 

combination of one or more measures from the following three 

sets of measures or building blocks: 

1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units for 

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from new low- and 

zero-emitting generating units for reduced generation 

from affected fossil fuel-fired generating units. 

Consistent with CAA section 111(d) and other rules 

promulgated under this section, the EPA is taking a traditional, 
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performance-based approach to establishing emission guidelines 

for affected sources and applying the BSER to two source 

subcategories of existing fossil fuel-fired EGUs -- fossil fuelfired electric utility steam generating units and stationary 

combustion turbines. The EPA is finalizing source subcategoryspecific emission performance rates that reflect the EPA’s 

application of the BSER. For fossil fuel-fired steam generating 

units, we are finalizing a performance rate of 1,305 lb/MWh of 

CO2. For stationary combustion turbines, we are finalizing a 

performance rate of 771 lb/MWh of CO2. The EPA has also 

translated the source subcategory-specific CO2 emission 

performance rates into equivalent statewide rate-based and massbased CO2 goals and is providing those as an option for states to 

use. 

Under CAA section 111(d), each state must develop, adopt, 

and then submit its plan to the EPA. For its CAA section 111(d) 

plan, a state will determine whether to apply these emission 

performance rates to each affected EGU, individually or 

together, or to take an alternative approach and meet either an 

equivalent statewide rate-based goal or an equivalent statewide 

mass-based goal, as provided by the EPA in this rulemaking. 

For these final emission guidelines, the term “state,” when 

used in the context of section 111(d) plans, encompasses the 50 

Deleted: 290

Deleted: 80
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states, the District of Columbia, U.S. territories, and any 

Indian tribe that has been approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and implement a CAA section 

111(d) plan. However, a jurisdiction is not obligated or 

potentially eligible to submit a CAA section 111(d) plan unless 

it has within its jurisdictional boundaries one or more affected 

EGUs that commenced construction on or before January 8, 2014. 

In developing its CAA section 111(d) plan, a state will 

have the option of choosing from two different approaches: 1) an 

“emission standards” approach, or 2) a “state measures” 

approach. With an emission standards approach, a state will 

apply all requirements for achieving the subcategory-specific CO2

emission performance rates or the state-specific CO2 emission 

goal to affected EGUs in the form of federally enforceable 

emission standards. With a state measures approach, a state plan 

would be comprised, at least in part, of measures implemented by 

the state that are not included as federally enforceable 

components of the plan, along with a backstop of federally 

enforceable emission standards for affected EGUs that would 

apply in the event the plan does not achieve its anticipated 

level of CO2 emission performance. 

The EPA is requiring states to make their final plan 

submittals by September 6, 2016 (i.e., 13 months from the 

Deleted: such a “state” would not be 

Deleted: initial

Deleted: August 31

Deleted: 5
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signature date of the rule), or to make an initial plan 

submittal by this date in order to obtain an extension for 

making their final plan submittals no later than September 6, 

2018, which is 3 years from the signature date of the rule. 

There are three required components for states to address in 

their initial plan submittals if they are seeking an extension 

to make their final plan submittals. The first required 

component is identification of final plan approaches under 

consideration. The second required component is an appropriate 

justification for why the state needs the extension to make a 

final plan submittal by September 6, 2018. The third required 

component for states to address in the initial plan submittal is 

a demonstration of how they have been engaging with the public, 

including overburdened communities, and a description of how 

they intend to meaningfully engage with community stakeholders 

during the additional time (if an extension is granted) for 

development of the final plan.

Affected EGUs must achieve the final emission performance 

rates or equivalent state goals by 2030 and maintain that level 

thereafter. The EPA is establishing an eight-year interim period 

over which states must achieve the full required reductions to 

meet the CO2 performance rates, and this begins in 2022. This 

eight-year interim period from 2022 through 2029, is separated 

Deleted: and to make their 

Deleted: August 31

Deleted: over 
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into three steps, 2022-2024, 2025-2027, and 2028-2029, each 

associated with its own interim CO2 emission performance rates 

that states must meet, as explained in Section VI of this 

preamble. 

For the final emission guidelines, the EPA is revising 

the list of components required in a final state plan 

submittal to reflect: 1) components required for all state 

plan submittals; 2) components required for the emission 

standards approach; and 3) components required for the 

state measures approach. The revised list of components 

also reflects the approvability criteria, which are no 

longer separate from the state plan submittal components. 

All state plans must include the following components:

• Description of the plan approach and geographic scope 

• Identification of the state’s CO2 interim period goal (for 

2022-2029), interim steps (interim step goal 1 for 2022-2024; 

interim step goal 2 for 2025-2027; interim step goal 3 for 2028-

2029) and final CO2 emission goal of 2030 and beyond 

• Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal 

• State recordkeeping and reporting requirements 

• Certification of hearing on state plan 

• Supporting documentation 

Also, in all state plans, as part of the supporting 

documentation, a state must include a description of how they 

considered reliability in developing its state plan. 

Deleted: Affected EGUs must achieve the final 

emission performance rates or equivalent 

statewide goals by 2030 and maintain that 

level thereafter.

Deleted: The EPA is further establishing, as 

part of the guidelines, timetables for states 

to submit their plans. Each state must use the 

established electronic submittal system to 

provide the EPA its complete plan submittal by 

August 31, 2016. However, if a state needs 

additional time to provide the EPA with a 

complete plan submittal, the state must 

provide an initial plan submittal by August 

31, 2016, that documents the reasons that more 

time is needed to provide a complete plan 

submittal and includes commitments to take 

concrete steps that will ensure that the state 

will submit a complete plan by August 31, 

2018. 

Deleted: state 

Deleted: A

Deleted: s

Deleted: their 

Deleted: required consultation with relevant 

ISOs/RTOs and/or planning/reliability 

authorities during plan development, including 

any recommendations and other comments 

provided by those authorities

Deleted: Further, the EPA is requiring that 

states provide, in their initial plan 

submittal, a summary of how they have been 

engaging with community stakeholders and how 

they intend to meaningfully engage with 

community stakeholders during the additional 

time (if an extension is granted) for 

development of the final plan. In their 

report, states must show how they identified 

low- income communities and communities of 

color with whom that they are conducting 

meaningful community engagement with in the 

state plan development process. For the final 

plan submittal, states must engage with all 

members of the public, including communities, 

during the complete plan development process 

pursuant to the public participation 

requirements of the implementing regulations. 
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State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard is quantifiable, 

non-duplicative, permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 

 If a state with affected EGUs does not submit a plan or if 

the EPA does not approve a state’s plan, then under CAA section 

111(d)(2)(A), the EPA must establish a plan for that state. A 

state that has no affected EGUs must document this in a formal 

letter submitted to the EPA by September 6, 2016. In the case of 

a tribe that has one or more affected EGUs in its area of Indian 

Deleted: August 31
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country,288 the tribe has the opportunity, but not the 

obligation, to establish a CAA section 111(d) plan for its area 

of Indian country. If a tribe with one or more affected EGUs 

located in its area of Indian country does not submit a plan or 

does not receive EPA approval of a submitted plan, the EPA has 

the responsibility to establish a CAA section 111(d) plan for 

that area if it determines that such a plan is necessary or 

appropriate. 

 During and following implementation of its plan, each state 

must demonstrate to the EPA that its affected EGUs are meeting 

the interim and final performance requirements included in this 

final rule through monitoring and reporting requirements. State 

plan requirements and flexibilities are described more fully in 

Section VIII of this preamble.

B. Legal Basis 

This rule is consistent with the requirements of CAA 

section 111(d) and the implementing regulations.289 As an initial 

 

288 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Power Plant; one on Ute lands, the 

Bonanza Power Plant; and one on Fort Mojave lands, the South 

Point Energy Center. The affected EGUs at the first three plants 

are coal-fired EGUs. The fourth affected EGU is an NGCC 

facility. 

289 Under CAA section 111(d), there is no requirement that the EPA 

make a finding that the emissions from existing sources that are 

the subject of regulation cause or contribute significantly to 
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matter, the EPA reasonably interprets the provisions identifying 

which air pollutants are covered under CAA section 111(d) to 

authorize the EPA to regulate CO2 from fossil fuel-fired EGUs. In 

addition, the EPA recognizes that CAA section 111(d) applies to 

sources that, if they were new sources, would be covered under a 

CAA section 111(b) rule. Concurrently with this rule, the EPA is 

finalizing a CAA section 111(b) rulemaking establishing 

standards of performance for CO2 emissions from new fossil fuelfired EGUs, from modified fossil fuel-fired EGUs, and from 

reconstructed fossil fuel-fired EGUs, and any of those sets of 

section 111(b) standards of performance provides the requisite 

predicate for this rulemaking. 

A key step in promulgating requirements under CAA section 

111(d)(1) is determining the “best system of emission reduction 

 

air pollution which may reasonably be anticipated to endanger 

public health or welfare. As predicates to promulgating 

regulations under CAA section 111(d) for existing sources, the 

EPA must make endangerment and cause-or-contribute-significantly 

findings for emissions from the source category, and the EPA 

must promulgate regulations for new sources in the source 

category. In the CAA section 111(b) rule for CO2 emissions for 

new affected EGUs that the EPA is promulgating concurrently with 

this rule, the EPA discusses the endangerment and cause-orcontribute-significantly findings and explains why the EPA has 

already made them for the affected EGU source categories so that 

the EPA is not required to make them for CO2 emissions from 

affected EGUs, and, in the alternative, why, if the EPA were 

required to make those findings, it was making them in that 

rulemaking.
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which ... the Administrator determines has been adequately 

demonstrated” (BSER) under CAA section 111(a)(1). It is clear by 

the terms of section 111(a)(1) and the implementing regulations 

for section 111(d) that the EPA is authorized to determine the 

BSER;290 accordingly, in this rulemaking, the EPA is determining 

the BSER. 

The EPA is finalizing the BSER for fossil fuel-fired EGUs 

based on building blocks 1, 2, and 3. Building block 1 includes 

operational improvements and equipment upgrades that the coalfired steam-generating EGUs in the state may undertake to 

improve their heat rate. It qualifies as part of the BSER 

because it improves the carbon intensity of the affected EGUs in 

generating electricity through actions the affected sources may 

undertake that are adequately demonstrated and whose cost is 

“reasonable.” Building blocks 2 and 3 include increases in lowor zero-emitting generation which substitute for generation from 

the affected EGUs and thereby reduce CO2 emissions from those 

sources. All of these measures are components of a “system of 

emission reduction” for the affected EGUs because they entail 

actions that the affected EGUs may themselves undertake that 

have the effect of reducing their emissions. Further, these 

 

290 The EPA is not re-opening that interpretation in this 

rulemaking. 
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measures meet the criteria in CAA section 111(a)(1) and the case 

law for the “best” system of emission reduction that is 

“adequately demonstrated” because they achieve the appropriate 

level of reductions, their cost is “reasonable,” they do not 

have adverse non-air quality health and environmental impacts or 

impose adverse energy requirements, and they are each wellestablished among affected EGUs. It should be emphasized that 

these measures are consistent with current trends in the 

electricity sector. 

Building blocks 2 and 3 include reduced generation from the 

fossil fuel-fired EGUs because that is a step in the process of 

substituting lower- or zero-emitting generation for higheremitting generation. In addition, states should be expected to 

allow their affected EGUs to trade rate-based emission credits 

or mass-based emission allowances (trading) because trading is 

well-established for this industry and has the effect of 

focusing costs on the affected EGUs for which reducing emissions 

is most cost-effective. Because trading facilitates 

implementation of the building blocks and may help to optimize 

cost-effectiveness, trading is within the BSER as well. 

As a result, an affected EGU has a set of choices for 

achieving its emission standards. It can achieve a rate-based 

standard through a set of actions that implement the building 
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block 1 measures and that implement the building block 2 and 3 

measures through a set of actions that range from purchasing 

full or partial interest in existing NGCC or new renewable 

energy assets to purchasing emission rate credits that represent 

the environmental attributes of increased NGCC generation or new 

renewable generation. In addition, the affected EGU may reduce 

its generation and thereby reduce the extent that it needs to 

implement the building blocks. The affected EGU may also 

purchase rate-based emission credits from other affected EGUs. 

If the state chooses to impose a mass-based emission standard, 

the affected EGU may implement building block 1 measures, 

purchase mass-based emission allowances from other affected 

EGUs, or reduce its generation. In light of the available 

sources of lower- and zero-emitting replacement generation, this 

approach would achieve an appropriate level of emission 

reductions and maintain the reliability of the electricity 

system. 

With the promulgation of the emission guidelines, each 

state must develop and submit a plan to achieve the CO2 emission 

performance rates established by the EPA or the equivalent 

statewide rate-based or mass-based goal provided by the EPA in 

this rule. The EPA interprets CAA section 111(d) to allow states 

to establish standards of performance and provide for their 

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implementation and enforcement through either the “emission 

standards” or the “state measures” plan type. In the case of the 

“emission standards” plan type, the emission standards establish 

standards of performance, and the other components of the plan 

provide for their implementation and enforcement. In the case of 

the “state measures” plan type, –the state submits a plan that 

relies upon one or more measures that are only enforceable as a 

matter of state law that will in conjunction with any emission 

standards on affected EGUs result in the achievement of the 

applicable performance rates or state goals by the affected 

EGUs. Under the state measures plan type, states must also 

submit a federally enforceable backstop and a mechanism that 

would trigger implementation of the backstop; therefore, in a 

state measures plan, the standards of performance take the form 

of the backstop, the trigger mechanism provides for the 

implementation of such backstop, and the other required 

components of the plan provide for implementation and 

enforcement of the standards of performance. 

 These two types of state plans and their respective 

approaches, which could be implemented on a single-state or 

multi-state basis, allow states to meet the statutory 

requirements of section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 

Deleted: in which, 

Deleted: standards of performance in the form 

of

Deleted: a set of programs or 

Deleted: to be implemented within the state 

that would not be federally enforceable

Deleted: , plus

Deleted: –

Deleted: a federally enforceable 

Deleted: also 
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have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. It should be noted that 

both state plan types allow the state flexibility in assigning 

the emission performance obligations to its affected EGUs in the 

form of standards of performance as long as the required 

emission performance level is met. Both plan types harness the 

efficiencies of emission reduction opportunities in the 

interconnected electricity system and are fully consistent with 

the principles of cooperative federalism that underlie the Clean 

Air Act generally and CAA section 111(d) particularly. That is, 

both plan types achieve the emission performance requirements 

through the vehicle of a state plan, and provide each state 

significant flexibility to take local circumstances and state 

policy goals into account in determining how to reduce emissions 

from its affected sources, as long as the plan meets minimum 

federal requirements. 

Both state plan types, and the standards of performance for 

the affected EGUs that the states will establish through the 

state plan process, are consistent with the applicable CAA 

section 111 provisions. A state has discretion in determining 

the appropriate measures to rely upon for its plan. The state 

may adopt measures that assure the achievement of the requisite 

CO2 emission performance rate or state goal by the affected EGUs, 
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and is not limited to the measures that the EPA identifies as 

part of the BSER. 

 In this rulemaking, the EPA establishes reasonable 

deadlines for state plan submission. Under CAA section 

111(d)(1), state plans must “provide for implementation and 

enforcement” of the standards of performance, and under CAA 

section 111(d)(2), the state plans must be “satisfactory” for 

the EPA to approve them. In this rulemaking, the EPA is 

finalizing the criteria that the state plans must meet under 

these requirements. 

 The EPA discusses its legal interpretation in more detail 

in other parts of this preamble and provides additional 

information about certain issues in the Legal Memorandum 

included in the docket for this rulemaking. 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Source Categories 

A. EPA’s Authority under CAA Section 111(d) 

EPA’s authority for this rule is CAA section 111(d). CAA 

section 111(d) provides that the EPA will promulgate regulations 

under which each state will establish standards of performance 

for existing sources for any air pollutant that meets two 

criteria. First, CAA section 111(d) applies to air pollutants 

that are not regulated as a criteria pollutant under section 108 

Deleted: discusses 

Deleted: in more detail 
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or as a hazardous air pollutant (HAP) under CAA section 112. 42 

U.S.C. 7411(d)(1)(A)(i).291 Second, section 111(d) applies only 

to air pollutants for which the existing source would be 

regulated under section 111 if it were a new source. 42 U.S.C. 

7411(d)(1)(A)(ii). Here, carbon dioxide (CO2) meets both 

criteria: (1) it is not a criteria pollutant regulated under 

section 108 nor a HAP regulated under CAA section 112, and (2) 

CO2 emissions from new power plants (including newly constructed, 

modified and reconstructed power plants) are regulated under the 

CAA section 111(b) rule that is being finalized along with this 

rule. 

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority 

CAA section 111(d) contains an exclusion that limits the 

regulation under CAA section 111(d) of air pollutants that are 

regulated under CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i). 

This “Section 112 Exclusion” in CAA section 111(d) was the 

subject of a significant number of comments based on two 

differing amendments to this exclusion enacted in the 1990 CAA 

Amendments. As discussed in more detail below, the House and the 

Senate each initially passed different amendments to the Section 

 

291 Section 111(d) might be read to apply to HAP under certain 

circumstances. However, because carbon dioxide is not a HAP, 

this issue does not need to be resolved in the context of this 

rule.

Deleted: 

Deleted: published today
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112 Exclusion and both amendments were ultimately passed by both 

houses and signed into law. In 2005, in connection with the 

Clean Air Mercury Rule (CAMR), the EPA discussed the agency’s 

interpretation of the Section 112 Exclusion in light of these 

two differing amendments and concluded that the two amendments 

were in conflict and that the provision should be read as 

follows to give both amendments meaning: where a source category 

has been regulated under CAA section 112, a CAA section 111(d) 

standard of performance cannot be established to address any HAP 

listed under CAA section 112(b) that may be emitted from that 

particular source category. See 70 FR 15994, 16029-32 (March 29, 

2005). 

 In June 2014, the EPA presented this previous 

interpretation along with the proposed rule and requested 

comment on it. The EPA received numerous comments on its 

previous interpretation, including comments on the proper 

interpretation and effect of each of the two differing 

amendments, and whether the Section 112 Exclusion should be read 

to mean that the EPA’s regulation of HAP from power plants under 

CAA section 112 bars the EPA from establishing CAA section 

111(d) regulations covering CO2 emissions from power plants. In 

particular, many comments focused on two specific issues. 

First, some commenters -- including some industry and state 

Deleted: e

Deleted: ,

Deleted: , and should be interpreted as follows

Deleted: 0
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commenters that had previously endorsed the EPA’s interpretation 

of the Section 112 Exclusion in other contexts292 -- argued that 

the EPA’s 2005 interpretation was in error because it allowed 

the regulation of certain pollutants from source categories 

under CAA section 111(d) when those source categories were also 

regulated for different pollutants under CAA section 112. 

Second, some commenters argued that the EPA’s previous 

interpretation of the House amendment (as originally represented 

in 2005 at 70 FR at 16029-30) was in error because it improperly 

read that amendment as focusing on whether a source category was 

regulated under CAA section 112 rather than on whether the air 

pollutant was regulated under CAA section 112, and that improper 

reading lead to an interpretation that was inconsistent with the 

structure and purpose of the CAA. 

In light of the comments, the EPA has reconsidered its 

previous interpretation of the Section 112 Exclusion and, in 

particular, considered whether the exclusion precludes the 

 

292 For example, in the CAMR litigation (State of New Jersey v. 

EPA, No. 05-1097 (D.C. Cir.), the joint brief filed by a group 

of intervenors and an amicus (including six states and the West 

Virginia Department of Environmental Protection, and Utility Air 

Regulatory Group and nine other industry entities) stated that 

the EPA had interpreted section 111(d) in light of the two 

different amendments and that the EPA’s interpretation was “a 

reasoned way to reconcile the conflicting language and the Court 

should defer to the EPA’s interpretation.” Joint Brief of State 

Respondent-Intervenors, Industry Respondent-Intervernors, and 

State Amicus, filed May 18, 2007, at 25. 

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regulation under CAA section 111(d) of CO2 from power plants 

given that power plants are regulated for certain HAP under CAA 

section 112. On this issue, the EPA has concluded that the two 

differing amendments are not properly read as conflicting. 

Instead, the House amendment and the Senate Amendment should 

each be read to mean the same in the context presented by this 

rule: that the Section 112 Exclusion does not bar the regulation 

under CAA section 111(d) of non-HAP from a source category, 

regardless of whether that source category is subject to 

standards for HAP under CAA section 112. In reaching this 

conclusion, the EPA has revised its previous interpretation of 

the House amendment, as discussed below. 

1. Structure of the CAA and Pre-1990 Section 112 Exclusion 

The Clean Air Act sets out a comprehensive scheme for air 

pollution control, addressing three general categories of 

pollutants emitted from stationary sources: (1) criteria 

pollutants (which are addressed in sections 108-110); (2) 

hazardous pollutants (which are addressed under section 112); 

and (3) “pollutants that are (or may be) harmful to public 

health or welfare but are not or cannot be controlled under 

sections 108-110 or 112.” 40 Fed. Reg. 53,340 (Nov. 17, 1975). 

Six “criteria” pollutants are regulated under sections 108-

110. These are pollutants that the Administrator has concluded 

Deleted: is

Deleted: any 

Deleted: may be 

Deleted: The EPA’s analysis is entitled to 

deference under the principles established in 

Chevron v. NRDC, 467 U.S. 837 (1984). See 

White Stallion Energy v. EPA, 748 F.3d 1222, 

1235 (D.C. Cir. 2014) (a revision to an agency 

interpretation is reviewed under the Chevron 

framework. Under that framework, the revised 

interpretation will be upheld if the court 

finds that it “is permissible under the 

statute, that there are good reasons for it, 

and that the agency believes it to be 

better.”) (quoting FCC v. Fox Television 

Stations, Inc., 556 U.S. 502, 515 (2009)).293 

The EPA’s revised interpretation is discussed 

below. ¶
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“cause or contribute to air pollution which may reasonably be 

anticipated to endanger public health or welfare;” “the presence 

of which in the ambient air results from numerous and diverse 

mobile or stationary sources;” and for which the Administrator 

has issued, or plans to issue, “air quality criteria. 42 U.S.C. 

§7408(a)(1). Once the EPA issues air quality criteria for such 

pollutants, the Administrator must propose primary National 

Ambient Air Quality Standards (NAAQS) for them, set at levels 

“requisite to protect the public health” with an “adequate 

margin of safety. 42 U.S.C. § 7409(a)-(b). States must then 

adopt plans for implementing NAAQS. 42 U.S.C. § 7410. 

Hazardous air pollutants are regulated under CAA section 

112 and include the pollutants listed by Congress in section 

112(b)(1) and other pollutants that the EPA lists under sections 

112(b)(2) and (b)(3). CAA section 112 further provides that the 

EPA will publish and revise a list of “major” and “area” source 

categories of hazardous pollutants, and then establish emissions 

standards for hazardous air pollutants emitted by sources within 

each listed category. 42 U.S.C. § 7412(c)(1) & (2). 

 CAA section 111, 42 U.S.C. § 7411, is the third part of the 

CAA’s structure for regulating stationary sources. Section 111 

has two main components. First, section 111(b) requires the EPA 

to promulgate federal “standards of performance” addressing new

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Deleted: CAA s

Deleted: CAA 
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stationary sources that cause or contribute significantly to 

“air pollution which may reasonably be anticipated to endanger 

public health or welfare.” 42 U.S.C. § 7411(b)(1)(A). Once the 

EPA has set new source standards addressing emissions of a 

particular pollutant under CAA section 111(b), CAA section 

111(d) provides that the EPA will promulgate regulations 

requiring states to establish standards of performance for 

existing stationary sources of the same pollutant. 42 U.S.C. § 

7411(d)(1). 

Together, the criteria pollutant/NAAQS provisions in 

sections 108-110, the hazardous air pollutant provisions in 

section 112, and performance standard provisions in section 111 

constitute a comprehensive scheme to regulate air pollutants 

with ““no gaps in control activities pertaining to stationary 

source emissions that pose any significant danger to public 

health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 294 

The specific role of CAA section 111(d) in this structure 

can be seen in CAA subsection 111(d)(1)(A)(i), which provides 

that regulation under CAA section 111(d) regulation of 

pollutants is intended to cover pollutants that are not 

 

294 In subsequent CAA amendments, Congress has maintained this 

three-part scheme, but supplemented it with the Preservation of 

Significant Deterioration (PSD) program, the Acid Rain Program 

and the Regional Haze program. 
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regulated under either the criteria pollutant/NAAQS provisions 

or the hazardous air pollutants regulated under section 112. 

Prior to 1990, this limitation was laid out in plain language, 

which stated that CAA section 111(d) regulation applied to “any 

air pollutant... for which air quality criteria have not been 

issued or which is not included on a list published under 

section [108(a)] or [112(b)(1)(A)].” This plain language 

demonstrated that section 111(d) is designed to regulate 

pollutants from existing sources that fall in the gap not 

covered by the criteria pollutant provisions and the hazardous 

air pollutant provisions. 

This gap-filling purpose can be seen in the early 

legislative history of the CAA. As originally enacted in the 

1970 CAA, the precursor to CAA section 111 (which was originally 

section 114) was described as covering pollutants that would not 

be controlled by the criteria pollutant provisions or the 

hazardous air pollutant provisions. See S. Committee Rep. to 

accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 

(“It should be noted that the emission standards for pollutants 

which cannot be considered hazardous (as defined in section 115 

[which later became section 112]) could be established under 

section 114 [later, section 111]. Thus, there should be no gaps 

in control activities pertaining to stationary source emissions 

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that pose any significant danger to public health or welfare.”); 

Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 227 (“[T]he bill [in section 114] 

provides the Secretary with the authority to set emission 

standards for selected pollutants which cannot be controlled 

through the ambient air quality standards and which are not 

hazardous substances.”). 

2. The 1990 Amendments to the Section 112 Exclusion 

The Act was amended extensively in 1990. Among other 

things, Congress sought to accelerate the EPA’s regulation of 

hazardous pollutants under section 112. To that end, Congress 

established a lengthy list of hazardous air pollutants; set 

criteria for listing “source categories” of such pollutants; and 

required the EPA to establish standards for each listed source 

category’s hazardous pollutant emissions. 42 U.S.C. § 7412(b), 

(c) and (d). In the course of overhauling the regulation of 

hazardous air pollutants under section 112, Congress needed to 

edit section 111(d)’s reference to section 112(b)(1)(A), which 

was to be eliminated as part of the revisions to section 112. 

To address the obsolete cross-reference to section 

7412(b)(1)(A), Congress passed two differing amendments – one 

from the Senate and one from the House – that were never 

reconciled in conference. The Senate amendment replaced the 

Deleted: or subcategory

Deleted: (a), (b)(1) & (2), & (d)(1)

Deleted: , which cross-referenced a provision 

of old section 112 that was to be eliminated –

Deleted: T

Deleted: House

Deleted: Senate

Moved down [8]: The House amendment replaced 

the cross-reference with the phrase “emitted 

from a source category which is regulated 

under section [112].” Pub. L. No. 101-549, § 

108(g), 104 Stat. 2399, 2467 (1990). 
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cross reference to old section 112(b)(1)(A) with a crossreference to new section 112. Pub. L. No. 101-549, § 302(a), 104 

Stat. 2399, 2574 (1990). The House amendment replaced the crossreference with the phrase “emitted from a source category which 

is regulated under section [112].” Pub. L. No. 101-549, § 

108(g), 104 Stat. 2399, 2467 (1990).295 Both amendments were 

enacted into law, and thus both are part of the current CAA. To 

 

295 Originally, when the House bill to amend the CAA was 

introduced in January 1989, it focused on amendments to control 

HAP. Of particular note, the amendments to section 112 included 

a provision that excluded regulation under section 112 of “[a]ny 

air pollutant which is included on the list under section 

108(a), or which is regulated for a source category under 

section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA Legist. 

Hist. at 4046. In other words, the Section 112 Exclusion in 

section 111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be called a 

“Section 111(d) Exclusion” in section 112. This is significant 

because the “source category” phrasing in the original January 

1989 text with respect to section 111(d) makes sense, whereas 

the “source category” phrasing in the 1990 House amendment does 

not. When referring to the scope of what is regulated under 

section 111(d), it makes sense to frame that scope with respect 

to source categories, because section 111 regulation begins with 

the identification of source categories under section 

111(b)(1)(A). By contrast, regulation under section 112 begins 

with the identification of HAP under section 112(b); the listing 

of source categories under section 112(c) is secondary to the 

listing of HAP. From this history, and in light of this 

difference between the scope of what is regulated in sections 

111 and 112, it is reasonable to conclude that the “source 

category” phrasing is a legacy from the original 1989 bill—that 

is, when converting the 1989 text into the Section 112 Exclusion 

that we see in the 1990 House amendment, the legislative 

drafters continued to use phrasing based on “source category” 

notwithstanding that this phrasing created a mismatch with the 

way that the scope of section 112 regulation is determined.

Deleted: same text 

Moved (insertion) [8]

Deleted: are 
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determine how this provision is properly applied in light of 

the two differing amendments, we first look at the Senate 

amendment, then at the House amendment, then discuss how the two 

amendments are properly read together. 

3. The Senate Amendment is Clear and Unambiguous 

 Unlike the ambiguous amendment to CAA section 111(d) in the 

House amendment (discussed below), the Senate amendment is 

straightforward and unambiguous. It maintained the pre-1990 

meaning of the Section 112 Exclusion by simply substituting 

“section 112(b)” for the prior cross-reference to “section 

112(b)(1)(A).” Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 

2574 (1990). So amended, section 111(d) mandates that the EPA 

require states to submit plans establishing standards for “any 

air pollutant . . . which is not included on a list published 

under section [108(a)] or section [112(b)].” Thus, the Section 

112 Exclusion resulting from the Senate amendment would preclude 

section 111(d) regulation of HAP emission but would not preclude 

section 111(d) regulation of CO2 emissions from power plants 

notwithstanding that power plants are also regulated for HAP 

under CAA section 112 under the MATS rule. 

 Some commenters have argued that the Senate amendment 

should be given no effect, because only the House amendment is 

shown in the U.S. Code, and because the Senate amendments 

appeared under the heading “conforming amendments,” and for 

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Deleted: the EPA from regulating 
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various other reasons. The EPA disagrees. The Senate amendment, 

like the House amendment, was enacted into law as part of the 

1990 CAA amendments, and must be given effect. 

 First, that the U.S. Code only reflects the House amendment 

does not change the fact that both amendments were signed into 

law as part of the 1990 Amendments, as shown in the Statutes at 

Large. Pub. L. No. 101-549, §§ 108(g) and 302(a), 104 Stat. 

2399, 2467, 2574 (1990). Where there is a conflict between the 

U.S. Code and the Statutes at Large, the latter controls. See 1 

U.S.C. §§ 112 & 204(a); Stephan v. United States, 319 U.S. 423, 

426 (1943) (“the Code cannot prevail over the Statutes at Large 

when the two are inconsistent”); Five Flags Pipe Line Co. v. 

Dep’t of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) (“[W]here 

the language of the Statutes at Large conflicts with the 

language in the United States Code that has not been enacted 

into positive law, the language of the Statutes at Large 

controls.”). 

 Second, the “conforming” label is irrelevant. A 

“conforming” amendment may be either substantive or nonsubstantive. Burgess v. United States, 553 U.S. 124, 135 

(2008). And while the House Amendment contains more words, it 

also qualifies as a “conforming amendment” under the definition 

in the Senate Legislative Drafting Manual, Section 126(b)(2) 

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(defining “conforming amendments” as those “necessitated by the 

substantive amendments of provisions of the bill”). Here, both 

the House and Senate amendments were “necessitated by” Congress’ 

revisions to section 112 in the 1990 CAA Amendment, which 

included the deletion of old section 112(b)(1)(A). Thus, the 

House’s amendment is no less “conforming” than the Senate’s, and 

the heading under which it was enacted (“Miscellaneous 

Guidance”) does not suggest any more importance than “Conforming 

Amendments.” In any event, courts gives full effect to 

conforming amendments, see Washington Hosp. Ctr. v. Bowen, 795 

F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate 

Amendment nor the House amendment can be ignored. 

Third, the legislative history of the Senate amendment 

supports the conclusion that the substitution of the updated 

cross-reference was not a mindless, ministerial decision, but 

reflected a decision to choose an update of the cross reference 

over the text that was inserted into the Section 112 Exclusion 

by the House amendment. In mid-1989, the House and Senate 

introduced identical bills (H.R. 3030 and S. 1490, respectively) 

to provide for “miscellaneous” changes to the CAA. In both the 

Senate and House bills as they were introduced in mid-1989, the 

Section 112 Exclusion was to be amended by taking out “or 

112(b)(1)(A)” and inserting “or emitted from a source category 
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which is regulated under section 112.” H.R. 3030, as introduced, 

101st Cong. § 108 (Jul. 27, 1989); S. 1490, as introduced, 101st 

Cong. § 108 (Aug. 3, 1989). See 1990 CAA Legis. Hist. at 3857 

(noting that H.R. 3030 and S.1490, as introduced, were the 

same). Although S. 1490 was identical to H.R. 3030 when they 

were introduced, the Senate reported a vastly different bill 

(S.1630) at the end of 1989. See S. 1630, as reported (Dec. 20, 

1989), 1990 CAA Legis. Hist. at 7906. As reported and eventually 

passed, S. 1630 did not contain the text in the House amendment 

(“or emitted from a source category which is regulated under 

section 112”) and instead contained the substitution of cross 

references (changing “section 112(b)(1)(A)” to “section 112(b)”) 

as a “conforming” amendment. See S. 1630, as reported, 101st

Cong. § 305, 1990 CAA Legis. Hist. at 8153; S. 1630, as passed, 

§ 305 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 4534. Though the 

EPA is not aware of any statements in the legislative history 

that expressly explain the Senate’s intent in making these 

changes to the Senate bill, the sequence itself supports the 

conclusion that the Senate’s substitution reflects a decision to 

retain the pre-1990 approach of using a cross-reference to 

112(b) to define the scope of the Section 112 Exclusion. Whether 

the difference in approach between the final Senate amendment in 

S.1630 and the House amendment in H.R. 3030 creates a 
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substantive difference or are simply two different means of 

achieving the same end depends on what interpretation one gives 

to the text in the House amendment, which we turn to next. 

4. The House amendment 

a. The House amendment is ambiguous. Before looking at the 

specific text of the House amendment, it is helpful to review 

some principles of statutory interpretation. First, statutory 

interpretation begins with the text, but does not end there. As 

the D.C. Circuit Court has explained, “[t]he literal language of 

a provision taken out of context cannot provide conclusive proof 

of congressional intent.” Bell Atlantic Telephone Cos. v. 

F.C.C., 131 F.3d 1044, 1047 (D.C. Cir. 1977). See King v. 

Burwell, 2015 U.S. LEXIS 4248, *19(“[O]ftentimes the ‘meaning—or 

ambiguity—of certain words or phrases may only become evident 

when placed in context.’ Brown & Williamson, 529 U. S., at 132, 

120 S. Ct. 1291, 146 L. Ed. 2d 121. So when deciding whether the 

language is plain, we must read the words ‘in their context and 

with a view to their place in the overall statutory scheme.’ 

Id., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 121 (internal 

quotation marks omitted). Our duty, after all, is ‘to construe 

statutes, not isolated provisions.’ Graham County Soil and Water 

Conservation Dist. v. United States ex rel. Wilson, 559 U. S. 

280, 290, 130 S. Ct. 1396, 176 L. Ed. 2d 225 (2010) (internal 

Deleted: A

Deleted: A

Deleted: A

Deleted: S
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quotation marks omitted).”). Further,a proper reading of 

statutory text “must employ all the tools of statutory 

interpretation, including text, structure, purpose, and 

legislative history.” Loving v. I.R.S., 742 F.3d 1013, 1016 

(D.C. Cir. 2014) (internal quotation omitted). See, also, 

Robinson v. Shell Oil Co., 519 U.S. 337, 341 (1997) (statutory 

interpretation involves consideration of “the language itself, 

the specific context in which that language is used, and the 

broader context of the statute as a whole.”). Moreover, one 

principle of statutory construction that has particular 

application here is that provisions in a statute should be read 

to be consistent, rather than conflicting, if possible. This 

principle was discussed in the recent case of Scialabba v. 

Cuellar De Osorio, 134 S. Ct. 2191, 2214 (concurring opinion by 

Chief Justice Roberts and Justice Scalia), 2219-2220 (dissent by 

Justices Sotomayor, Breyer and Thomas)(2014). As Justice 

Sotomayor wrote (at 134 S. Ct. at 2220): 

“We do not lightly presume that Congress has legislated in selfcontradicting terms. See A. Scalia & B. Garner, Reading Law: The 

Interpretation of Legal Texts 180 (2012) (“The provisions of a 

text should be interpreted in a way that renders them 

compatible, not contradictory. . . . [T]here can be no 

justification for needlessly rendering provisions in conflict if 

they can be interpreted harmoniously”). *** Thus, time and again 

we have stressed our duty to “fit, if possible, all parts [of a 

statute] into [a] harmonious whole.” FTC v. Mandel Brothers, 

Inc., 359 U.S. 385, 389, 79 S. Ct. 818, 3 L. Ed. 2d 893 (1959); 

see also Morton v. Mancari, 417 U.S. 535, 551, 94 S. Ct. 2474, 

41 L. Ed. 2d 290 (1974) (when two provisions “are capable of coDeleted: Rather, 

Commented [A15]: ? 
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existence, it is the duty of the courts . . . to regard each as 

effective”). In reviewing an agency’s construction of a statute, 

courts “must,” we have emphasized, “interpret the statute ‘as a 

. . . coherent regulatory scheme’” rather than an internally 

inconsistent muddle, at war with itself and defective from the 

day it was written. Brown & Williamson, 529 U.S., at 133, 120 S. 

Ct. 1291, 146 L. Ed. 2d 121. 

As amended by the House, CAA section 111(d)(1)(A)(i) limits 

CAA section 111(d) to any air pollutant “for which air quality 

criteria have not been issued or which is not included on a list 

published under section 7408(a) of this title or emitted from a 

source category which is regulated under section 7412 of this 

title . . .” This statutory text is ambiguous and subject to 

numerous possible readings. Certain possible readings are 

based on section 111(d)’s literal text, but these readings are 

not reasonable and no one has advocated that either of those 

readings be adopted. 

 First, the text of the House-amended version of CAA section 

111(d) could be read literally as authorizing the regulation of 

any pollutant that is not a criteria pollutant. This reading 

arises if one focuses on the use of “or” to join the three 

clauses: 

The Administrator shall prescribe regulations . . . under 

which each State shall submit to the Administrator a plan 

which establishes standards of performance for any existing 

source for any air pollutant [1] for which air quality 

criteria have not been issued or [2] which is not included 

on a list published under section 7408(a) of this title or

[3] emitted from a source category which is regulated under 

section 7412 of this title . . . . 

Deleted: ”

Deleted: Two

Deleted: its 

Deleted: neither of those 

Deleted: is 

Deleted: Further, there are additional 

interpretations that arise from different 

readings of the ambiguous phrases and 

structure created by the House amendment. As 

discussed below, two of these additional 

interpretations are unreasonable, while three 

are reasonable. 

Deleted: literal 

Deleted: interpretation becomes apparent 
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42 U.S.C. § 7411(d)(1) (emphasis and internal numbering added). 

Because the text contains the conjunction “or” rather than “and” 

between the three clauses, a literal reading could read the 

three clauses as alternatives, rather than requirements to be 

imposed simultaneously. In other words, one literal reading of 

the language of section 111(d) provides that the Administrator 

may require states to establish standards for an air pollutant 

so long as either air quality criteria have not been established 

for that pollutant, or one of the remaining criteria is met. If 

this reading were applied to determine whether the EPA may 

promulgate section 111(d) regulations for CO2 from power plants, 

the result would be that CO2 from power plants coule be 

regulated under section 111(b) because air quality criteria have 

not been issued for CO2 and therefore whether CO2 or power plants 

are regulated under section 112 would be irrelevant. This 

interpretation, however, is not a reasonable reading of the 

statute because, among other reasons, it gives little or no 

meaning to the limitation covering hazardous air pollutants that 

are regulated under CAA section 112 and thus is contrary to both 

the CAA’s comprehensive scheme created by the three sets of 

provisions (under which CAA section 111 is not intended to 

duplicate the regulation of pollutants regulated under 

section112) and the principle of statutory construction that 

Deleted: literal 

Deleted: regulate 

Deleted: under section 111(d)

Deleted: 

Deleted: analysis would be (a) 

Deleted: ,

Deleted: (b) 

Deleted: is 

Deleted: . , and (c) CO2 emissions from power 

plants may be regulated under section 111(d)
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text should not be construed such that a provision does not have 

effect. 

A second literal reading of CAA section 111(d) as revised 

by the House amendment focuses on the lack of a negative before 

the third clause. That is, unlike the first and second clauses 

that each contain negative phrases (either “has not been issued” 

or “which is not included”), the third clause does not. One 

could presume that the negative from the second clause was 

intended to carry over, implicitly inserting another “which is 

not” before “emitted from a source category which is regulated 

under section [112].” But that is a presumption, and not the 

plain language of the statute. The text as amended by the House 

says that the EPA “shall” prescribe regulations for “any air 

pollutant . . . emitted from a source category which is 

regulated under section [112].” 42 U.S.C. § 7411(d)(1). Thus, 

CAA section 111(d)(1)(A)(i) could be read literally as providing 

for the regulation of emissions of pollutants if they are 

emitted from a source category that is regulated under CAA 

section 112. But, this second literal reading is not reasonable 

because it would provide for the regulation of a source’s HAP 

emissions under CAA section 111(d) when those same emissions 

were also subject to standards under CAA section 112. Thus, this 

reading would be contrary to Congress’s intent that CAA section 

Deleted: arises from 

Deleted: require standards 

Deleted: requiring EPA to regulate

Deleted: under section 111(d) if that source 

category 

Deleted: If this reading were applied to the 

question of the EPA’s authority for this rule, 

the result would be that the EPA not only has 

the authority to regulate CO2 from power 

plants, but became obligated to do so once 

power plants were regulated under section 112. 

Again, 

Deleted: interpretation 

Deleted: not only call for the regulation under 

CAA section 111(d) of pollutants that were not 

regulated under CAA section 112, but would 

also 

Deleted: the comprehensive scheme of the 

statute under which 
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111(d) regulation fill the gap between the other programs by 

covering pollutants that the other programs do not, but not 

duplicate the regulation of pollutants that the other programs 

cover. 

If one does presume that the “which is not” phrase is 

intended to carry over to the third clause, then CAA section 

111(d) regulation under the House amendment would be limited to 

“any air pollutant...which is not... emitted from a source category 

which is regulated under section [112].” Even with this 

presumption, however, the House amendment contains further 

ambiguities with respect to the phrases “a source category” and 

“regulated under section 112,” and how those phrases are used 

within the structure of the provision limiting what air 

pollutants may be regulated under CAA section 111(d). 

The phrase “regulated under section 112” is ambiguous. As 

the Supreme Court has explained in the context of other statutes 

using a variation of the word “regulate,” an agency must 

consider what is being regulated. See Rush Prudential HMO, Inc. 

v. Moran, 536 U.S. 355, 366 (2002) (It is necessary to “pars[e] 

. . . the ‘what’” of the term “regulates.”); UNUM Life Ins. Co. 

of Am. v. Ward, 526 U.S. 358, 363 (1999) (the term “‘regulates 

insurance’ . . . requires interpretation, for [its] meaning is 

not plain.”). Here, one possible reading is that the phase 

Deleted: is intended to 

Deleted: and 

Deleted: Turning now to the interpretation of 

the ambiguous phrases and structure created by 

the House amendment, i 

Deleted: T

Deleted: , first, because the sentence 

structure in the text does not make clear what 

that phrase is intended to modify. Young v. 

Community Nutrition Inst., 476 U.S. 974, 980-

81 (1986) (“As enemies of the dangling 

participle well know, the English language 

does not always force a writer to specify 

which of two possible objects is the one to 

which a modifying phrase relates.”) Second, a
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modifies the words “a source category” without regard to what 

pollutants are regulated under section 112, which then presents 

the issue of what meaning to give to the phrase “a source 

category.” 

Under this reading, and assuming the phrase “a source 

category” is read to mean the particular source category, the 

House amendment would preclude the regulation under CAA section 

111(d) of a specific source category for any pollutant if that 

source category has been regulated for any HAP under CAA section 

112.296 The effect of this reading would be to preclude the 

regulation of CO2 from power plants under CAA section 111(d) 

because power plants have been regulated for hazardous air 

pollutants under CAA section 112. This is the interpretation 

that the EPA applied to the House amendment in connection with 

the CAMR rule in 2005, when looking at the question of whether 

HAP can be regulated under CAA section 111(d) for a source 

category that is not regulated for HAP under section 112, and 

 

296 “A source category” could also be interpreted to mean “any 

source category.” Under this interpretation, CAA 111(d) 

regulation would be limited to air pollutants that are not 

emitted by any source category for which the EPA has issued 

standards for HAP under CAA section 112. This interpretation is 

not reasonable because it would effectively read CAA 111(d) out 

of the statute. Given the extensive list of source categories 

regulated under CAA 112 and the breadth of pollutants emitted by 

those categories collectively, literally all air pollutants 

would be barred from CAA 111(d) regulation under this 

interpretation.

Deleted: and leads to a third and fourth 

interpretation of the House amendment.

Deleted: U

Deleted: In this context, a third 

interpretation of the Section 112 Exclusions 

arises if one reads “a source category” to 

mean “any” source category. Under this third 

interpretation of the House amendment, CAA 

section 111(d) regulation is limited to air 

pollutants that are not emitted by any source 

category for which the EPA has issued 

standards for HAP under CAA section 112. But 

this interpretation would read CAA section 

111(d) out of the statute. Given the extensive 

list of source categories regulated under CAA 

section 112 and the breadth of the pollutants 

emitted by those categories collectively, 

literally all air pollutants would be barred 

from CAA section 111(d) regulation under this 

interpretation, because any given air 

pollutant is emitted by at least one source 

category for which the EPA has issued 

standards for HAP under the mandate of CAA 

section 112. Based on the principle that 

statutes should be interpreted such that all 

parts of it have meaning, see, e.g., Mountain 

States Tel. & Tel. v. Pueblo of Santa Anna, 

472 U.S. 237, 249 (1985), the EPA concludes 

this is not a reasonable interpretation of the 

House amendment.¶

A fourth interpretation would read the words 

“a source category” to mean the particular 

source category, again without regard to the 

scope of pollutants that are regulated under 

CAA section 112, and interpret the House 

amendment to 
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some commentors have advocated for this interpretation here. 

But, after considering all of the comments and reconsidering 

this interpretation, the EPA has concluded that this 

interpretation of the House amendment is not a reasonable 

reading because it would disrupt the comprehensive scheme for 

regulating existing sources created by the three sets of 

provisions covering criteria pollutants, hazardous air 

pollutants and the other pollutants that fall outside of those 

two programs and frustrate the role that section 111 is intended 

to play.297 Specifically, under this interpretation, the EPA 

could not regulate a source category’s emissions of hazardous 

air pollutants under CAA section 112, and then promulgate 

regulations for other pollutants from that source category under 

section 111(d).298 There is no reason to conclude that the House 

 

297 In assessing any interpretation of section 111(d), EPA must 

consider how the three main programs set forth in the CAA work 

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory 

interpretation must account for . . . the broader context of the 

statute as a whole”) (quotation omitted). 

298 Supporters of this interpretation have noted that the EPA 

could regulate power plants under both CAA section 111(d) and 

CAA section 112 if it regulated under section 111(d) first, 

before the Section 112 Exclusion is triggered. But that argument 

actually further demonstrates another reason why this 

interpretation is unreasonable. There is no basis for concluding 

that Congress intended to mandate that section 111(d) regulation 

occur first, nor is there any logical reason why the need to 

regulate under section 111(d) should be dependent on the timing 

of such regulation in relation to CAA 112 regulation of that 

source category.

Deleted: the Section 112 Exclusion as amended 

by just 

Deleted: fourth 

Deleted: both (a) 

Deleted: 

Deleted: (b) regulate that category’s 

Deleted: 
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amendment was intended to abandon the existing structure and 

relationship between the three programs in this way. Indeed, 

Congress expressly provided that regulation under CAA section 

112 was not to “diminish or replace the requirements of” the 

EPA’s regulation of non-hazardous pollutants under section 7411. 

See 42 U.S.C. § 7412(d)(7). Further, consistent with CAA 

section 112’s direction that EPA list “all categories and 

subcategories of major sources and area [aka, non-major] 

sources” of HAP and then establish CAA section 112 standards for 

those categories and subcategories, 42 U.S.C. §§ 7412(c)(1) and 

(c)(2), the EPA has listed and regulated over 140 categories of 

sources under CAA section 112. Thus, this reading would 

eviscerate the EPA’s authority under section 111(d) and prevent 

it serving as the gap-filling provision within the 

comprehensive scheme of the CAA as Congress intended.299 In 

 

299 Some commenters have stated that EPA could choose to regulate 

both HAP and non-HAP under section 111(d), and thus could 

regulate HAP without creating a gap. But this presumes that 

Congress intended EPA to have the choice of declining to 

regulate a section 112-listed source category for HAP under 

section 112, which is inconsistent with the mandatory language 

in section 112. See, e.g., section 112(d)(1)(“The Administrator 

shall promulgate regulations establishing emissions standards 

for each category or subcategory of major sources and area 

sources of hazardous air pollutants listed for regulation 

pursuant to subsection (c) of this section in accordance with 

the schedules provided in subsections (c) and (e) of this 

section.”). Moreover, given the prescriptive language that 

Congress added into section 112 concerning how to set standards 

Deleted: similar to the third reading above, 

Deleted: prevent 

Deleted: from

Deleted: 
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short, it is not reasonable to interpret the Section 112 

Exclusion in section 111(d) to mean that the existence of CAA 

section 112 standards covering hazardous pollutants from a 

source category would entirely eliminate regulation of nonhazardous emissions from that source category under section 

111(d). 301

a. The EPA’s Interpretation of the House Amendment. Having 

concluded that the interpretations discussed above are not 

reasonable, the EPA now turns to what it has concluded is the 

best, and sole reasonable, interpretation of the House 

amendment as it applies to the issue here. 

The EPA’s interpretation of the House amendment as applied 

to the issue presented in this rule is that the Section 112 

 

for HAP, see section 112(d)(2) and (d)(3), it is unreasonable to 

conclude that Congress intended that the EPA could simply choose 

to ignore the provisions in section 112 and instead regulate HAP 

for a section 112 listed source category under section 111(d).

301 Even if one were to determine that this interpretation were 

the proper reading of the House amendment that would not be the 

end of the analysis. Instead, that reading would create a 

conflict between the Senate amendment and the House amendment 

that would need to be resolved. In that event, the proper 

resolution of a conflict between the two amendments would be the 

analysis and conclusion discussed in the Proposed Rule’s legal 

memorandum (discussing EPA’s analysis in the CAMR rule at 70 FR 

15994, 16029-32): The two amendments must be read together so as 

to give some effect to each amendment and they are properly read 

together to provide that, where a source category is regulated 

under section 112, EPA may not establish regulations covering 

the HAP emissions from that source category under section 

111(d).

Deleted: For these reasons, and as further 

discussed [below/in the Response to Comments], 

Deleted: CAA 

Deleted: s

Deleted: e

Deleted: 300

Deleted: has identified three reasonable

Deleted: s

Deleted: First, one could interpret 

Deleted: to mean 

Deleted: 
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Exclusion excludes the regulation of HAP if the source category 

at issue is regulated under CAA section 112, but does not 

exclude the regulation of other pollutants, regardless of 

whether that source category is subject to CAA section 112 

standards. This interpretation reads the phrase “regulated under 

section 112” as modifying the words “source category” (as does 

the interpretation discussed above) but also recognizes that the 

phrase “regulated under section 112” refers only to the 

regulation of HAP emissions. In other words, the EPA’s 

interpretation recognizes that source categories “regulated 

under section 112” are not regulated by CAA section 112 with 

respect to all pollutants, but only with respect to HAP. Thus, 

it is reasonable to interpret the House amendment of the Section 

112 Exclusion as only excluding the regulation of HAP emissions 

under CAA section 111(d) and only when that source category is 

regulated under CAA section 112. We note that this 

interpretation of the House amendment alone is the same as the 

2005 CAMR interpretation of the two amendments combined: where a 

source category has been regulated under CAA section 112, a CAA 

section 111(d) standard of performance cannot be established to 

address any HAP listed under CAA section 112(b) that may be 

emitted from that particular source category. See 70 FR 15994, 

16029-30 (March 29, 2005). 

Deleted: fourth 

Deleted: this 

Deleted: first reasonable 
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There are a number of reasons why the EPA’s interpretation 

is reasonable and avoids the issues discussed above. 

First, the EPA’s interpretation reads the House amendment 

to the Section 112 Exclusion as determining the scope of what 

air pollutants are to be regulated under CAA section 111(d), as 

opposed to creating a wholesale exclusion for source categories. 

The other text in subsections 111(d)(1)(A)(i) and (ii) modify 

the phrase “any air pollutant.” Thus, reading the Section 112 

Exclusion to also address the question of what air pollutants 

may be regulated under CAA section 111(d) is consistent with the 

overall structure and focus of section 111(d)(1)(A)e. 

Second, the EPA’s interpretation furthers – rather than 

undermines – the purpose of CAA section 111(d) within the longstanding structure of the CAA. That is, this interpretation 

supports the comprehensive structure for regulating various 

pollutants from existing sources under the criteria 

pollutant/NAAQS program under sections 108-110, the HAP program 

under section 112, and other pollutants under section 111(d), 

and avoids creating a gap in that structure. See King v. Burwell, 

2015 U.S. LEXIS 4248, *28 (2015)(“A provision that may seem 

ambiguous in isolation is often clarified by the remainder of 

the statutory scheme . . . because only one of the permissible 

Deleted: Second, one could interpret the House 

amendment to mean that the Section 112 

Exclusion always excludes the regulation of 

CAA section 112 pollutants, but does not 

exclude other pollutants, and the scope of the 

exclusion is the same regardless of whether 

the source category is subject to standards 

under CAA section 112. This interpretation of 

the House amendment reads the phrase 

“regulated under section 112” as modifying 

“air pollutant” rather than “source category” 

and reads the phrase “emitted by a source 

category” as having minimal import because it 

is the remnant of phrasing that was originally 

intended to be an exclusion within CAA section 

112 for source categories regulated under 

section 111.302 A key distinction between this 

second reasonable interpretation and the first 

reasonable interpretation discussed above is 

that this second reasonable interpretation 

concludes that HAP can never be regulated 

under CAA section 111(d).

Deleted: Third, one could interpret the House 

amendment to mean that the Section 112 

Exclusion excludes all of the CAA section 112 

pollutants that have actually been regulated 

for at least one source category under CAA 

section 112, but does not exclude other 

pollutants (that is, pollutants that are not 

listed under CAA section 112). This third 

reasonable interpretation reads the phrase “a 

source category” as meaning “any” source 

category listed under section 112 and the 

phrase “regulated under section 112” in light 

of the fact that a source category is 

“regulated under 112” with respect to HAP and 

not other pollutants. Thus, under this third 

reasonable interpretation of the House 

amendment, the scope of the Section 112 

Exclusion does not cover non-HAP. ¶

Deleted: se three 

Deleted: s share a number of common reasons why 

they are

Deleted: all three of these reasonable

Deleted: s

Deleted: 

Deleted: do 

Deleted: nature of the t

Deleted: xt in which it appears

Deleted: all three reasonable 

Deleted: s

Deleted: ese 

Deleted: s
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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meanings produces a substantive effect that is compatible with 

the rest of the law.”) (quoting United Sav. Assn. of Tex. v. 

Timbers of Inwood Forest Associates, Ltd., 484 U. S. 365, 371, 

108 S. Ct. 626, 98 L. Ed. 2d 740 (1988)”) 

Third, by avoiding the creation of gaps in the statutory 

structure, the EPA’s interpretation is consistent with the 

legislative history demonstrating that Congress’s intent in the 

1990 CAA Amendments was to expand the EPA’s regulatory authority 

across the board, compelling the agency to regulate more 

pollutants, under more programs, more quickly.303 Conversely, the 

EPA is aware of no statement in the legislative history 

indicating that Congress simultaneously sought to restrict the 

EPA’s authority under CAA section 111(d) or to create gaps in 

 

303 See S. Rep. No. 101-228 at 133 (“There is now a broad 

consensus that the program to regulate hazardous air pollutants 

. . . should be restructured to provide the EPA with authority 

to regulate industrial and area sources of air pollution . . . 

in the near term”), reprinted in 5 A Legislative History of the 

Clean Air Act Amendments of 1990 (“Legis. Hist.”) 8338, 8473 

(Comm. Print 1993); S. Rep. No. 101-228 at 14 (“The bill gives 

significant authority to the Administrator in order to overcome 

the deficiencies in [the NAAQS program]”) & 123 (“Experience 

with the mobile source provisions in Title II of the Act has 

shown that the enforcement authorities . . . need to be 

strengthened and broadened . . .”), reprinted in 5 Legis. Hist. 

at 8354, 8463; H.R. Rep. No. 101-952 at 336-36, 340, 345 & 347 

(discussing enhancements to Act’s motor vehicle provisions, the 

EPA’s new authority to promulgate chemical accident prevention 

regulations, the enactment of the Title V permit program, and 

enhancements to the EPA’s enforcement authority), reprinted in 5 

Legis. Hist. at 1786, 1790, 1795, & 1997. 

Deleted: all three

Deleted: s

Deleted: are 

Deleted: the
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the comprehensive structure of the statute. If Congress had 

intended this amendment to make such a change, one would expect 

to see some indication of that in the legislative history. 

Fourth, when applied in the context of this rule, the EPA’s

interpretation of the House amendment is consistent with the 

Senate amendment. Thus, this interpretation avoids creating a 

conflict within the statute. See discussion above of Scialabba, 

134 S. Ct. 2191 at 2220 (citing and quoting, among other 

authorities, A. Scalia & B. Garner, Reading Law: The 

Interpretation of Legal Texts 180 (2012) (“The provisions of a 

text should be interpreted in a way that renders them 

compatible, not contradictory. . . . [T]here can be no 

justification for needlessly rendering provisions in conflict if 

they can be interpreted harmoniously”)). 

In sum, when this interpretation of the House amendment is 

applied in the context of this rule, the result is that the EPA 

may promulgate CAA section 111(d) regulations covering carbon 

dioxide emissions from existing power plants notwithstanding 

that power plants are regulated for their HAP emissions under 

CAA section 112. 

5. The Two Amendments Are Easily Reconciled And Can Be Given Full 

Effect 

Deleted: all three of these reasonable

Deleted: s

Deleted: are 

Deleted: ese

Deleted: s in this context

Deleted: and fulfill that principle of 

statutory construction

Deleted: either of these three reasonable 

Deleted: s

Deleted: each interpretation reaches the same 

result: 

Deleted: Thus, in the context of this rule, the 

EPA does not need to decide which of these 

three reasonable interpretations is better.
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Given that both the House and Senate amendments should be 

read individually as having the same meaning in the context 

presented in this rule, giving each amendment full effect is 

straight-forward: the Section 112 Exclusion in section 111(d) 

does not foreclose the regulation of non-HAP from a source 

category regardless of whether that source category is also 

regulated under CAA section 112. As applied here, the EPA has 

the authority to promulgate CAA boswellsection 111(d) 

regulations for CO2 from power plants notwithstanding that power 

plants are regulated for HAP under CAA section 112.

C. Authority to Regulate EGUs 

In a separate, concurrent action, the EPA is also 

finalizing a CAA section 111(b) rulemaking that regulates CO2

emissions from new, modified, and reconstructed EGUs. The 

promulgation of standards for new, modified, or reconstructed 

sources is the requisite predicate for applicability of CAA 

section 111(d). 

 CAA section 111(d)(1) requires the EPA to promulgate 

regulations under which states must submit state plans 

regulating “any existing source” of certain pollutants “to which 

a standard of performance would apply if such existing source 

were a new source.” A “new source” is “any stationary source, 

the construction or modification of which is commenced after the 

Deleted: allows the EPA to 

Deleted: e

Deleted: Thus, 

Commented [A16]: ? 

Deleted: regulate 

Deleted: this rule
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 274 of 1544

publication of regulations (or, if earlier, proposed 

regulations) prescribing a standard of performance under [CAA 

section 111] which will be applicable to such source.” It should 

be noted that these provisions make clear that a “new source” 

includes one that undertakes either new construction or a 

modification. It should also be noted that the EPA’s 

implementing regulations define “construction” to include 

“reconstruction,” which the implementing regulations go on to 

define as the replacement of components of an existing facility 

to an extent that (i) the fixed capital cost of the new 

components exceeds 50 percent of the fixed capital cost that 

would be required to construct a comparable entirely new 

facility, and (ii) it is technologically and economically 

feasible to meet the applicable standards. 

 Under CAA section 111(d)(1), in order for existing sources 

to become subject to that provision, the EPA must promulgate 

standards of performance under CAA section 111(b) to which, if 

the existing sources were new sources, they would be subject. 

Those standards of performance may include standards for sources 

that undertake new construction, modifications, or 

reconstructions. 

The EPA is finalizing a rulemaking under CAA section 111(b) 

for CO2 emissions from affected EGUs concurrently with this CAA 
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Page 275 of 1544

section 111(d) rulemaking, which will provide the requisite 

predicate for applicability of CAA section 111(d).304

D. Definition of Affected Sources 

For the emission guidelines, an affected EGU is any fossil 

fuel-fired electric utility steam generating unit (i.e., utility 

boiler or integrated gasification combined cycle (IGCC) unit) or 

stationary combustion turbine that was in operation or had 

commenced construction as of January 8, 2014,305 and that meets 

the following criteria, which differ depending on the type of 

unit. To be an affected EGU, such a unit, if it is a fossil 

fuel-fired electric utility steam generating unit (i.e., a 

utility boiler or IGCC unit), must serve a generator capable of 

selling greater than 25 MW to a utility power distribution 

system and have a base load rating greater than 260 GJ/h (250 

MMBtu/h) heat input of fossil fuel (either alone or in 

combination with any other fuel). If such a unit is a stationary 

combustion turbine, the unit must meet the definition of a 

 

304 In the past, the EPA has issued standards of performance under 

section 111(b) and emission guidelines under section 111(d) 

simultaneously. See “Standards of Performance for new Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills – Final Rule,” 61 Fed. Reg. 9905 

(March 12, 1996). 

305 Under Section 111(a) of the CAA, determination of affected 

sources is based on the date that the EPA proposes action on 

such sources. January 8, 2014 is the date the proposed GHG 

standards of performance for new fossil fuel-fired EGUs were 

published in the Federal Register (79 FR 1430).

Deleted: source
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combined cycle or combined heat and power combustion turbine, 

serve a generator capable of selling greater than 25 MW to a 

utility power distribution system, and have a base load rating 

of greater than 260 GJ/h (250 MMBtu/h). 

When considering and understanding applicability, the 

following definitions may be helpful. Simple cycle combustion 

turbine means any stationary combustion turbine which does not 

recover heat from the combustion turbine engine exhaust gases 

for purposes other than enhancing the performance of the 

stationary combustion turbine itself. Combined cycle combustion 

turbine means any stationary combustion turbine which recovers 

heat from the combustion turbine engine exhaust gases to 

generate steam that is used to create additional electric power 

output in a steam turbine. Combined heat and power (CHP) 

combustion turbine means any stationary combustion turbine which 

recovers heat from the combustion turbine engine exhaust gases 

to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric 

generation, or directly uses the heat in the exhaust gases for a 

useful purpose.

We note that certain affected EGUs are exempt from 

inclusion in a state plan. Affected EGUs that may be excluded 

from a state’s plan are those that (1) are subject to subpart 
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TTTT as a result of commencing modification or reconstruction; 

(2) steam generating units or IGCC units that are currently and 

always have been subject to a federally enforceable permit 

limiting net-electric sales to one-third or less of its 

potential electric output or 219,000 MWh or less on an annual 

basis; (3) non-fossil units (i.e., units that are capable of 

combusting 50 percent or more non-fossil fuel) that have 

historically limited the use of fossil fuels to 10 percent or 

less of the annual capacity factor or are subject to a federally 

enforceable permit limiting fossil fuel use to 10 percent or 

less of the annual capacity factor; (4) stationary combustion 

turbines that are not capable of combusting natural gas (i.e., 

not connected to a natural gas pipeline); (5) are a combined 

heat and power unit that are subject to a federally enforceable 

permit limiting, or have historically limited, annual net 

electric sales to a utility power distribution system to the 

product of the design efficiency and the potential electric 

output or 219,000 MWh (whichever is greater) or less; (6) serve 

a generator along with other steam generating unit(s), IGCC(s), 

or stationary combustion turbine(s) where the effective 

generation capacity (determined based on a prorated output of 

the base load rating of each steam generating unit, IGCC, or 

stationary combustion turbine) is 25 MW or less; (7) are a 

Commented [A17]: 

Commented [A18]: Does this conform with changes to 111(b) 
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municipal waste combustor unit subject to subpart Eb of Part 60; 

or (8) are a commercial or industrial solid waste incineration 

unit that is subject to subpart CCCC of Part 60.

The rationale for applicability of this final rule is 

multi-fold. We had proposed that affected EGUs were those 

existing source fossil fuel-fired EGUs that met the 

applicability criteria for coverage under the final GHG 

standards for new fossil fuel-fired EGUs being promulgated under 

section 111(b). However, we are finalizing that States need not 

include certain units that would otherwise meet the CAA section 

111(b) applicability in this CAA section 111(d) emission 

guidelines. These include simple cycle turbines, certain nonfossil units, and certain combined heat and power units. The 

final 111(b) standards include applicability criteria for simple 

cycle combustion turbines, for reasons relating to 

implementation and minimizing emissions from all future 

combustion turbines. However, for the following reasons none of 

the building blocks would result in emission reductions from

simple cycle turbines so we are not requiring that States 

including them in their CAA section 111(d) plans. 

First, even more than combined cycle units, simple cycle 

units have limited opportunities, compared to steam generating 

units, to reduce their heat rate. Most combustion turbines 

Deleted: apply to
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likely already follow the manufacturer’s recommended regular 

preventive/restorative maintenance for both reliable and 

efficiency reasons. These regularly scheduled maintenance 

practices are highly effective methods to maintain heat rates, 

and additional fleet-wide reductions from simple cycle 

combustion turbines are likely less than 2 percent. In addition, 

while approximately one-fifth of overall fossil fuel-fired 

capacity (GW) consists of simple cycle turbines, these units 

historically have operated at capacity factors of less than 5 

percent and only provide about 1 percent of the fossil fuelfired generation (GWh). Combustion turbine capacity can 

therefore only contribute CO2 emissions amounting to 

approximately 2 percent of total coal-steam CO2 emissions. Any 

single-digit percentage reduction in combustion turbine heat 

rates would therefore provide less than 1 percent reduction in 

total fossil-fired CO2 emissions. 

Further, we are not aware of an approach to estimate any 

limited opportunities that existing simple cycle turbines may 

have to reduce their heat rate. Similar to coal-steam EGUs, we 

do not have the unit-specific detailed design information on 

existing individual simple cycle combustion turbines that is 

necessary for a detailed assessment of the heat rate improvement 

potential via best practices and upgrades for each unit. While 
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the EPA could conduct a “variability analysis” of simple cycle 

historical hourly heat rate data (as was done for coal-steam 

EGUs), the various simple cycle models in use and the 

historically lower capacity factors of the simple cycle fleet 

(less run time per start, and more part load operation) would 

require a simple cycle analysis that includes more complexity 

and likely more uncertainty than in the coal-steam analysis. 

Therefore, we do not consider it feasible to estimate potential 

reductions due to heat rate improvements from simple cycle 

turbines, and even if it were, we have concluded those 

reductions would be negligible compared to the reductions from 

steam generating units. Hence, we do not consider building block 

1 as practically applicable to simple cycle units. 

Second, the vast majority of simple cycle turbines serve a 

specific need – providing power during periods of peak electric 

demand (i.e., peaking units). The existing block of simple cycle 

turbines are the only units that are able to start fast enough 

and ramp to full load quickly enough to serve as peaking units. 

If these units were to be used under building block 2 to 

displace higher emitting coal-fired units, they would no longer 

be available to serve as peaking units. Therefore, building 

block 2 could not be applied to simple cycle combustion turbines 

without jeopardizing grid reliability. 

Deleted: Further, we have not evaluated any 

opportunities that existing simple cycle have 

to reduce their heat rate. Further, we have 

not evaluated any opportunities that existing 

simple cycle have to reduce their heat rate. 

Deleted: Therefore

Deleted: 2 

Deleted: would not apply to 

Deleted: Therefore, building block 3 would not 

apply to simple cycle combustion turbines.
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Third, many commenters on the CAA section 111(b) proposal 

stated that simple cycle turbines will be used to provide backup 

power to intermittent renewable sources of power such as wind 

and solar. Consequently, adding additional generation from 

intermittent renewable sources has the potential to actually 

increase emissions from simple cycle turbines. Therefore, 

applying building block 3 based on the capacity of simple cycle 

turbines would not result in emission reductions from simple 

cycle combustion turbines. Finally, the EPA expects existing 

simple cycle turbines to continue to operate as they 

historically have operated, as peaking units. Including simple 

cycle turbines in CAA section 111(d) applicability would impact 

the numerical value of state goals, but it would not impact the 

stringency of the plans. Such inclusion would increase burden 

but result in no environmental benefit. 

Additionally, under CAA section 111(b) final applicability 

criteria, new dedicated non-fossil and industrial CHP units are 

not affected sources if they include permit restrictions on the 

amount of fossil fuel they burn and the amount of electricity 

they sell. Such units historically have had no regulatory 

mandate to include permit requirements limiting the use of 

fossil fuel or electric sales. We are exempting them from 

inclusion in CAA section 111(d) state plans in the interest of 

Deleted: Therefore, building block 3 would not 

apply to simple cycle combustion turbines. 

Deleted: Finally
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consistency with CAA section 111(b) and based on their 

historical fuel use and electric sales. 

We discuss changes in applicability of units in relation to 

state plans in Section VIII of this preamble. 

E. Combined Categories and Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is combining the listing of 

sources from the two existing source categories for the affected 

EGUs, as listed in 40 CFR subpart Da and 40 CFR subpart KKKK, 

into a single location, 40 CFR subpart UUUU, for purposes of 

addressing the CO2 emissions from existing affected EGUs. The EPA 

is also codifying all of the requirements for the affected EGUs 

in a new subpart UUUU of 40 CFR part 60 and including all GHG 

emission guidelines for the affected sources – fossil fuel–fired 

electric utility steam generating units, as well as stationary 

combustion turbines -- in that newly created subpart.306

We believe that combining the emission guidelines for 

affected sources into a new subpart UUUU is appropriate because 

the emission guidelines the EPA is establishing do not vary by 

type of source. Combining the listing of sources into one 

location, subpart UUUU, will facilitate implementation of CO2

 

306 The EPA is not codifying any of the requirements of this 

rulemaking in subparts Da or KKKK. 

Deleted: 
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mitigation measures, such as shifting generation from higher to 

lower-carbon intensity generation among existing sources (e.g., 

shifting from utility boilers to NGCC units), and emission 

trading among sources in the source category. 

As discussed in the January 8, 2014 proposal for the CAA 

section 111(b) standards for GHG emissions from EGUs (79 FR 

1430), in 1971 the EPA listed fossil fuel-fired steam generating 

boilers as a new category subject to section 111 rulemaking, and 

in 1979 the EPA listed fossil fuel-fired combustion turbines as 

a new category subject to the CAA section 111 rulemaking. In the 

ensuing years, the EPA has promulgated standards of performance 

for the two categories and codified those standards, at various 

times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. 

In the January 8, 2014 proposal, the EPA proposed separate 

standards of performance for new sources in the two categories 

and proposed codifying the standards in the same Da and KKKK 

subparts that currently contain the standards of performance for 

conventional pollutants from those sources. In addition, the EPA 

co-proposed combining the two categories into a single category 

solely for purposes of the CO2 emissions from new construction of 

affected EGUs, and codifying the proposed requirements in a new 

40 CFR part 60 subpart TTTT. For the final standards of 

performance for new construction of affected EGUs, the EPA is 
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codifying the final requirements in a new 40 CFR part 60 subpart 

TTTT. 

In this rulemaking, the EPA is combining the two listed source 

categories into a single source category for purposes of the 

emission guidelines for the CO2 emissions from existing affected 

EGUs. Because the two source categories are pre-existing and the 

EPA would not be subjecting any additional sources to 

regulation, the combined source category is not considered a new 

source category that the EPA must list under CAA section 

111(b)(1)(A). As a result, this final rule does not list a new 

source category under section 111(a)(1)(A), nor does this final 

rule revise either of the two source categories – fossil fuel–

fired electric utility steam generating units and stationary 

combustion turbines – that the EPA has already listed under that 

provision. Thus, the EPA is not required to make a finding that 

the combined source category causes or contributes significantly 

to air pollution which may reasonably be anticipated to endanger 

public health or welfare. 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

 In the June 2014 proposal, the EPA proposed to determine 

that the best system of emission reduction adequately 

demonstrated (BSER) for reducing CO2 emissions from existing EGUs 
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was a combination of measures –- (1) increasing the operational 

efficiency of existing coal-fired steam EGUs, (2) substituting 

increased generation at existing NGCC units for generation at 

existing steam EGUs, (3) substituting generation from low- and 

zero-carbon generating capacity for generation at existing 

fossil fuel-fired EGUs, and (4) increasing demand-side energy 

efficiency to reduce the amount of fossil fuel-fired generation 

–- which we categorized as four “building blocks.” As an 

alternative to the proposed building blocks 2, 3, and 4, the EPA 

also identified reduced generation in the amount of those 

building blocks as part of the BSER. These measures are not the 

only approaches EGUs can take to reduce CO2, but are those that 

the EPA felt best met the statutory criteria. We solicited 

comment on all aspects of our BSER determination, including 

other approaches. We have considered thoroughly the extensive 

comments submitted on a variety of topics related to the BSER 

and the individual building blocks, along with our own continued 

analysis, and we are finalizing the BSER based on the first 

three building blocks, with certain refinements. 

 Consistent with the approach taken in the proposed rule, in 

determining the BSER we have taken account of the global nature 

of CO2 pollution and the unique characteristics of the source 

category, particularly the exceptional degree of 
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interconnectedness among individual affected EGUs and the 

longstanding practice of coordinating planning and operations 

across multiple sources, reflecting the fact that each EGU’s 

function is interdependent with the function of other EGUs. Each 

building block is a proven approach for reducing emissions from 

the affected source category that is appropriate in this 

pollutant- and industry-specific context. Each building block 

also encompasses a variety of actions that individual affected 

EGUs may take, including (i) direct investment in efficiency 

improvements and in lower- and zero-carbon generation, (ii) 

cross-investment in these activities through mechanisms such as 

emissions trading approaches, where the state-established 

standards of performance to which sources are subject 

incorporate such approaches, and (iii) reduction of highercarbon generation. 

 With attention to costs, electricity rates, and the 

importance of ensuring continued reliability of electricity 

supplies, the individual building blocks and the overall BSER 

have been defined not at the maximum possible degree of 

stringency but at a reasonable degree of stringency designed to 

appropriately balance consideration of the various BSER factors. 

Additional, non-building block specific aspects of the BSER 

quantification methodology discussed below are similarly mindful 

Deleted: sources 

Deleted: sources 

Deleted: or other multi-unit compliance 

Deleted: or allow 
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of these considerations. This approach to determination of the 

BSER provides compliance headroom that ensures that the emission 

limitations reflecting the BSER are achievable by the source 

category, but nevertheless, as required by the CAA, will result 

in meaningful reductions in CO2 emissions from this sector. The 

wide range of actions encompassed in the building blocks, and a 

further wide range of possible emissions-reducing actions not 

included in the BSER but nevertheless available to help with 

compliance, ensure that the BSER is achievable by individual 

affected EGUs as well. 

 The final BSER incorporates certain changes from the 

proposed rule, reflecting the EPA’s consideration of comments 

received and further analysis. The principal changes are the 

exclusion from the BSER of emission reductions achievable 

through demand-side energy efficiency and through nuclear 

generation; a revised approach to determination of emission 

reductions achievable through increased renewable energy 

generation; a consistent approach to determination of emission 

reductions achievable through all the building blocks that 

better reflects the regional nature of the electricity system; 

and a revised interim goal period of 2022 to 2029 (instead of 

the proposed interim period of 2020 to 2029). These changes to 

Deleted: conservative. 

Deleted: sources 
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the BSER and the building blocks are discussed in more detail 

later in this section of the preamble. 

 Also in response to comments, in the final rule we have 

represented the emission limitations achievable through the BSER 

in the form of uniform CO2 emission performance rates for each of 

two affected source subcategories: steam generating units and 

stationary combustion turbines. However, like the proposed rule, 

the final rule also provides weighted-average state-specific 

goals that a state may choose as an alternative method for 

complying with its obligation to set standards of performance 

for its affected EGUs -– an alternative, that is, to adopting 

the nationwide subcategory-based CO2 emission performance rates 

as the standard of performance for its affected EGUs. The change 

to uniform CO2 emission performance rates is discussed in this 

section and in section VI of the preamble, and the relation of 

the performance rates to the state-specific goals and states’ 

section 111(d) plan options is discussed in sections VII and 

VIII of the preamble. 

 Section V.A. describes our determination of the final BSER, 

including a discussion of the associated emissions performance 

level, and provides the rationale for our determination. In 

section V.B. we address certain legal issues in greater detail, 

including key issues raised in comments. Sections V.C. through 
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V.E. contain more detailed discussions of the three individual 

building blocks included in the final BSER. Further information 

can be found in the GHG Mitigation Measures TSD for the CPP 

Final Rule, the CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule, the Response to Comments 

document, and, about certain topics, the Legal Memorandum for 

the Clean Power Plan Final Rule, all of which are available in 

the docket. 

A. The Best System of Emission Reduction 

 This section sets forth our determination of the BSER for 

reducing CO2 emissions from existing EGUs, including a discussion 

of the associated emissions performance level, and the rationale 

for that determination. In section V.A.1., we describe the legal 

framework for determination of the BSER in general. Section 

V.A.2. summarizes the determination of the BSER for this rule. 

In section V.A.3., we discuss changes from the proposal. Section 

V.A.4. provides more detail on our determination of the BSER, 

including our determinations regarding the individual elements 

of the BSER, as applied to two subcategories of fossil steam 

units and combustion turbines. In section V.A.5., we explain the 

specific actions that individual affected EGUs in the two 

subcategories may take to implement the BSER and thereby achieve 

the EPA-identified source subcategory-specific emission 

Deleted: the Legal Memorandum for the CPP Final 

Rule, 

Deleted: and 

Deleted: viewed from the perspective of

Deleted: the overall 

Deleted: y

Deleted: affected sources.

Deleted: discuss the BSER from a second 

perspective, comprising the range of 

Deleted: sources 
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performance rates that, in turn, form the basis for the 

standards of performance that states must set. Because these 

actions implement the BSER, they may be understood as part of 

the BSER. In this discussion, we recognize that states can 

choose to set sources’ standards of performance in different 

forms and that the form of the standard affects how various 

types of actions can be used to comply with the standard. In 

section V.A.6., we discuss the substantial compliance 

flexibility provided by additional measures, not included in the 

BSER, that individual affected EGUs can use to achieve their 

standards of performance. Finally, section V.A.7. addresses 

severability of the building blocks. 

1. Legal requirements for BSER in the emission guidelines 

a. Introduction. In the June 2014 proposal for this rule, we 

described the principal legal requirement for standards of 

performance under CAA section 111(d)(1) and (a)(1). We based our 

description in part on our discussion of the legal requirements 

for standards of performance under CAA section 111(b) and 

(a)(1), which we included in the January 2014 proposal for 

standards of performance for CO2 emissions from new fossil fuelfired EGUs. In the latter proposal, we noted that the D.C. 

Circuit has handed down numerous decisions that interpret CAA 

section 111(a)(1), including its component elements, and we 

Deleted: levels 

Deleted: reflect the BSER and that 

Deleted: sources 
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reviewed that case law in detail.307

We received comments on our proposed interpretation, and in 

light of those comments, in this final rule, we are clarifying 

our interpretation in certain respects. We discuss our 

interpretation below.308 

b. CAA requirements and court interpretation.309 Section 

111(d)(1) directs the EPA to promulgate regulations establishing 

a section 110-like procedure under which states submit state 

plans that establish “standards of performance” for emissions of 

certain air pollutants from sources which, if they were new 

 

307 79 FR 1430, 1462 (January 8, 2014). 308

 We also discuss our interpretation of the requirements for 

standards of performance and the BSER under section 111(b), for 

new sources, in the section 111(b) rulemaking that the EPA is 

finalizing simultaneously with this rule and in the Legal 

Memorandum for this rule. Our interpretations of these 

requirements in the two rules are generally consistent except to 

the extent that they reflect distinctions between new and 

existing sources. For example, as discussed in the section 

111(b) rule, the legislative history indicates that Congress 

intended that the BSER for new industrial facilities, which were 

expected to have lengthy useful lives, would include the most 

advanced pollution controls available, but Congress had a 

broader conception of the BSER for existing facilities. 

309 Our interpretation of the CAA provisions at issue is guided 

by Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984). In 

Chevron, the U.S. Supreme Court held that an agency must, at 

Step 1, determine whether Congress’s intent as to the specific 

matter at issue is clear, and, if so, the agency must give 

effect to that intent. If congressional intent is not clear, 

then, at Step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of the statute.
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sources, would be regulated under section 111(b), and that 

implement and enforce those standards of performance. 

The term “standard of performance” is defined to mean— 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated. 

Section 111(a)(1). 

These provisions authorize the EPA to determine the BSER 

for the affected sources and, based on the BSER, to establish 

emission guidelines that identify the minimum amount of emission 

limitation that a state, in its state plan, must impose on its 

sources through standards of performance. Consistent with these 

CAA requirements, the EPA’s regulations require that the EPA’s 

guidelines reflect-- 

the degree of emission reduction achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of such reduction) the 

Administrator has determined has been adequately 

demonstrated.310 

The EPA’s approach in this rulemaking is to determine the 

 

310 40 C.F.R. § 60.21(e). This definition was promulgated as part 

of the EPA’s CAA 111(d) implementing regulations and was not 

updated to reflect the textual changes adopted by Congress in 

1977. That said, Congress recognized that those changes “merely 

make[] explicit what was implicit in the previous language.” 

H.R. Rep. No. 95-294, at 190 (May 12, 1977). 
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BSER on a source category-wide basis, to determine the emission 

limitation that results from applying the BSER to the sources, 

and then to establish emission guidelines for the states that 

incorporate those emission limitations. The EPA expresses these 

emission limitations in the form of the performance levels, and 

they must be achievable by the source category.311 

Following the EPA’s promulgation of emission guidelines, 

each state must determine the standards of performance for its 

sources, which the EPA’s regulations term “designated 

facilities.”312 A state has broad discretion in doing so. CAA 

section 111(d)(1) requires the EPA’s regulations to “permit the 

State in applying a standard of performance to any particular 

source ... to take into consideration, among other factors, the 

remaining useful life of the ... source....”313 In addition, 

 

311

See Sierra Club v. Costle, 657 F.2d at 330 (“The language of 

section 111 not only authorizes variable control but also gives 

EPA authority when determining the best technological system to 

weigh cost, energy, and environmental impacts in the broadest 

sense at the national and regional levels and over time as 

opposed to simply at the plant level in the immediate present. 

... The standard is, after all, a national standard with longterm effects.”). 

312 40 C.F.R. § 60.24(b)(3). 313 The EPA’s regulations, promulgated prior to enactment of the 

“remaining useful life” provision of section 111(d)(1), provide: 

“Unless otherwise specified in the applicable subpart on a caseby-case basis for particular designated facilities, or classes 

of facilities, States may provide for the application of less 

stringent emission standards or longer compliance schedules than 

Deleted: s
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under CAA section 116, the state is authorized to set a standard 

of performance for any particular source that is more stringent 

than the emission limit contained in the EPA’s emission 

guidelines.314 Thus, for any particular source, a state may apply 

a standard of performance that is either more stringent or less 

stringent than the performance level in the emission guidelines, 

as long as, in total, the state’s sources achieve at least the 

same degree of emission limitation as included in the EPA’s 

emission guidelines. The states must include the standards of 

performance in their state plans and submit the plans to the EPA 

for review.315 Under CAA section 111(d)(2)(A), the EPA approves 

state plans as long as they are “satisfactory.” 

As noted in the January 2014 proposal and discussed in more 

detail above under section II.G, Congress first included the 

definition of “standard of performance” when enacting CAA 

section 111 in the 1970 Clean Air Act Amendments (CAAA), amended 

 

those otherwise required” by the corresponding emission 

guideline. 40 C.F.R. § 60.24(f). Some of the factors that a 

state may consider for this case-by-case analysis include the 

“cost of control resulting from plant age, location, or basic 

process design” and the “physical impossibility of installing 

necessary control equipment,” among other factors “that make 

application of a less stringent standard or final compliance 

time significantly more reasonable.” Id. 314 In addition, CAA section 116 authorizes the state to set 

standards of performance for all of its sources that, together, 

are more stringent than the EPA’s emission guidelines. 

315 40 C.F.R. § 60.23. 
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it in the 1977 CAAA, and then amended it again in the 1990 CAAA 

to largely restore the definition as it read in the 1970 CAAA. 

It is in the legislative history for the 1970 and 1977 CAAA that 

Congress primarily addressed the definition as it read at those 

times and that legislative history provides guidance in 

interpreting this provision.316 In addition, although the D.C. 

 

316 In the 1970 CAAA, Congress defined “standard of performance,” 

under §111(a)(1), as: 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated. 

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard (i) be based 

on, in lieu of the “best system of emission reduction ... 

adequately demonstrated,” the “best technological system of 

continuous emission reduction ... adequately demonstrated;” and 

(ii) require a percentage reduction in emissions. In addition, 

in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 

consider “any nonair quality health and environment impact and 

energy requirements.” 

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction ... adequately demonstrated.” 

This 1990 CAAA version is the current definition, which is 

applicable at present. Even so, because parts of the definition 

as it read under the 1977 CAAA were retained in the 1990 CAAA,

the explanation in the 1977 CAAA legislative history, and the 

interpretation in the case law, of those parts of the definition 

Deleted: 
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Circuit has never reviewed a section 111(d) rulemaking, the 

Court has reviewed section 111(b) rulemakings on numerous 

occasions during the past 40 years, handing down decisions dated 

from 1973 to 2011,317 through which the Court has developed a 

body of case law that interprets the term “standard of 

performance.” 

c. Key elements of interpretation. The emission guidelines 

promulgated by the Administrator must include emission 

limitations that are “achievable” by the source category by 

application of a “system of emission reduction” that is 

“adequately demonstrated” and that the EPA determines to be the 

“best,” “taking into account” the factors of “cost ... nonair 

quality health and environmental impact and energy 

requirements.” The D.C. Circuit has stated that in determining 

the “best” system, the EPA must also take into account “the 

amount of air pollution”318 reduced and the role of 

“technological innovation.”319 The Court has emphasized that the 

 

in the case law remain relevant to the definition as it reads 

today. 

317 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 

1, 2015). 

318 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981). 

319 See Sierra Club v. Costle, 657 F.2d at 347. 

Deleted: 
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EPA has discretion in weighing those various factors.320, 321

Our overall approach to determining the BSER and emission 

guidelines, which incorporates the various elements, is as 

follows: In developing an emission guideline, we generally 

engage in an analytical approach that is similar to what we 

conduct under CAA section 111(b) for new sources. First, we 

identify “system[s] of emission reduction” that have been 

“adequately demonstrated” for a particular source category. 

Second, we determine the “best” of these systems after 

evaluating the amount of reductions, costs, any nonair health 

and environmental impacts, energy requirements, and, in the 

alternative, the advancement of technology (that is, we apply a 

formulation of the BSER with the above noted factors, and then, 

 

320 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999). 

321 Although CAA section 111(a)(1) may be read to state that the 

factors enumerated in the parenthetical are part of the 

“adequately demonstrated” determination, the D.C. Circuit’s case

law appears to treat them as part of the “best” determination. 

See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA 

section 111 gives the EPA authority “when determining the best 

technological system to weigh cost, energy, and environmental 

impacts”). Nevertheless, it does not appear that those two 

approaches would lead to different outcomes. See, e.g., Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) 

(rejecting challenge to the EPA’s cost assessment of the “best 

demonstrated system”). In this rule, the EPA treats the factors 

as part of the “best” determination, but, as noted, even if the 

factors were part of the “adequately demonstrated” 

determination, our analysis and outcome would be the same. 
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in the alternative, we apply a formulation of the BSER with 

those same factors plus the advancement of technology). And 

third, we select an achievable emission limit –- here, the 

emission performance standard -- based on the BSER.322 In 

contrast to subsection (b), however, subsection (d)(1) assigns 

to the states, not the EPA, the obligation of setting standards 

of performance for the affected sources. Thus, we also take into 

account whether states can establish standards of performance 

that can implement the measures under consideration for 

inclusion in the BSER. As discussed below in the following 

subsection, in examining the range of reasonable options for 

states to consider in setting standards of performance under 

these guidelines, we identified a number of considerations, 

including the interconnected operations of the affected sources 

and the global nature of the CO2 pollutant. And third, we select 

an achievable emission limit –- here, the emission performance 

standard -- based on the BSER.323 

 

322

See, e.g., Oil and Natural Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

pollutants Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 

(describing the three-step analysis in setting a standard of 

performance). 

323

See, e.g., Oil and Natural Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

pollutants Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 

Deleted: F.R.

Deleted: F.R.
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The remainder of this subsection discusses the various 

elements in our general analytical approach. 

(1) System of emission reduction. 

As we discuss below, the CAA does not define the phrase 

“system of emission reduction.” The ordinary, everyday meaning 

of “system” is a set of things or parts forming a complex whole; 

a set of principles or procedures according to which something 

is done; an organized scheme or method; and a group of 

interacting, interrelated, or interdependent elements.324 With 

this definition, the phrase “system of emission reduction” takes 

a broad meaning: a set of measures that work together to reduce 

emissions. The EPA interprets this phrase to carry an important 

limitation: because the emission guidelines for the existing 

sources must reflect “the degree of emission limitation 

achievable through the application of the best system of 

emission reduction ... adequately demonstrated,” the system must 

be limited to measures that can be implemented -– “appl[ied]” -- 

 

(describing the three-step analysis in setting a standard of 

performance). 

324 Oxford Dictionary of English (3rd ed.) (2010), available at

http://www.oxforddictionaries.com/us/definition/american_english

/system; see also American Heritage Dictionary (5th ed.) (2013), 

available at 

http://www.yourdictionary.com/system#americanheritage; and The 

American College Dictionary (C.L. Barnhart, ed. 1970) (“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”). 

Deleted: “a set of things working together as 

parts of a mechanism or interconnecting 

network; a complex whole.”325

Deleted: things 

Deleted: things 
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by the sources themselves, that is, as a practical matter, by 

actions taken by the owners or operators of the sources. As we 

discuss below, this definition is sufficiently broad to include 

the building blocks. 

(2) “Adequately demonstrated.” 

Under section 111(a)(1), in order for a “system of emission 

reduction” to serve as the basis for an “achievable” emission 

limitation, the Administrator must determine that the system is 

“adequately demonstrated.” This means, according to the D.C. 

Circuit, that the system is “one which has been shown to be 

reasonably reliable, reasonably efficient, and which can 

reasonably be expected to serve the interests of pollution 

control without becoming exorbitantly costly in an economic or 

environmental way.”326 It does not mean that the system “must be 

in actual routine use somewhere.”327 Rather, the Court has said, 

“[t]he Administrator may make a projection based on existing 

technology, though that projection is subject to the restraints 

of reasonableness and cannot be based on ‘crystal ball’ 

 

326

Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 

1973), cert. denied, 416 U.S. 969 (1974). 327

Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted) (discussing the Senate and House 

bills and reports from which the language in CAA section 111 

grew). 
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inquiry.”328 Similarly, the EPA may “hold the industry to a 

standard of improved design and operational advances, so long as 

there is substantial evidence that such improvements are 

feasible.”329 Ultimately, the analysis “is partially dependent on 

‘lead time,’” that is, “the time in which the technology will 

have to be available.”330 Unlike for CAA section 111(b) standards 

that are applicable immediately after the effective date of 

their promulgation, under CAA section 111(e), compliance with 

CAA section 111(d) standards may be set sometime in the future. 

This is due, in part, to the period of time for states to submit 

state plans and for the EPA to act on them. 

(3) “Best.” 

In determining which adequately demonstrated system of 

emission reduction is the “best,” the EPA considers the 

following factors: 

(a) Costs. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “the cost of achieving” the required emission 

reductions. As described in the January 2014 proposal,331 in 

 

328 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 

329 Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 330 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 

331 79 FR 1430, 1464 (January 8, 2014). 
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several cases the D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard in various ways, stating 

that the EPA may not adopt a standard the cost of which would be 

“exorbitant,”332 “greater than the industry could bear and 

survive,”333 “excessive,”334 or “unreasonable.”335 These 

formulations appear to be synonymous, and for convenience, in 

this rulemaking, we will use reasonableness as the standard, so 

that a control technology may be considered the “best system of 

emission reduction ... adequately demonstrated” if its costs are 

reasonable, but cannot be considered the best system if its 

 

332 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999). 

333 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975). 

334 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 335 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 
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costs are unreasonable.336, 337

The D.C. Circuit has never invalidated a standard of 

performance on grounds that it was too costly. In several cases, 

the Court upheld standards that entailed significant costs, 

consistent with Congress’s view that “the costs of applying best 

 

336 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted: 

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business. 

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is “available” should 

not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach. 

S. Comm. Rep. No. 91-1196 at 16. 

337 We received comments that we do not have authority to revise 

the cost standard as established in the case law, e.g., 

“exorbitant,” “excessive,” etc., to a “reasonableness” standard 

that the commenters considered less protective of the 

environment. We agree that we do not have authority to revise 

the cost standard as established in the case law, and we are not 

attempting to do so here. Rather, our description of the cost 

standard as “reasonableness” is intended to be a convenient term 

for referring to the cost standard as established in the case 

law.

Deleted: 
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practicable control technology be considered by the owner of a 

large new source of pollution as a normal and proper expense of 

doing business.”338 See Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d 427, 440 (D.C. Cir. 1973);339 Portland Cement Association v. 

Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club 

v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding 

standard imposing controls on SO2 emissions from coal-fired power 

plants when the “cost of the new controls ... is 

substantial”).340 

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis. 

(b) Non-air health and environmental impacts. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “any nonair quality health and environmental 

impact” in determining the BSER. As the D.C. Circuit has 

 

338 1977 House Committee Report at 184. 339 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972). 

340 Indeed, in upholding the EPA’s consideration of costs under 

other provisions requiring consideration of cost, courts have 

also noted the substantial discretion delegated to the EPA to 

weigh cost considerations with other factors. Chemical Mfr’s 

Ass’n v. EPA, 870 F. 2d 177, 251 (5th Cir. 1989); Association of 

Iron and Steel Inst. v. EPA, 526 F. 2d 1027, 1054 (3d Cir. 

1975); Ass’n of Pacific Fisheries v. EPA, 615 F. 2d 794, 808 

(9th Cir. 1980). 
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explained, this requirement makes explicit that a system cannot 

be “best” if it does more harm than good due to cross-media 

environmental impacts.341

(c) Energy considerations. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “energy requirements.” As discussed below, the EPA 

may consider energy requirements on both a source-specific basis 

and a sector-wide, region-wide, or nationwide basis. Considered 

on a source-specific basis, “energy requirements” entails, for 

example, the impact, if any, of the system of emission reduction 

on the source’s own energy needs. 

(d) Amount of emissions reductions. 

In the proposed rulemakings for this rule and the 

associated section 111(b) rule, we noted that although the 

definition of “standard of performance” does not by its terms 

identify the amount of emissions from the category of sources or 

the amount of emission reductions achieved as factors the EPA 

must consider in determining the “best system of emission 

reduction,” the D.C. Circuit has stated that the EPA must do so. 

See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) 

 

341 Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 

Costle, 657 F. 2d at 331; see also Essex Chemical Corp. v. 

Ruckelshaus, 486 F. 2d at 439 (remanding standard to consider 

solid waste disposal implications of the BSER determination). 
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(“we can think of no sensible interpretation of the statutory 

words “best ... system” which would not incorporate the amount 

of air pollution as a relevant factor to be weighed when 

determining the optimal standard for controlling ... 

emissions”).342 The fact that the purpose of a “system of 

emission reduction” is to reduce emissions, and that the term 

itself explicitly incorporates the concept of reducing 

emissions, supports the Court’s view that in determining whether 

a “system of emission reduction” is the “best,” the EPA must 

consider the amount of emission reductions that the system would 

yield. Even if the EPA were not required to consider the amount 

of emission reductions, the EPA has the discretion to do so, on 

grounds that either the term “system of emission reduction” or 

the term “best” may reasonably be read to allow that discretion. 

 (e) Sector- or nationwide component of factors in 

determining the BSER. 

As discussed in the January 2014 proposal for the section 

 

342 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system” to read, 

“best technological system.” As noted above, the 1990 CAAA 

deleted “technological,” and thereby returned the phrase to how 

it read under the 1970 CAAA. The court’s interpretation of this 

phrase in Sierra Club v. Costle to require consideration of the 

amount of air emissions remains valid for the phrase “best 

system.” 

Deleted: under Chevron step 2 
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111(b) rulemaking and the proposal for this rulemaking, another 

component of the D.C. Circuit’s interpretations of CAA section 

111 is that the EPA may consider the various factors it is 

required to consider on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.343 The D.C. Circuit based this interpretation – which 

it made in the 1981 Sierra Club v. Costle case, which concerned 

the NSPS for new power plants -- on a review of the legislative 

history, stating, 

[T]he Reports from both Houses on the Senate and House 

bills illustrate very clearly that Congress itself was 

using a long-term lens with a broad focus on future 

costs, environmental and energy effects of different 

technological systems when it discussed section 111.344 

The Court has upheld EPA rules that the EPA “justified ... in 

terms of the policies of the Act,” including balancing long-term 

national and regional impacts: 

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

 

343 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351). 344 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).

Deleted: 

Deleted: The Conferees defined the best 

technology in terms of “long-term growth,” 

“long-term cost savings,” effects on the 

“coal market,” including prices and 

utilization of coal reserves, and 

“incentives for improved technology.” 

Indeed, t
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and industrial sources. 

By substantially reducing SO2 emissions, the standard 

will enhance the potential for long term economic 

growth at both the national and regional levels.345

As with the final rule under section 111(b) that is 

associated with this rule, the EPA is considering costs and 

energy implications on the basis of both their sourcespecific impacts and a sector-wide, regional, or national 

basis. 

(4) Achievability of the emission limitation in the 

emission guidelines. 

Before discussing the requirement under section 111(d) that 

the emission limitation in the emission guidelines must be 

“achievable,” it is useful to discuss the comparable requirement 

under section 111(b) for new sources. For new sources, CAA 

section 111(b)(1)(B) and (a)(1) provides that the EPA must 

establish “standards of performance,” which are standards for 

emissions that reflect the degree of emission limitation that is 

“achievable” through the application of the BSER. According to 

the D.C. Circuit, a standard of performance is “achievable” if a 

 

345 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg. at 33,583/3-33,584/1). In the January 2014 proposal, we 

explained that although the D.C. Circuit decided Sierra Club v. 

Costle before the Chevron case was decided in 1984, the D.C. 

Circuit’s decision could be justified under either Chevron step 

1 or 2. 79 FR 1430, 1466 (January 8, 2014). 

Deleted: 

Deleted: 
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technology can reasonably be projected to be available to an 

individual source at the time it is constructed that will allow 

it to meet the standard.346 Moreover, according to the Court, 

”[a]n achievable standard is one which is within the realm of 

the adequately demonstrated system’s efficiency and which, while 

not at a level that is purely theoretical or experimental, need 

not necessarily be routinely achieved within the industry prior 

to its adoption.”347 To be achievable, a standard “must be 

capable of being met under most adverse conditions which can be 

reasonably be expected to recur and which are not or cannot be 

taken into account in determining the ‘cost of compliance.’”348

To show a standard is achievable, the EPA must “(1) identify 

variable conditions that might contribute to the amount of 

expected emissions, and (2) establish that the test data relied 

on by the agency are representative of potential industry-wide 

performance, given the range of variables that affect the 

achievability of the standard.”349

 

346 Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. Cir. 

1981). 

347 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 348 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 

1980). 

349 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 

(citing Nat’l Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 

In considering the representativeness of the source tested, the 

EPA may consider such variables as the “‘feedstock, operation, 
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The D.C. Circuit established these standards for 

achievability in cases concerning CAA section 111(b) new source 

standards of performance. There is no case law under CAA section 

111(d). Assuming that those standards for achievability apply 

under section 111(d), in this rulemaking, we are taking a 

similar approach for the emission limitation that the EPA 

identifies in the emission guidelines. For existing sources, 

section 111(d)(1) requires the EPA to establish requirements for 

state plans that, in turn, must include “standards of 

performance.” Through long-standing regulations350 and consistent 

practice, the EPA has interpreted this provision to require the 

EPA to promulgate emission guidelines that determine the BSER 

for a source category and that identify the amount of emission 

limitation achievable by application of the BSER. 

The EPA has promulgated these emission guidelines on the 

basis that the existing sources can achieve the limitation, even 

though the State retains discretion to apply standards of 

performance to individual sources that are more or less 

stringent. 

 

size and age’ of the source.” Nat’l Lime Ass’n v. EPA, 627 F.2d 

416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to 

“generalize from a sample of one when one is the only available 

sample, or when that one is shown to be representative of the 

regulated industry along relevant parameters.” Nat’l Lime Ass’n 

v. EPA, 627 F.2d 416, 434, n.52 (D.C. Cir. 1980). 350 40 C.F.R. § 60.21(e). 

Deleted: I

Deleted: the same 
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(a) Technical feasibility. 

As indicated in the proposed rulemakings for this rule and 

the associated section 111(b) rule, the requirement that the 

emission limitation in the emission guidelines be “achievable” 

based on the “best system of emission reduction ... adequately 

demonstrated” indicates that the technology or other measures 

that the EPA identifies as the BSER must be technically 

feasible. See 79 FR 1430, 1463 (January 8, 2014). At least in 

some cases, in determining whether the emission limitation is 

achievable, it is useful to analyze the technical feasibility of 

the system of emission reduction, and we do so in this 

rulemaking. 

(5) Expanded use and development of technology. 

The D.C. Circuit has long held that Congress intended for 

CAA section 111 to create incentives for new technology and 

therefore that the EPA is required to consider technological 

innovation as one of the factors in determining the “best system 

of emission reduction.” See Sierra Club v. Costle, 657 F.2d at 

346-47. The Court has grounded its reading in the statutory 

text.351 In addition, the Court’s interpretation finds firm 

 

351 Sierra Club v. Costle, 657 F. 2d at 346 (“Our interpretation 

of section 111(a) is that the mandated balancing of cost, 

energy, and nonair quality health and environmental factors 

embraces consideration of technological innovation as part of 
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support in the legislative history.352 The legislative history 

identifies three different ways that Congress designed CAA 

section 111 to authorize standards of performance that promote 

technological improvement: (i) the development of technology 

that may be treated as the “best system of emission reduction ... 

adequately demonstrated;” under section 111(a)(1);353 (ii) the 

expanded use of the best demonstrated technology;354 and (iii) 

the development of emerging technology.355 Even if the EPA were 

not required to consider technological innovation as part of its 

determination of the BSER, it would be reasonable for the EPA to 

consider it, either because technological innovation may be 

 

that balance. The statutory factors which EPA must weigh are 

broadly defined and include within their ambit subfactors such 

as technological innovation.”). 

352 See S. Rep. 91-1196 at 16 (1970) (“Standards of performance 

should provide an incentive for industries to work toward 

constant improvement in techniques for preventing and 

controlling emissions from stationary sources”); S. Rep. 95-127 

at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n. 

174) (“The section 111 Standards of Performance ... sought to 

assure the use of available technology and to stimulate the 

development of new technology”). 

353 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”). 

354 See 1970 Senate Committee Report No. 91-1196 at 15 (“The 

maximum use of available means of preventing and controlling air 

pollution is essential to the elimination of new pollution 

problems”). 

355 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 

standard of performance designed to promote the use of an 

emerging technology). 
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considered an element of the term “best,” or because the term 

“best system of emission reduction” is ambiguous as to whether 

technological innovation may be considered, and it is reasonable 

for the EPA to interpret it to authorize consideration of 

technological innovation in light of Congress’s emphasis on 

technological innovation. 

In any event, as discussed below, the EPA may justify the 

control technologies identified in this rule as the BSER even 

without considering the factor of incentivizing technological 

innovation or development. 

(6) EPA discretion. 

The D.C. Circuit has made clear that the EPA has broad 

discretion in determining the appropriate standard of 

performance under the definition in CAA section 111(a)(1), 

quoted above. Specifically, in Sierra Club v. Costle, 657 F.2d 

298 (D.C. Cir. 1981), the Court explained that “section 111(a) 

explicitly instructs the EPA to balance multiple concerns when 

promulgating a NSPS,”356 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

the standard.”357 In Lignite Energy Council v. EPA, 198 F.3d 930 

 

356

Sierra Club v. Costle, 657 F.2d at 319. 357 Sierra Club v. Costle, 657 F.2d at 321; see also New York v. 

Reilly, 969 F. 2d at 1150 (because Congress did not assign the 

Deleted: 

Deleted: 
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(D.C. Cir. 1999), the Court reiterated: 

Because section 111 does not set forth the weight that 

should be assigned to each of these factors, we have 

granted the agency a great degree of discretion in 

balancing them.... EPA's choice [of the ‘best system’] 

will be sustained unless the environmental or economic 

costs of using the technology are exorbitant.... EPA 

[has] considerable discretion under section 111.358 

d. Approach to the source category and subcategorizing. Section 

111 requires the EPA first to list source categories that may 

reasonably be expected to endanger public health or welfare and 

then to regulate new sources within each such source category. 

Section 111(b)(2) grants the EPA discretion whether to 

“distinguish among classes, types, and sizes within categories 

of new sources for the purpose of establishing [new source] 

standards,” which we refer to as “subcategorizing.” Section 

111(d)(1), in conjunction with section 111(a)(1), simply 

 

specific weight the Administrator should assign to the statutory 

elements, “the Administrator is free to exercise [her] 

discretion” in promulgating an NSPS). 

358

Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience). See New York v. 

Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) (“Because Congress 

did not assign the specific weight the Administrator should 

accord each of these factors, the Administrator is free to 

exercise his discretion in this area.”); see also NRDC v. EPA, 

25 F.3d 1063, 1071 (D.C. Cir. 1994) (EPA did not err in its 

final balancing because “neither RCRA nor EPA’s regulations 

purports to assign any particular weight to the factors listed 

in subsection (a)(3). That being the case, the Administrator was 

free to emphasize or deemphasize particular factors, constrained 

only by the requirements of reasoned agency decisionmaking.”). 
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requires the EPA to determine the BSER, does not prescribe the 

method for doing so, and is silent as to whether the EPA may 

subcategorize. The EPA interprets this provision to authorize 

the EPA discretion as to whether and, if so, how to 

subcategorize. In addition, the regulations under CAA section 

111(d) provide -- 

The Administrator will specify different emission 

guidelines or compliance times or both for different 

sizes, types, and classes of designated facilities 

when costs of the control, physical limitations, 

geographical location, or similar factors make 

subcategorization appropriate.359

 As with any of its own regulations, the EPA has authority 

to interpret or revise these regulations. 

 Of course, regardless of whether the EPA subcategorizes 

within a source category for purposes of determining the BSER 

and the emissions performance level for the emission guideline, 

as part of its section 111(d) plan, a state retains great 

flexibility in assigning standards of performance to its 

affected EGUs. Thus, the state may, if it wishes, impose 

different emission reduction obligations on different sources, 

as long as the overall level of emission limitation is at least 

as stringent as the emission guidelines. 

2. The BSER for this Rule -– Overview 

 

359 40 CFR 60.22(b)(5). 
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a. Summary. This section describes the EPA’s overall approach to 

establishing the BSER. This rule, promulgated under CAA section 

111(d), establishes emission guidelines for states to use in 

establishing standards of performance for affected EGUs, and the 

BSER is the central determination that the EPA must make in 

formulating the guidelines. In order to establish the BSER we 

have considered the subcategory of the steam affected EGUs as a 

whole, and the subcategory of the combustion turbine affected 

EGUs as a whole, and have identified the BSER for each 

subcategory as the measures that the sources, viewed together 

and operating under the standards of performance established for 

them by the states, can implement to reduce their emissions to 

an appropriate amount, and that meet the other requirements for 

the BSER including, for example, cost reasonableness.360 After 

identifying the BSER in this manner, the EPA determines the 

performance levels –- in this case, the CO2 emission performance 

rates –- for the steam generators and for the combustion 

turbines. 

 

360 In this rulemaking, our determination that the costs are 

reasonable means that the costs meet the cost standard in the 

case law no matter how that standard is articulated, this is, 

whether the cost standard is articulated through the terms that 

the case law uses, e.g., “exorbitant,” “excessive,” etc., or 

through the term we use for convenience, “reasonableness”.

Deleted: In understanding the EPA’s basis for 

the BSER, it is useful to view the BSER from 

two complementary perspectives. The first 

perspective considers 

Deleted: treats 

Deleted: identified by the EPA 

Deleted: For convenience, this may be referred 

to as the source-category perspective because 

it views the BSER on a category- or 

subcategory-wide basis. 
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In establishing the BSER the EPA also considered the set of 

actions that an EGU, operating under a standard of performance 

established by its state, may take to achieve the applicable 

performance rate, if the state adopts that rate as the standard 

of performance and applies it to the EGUs in its jurisdiction, 

or to achieve the equivalent mass-based limit, and that meet the 

other requirements for the BSER. These actions implement the 

BSER and may therefore be understood as part of the BSER. 

An example illustrating the relationship between the 

measures determined to constitute the BSER for the source 

category and the actions that may be undertaken by individual 

sources that are therefore also part of the BSER is the 

substitution of non-emitting generation for CO2-emitting 

generation. This measure involves two distinct actions: 

increasing the amount of non-emitting generation and reducing 

the amount of CO2-emitting generation. From the perspective of 

the source category, the two actions are halves of a single 

balanced endeavor, but from the perspective of any individual 

affected EGU, the two actions are separable, and a particular 

affected EGU may decide to implement either or both of the 

actions. Further, an individual source may choose to invest 

directly in actions at its own facility or an affiliated 

Deleted: The second perspective considers the 

affected EGUs individually, and treats the 

BSER as 

Deleted: For convenience, this may be referred 

to as the individual-source perspective.

Deleted: Under either perspective, the EPA 

determines the BSER as encompassing the same 

set of actions, but the two perspectives serve 

to elucidate the EPA’s reasoning. ¶

Deleted: source-category and individual-source 

perspectives for this rule 

Deleted: source-category

Deleted: individual-source 
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facility or to cross-invest in actions at other facilities on 

the interconnected electricity system. 

To reiterate the overall context for the BSER: In this 

rule, the EPA determined the BSER, and applied it to the 

category of affected EGUs to determine the performance levels –- 

that is, the CO2 emission performance rates -- for steam 

generators and for combustion turbines. States must impose 

standards of performance on their sources that implement the CO2

emissions performance rates, or, as an alternative method of 

compliance, in total, achieve the same emissions performance 

level that the CO2 emission performance rates would achieve if 

applied directly to each source as the standard or emissions 

limitation it must meet.361 Each state has flexibility in how it 

assigns the emission limitations to its affected EGUs –- and in 

fact, the state can be more stringent than the guidelines 

require –- but one of the state’s choices is to convert the CO2

emission performance rates into standards of performance –- 

which may incorporate emissions trading –- for each of its 

affected EGUs. If a state does so, then the affected EGUs may 

achieve their emission limits by taking the actions that qualify 

as the BSER. Since the BSER and, in this case its constituent 

 

361 The approaches that states may take in their plans are 

discussed in section VIII. 

Deleted: sources 
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elements, reflect the critical criteria of feasibility, 

reasonable cost, and other BSER criteria, the BSER assures that 

there is at least one pathway –- the CO2 emission performance 

rates -- for the state and its affected EGUs to take that 

achieves the requisite level of emission reductions, while, 

again, assuring that the affected EGUs can achieve those 

emission limits at reasonable cost and consistent with the other 

factors for the BSER. 

This section describes the EPA’s process and basis for 

determining the BSER for the purpose of determining the CO2

emission performance rates.362 The EPA is identifying the BSER as 

a well-established set of measures that have been used by EGUs 

for many years to achieve various business and policy purposes, 

and have been used in recent years for the specific purpose of 

reducing EGUs’ CO2 emissions, and that are appropriate to the 

global nature of carbon pollution and afforded by the highly 

integrated nature of the utility power sector. We evaluated 

these measures with a view to the states’ obligation to 

establish standards of performance and included in our BSER 

determination consideration of the range of options available 

for states to employ in establishing those standards of 

 

362 Other sections in this preamble describe how EPA calculated 

the CO2 emission performance rates based on the BSER. 

Deleted: As noted above, the BSER determined 

through this process can be described from two 

perspectives. Viewed from the source-category 

perspective, the 

Deleted: As also noted, we
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performance. These measures include (i) increasing the 

operational efficiency of existing coal-fired steam EGUs on 

average by a specified percentage (building block 1); (ii) 

substituting increased generation from existing NGCC units for 

reduced generation at existing steam EGUs in specified amounts 

(building block 2); and (iii) substituting increased generation 

from new zero-emitting renewable energy generating capacity for 

reduced generation at existing fossil fuel-fired EGUs in 

specified amounts (building block 3). It should be noted that 

building block 2 incorporates reduced generation from steam EGUs 

on a source category-wide basis and building block 3 

incorporates reduced generation from all fossil fuel-fired EGUs 

on a source category-wide basis. Further, as discussed below, 

given the global nature of carbon pollution and the highly 

integrated utility power sector, each of the building blocks 

incorporates various mechanisms for facilitating crossinvestment by individual affected EGUs in emission rate 

improvements or emission reduction activities at other locations 

on the interconnected electricity system. The range of 

mechanisms includes bilateral investment of various kinds; the 

issuance and acquisition of emission rate credits representing 

the emissions-reducing effects of specific activities, where 

available under state plans; and more general emissions trading 

Deleted: carbon 

Deleted: purchase 
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using rate-based credits or mass-based allowances (as discussed 

in section V.A.2.f. below), where the affected EGUs are 

operating under standards of performance that incorporate 

emissions trading .363

The set of measures identified as the BSER for the source 

category encompasses a menu of actions that are part of the BSER 

and that individual affected EGUs may implement in different 

amounts and combinations in order to achieve their emission 

limits at reasonable cost. This menu includes actions that (i) 

affected steam EGUs can implement to improve their heat rates; 

(ii) affected steam EGUs can implement to increase generation 

from lower-emitting existing NGCC units in specified amounts, 

(iii) all affected EGUs can implement to increase generation 

from new low- or zero-carbon generation sources in specified 

amounts, (iv) all affected EGUs can implement to reduce their 

generation in specified amounts, and (v) all affected EGUs 

operating under a standard of performance that incorporates 

emissions trading can implement by means of purchasing ratebased emission credits or mass-based emission allowances from 

other affected EGUs, since the effect of the purchase would be 

 

363 Conditions for the use of these mechanisms under various 

state plans are discussed in section VIII. 

Deleted: ; and other multi-unit compliance

Deleted: approaches such as averaging or 

bubbling, where available under state plans

Deleted: Viewed from the individual-source 

perspective, the EPA is identifying the BSER 

as a menu of actions -- all of which fall 

within the 

Deleted: from the source-category perspective -

- 

Deleted: coal-fired
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the same as achieving the other listed actions through direct 

means.364 

Importantly, affected EGUs also have available numerous 

other measures that are not included in the BSER but that could 

materially help the EGUs achieve their emission limits and 

thereby provide compliance flexibility. Examples include, among 

numerous other approaches, investment in demand-side energy 

efficiency, co-firing with natural gas (for coal-fired steam 

EGUs), and investment in new generating units using low- or 

zero-carbon generating technologies other than those that are 

part of building block 3. 

b. The EPA’s review of measures for determining the BSER. The 

EPA described in the proposal for this rule the analytical 

process by which the EPA determined the BSER for this source 

category. The EPA is finalizing large parts of that analysis, 

but the EPA is also refining that analysis as informed by the 

information and data provided by commenters and our further 

evaluation. What follows is the EPA’s final determination. 

As described in the proposal, to determine the BSER, the 

EPA began by considering the characteristics of CO2 pollution and 

the utility power sector. Not surprisingly, whenever the EPA 

 

364 Again, conditions for the use of these mechanisms under 

various state plans are discussed in section VIII. 

Deleted: , and (vi) all affected EGUs can 

implement through other multi-unit compliance 

approaches such as averaging or bubbling, 

where available under state plans

Deleted: viewed from either the source-category 

perspective or the individual-source 

perspective, 
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begins the regulatory process under section 111, it initially 

undertakes these same inquiries and then proceeds to fashion the 

rule to fit the industry. For example, in 1979, the EPA 

finalized new standards of performance to limit emissions of SO2

from new, modified, and reconstructed EGUs.365 In assessing the 

final SO2 standard, the EPA carried out extensive analyses of a 

range of alternative SO2 standards “to identify environmental, 

economic, and energy impacts associated with each of the 

alternatives considered at the national and regional levels.”366

In identifying the best system underlying the final standard, 

the EPA evaluated “coal cleaning and the relative economics of 

FGD [flue gas desulfurization] and coal cleaning” together as 

the “best demonstrated system for SO2 emission reduction.”367 The 

 

365

 The need for new standards was due in part to findings that in 

1976, steam electric generating units were responsible for “65 

percent of the SO2 ... emissions on a national basis.” 44 FR 

33580, 33587 (June 11, 1979). The EPA explained that [u]nder the 

current performance standards for power plants, national SO2

emissions are projected to increase approximately 17 percent 

between 1975 and 1995. Impacts will be more dramatic on a 

regional basis.” Id. Thus, “[o]n January 27, 1977, EPA announced 

that it had initiated a study to review the technological, 

economic, and other factors needed to determine to what extent 

the SO2 standard for fossil-fuel-fired steam generators should be 

revised.” Id. at 33587-33588. 366 44 FR 33580, 33582 (June 11, 1979). 367 44 FR 33580, 33593. The EPA considered an investigation by 

the U.S. Department of the Interior regarding the amount of 

sulfur that could be removed from various coals by physical coal 

cleaning. Id. at 33593. 
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EPA also took into account the unique features of power 

transmission along the interconnected grid and the unique 

commercial relationships that rely on those features.368=

Similarly, in 1996, the EPA finalized section 111(b) 

standards and 111(d) emission guidelines to ensure that certain 

municipal solid waste (MSW) landfills controlled landfill gases 

to the level achievable through application of the BSER.369 EPA’s 

identification of this BSER was critically influenced by the 

“unique emission pattern of landfills.”370 Unlike “typical 

stationary source[s],” which only generate emissions while in 

operation, MSW landfills can “continue to generate and emit a 

significant quantity of emissions” long after the facility has 

 

368 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 

369

 61 FR 9905, 9905 (March 12, 1996). In the rule, the EPA 

referred to the BSER for both new and existing MSW landfills as 

“the best demonstrated system of continuous emission reduction,” 

as well as the “BDT”—short for “best demonstrated technology.”

See, e.g., id. at 9905–07, 9913–14. 370 61 FR 9905, 9908; see 56 FR 24468, 24478 (May 30, 1991) 

(explaining at proposal that because landfill-gas emission rates 

“gradually increase” from zero after the landfill opens, and 

“gradually decrease” from peak emissions after closure, the 

EPA’s identification of the BSER for landfills inherently 

requires a determination of “when controls systems must be 

installed and when they may be removed”). 

Deleted: 
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closed or otherwise stopped accepting waste.371 In recognition of 

this salient and unique characteristic of landfills, the EPA set 

the BSER based on an emission-reducing system of gas collection 

and control that remained in place as long as emissions remained 

above a certain threshold -- even after the regulated landfill 

had permanently closed.372 The EPA acknowledged that for some 

landfills, it could take 50 to 100 years for emissions to drop 

below the cutoff.373

For this rule, we discuss at length in the proposed rule 

and in section II above the unique characteristics of CO2

pollution. The salient facts include the global nature of CO2, 

which makes the specific location of emission reductions 

unimportant; the enormous quantities of CO2 emitted by the 

utility power sector, coupled with the fact that CO2 is 

relatively unreactive, which make CO2 much more difficult to 

mitigate by measures or technologies that are typically utilized 

within an existing power plant; the need to make large 

reductions of CO2 in order to protect human health and the 

 

371 See U.S. EPA, Municipal Solid Waste Landfills, Volume 1: 

Summary of the Requirements for the New Source Performance 

Standards and Emission Guidelines for Municipal Solid Waste 

Landfills, Docket No. EPA-453R/96-004 at 1-3 (February 1999). 372 61 FR 9905, 9907–08. 373 61 FR 9905, 9908. 

Deleted: are discussed at length in the 

proposed rule and in section II above.

Deleted: pollutant’s
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environment; and the fact that the utility power sector is the 

single largest source category by a considerable margin. 

We also discuss at length in the proposal and in section II 

above the unique characteristics of the utility power sector.

Topics of that discussion include the physical properties of 

electricity and the integrated nature of the electricity system. 

Here, we reiterate and emphasize that the utility power sector 

is unique in the extent to which it must balance supply and 

demand on a real-time basis, with limited electricity storage 

capacity to act as a buffer. In turn, the need for real-time 

synchronization across each interconnection has led to a 

uniquely high degree of coordination and interdependence in both 

planning and real-time system operation among the owners and 

operators of the facilities comprised within each of the three 

large electrical interconnections covering the contiguous 48 

states. Given these unique characteristics, it is not surprising 

that the North American power system has been characterized as a 

“complex machine.”374 The core function of providing reliable 

electricity service is carried out not by individual electricity 

generating units but by the complex machine as a whole. 

Important subsidiary functions such as management of costs and 

 

374 S. Massoud Amin, “Securing the Electricity Grid,” The Bridge, 

Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A Journey 

Through the Heart of Our Electrified World 1 (2007). 

Deleted: T

Deleted: are also discussed at length in the 

proposal and in section II above. 
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management of environmental impacts are also carried out to a 

great extent on a multi-unit basis rather than an individualunit basis. Generation from one generating unit can be and 

routinely is substituted for generation from another generating 

unit in order to keep the complex machine operating while 

observing the machine’s technical, environmental, and other 

constraints and managing its costs. 

The EPA also reviewed broad trends within the utility power 

sector.375 It is evident that, in the recent past, coal-fired 

electricity generation has been reduced, and projected future 

trends are for continued reduction. By the same token, loweremitting NGCC generation and renewable generation have 

increased, and projected future trends are for continued 

increases.376 A survey of integrated resource plans (IRPs), 

included in the docket, shows that fossil fuel-fired EGUs are 

taking actions to reduce emissions of both non-GHG air 

pollutants and GHGs.377 Some fossil fuel-fired EGUs are investing 

in lower- or zero-emitting generation. In fact, our review 

indicates that the great majority of fossil fuel-fired 

 

375 These trends are discussed in more detail in sections V.D. 

and V.E. below.

376 Demand-side energy efficiency measures have also increased, 

and the projected future trends are for continued increase. 

377 The IRPs typically also indicate planned investment in 

demand-side energy efficiency. 
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generators surveyed are including new renewable energy resources 

in their planning. In addition, some fossil fuel-fired EGUs are 

using those measures to replace their higher-emitting 

generation. Some fossil fuel-fired generators appear to be 

reducing their higher-emitting generation without fully 

replacing it. These measures in aggregate result in the 

replacement of higher-emitting generation with lower- or zeroemitting generation, reflecting the integrated nature of the 

electricity system. 

The EPA examined state and company programs intended at 

least in part to reduce CO2 from fossil fuel-fired power plants. 

These programs include GHG performance standards established by 

states including California, New York, Oregon, and Washington; 

utility planning approaches carried out by companies in Colorado 

and Minnesota; and renewable portfolio standards (RPS) 

established in more than 25 states.378 They also include marketbased initiatives, such as the Regional Greenhouse Gas 

Initiative (RGGI) and the GHG emissions trading program 

established by the California Global Warming Solutions Act, and 

conservation and demand reduction programs. 

We also examined federal legislative and regulatory 

programs, as well as state programs currently in operation, that 

 

378 See 79 FR 34848-34850. 
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address pollutants other than CO2 emitted by the power sector. 

These programs include, among others, the CAA Title IV program 

to reduce SO2 and NOX, the MATS program to reduce mercury and air 

toxic emissions, and the CSAPR program to reduce SO2 and NOX.379

This analysis demonstrated that, among other measures, the 

application of control technology, fuel-switching, and 

improvements in the operational efficiency of EGUs all resulted 

in reductions in a range of pollutants. These programs also 

demonstrate that replacement of higher-emitting generation with 

lower-emitting generation -- including generation shifts between 

coal-fired EGUs and natural gas-fired EGUs –- and zero-emitting 

generation such as renewable energy, also reduces emissions. 

Some of these programs also include emissions trading among the 

power plants. 

In this rule, when evaluating the types and amounts of 

measures that the source category can take to reduce CO2

emissions, we have appropriately taken into account the global 

nature of the pollutant and the high degree to which each 

individual affected EGU is integrated into a “complex machine” 

that makes it possible for generation from one generating unit 

to be replaced with generation from another generating unit for 

the purpose of reducing generation from CO2–emitting generating 

 

379 Many of these programs are discussed in section V.B. 
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units. We have also taken into account the trends away from 

higher-carbon generation toward lower- and zero-carbon 

generation and trends towards demand-side energy efficiency. 

These factors strongly support consideration of emission 

reduction approaches that focus on the machine as a whole –- 

that is, the overall source category –- by shifting generation 

from dirtier to cleaner sources in addition to emission 

reduction approaches that focus on improving the emission rates 

of individual sources. 

The factors just discussed that support consideration of 

emission reduction measures at the source-category level 

likewise strongly support consideration of mechanisms such as 

emissions trading approaches, especially since, as discussed in 

section VIII, the states will have every opportunity to design 

their section 111(d) plans to allow the affected EGUs in their 

respective jurisdictions to employ emissions trading approaches 

to achieve the standards of performance established in those 

plans. In short, as discussed in more detail in section V.A.2.f. 

below, it is entirely feasible for states to establish standards 

of performance that incorporate emissions trading, and it is 

reasonable to expect that states will do so. These approaches 

lower overall costs, add flexibility, and make it easier for 

individual sources to address pollution control objectives. To 

Deleted: and other multi-unit compliance 

Deleted: or other multi-unit compliance 
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the extent that the purchase of an emissions credit or allowance 

represents the purchase of surplus emission reductions by an 

emitting source, emissions trading represents, in effect, the 

investment in pollution control by the purchasing source, 

notwithstanding that the control activity may be occurring at 

another source. As noted above, the utility power sector has a 

long history of using the “complex machine” to address 

objectives and constraints of various kinds. When afforded the 

opportunity to address environmental objectives on a multi-unit 

basis, the industry has done so. Congress and the EPA have 

selected emissions trading approaches when addressing regional 

pollution from the utility power sector contributing to problems 

such as acid precipitation and interstate transport of ozone and 

particulate matter. Similarly, states have selected market-based 

approaches for their own programs to address regional and global 

pollutants. The industry has readily adapted to that form of 

regulation, taking advantage of the flexibility and 

incorporating those programs into the planning and operation of 

the “machine.” Further reinforcing our conclusion that reliance 

on trading is appropriate is the extensive interest in using 

such mechanisms that states and utilities demonstrated through 

their formal comments and in discussions during the outreach 
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process. The role of emissions trading is discussed further in 

section V.A.2.f. below. 

This entire review has made clear that there are numerous 

measures that, alone or in various combinations, merit analysis 

for inclusion in the BSER. The review has also made clear that 

the global nature of CO2 pollution and the unique, interconnected 

and interdependent manner in which affected EGUs and other 

generating sources operate within the electricity sector make 

certain types of measures and mechanisms available and 

appropriate for consideration as the BSER for this rule that 

would not be appropriate for other pollutants and other 

industrial sectors. For purposes of this discussion, the 

measures can be categorized in terms of the essential 

characteristics of the four building blocks described in the 

proposal: Measures that (i) reduce the CO2 emission rate at the 

unit, (ii) substitute generation from existing lower-emitting 

fossil fuel-fired units for generation from higher-emitting 

fossil fuel-fired units, (iii) substitute generation from new 

low- or zero-emitting generating capacity, especially renewable 

energy, for generation from fossil fuel-fired units, and (iv) 

increase demand-side energy efficiency to avoid generation from 

fossil fuel-fired units. In the proposal, we described our 

evaluations of various measures in each of these categories. In 
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this rule, with the benefit of comments, we have refined our 

evaluation of which specific measures should comprise the first 

three building blocks, and, for reasons discussed below, we have 

determined that the fourth building block, demand-side energy 

efficiency, should not be included in the BSER in these 

guidelines. 

The measures are discussed more fully below, but it should 

be noted here that because of the integrated nature of the 

utility power sector, in which individual EGUs’ operations 

intrinsically depend on the operations of other generators, 

coupled with the sector’s high degree of planning and 

reliability safeguards, the measures in the second and third 

categories, which involve generation shifts to lower- and zeroemitting sources, may occur through several different actions 

from the perspective of an individual source, all of which are 

equivalent from the perspective of the source category as a 

whole. First, a higher-emitting fossil unit may invest in 

cleaner generation without reducing its own generation, which 

would result in less demand for, and therefore reductions in 

generation by, other higher-emitting units. Second, a higheremitting fossil unit may reduce its generation, which, in the 

presence of requirements for the source category as a whole to 

reduce CO2 emissions, would result in increased demand for, and 

Deleted: in several different ways from the 

individual-source perspective, 

Deleted: source-category perspective. 
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therefore increased amounts of, cleaner generation. Third, a 

higher-emitting fossil unit may do both of these things, 

directly replacing part of its generation with investments in 

lower- or zero-emitting generation.380 In addition, for measures 

in all of the categories, multiple mechanisms exist by which an 

individual affected EGU may make these investments, ranging from 

bilateral investments, to purchase of credits representing the 

emissions-reducing benefits of specific activities, to purchase 

of general rate-based emissions credits or mass-based emission 

allowances. As discussed below, mechanisms involving tradable 

credits or allowances are well within the realm of consideration 

for the standards of performance states can choose to apply to 

their EGUs and hence, are entirely appropriate for EPA to 

consider in evaluating these measures in the course of making 

its BSER determination. 

c. State establishment of standards of performance and source 

compliance. Before identifying in detail the measures that the 

BSER comprises, it is useful to describe the process by which 

the states establish the standards of performance with which the 

affected EGUs must comply, and the implications for the sources 

that will be operating subject to those standards of 

 

380 The same is true for demand-side energy efficiency measures, 

although, as discussed elsewhere, demand-side energy efficiency 

measures are not included in the BSER in the final rule. 

Deleted: source 

Deleted: , to other multi-unit compliance 

approaches such as averaging or bubbling

Deleted: these latter 
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performance. As part of the EPA’s emission guidelines in this 

rule, and based on the BSER, the EPA is identifying CO2 emission 

performance rates that reflect the BSER and, pursuant to 

subsection 111(d)(1), requiring states to establish standards of 

performance for affected EGUs in order to implement those rates. 

States, of course, could simply impose those rates on each 

affected EGU in their respective jurisdictions, but we are also 

offering states alternative approaches to carrying out their 

obligations. For purposes of defining these alternatives and 

facilitating states’ efforts to formulate compliance plans 

encompassing maximum flexibilities, we are aggregating the 

performance rates into goals for each state. The state, in turn, 

has the option of setting specific standards of performance for 

its EGUs such that the emission limitations from the EGUs 

operating under those standards of performance together meet the 

performance rates or the state goal. To do this, the state must 

adopt a plan that establishes the EGUs’ standards of performance 

and that implements and enforces those standards. 

Each state has significant flexibility in several respects. 

For example, as mentioned, a state may impose standards of 

performance on its steam EGU sources and on its combustion 

turbine sources that simply reflect the respective CO2 emission 

performance rates for those subcategories set in the emission 

Deleted: represent 
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guidelines. Alternatively, a state may impose standards with 

differing degrees of stringency on various sources, and, in 

fact, may be more stringent overall than its state goal 

requires. In addition –- and most importantly for purposes of 

describing the BSER -- a state may set standards of performance 

either as emission rates (e.g., lbs of CO2 per MWh) or mass 

limits (e.g., tons of CO2 per year). Moreover, a state may make 

those limits tradable (subject to conditions described in 

section VIII below). The form of the emission limits, whether 

emission rate limits or mass limits, has implications for what 

specific actions that are part of the BSER the individual 

affected EGUs may take to achieve those limits as well as what 

specific non-BSER measures are available to the individual 

affected EGUs for compliance flexibility. For example, if an 

individual source chooses to adopt building block 3 by both 

investing in lower- or zero-emitting generation and reducing its 

own generation, both those actions will be accounted for in its 

emission rate and both will therefore help the source meet its 

rate-based limit. If the same individual source takes the same 

actions but is subject to a mass-based limit, the action of 

reducing its generation will directly count in helping the 

source meet its own mass-based limit but the action of investing 

in cleaner generation will not. However, the investment in 

Deleted: or authorize other multi-unit 

compliance mechanisms 

Deleted: –- that is, the measures that comprise 

the BSER from the individual-source 

perspective –- 
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lower-or zero-emitting generation by that source and other 

sources collectively will help the overall source category 

achieve the emission limits consistent with the BSER and in 

doing so will make it easier for that source and other sources 

collectively to meet their mass-based limits. 

In instances where a state establishes standards of 

performance that incorporate emissions trading, the tradable 

credits or allowances can serve as a medium through which 

affected EGUs can invest in any emission reduction measure. 

d. Identification of the BSER measures. We now discuss the 

evaluation of potential measures for inclusion in the BSER for 

the source category as a whole. 

(1) Measures that reduce individual affected EGUs’ CO2

emission rates. 

As described in the proposal, the measures that the 

affected EGUs could implement to improve their CO2 emission rates 

includes a set of measures that the EPA determined would result 

in improvements in heat rate at coal-fired steam EGUs in the 

amount of 6 percent on average, and the EPA proposed that this 

set of measures qualifies as a component of the BSER. In this 

final rule, the EPA concludes that those measures do qualify as 

a component of the BSER. However, as described in section V.C. 

below, based on comments and further evaluation, the EPA is 

Deleted: – the source-category perspective

Deleted: first 

Deleted: from the source-category perspective. 
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narrowing the set of these types of measures that qualify as a 

component of the BSER and has quantified the emission reductions 

achievable through application of the measures on a regional 

basis, consistent with the treatment of the other building 

blocks in this final rule, rather than the nationwide basis used 

for building block 1 in the proposed rule. As a result of these 

refinements, the EPA is identifying the heat rate improvements 

achievable by coal-fired steam EGUs as 4.3 percent for the 

Eastern Interconnection, 2.1 percent for the Western 

Interconnection, and 2.3 percent for the Texas Interconnection. 

The refinements are based, in significant part, on the numerous 

comments we received on these points, especially those from 

states and utilities. 

 These heat rate improvement measures include best practices 

such as improved staff training; boiler chemical cleaning; 

cleaning air preheater coils, and use of various kinds of 

software, as well as equipment upgrades such as turbine 

overhauls. These are measures that the owner/operator of an 

affected coal-fired steam EGU may take that would have the 

effect of reducing the amount of CO2 the source emits per MWh. As 

a result, these measures would help the source achieve an 

emission limit expressed as either an emission rate limit or as 

a mass limit. We note again that in the context both of the 
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integrated electricity system and of available and anticipated 

state approaches to setting standards of performance, emissions 

trading approaches could be used as mechanisms through which one 

affected EGU could invest in heat rate improvements at another 

EGU. We note this aspect below in describing the actions an 

individual affected EGU can take to implement the BSER and 

discuss it in more detail in section V.A.2.f. 

These heat rate improvements are a low-cost option that fit 

the criteria for the BSER, except that they lead to only small 

emission reductions for the source category.381 Given the 

magnitude of the environmental problem and projections by 

climate scientists that much larger emission reductions are 

needed from fossil fuel-fired EGUs to address climate change, 

the EPA looked at additional measures to reduce emission rates. 

This reflects our conclusion that, given the availability of 

other measures capable of much greater emission reductions, the 

emission reductions limited to this set of heat rate improvement 

measures would not meet one of the considerations critical to 

 

381 As further discussed below, if heat rate improvements at 

coal-fired steam EGUs were implemented in isolation, without 

other measures to reduce CO2 emissions, the heat rate 

improvements could lead to increases in competitiveness and 

utilization of the coal-fired EGUs – a so-called “rebound 

effect” - causing increases in CO2 emissions that could partially 

or even entirely offset the CO2 emission reductions achieved 

through the reductions in the amount of CO2 emissions per MWh of 

generation. 

Deleted: or other multi-unit compliance

Deleted: source 

Deleted: source. 

Deleted: individual-source perspective of 

Deleted: 
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the BSER determination –- the quantity of emissions reductions 

resulting from the application of these measures is too small 

for these measures to be the BSER by themselves for this source 

category.

Specifically, as described in the proposal, the EPA also 

considered co-firing (including 100 percent conversion) with 

natural gas, a measure that presented itself in part because of 

the recent increase in availability and reduction in price of 

natural gas, and the industry’s consequent increase in reliance 

on natural gas.382 The EPA also considered implementation of 

carbon capture and storage (CCS).383 The EPA found that some of 

these co-firing and CCS measures are technically feasible and 

within price ranges that the EPA has found to be cost effective 

in the context of other GHG rules, that a segment of the source 

category may implement these measures, and that the resulting 

emission reductions could be potentially significant. 

However, these co-firing and CCS measures are more 

expensive than other available measures. This is because the 

integrated nature of the electricity system affords 

significantly lower cost options, ones that fossil fuel-fired 

 

382 The EPA further addressed co-firing in the NODA. 79 FR 64549-

51. 

383 CCS is also sometimes referred to as carbon capture and 

sequestration. 

Deleted: 

Deleted: 
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power plants throughout the United States and in foreign nations 

are already using to reduce their CO2. 

The less expensive options include shifting generation to 

existing NGCC units -- an option that has become particularly 

attractive in light of the increased availability and lower 

prices of natural gas -- as well as shifting generation to new 

renewable energy generating units.384 A comparison of the costs 

of converting an existing coal-fired boiler to burn 100 percent 

natural gas compared to the cost of shifting generation to an 

existing NGCC unit illustrates this point. Because an NGCC unit 

burns natural gas significantly more efficiently than an 

affected steam EGU does, the cost of shifting generation from 

the steam EGU to an existing NGCC unit is significantly cheaper 

in most cases than more aggressive emission rate reduction 

measures at the steam EGU. As a result, as a practical matter, 

were the EPA to include co-firing and CCS in the BSER and 

promulgate performance standards accordingly, few EGUs would 

likely comply with their emission standards through co-firing 

and CCS; rather, the EGUs would rely on the lower cost options 

 

384 Similarly, demand-side energy efficiency measures are lowcost measures. 
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of substituting lower- or zero-emitting generation or, as a 

related matter, reducing generation.385

The EPA also considered heat rate improvement opportunities 

at oil- and gas-fired steam EGUs and NGCC units and found that 

the available emission reductions would likely be more expensive 

or too small to merit consideration as a material component of 

the BSER. 

 Thus, in reviewing the entire range of control options, it 

became clear that controlling CO2 from affected EGUs at levels 

that are commensurate with the sector’s contribution to GHG 

emissions and thus necessary to mitigate the dangers presented 

by climate change, could depend in part, but not primarily, on 

measures that improve efficiency at the power plants. Rather, 

most of the CO2 controls need to come in the form of those other 

measures that are available to the utility power sector thanks 

specifically to the integrated nature of the electricity system, 

and that involve, in one form or another, replacement of higher 

emitting generation with lower- or zero-emitting generation. 

Although the presence of lower-cost options that achieve 

the emission reduction goals mean that the EPA is not 

identifying either natural gas co-firing or CCS at coal-fired 

 

385 Many EGUs would also rely on demand-side energy efficiency 

measures. 
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steam EGUs, or heat rate improvements at other types of EGUs, as 

part of the BSER, those controls remain measures that some 

affected EGUs may be expected to implement and that as a result, 

will provide reductions that those affected EGUs may rely on to 

achieve their emission limits or may sell, through emissions 

trading, to other affected EGUs to achieve emission limits (to 

the extent permitted under the relevant section 111(d) plans). 

Another example of a non-BSER measure that an affected EGU in 

certain circumstances could choose to implement is the 

conversion of waste heat from electricity generation into useful 

thermal energy. The EPA further discusses the potential use of 

these non-BSER measures for compliance flexibility below. 

The EPA’s quantification of the CO2 emission reductions 

achievable through heat rate improvements as a component of the 

BSER (building block 1) is discussed in section V.C. of this 

preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(2) Measures available because of the integrated 

electricity system. 

To determine the BSER that meets the expectations and 

requirements of the CAA, including the achievement of meaningful 

reductions of CO2, the EPA turned next to the set of measures 

that presented themselves as a result of the fact that the 
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operations of individual affected EGUs are interdependent on and 

integrated with one another and with the overall electricity 

system. Those are the measures in the categories represented in 

the proposal by building blocks 2, 3, and 4. This section 

discusses the components of the BSER that relate to building 

blocks 2 and 3, which the EPA is finalizing as components of the 

BSER. This section also discusses the measures comprising the 

proposed building block 4, which the EPA is not including in the 

BSER in this final rule. 

It bears reiterating that the extent to which the 

operations of individual affected EGUs are integrated with one 

another and with the overall electricity system is a highly 

salient and unique attribute of this source category. Because of 

this integration, the individual sources in the source category 

operate through a network that physically connects them to each 

other and to their customers, an interconnectedness that is 

essential to their operation under the status quo and by all 

indications is projected to be augmented further on a continual 

basis in the future to address fundamental objectives of 

reliability assurance and cost reduction. This physical 

interconnectedness exists to serve a set of interlocking regimes 

that, to a substantial extent, determine, if not dictate, any 

given EGU’s operations on a nearly moment-to-moment basis. In 
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analyzing BSER from the perspective of the overall source 

category, because the affected EGUs are connected to each other 

operationally, a combination of dispatching and investment in 

lower- and zero-emitting generation allows the replacement of 

higher-emitting generation with lower-emitting and zero-emitting 

generation (measures in building blocks 2 and 3), and thereby 

reduces emissions while continuing to serve load. 

 As noted above, substitution of higher-emitting generation 

for lower- or zero-emitting generation may include reduced 

generation, depending on the specific action taken by the 

individual EGU. Likewise, when incorporated into standards of 

performance, emissions trading mechanisms may be readily used 

for implementing these building blocks. We discuss these aspects 

below in describing the actions that individual sources may take 

to implement the BSER. 

 (a) Substituting generation from lower-emitting affected 

EGUs for reduced generation from higher-emitting affected EGUs 

(building block 2). 

In the proposal, the EPA observed that substantial CO2

emission reductions could be achieved at reasonable cost by 

increasing generation from existing NGCC units and 

commensurately reducing generation from steam EGUs. Because NGCC 

units produce much less CO2 per MWh of generation than steam EGUs 

Deleted: a source-category perspective, 

Deleted: or other multi-unit compliance 

Deleted: individual-source perspective of 
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–- typically less than half as much CO2 as coal-fired steam EGUs, 

which account for most generation from steam EGUs –- this 

generation shift reduces CO2 emissions. We also noted that 

because NGCC units can generate as much as 46 percent more 

electricity from a given quantity of natural gas than a steam 

unit can, generation shifting from coal-fired steam EGUs to 

existing NGCC units is a more cost-effective strategy for 

reducing CO2 emissions from the source category than converting 

coal-fired steam EGUs to combust natural gas or co-firing coal 

and natural gas in steam EGUs. We proposed to find that shifting 

generation consistent with a 70 percent target utilization rate 

(based on nameplate capacity) for NGCC units was feasible and 

should be a component of the BSER. 

As described in section V.D. below, analysis reflecting 

consideration of the many comments we received on this issue 

supports the inclusion of generation shifting from higheremitting to lower-emitting EGUs as a component of the BSER. 

Shifting of generation among EGUs is an everyday occurrence 

within the integrated operations of the utility power sector 

that is used to ensure that electricity is provided to meet 

customer demands in the most economic manner consistent with 

system constraints. Generation shifting to lower-emitting units 
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has been recognized as an approach for reducing emissions in 

other EPA rules such as CSAPR. 

The EPA’s analysis continues to show that the magnitude of 

emission reductions included in the proposed rule from 

generation shifting is achievable. Some commenters stated that 

summer capacity ratings are a more appropriate basis upon which 

to compute a target utilization than nameplate capacity ratings 

used at proposal. We agree, and accordingly, using the same data 

on historical generation as at proposal, we have reanalyzed 

feasible NGCC utilization levels expressed in terms of summer 

capacity ratings and have found that a 75 target utilization 

rate based on summer capacity ratings is feasible. 

The EPA is finalizing a determination that generation shift 

from higher-emitting affected EGUs to lower-emitting affected 

EGUs is a component of the BSER (building block 2). Our 

quantification of the associated emission reductions is 

discussed in section V.D. of this preamble and in the GHG 

Mitigation Measures TSD for the CPP Final Rule. 

(b) Substituting increased generation from new low- or 

zero-carbon generating capacity for reduced generation from 

affected EGUs (building block 3). 

Reducing generation from fossil fuel-fired EGUs and 

replacing it with generation from lower- or zero-emitting EGUs 
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is another method for reducing CO2 emissions from the utility 

power sector. In the proposal, the EPA identified renewable 

energy (RE) generating capacity and nuclear generating capacity 

as potential sources of lower- or zero-CO2 generation that could 

replace higher-CO2 generation from affected EGUs. 

(i) Increased generation from new RE generating capacity. 

The EPA’s survey of trends and actions already being taken 

in the utility power sector indicated that RE generating 

capacity and generation have grown rapidly in recent years, in 

part because of the environmental benefits of shifting away from 

fossil fuel-fired generation and in part because of improved 

economics of RE generation relative to fossil fuel-fired 

generation. It is clear that increasing the amount of new RE 

generating capacity and allowing the increased RE generation to 

replace generation from fossil fuel-fired EGUs can reduce CO2

emissions from the affected source category. Accordingly, we 

proposed to include replacement of defined quantities of fossil 

generation by RE generation in the BSER. 

With the benefit of comments, the EPA is finalizing the 

determination that substitution of RE generation from new RE 

generating capacity is a component of the BSER but has adjusted 

the approach for determining the quantities of RE generation. As 

part of the adjustment in approach, we have also refocused the 
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quantification solely on generation from new RE generating 

capacity rather than total (new and existing) RE generating 

capacity as in the proposal. Our quantification of the RE 

generation component of the BSER is discussed in section V.E. of 

the preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(ii) Increased and preserved generation from nuclear 

generating capacity. 

In the June 2014 proposal, the EPA also identified the 

replacement of generation from fossil fuel-fired EGUs with 

generation from nuclear units as a potential approach for 

reducing CO2 emissions from the affected source category. We 

proposed to include two elements of nuclear generation in the 

BSER: an element representing projected generation from nuclear 

units under construction, and an element representing preserved 

generation from existing nuclear generating capacity at risk of 

retirement. 

Like generation from new RE generating capacity, generation 

from new nuclear generating capacity can clearly replace fossil 

fuel-fired generation and thereby reduce CO2 emissions. However, 

there are also important differences between these types of lowor zero-CO2 generation. Investments in new nuclear capacity are 

very large, “lumpy,” capital-intensive investments and the 
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building of nuclear facilities historically has been subject to 

delays, which tend to raise costs. By comparison, investments in 

new RE generating capacity are relatively small with relatively 

more certain costs. Based on the small number of new nuclear 

generating projects, it is difficult to ascertain a trend of 

increasing nuclear generation in the industry, in contrast to 

the clear trend of increasing RE generation. These differences 

create greater uncertainty regarding the achievability and cost 

of generation from new nuclear capacity as a replacement for 

fossil fuel-fired generation, two important factors in 

determination of the BSER. Accordingly, as described in section 

V.A.3., the EPA is not finalizing increased generation from new 

nuclear capacity as a component of the BSER. 

The EPA is likewise not finalizing the proposal to include 

a component representing preserved existing nuclear generation 

in the BSER. On further consideration, we believe it is 

inappropriate to base the BSER on elements that will not reduce 

CO2 emissions from affected EGUs below current levels. Existing 

nuclear generation helps make existing CO2 emissions lower than 

they would otherwise be, but will not further lower CO2 emissions 

below current levels. Accordingly, as described in section 

V.A.3., the EPA is not finalizing preservation of generation 

from existing nuclear capacity as a component of the BSER. 

Deleted: and substantial risks of noncompletion, both of 

Deleted: and low-risk. 
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(iii) Generation from new NGCC units. 

 New NGCC units –- that is, units that had not commenced 

construction as of January 8, 2014, the date of publication of 

the proposed CO2 standards of performance for new EGUs under 

section 111(b) –- are not subject to the standards of 

performance that will be established for existing sources under 

section 111(d) plans based on the BSER determined in this final 

rule. In the June 2014 proposed emission guidelines for existing 

EGUs, the EPA solicited comment on whether to include this 

measure in the BSER. Commenters raised numerous concerns, and 

after consideration of the comments, we are not including 

replacement of generation from affected EGUs through the 

construction of new NGCC capacity in the BSER. In this section, 

we discuss the reasons for our approach. 

 The EPA did not include reduced generation from affected 

EGUs achieved through construction and operation of new NGCC 

capacity in the proposed BSER because we expected that the CO2

emission reductions achieved through such actions would, on 

average, be more costly than CO2 emission reductions achieved 

through the proposed BSER measures. Our determination not to 

include new construction and operation of new NGCC capacity in 

the BSER in this final rule rests primarily on the achievable 

magnitude of emission reductions rather than costs. 

Deleted: Because we agree with these 

commenters, it is not necessary to address 

each of their concerns. 

Deleted: primarily 

Deleted: two 

Deleted: , and we then list, but do not further 

address, additional concerns raised by 

commenters.

Deleted: in part 

Deleted: In particular, we observed that these 

emission reductions would be more costly than 

the reductions achievable through increased 

generation from existing NGCC capacity under 

building block 2. The greater costs would 

arise from two factors: first, capital costs 

incurred to build the new NGCC capacity –- 

which of course would not be necessary with 

respect to existing NGCC capacity –- and 

second, increases in the price of natural gas 

that would be expected to occur with 

additional usage of natural gas beyond the 

amounts used to increase generation from 

existing NGCC capacity. Although commenters 

expressed a range of views on whether 

replacement of generation from affected EGUs 

through generation from new NGCC capacity 

should be included in BSER, after 

consideration of comment we continue to view 

our cost concerns related to these two factors 

as valid and salient.
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 Unlike emission reductions achieved through the use of any 

of the building blocks, emission reductions achieved through the 

use of new NGCC capacity require the construction of additional 

CO2-emitting generating capacity, a consequence that is 

inconsistent with the long-term need to continue reducing CO2

emissions beyond the reductions that will be achieved through 

this rule. New generating assets are planned and built for long 

lifetimes –- frequently 40 years or more –- that are likely 

longer than the expected remaining lifetimes of the steam EGUs 

whose CO2 emissions would initially be displaced be the 

generation from the new NGCC units. The new capacity is likely 

to continue to emit CO2 throughout these longer lifetimes, absent 

decisions to retire the units before the end of their planned 

lifetimes or to install CCS technology in the future at 

substantial additional cost. Because of the likelihood of CO2

emissions for decades, the overall net emission reductions 

achievable through the construction and operation of new NGCC 

are less than for the measures including in the BSER, such as 

increased generation at existing NGCC capacity, which would be 

expected to reach the end of its useful life sooner than new 

NGCC capacity, or construction and operation of zero-emitting RE 

generating capacity. We view the production of long-term CO2

emissions that otherwise would not be created as inconsistent 

Deleted: In addition, we note that unlike 
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with the BSER requirement that we consider the magnitude of 

emissions reductions that can be achieved. For this reason, we 

are not including replacement of generation from affected EGUs 

through the construction and operation of new NGCC capacity in 

the final BSER. 

 Commenters also raised a concern with the interrelation of 

section 111(b) and section 111(d). New NGCC capacity is 

distinguished from the other non-BSER measures discussed above 

by the fact that its CO2 emissions would be subject to the CO2

standards for new EGUs being established under section 111(b). 

Section 111 creates an express distinction between the sources 

subject to section 111(b) and the sources subject to section 

111(d), and commenters expressed concern that to allow section 

111(b) sources to play a direct role in setting the BSER under 

section 111(d) would be inconsistent with congressional intent 

to treat the two sets of sources separately. Section VIII of 

this preamble includes a discussion of ways to address new NGCC 

capacity in the context of different types of section 111(d) 

plans. 

(c) Increasing demand-side energy efficiency to avoid 

generation and emissions from fossil fuel-fired EGUs. 

The final category of approaches for reducing generation 

and CO2 emissions from affected EGUs that the EPA considered in 

Deleted: For both these reasons –- greater cost 

than the emission reductions achievable 

through the building blocks and the long-term 

policy concerns about construction of 

additional CO2-emitting generating capacity –-

Deleted: Commenters raised additional concerns. 

First, commenters expressed 

Deleted: Commenters also expressed concern with 

the potential incentives created by including 

new NGCC capacity in the BSER. Some commenters 

suggested that including new NGCC capacity in 

the BSER would distort market incentives to 

build new NGCC units, particularly if new 

units were allowed to generate emission rate 

credits (ERCs) that could be sold to affected 

EGUs. These commenters suggested that the 

additional incentive for new NGCC units could 

make existing NGCC units less competitive. 

Other commenters suggested that including new 

NGCC capacity in the BSER would promote 

generation from new CO2-emitting units at the 

expense of new zero-emitting units, increasing 

overall emissions within a state. This effect 

would be exacerbated if state plans allowed 

new NGCC units to be treated as “zeroemitting” for purposes of compliance –- as 

suggested by other commenters.¶

In addition, commenters expressed concern 

that the EPA’s inclusion of new NGCC capacity 

in setting the BSER could negatively impact 

ratepayers over the long-term by sending the 

wrong signal to industry and resulting in 

stranded assets if, in the future, carbon 

emissions become more expensive or the EPA 

proposes to incorporate sources built under 

the forthcoming section 111(b) standard into 

the section 111(d) program. ¶

Commenters also expressed concern that 

including generation from new NGCC units in 

setting the BSER could create unreasonable 

uncertainty in the standard, given limitations 

on the ability to accurately project new NGCC 

builds; could create undue pressure on natural 

gas prices; and could create unfair 

disparities in the compliance opportunities 

afforded different states. ¶
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the proposal involves increasing demand-side energy efficiency. 

When demand-side energy efficiency is increased, energy 

consumers need less electricity in order to provide the same 

level of electricity-dependent services – e.g., heating, 

cooling, lighting, and use of motors and electronic devices. 

Through the integrated electricity system, including the 

connection of customers to affected EGUs through the electricity 

grid, reduced demand for electricity, in turn, leads to reduced 

generation and reduced CO2 emissions. Our examination of actions 

and trends underway in the utility power sector confirmed that 

demand-side energy programs are being implemented widely across 

the sector and that investments are increasing. We proposed to 

include avoidance of defined quantities of fossil fuel-fired 

generation through increased demand-side energy efficiency as a 

component of the BSER (proposed building block 4). 

Commenters expressed a wide range of views on the proposed 

reliance on demand-side energy efficiency in the BSER. Some 

commenters strongly supported the proposal, with suggestions for 

improvements, while some commenters strongly opposed the 

proposal and took the position that it exceeded the EPA’s legal 

authority. We do not address the merits of these comments here 

because, for the reasons discussed in section V.B.3.b.(1) below, 

we are not finalizing the proposal to include avoided generation 

Deleted: V.A.3.e. 
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achieved through demand-side energy efficiency as a component of 

the BSER. However, we note that most commenters also supported 

the use of demand-side energy efficiency for compliance whether 

or not it is used in determining the BSER, and we are allowing 

demand-side energy efficiency to be used for that purpose. 

(3) Further analysis to quantify the BSER. 

While the discussion above summarizes how and why the 

components of the BSER were determined in terms of qualitative 

characteristics, it still leaves a wide range of potential 

stringencies for the BSER. As explained in sections V.C., V.D., 

and V.E. below, discussing building blocks 1, 2, and 3 

respectively, the EPA has determined a reasonable level of 

stringency for each of the building blocks rather than the 

maximum possible level of stringency. We have taken this 

approach in part to ensure that there is “headroom” within the 

BSER measures that provides greater assurance of the 

achievability of the BSER for the source category and for 

individual sources. We believe this approach is permissible 

under the CAA. We note that a feature of the method by which we 

have quantified the degree of emission limitation achievable 

through application of the BSER to the two source subcategories 

-– namely, the use of the least stringent CO2 emission 

performance rate quantified for a given source subcategory for 
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any of the three major Interconnections as the CO2 emission 

performance rate for that source subcategory in all three 

Interconnections386 –- provides additional headroom within the 

BSER for sources in the two Interconnections that did not set 

the CO2 emission performance rates ultimately used. Additional 

headroom within the BSER is available through the use of 

emissions trading approaches, because the final rule does not 

limit the use of these mechanisms to sources within the same 

Interconnections. In fact, in response to proposals that emerged 

from the comment record and direct engagement with states and 

stakeholders reflecting their strong interest in pursuing multistate approaches, the guidelines include mechanisms for 

implementing standards of performance that incorporate 

interstate trading, as discussed in section VIII. (In addition, 

as further discussed below, the rule also permits section 111(d) 

plans to allow the use of non-BSER measures for compliance in 

certain circumstances, increasing both compliance flexibility 

and the assurance that the emission limitations reflecting 

application of the BSER are achievable.) 

 

386 Specifically, the respective CO2 emission performance rates 

quantified for the steam EGU subcategory and for the stationary 

combustion turbine subcategory in the Eastern Interconnection 

are being applied to those subcategories in the Western and 

Texas Interconnections as well. This aspect of the BSER 

quantification methodology is discussed below in section V.A.3 

and section VI. 

Deleted: or other multi-unit compliance 
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Further, the sets of measures in each of these individual 

building blocks, in the stringency assigned in this rule, meet 

the criteria for the BSER. That is, they each achieve the 

appropriate level of reductions, are of reasonable cost, do not 

impose energy penalties on the affected EGUs and do not result 

in non-air quality pollutants, and have acceptable cost and 

energy implications for the energy sector as a whole. In 

addition, as explained below, each is adequately demonstrated. 

Importantly, past industry practice and current trends strongly 

support each of the building blocks, as do federal and state 

pollution control programs that require or result in similar 

measures. 

For example, all of the measures in building blocks 2 and 3 

have been implemented for decades, initially for reasons 

unrelated to pollution control, then in recent years in order to 

control non-GHG air pollutants, and more recently, for purposes 

of CO2-emission control by states and companies. Moreover, 

Congress itself recognized in enacting the acid rain provisions 

of CAA Title IV that renewable energy measures reduce CO2 from 

affected EGUs. In addition, the EPA has relied on the measures 

in building blocks 2 and 3 in other rules. 
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It should also be noted that building blocks 2 and 3 also 

meet the criteria for the BSER in combination with one another 

and with building block 1, as described below. 

e. Actions that individual affected EGUs can take to implement 

the BSER measures. We now turn to a summary of actions that 

individual EGUs can take to implement the BSER and that are 

therefore part of the BSER. 

 (1) Improvement in CO2 emission rate at the unit. 

An affected EGU may take steps to improve its CO2 emission 

rate as discussed above for the source category as a whole. As 

discussed in section V.C., the record makes clear that coalfired steam EGUs can make, and have made, heat rate improvements 

to a greater or lesser degree, resulting in reductions in CO2

emissions. The resulting improvement in an EGU’s CO2 emission 

rate would help the EGU achieve an emission limit imposed in the 

form of an emission rate. If the EGU’s emission limit is imposed 

in the form of a mass standard, the heat rate improvement would 

also lower the EGU’s mass emissions provided that the EGU held 

the amount of its generation constant or increased its 

generation by a smaller percentage than the efficiency 

improvement. Under a mass-based standard that incorporates 

emission trading, an EGU that improves its heat rate would need 

Deleted: Identification of 

Deleted: – the individual-source perspective

Deleted: the evaluation of potential BSER 

measures from the individual-source 

perspective.

Deleted: under the source-category perspective. 

Deleted: such 

Deleted: Although the only actions in this 

category identified for inclusion in the BSER 

are heat rate improvements at coal-fired steam 

EGUs, if a particular affected EGU found that 

its circumstances made some other actions in 

the category relatively attractive –- for 

example, heat rate improvements at other types 

of EGUs, co-firing of natural gas, or retrofit 

of CCS –- the EGU could pursue those 

improvements. 

Deleted: s

Deleted: the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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fewer emission allowances for each MWh of generation whatever 

level of generation it chose to produce. 

(2) Actions to implement measures in building blocks 2 and 

3. 

Viewing the BSER from the perspective of an individual EGU, 

there are several ways that affected EGUs can access the 

measures in building blocks 2 and 3, thanks to the integrated 

nature of the electricity system, coupled with the system’s high 

degree of planning and reliability mechanisms. The affected EGUs 

can (a) invest in lower- or zero-emitting generation, which will 

lead to reductions in higher-emitting generation at other units 

in the integrated system; (b) reduce their generation, which in 

the presence of emission reduction requirements applicable to 

the source category as a whole will have the effect of 

increasing demand for and thereby incentivize investment in the 

measures in the building blocks elsewhere in the integrated 

system; or (c) both invest in the measures in the building 

blocks and reduce their own generation, effectively replacing 

their generation with cleaner generation. The availability of 

these options is further enhanced where the individual EGU is 

operating under a standard of performance that incorporates 

emissions trading. 

(a) Investment in measures in building blocks 2 and 3. 

Deleted: , and would also help the EGU achieve 

an emission limit imposed in the form of a 

mass limit if the EGU did not increase its 

generation by a larger percentage than the 

percentage of its emission rate improvement.

Deleted: individual-source 

Deleted: ing
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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An affected EGU may take the following actions to invest in 

the measures in building blocks 2 and 3: For building block 2, 

the owner/operator of a steam EGU may increase generation at an 

existing NGCC unit it already owns, or one that it purchases or 

invests in. In addition, the owner/operator may, through a 

bilateral transaction with an existing NGCC unit, pay the unit 

to increase generation, and acquire the CO2-reducing effects of 

that increased generation. 

Similarly, for building block 3, an owner/operator of an 

affected EGU may build, or purchase an ownership interest in, 

new renewable energy generating capacity and acquire the CO2-

reducing effects of that increased generation. Alternatively, an 

owner/operator may, through bilateral transactions, purchase the 

CO2-reducing effects of that increased generation from renewable 

generation providers. 

In case of an investment in either building block 2 or 

building block 3 by a unit subject to a rate-based form of CO2

performance standard, it would be reasonable for state plans to 

authorize affected EGUs to use an approved and validated 

instrument such as an “emission rate credit” (ERC) representing 

the emissions-reducing benefit of the investment.387 

 

387 Criteria for issuance of valid emission rate credits and for 

tracking credits after issuance are discussed in section VIII 

below. 

Deleted: purchase 

Deleted: as emission rate credits

Deleted: purchase 

Deleted: the section 111(d) plan would specify 

the mechanism by which the affected unit could 

account for the emissions-reducing benefit of 

the investment when computing its emission 

rate for purposes of determining compliance 

with the performance standard. The mechanism 

could involve 

Deleted: of 

Deleted: or could involve an approved 

averaging arrangement
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When combined with reduced generation, either at the 

affected EGU or elsewhere in the interconnected system, the 

types of actions listed above would be fully equivalent to 

building blocks 2 and 3 when viewed from perspective of the 

overall source category. Thus, a source could achieve a standard 

of performance identical to the applicable CO2 emission 

performance rate in the EPA emission guidelines, through 

implementation of the actions described above for building 

blocks 2 and 3, along with the actions described further above 

for building block 1. 

The EPA anticipates that in instances where section 111(d) 

plans provide for the use of instruments such as emission rate 

credits as a mechanism to facilitate use of these measures, 

organized markets will develop so that owner/operators of 

affected EGUs that have invested in measures eligible for the 

issuance of emission rate credits will be able to sell those 

credits and other affected EGUs will be able to purchase them. 

Such markets have developed for other instruments used for 

emissions trading purposes. For example, liquid markets for SO2

allowances developed rapidly following the implementation of 

Title IV of the 1990 Clean Air Act Amendments establishing the 

Acid Rain Program. Members of Congress and industry had 

expressed concern during the legislative debate that the lack of 

Deleted: the source-category 

Deleted: Therefore, the menu of these actions, 

including reduced generation, is appropriate 

for inclusion in the BSER. That is,

Deleted: 

Deleted: or the mass limit equivalent, 

Deleted: By the same token, for the demand-side 

energy measures that the EPA proposed as 

building block 4, an owner/operator of an 

affected EGU may implement demand-side energy 

efficiency programs directly or hire 

contractors or energy service companies to do 

so, and claim the resulting emission rate 

credits. The owner/operator may also engage in 

bilateral transactions with distribution 

utilities that already implement demand-side 

energy efficiency programs and pay them to 

implement such a program.388 When combined with 

reduced generation, either at the affected EGU 

or elsewhere in the interconnected system, 

these types of actions would be fully 

equivalent to proposed building block 4 when 

viewed from a source-category perspective. As 

noted elsewhere, the EPA has determined not to 

include proposed building block 4 in the BSER 

in this final rule. However, the measures in 

building block 4 would still be available for 

compliance purposes to the extent permitted 

under state plans, and the list of actions 

above indicates the range of ways through 

which affected EGUs could access this 

resource.¶
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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a liquid SO2 allowance market would create challenges for 

affected sources that needed to acquire allowances to meet their 

compliance obligations. Congress added statutory provisions to 

ensure that, should a market not develop, sources could purchase 

needed allowances directly from EPA. In fact, these provisions 

went unused because a liquid market for allowances did develop 

very quickly. Sources engaged in allowance transactions directly 

with other sources as they sought to lower compliance costs. 

Market intermediaries offered services to sources to match 

allowance buyers and sellers and helped sources understand their 

compliance options. Trade associations worked with members to 

develop standardized contracts and other tools to facilitate 

allowance transactions, thereby reducing transaction costs. 

Similar developments have occurred in state-level renewable 

portfolio standard programs.389

If states choose to allow through their section 111(d) 

plans mechanisms or standards of performance involving 

instruments such as emission rate credits (ERCs), the EPA 

 

389 The emergence of markets under the Acid Rain Program and 

other environmental programs where trading has been permitted, 

as well as state and industry support for the development of 

markets under states’ section 111(d) plans, is discussed in a 

recent report by the Advanced Energy Economy Institute. AEE 

Institute, Markets Drive Innovation – Why History Shows that the 

Clean Power Plan Will Stimulate a Robust Industry Response (July 

2015), available at https://www.aee.net/aeei/initiatives/epa111d.html#epa-reports-and-white-papers.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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believes that there would be an ample supply of such credits, 

for several reasons. First, as discussed in sections V.D. and 

V.E., the EPA has established the stringencies for building 

blocks 2 and 3 at levels that are reasonable and not at the 

maximum achievable levels, providing headroom for investment in 

the measures in these building blocks beyond the amounts 

reflected in the CO2 emission performance rates reflecting 

application of the BSER. In addition, if emission limits are set 

at the CO2 emission performance rates, affected EGUs in the 

Western and Texas Interconnections on average do not need to 

implement the building blocks to their full extent in order to 

achieve their emission limits because the performance rates for 

sources in these regions are set at the less stringent rates 

determined to be reasonable for application of the BSER to 

sources in the Eastern Interconnection. Further, to the extent 

that section 111(d) plans take advantage of the latitude the 

final guidelines provide for states to set standards of 

performance incorporating emissions trading on an interstate 

basis among affected EGUs in different Interconnections, all 

sources can take advantage of the headroom available in other 

Interconnections. As a result, significant amounts of existing 

NGCC capacity and potential for renewable energy remain 

available to serve as the basis for issuance of ERCs for all 

Deleted: should 

Deleted: sources 

Deleted: that includes the use of multi-state 

trading 

Deleted: sources or other multi-unit compliance 

approaches among sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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affected EGUs in both source subcategories to rely on to achieve 

their emission limits. Because we recognize the ready 

availability to states of standards of performance that 

incorporate emissions trading –- and because such standards can 

easily encompass interstate trading -- this rule includes by 

express design a variety of options that states and utilities 

can select to pursue interstate compliance regimes that mirror 

the interconnected operation of the electricity system. As a 

result, the EPA believes that it is reasonable to anticipate 

that a virtually nationwide emission trading market for 

compliance will emerge, and that ERCs will be effectively 

available to any affected EGU wherever located, as long as its 

state plan authorizes emissions trading among affected EGUs.390

It should also be noted that although the measures in 

building blocks 2 and 3 can be taken into account directly in 

computations to determine whether an individual affected EGU has 

achieved an emissions limit set in an emission rate-based form 

 

390 There is a theoretical possibility – which we view as 

extremely unlikely – that the affected EGUs in a given state 

that has chosen to pursue a rate-based approach could have 

insufficient access to ERCs because of the choices of all or 

most other states to pursue mass-based approaches. In such a 

situation, it might be appropriate to allow the affected EGUs in 

that state to assume for purposes of demonstrating compliance 

with their standards of performance that the generation 

replacing any reductions in generation at those affected EGUs 

that was not paired with verified ERCs came from existing NGCC 

units in other states. 

Deleted: source 

Deleted: either 

Deleted: sources or the purchase and use of 

ERCs in meeting the standard of performance 

the state establishes.

Deleted: quantified 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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if, as expected, the state chooses to authorize a mechanism for 

doing so, they are not taken into account directly in 

computations to determine whether an individual affected EGU has 

achieved an emissions limit set in a mass-based form. However, 

by reducing generation and therefore CO2 emissions from the group 

of affected EGUs within a region, these measures facilitate the 

ability of the individual EGUs within the region to achieve 

mass-based limits by choosing to reduce their own generation and 

emissions. 

(b) Reduced generation. 

In addition, the owner/operator of an affected EGU may help 

itself meet its emission limit by reducing its generation. If 

the owner/operator reduces generation and therefore the amount 

of its CO2 emissions, then, if the affected EGU is subject to an 

emission rate limit, the owner/operator will need to implement 

fewer of the building block measures, e.g., buy fewer emission 

rate credits, to achieve its emission rate; and if the affected 

EGU is subject to a mass emissions limit, the owner/operator 

will need fewer mass allowances. 

An owner/operator may take actions to ensure that it 

reduces its generation. For example, it may accept a permit 

restriction on the amount of hours that it generates. In 

addition or alternatively, it may represent the cost of 
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additional emission credits or allowances that would be required 

due to incremental generation as an additional variable cost 

that increases the total variable cost considered when dispatch 

decisions are made for the unit. 

Because of the integrated nature of the electricity system, 

combined with the system’s high degree of planning and 

reliability safeguards, as well as the long planning horizon 

afforded by this rule, individual affected EGUs can in aggregate 

achieve the requisite level of reductions in generation adequate 

to achieve emission limits reflecting the BSER.391 Individual 

affected steam EGUs can reduce their generation in the amounts 

of building blocks 2 and 3, while individual affected NGCC units 

can reduce their generation in the amount of building block 3. 

With emission limits for the source category as a whole in 

place, the resulting reduction in supply of higher-emitting 

generation will incentivize additional utilization of existing 

NGCC capacity, and the resulting reduction in overall fossil 

fuel-fired generation will incentivize investment in additional 

renewable energy generating capacity, and the integrated 

 

391 For purposes of this discussion, we assume that coal-fired 

steam generators also implement building block 1 measures so 

that they will implement the full set of measures needed to 

achieve their emission limit. 
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system’s response to these incentives will ensure that the 

demand for electricity services will continue to be met.

(c) Emissions trading. 

As described above, viewed from the perspective of the 

source category as a whole, it is reasonable for our analysis of 

the BSER to include an element of source-category-wide multiunit compliance which could be implemented via a state-set 

standard of performance incorporating emissions trading, under 

which EGUs could engage in trading of rate-based emission 

credits or mass-based emission allowances. By the same token, 

viewed from the perspective of an individual EGU, consideration 

of the ready availability to states of the opportunity to 

establish standards of performance that incorporate emissions 

trading is integral to our analysis, and our assessment of the 

actions available to individual EGUs for achieving standards of 

performance reflecting the BSER therefore include the purchase 

of rate-based emission credits or mass-based emission 

allowances, because one of the things an affected EGU can do to 

achieve its emission limit is to buy a credit or an allowance 

from another affected EGU that has over-complied. The use of 

purchased credits or allowances would have to be authorized, of 

course, in the purchasing EGUs’ states’ section 111(d) plans and 

would have to meet conditions set out for such approaches in 

Deleted: source-category

Deleted: 

Deleted: individual-source 

Deleted: sources 

Deleted: sources’ 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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section VIII below. The role of emissions trading in the BSER 

analysis is discussed further in section V.A.2.f. below. 

f. The role of emissions trading. In making its BSER 

determination here, the EPA examined a number of technologies 

and emissions reduction measures that result in lower levels of 

CO2 emissions and evaluated each one on the basis of the several 

criteria on which the EPA relies in determining the BSER. In 

contrast to section 111(b), however, section 111(d)(1) obliges 

the states, not the EPA, to set standards of performance for the 

affected EGUs in order to implement the BSER. Accordingly, with 

respect to each measure or control strategy under consideration, 

the EPA also evaluated whether or not the states could establish 

standards of performance for affected EGUs that would allow 

those sources to adopt the measure in question. In this case, 

the EPA identified a host of factors that persuaded us that a 

state could establish a standard of performance that 

incorporated emissions trading.393 These wide-ranging factors 

include (i) the global nature of the air pollutant in question – 

i.e., CO2; (ii) the transactional nature of the industry; (iii) 

the interconnected functioning of the industry and the 

 

393 As an alternative to authorizing trading that would still 

provide a degree of multi-unit flexibility, a state could choose 

in its state plan to give an owner of multiple affected EGUs 

flexibility regarding how the owner distributes any credits or 

allowances it acquires among its affected EGUs.

Deleted: (d) Other multi-unit compliance 

approaches. ¶

The measures included in the BSER are also 

available through standards of performance and 

state plans that operate without emissions 

trading involving tradable instruments (e.g., 

rate-based emission credits or mass-based 

emission allowances) but include other multiunit compliance approaches that reflect the 

global nature of the CO2 pollutant and the 

interconnected nature of the electricity 

system. Although potentially somewhat less 

flexible than emissions trading approaches, 

other types of multi-unit compliance 

approaches generally offer the same ability 

for affected sources with lower-cost emissionreduction opportunities to overcomply and to 

make surplus emission reductions available for 

use by affected sources with higher-cost 

emission-reduction opportunities. Thus, like 

emissions trading, these approaches 

effectively make it possible for affected EGUs 

to invest in emission reduction measures that 

are physically implemented at other locations, 

consistent with longstanding practice in the 

interconnected electricity system.¶

For units subject to rate-based performance 

standards, multi-unit compliance approaches 

other than emissions trading approaches would 

generally be “averaging” approaches where 

multiple units would combine their monitored 

emissions and generation (as well as any 

authorized emission rate credits representing 

the emissions-reducing benefits of investments 

in specific emissions-reducing activities) in 

order to compute a combined emission rate that 

would, in turn, be compared to a combined 

rate-based performance standard. For units 

subject to mass-based performance standards, 

such approaches would generally be 

“aggregation” approaches where multiple units 

would combine their monitored emissions in 

order to compute a combined total mass of 

emissions that would, in turn, be compared to 

a combined mass-based performance standard.392

The use of averaging or aggregation approaches 

would have to be authorized in the 111(d) 

plans covering all the participating affected 

sources and would have to meet conditions set 

out for such approaches in section VIII below. 

Deleted: sources 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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coordination of generation resources at the level of the 

regional grid; (iv) the extensive experience that states – and 

EGUs – already have with emissions trading; and (v) material in 

the record demonstrating strong interest on the part of many 

states and affected EGUs in using emissions trading in meeting 

their obligations.394

 

394 Numerous states submitted comments urging the EPA to allow 

states to develop trading programs, including interstate trading 

programs. They include, for example, Alabama (EPA should develop 

and issue guidelines that allow options for multi‐state plans and 

interstate credit trading programs, comment 23584), California 

(EPA should provide flexibility for allowance trading programs 

to be integrated into state plans, comment 23433), Hawaii 

(supports use of emission credit trading with other entities to 

achieve compliance, comment 23121), Massachusetts (EPA should 

explore possibility of hosting a third‐party emissions trading 

bank that can allow states interested in allowance trading to 

plug and play in to a wider, more cost‐effective market, comment 

31910), Michigan (supports emissions trading programs, comment 

23987), Minnesota (develop model trading rule that states could 

incorporate by reference as part of plan and automatically be 

included in multi-state mass trading program, comment 23987), 

North Carolina (EPA should examine a system of banking and 

trading for energy efficiency, comment 23542), Oregon (EPA 

should expand the explicit options for multi‐state plans beyond 

cap‐and-trade, comment 20678), Washington (supporting trading, 

comment 22764), Wisconsin (requesting EPA to develop a national 

trading program, Post‐111(d) Proposal Questions to EPA WI 

Questions for 7/16 Hub call). 

In addition, several groups of states supported trading 

programs: Georgetown Climate Center (a group of state 

environmental agency leaders, energy agency leaders, and public 

utility commissioners from California, Colorado, Connecticut, 

Delaware, Illinois, Maine, Maryland, Massachusetts, Minnesota, 

New Hampshire, New York, Oregon, Rhode Island, Vermont, and 

Washington) (“We believe states should have maximum flexibility 

to determine what kinds of collaborations might work for them. 

These could include submission of joint plans, standardized 

Deleted: suggesting 

Deleted: and states 

Deleted: 

Deleted: IBR 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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approaches to trading renewable or energy efficiency credits.... 

We also encourage EPA to help facilitate such interstate 

agreements or multi-state collaborations by working with states 

to either identify or provide a platform or framework that 

states may elect to use for the tracking and trading of avoided 

generation or emissions credits due to interstate efficiency or 

renewable energy.” comment 23597, at 39-40); Regional Greenhouse 

Gas Initiative (including Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

Vermont) (“[E]very serious proposal to reduce carbon emissions 

from EGUs, from proposed US legislation to programs in place in 

California and Europe, has identified allowance trading as the 

best approach.” Comment 22395 at 7-8); Western States Center for 

New Energy Economy (including Arizona, California, Colorado, 

Idaho, Montana, Nevada, Oregon, South Dakota, Utah, Washington) 

(“Some degree of RE and EE credit trading among states may 

support compliance, even in the absence of a comprehensive 

regional plan. Therefore, EPA should support approaches which 

allow states flexibility to allocate credit for these zerocarbon resources, along with approaches which allow states to 

reach agreements on the allocation of carbon liabilities. This 

includes ensuring that existing tracking mechanisms for 

renewable energy in the West, such as the Western Renewable 

Energy Generation Information System (WREGIS), are compatible 

with the final proposal.” Comment 21787 at 5); Midcontinent 

States Environmental and Energy Regulators (including Arkansas, 

Illinois, Michigan, Minnesota Missouri, Wisconsin) (EPA should 

also provide states with optional ... systems (or system) for 

tracking emissions, allowances, reduction credits, and/or 

generation attributes that states may choose to use in their 

111(d) plans,” comment 22535 at 3). 

In addition, trading programs were supported by, among 

others, a group of Attorneys General from 11 states and the 

District of Columbia. Comment 25433 (Attorneys General from New 

York, California, Connecticut, Maine, Maryland, Massachusetts, 

New Mexico, Oregon, Rhode Island, Vermont, Washington, District 

of Columbia, and New York City Corporation Counsel). 

Numerous industry commenters also supported trading, 

including Alliant Energy Corporate Services, Inc. (comment 

22934), Calpine (comment 23167), DTE Energy (comment 24061), 

Exelon (comment 23428 and 23155), Michigan Municipal Electric 

Association (MMEA) (comment 23297), National Climate Coalition 

(comment 22910), Pacific Gas and Electric Company (comment 

23198), Western Power Trading Forum (WPTF) (comment 22860). 

Deleted: ¶
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The states’ and EGUs’ interest in emissions trading is 

rooted in the well-recognized benefits that trading provides. 

The experience of multiple trading programs over many years has 

shown that some units can achieve emissions reductions at lower 

cost than others, and a system that allows for those lower-cost 

reductions to be maximized is more cost-effective overall to the 

industry and to society. Trading provides an affected EGU other 

options besides direct implementation of emission reduction 

measures in its own facility or an affiliated facility when 

lower-cost emission reduction opportunities exist elsewhere. 

Specifically, the affected EGU can cross-invest, that is, invest 

in actions at facilities owned by others, in exchange for ratebased emission credits or mass-based emission allowances. 

Through cross-investment, trading allows each affected EGU to 

access the control measures that other affected EGUs decide to 

implement, which in this case include all the building blocks as 

well as other measures. 

Accordingly, our analysis of the measures under 

consideration in our BSER determination reflected the wellfounded conclusion that it is reasonable for states to 

 

Environmental advocates also supported trading, including Clean 

Air Task Force (comment 22612), Environmental Defense Fund 

(comment 23140), Institute for Policy Integrity, New York 

University School of Law (comment 23418). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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incorporate emissions trading in the standards of performance 

they establish for affected EGUs and that many, if not all, 

would do so. 

Whether viewed from the perspective of an individual EGU or 

the source category as a whole, emissions trading is thus an 

integral part of our BSER analysis. Again, we concluded that 

this is reasonable given the global nature of the pollutant, the 

transactional and interconnected nature of this industry, and 

the long history and numerous examples demonstrating that, in 

this sector, trading is integral to how regulators have 

established, and sources have complied with, environmental and 

similar obligations (such as renewable energy standards) when it 

was appropriate to do so given the program objective. The 

reasonableness is further demonstrated by the numerous comments 

(some of which are noted above) from industry, states, and other 

stakeholders in this rulemaking that supported allowing states 

to adopt trading programs to comply with section 111(d) and 

encouraged EPA to facilitate trading across state lines through 

the use of trading-ready state plans. The EPA’s reliance on 

trading in its BSER determination does not mean, however, that 

states are required to establish trading programs (just as 

states are not required to implement the building blocks that 

comprise BSER). Nor does it mean that trading is the only 

Deleted: through the source category or 

individual source perspective, 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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transactional approach that we could have considered in setting 

the BSER or that states could use to effectuate the building 

blocks were they to decide that they did not want to take on the 

responsibility of running a trading program. Rather, it is 

simply a recognition of the nature of this industry and the long 

history of trading as an important regulatory tool in 

establishing regulatory regimes for this industry and its 

reasonable availability to states in establishing standards of 

performance. 

As an initial matter, trading is permissible for these 

emission guidelines because CO2 is a global pollutant; the 

location of its emission does not affect the location of the 

environmental harm it causes. For CO2, it is the total amount of 

emissions from the source category that matters, not the 

specific emissions from any one EGU. The fact that trading 

allows sources to shift emissions from one location to another 

does not impede achievement of the environmental goal of 

reducing CO2 pollution. In its character as a pollutant whose 

impacts extend beyond local areas, CO2 pollution resembles to 

some extent the regional SO2 pollution that Congress chose to 

address with the emissions trading program enacted in Title IV 

of the 1990 CAA Amendments. The argument in support of trading 

approaches is even stronger for CO2 pollution, whose adverse 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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effects are global rather than merely regional like the SO2

emissions contributing to acid precipitation. 

Further, as discussed elsewhere in the preamble, the 

utility power sector – and the affected EGUs and other 

generation assets that it encompasses – has a long history of 

working on a coordinated basis to meet operating and 

environmental objectives, necessitated and facilitated by the 

unique interconnectedness and interdependence of the sector. 

That history includes joint dispatch for economic and 

reliability purposes, both within large utility systems and in 

multi-utility power pools that have evolved into RTOs; joint 

power plant ownership arrangements; and long-term and short-term 

bilateral power purchase arrangements. More recently, the 

sector’s history also includes emissions trading programs 

designed by Congress, the EPA, and the states to address 

regional environmental problems and, most recently, climate 

change. Examples of such programs are noted below. 

Essentially, trading does nothing more than commoditize 

compliance, with the following two important results emerging 

from that: it reduces the overall costs of controls and spreads 

those costs among the entire category of regulated entities 

while providing a greater range of options for sources that may 

not want to make on-site investments for controlling their 

Commented [A19]: Which are the two points? 

Deleted: 
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emissions and may prefer to make the same investment, via the 

purchase of the tradable compliance instrument, at another 

generating source. Building blocks 2 and 3 entail affected EGUs 

investing in increased generation from existing NGCC units and 

renewable energy. The affected EGUs could do so in any number of 

ways, including acquiring ownership interests in existing NGCC 

or renewable energy facilities or entering into bilateral 

transactions with the owners of existing NGCC facilities or 

renewable energy sources. As discussed elsewhere, it is 

reasonable to expect that these actions can develop into 

discrete, tradable commodities (e.g., an emission rate credit, 

or ERC) and that liquid markets will develop, which would reduce 

transaction costs and allow an affected EGU to comply with its 

emission limits by purchasing discrete units in amounts tailored 

closely to its compliance needs. The existence of such tradable 

commodities also incentivizes over-compliance by affected EGUs, 

which can then sell their over-compliance in the form of ERCs or 

allowances to other affected EGUs. Moreover, as noted elsewhere, 

the opportunity to trade is consistent with the EPA’s regional 

approach for the building blocks. 

By the same token, the opportunity to trade incentivizes 

affected EGUs to over-comply with building block 1. Thus, the 

opportunity to trade supports the EPA’s assumptions about what 
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an average affected EGU can achieve with regards to heat rate 

improvement even if each and every affected EGU cannot achieve 

that level of improvement. In addition, trading incentivizes 

affected EGUs to consider low-cost, non-BSER methods to reduce 

emissions as well, and, as discussed below, there are numerous 

non-BSER methods, ranging from implementation of demand-side 

energy efficiency programs to natural gas co-firing. 

Trading has become an important mechanism for achieving 

environmental goals in the electricity sector in part because 

trading allows environmental regulators to set an environmental 

goal while preserving the ability of the operators of the 

affected EGUs to decide the best way to meet it taking account 

of the full range of considerations that govern their overall 

operations. For example, commenters were concerned that because 

of building block 2, the emission guidelines would require state 

environmental regulators to make dispatch decisions for the 

electricity markets, a role that state environmental regulators 

do not currently play. Although building block 2 entails 

substituting existing NGCC generation for steam generation, 

implementing the emission limits that are based in part on 

building block 2 through a trading program provides the 

individual affected EGUs with a great deal of control over their 

own generation while the industry as a whole achieves the 
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environmental goals. For example, individual steam generators 

have the option of maintaining their generation as long as they 

acquire additional ERCs. Moreover, trading provides a way for 

states to set standards of performance that realize the required 

emissions reduction without requiring any form of “environmental 

dispatch” because, as many existing trading programs have shown, 

monetization of the environmental constraint is consistent with 

a least-cost dispatch system. Trading also supports the EPA’s 

approach to the “remaining useful life” provision in section 

111(d)(1) because with trading, an affected EGU with a limited 

remaining useful life can avoid the need to implement long-term 

emission reduction measures and can instead purchase ERCs or 

other tradable instruments, such as mass-based allowances, 

thereby allowing the state to meet the requirements of this 

rule. 

The EPA’s job in issuing these emission guidelines is to 

determine the BSER that has been adequately demonstrated and to 

set emission limitations that are achievable through the 

application of the BSER and implementable through standards of 

performance established by the states. The three building blocks 

are the EPA’s determination of what technology is adequately 

demonstrated. We also consider trading an integral part of the 

BSER analysis because, in addition to being available to states 

Deleted: purchase 

Deleted: source 
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for incorporation in the standards of performance they set for 

affected EGUs, trading has been adequately demonstrated for this 

industry in circumstances where systemic rather than unit-level 

reductions are central. Congress, the EPA, and state regulators 

have established successful environmental programs for this 

industry that allow trading of environmental (or similar) 

attributes, and trading has been widely used by the industry to 

comply with these programs. Examples include the CAA Title IV 

Acid Rain Program, the NOX SIP Call (currently referred to as the 

NOX Budget Trading Program), the Clean Air Interstate Rule 

(CAIR), the Cross-State Air Pollution Rule (CSAPR),395 the 

Regional Haze trading programs, the Clean Air Mercury Rule,396

 

395 For example, in CSAPR, which covered the states in the 

eastern half of the U.S., the EPA assumed the existence of 

trading across those states in the rule’s cost estimates 

contained in the Regulatory Impact Analysis (RIA). “Regulatory 

Impact Analysis for the Federal Implementation Plans to Reduce 

Interstate Transport of Fine Particulate Matter and Ozone in 27 

States; Correction of SIP Approvals for 22 States” 32 (June 

2011), http://www.epa.gov/airtransport/CSAPR/pdfs/FinalRIA.pdf 

In addition, the rule is being implemented either through 

federal implementation plans (FIPs) that authorize interstate 

emission trading or state implementation plans (SIPs) that 

authorize interstate emissions trading.

396 Although the CAMR trading program never took effect because 

the rule was vacated on other grounds, it consisted of a 

nationwide trading program that the EPA adopted under CAA 

section 111(d). Some states declined to allow their sources to 

participate in the trading program on the grounds that 

nationwide trading was not appropriate for the air pollutant at 

issue, mercury, a hazardous air pollutant that caused adverse 

local impacts. 
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RGGI, the trading program established by California AB32, and 

the South Coast Air Quality Management District RECLAIM program. 

We describe these programs in section II.E. of this preamble. In 

addition, we note in the Legal Memorandum accompanying this 

preamble that Congress, in enacting the Title IV acid rain 

trading program, and the EPA, in promulgating the regulatory 

trading programs listed, recognized both the suitability of 

trading for the EGU industry and the benefits of trading in 

reducing costs, spreading costs to affected EGUs throughout the 

sector, and facilitating the ability of affected EGUs to comply 

with their emission limits. In addition, as we discuss in 

section V.E. of this preamble, many states have adopted 

renewable energy standards that promote renewable energy through 

the trading of renewable energy certificates (RECs). 

Based on this history, it is reasonable for the EPA to 

determine that states can establish standards of performance 

that incorporate trading and, as a result, for purpose of making 

a BSER determination here to evaluate prospective emissions 

control measures in light of the availability of trading. 

Trading is a regulatory mechanism that works well for this 

industry. The environmental attributes in the preceding programs 

(representing emissions of air pollutants) are identical to or 

similar in nature to the environmental attribute here (CO2

Deleted: the background 

Deleted: credits 
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emissions). The markets for RECs show that robust markets for 

renewable energy, in particular, already exist. 

Given the benefits of trading and the background of multiunit coordination grounded in the nature of the utility power 

sector, it is natural for sources and states to look for 

opportunities to apply similar coordination to a regional 

problem such as reduction of CO2 emissions from the sector. As 

noted earlier, the EPA heard this interest expressed during the 

outreach process for this rulemaking and saw it reflected in 

comments on the proposal. Emissions trading was prominent in 

these expressions of interest: while the proposal allowed 

trading and encouraged the development of multi-state plans 

which would allow the benefits of trading to extend over larger 

regions, we heard that interest was even greater in “tradingready” plans that would use trading mechanisms and market-based 

coordination, rather than state-to-state coordination, as the 

primary means of facilitating multi-unit approaches to 

compliance. The general industry and state preference for multiunit compliance approaches makes great sense in the context of 

the industry and this pollutant, as does the specific preference 

for trading-ready section 111(d) plans, and we have made efforts 

in the final rule to accommodate trading-ready plans as 

described in section VIII. 

Deleted: The 
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g. Measures that reduce CO2 emissions or CO2 emission rates but 

are not included in the BSER. There are numerous other measures 

that are available to at least some affected EGUs to help assure 

that they can achieve their emission limits, even though the EPA 

is not identifying these measures as part of the BSER. These 

measures include demand-side energy efficiency implementable by 

affected EGUs; new or up-rated nuclear generation; renewable 

measures other than those that are part of building block 3, 

including distributed generation solar power and off-shore wind; 

combined heat and power and waste heat power; and transmission 

and distribution improvements. In addition, a state may 

implement measures that yield emission reductions for use in 

reducing the obligations on affected EGUs, such as demand-side 

energy efficiency measures not implementable by affected EGUs, 

including appliance standards, building codes, and drinking 

water or wastewater system efficiency measures. The availability 

of these measures further assures that the appropriate level of 

emission reductions can be achieved and that affected EGUs will 

be able to achieve their emission limits. 

h. Ability of EGUs to implement the BSER. The EPA’s analysis, 

based in part on observed decades-long behavior of EGUs, shows 

that all types and sizes of affected EGUs in all locations are 

able to undertake the actions described as the BSER, including 
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investor-owned utilities, merchant generators, rural 

cooperatives, municipally-owned utilities, and federal 

utilities. Some may need to focus more on certain measures; for 

example, an owner of a small generation portfolio consisting of 

a single coal-fired steam EGU may need to rely more on crossinvestment approaches, possibly including the purchase of 

emission credits or allowances, because of a lack of sufficient 

scale to diversify its own portfolio to include NGCC capacity 

and RE generating capacity in addition to coal-fired capacity. 

As noted elsewhere, as a legal matter, it is not necessary that 

each affected EGU be able to implement the BSER, but in any 

event, in this rule, all affected EGUs can do so. Since states 

can reasonably be expected to establish standards of performance 

incorporating emissions trading, affected EGUs may rely on 

emissions trading approaches authorized under their states’ 

section 111(d) plans to, in effect, invest in building block 

measures that are physically implemented at other locations. As 

discussed above, the EPA’s quantification of the CO2 emission 

performance rates in a manner that provides headroom within the 

BSER also contributes to the ability of all affected EGUs to 

implement the BSER and achieve emissions limitations consistent 

with those performance rates. 

Deleted: multi-unit compliance 

Deleted: renewable 

Deleted: source 

Deleted: or other multi-unit compliance 
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i. Subcategorization. As noted above, in this rule, we are 

treating all fossil fuel-fired EGUs as a single category, and, 

in the emission guidelines that we are promulgating with this 

rule, we are treating steam EGUs and combustion turbines as 

separate subcategories. We are determining the BSER for steam 

EGUs and the BSER for combustion turbines, and applying the BSER 

to each subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. As we discuss below, 

this approach is fully consistent with the provisions of section 

111(d), which simply require the EPA to determine the BSER, do 

not prescribe the method for doing so, and are silent as to 

subcategorization. This approach is also fully consistent with 

other provisions in section 111, which require the EPA first to 

list source categories that may reasonably be expected to 

endanger public health or welfare and then to regulate new 

sources within each such source category, and which grant the 

EPA discretion whether to subcategorize the sources for purposes 

of determining the BSER. 

 As discussed below, each affected EGU can achieve the 

performance rate by implementing the BSER, specifically, by 

taking a range of actions –- some of which depend on features of 

the section 111(d) plan chosen by the state, such as the choice 
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of rate-based or mass-based standards of performance and the 

choice of whether and how to permit emissions trading -- 

including investment in the building blocks, replaced or reduced 

generation, and purchase of emission credits or allowances. 

Further, in the case of a rate-based state plan, several other 

compliance options not included in the BSER for this rule are 

also available to all affected EGUs, including investment in 

demand-side energy efficiency measures. Such compliance options 

may also indirectly help affected EGUs achieve compliance under 

a mass-based plan. 

 Our approach of subcategorizing between steam EGUs and 

combustion turbines is reasonable because building blocks 1 and 

2 apply only to steam EGUs. Moreover, our approach of not 

further subcategorizing as between different types of steam EGUs 

or combustion turbines reflects the reasonable policy that 

affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates and can do so at a reasonable cost using the 

approaches we have identified as the BSER as well as other 

available measures. 

 Of course, a state retains great flexibility in assigning 

standards of performance to its affected EGUs and can impose 

different emission reduction obligations on its sources, as long 

Deleted: what multi-unit compliance approaches 

Deleted: , possibly including

Deleted: approaches 

Deleted: emissions trading or other multi-unit 

compliance approaches

Deleted: sources, 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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as the overall level of emission limitation is at least as 

stringent as the emission guidelines, as discussed below. 

3. Changes from proposal 

 For the BSER determined in this final rule, based on 

consideration of comments, the EPA has adopted certain 

modifications to the proposed BSER. In this subsection we 

describe the most significant modifications, including some that 

relate to individual building blocks and some that are more 

general. Additional modifications that relate to individual 

building blocks are discussed in the respective sections for 

those building blocks below (sections V.C. through V.E.). 

 We note that taken together, the modifications yield 

emission reductions requirements that commence more gradually 

than the proposed goals but are projected to produce greater 

emission reductions overall by 2030.397 We also note that the 

modifications lead to requirements that are more uniform across 

states than was the case in the proposal, with the final 

requirements generally becoming more stringent in states with 

 

397 For the proposed rule, the EPA projected total CO2 emission 

reductions from 2005 levels of 29% in 2025 and 30% in 2030. For 

the final rule, the EPA projects total CO2 emissions reductions 

from 2005 levels of 28% in 2025 and 32% in 2030. See Regulatory 

Impact Analysis for the CPP Proposed Rule, Table 3-6, and 

Regulatory Impact Analysis for the CPP Final Rule, Table 3-6, 

available in the docket. 

Deleted: refinements, 

Deleted: refinements 

Deleted: slightly 

Deleted: refinements 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the highest 2012 CO2 emission rates and less stringent in states 

with lower 2012 CO2 emission rates. 

a. Interpretations of CAA section 111. In the June 2014 proposal, 

the EPA proposed interpretations of section 111(a)(1) and (d), 

and applied these interpretations to existing fossil fuel-fired 

EGUs.398 Informed by comments, the EPA has clarified some of 

these interpretations, and has developed a more refined 

understanding of how some of these interpretations should be 

applied. The clarified and more refined interpretations replace 

the proposed interpretations.

 Two of these points merit mention here. First, the EPA is 

clarifying in this rule that the interpretation of “system of 

emission reduction” does not include emission reduction measures 

that the states have authority to mandate without the affected 

EGUs being able to implement the measures themselves (e.g., 

appliance standards or building codes). In the final rule, we 

have clarified that the components of the BSER must be 

implementable by the affected EGUs, not by the states, and we 

show that all the components of the BSER have been demonstrated 

to be achievable on that basis without reliance on actions that 

 

398 The June 2014 proposal in part referenced proposed 

interpretations of section 111(a)(1) that the EPA explained in 

the January 2014 proposal to address CO2 emissions from new 

fossil fuel-fired EGUs under section 111(b). 

Deleted: , as indicated in section V.A.1. and 

the Legal Memorandum for the CPP Final Rule 

available in the docket, as well as in the 

final rule for new sources promulgated 

concurrently with this final rule for existing 

sources.

Deleted: sources 

Deleted: sources, 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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can be accomplished only through government mandates. Further 

discussion of these points can be found throughout this section 

on the BSER and the following sections on the individual 

building blocks. 

 Second, the EPA has adopted a combined interpretation of 

sections 111(a)(1) and 111(d) that, compared to the proposal, 

places more weight on the historical interpretations of section 

111(a)(1), which have generally supported emissions standards 

that are nationally uniform for sources incorporating a given 

technology, and less weight on the state-focused character of 

section 111(d), which calls for emissions standards to be 

implemented through the development of individual state plans. 

The proposed state goals were heavily (although not entirely) 

dependent on the emission reduction opportunities available to 

the EGUs in each individual state, and because the relative 

magnitudes of these opportunities varied by state, states with 

similar EGU fleet compositions could have faced state goals of 

different stringencies, potentially making it difficult for 

multiple states to set the same standards of performance for 

affected EGUs using the same technologies (assuming the states 

were interested in setting standards of performance for their 

various affected EGUs in such a manner). Some commenters viewed 

this potential result as inconsistent with section 111(a)(1), 

Deleted: sources 

Deleted: sources incorporating the same 

technology could have faced disparate 

standards of performance (depending to some 

extent on how the states chose to distribute 

the emission reduction requirements among 

their individual sources). 
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inequitable, or both. In this final rule, we are obviating those 

concerns by assessing the emission reduction opportunities at an 

appropriate regional scale and formulating nationally uniform 

emissions standards for the emission guidelines.399 National 

uniformity is consistent with prior section 111 rulemaking. The 

methodological refinements related to regional assessment of 

emission reduction opportunities and the use of uniform 

emissions standards by technology subcategory are further 

discussed below. 

b. Approach to quantification of emission reductions from 

increased RE generation. In the June 2014 proposal, the EPA 

described two possible approaches for quantifying the amount of 

emission reductions achievable from affected EGUs through the 

use of renewable energy generation. The proposed approach used 

information on state RPS aggregated at a regional level along 

with historical RE generation data to project the amount of RE 

generation used in quantifying the emission reductions 

achievable through the BSER. The alternative approach used 

information on the technical and market potential for 

 

399 Of course, a source in one state may face different 

requirements than similar sources in other states, depending on 

whether the state adopts the state measures approach or, if it 

adopts the emission standards approach, whether it imposes a 

mass limit or an emission rate and, if the latter, at what 

level.
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development of renewable resources in each state to project the 

RE-related emission reductions. In the October 30, 2014 Notice 

of Data Availability, we provided notice that some commenters 

had suggested modifying the alternative approach to aggregate 

the state-level information to a regional level. In this final 

rule we are adopting a combination of these approaches that uses 

historical RE generating capacity deployment data aggregated to 

a regional level, supported and confirmed by projections of 

market potential developed through a techno-economic approach. 

 In the June 2014 proposal, RE generation was also 

quantified as generation from total –- that is, existing and new 

–- RE generating capacity, a formulation that was consistent 

with the formulation of most RPS, which are typically framed in 

terms of total rather than incremental generation. Commenters 

observed that this quantification approach was inconsistent with 

the approach taken for other building blocks, and that 

generation from RE generating capacity that already existed as 

of 2012 should not be treated as reducing emissions of affected 

EGUs from 2012 levels. As just noted, we are not using the RPSbased methodology in the final rule, and we agree with comments 

that quantification of RE generation on an incremental basis is 

both more consistent with the treatment of other building blocks 

and more consistent with the general principle that the BSER 

Deleted: the alternative approach from the 

proposal, modified as described in the NODA. 
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should comprise incremental measures that will reduce emissions 

below existing levels, not measures that are already in place, 

even if those in-place measures help current emission levels be 

lower than would be the case without the measures. The final 

rule therefore defines the RE component of the BSER in terms of 

incremental rather than total RE generation.400 Further details 

regarding the final rule’s quantification of RE generation are 

provided in section V.E. below. 

c. Exclusion from the BSER of emission reductions from use of new 

or preserved nuclear capacity. In the June 2014 proposal, the 

EPA included in building block 3 provisions reflecting the 

ability for nuclear generation to replace fossil generation and 

thereby reduce CO2 emissions at affected EGUs. We proposed to 

include in building block 3 the potential generation from five 

under-construction nuclear generating units whose construction 

had commenced prior to the issuance of the proposal. In 

addition, to address the potential that some currently operating 

nuclear facilities may shut down prior to 2030, the proposal 

incorporated into the BSER for each state with nuclear capacity 

 

400 Generation from existing RE capacity will continue to make 

compliance with mass-based standards easier to achieve by making 

the overall amount of fossil fuel-fired generation that is 

required to meet the demand for energy services lower than it 

would otherwise be, thereby keeping CO2 emissions lower than they 

would otherwise be. 

Deleted: sources. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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a projected 5.8 percent reduction in nuclear generation, based 

on an estimate of potential nationwide loss of nuclear 

generation from existing units. We sought comment on all aspects 

of these proposed approaches. While we recognize the important 

role nuclear power plants have to play in providing carbon-free 

generation in an all-of-the-above energy system, for this final 

rule, the BSER does not include either of the components related 

to nuclear generation. 

 The EPA received numerous comments on the proposed BSER 

components related to nuclear power. With respect to generation 

from new nuclear units, some commenters expressed strong 

opposition to the inclusion of this generation in the BSER and 

the setting of state goals, stating that inclusion would result 

in very stringent state goals for the states where the new units 

are being built and that the inclusion of the generation in the 

goals is premature because the units’ actual completion dates 

could be delayed. Commenters also stated that inclusion of the 

new nuclear generation in the BSER would be inequitable because 

states where the same heavy investment in zero-CO2 generation was 

not being made would have relatively less stringent goals. 

 With respect to generation from existing nuclear units, 

some commenters stated that our method of accounting for 

potential unit shutdowns was flawed, observing that even if the 

Deleted: are uncertain. Some commenters 

expressed concern regarding the lack of 

flexibility to find alternative emission 

reduction measures comparable in magnitude to 

the assumed emission reductions from the new 

nuclear generation in the event that 

construction was not completed, potentially 

hampering the ability to achieve the state 

goals. 
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prediction of a 5.8 percent nationwide loss of nuclear 

generation were accurate, the actual shutdowns would occur in a 

handful of states, resulting in much larger losses of generation 

in those particular states. 

 Upon consideration of comments and the accompanying data, 

the EPA has determined that the BSER should not include either 

of the components related to nuclear generation from the 

proposal. With respect to nuclear units under construction, 

although we believe that other refinements to this final rule 

would address commenters’ concerns that goals for the particular 

states where the units are located would be overly stringent 

either in absolute terms or relative to other states, we also 

acknowledge that, in contrast to RE generating technology, 

investments in new nuclear units tend to be very large and 

“lumpy” and have historically been susceptible to delays that 

increase costs. Also, there is no clear trend demonstrating 

increased construction of new nuclear capacity. We view these 

factors as distinguishing the under-construction nuclear units 

from RE generating capacity, indicating that the new nuclear 

capacity is of higher cost and therefore less appropriate for 

inclusion in the BSER. Excluding the under-construction nuclear 

units from the BSER, but allowing emission reductions 

attributable to generation from the units to be used for 
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compliance as discussed below and in section VIII, will 

recognize the CO2 emission reduction benefits achievable through 

the significant ongoing commitment required to complete these 

major investments. 

 With respect to existing nuclear units, although again we 

believe that other refinements in the final rule would address 

the concern about disparate impacts on particular states, we 

acknowledge that we lack information on shutdown risk that would 

enable us to improve the estimated 5.8 percent factor for 

nuclear capacity at risk of retirement. Further, based in part 

on comments received on another aspect of the proposal –- 

specifically, the proposed inclusion of existing RE generation 

in the goal-setting computations –- we believe that it is 

inappropriate to base the BSER in part on the premise that the 

preservation of existing low- or zero-carbon generation, as 

opposed to the production of incremental, low- or zero-carbon 

generation, could reduce CO2 emissions from current levels. 

Accordingly, we have determined not to reflect either of the 

nuclear elements in the final BSER. 

 Generation from new nuclear units and capacity uprates at 

existing nuclear units would still be able to help sources meet 

emission rate-based standards of performance through the 

creation and use of credits, as noted in section V.A.6.b. and 

Deleted: host states would be at risk of being 

unable to achieve their goals if the units 

were not completed, we also acknowledge that 

including generation from the units in the 

BSER would fail to recognize the significant 

ongoing commitment required to complete these 

major investments by instead treating them as 

though there were no chance they would not be 

completed. 

Deleted: discussed 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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section VIII.K.1.a.(8), and would help sources meet mass-based 

standards of performance through reduced utilization of fossil 

generating capacity leading to reduced CO2 emissions at affected 

EGUs. However, consistent with the reasons just discussed for 

not reflecting preservation of existing nuclear capacity in the 

BSER –- namely, that such preservation does not actually reduce 

existing levels of emissions from affected EGUs –- the rule does 

not allow preservation of generation from existing or relicensed 

nuclear capacity to serve as the basis for creation of credits 

that individual affected EGUs could use for compliance, as 

further discussed in section VIII.K.1.a.(8).401

d. Exclusion from the BSER of emission reductions from demandside energy efficiency. The June 2014 proposal included demandside energy efficiency measures in building block 4 as part of 

the BSER. Building block 4 was a topic of considerable 

controversy among commenters. While many commenters emphasized 

the cost-effectiveness of demand-side energy efficiency measures

as a means of reducing CO2 emissions from the utility power 

 

401 As with generation from existing RE capacity, generation from 

existing nuclear capacity will continue to make compliance with 

mass-based standards easier to achieve by making the overall 

amount of fossil fuel-fired generation that is required to meet 

the demand for energy services lower than it would otherwise be, 

thereby keeping CO2 emissions lower than they would otherwise be. 

Commented [A20]: This would be a good opportunity to speak 

to the importance of retaining existing nuclear, and to the [possible?] 

reporting requirement plus other means to encourage keeping 

licensed nuclear units on line., such as the mooted state reporting 

and potential readjustment. 

Deleted: , but the EPA is not finalizing that 

part of the proposal, for the following 

reasons. ¶

Deleted: caused 

Deleted: generated 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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sector and strongly supported the inclusion of such measures in 

the BSER, other commenters expressed significant concerns. 

For the reasons discussed in section V.B.3.b.(1) below, the 

EPA is not finalizing the proposal to include demand-side energy 

efficiency measures as part of the BSER.

 It should be noted that commenters also took the position 

that the EPA should allow demand-side energy efficiency as a 

means of compliance with the requirements of this rule, and, as 

discussed in section V.A.6.b. and section VIII below, we agree. 

e. Consistent regionalized approach to quantification of emission 

reductions from all building blocks. In the June 2014 proposal, 

the EPA treated each of the building blocks differently with 

respect to the regional scale on which the building block was 

applied for purposes of assessing the emission reductions 

achievable through use of that building block. Building block 1 

was quantified at a national scale, identifying a single heat 

rate improvement opportunity applicable on average to all coalfired steam EGUs. Building block 2 was quantified at the scale 

of each individual state, considering the amount of generation 

that could be shifted from steam EGUs to NGCC units within the 

state, although we solicited comment on considering generation 

shifts at a broader regional scale. The RE component of building 

block 3 was quantified at a regional scale using RPS information 

Deleted: As a legal matter, commenters 

emphasized that demand-side energy efficiency 

measures reduce emissions from the generation 

of electricity by reducing overall demand for 

electricity and that this is different from 

generation shifts and renewable energy. 

Commenters also asserted that those 

differences are legally significant for 

purposes of determining whether demand-side 

energy efficiency measures may qualify as part 

of the BSER. Commenters viewed demand-side 

energy efficiency as a restriction on the 

amount of electricity that the affected 

industry could generate, and they viewed that 

type of restriction as beyond the scope of the 

EPA’s authority under CAA section 111.¶

The demand-side energy efficiency measures in 

building block 4 are different in certain 

respects from the generation shifts and 

renewable energy measures in building blocks 2 

and 3. As noted, the generation shifts and 

renewable energy measures are mechanisms 

through which affected EGUs may generate the 

same electricity (which is a highly 

substitutable product) with fewer CO2

emissions, whereas the demand-side energy 

efficiency measures in building block 4 do not 

provide the same amount of generation through 

cleaner processes, but instead bring about 

reductions in demand for electricity, which 

avoids the need for corresponding amounts of 

electricity generation. ¶

Commenters also assert that inclusion of 

building block 4 would amount to an attempt to 

extend EPA regulation beyond emitting sources 

to electricity end-users, and they observe 

that such an extension would exceed the EPA’s 

authority. While we do not agree that 

inclusion of building block 4 in the BSER 

would be equivalent to regulation of 

electricity end-users, the legal uncertainty 

associated with this claim would increase the 

uncertainty for states during a window of time 

when significant progress must be made on 

their section 111(d) plans, potentially 

hindering those planning efforts. ¶

In addition, commenters noted that as a 

practical matter, demand-side energy 

efficiency programs involve the participation 

of more entities, including end-users, which 

creates levels of complexity in implementation 

not found with the other building blocks. 

Commenters also asserted that the record for 

the proposal lacked information demonstrating 

that a number of states could implement 

demand-side energy efficiency programs in the 

amounts and on the time-table that the 

proposal called for, or that certain segments 

of the industry –- independent power 

producers, who comprise some 35-40 percent of 

the industry, but do not have a direct 

business relationship with end-users –- could 

do so. ¶

Upon consideration of the variety of points 

raised above, without necessarily agreeing 

with those points, the EPA has determined not 

to include demand-side energy efficiency in 

the BSER in this final rule. ¶
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 396 of 1544

as a proxy for RE development potential, and the regional 

results were then applied to each state in the region using the 

state’s baseline data; an alternative methodology on which we 

requested comment quantified the RE component using a technoeconomic approach on a state-specific basis. In the October 2014 

NODA, we requested comment on using a techno-economic approach 

to quantify RE generation potential at a regional scale.403

 For the final rule, with the benefit of comments received, 

we have adopted a consistent regionalized approach to 

quantification of emission reductions achievable through all the 

building blocks. A regionalized approach is more consistent with 

the global nature of CO2 as a pollutant than a state-focused 

approach. Further, compared to the proposal’s more state-focused 

quantification approach, a regionalized approach better reflects 

the interconnected system within which interdependent affected 

EGUs actually carry out planning and operations in order to meet 

electricity demand. We have already discussed the relevance of 

the interconnected system and the interdependent operations of 

EGUs as factors supporting consideration of building blocks 2 

and 3 as elements of the BSER for this pollutant and this 

industry, and these same factors support quantifying the 

emission reductions achievable through building blocks 2 and 3 

 

403 79 FR 64543, 64551-62

Deleted: 402

Deleted: Compared 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 397 of 1544

on a regionalized basis. Because it better reflects how the 

industry works, a regionalized approach also better represents 

the full scope of emission reduction opportunities available to 

individual affected EGUs through the normal transactional 

processes of the industry, which do not stop at state borders. 

With respect to building block 1, which comprises types of 

emission reduction measures that in other rulemakings under CAA 

section 111 would typically be evaluated on a nationwide basis, 

for this rule, as discussed in section V.C. below, we are 

quantifying the emission reductions achievable through building 

block 1 on a regional basis as well in order to treat the 

building blocks consistently and to ensure that for each region 

the quantification of the BSER represents only as much potential 

emission reduction from building block 1 as our analysis 

indicates can be achieved on average by the affected EGUs in 

that region. 

 Characterizing and quantifying the measures included in the 

BSER on a regional basis is also appropriate because states can 

establish standards of performance that incorporate emissions 

trading, including trading between and among EGUs operating in 

different states, and thus provide EGUs the opportunity to 

trade. Emissions trading provides at least one mechanism by 

which owners of affected EGUs can access any of the building 

Deleted: Further, use of a broad regionalized 

approach, as opposed to a state-focused 

approach, is more consistent with the global 

nature of CO2 as a pollutant.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 398 of 1544

blocks at other location. With emissions trading, an affected 

EGU whose access to heat rate improvement opportunities, 

incremental generation from existing NGCC units, or generation 

from new renewable energy generating capacity is relatively 

favorable can overcomply with its own standard of performance 

and sell rate-based emission credits or mass-based emission 

allowances to other affected EGUs. Purchase of the credits or 

allowances by the other EGUs represents cross-investment in the 

emission reduction opportunities, and such cross-investment can 

be carried out on as wide a geographic scale as trading rules 

allow. 

 The regions we have determined to be appropriate for the 

regionalized approach in the final rule are the Eastern, 

Western, and Texas Interconnections, as we explain in more 

detail below.404 Each of the building blocks is quantified and 

applied at the regional level, resulting in the computation for 

each region of a performance rate for steam EGUs and a 

performance rate for NGCC units. For each of the technology 

subcategories, we identify the most conservative –- that is, the 

least stringent –- of the three regional performance rates. We 

 

404 The Texas Interconnection encompasses the portion of the 

Texas electricity system commonly known as ERCOT (for the 

Electric Reliability Council of Texas). The state of Texas has 

areas within the Eastern and Western Interconnections as well as 

the Texas Interconnection. 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 399 of 1544

then apply these subcategory-specific performance rates to the 

baseline data for each state in all three regions to establish 

state goals of consistent stringency across the states within 

and across the three regions (although the actual state goals 

vary among states to reflect the differences in generation mix 

among states). Further description of the steps in this overall 

process is contained in the preamble sections addressing the 

individual building blocks (sections V.C., V.D., and V.E.), CO2

emission performance rate computation (section VI), and state 

goal computation (section VII), as well as the GHG Mitigation 

Measures TSD for the CPP Final Rule and the CO2 Emission 

Performance Rate and Goal Computation TSD for the CPP Final Rule 

available in the docket. 

 In determining that the appropriate regional level for 

quantification of the BSER was the level of the interconnection, 

the EPA considered several factors. First, we considered the 

regional scale on which electricity is actually produced, 

physically coordinated, and consumed in real time –- 

specifically the Eastern, Western, and Texas Interconnections. 

The Bulk Power System (BPS) in the contiguous United States 

(including adjacent portions of Canada and Mexico) consists of 

these three interconnections, which are alternating current (AC) 

power grids where power flows freely from generating sources to 

Deleted: a region 

Deleted: and 

Deleted: sections VI and 

Deleted: 

Deleted: , and concluded that the three large 

interconnections

Deleted: –- were more appropriate than 

subregions within these interconnections. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 400 of 1544

consuming loads. These interconnections are separately planned 

and operated; they are connected to each other only through lowcapacity direct current (DC) tie lines. Each interconnection is 

managed to maintain a single frequency and to maintain stable 

voltage levels throughout the interconnection. Physically, each 

interconnection functions as a large pool, where all electricity 

delivered to the electric grid flows by displacement over all 

transmission lines in the interconnection and must be 

continually balanced with load to ensure reliable electricity 

service to customers throughout each interconnection. “Since 

power flows on all transmission paths, it is not uncommon to 

find circumstances in which part of a power delivery within one 

balancing area flows on transmission lines in adjoining areas, 

or part of a power delivery between two balancing areas flows 

over the transmission facilities of a third area.”405 The 

Interconnections are the “complex machines” within which EGUs 

plan, coordinate, and operate, manifesting a degree of both 

long-term and real-time interdependence that is unique to this 

industry. We concluded that, absent a compelling reason to adopt 

a smaller regional scale for evaluation of CO2 emission reduction 

opportunities for the electric power sector –- which we have not 

 

405 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 188 (2d ed. 2010). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 401 of 1544

found, as discussed below –- the Interconnections should be the 

regions used for evaluation of the BSER for CO2 emission 

reductions from the electric power sector because of the 

fundamental characteristics of electricity, the industry’s basic 

interconnected physical infrastructure, and the interdependence 

of the affected EGUs within each interconnection. 

 Second, we considered the whether the interconnection 

subregions for which various planning and operational functions 

are carried out by separate institutional actors would represent 

more appropriate regions than the entire Interconnnections, and 

concluded that they would not. Interconnection planning and 

management follows the NERC functional model, which defines 

subregional areas and regional entities within each 

interconnection for the purposes of balancing generation with 

load and ensuring that reliability is maintained. While a 

variety of organizations plan and operate these subregions,

those activities always occur in the context of the 

interconnections, and the subregions cannot be operated 

autonomously. The need to maintain common frequency and stable 

voltage levels throughout the interconnections requires 

constantly changing flows of electricity between the planning 

and operating subregions within each interconnection. 

Deleted: –- with the borders of the subregions 

occasionally changing as planning and 

management functions evolve or as owners of 

various portions of the grid change 

affiliations –- 

Deleted: , whose boundaries change much less 

often
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 402 of 1544

 Because each interconnection is a freely flowing AC grid, 

any power generated or consumed flows through the entire 

interconnection in real time; as a result of this highly 

interconnected nature of the power system, the management of 

generation and load on the grid must be carefully maintained. 

This management is carried out principally by subregional 

entities responsible for the operation of the grid, but this 

operation must be coordinated in real time to ensure the 

reliability of the system. Regional operators must coordinate 

the dispatch of power, not only in their own areas, but also 

with the other regions within the interconnection. Although this 

coordination has always been important, grid planning and 

management has evolved to be increasingly interconnection-wide, 

through the development of larger regional entities, such as 

RTO/ISOs, or large-utility dispatch across multiple balancing 

areas. As a result, the fact that much of the necessary 

coordination for the interconnections is performed regionally on 

a partially decentralized basis (at least in the case of the 

Eastern and Western Interconnections) or occurs through the 

operation of automated equipment and the physics of the grid 

does not render the subregions more relevant than the 

interconnections as the ultimate regions within which 

electricity supply and demand must balance. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 403 of 1544

 Moreover, some planning and standard setting activities are 

undertaken explicitly at the interconnection level. For example, 

interconnections also have interconnection reliability operating 

limits (IROLs).406 A joint FERC-NERC report on the September 8, 

2011 Arizona-Southern California outages outlined the importance 

of IROLs.407 The report noted that to ensure the reliable 

operation of the bulk power system, entities must identify a 

plan for IROLs to avoid cascading outages. “In order to ensure 

the reliable operation of the BPS, entities are required to 

identify and plan for IROLs, which are SOLs that, if violated, 

can cause instability, uncontrolled separation, and cascading 

outages. Once an IROL is identified, system operators are then 

required to create plans to mitigate the impact of exceeding 

such a limit to maintain system reliability.”408 

 

406 For example, the Eastern Interconnection has Reliability 

Standard IRO-006-EAST-1, Transmission Loading Relief Procedure 

for the Eastern Interconnection, available at 

http://www.nerc.com/files/IRO-006-EAST-1.pdf (providing an 

“Interconnection-wide transmission loading relief procedure 

(TLR) for the Eastern Interconnection that can be used to 

prevent and/or mitigate potential or actual System Operating 

Limit (SOL) and Interconnection Reliability Operating Limit 

(IROL) exceedances to maintain reliability of the Bulk Electric 

System (BES).”). 

407 FERC-NERC, Arizona-Southern California Outages on September 

8, 2011: Causes and Recommendations (Apr. 2012), available at

http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nercreport.pdf. 

408 FERC-NERC, Arizona-Southern California Outages on September 

8, 2011: Causes and Recommendations, at 97 (Apr. 2012), 
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Page 404 of 1544

Congress recognized the significance of the three 

interconnections in the American Recovery and Reinvestment Act 

of 2009 (Recovery Act) when it provided $80 million in funding 

for interconnection-based transmission planning.409 In order to 

fulfill this Congressional mandate, DOE and FERC signed a 

memorandum of understanding to enumerate their roles “for 

activities related to the Resource Assessment and 

Interconnection Planning project funded by the American Recovery 

and Reinvestment Act of 2009 (Recovery Act). Among the 

objectives of the project is to facilitate the development or 

strengthening of capabilities in each of the three 

interconnections serving the contiguous lower forty-eight 

States, to prepare analyses of transmission requirements under a 

broad range of alternative futures and develop long-term 

interconnection-wide transmission plans.”410 DOE issued awards to 

five organizations that performed work in the Western, Eastern, 

 

available at http://www.ferc.gov/legal/staff-reports/04-27-2012-

ferc-nerc-report.pdf. 

409 American Reinvestment and Recovery Act of 2009, Title IV, 

Public Law 111-5 (2009). 

410 Memorandum of Understanding Between the U.S. Department of 

Energy and the Federal Energy Regulatory Commission, available 

at http://www.ferc.gov/legal/mou/mou-doe-ferc.pdf. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 405 of 1544

and Texas Interconnections to develop long-term interconnectionwide transmission expansion plans.411 

In Order No. 1000, FERC also took a broader regional view 

of transmission planning.412 FERC required each public utility 

transmission provider to participate in a regional transmission 

planning process that produces a regional transmission plan. 

FERC also required neighboring transmission planning regions to 

coordinate with each other. This interregional coordination 

includes identifying methods for evaluating interregional 

transmission facilities as well as establishing a common method 

or methods of cost allocation for interregional transmission 

facilities. 

In addition to Congressional, DOE, and FERC recognition of 

the importance of the three interconnections, NERC also 

considers them to be significant. NERC Organizational Standards 

“are based upon certain Reliability Principles that define the 

foundation of reliability for North American bulk electric 

 

411 DOE, Recovery Act Interconnection Transmission Planning, 

available at http://energy.gov/oe/services/electricity-policycoordination-and-implementation/transmission-planning/recoveryact. 

412 Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities, Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-

A, 139 FERC ¶ 61,132, order on reh’g, Order No. 1000-B, 141 FERC 

¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 

762 F.3d 41 (D.C. Cir. 2014). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 406 of 1544

systems.”413 These principles take a broad view of electric 

system reliability, considering the reliability of 

interconnected bulk electric systems. For example, Reliability 

Principle 1 states, “Interconnected bulk electric systems shall 

be planned and operated in a coordinated manner to perform 

reliably under normal and abnormal conditions as defined in the 

NERC standards.”414 NERC took a similarly broad view of system 

reliability when it delegated its authority to monitor and 

enforce mandatory reliability standards to a single Regional 

Entity in both the Western and Texas Interconnections (WECC in 

the West and the Texas Reliability Entity in the ERCOT region of 

Texas).415 Moreover, both WECC and ERCOT have interconnectionwide reliability standards.416 The Eastern Interconnection has 

multiple reliability regions with some differences in standards, 

 

413 NERC, Reliability and Market Interface Principles, at 1, 

available at 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf. 

414 NERC, Reliability and Market Interface Principles, at 1, 

available at 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf. 

415 NERC, Key Players, available at

http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx. 

416 WECC, Standards, available at

https://www.wecc.biz/Standards/Pages/Default.aspx (last visited 

July 3, 2015); Texas Reliability Entity, Reliability Standards, 

available at 

http://www.texasre.org/standards_rules/Pages/Default.aspx (last 

visited July 3, 2015). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 407 of 1544

but power flows and reliability are managed through a single 

Reliability Coordinator Information System that tracks power 

flows for all transmission transactions.417 

 The importance that Congress, DOE, FERC, and NERC each 

place upon the interconnections for electric reliability and 

operational issues is another factor supporting our decision to 

set the interconnections as the regional boundaries for the 

establishment of BSER. The utilization of the three 

interconnections for both planning and reliability purposes is a 

clear indication of the importance that electricity system 

regulators, operators, and industry place upon the 

interconnections. Those responsible for the electricity system 

recognize the need to ensure that there is a free flow of 

electricity throughout each interconnection such that 

transmission planning and reliability analysis are occurring at 

the interconnection level. Further, this vigilance with respect 

to considering reliability from an interconnection-wide basis 

recognizes that each of the interconnections behaves as a single 

 

417 The NERC glossary defines the Reliability Coordinator 

Information System as the “system that Reliability Coordinators 

use to post messages and share operating information in real 

time.” NERC, Glossary of Terms Used in Reliability Standards

(Apr. 20, 2009), available at

http://www.eia.gov/electricity/data/eia411/nerc_glossary_2009.pd

f. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 408 of 1544

machine where “outages, generation, transmission changes, and 

problems in any one area in the synchronous network can affect 

the entire network.”418 By setting the three interconnections as 

the regions for purposes of BSER, we are affirming the way in 

which planning, reliability, and industry experts view the 

electricity system.

An additional factor weighing against the use of planning 

or operational subregions of the Interconnections as the regions 

for our BSER analysis for this rule is that the borders of those 

subregions occasionally change as planning and management 

functions evolve or as owners of various portions of the grid 

change affiliations. This is not a merely theoretical 

consideration; numerous ISO/RTO and other regional boundaries 

have substantially changed in recent years. For example, in 

2012, Duke Energy Ohio and Duke Energy Kentucky integrated into 

PJM.419 The following year, in December 2013, Entergy and its six 

utility operating companies joined MISO, creating the MISO South 

 

418 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). 419 PJM, Duke Energy Ohio, Inc., and Duke Energy Kentucky, Inc., 

Successfully Integrated Into PJM (Jan. 3, 2012), available at 

http://www.pjm.com/~/media/about-pjm/newsroom/2012-

releases/20120103-duke-ohio-and-kentucky-integrate-intopjm.ashx.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 409 of 1544

Region.420 The integration of MISO South correspondingly led to 

changes in NERC’s regional assessment areas.421 FERC also 

recently approved the integration of the Western Areas Power 

Administration – Upper Great Plains, Basin Electric Power 

Cooperative, and Heartland Consumers Power District into SPP.422

Additionally, PacifiCorp and the CAISO recently began operating 

the western Energy Imbalance Market (EIM).423 Other entities such 

as NV Energy, Arizona Public Service Co., and Puget Sound Energy 

are planning to participate in the EIM in the future.424 The EIM 

 

420 Miso, South Region Integration, available at 

https://www.misoenergy.org/WhatWeDo/StrategicInitiatives/Souther

nRegionIntegration/Pages/SouthernRegionIntegration.aspx (noting 

that the creation of the MISO South Region “brought over 18,000 

miles of transmission, ~50,000 megawatts of generation capacity, 

and ~30,000 MW of load into the MISO footprint.”). 

421 NERC previously included Entergy and its six operating areas 

as part of the SERC Assessment Areas. NERC, 2014 Reliability 

Assessment (May 2014). “MISO now coordinates all RTO activities 

in the newly combined footprint, consisting of all or parts of 

15 states with the integration of Entergy and other MISO South 

entities. This transition has led to substantial changes to 

MISO’s market dispatch, creating the potential for unanticipated 

flows across the following systems: Tennessee Valley Authority 

(TVA), Associated Electric Cooperative Inc. (AECI), and Southern 

Balancing Authority.” Id. at 7. 422 SPP, FERC approves Integrates System joining SPP (Nov. 12, 

2014), available at 

http://www.spp.org/publications/FERC%20approves%20IS%20membershi

p.pdf.

423NREL, Energy Imbalance Market, available at

http://www.nrel.gov/electricity/transmission/energy_imbalance.ht

ml. 

424 CAISO, EIM Company Profiles (May 2015), available at

http://www.caiso.com/Documents/EIMCompanyProfiles.pdf. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 410 of 1544

“creates significant reliability and renewable integration 

benefits for consumers by sharing and economically dispatching a 

broad array of resources.”425 This history of changing regional 

boundaries leads us to the conclusion that selecting smaller 

regional boundaries for purposes of setting the BSER would 

merely represent a snapshot of current, changeable regional 

boundaries. As we have seen with recent, large-scale changes 

regarding ISO/RTO boundaries and NERC reliability assessment 

areas, such regions would likely not stand the test of the time, 

nor would smaller regional boundaries accurately reflect 

electricity flows on the grid. The EPA believes that the 

interconnections are the most stable and reasonable regional 

boundaries for setting BSER. 

 Third, we considered whether transmission constraints, and 

the fact that the specific locations of generation resources and 

loads within each interconnection clearly matter to grid 

planning and operations, necessitate evaluation of the emission 

reductions available from the building blocks at scales smaller 

than the interconnections. We concluded that no reduction in 

scale was needed due to such constraints. The same industry 

trends that are reflected in the BSER -- the changing 

 

425 CAISO, Energy Imbalance Market, available at

http://www.caiso.com/informed/pages/stakeholderprocesses/energyi

mbalancemarket.aspx. 

Deleted: Second
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 411 of 1544

efficiencies and mix of existing fossil EGUs and the development 

of renewable energy throughout each interconnection -- as well 

as the management of the interconnected grid as loads are 

reduced through energy efficiency, which is not reflected in the 

final BSER, are already driving power system development and are 

being managed through interconnection-wide planning, 

coordination and operations, and will continue to be managed in 

that manner in the future with or without this rule. While 

electricity supply and demand must be balanced in real time in a 

manner that observes all security constraints at that point in 

time, and key aspects of that management are carried out at a 

subregional scale, the emissions standards established in this 

rule can be met over longer timeframes through processes managed 

at larger geographic scales, just as they are today. We believe 

this rule will reinforce these developments and help provide a 

secure basis for moving forward. If a local transmission 

constraint requires that for reliability reasons a higheremitting resource must operate during a certain period of time 

in preference to a lower-emitting resource that would otherwise 

be the more economic choice when all costs are considered, 

nothing in this rule prevents the higher-emitting source from 

being operated. If the same transmission constraint causes the 

same conditions to occur frequently, the extra cost associated 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 412 of 1544

with finding alternative ways to reduce emissions will provide 

an economic incentive for concerned parties to explore ways to 

relieve the transmission constraint. If relieving the constraint 

would be more costly than employing alternative measures to 

reduce emissions, the rule allows parties to pursue those 

alternative emission reduction measures. Accommodation of 

intermittent constraints and evaluation of alternatives for 

relieving or working around them have been routine operating and 

planning practices within the utility power sector for many 

years; the rule will not change these basic economic practices 

that occur today. The 2022-29 schedule for the rule’s interim 

goals and the 2030 schedule for the rule’s final goals allow 

time for planning and investment comparable to the sector’s 

typical planning horizons. 

 Finally, the EPA also considered whether the smaller 

geographic scales on which affected EGUs may typically engage in 

energy and capacity transactions necessitate evaluating the 

emission reductions available from the building blocks at scales 

smaller than the interconnections, and again concluded that a 

smaller scale was not necessary or justified. We first note that 

electricity trading occurs today throughout the interconnection 

through RTO/ISO markets and active spot markets, often over 

large areas such as RTO/ISOs, or managed over large dispatch 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 413 of 1544

areas outside RTOs. These trades result in interconnection-wide 

changes in flow that are managed in real time. Moreover, the 

exchange of power is not limited to these areas. For example, 

RTOs regularly manage flows between RTOs, and EGUs near the 

boundaries of RTOs impact multiple subregions across the 

interconnections, so that any subregional boundaries that might 

be evaluated for potential relevance as trading region 

boundaries will change as conditions and EGU choices change, 

while interconnection boundaries will remain stable. 

 In addition, the final rule permits trading of rate-based 

emission credits or mass-based emission allowances. Emission 

allowances and other commodities associated with electricity 

generation activities, such as renewable energy certificates, 

which, again, represent investments in pollution control 

measures, are already traded separately from the underlying 

electric energy and capacity. There is no reason that whatever 

geographic limits may exist for electricity and capacity 

transactions by an affected EGU should also limit the EGU’s 

transactions for validly issued rate-based emission credits or 

mass-based emission allowances. In fact, as discussed below, the 

final rule not only allows national trading without regard to 

the interconnection boundaries, but also includes a number of 

options that readily facilitate states’ and utilities’ very 

Deleted: source 

Deleted: source’s 

Deleted: rate 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 414 of 1544

extensive reliance on emissions trading. It is appropriate for 

the rule to take this approach, in part, because the non-local 

nature of the impacts of CO2 pollution do not necessitate 

geographic constraints, and in the absence of a policy reason to 

constrain the geographic scope of trading, the largest possible 

scope is the most efficient scope. 

f. Uniform CO2 emission performance rates by technology 

subcategory. In conjunction with the refinements to the 

interpretations of section 111 reflected in the final rule, the 

EPA has refined the methodology for applying the BSER to the 

affected EGUs so as to incorporate performance rates that are 

uniform across technology subcategories. 

 Specifically, the final rule reflects a performance rate of 

1305 lbs. per net MWh for all affected steam EGUs nationwide and 

a performance rate of 771 lbs. per net MWh for all affected 

stationary combustion turbines nationwide. The computations of 

these performance rates and the determinations of state goals 

reflecting the performance rates are described in sections VI 

and VII of the preamble, respectively. This modification is 

consistent with a number of comments we received on the proposal 

and is a logical outgrowth of the proposal informed by the 

comments. The commenters took the position that the proposed 

state goals varied too much among states and unavoidably 

Deleted: type

Deleted: sources 

Deleted: types.

Deleted: 0

Deleted: refinement 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 415 of 1544

implied, or would inevitably result in, states establishing 

inconsistent standards of performance for sources of the same 

technology type in their respective states, which in the 

commenters’ view was not appropriate under section 111.

 Evaluating the emission reduction opportunities achievable 

through application of the BSER on a broad regionalized basis, 

which is appropriate for the reasons discussed above, makes it 

possible to express the degree of emission limitation reflecting 

the BSER as CO2 emission performance rates that are uniform for 

all affected EGUs in a technology subcategory within each 

region. Recognizing the comments favoring the use of nationally 

uniform performance rates by technology subcategory, the EPA 

further considered whether any of the regional emission 

performance rates could represent the emission limitation 

achievable through application of the BSER for its respective 

technology subcategory nationwide. The Eastern, Western, and 

Texas Interconnections each encompass large and diverse 

populations of EGUs with many and diverse opportunities to 

reduce CO2 emissions through application of the measures in each 

of the three building blocks. Based on these considerations of 

scale and diversity, we conclude that each of the 

Interconnections is sufficiently representative of the source 

subcategories and emission reduction opportunities encompassed 

Deleted: In section VI, below, we describe how 

we use data assembled for the building blocks 

through the consistent regional approach 

described above to determine for each region a 

set of uniform performance rates representing 

emission limits achievable through the 

application of the BSER to the subcategory of 

steam EGUs and the subcategory of NGCC units. 

Deleted: source 

Deleted: Except for Alaska, Hawaii, Puerto 

Rico, and Guam, which are geographically 

isolated from the three major interconnections 

as well as from one another, 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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in the BSER to potentially serve as the basis for CO2 emission 

performance rates applicable to the respective source 

subcategories on a nationwide basis. 

 Having determined that the performance rates determined on 

a regional basis merit consideration as nationally applicable 

performance rates, we are also determining that it would be more 

appropriate to use the least stringent of the regional 

performance rates for the three interconnections for each 

technology subcategory as the basis for nationally uniform 

performance rates for that technology subcategory than to use 

the most stringent or the region-specific performance rates. 

Under this approach, the CO2 emission performance rate reflecting 

the BSER for all steam EGUs is uniform across the contiguous 

U.S., regardless of the state or Interconnection where the steam 

EGUs are located. While it is true that steam EGUs in the 

Western and Texas Interconnections have opportunities to 

implement the measures in the building blocks to a greater 

extent than the steam EGUs in the Eastern Interconnection –- for 

example, under building block 2, they have greater amounts of 

incremental NGCC generation available to replace their 

generation in all years for which performance rates were 

computed -- we do not conclude that this means that the EGUs in 

the Western and Texas Interconnections should be assigned a more 

Deleted: the CO2 emission performance rates 

developed using data for the Eastern, Western 

and ERCOT Interconnections represented 

sufficiently broad combinations of affected 

EGUs sources and emission reduction 

opportunities to apply nationally.

Deleted: We also determined

Deleted: type 

Deleted: type 

Deleted: continental 

Deleted: capacity 

Deleted: believe that 

Deleted: they 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 417 of 1544

stringent CO2 emission performance rate. Through the use of a 

common CO2 emission performance rate across all of the steam EGUs 

in all three regions, the burdens of the BSER are allocated 

equally across the steam EGU source subcategory. The same is 

true for the combustion turbine source subcategory, even though, 

in any year for which emission performance rates are computed, 

the combustion turbines in two of the Interconnections have 

greater amounts of renewable energy available to replace their 

generation than combustion turbines in the third 

Interconnection.426 

In addition, using the least stringent rate provides

greater “headroom” –- that is, emission reduction opportunities 

beyond those reflected in the performance rates –- to affected 

EGUs in the Interconnections that do not set the nationwide

level. This greater “headroom” provides greater compliance 

flexibility and assurance that the standards set by the states 

 

426 As discussed in section VI and the CO2 Emission Performance 

Rate and State Goal Computation TSD, the emission performance 

rates for each technology subcategory are computed by region for 

each year from 2022 through 2030, and the region with the least 

stringent emission rate for a particular subcategory, whose rate 

therefore is used for all three regions, can differ across 

years. In the case of the steam EGU subcategory, the nationwide 

rate for all years is the rate computed for the Eastern 

Interconnection. In the case of the NGCC subcategory, the 

nationwide rate is the rate computed for the Texas 

Interconnection for the years from 2022 through 2026 and the 

rate computed for the Eastern Interconnection for the years from 

2027 through 2030.

Deleted: BSER. In this manner

Deleted: the Western and Texas Interconnection 

Deleted: This is generally consistent with the 

approach taken in other NSPS rulemakings, 

where once the appropriate technology has been 

identified, stringencies are generally set 

based on what is reasonably achievable using 

that technology. 

Deleted: U

Deleted: would 

Deleted: sources 

Deleted: Western and Texas 

Deleted: because they 

Deleted: regions 

Deleted: ting

Deleted: al

Deleted: , and therefore 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 418 of 1544

based on the emission guidelines will be achievable at 

reasonable cost and without adverse impacts on reliability. This 

is because affected EGUs in the Interconnections that do not set 

the nationwide level have more opportunities to directly invest 

in each of the building blocks in their respective regions, and 

affected EGUs in the Interconnection that does set the 

nationwide level may in effect invest in the opportunities in 

the other Interconnections through trading. At the same time, 

our approach still represents the degree of emission limitation 

achievable through use of an appropriately large and diverse set 

of emission reduction opportunities and can therefore reasonably 

be considered the “best” system of emission reduction for each 

technology subcategory. 

 Our approach in this rulemaking thus not only addresses the 

comments we received regarding potentially disparate impacts of 

the approach presented in the proposal, it is also generally 

consistent with the approach we have taken in other NSPS 

rulemakings, where standards of performance or emission 

guidelines have typically been established at uniform 

stringencies for all units in a given source subcategory, and 

where once the appropriate control technology has been 

identified, stringencies are generally set based on what is 

reasonably achievable using that technology. 

Deleted: would 

Deleted: to all affected EGUs sources in the 

subcategories

Deleted: sources 

Deleted: Western and Texas 

Deleted: sources 

Deleted: Eastern 

Deleted: do so 

Deleted: , while 

Deleted: ing

Deleted: to 

Deleted: type.

Deleted: is
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 419 of 1544

 We continue to believe that, as in the proposal, providing 

each state with a state-specific weighted average rate-based 

goal allows the state to determine how the emission reduction 

requirements should be allocated among the state’s affected EGUs 

and is an important source of flexibility for states in 

developing their section 111(d) plans. Accordingly, in this 

final rule we are providing equivalent state-specific weighted 

average goals in addition to providing the uniform CO2 emission 

performance rates for each source subcategory. For additional 

flexibility, we are also providing equivalent state-specific 

mass-based goals. Our determinations of the emission performance 

rates are described in section VI below, and our determinations 

of the equivalent rate-based and mass-based goals are described 

in section VII below. 

 We note here that the weighted-average state goals reflect 

the application of the uniform CO2 emission performance rates for 

affected steam EGUs and affected NGCC units to the respective 

units in each subcategory in each state. Each state goal 

therefore reflects uniform stringency of emission reduction 

requirements with respect to affected units in each source 

subcategory, but also reflects the EGU fleet composition and 

historical generation specific to that particular state. 

Compared to the proposal, the approach of quantifying the BSER 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 420 of 1544

through regionalized analysis and use of uniform emission 

performance rates by source subcategory results in more 

stringent goals for states whose generation has historically 

been most heavily concentrated at coal-fired steam EGUs. This 

shift is an expected consequence of the use of uniform 

performance rates by source subcategory. At proposal, these 

states’ goals reflected assumptions in the goal quantification 

methodology that to a considerable extent limited their emission 

reduction opportunities based on their states’ borders, and the 

proposed goals therefore were less stringent in states which had 

substantial coal generation and little local NGCC capacity. The 

final rule more realistically recognizes that emission reduction 

opportunities, like other aspects of the interconnected 

electricity system, are regional and are not constrained by 

state borders. We consequently apply the same emission 

performance rates to coal-fired units in states with heavy 

reliance on coal-fueled generation as we do to coal-fired units 

in other states, which produces more stringent state goals than 

at proposal for the states with the highest concentrations of 

coal-fired generation. At the same time, the final goals for 

some states are less stringent than their proposed goals –- for 

example, because a goal based on the least stringent regional 

rates is less stringent than a goal based on state-specific 
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Page 421 of 1544

emission reduction opportunities would be -- so that the 

differences among the final state goals are generally smaller 

than the differences among the proposed state goals. All of the 

final rate-based state goals are necessarily in the range 

bounded by the CO2 emission performance rate for NGCC units and 

the CO2 emission performance rate for steam EGUs because all of 

the state goals are computed as a weighted average of those two 

performance rates, and this range is narrower than the range of 

state goals in the proposal. 

 The computations of the regionally uniform performance 

rates applicable to affected EGUs in the states and areas of 

Indian country428 located in each of the three Interconnections 

are shown in the CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule. We have not applied the 

uniform performance rates to states and territories that are 

isolated from the three major interconnections –- that is, 

Alaska, Hawaii, Puerto Rico, and Guam429 –- nor are we finalizing 

 

428 As explained in section III.A. above, an Indian tribe whose 

area of Indian country has affected EGUs will have the 

opportunity but not the obligation to seek authority to develop 

and implement a section 111(d) plan. If no tribal plan is 

approved, the EPA has the responsibility to establish a plan if 

it determines that such a plan is necessary or appropriate. 

429 The section 111(d) requirements do not currently apply to the 

other isolated U.S. territories –- the U.S. Virgin Islands, 

American Samoa, and the Northern Mariana Islands –- because no 

affected EGUs currently operate in these territories. 

Deleted: We have determined that the 

nationwide performance rates should not 

necessarily apply to states and territories 

that are isolated from the three major 

interconnections –- that is, Alaska, Hawaii, 

Puerto Rico, and Guam427 –- because affected 

EGUs in those areas lack the same 

opportunities to access the building blocks 

across wide regions that affected EGUs in the 

contiguous states enjoy. Instead, if the 

performance rates computed using data specific 

to one of these isolated states or territories 

is less stringent than the nationwide 

performance rates, we have determined that the 

less stringent state- or territory-specific 

rates should apply. ¶

Deleted: for 

Deleted: major i

Deleted: as well as Alaska, Hawaii, Guam, and 

Puerto Rico 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 422 of 1544

state goals for these jurisdictions based on those performance 

rates. These jurisdictions are distinct from the contiguous 

portions of the U.S. with respect to the isolated nature of 

their electricity systems, and their EGUs lack the same 

opportunities as EGUs in the contiguous areas to access emission 

reduction opportunities from physically interconnected 

generators across wide regions. Important aspects of the basis 

that the EPA has used to define the BSER therefore do not apply 

in these isolated areas. In addition, at present we lack the 

data to quantify the emissions reductions available from 

building block 3 in these isolated areas using the same 

methodology used for the contiguous portions of the U.S. Further 

discussion regarding the isolated jurisdictions can be found in 

section VII.F. of the preamble.

g. Establishment of a 2022-2029 interim compliance period. The 

June 2014 proposal separately quantified emission limitations 

applicable to an interim 2020-29 period and to the period 

beginning in 2030. Although the proposal provided flexibility in 

the timing with which emission reductions could be made over the 

course of the 2020-2029 period in order to achieve compliance 

with the emission limitations applicable to that interim period, 

many commenters perceived the start of the period as too soon 

and stated that it provided insufficient time for planning and 

Deleted: 
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Page 423 of 1544

investments necessary for sources to begin implementation 

activities while maintaining reliable electricity supplies. 

 The EPA has considered these comments and in the final rule 

has established an interim compliance period of 2022-2029, 

providing two additional years for planning and investment 

before the start of compliance. We are persuaded by comments and 

by our own further analysis that this timeframe is appropriate 

and will, in combination with the glide path of emission 

reductions reflected in the final building blocks and the 

states’ flexibility to define their own paths of emission 

reductions over the interim period (provided that their affected 

EGUs still meet the interim performance rates or interim goal 

over the period as a whole), provide adequate time for necessary 

planning and investment activities, thereby enabling the final 

rule’s requirements to be implemented in an orderly manner while 

reliability of electricity supplies is maintained. Further 

discussion is provided in the sections of the preamble 

addressing the individual building blocks (sections V.C., V.D., 

and V.E.) and on electricity system reliability (section 

VIII.G.2.). 

The initial compliance date of 2022, coupled with the fact 

that the 2030 standard is phased in over the subsequent eight 

years, affords affected EGUs the benefit of having an extended 

Deleted: complying 

Deleted: compliance 

Deleted: given the nature and magnitude of 

Deleted: that will be necessary to begin 

compliance with 

Deleted: maintaining 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 424 of 1544

planning period before they need to incur any significant 

obligations. We expect that many states will not adopt and 

submit to the EPA their final state plans until September 2018, 

and in these states affected EGUs will be able to work with the 

states during that three-year process to develop compliance 

approaches. States will also have the flexibility to select 

their own emissions trajectories in such a way that certain 

emission reduction measures could be implemented later in the 

interim period (again, provided that their affected EGUs still 

meet the interim performance rates or interim goal over the 

interim period as a whole). As a result, the affected EGUs in 

those states will not need to incur significant expenses before 

the adoption of the final state plans. It is possible that some 

states may adopt and submit to the EPA state plans by September 

6, 2016, but those states are likely to be limited to ones that 

already have established programs for limiting CO2 emissions from 

power plants, such as California or the northeast states in 

RGGI. In those states, sources will already have developed 

compliance approaches to meet state law requirements. It is also 

possible that some states will not submit initial plan 

submittals by September 6, 2016, and that the EPA will 

promulgate federal plans. Sources in those states will have 

approximately six years to meet their 2022 compliance 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 425 of 1544

obligations, a lengthy period that will afford them the 

opportunity to plan before incurring significant expenditures. 

 These periods of time are consistent with current industry 

practice in changing generation or adding new generation. For 

example, in June 2015, Alabama Power Company announced plans to 

acquire 500 MW of renewable energy generation over the next six 

years. This amount would make up between four and five percent 

of Alabama Power’s generation mix.430 In addition, the study of 

utility IRPs placed in the docket for this rulemaking shows that 

sources are able to replace coal-fired generation with naturalgas fired generation and add incremental amounts of renewable 

energy (as well as take other actions, such as implement demandside energy efficiency programs), on a gradual basis, after a 

several-year lead time, over an extended period.

 

430 Alabama Power Co., “Petition for a Certificate of Convenience 

and Necessity,” submitted to the Alabama Public Service 

Commission (June 25, 2015) (petition requests “a certificate of 

convenience and necessity for the construction or acquisition of 

renewable energy and environmentally specialized generating 

resources and the acquisition of rights and the assumption of 

payment obligations under power purchase arrangements pertaining 

to renewable energy and environmentally specialized generating 

resources, together with all transmission facilities, fuel 

supply and transportation arrangements, appliances, 

appurtenances, equipment, acquisitions and commitments necessary 

for or incident thereto”) (included in the docket for this 

rulemaking). See Swartz, Kristi, “Alabama Power plan would 

dramatically boost its renewables portfolio,” E&E Publishing, 

July 16, 2015. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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h. Refinements to stringency for individual building blocks. For 

each individual building block, the EPA has reexamined the data 

and assumptions used at proposal in light of comments received 

and has made a number of refinements in the final rule based on 

that information. The refinements are discussed in the preamble 

sections for each building block (sections V.C., V.D., and V.E.) 

and emission performance rate computation (section VI) and in 

the GHG Mitigation Measures TSD for the CPP Final Rule and the 

CO2 Emission Performance Rate and Goal Computation TSD for the 

CPP Final Rule. As previously noted, viewed in terms of 

projected nationwide emission reductions (but not necessarily 

with respect to each individual state), these refinements 

generally tend to make the interim goals somewhat less stringent 

than at proposal and the 2030 goals somewhat more stringent than 

at proposal. In addition to the changes described above, the 

refinements include the following: 

 Use of regional rates ranging from 2.1 percent to 4.3 

percent (rather than 6 percent) as the average heat rate 

improvement opportunity achievable by steam units under 

building block 1. 

 Use of 75 percent of summer capacity (rather than 70 

percent of nameplate capacity) as the target capacity 

factor for existing NGCC units under building block 2. 

Deleted: ,

Deleted: in light of 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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 Use of updated information from the National Renewable 

Energy Laboratory (NREL) on renewable energy costs and 

potential, and revision of the list of quantified RE 

technologies to exclude landfill gas under building block 

3. 

4. Determination of the BSER 

 In this rule, the EPA is finalizing as the BSER a 

combination of building blocks 1, 2, and 3, with refinements as 

discussed below. The building blocks constitute the BSER from 

the perspective of the source category as a whole. Each building 

block can be implemented through standards of performance set by 

the states and includes a set of actions that individual sources 

can use to achieve the emission limitations reflecting the BSER. 

These actions and mechanisms, which include reduced generation 

and emissions trading approaches where the state-set standards 

of performance incorporate trading and which may be understood 

as part of the BSER, will be discussed below in section V.A.5. 

Each of the building blocks consists of measures that the source 

category and individual affected EGUs have already demonstrated 

the ability to implement. In quantifying the application of each 

building block, the EPA has identified reasonable levels of 

stringency rather than the maximum possible levels.

Deleted: source-category 

Deleted: or other multi-unit compliance 

Deleted: or the state plans permit multi-unit 

approaches, represent the BSER from the 

individual-source perspective and 
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 As discussed above, one of the modifications being made in 

this rule is the establishment of uniform performance rates by 

technology type. The emission reductions achievable through use 

of the building blocks are being evaluated on a regional basis 

that reflects the regional nature of the interconnected 

electricity system and the region-wide scope of opportunities 

available for affected EGUs in each region to access emission 

reduction measures. However, the EPA recognizes that the 

emission reduction opportunities under these building blocks 

vary by region because of regional differences in the existing 

mix of types of fossil fuel-fired EGUs and the available 

opportunities to increase low- and zero-carbon generation. In 

order to achieve uniform performance rates by technology type, 

and to do so in a way that respects regional differences in 

emission reduction opportunities, we have determined that it is 

reasonable not to establish the stringency of the BSER 

separately by region based on the maximum emission reduction 

that would be achievable in that region, but instead to 

establish uniform stringency across all regions at a level that 

is achievable at reasonable cost in any region. Thus, for each 

technology subcategory, the BSER is the combination of the 

elements described above at the combined stringency that is 

reasonably achievable in the region where the CO2 emission 

Deleted: refinements 

Deleted: sources 

Deleted: type

Deleted: the Eastern Interconnection (or in 

some individual years of the interim goal 

period for NGCC units, the Texas 

Interconnection), which is 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 429 of 1544

performance rates determined to be achievable at reasonable cost 

by the EGUs in that subcategory were least stringent.431

 This approach is consistent with the approach we have taken 

in other NSPS rulemakings, where the degree of emission 

limitation achievable through the application of the BSER for 

each subcategory of affected sources generally has been 

determined not on the basis of what is achievable by the sources 

that can reduce emissions most easily, but instead on the basis 

of what is reasonably achievable through the application of the 

BSER. This approach also provides compliance headroom –- in 

addition to the headroom provided by our approach to setting the 

stringency for each individual building block -- for affected 

EGUs in regions where the emission reductions that could be 

achieved at reasonable cost exceed the reductions that are 

achievable at reasonable cost in the limiting region, thereby 

promoting compliance flexibility. Further, because we are 

authorizing states to establish standards of performance that 

 

431 The determinations of stringency for each source subcategory 

were made independently for each year from 2022 through 2030, 

and in the case of the NGCC category, the limiting region 

changed over time. Thus, for the NGCC category, the uniform CO2

emission performance rate is based on the stringency achievable 

in the Texas Interconnection for the years from 2022 through 

2026 and the stringency achievable in the Eastern 

Interconnection for the years from 2027 through 2030. For the 

steam EGU subcategory, the uniform CO2 emission performance rate 

is based on the stringency achievable in the Eastern 

Interconnection in all years. 

Deleted: for both steam EGUs and combustion 

turbines

Deleted: (For the isolated states and 

territories of Alaska, Hawaii, Puerto Rico, 

and Guam, if the performance rates determined 

to be achievable at reasonable costs based on 

the application of the BSER to that state or 

territory are less stringent than the 

nationwide rates, the state- or territoryspecific performance rates are used instead.) 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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incorporate trading without geographic restrictions, the 

opportunity of affected EGUs to engage in emissions trading, to 

the extent allowed under the relevant section 111(d) plans, 

ensures the availability of additional, lower-cost emission 

reduction opportunities in other regions that will also promote 

compliance flexibility and reduces compliance costs. 

 As discussed in section XI of the preamble and the 

Regulatory Impact Analysis, application of the BSER determined 

as summarized above is projected to result in substantial and 

meaningful reductions of CO2 emissions. 

 Briefly, the elements of the BSER are: 

Building block 1: Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat rate 

improvements in specified percentages. 

Building block 2: Substituting increased generation from 

existing affected NGCC units for reduced generation from 

affected steam EGUs in specified quantities. 

Building block 3: Substituting generation from new zero-emitting 

RE generating capacity for reduced generation from affected EGUs 

in specified quantities. 

a. Building block 1. Building block 1 -- reducing the carbon 

intensity of generation at individual affected coal-fired steam 

EGUs through heat rate improvements -- is a component of the 

Deleted: or other multi-unit compliance 

approaches

Deleted: 

Deleted: 

Deleted: 

Deleted: low- or zero-carbon 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 431 of 1544

BSER with respect to coal-fired steam EGUs432 because the 

measures the affected EGUs may undertake to achieve heat rate 

improvements are technically feasible and of reasonable cost, 

and perform well with respect to other factors relevant to a 

determination of the “best system of emission reduction ... 

adequately demonstrated.” Building block 1 is a “system of 

emission reduction” for steam EGUs because owners of these EGUs 

can take actions that will improve their heat rates and thereby 

reduce their rates of CO2 emissions with respect to generation. 

 The EPA has analyzed the technical feasibility, costs, and 

magnitude of CO2 emission reductions achievable through heat rate 

improvements at coal-fired steam EGUs based on engineering 

studies and on these EGUs’ reported operating and emissions 

data. We conclude that taking action to improve heat rates is a 

common and well-established practice within the industry that is 

capable of achieving meaningful reductions in CO2 emissions at 

reasonable cost, although, as discussed earlier, we also 

conclude that the quantity of emission reductions achievable 

through heat rate improvement measures is insufficient for these 

 

432 For the reasons discussed in the proposal, the EPA is not 

determining that heat rate improvements at other types of 

affected EGUs, such as NGCC units and oil-fired and natural gasfired steam EGUs, are components of the BSER. However, all types 

of affected EGUs would be able to employ heat rate improvements 

as measures to help achieve compliance with their assigned 

standards of performance. 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 432 of 1544

measures alone to constitute the BSER. Specifically, we have 

determined that an average heat rate improvement ranging from 

2.1 to 4.3 percent by all affected coal-fired EGUs, depending on 

the region, is an element of the BSER, based on the inclusion of 

those amounts of improvement in the three regions, determined 

through our regional analysis. Our analysis and conclusions are 

discussed in Section V.C. below and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. 

 Consideration of other BSER factors also favors a 

conclusion that building block 1 is a component of the BSER. For 

example, with respect to non-air health and environmental 

impacts, heat rate improvements cause fuel to be used more 

efficiently, reducing the volumes of, and therefore the adverse 

impacts associated with, disposal of coal combustion solid waste 

products. By definition, heat rate improvements do not cause 

increases in net energy usage. Although we are justifying 

building block 1 as part of the BSER without reference to 

technological innovation, we also consider technological 

innovation in the alternative, and we note that building block 1 

encourages the spread of more advanced technology to EGUs 

currently using components with older designs. 

 As noted in the June 2014 proposal, the EPA is concerned 

about the potential “rebound effect” associated with building 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 433 of 1544

block 1 if applied in isolation. More specifically, we noted 

that in the context of the integrated electricity system, absent 

other incentives to reduce generation and CO2 emissions from 

coal-fired EGUs, heat rate improvements and consequent variable 

cost reductions at those EGUs would cause them to become more 

competitive compared to other EGUs and increase their 

generation, leading to smaller overall reductions in CO2

emissions (depending on the CO2 emission rates of the displaced 

generating capacity). Unless mitigated, the occurrence of a 

rebound effect would reduce the emission reductions achieved by 

building block 1, exacerbating the inadequacy of emission 

reductions that is the basis for our conclusion that building 

block 1 alone would not represent the BSER for this industry. 

However, we believe that our concern about the potential rebound 

effect can be readily addressed by ensuring that the BSER also 

reflects other CO2 reduction strategies that encourage increases 

in generation from lower- or zero-carbon EGUs, thereby allowing 

building block 1 to be considered an appropriate part of the 

BSER for CO2 emissions at affected EGUs as long as the building 

block is applied in combination with other building blocks. 

b. Building block 2. Building block 2 –- reducing CO2 emissions 

at, and substituting for generation from, the most carbonintensive affected EGUs with generation from less carbonDeleted: this 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 434 of 1544

intensive affected EGUs (specifically NGCC units that are 

currently operating or under construction) –- is a component of 

the BSER for steam EGUs because generation shifts that will 

reduce the amount of CO2 emissions at higher-emitting EGUs and 

from the source category as a whole are technically feasible, 

are of reasonable cost, and perform well with respect to other 

factors relevant to a determination of the “best system of 

emission reduction ... adequately demonstrated.” Building block 

2 is a “system of emission reduction” for steam EGUs because 

incremental generation from existing NGCC units will result in 

reduced generation and emissions from steam EGUs, and owners of 

steam EGUs can, and many do, invest in incremental generation 

from NGCC units through a variety of possible mechanisms. A 

steam EGU investing in incremental generation from NGCC units 

may choose to reduce its own generation or may maintain its 

generation level and choose to allow the reduction in generation 

to occur at other steam EGUs through the coordinated planning 

and operation of the interconnected electricity system. An 

affected EGU may also invest in emission reductions from 

building block 2 through the mechanism of engaging in emissions 

trading where the EGU is operating under a standard of 

performance that incorporates trading. 

Deleted: it 
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Page 435 of 1544

 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable at high-emitting EGUs through generation shifts to 

lower-emitting affected EGUs are discussed in Section V.D. 

below. We consider generation shifts among the large number of 

diverse EGUs that are linked to one another and to customers by 

extensive regional transmission grids to be a routine and wellestablished operating practice within the industry that is used 

to facilitate the achievement of a wide variety of objectives, 

including environmental objectives, while meeting the demand for 

electricity services. In the interconnected and integrated 

electricity industry, fossil fuel-fired steam EGUs are able to 

reduce their generation and NGCC units are able to increase 

their generation in a coordinated manner through mechanisms –- 

in some cases centralized and in others not -- that regularly 

deal with such changes on both a short-term and a longer-term 

basis. Our analysis demonstrates that the emission reductions 

that can be achieved or supported by such generation shifts are 

substantial and of reasonable cost. Further, both the 

achievability of this building block and the reasonableness of 

its costs are supported by the fact that there has been a longterm trend in the industry away from coal-fired generation and 

toward NGCC generation for a variety of reasons. 
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 Building block 2 is adequately demonstrated as a “system of 

emission reduction” for affected steam EGUs. As discussed in 

section V.B., Congress has long recognized that generation 

shifts among EGUs are one means of reducing emissions from the 

utility power sector and multiple provisions of the CAA reflect 

that recognition, and generation shifts similarly have been 

recognized as means of reducing emissions under trading programs 

established by the EPA to implement the Act’s provisions. It is 

common practice in the industry to account for the cost of 

emission allowances as a variable cost when making securityconstrained, cost-based dispatch decisions; doing so integrates 

generation shifts into the operating practices used to achieve 

compliance with environmental requirements in an economical 

manner. These industry trends are further discussed in section 

V.D. Thus, legislative history, regulatory precedent, and 

industry practice support interpreting the broad term “system of 

emission reduction” as including generation shifts among 

affected EGUs. 

 An important additional consideration supporting the 

determination that building block 2 is adequately demonstrated 

as a “system of emission reduction” is that owners of affected 

steam EGUs have the ability to invest in generation shifts as a 

way of reducing emissions. The owner of an affected EGU could 
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Page 437 of 1544

invest in such generation shifts in several ways, including by 

operating an NGCC unit it already owns more or by purchasing an 

existing NGCC unit and operating that unit more. Increases in 

generation by NGCC units over baseline levels can also serve as 

the basis for creation of CO2 emission rate credits (ERCs) –- 

that is, instruments representing the ability of incremental 

electricity generated by NGCC units to cause emission reductions 

at affected steam EGUs, as distinct from the incremental 

electricity itself. Again, it is important to note that the 

acquisition of such ERCs represents an investment in the actions 

of the facility or facilities whose alteration of utilization 

levels generated the emissions rate improvement or reduction. In 

the context of the BSER, purchase of instruments representing 

the emissions-reducing benefit of an action is simply a medium 

of investment in the underlying emissions reduction action. 

These mechanisms are discussed further in section V.A.5. In this 

rule, the EPA is establishing minimum criteria for the creation 

of valid ERCs by NGCC units and for the use of such ERCs by 

affected steam EGUs for demonstrating compliance with emission 

rate-based standards of performance established under state 

plans. The existence of minimum criteria will ensure that 

crediting mechanisms are feasible and will facilitate the 

development of organized markets to simplify the process of 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 438 of 1544

buying and selling ERCs. The minimum criteria are discussed in 

section VIII of this preamble.

 We note that an affected EGU investing in building block 2 

to reduce emissions may, but need not, also choose to reduce its 

own generation as part of its approach for meeting the standard 

of performance assigned to it by its state. Through the 

coordinated operation of the integrated electricity system, 

subject to the collective requirements that will be imposed on 

affected EGUs in order to meet the emissions standards 

representing the BSER, an increase in NGCC generation will be 

offset elsewhere in the interconnection by a decrease in other 

generation. Because of the need to meet the collective 

requirements, the decrease in generation resulting from that 

coordinated operation is most likely to be generation from an 

affected steam EGU. Measures taken by affected EGUs that result 

in emission reductions from other EGUs in the source category 

may appropriately be deemed components of a “system of emission 

reduction.” 

 Consideration of other BSER factors also supports a 

determination to include building block 2 as a component of the 

BSER. For example, we expect that building block 2 would have 

positive non-air health and environmental impacts. Coal 

combustion for electricity generation produces large volumes of 

Deleted: 

Deleted: source 

Deleted: sources 

Deleted: sources 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 439 of 1544

solid wastes that require disposal, with some potential for 

adverse environmental impacts; these wastes are not produced by 

natural gas combustion. The intake and discharge of water for 

cooling at many EGUs also carries some potential for adverse 

environmental impacts; NGCC units generally require less cooling 

water than steam EGUs.433 With respect to energy impacts, 

building block 2 represents replacement of electrical energy 

from one generator with electrical energy from another generator 

that consumes less fuel, so the overall energy impact should be 

a reduction in fuel consumption by the overall source category 

as well as by individual affected coal-fired steam EGUs. 

Although for purposes of this rule we consider the incentive for 

technological innovation only in the alternative, we note that 

building block 2 promotes greater use of the NGCC technology 

installed in the existing fleet of NGCC units, which is newer 

and more advanced than the technology installed in much of the 

older existing fleet of steam EGUs. For all these reasons, the 

 

433 For example, according to a DOE/NETL study, the relative 

amount of water consumption for a new pulverized coal plant is 

2.5 times the consumption for a new NGCC unit of similar size. 

“Cost and Performance Baseline for Fossil Energy Plants: Volume 

1: Bituminous Coal and Natural Gas to Electricity,” Rev 2a, 

September 2013, National Energy Technology Laboratory Report 

DOE/NETL-2010/1397. EPA believes the difference would on average 

be even more pronounced when comparing existing coal and NGCC 

units. 

Deleted: advancement 

Deleted: does not call for deployment of new 

technology, but does
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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measures in building block 2 qualify as a component of the “best 

system of emission reduction ... adequately demonstrated.” 

 It should be observed that, by definition of the elements 

of this building block, the shifts in generation taking place 

under building block 2 occur entirely among existing EGUs 

subject to this rulemaking.434 Through application of this 

building block considered in isolation, some affected EGUs –- 

mostly coal-fired steam EGUs -- would reduce their generation 

and CO2 emissions, while other affected EGUs –- NGCC units –- 

would increase their generation and CO2 emissions. However, 

because for each MWh of generation, NGCC units produce fewer CO2

emissions than coal-fired steam EGUs, the total quantity of CO2

emissions from all affected EGUs in aggregate would decrease. In 

the context of the integrated electricity system, where the 

operation of affected EGUs of multiple types is routinely 

coordinated to provide a highly substitutable service, and in 

the context of CO2 emissions, where location is not a 

consideration, in contrast with other pollutants, a measure that 

takes advantage of that integration to reduce CO2 emissions from 

the overall set of affected EGUs is readily encompassed within 

 

434 For purposes of this rulemaking, “existing” EGUs include 

units under construction as of January 8, 2014, the date of 

publication in the Federal Register of the Carbon Pollution 

Standards for new fossil fuel-fired EGUs. 

Deleted: sources 

Deleted: sources 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the meaning of a “system of emission reduction” for CO2 emissions 

at affected EGUs even if the measure would increase CO2 emissions 

from a subset of those affected EGUs. Indeed, some industry 

participants are already moving in this direction for this 

purpose (while other participants are moving in the same 

direction for other purposes). Standards of performance that 

incorporate emissions trading can facilitate the implementation 

of such a “system” and such approaches have already been used in 

the electricity industry to address CO2 as well as other 

pollutants, as discussed above. 

c. Building block 3. Building block 3 –- reducing CO2 emissions 

at, and substituting for generation from, affected EGUs by using 

generation from expanded RE generating capacity –- is a 

component of the BSER because the expansion and use of renewable 

generating capacity to reduce emissions from affected EGUs is 

technically feasible, is of reasonable cost, and performs well 

with respect to other factors relevant to a determination of the 

“best system of emission reduction ... adequately demonstrated.”

Building block 3 is a “system of emission reduction” for all 

affected EGUs because incremental RE generation will result in 

reduced generation and emissions from affected EGUs, and owners 

of affected EGUs can invest in incremental RE generation either 

directly or through the purchase of ERCs. An affected EGU 

Deleted: and other multi-unit compliance 

approaches 

Deleted: sources 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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investing in incremental RE generation may choose to reduce its 

own generation by a corresponding amount or may choose to allow 

the reduction in generation to occur at other affected EGUs 

through the coordinated planning and operation of the 

interconnected electricity system. An affected EGU can also 

invest in RE generation by means of engaging in emissions 

trading where the EGU is operating under a standard of 

performance that incorporates trading. 

 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the measures in building 

block 3 are discussed in Section V.E. below. We consider 

construction and operation of expanded RE generating capacity to 

be proven, well-established practices within the industry 

consistent with recent industry trends. States are already 

pursuing policies that encourage production of greater amounts 

of renewable energy, such as the establishment of targets for 

procurement of renewable generating capacity. Moreover, as 

discussed earlier, markets are likely to develop for ERCs that 

would facilitate investment in increased RE generation as a 

means of helping sources comply with their standards of 

performance; indeed, markets for renewable energy certificates, 

which similarly facilitate investment in renewable energy for 

other purposes, are already well-established. As noted in 

Deleted: it 

Deleted: emission rate credits 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 443 of 1544

Section V.A.5. below, an allowance system or tradable emission 

rate system would provide incentives for affected EGUs to reduce 

their emissions as much as possible where such reductions could 

be achieved economically (taking into account the value of the 

emission credits or allowances), including through substituting 

for their generation with generation from renewable energy, or 

could provide a mechanism, as stated above, for such sources to 

invest in or acquire such generation. 

 Building block 3 is adequately demonstrated as a “system of 

emission reduction” for all affected EGUs. Both Congress and the 

EPA have previously established frameworks under which RE 

generation could be used as a means of achieving emission 

reductions from the utility power sector, as discussed in 

section V.B. Investment in RE generation has grown rapidly, such 

that in recent years the amount of new RE generating capacity 

brought into service has been comparable to the amount of new 

fossil fuel-fired capacity. Rapid growth in RE generation is 

projected to continue as costs of RE generation fall relative to 

the costs of other generation technologies. These trends are 

further discussed in section V.E. Interpretation of a “system of 

emission reduction” as including RE generation for purposes of 

this rule is thus supported by legislative history, regulatory 

precedent, and industry practice. 

Deleted: sources 
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Page 444 of 1544

 Also supporting the determination that building block 3 is 

adequately demonstrated as a “system of emission reduction” is 

the fact that owners of affected EGUs have the ability to invest 

in RE generation as a way of reducing emissions. As with 

building block 2, this can be accomplished in several ways. For 

example, the owner of an affected EGU could invest in new RE 

generating capacity and operate that capacity in order to obtain 

ERCs. Alternatively, the affected EGU could purchase ERCs 

created based on the operation of an unaffiliated RE generating 

facility, effectively investing in the actions at another site 

that allow CO2 emission reductions to occur. These mechanisms are 

discussed further in section V.A.5. As with building block 2, in 

this rule the EPA is establishing minimum criteria for the 

creation of valid ERCs by new RE generators and for the use of 

such ERCs by affected EGUs for demonstrating compliance with 

emission rate-based standards of performance established under 

state plans. The existence of minimum criteria will ensure that 

crediting mechanisms are feasible and will facilitate the 

development of organized markets to simplify the process of 

buying and selling credits. The minimum criteria are discussed 

in section VIII of the preamble. 

 As with building block 2, an affected EGU investing in 

building block 3 to reduce emissions may, but need not, also 

Deleted: . Operation of new RE generating 

capacity could also serve as the basis for 

issuance of an ERC, and the owner of the 

affected EGU could either operate new RE 

generating capacity

Deleted: or 

Deleted: emission rate credits 

Deleted: credits 

Deleted: source 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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choose to reduce its own generation as part of its approach for 

meeting the standard of performance assigned to it by its state. 

Through the coordinated operation of the integrated electricity 

system, subject to the collective requirements that will be 

imposed on affected EGUs in order to meet the emissions 

standards representing the BSER, an increase in RE generation 

will be offset elsewhere in the interconnection by a decrease in 

other generation. Because of the need to meet the collective 

requirements, the decrease in generation resulting from that 

coordinated operation is most likely to be generation from an 

affected EGU. As discussed in section V.B., measures taken by 

affected EGUs that result in emission reductions from other 

sources in the source category may appropriately be deemed 

components of a “system of emission reduction.” 

 The renewable capacity measures in building block 3 

generally perform well against other BSER criteria. Generation 

from wind turbines and solar voltaic installations, two common 

renewable technologies, does not produce solid waste or require 

cooling water, a better environmental outcome than if that 

amount of generation had instead been produced at a typical 

range of fossil fuel-fired EGUs. With respect to energy impacts, 

fossil fuel consumption will decrease both for the source 

category as a whole and for individual affected EGUs. Although 

Deleted: sources 

Deleted: sources 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the variable nature of generation from renewable resources such 

as wind and solar units requires special consideration from grid 

operators to address possible changes in operating reserve 

requirements, renewable generation has grown quickly in recent 

years, as discussed above, and grid planners and operators have 

proven capable of addressing any consequent changes in 

requirements through ordinary processes. The EPA believes that 

planners and operators will be similarly capable of addressing 

any changes in requirements due to future growth in renewable 

generation through ordinary processes, but notes that in 

addition, the reliability safety valve in this rule, discussed 

in section VIII.G.2, will ensure the absence of adverse energy 

impacts. With respect to technological innovation, which we 

consider for the BSER only in the alternative, incentives for 

expansion of renewable capacity encourage technological 

innovation in improved renewable technologies as well as more 

extensive deployment of current advanced technologies. For all 

these reasons, the measures in building block 3 qualify as a 

component of the “best system of emission reduction ... 

adequately demonstrated.” 

d. Combination of all three building blocks. The final BSER 

includes a combination of all three building blocks. For the 

reasons described below, and similar to each of the building 

Deleted: similarly 

Deleted: H

Deleted: an alternative consideration 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 447 of 1544

blocks, the combination must be considered a “system of emission 

reduction.” Moreover, as also discussed below, the combination 

qualifies as the “best” system that is “adequately 

demonstrated.” The combination is technically feasible; it is 

capable of achieving meaningful reductions in CO2 emissions from 

affected EGUs at a reasonable cost; it also performs well 

against the other BSER factors; and its components are wellestablished. The combination of the three building blocks will 

achieve greater CO2 emission reductions at reasonable costs than 

possible combinations with fewer building blocks and will also 

perform better against other BSER factors. We therefore find the 

combination of all three building blocks to be the “best system 

of emission reduction ... adequately demonstrated” for reducing 

CO2 emissions at affected EGUs. 

As already discussed, each of the individual building 

blocks generally performs well with respect to the BSER factors 

identified by the statute and the D.C. Circuit. (The exception, 

which we have pointed out above, is that building block 1, if 

implemented in isolation, would achieve an insufficient 

magnitude of emission reductions to be considered the BSER.) The 

EPA expects that combinations of the building blocks would 

perform better than the individual building blocks. Beginning 

with the most obvious and important advantage, combinations of 

Deleted: 435
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Page 448 of 1544

the building blocks will achieve greater emission reductions 

than the individual building blocks would in isolation, assuming 

that the building blocks are applied with the same stringency. 

Because fossil fuel-fired EGUs generally have higher variable 

costs than other EGUs, it will generally be fossil fuel-fired 

generation that is replaced when low-variable cost RE generation 

is increased. At the levels of stringency determined to be 

reasonable in this rule, opportunities to deploy building block 

2 to replace higher-emitting generation and to deploy building 

block 3 to replace any emitting generation are not exhausted. 

Thus, as the system of emission reduction is expanded to include 

each of these building blocks, the emission reductions that will 

be achieved increase. 

Because the stringency and timing of emission reductions 

achievable through use of each individual building block have 

been set based on what is achievable at reasonable cost rather 

than the maximum achievable amount, the stringency of the 

combination of building blocks is also reasonable, and the 

combination provides headroom and additional flexibility for 

states in setting standards of performance and for sources in 

complying with those standards to choose among multiple means of 

reducing emissions. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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With respect to the quantity of emission reductions 

expected to be achieved from building block 1 in particular, the 

BSER encompassing all three building blocks is a substantial 

improvement over building block 1 in isolation. As noted 

earlier, the EPA is concerned that implementation of building 

block 1 in isolation not only would achieve insufficient 

emission reductions assuming generation levels from affected 

steam EGUs were held constant, but also has the potential to 

result in a “rebound effect.” The nature of the potential 

rebound effect is that by causing affected steam EGUs to improve 

their heat rates and thereby lower their variable operating 

costs, building block 1 if implemented in isolation would make 

those EGUs more competitive relative to other, lower-emitting 

fossil fuel-fired EGUs, possibly resulting in increased 

generation and higher emissions from the affected steam EGUs in 

spite of their lower emission rates. Combining building block 1 

with the other building blocks addresses this concern by 

ensuring that owner/operators of affected steam EGUs as a group 

would have appropriate incentives not only to improve the steam 

EGUs’ efficiency but also to reduce generation from those EGUs 

consistent with replacement of generation by lower- or nonemitting EGUs. While combining building block 1 with either 

building block 2 or 3 should address this concern, the 

Deleted: and avoidance of generation through 

demand-side energy efficiency. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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combination of all three building blocks addresses it more 

effectively by strengthening the incentives to reduce generation 

from affected steam EGUs. 

The combination of all three building blocks is also of 

reasonable cost. As described in sections V.C. through V.E. and 

the GHG Mitigation Measures TSD, the EPA determined that the 

cost of each of the three building blocks was reasonable. In 

summary, these cost estimates are $23 per ton of CO2 reductions 

for building block 1, $24 per ton for building block 2, and $37 

per ton for building block 3. The EPA also considered the 

reasonableness of the cost of all three building blocks if 

assessed together. The EPA estimates that, together, the three 

building blocks are able to achieve CO2 reductions at an average 

cost of $30 per ton. This estimate is an average of the 

estimates for each building block, weighted by the total 

estimated cumulative CO2 reductions for each of these building 

blocks over the 2022-2030 period. While it is possible to weight 

each building block by other amounts, the EPA believes that 

weighting by cumulative CO2 reductions best reflects the average 

cost of total reduction potential across the three building 

blocks. The EPA considers each of these cost levels reasonable 

for purposes of the BSER established for this rule. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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The EPA views the weighted average cost estimate as a 

conservatively high estimate of the cost of deploying all three 

building blocks simultaneously. The simultaneous application of 

all three building blocks produces interactive dynamics, some of 

which could increase the cost and some of which could decrease 

the cost represented in the individual building blocks. For 

example, one dynamic that would tend to raise costs (and whose 

omission would therefore make the weighted average understate 

costs) is that the emission reduction measures associated with 

building blocks 2 and 3 both prioritize the replacement of 

higher-cost generation (from affected steam EGUs in the case of 

building block 2 and from all affected EGUs in the case of 

building block 3). The EPA recognizes that the increased 

magnitude of generation replacement when building blocks 2 and 3 

are implemented together necessitates that some of the 

generation replacement will occur at more efficient affected 

EGUs, at a relatively higher cost; however, this is a 

consequence of the greater emission reductions that can be 

achieved by combining building blocks, not an indication that 

any individual building block has become more expensive because 

of the combined deployment. 

Also, the EPA recognizes that when building block 1 is 

combined with the other building blocks, the combination has the 

Deleted: In general, building blocks 2 and 3 do 

not interact with one another in a manner that

would cause the cost of deploying any of these 

building blocks in combination with the other 

building blocks to be more than the cost of 

deploying the respective building block in 

isolation to the same degree of stringency. 

The EPA recognizes that as increasing 

quantities of generation from higher-emitting 

EGUs are replaced, the avoided cost of the 

generation that is being replaced by lower- or 

non-emitting generation decreases, but 

Deleted: Moreover, the availability to states 

of standards of performance that allow the use 

of emissions trading or other multi-unit 

compliance approaches will further reduce the 

overall costs of this rule by facilitating the 

ability of individual affected EGUs to take 

advantage of instances where other affected 

EGUs have opportunities to reduce emissions at 

lower cost.

Deleted: The 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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potential to raise the cost of the portion of the overall 

emission reductions achievable through heat rate improvements 

relative to the cost of those same reductions if building block 

1 were implemented in isolation (assuming for purposes of this 

discussion that the rebound effect is not an issue and that the 

affected steam EGUs would in fact reduce their emissions if 

building block 1 were implemented in isolation).436 However, we 

believe that the cost of emission reductions achieved through 

heat rate improvements in the context of a three-building block 

BSER will remain reasonable for two reasons. First, as discussed 

in section V.C. below, even when conservatively high investment 

costs are assumed, the cost of CO2 emission reductions achievable 

through heat rate improvements is low enough that the cost per 

ton of CO2 emission reductions will remain reasonable even if 

that cost is substantially increased. Second, although under a 

BSER encompassing all three building blocks the volume of coalfired generation will decrease, that decrease is unlikely to be 

 

436 If an EGU produces less generation output, then an 

improvement in that EGU’s heat rate and rate of CO2 emissions per 

unit of generation produces a smaller reduction in CO2 emissions. 

If the investment required to achieve the improvement in heat 

rate and emission rate is the same regardless of the EGU’s 

generation output, then the cost per unit of CO2 emission 

reduction will be higher when the EGU’s generation output is 

lower. Commenters have also stated that operating at lower 

capacity factors may cause units to experience deterioration in 

heat rates. 

Deleted: quite low, and 

Deleted: it 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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spread uniformly among all coal-fired EGUs. It is more likely 

that some coal-fired EGUs will decrease their generation 

slightly or not at all while others will decrease their 

generation by larger percentages or cease operations altogether. 

We would expect EGU owners to take these changes in EGU 

operating patterns into account when considering where to invest 

in heat rate improvements, with the result that there will be a 

tendency for such investments to be concentrated in EGUs whose 

generation output is expected to decrease the least. This 

enlightened bias in spending on heat rate improvements –- that 

is, focusing investments on EGUs where such improvements will 

have the largest impacts and produce the highest returns, given 

consideration of projected changes in dispatch patterns –- will 

tend to mitigate any deterioration in the cost of CO2 emission 

reductions achievable through heat rate improvements. 

In contrast with those prior examples, combining the 

building blocks also produces interactive dynamics that 

significantly reduce the cost for CO2 reductions represented in 

the individual building blocks (and whose omission would 

therefore make the weighted average overstate costs). Foremost 

among these dynamics is the stabilization of wholesale power 

prices. When assessed individually, building blocks 2 and 3 have 

opposite impacts on wholesale power prices, although in each 
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Page 454 of 1544

case, the direction of the wholesale power price impact 

corresponds to an increasing cost of that building block in 

isolation. For example, building block 2 promotes more 

utilization of existing NGCC capacity, which (assessed on its 

own) would increase natural gas consumption and therefore price, 

in turn raising wholesale power prices (which are often 

determined by gas-fired generators as the power supplier on the 

margin); this dynamic puts upward pressure on the cost of 

achieving CO2 reductions through shifting generation from steam 

EGUs to NGCC units.437 Meanwhile, building block 3 increases RE 

deployment; because RE generators have very little variable 

cost, an increase in RE generation replaces other supply with 

higher variable cost, which would yield lower wholesale power 

prices. Lower wholesale power prices would make further RE 

deployment less competitive against generation from existing 

emitting sources; this dynamic puts upward pressure on the cost 

of achieving CO2 reductions through increased RE deployment.438

Applying building blocks 2 and 3 together produces significantly 

more CO2 reductions at a relatively lower cost because the 

 

437 The EPA’s cost-effectiveness estimate of $24 per ton for 

building block 2 reflects these market dynamics. 

438 The EPA’s cost-effectiveness estimate of $37 per ton for 

building block 3 reflects these market dynamics. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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countervailing nature of these wholesale power price dynamics 

mitigates the primary cost drivers for each building block. 

The EPA believes the dynamics tending to cause the weighted 

average above to overstate costs of the combination of building 

blocks are greater than the dynamics tending to cause costs to 

be understated, and that the weighted average costs are 

therefore conservatively high. Analysis performed by the EPA at 

an earlier stage of the rulemaking supports this conclusion. At 

proposal, the EPA evaluated the cost of increasing NGCC 

utilization (building block 2) and deploying incremental RE 

generation (building block 3) independently, as well as the cost 

of simultaneously increasing NGCC utilization and incremental RE 

generation. The average cost (in dollars per ton of CO2 reduced) 

was less for the combined building block scenario, showing that 

the net outcome of the interactivity effects described above is 

a reduction in cost per ton when compared to cost estimates that 

do not incorporate this interactivity.439 

A final reason why the EPA considers the weighted-average 

cost above conservatively high is that simply combining the 

building blocks at their full individual stringencies overstates 

 

439 Specifically, at proposal the EPA quantified the average 

cost, in dollar per ton of CO2 reduced, of building blocks 1, 2, 

and 3 ($22.5 per ton) to be less than the cost of either 

building block 2 ($28.9 per ton) or building block 3 ($23.4 per 

ton) alone. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the stringency of the BSER. As discussed in section V.A.3.f and 

section VI, the BSER reflects the combined degree of emission 

limitation achieved through application of the building blocks 

in the least stringent region. By definition, in the other two 

regions, the BSER is less stringent than the simple combination 

of the three building blocks whose stringency is represented in 

the weighted-average cost above. 

In addition to the weighted-average cost analysis discussed 

above, for the regulatory impacts analysis accompanying this 

final rule, the EPA has assessed the costs, benefits, and other 

impacts of deployment of the final BSER through section 111(d) 

plans. The analysis reflects transmission and pipeline 

capabilities and constraints, fuel market and electricity 

dispatch dynamics, and seasonal electricity load requirements. 

Moreover, the analysis also includes a limited representation of 

the ability for states to craft standards of performance that 

allow the use of emissions trading approaches, which facilitate 

the ability of individual affected EGUs to take advantage of 

instances where other affected EGUs have opportunities to reduce 

emissions at lower cost. As described below in section XI, the 

results indicate that compliance with standards of performance 

consistent with the final BSER is readily achievable with no 

adverse impacts on electricity system reliability, and that 

Deleted: For 

Deleted: the compliance flexibility under the 

rule, along with 
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impacts on retail electricity prices are modest and fall within 

the range of price variability seen historically in response to 

changes in factors such as weather and fuel supply. Further, the 

costs tend to decline over time as states and regulated entities 

take advantage of the available flexibility and expand 

deployment of more cost-effective measures (notably demand-side 

energy efficiency). The EPA considers this analysis strong 

confirmation of the reasonableness of the costs of the measures 

in the three building blocks in combination as the best system 

of emission reduction. As discussed above, D.C. Circuit case law 

authorizes the EPA to consider costs on a broader basis, 

including on the sector and the country as a whole, in 

determining the BSER. Here, we find that whether costs are 

considered on an individual source basis in light of the costper-ton of the building blocks, or on a broader basis, or both 

bases together, the costs are reasonable.

Finally, the EPA notes that the combination of all three 

building blocks would perform consistently with the individual 

building blocks with respect to non-air energy and environmental 

impacts. There is no reason to expect an adverse non-air 

environmental or energy impact from deployment of the 

combination of the three building blocks, whether considered on 

a source-by-source basis, on a sector-wide or national basis, or 

Deleted: 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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both. Likewise, with respect to technological innovation, which 

we consider only in the alternative, the building blocks in 

combination would have the same positive effects that they would 

have if implemented independently.

e. Other combinations of the building blocks. The EPA has 

considered whether other combinations of the building blocks, 

such as a combination of building blocks 1 and 2 or a 

combination of building blocks 1 and 3, could be the BSER. We 

believe that any such combination is technically feasible and 

would be a “system of emission reduction” capable of achieving 

meaningful reductions in CO2 emissions from affected EGUs at a 

reasonable cost. As with the combination of three building 

blocks discussed above, any combination of building blocks would 

achieve greater emission reductions than the individual building 

blocks encompassed in that combination would achieve if 

implemented in isolation. Further, the cost of any combination 

would be driven principally by the combined stringency and would 

remain reasonable in aggregate. We have already noted our 

determination that building block 1 in isolation is not the BSER 

because it would not produce a sufficient quantity of emission 

reductions. A combination of building block 1 with one of the 

other building blocks would produce greater emission reductions 

and would not be subject to this concern. Any combination of 
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Page 459 of 1544

building blocks including building block 1 and at least one 

other building block would also address the concern about 

potential “rebound effect,” discussed above, that could occur if 

building block 1 were implemented in isolation. Finally, there 

is no reason to expect any combination of the building blocks to 

have adverse non-air energy or environmental impacts, and the 

implications for technological innovation, which we consider 

only in the alternative, would likewise be positive for any 

combination of the building blocks because those implications 

are positive of the individual building blocks and there is no 

reason to expect negative interaction from a combination of 

building blocks. 

For these reasons, any combination of the building blocks 

(but not a BSER comprising building block 1 in isolation) could 

be the BSER if it were not for the fact that a BSER comprising 

all three of the building blocks will achieve greater emission 

reductions at a reasonable cost and is therefore “better.” As 

discussed below in section V.A.7., we intend for the individual 

building blocks to be severable, such that if a court were to 

strike down building block 2 or 3, but not both, the BSER would 

comprise the remaining building blocks. 

f. Achievability of emission limits. As noted, based on the 

BSER, the EPA has established a source subcategory-specific 

Deleted: a 
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emission performance rate for fossil steam units and one for 

NGCC units. As discussed in section V.A.1.c., for new sources, 

standards of performance must be “achievable,” under CAA section 

111(a)(1), and the D.C. Circuit has identified criteria for 

achievability.440 In this rule, the EPA is taking the approach 

that while the states are not required to adopt those source 

subcategory-specific emission performance rates as the standards 

of performance for their affected EGUs, those rates must be 

achievable by the steam generator and NGCC subcategories, 

respectively. In addition, the EPA is assuming that the criteria 

in the case law for new sources apply to existing sources under 

section 111(d). For the reasons discussed next, for this rule, 

the source subcategory-specific emission performance rates are 

achievable in accordance with those criteria in the case law. 

As noted, the building blocks include several features that 

assure that affected EGUs may implement them. The building 

blocks may be implemented through a range of methods, including 

through the purchase of ERCs and emission trading. In addition, 

the building blocks incorporate “headroom.” Moreover, the source 

subcategory-specific emission performance rates apply on an 

 

440 See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 

(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); Nat’l Lime 

Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 1980); Sierra 

Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l 

Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980).
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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annual basis, so that short-term issues need not jeopardize 

compliance. In addition, we quantify the emission performance 

rates based on the degree of emission limitation achievable by 

affected EGUs in the region where application of the combined 

building blocks results in the least stringent emission rate. 

Because the means to implement the building blocks are widely 

available and because of the just-noted flexibilities and 

approaches to the emission performance rates, all types of 

affected steam generating units, operating throughout the lower48 states and under all types of regulatory regimes, are able to 

implement building blocks 1, 2 and 3 and thereby achieve the 

emission performance rate for fossil steam units, and all types 

of NGCC units operating in all states under all types of 

regulatory requirements are able to implement building block 3 

and thereby achieve the emission performance rate for NGCC 

units.441 

Commenters have raised questions about whether particular 

circumstances could arise, such as the sudden loss of certain 

generation assets, that would cause the implementation of the 

building blocks to cause reliability problems, and have 

cautioned that these circumstances could preclude implementation 

 

441 We discuss the ability of affected EGUs to implement the 

building blocks in more detail in sections V.C., V.D., and V.E. 

and the accompanying support documents. 
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of the building blocks and thus achievement of the emission 

performance rates. Commenters have also raised concerns about 

whether affected EGUs with limited remaining useful lives can 

implement the building blocks and achieve the emission 

performance rates. We address those concerns in section VIII, 

where we authorize state plans to include a reliability 

mechanism and discuss affected EGUs with limited remaining 

useful lives. Accordingly, we conclude that the source 

subcategory specific emission performance standards are 

achievable in accordance with the case law. 

5. Actions under the BSER that sources can take to achieve 

standards of performance 

 Based on the determination of the BSER described above, the 

EPA has identified a performance rate of 1305 lbs. per net MWh 

for affected steam EGUs and a performance rate of 771 lbs. per 

net MWh for affected stationary combustion turbines. The 

computations of these performance rates and the determinations 

of state goals reflecting these rates are described in sections 

VI and VII of the preamble, respectively. 

 Under section 111(d), states determine the standards of 

performance for individual sources. The EPA is authorizing 

states to express the standards of performance applicable to 

affected EGUs as either emission rate-based limits or mass-based 

Deleted: 0
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limits. As described above, the sets of actions that sources can 

take to comply with these standards may be understood as part of 

the BSER. 

 A source to which a state applies an emission rate-based 

limit can achieve the limit through a combination of the 

following set of measures (to the extent allowed by the state 

plan), all of which are components of the BSER: 

 Reducing its heat rate (building block 1). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, incremental generation from 

existing NGCC units (building block 2). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, generation from new or up-rated RE 

generators (building block 3). 

 Reducing its utilization, coupled with direct investment in 

or purchase of emission rate credits representing building 

blocks 2 and 3 as indicated above. 

 Investing in surplus emission rate reductions at other 

affected EGUs through the purchase or other acquisition of 

rate-based emission credits. 

 A source to which a state applies a mass-based limit can 

achieve the limit through a combination of the following set of 

Deleted: are another expression of the BSER, 

viewed through an individual-source lens.

Deleted: or the use of other multi-unit 

compliance approaches (e.g., averaging)
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measures (to the extent allowed by the state plan), all of which 

are likewise components of the BSER: 

 Reducing its heat rate (building block 1). 

 Reducing its utilization and allowing its generation to be 

replaced or avoided through the routine operation of 

industry reliability planning mechanisms and market 

incentives. 

 Investing in surplus emission reductions at other affected 

EGUs through the purchase or other acquisition of massbased emission allowances. 

 The EPA has determined appropriate CO2 emission performance 

rates for each of the two source subcategories as a whole,

achievable through application of the building blocks. The wide 

ranges of measures included in the BSER and available to 

individual sources as indicated above provide assurance that the 

source category as a whole can achieve standards of performance 

consistent with those emissions standards using components of 

the BSER, whether states choose to establish emission rate-based 

limits or mass-based limits. The wide ranges of measures 

included in the BSER also provide assurance that each individual 

affected EGU could achieve the standard of performance its state 

establishes for it using components of the BSER. Of course, 

Deleted: or the use of other multi-unit 

compliance approaches (e.g., aggregation or 

bubbling)

Deleted: emissions standards 

Deleted: o

Deleted: 2

Deleted: category 

Deleted: source 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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sources may also employ measures not included in the BSER, to 

the extent allowed under the applicable state plan. 

 In the remainder of this subsection, we discuss further how 

affected EGUs can use each of the measures listed above to 

achieve emission rate-based forms of performance standards and 

mass-based forms of performance standards, indicating that all 

types of owner/operators of affected EGUs –- i.e., vertically 

integrated utilities and merchant generators; investor-owned, 

government-owned, and customer-owned (cooperative) utilities; 

and owner/operators of large, small, and single-unit fleets of 

generating units –- have the ability to deploy each of the 

building blocks in some way. In the following subsection we 

discuss the use of measures not in the BSER that can help 

sources achieve the standards of performance. 

a. Use of BSER measures to achieve an emission rate-based 

standard. Under an emission-rate based form of performance 

standards, compliance is nominally determined through a 

comparison of the affected EGU’s emission rate to the emission 

rate standard. The emissions-reducing impact of BSER measures 

that reduce CO2 emissions through reductions in the quantity of 

generation rather than through reductions in the amount of CO2

emitted per unit of generation would not be reflected in an 

affected EGU’s emission rate computed solely based on measured 

Deleted: Because an emission rate computed 

solely based on measured stack emissions and 

measured electricity generation will not 

reflect the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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stack emissions and measured electricity generation but can 

readily be reflected in an emission rate computation by 

averaging ERCs acquired by the affected into the rate 

computation. 

 In section VIII.K., we discuss the processes for issuance 

and use of ERCs that can be included in the emission rate 

computations that affected EGUs perform to demonstrate 

compliance with an emission rate standard. This ERC mechanism is 

analogous to the approach the EPA has used to reflect building 

blocks 2 and 3 in the uniform emission rates representing the 

BSER, as discussed in section VI below. As summarized below and 

as discussed in greater detail in section VIII.K., the existence 

of a clearly feasible path for usage of ERCs ensures that 

emission reductions achievable through implementation of the 

measures in building blocks 2 and 3 are available to assist all 

affected EGUs in achieving compliance with standards of 

performance based on the BSER. 

 (1) Building block 1. 

 The owner/operator of an affected steam EGU can take steps 

to reduce the unit’s heat rate, thereby lowering the unit’s CO2

emission rate. Examples of actions in this category are included 

in section V.C. below and in the GHG Mitigation Measures TSD for 

Deleted: , a plan that imposes emission ratebased standards of performance on affected 

EGUs will also need to authorize a rate 

computation mechanism whereby affected EGUs 

can adjust the rate computation to account for 

generation reduction measures.

Deleted: One mechanism that the 

Deleted: EPA has determined to be appropriate 

is to include emission rate credits (ERCs) 

Deleted: We have determined that one viable way 

to specify ERCs – which we believe offers 

benefits of fungibility and ease of tracking –

is to define the ERCs associated with building 

blocks 2 and 3 as units of zero-emissions 

generation. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the CPP Final Rule. Any type of owner/operator can take 

advantage of this measure. 

 (2) Building block 2. 

 The owner/operator of an affected EGU can average the EGU’s 

emission rate with ERCs issued on the basis of incremental 

generation from an existing NGCC unit. As permitted under the 

EGU’s state’s section 111(d) plan, the owner/operator of the 

affected EGU could accomplish this through either common 

ownership of the NGCC unit, a bilateral transaction with the 

owner/operator of the NGCC unit, or a transaction for ERCs 

through an intermediary, which could, but need not, involve an 

organized market.442 As discussed earlier, based on observation 

of market behavior both inside and outside the electricity 

industry, we expect that intermediaries will seek opportunities 

to participate in such transactions and that organized markets 

are likely to develop as well if section 111(d) plans authorize 

the use of ERCs. While the opportunity to acquire ERCs through 

common ownership of NGCC facilities might not extend to 

owner/operators of single EGUs or small fleets, all 

 

442 Each of these methods of implementing building block 2 meets 

the criteria for the BSER in that (i) as we discuss in section 

V.D. and supporting documents, each of these methods is 

adequately demonstrated;(ii) the costs of each of these methods 

on a source-by-source basis are reasonable, as discussed above; 

and (iii) none of these methods causes adverse energy impacts or 

non-quality environmental impacts.

Deleted: with incremental generation from an 

existing NGCC unit or 

Deleted: The 

Deleted: either 

Deleted: Based 
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owner/operators would have the ability to engage in bilateral or 

intermediated purchase transactions for ERCs just as they can 

engage in transactions for other kinds of goods and services. 

 In section VIII.K. below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon incremental electricity generation by an 

existing NGCC unit. Those criteria generally concern ensuring 

that the physical basis for the ERC –- i.e., qualifying 

generation by an existing NGCC unit and the NGCC unit CO2

emissions associated with that qualifying generation –- is 

adequately monitored and that there is an adequate 

administrative process for tracking credits to avoid doublecounting. In the case of ERCs related to building block 2, the 

monitoring criteria would generally be satisfied by standard 40 

CFR part 75 monitoring. 

 The owner/operator of an affected steam EGU would use the 

ERCs it has acquired for compliance –- whether acquired through 

ownership of NGCC capacity, a bilateral transaction, or an 

intermediated transaction –- by adding the ERCs to its measured 

net generation when computing its CO2 emission rate for purposes 

of demonstrating compliance with its emission rate-based 

standard of performance. 

 (3) Building block 3. 

Deleted: incremental 

Deleted: incremental 

Deleted: As noted above, the EPA has 

determined that one way to define an ERC –- 

which facilitates fungibility and tracking –- 

is to denominate each ERC in the form of a 

single zero-emissions MWh. NGCC units have 

non-zero CO2 emission rates, but their CO2

emission rates are lower than the CO2 emission 

rates of affected steam EGUs. Consistent with 

the fact that the BSER for affected steam EGUs 

reflects the opportunity to replace generation 

from affected steam EGUs with incremental 

generation from existing NGCC units at a 

lower, but non-zero, emission rate, 

incremental generation by an existing NGCC 

unit can qualify as the basis for issuance of 

ERCs, but one incremental MWh of NGCC 

generation would be insufficient to serve as 

the basis for an ERC worth one full MWh of 

zero-emissions generation. The specific number 

of incremental MWh that an NGCC unit would 

need to generate in order to qualify for 

issuance of an ERC representing one MWh of 

zero-emissions generation would depend on the 

magnitude of the difference between the NGCC 

unit’s actual emission rate and the average 

standard of performance for affected steam 

EGUs in its state –- e.g., the uniform 

emission rate representing the BSER for steam 

EGUs. Further details are provided in section 

VIII. ¶
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 The owner/operator of an affected EGU can average the EGU’s 

emission rate with ERCs issued on the basis of generation from 

new (i.e., post-2012) RE generating capacity, including both 

newly constructed capacity and new uprates to existing RE 

generating capacity. As permitted under the EGU’s state’s 

section 111(d) plan, the owner/operator of the affected EGU 

could accomplish this through either common ownership of the RE 

generating capacity, a bilateral transaction with the 

owner/operator of the RE generating capacity, or a transaction 

for ERCs through an intermediary, which could, but need not, 

involve an organized market.443 As discussed earlier, based on 

observation of market behavior both inside and outside the 

electricity industry, we expect that intermediaries will seek 

opportunities to participate in such transactions and that 

organized markets are likely to develop as well if section 

111(d) plans authorize the use of ERCs. While the opportunity to 

acquire ERCs through common ownership of RE generating 

facilities might not extend to owner/operators of single EGUs or 

 

443 As with building block 2, each of these methods of 

implementing building block 3 meets the criteria for the BSER in 

that (i) as we discuss in section V.E. and supporting documents, 

each of these methods is adequately demonstrated;(ii) the costs 

of each of these methods on a source-by-source basis are 

reasonable, as discussed above; and (iii) none of these methods 

causes adverse energy impacts or non-quality environmental 

impacts.

Deleted: , or with ERCs issued on the basis of 

such generation. The 

Deleted: can 

Deleted: either 

Deleted: Based 
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small fleets, all owner/operators would have the ability to 

engage in bilateral or intermediated purchase transactions for 

ERCs just as they can engage in transactions for other kinds of 

goods and services. 

 In section VIII.K. below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon generation from new RE generating capacity. 

Those criteria generally concern assuring that the physical 

basis for the ERC –- i.e., generation by from qualifying new RE 

capacity –- is adequately monitored and that there is an 

adequate administrative process for tracking credits to avoid 

double-counting and to facilitate enforceability of emission 

limits.444 

 As with building block 2, the owner/operator of an affected 

EGU would use the ERCs it has acquired for compliance –- whether 

acquired through ownership of qualifying RE generating capacity, 

a bilateral transaction, or an intermediated transaction –- by 

adding the ERCs to its measured net generation when computing 

its CO2 emission rate for purposes of demonstrating compliance 

with its emission rate-based standard of performance. 

 (4) Reduced generation. 

 

444 The possible use of types of RE generating capacity that are 

not included in the BSER is discussed in section V.A.6. and 

section VIII of the preamble.

Deleted: The types of RE generating capacity 

used by the EPA to quantify building block 3 

are zero-emitting units. Under the definition 

of ERCs described above, each MWh of 

incremental generation by qualifying new RE 

generating capacity therefore can qualify as 

the basis for issuance of an ERC representing 

a full zero-emissions MWh.445 Further details 

are provided in section VIII. ¶
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 The owner/operator of an affected EGU can reduce the unit’s 

generation and reflect that reduction in the form of a lower 

emission rate provided that the owner/operator also acquires 

some amount of ERCs to use in computing the unit’s emission rate 

for purposes of demonstrating compliance. As permitted under the 

EGU’s state’s section 111(d) plan, the ERCs could be acquired 

through investment in incremental generation from existing NGCC 

capacity, generation from new RE generating capacity, or 

purchase from an entity with surplus ERCs. If the owner/operator 

does not average any ERCs into the unit’s emission rate, 

reducing the unit’s own generation will proportionately reduce 

both the numerator and denominator of the fraction and therefore 

will not affect the computed emission rate (unless the unit 

retires, reducing its emission rate to zero). However, if the 

owner/operator does average ERCs into the unit’s emission rate, 

then a proportional reduction in both the numerator and the 

portion of the denominator representing the unit’s measured 

generation will amplify the effect of the acquired ERCs in the 

computation, with the result that the more the unit reduces its 

generation, the fewer ERCs will be needed to reach a given 

emission rate-based standard of performance. All owner/operators 

have the ability to reduce generation, and as discussed above 

all also would be capable of acquiring ERCs, so all would be 

Deleted: or otherwise invests 

Deleted: or 

Deleted: or qualifying cleaner generation 

Deleted: or qualifying cleaner generation 
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capable of reflecting reduced utilization in their emission 

rates for purposes of demonstrating compliance. 

 (5) Emissions trading approaches. 

 To the extent allowed under standards of performance that 

incorporate emissions trading or otherwise through the relevant 

section 111(d) plans, the owner/operator of an affected EGU can 

acquire tradable rate-based emission credits representing an 

investment in surplus emission rate reductions not needed by 

another affected EGU and can average those credits into its own 

emission rate for purposes of demonstrating compliance with its 

rate-based standard of performance. The approach would have to 

be authorized in the appropriate section 111(d) plan and would 

have to conform to the minimum conditions for such approaches 

described in section VIII below. As we have repeatedly noted, we 

read the comment record and the discussions that occurred during 

the outreach process to support the prediction that such 

authorization will be forthcoming from virtually all states that 

submit plans establishing standards of performance for their 

affected EGUs. 

 Under a rate-based emissions trading approach, credits are 

initially created and issued according to processes defined in 

the state plan. After credits are initially issued, the 

owner/operator of an affected EGU needing additional credits can 

Deleted: or other multi-unit compliance 

Deleted: reductions 

Deleted: A multi-unit approach without tradable 

credits is possible, commonly referred to as 

averaging. Alternatively, tradable credits 

could be used, reflecting an emissions trading 

approach. In either case, the 

Deleted: 

Deleted: an 

Deleted: the 
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acquire credits through common ownership of another affected EGU 

or through a bilateral transaction with the other affected EGU, 

or the owner/operator of the affected EGU can acquire credits in 

a transaction through an intermediary, which could, but need 

not, involve an organized market. As discussed earlier, based on 

observation of market behavior both inside and outside the 

electricity industry, we expect that intermediaries will seek 

opportunities to participate in such transactions and that 

organized markets are likely to develop as well if section 

111(d) plans and/or standards of performance established 

thereunder authorize emissions trading. While the opportunity to 

acquire credits through common ownership might not extend to 

owner/operators of single EGUs or small fleets, all 

owner/operators would have the ability to engage in bilateral or 

intermediated purchase transactions for credits just as they can 

engage in transactions for other kinds of goods and services. 

 Further details regarding the possible use of rate-based 

emission credits in a state plan (using ERCs issued on the basis 

of investments in building blocks 2 and 3 and potentially other 

measures as the credits) are provided in section VIII.K. 

b. Use of BSER measures to achieve a mass-based standard. Under 

a mass-based form of the standard, compliance is determined 

through a comparison of the affected EGU’s monitored mass 

Deleted: surplus 

Deleted: Based 

Deleted: One possible form of tradable credit 

that could be traded among affected EGUs would 

be a credit denominated in the form of a 

single zero-emission MWh, which would could be 

entirely fungible with the form of ERC 

described above by which affected EGUs could 

acquire the emissions-reducing benefits of 

activating activities encompassed in building 

blocks 2 and 3. The number of MWh that an 

affected EGU with an emission rate below its 

standard would need to generate to serve as 

the basis for issuance of each tradable credit 

– or, conversely, the number of tradable 

credits that a unit with an emission rate 

above its standard would need to acquire in 

order to achieve compliance – would be based 

on the difference between the unit’s actual 

emission rate and the unit’s standard of 

performance established in the applicable 

section 111(d) plan. 
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emissions to a mass-based emission limit. Although a state could 

choose to impose specific mass-based limits that each EGU would 

be required to meet on a physical basis, in past instances where 

mass-based limits have been established for large numbers of 

sources it has been typical for the limit on each affected EGU 

to be structured as a requirement to periodically surrender a 

quantity of emission allowances equal to the source’s monitored 

mass emissions. The EPA believes that section 111(d) encompasses 

the flexibility for plans to impose mass-based standards in the 

typical manner where the standard of performance for each 

affected EGU consists of a requirement to surrender emission 

allowances rather than a requirement to physically comply with a 

unit-specific emissions cap. 

 Measurements of mass emissions at a given affected EGU 

capture reductions in the EGU’s emissions arising from both 

reductions in generation and reductions in the emission rate per 

MWh. Accordingly, under a mass-based standard there is no need 

to provide a mechanism such as the ERC mechanism described above 

in order to properly account for emission reductions 

attributable to particular types of BSER measures. The relative 

simplicity of the mechanics of monitoring and determining 

compliance are significant advantages inherent in the use of 

mass-based standards rather than emission rate-based standards. 

Deleted: source 
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 (1) Building block 1. 

 The owner/operator of an affected steam EGU can take steps 

to reduce the unit’s heat rate, thereby lowering the unit’s CO2

mass emissions. Examples of actions in this category are 

included in section V.C. below and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. Any type of owner/operator 

can take advantage of this measure. 

 (2) Reduced generation. 

 The owner/operator of an affected EGU can reduce its 

generation, thereby lowering the unit’s CO2 mass emissions. Any 

type of owner/operator can take advantage of this measure. 

Although some action or combination of actions to increase 

lower-carbon generation or reduce electricity demand somewhere 

in the interconnected electricity system of which the affected 

EGU is a part will be required to enable electricity supply and 

demand remain in balance, the affected EGU does not need to 

monitor or track those actions in order to use its reduction in 

generation to help achieve compliance with the mass-based 

standard. Instead, multiple participants in the interconnected 

electricity system will act to ensure that supply and demand 

remain in balance, subject to the complex and constantly 

changing set of constraints on operation of the system, just as 

those participants have routinely done for years. 
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 Of course, if the owner/operator of the affected EGU wishes 

to play a direct role in driving the increase in lower-carbon 

generation or demand-side energy efficiency required to offset a 

reduction in the affected EGU’s generation, the owner/operator 

may do so as part of whatever role it happens to play as a 

participant in the interconnected electricity system. However, 

the owner/operator will achieve the benefit that reduction in 

generation brings toward compliance with the mass-based standard 

whether it takes those additional actions itself or instead 

allows other participants in the interconnected electricity 

system to play that role. 

 (3) Emissions trading approaches. 

 To the extent allowed under the relevant section 111(d) 

plans -- as the record indicates that it will be -- the 

owner/operator of an affected EGU can acquire tradable massbased emission allowances representing investment in surplus 

emission reductions not needed by another affected EGU and can 

aggregate those allowances with any other allowances it already 

holds for purposes of demonstrating compliance with its massbased standard of performance. The approach would have to be 

authorized in the appropriate section 111(d) plan and would have 

to conform to the minimum conditions for such approaches 

described in section VIII below. 

Deleted: or other multi-unit compliance 

Deleted: reductions 

Deleted: its own emissions

Deleted: This could be done through either 

approaches using tradable mass-based emission 

allowances or other multi-unit compliance 

approaches, which in this case would consist 

of aggregation or bubbling of emission limits. 

In either case, the 
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 Under a mass-based emissions trading approach, the total 

number of allowances to be issued is defined in the state plan, 

and affected EGUs may obtain an initial quantity of allowances 

through an allocation or auction process. After that initial 

process, the owner/operator of an affected EGU needing 

additional allowances can acquire allowances through common 

ownership of another affected EGU or through a bilateral 

transaction with the other affected EGU, or the owner/operator 

of the affected EGU can acquire allowances in a transaction 

through an intermediary, which could but need not involve an 

organized market. As discussed earlier, based on observation of 

market behavior both inside and outside the electricity 

industry, we expect that intermediaries will seek opportunities 

to participate in such transactions and that organized markets 

are likely to develop as well if section 111(d) plans authorize 

the use of emissions trading. While the opportunity to acquire 

allowances through common ownership might not extend to 

owner/operators of single EGUs or small fleets, all 

owner/operators would have the ability to engage in bilateral or 

intermediated purchase transactions for allowances just as they 

can engage in transactions for other kinds of goods and 

services. 

Deleted: an 

Deleted: the 

Deleted: Based 
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 Further details regarding the possible use of mass-based 

emission allowances in a state plan are provided in section 

VIII.J.

6. Use of non-BSER measures to achieve standards of performance 

 In addition to the BSER-related measures that affected EGUs 

can use to achieve the standards of performance set in section 

111(d) plans, there are a variety of non-BSER measures that 

could also be employed (to the extent permitted under a given 

plan). This final rule does not limit the measures that affected 

EGUs may use for achieving standards of performance to measures 

that are included in the BSER; thus, the existence of these nonBSER measures provides flexibility allowing the individual 

affected EGUs and the source category to achieve emission 

reductions consistent with application of the BSER at the levels 

of stringency reflected in this final rule even if one or more 

of the building blocks is not implemented to the degree that the

EPA has determined to be reasonable for purposes of quantifying 

the BSER. In this way, non-BSER measures therefore provide 

additional flexibility to states in establishing standards of 

performance for affected EGUs through section 111(d) plans and 

to individual affected EGUs for achieving those standards. 

 Any of the non-BSER measures described below would help the 

affected source category as a whole achieve emission limits 

Deleted: 
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consistent with the BSER. The non-BSER measures either reduce 

the amount of CO2 emitted per MWh of generation from the set of 

affected EGUs or reduce the amount of generation, and therefore 

associated CO2 emissions, from the set of affected EGUs. However, 

the manner in which the various non-BSER measures would help 

individual affected EGUs meet their individual standards of 

performance varies according to the type of measure and the type 

of standard of performance –- i.e., whether the standard is 

emission rate-based or mass based. 

 In general, a non-BSER measure that reduces the amount of 

CO2 emitted per MWh of generation at an affected EGU will reduce 

the amount of CO2 emissions monitored at the EGU’s stack 

(assuming the quantity of generation is held constant). Measures 

of this type can help the EGU meet either an emission rate-based 

or mass-based standard of performance. 

 Other non-BSER measures do not reduce an affected EGU’s CO2

emission rate but rather facilitate reductions in CO2 emissions 

by reducing the amount of generation from affected EGUs. Under a 

mass-based standard, the collective reduction in emissions from 

the set of affected EGUs is reflected in the collective 

monitored emissions from the set of affected EGUs. An individual 

EGU that reduces its generation and emissions will be able to 

use the measure to help achieve its mass-based limit. Individual 
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EGUs that do not reduce their generation and emissions will be 

able to use the measure, if the relevant section 111(d) plans 

provide for allowance trading, by purchasing emission allowances 

no longer needed by EGUs that have reduced their emissions. 

 Under an emission rate-based standard, non-BSER measures 

that reduce generation from affected EGUs but do not reduce an 

affected EGU’s emission rate generally can facilitate compliance 

by serving as the basis for ERCs that affected EGUs can average 

into their emission rates for purposes of demonstrating 

compliance. Section VIII.K. includes a discussion of the 

issuance of ERCs based on various non-BSER measures. Affected 

EGUs could use such ERCs to the extent permitted by the relevant 

section 111(d) plans. 

 The remainder of this section discusses some specific types 

of non-BSER measures. The first set discussed includes measures 

that can reduce the amount of CO2 emitted per MWh of generation, 

and the second set discussed includes measures that can reduce 

CO2 emissions by reducing the amount of generation from affected 

EGUs. In some cases, considerations related to use of these 

measures for compliance are discussed below in section VIII on 

state plans. The EPA notes that this is not an exhaustive list 

of non-BSER measures that could be employed to reduce CO2

emissions from affected EGUs, but merely a set of examples that 

Deleted: For some non-BSER measures, each MWh 

of incremental generation produced by the 

measure or each MWh of fossil fuel-fired 

generation avoided by the measure could 

qualify as the basis for issuance of an ERC 

representing a full zero-emissions MWh, 

similar to building block 3. For other nonBSER measures, more than one MWh of 

incremental generation would be required to 

qualify for the basis of an ERC representing a 

full zero-emissions MWh, similar to building 

block 2. 
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illustrate the extent of the additional flexibility such 

measures provide to states and affected EGUs under the final 

rule. 

a. Non-BSER measures that reduce CO2 emissions per MWh generated. 

In the June 2014 proposal, the EPA discussed several potential 

measures that could reduce CO2 emissions per MWh generated at 

affected EGUs but that were not proposed to be part of the BSER. 

The measures discussed included heat rate improvements at 

affected EGUs other than coal-fired steam EGUs; fuel switching 

from coal to natural gas at affected EGUs, either completely 

(conversion) or partially (co-firing); and carbon capture and 

storage by affected EGUs. One reason for not proposing to 

consider these measures to be part of the BSER was that they 

were more costly than other measures. Another reason was that 

the emission reduction potential was limited compared to the 

potential available from the measures that were proposed to be 

included in the BSER. However, we also noted that circumstances 

could exist where these measures could be sufficiently 

attractive to deploy, and that the measures could be used to 

help affected EGUs achieve emission limits consistent with the 

BSER. 

 In the final rule, the EPA has reached determinations 

consistent with the proposal with respect to these measures: 
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namely, that they do not merit inclusion in the BSER, but that 

they are capable of helping affected EGUs achieve compliance 

with standards of performance and are likely to be used for that 

purpose by some units. To the extent that they are selectively 

employed, they provide flexibility for the source category as a 

whole and for individual affected EGUs to achieve emission 

limits reflective of the BSER, as discussed above. 

 (1) Heat rate improvement at affected EGUs other than coalfired steam EGUs. 

 Building block 1 reflects the opportunity to improve heat 

rate at coal-fired steam EGUs but not at other affected EGUs. As 

the EPA stated at proposal, the potential CO2 reductions 

available from heat rate improvements at coal-fired steam EGUs 

are much larger than the potential CO2 reductions available from 

heat rate improvements at other types of EGUs, and comments 

offered no persuasive basis for reaching a different conclusion. 

Nevertheless, we recognize that there may be instances where an 

owner/operator finds heat rate improvement to be an attractive 

option at a particular non-coal-fired affected EGU, and nothing 

in the rule prevents the owner/operator from implementing such a 

measure and using it to help achieve a standard of performance. 

 (2) Carbon capture and storage at affected EGUs. 

Deleted: representative 

Deleted: Further discussion of these measures 

is also provided in the GHG Mitigation 

Measures TSD for the CPP Final Rule.
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 Another approach for reducing CO2 emissions per MWh of 

generation from affected EGUs is the application of carbon 

capture and storage (CCS) technology. Consistent with the June 

2014 proposal, we are determining that use of full or partial 

CCS technology should not be part of the BSER for existing EGUs 

because it would be more expensive than the measures determined 

to be part of the BSER, particularly if applied broadly to the 

overall source category. At the same time, we note that retrofit 

of CCS technology may be a viable option at some individual 

facilities, particularly where the captured CO2 can be used for 

enhanced oil recovery (EOR). For example, construction of one 

CCS retrofit application with EOR has already been completed at 

a unit at the Boundary Dam plant in Canada, and construction of 

another CCS retrofit application with EOR is underway at the 

W.A. Parish plant in Texas. We expect the costs of CCS to 

decline as implementation experience increases. CO2 emission rate 

reductions achieved through retrofit of CCS technology would be 

available to help affected EGUs achieve emission limits 

consistent with the BSER. State plan considerations related to 

CCS are discussed in section VIII.I.2.a.

 (3) Fuel switching to natural gas at affected EGUs. 

 In the proposal we discussed the opportunity to reduce CO2

emissions at an individual affected EGU by switching fuels at 
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the EGU, particularly by switching from coal to natural gas. 

Most coal-fired EGUs could be modified to burn natural gas 

instead, and the potential CO2 emission reductions from this 

measure are large – approximately 40 percent in the case of 

conversion from 100 percent coal to 100 percent natural gas, and 

proportionately smaller for partial co-firing of coal with 

natural gas. The primary reason for not considering this measure 

part of the BSER, both at proposal and in this final rule, is 

that it is more expensive than other BSER measures. In 

particular, combusting natural gas in a steam EGU is less 

efficient and generally more costly than combusting natural gas 

in an NGCC unit. For the category as a whole, CO2 emissions can 

be achieved far more cheaply by combusting additional natural 

gas in currently underutilized NGCC capacity and reducing 

generation from coal-fired steam EGUs (building block 2) than by 

combusting natural gas instead of coal in steam EGUs. 

 Some owner/operators are already converting some affected 

EGUs from coal to natural gas, and it is apparent that the 

measure can be attractive compared to alternatives in certain 

circumstances, such as when a unit must meet tighter unitspecific limits on emissions of non-GHG pollutants, the options 

for meeting those emission limits are costly, and retirement of 

the unit would necessitate transmission upgrades that are costly 
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or cannot be completed quickly. CO2 emission reductions achieved 

in these situations are available to help achieve emission 

limits consistent with the BSER. 

 (4) Fuel switching to biomass at affected EGUs. 

 Some affected EGUs may seek to co-fire qualifying biomass 

with fossil fuels. The EPA recognizes that the use of some 

biomass-derived fuels can play an important role in controlling 

increases of CO2 levels in the atmosphere. As with the other nonBSER measures discussed in this section, the EPA expects that 

use of biomass may be economically attractive for certain 

individual sources even though on a broader scale it would 

likely be more expensive or less achievable than the measures 

determined to be part of the BSER. Section VIII.I.2.c. describes 

the process and considerations for states proposing to use 

different kinds of biomass in state plans. 

 (5) Waste heat-to-energy conversion at affected EGUs. 

 Certain affected EGUs in urban areas or located near 

industrial or commercial facilities with needs for thermal 

energy may be able add new equipment to capture some of the 

waste heat from their electricity generation processes and use 

it to create useful thermal output, thereby engaging in combined 

heat and power (CHP) production. While the set of affected EGUs 

in locations making this measure feasible may be limited, where 

Deleted: control or reduce their CO2 emission 

contributions to the atmosphere by co-firing 

Deleted: or reducing the contribution 

Deleted: emissions to 

Deleted: G.1.a (2)

Deleted: that states must make when 
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feasible the potential CO2 emission rate improvements can be 

substantial: depending on the process used, the efficiency with 

which fuel is converted to useful energy can be increased by 25 

percent or more. The final rule allows an owner/operator 

applying CHP technology to an affected EGU to account for the 

increased efficiency by counting the useful thermal output as 

additional MWh of generation, thereby lowering the unit’s 

computed emission rate and assisting with achievement of an 

emission rate-based standard of performance. (The EPA notes that 

unless the unit also reduced its fuel usage, the addition of the 

capability to capture waste heat and produce useful thermal 

output would not reduce the unit’s mass emissions and therefore 

would not directly help the unit achieve a mass-based standard 

of performance.446)

b. Non-BSER measures that reduce CO2 emissions by reducing fossil 

fuel-fired generation. A second group of non-BSER measures has 

the potential to reduce CO2 emissions from affected EGUs by 

reducing the amount of generation from those EGUs. As discussed 

above, under a section 111(d) plan with mass-based standards of 

performance, no special action is required to enable measures of 

 

446 However, the EPA notes that a state could establish a 

mechanism for encouraging affected EGUs to apply CHP technology 

under a mass-based plan, for example, through awards of emission 

allowances to CHP projects. 
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this nature to help the source category as a whole and 

individual affected EGUs achieve their emission limits, because 

the CO2-reducing effects are captured in monitored stack 

emissions. However, under a section 111(d) plan with rate-based 

standards of performance, affected EGUs would need to acquire 

ERCs based on the non-BSER activities that could be averaged 

into their emission rate computations for purposes of 

determining compliance with their standards of performance.

 (1) Demand-side energy efficiency. 

 One of the major approaches available for achieving CO2

emission reductions from the utility power sector is demand-side 

energy efficiency. In the June 2014 proposal, the EPA identified 

demand-side energy efficiency as one of the four proposed 

building blocks for the BSER. We continue to believe that 

significant emission reductions can be achieved by the source 

category through use of such measures at reasonable costs. In 

fact, we believe that the potential emission reductions from 

demand-side energy efficiency rival those from building blocks 2 

and 3 in magnitude, and that demand-side energy efficiency is 

likely to represent an important component of state plans, 

particularly in instances where a state prefers to develop a 

plan reflecting the state measures approach discussed in section 

VIII below. We also expect that many sources would be interested 

Deleted: some form of crediting such as the ERC 

mechanism described earlier is necessary in 

order to enable measures of this nature to 

help the source category as a whole and 

individual affected EGUs achieve the emission 

limits. 

Deleted: will 
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in including demand-side energy efficiency in their compliance 

strategies to the extent permitted, and we received comment that 

it should be permitted. 

 For the reasons discussed in section V.A.3.d. above, the 

EPA has determined not to include demand-side energy in the BSER 

in this final rule. However, the final rule authorizes 

generation avoided through investments in demand-side energy 

efficiency to serve as the basis for issuance of ERCs when 

appropriate conditions are met. In section VIII.K. below, the 

EPA sets out the minimum criteria that must be satisfied for 

generation and issuance of a valid ERC based upon implementation 

of new demand-side EE programs. Those criteria generally concern 

ensuring that the physical basis for the ERC -– in this case, 

generation avoided through implementation of demand-side EE 

measures –- is adequately evaluated, measured, and verified and 

that there is an adequate administrative process for tracking 

credits. 

Through their authority over legal requirements such as 

building codes, states have the ability to drive certain types 

of demand-side energy efficiency measures that are beyond the 

reach of private-sector entities. The EPA recognizes that, by 

definition, this type of measure is beyond the ability of 

affected EGUs to invest in either directly or through bilateral 

Deleted: e.

Deleted: in defined circumstances. 

Deleted: assuring 

Deleted: monitored 

Deleted: to avoid double-counting and to 

facilitate enforceability of emission limits

Deleted: The particular considerations related 

to evaluation, measurement, and verification 

of demand-side EE programs are also discussed 

in section VIII.
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arrangements. However, the final rule also authorizes generation 

avoided through such state policies to serve as the basis for 

issuance of ERCs that in turn can be used by affected EGUs. The 

section 111(d) plan would need to include appropriate provisions 

for evaluating, measuring, and verifying the avoided MWh 

associated with the state policies, consistent with the criteria 

discussed in section VIII.K. below. 

 (2) New or up-rated nuclear generating capacity. 

 In the June 2014 proposal, the EPA included generation from 

the five nuclear units currently under construction as part of 

the proposed BSER. As discussed above in section V.A.3.c., upon 

consideration of comments, we have determined that generation 

from these units should not be part of the BSER. However, we 

continue to observe that the zero-emitting generation from these 

units would be expected to replace generation from affected EGUs 

and thereby reduce CO2 emissions, and the continued commitment of 

the owner/operators to completion of the units is essential in 

order to realize that result. Accordingly, a section 111(d) plan 

may rely on ERCs issued on the basis of generation from these 

units and other new nuclear units. For the same reason, a plan 

may rely on ERCs issued on the basis of generation from up-rates 

to the capacity of existing nuclear units. Requirements for 
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state plan provisions intended to serve this purpose are 

discussed in section VIII.K. 

 (3) Zero-emitting RE generating technologies not reflected 

in the BSER. 

 The range of available zero-emitting renewable energy 

generating technologies is broader than the range of RE 

technologies determined to be suitable for use in quantification 

of building block 3 as an element of the BSER. Examples of 

additional zero-emitting RE technologies not included in the 

BSER that could be used to achieve emission limits consistent 

with the BSER include offshore wind, distributed solar, and fuel 

cells. These technologies were not included in the range of RE 

technologies quantified for the BSER because they are generally 

more expensive than the measures that were included and the 

other measures in the BSER. However, these technologies are 

equally capable of replacing generation from affected EGUs and 

thereby reducing CO2 emissions. Further, as with any technology, 

there are likely to be certain circumstances where the costs of 

these technologies are more attractive relative to alternatives, 

making the technologies likely to be deployed to some extent. 

Indeed, distributed solar is already being widely deployed in 

much of the United States and offshore wind, while still unusual 

in this country, has been extensively deployed in some other 

Deleted: The plan provisions to accommodate 

ERCs for generation from new and uprated 

nuclear capacity would be similar to the plan 

provisions necessary to accommodate ERCs 

issued on the basis of generation from new RE 

generating capacity (i.e., building block 3), 

which is also zero-emitting. These provisions 

are discussed in section VIII below.
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parts of the world. We expect innovation in RE generating 

technologies to continue, making such technologies even more 

attractive over time. A section 111(d) plan may rely on ERCs 

issued on the basis of generation from new and uprated 

installations of these technologies. The necessary state plan 

provisions are discussed in section VIII.K. 

 (4) Non-zero-emitting RE generating technologies. 

 Generation from new or expanded facilities that combust 

qualifying biomass or biogenic portions of municipal solid waste 

(MSW) to produce electricity can also replace generation from 

affected EGUs and thereby control CO2 levels in the atmosphere.447

While the EPA believes it is reasonable to consider generation 

from these fuels and technologies to be forms of RE generation, 

the fact that they can produce stack emissions containing CO2

means that a section 111(d) plan seeking to permit use of such 

generation to serve as the basis for issuance of ERCs must 

include appropriate consideration of feedstock characteristics 

and climate benefits. Specifically, the use of some kinds of 

biomass has the potential to offer a wide range of environmental 

 

447 The EPA and many states have recognized the importance of 

integrated waste materials management strategies that emphasize 

a hierarchy of waste prevention and all other productive uses of 

waste materials to reduce the volume of disposed waste materials 

(see section VIII for more discussion of waste to energy 

strategies). 

Deleted: to accommodate ERCs issued on the 

basis of generation from these RE generating 

technologies again would be similar to the 

plan provisions necessary to accommodate ERCs 

issued on the basis of generation from other 

RE generating technologies (building block 3).

Deleted: or reduce 

Deleted: emission contributions to 

Deleted: the technologies 

Deleted: policy 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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benefits, including carbon benefits. However these benefits can 

only be realized if biomass feedstocks are sourced responsibly 

and attributes of the carbon cycle related to the biomass 

feedstock are taken into account. Section VIII.I.2.c. describes 

the process and considerations for states proposing to use 

biomass in state plans. Section VIII.K. describes additional 

provisions related to ERCs.

 (5) Waste heat-to-electricity conversion at non-affected 

facilities. 

 Industrial facilities that install new equipment to capture 

waste heat from an existing combustion process and then use the 

waste heat to generate electricity –- a form of combined heat 

and power (CHP) production –- can produce generation that 

replaces generation from affected EGUs and thereby reduces CO2

emissions. A section 111(d) plan may rely on ERCs issued on the 

basis of generation of this nature provided that the facility 

does not generate and sell sufficient electricity to qualify as 

a new EGU for purposes of section 111(b) and is not covered 

under section 111(d) for another source category. More 

information is provided in section VIII.K.

 (6) Reduction in transmission and distribution line losses. 

 Reductions of electricity line losses incurred from the 

transmission and distribution system between the points of 

Deleted: Again, as discussed in section VIII 

below, the EPA expects to recognize the 

biogenic CO2 emissions and climate policy 

benefits of waste-derived feedstocks and 

certain forest- and agriculture-derived 

industrial byproduct feedstocks when 

considering state plans. The EPA also expects 

that states’ reliance specifically on 

sustainably-derived agriculture- and forestderived feedstocks may also be an approvable 

element of their state plans. The EPA and many 

states have recognized the importance of 

integrated waste materials management 

strategies that emphasize a hierarchy of waste 

prevention and all other productive uses of 

waste materials to reduce the volume of 

disposed waste materials. Because it is likely 

that more than one MWh of incremental 

generation from these technologies would be 

required as the basis qualifying for the 

issuance of an ERC worth a full MWh of zeroemitting generation, the minimum requirements 

to accommodate ERCs issued on the basis of 

generation from these technologies would be 

similar to the plan provisions necessary to 

accommodate ERCs issued on the basis of 

incremental generation from existing NGCC 

units (building block 2), supplemented by 

appropriate provisions to address special 

characteristics of the feedstocks.

Deleted: If no supplemental fuel is used to 

produce the electricity, this generation could 

be considered zero-emitting because the waste 

heat would have been produced by the 

industrial process anyway. To the extent that 

the section 111(d) plan includes appropriate 

provisions for establishing that the heat 

input truly is waste heat, each MWh of 

incremental generation from this form of CHP 

could serve as the basis for issuance of an 

ERC worth a full MWh of zero-emitting 

generation similar to an ERC issued on the 

basis of building block 3. In order to permit 

ERCs issued on the basis of generation from 

facilities where the waste heat input is 

supplemented by fossil fuel input, the plan 

would need to include appropriate provisions 

for establishing the number of incremental MWh 

that would be generated in order to serve as 

the basis for issuance of each ERC worth one 

full MWh of zero-emitting generation, similar 

to the plan provisions required to support an 

ERC issued on the basis of building block 2.
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generation and the points of consumption by end-users allow the 

same overall demand for electricity services to be met with a 

smaller overall quantity of electricity generation. Such 

reductions in generation quantities would tend to reduce 

generation by affected EGUs, thereby reducing CO2 emissions. The 

opportunity for improvement is large because, on average, line 

losses account for approximately seven percent of all 

electricity generation. The EPA recognizes that, in general, 

only the owner/operators of the transmission and distribution 

facilities have the ability to undertake line loss reduction 

investments, and that merchant generators may have little 

opportunity to engage a contractor to pursue such opportunities 

on a bilateral basis. Nevertheless, for entities that do have 

the opportunity to make such investments, generation avoided 

through investment that reduces transmission and distribution 

line losses may serve as the basis for issuance of ERCs that in 

turn can be used by affected EGUs. Further information is 

provided in section VIII.K.

7. Severability. 

 The EPA intends that the components of the BSER summarized 

above be severable. It is reasonable to consider the building 

blocks severable because the building blocks do not depend on 

one another. Building blocks 2 and 3 are feasible and 

Deleted: This avoided generation is analogous 

to the generation avoided through demand-side 

energy efficiency described above, and each 

MWh of avoided generation could serve as the 

basis for creation of an ERC worth one full 

zero-emitting MWh of generation. The section 

111(d) would need to include appropriate 

provisions for quantifying and verifying the 

avoided MWh associated with the transmission 

and distribution investments.

Deleted: Each building block is a
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demonstrated means of reducing CO2 emissions from the utility 

power sector that can be implemented independently of the other 

building blocks. If implemented in combination with at least one 

of the other building blocks, building block 1 is also a 

feasible and demonstrated means of reducing CO2 emission from the 

utility power sector.448 As discussed in sections V.C. through 

V.E. below, we have determined that each building block is 

independently of reasonable cost whether or not the other 

building blocks are applied, and that alternative combinations 

of the building blocks are likewise of reasonable cost, and we 

have determined reasonable schedules and stringencies for 

implementation of each building block independently, based on 

factors that generally do not vary depending on the 

implementation of other building blocks. 

 Further, building block 2, building block 3, and all 

combinations of the building blocks (implemented on the 

schedules and at the stringencies determined to be reasonable in 

this rule) would achieve meaningful degrees of emission 

 

448 The heat rate improvement measures included in building block 

1 are capable of being implemented independently of the measures 

in the other building blocks but, as discussed earlier, unless 

at least one other building block is also implemented, a 

“rebound effect” arising from improved competitiveness and 

increased generation at the EGUs implementing heat rate 

improvements could weaken or potentially even eliminate the 

ability of building block 1 to achieve CO2 emission reductions.
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reductions,449 although less than the combination of all three 

building blocks. No combination of the building blocks would 

lead to adverse non-air environmental or energy impacts or 

impose a risk to the reliability of electricity supplies. 

 In the event that a court should strike down building block 

2 or 3, but not both, the standards and state goals can be 

recomputed on the basis of the remaining building blocks. All of 

the data and procedures necessary to determine recomputed state 

goals using any combination of the building blocks are set forth 

in the CO2 Emission Performance Rate and Goal Computation TSD for 

the CPP Final Rule available in the docket. 

B. Legal Discussion of Certain Aspects of the BSER 

This section includes a legal analysis of various aspects 

of EPA’s determination of the BSER, including responses to some 

of the major adverse comments. These aspects include (1) the 

EPA’s authority to determine the BSER; (2) the approach to 

subcategorization; (3) the EPA’s basis for determining that 

building blocks 2 and 3 qualify as part of the BSER under CAA 

sections 111(d)(1) and (a)(1), notwithstanding commenters’ 

arguments that these building blocks cannot be considered part 

of the BSER because they are not based on measures integrated 

 

449 This conclusion would not extend to a BSER comprising solely 

building block 1 because of the possibility of rebound effects 

discussed earlier. 

Deleted: any individual 

Deleted: used to compute the emissions 

standards and state goals set forth in this 

rule, 
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into the design or operation of the affected source’s own 

production processes or methods or because they are dependent on 

actions by entities other than the affected source; (4) the 

relationship between an affected EGU’s implementation of 

building blocks 2 and 3 and CO2 emissions reductions; (5) how 

reduced generation relates to the BSER; (6) reasons why, 

contrary to assertions by commenters, this rule is within the 

EPA’s statutory authority, is not inconsistent with the Federal 

Power Act or state laws governing public utility commissions, 

and does not result in what the U.S. Supreme Court described as 

“an enormous and transformative expansion in [the] EPA’s 

regulatory authority”;450 and (7) reasons that, contrary to 

assertions by commenters, the stringency of the BSER for this 

rule for CO2 emissions from existing affected EGUs is not 

inconsistent with the stringency of the BSER for the rules the 

EPA is promulgating at the same time for CO2 emissions from new 

or modified affected EGUs. 

1. The EPA’s authority to determine the BSER. 

In this section, we explain why the EPA, and not the 

states, has the authority to determine the BSER and, therefore, 

the level of emission limitation required from the existing 

 

450 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014). 

Deleted: the EPA’s basis for including 

Deleted: as a component of 
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sources in the source category in section 111(d) rulemaking and 

the associated state plans. 

CAA section 111(d)(1) requires the EPA to establish a 

section 110-like procedure under which each state submits a plan 

that “establishes standards of performance for any existing 

source of air pollutant” and “provides for the implementation 

and enforcement of such standards of performance.” As CAA 

section 111(d) was originally adopted in the 1970 CAA 

Amendments, however, state plans were required to establish 

“emission standards” –- an undefined term -- rather than 

“standards of performance,” a term that was limited to CAA 

section 111(b).451 The 1970 provision was in effect when the EPA 

issued the 1975 implementing regulations for CAA section 

111(d),452 which remain in effect to this day. 

These regulations establish a cooperative framework that is 

similar to that under CAA section 110. First, the EPA develops 

“emission guidelines” for source categories, which are defined 

as a final guideline document reflecting “the degree of emission 

reduction achievable through the application of the best system 

 

451 See 1970 CAA Amendments, § 4, 84 Stat. at 1683-84. 

Subsequently, in 1977, Congress replaced the term “emission 

standard” with “standards of performance.” See 1977 CAA 

Amendments, § 109, 91 Stat. at 699. 

452 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 
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of emission reduction ... which the Administrator has determined 

has been adequately demonstrated.” Then, the states submit 

implementation plans to regulate any existing sources.453 

The preamble to these regulations carefully considered the 

allocation of responsibilities as between the EPA and the states 

for purposes of CAA section 111(d), and concluded that the EPA 

is responsible for determining the level of emission limitation 

from the source category, while the states have the 

responsibility of assigning emission requirements to their 

sources that assured their achievement of that level of emission 

limitation.454 The EPA explained “that some substantive criterion 

was intended to govern not only the Administrator’s promulgation 

of standards but also [her] review of state plans.”455 The EPA 

added, “it would make no sense to interpret [CAA] section 111(d) 

as requiring the Administrator to base approval or disapproval 

of state plans solely on procedural criteria. Under that 

interpretation, states could set extremely lenient standards -- 

 

453 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 

454 As we made clear in the proposed rulemaking, we are not reopening these regulations (on the issue of the authority to 

determine the BSER or any other issue, unless specifically 

indicated otherwise) in this rulemaking, and our discussion of 

these regulations in responding to comments does not constitute 

a re-opening. 

455 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53342 (Nov. 17, 1975). 
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even standards permitting greatly increased emissions -- so long 

as [the] EPA’s procedural requirements were met.”456 The EPA 

concluded that “emission guidelines, each of which will be 

subjected to public comment before final adoption, will serve 

[the] function” of providing substantive criteria “in advance to 

the states, to industry, and to the general public” to aid 

states in “developing and enforcing control plans under [CAA] 

section 111(d).”457 Thus, the implementing regulations make clear 

that the EPA is responsible for determining the level of 

emission limitation that the state plans must achieve. 

In 1977, Congress revised CAA section 111(d) to require 

that the states adopt “standards of performance,” as defined 

under CAA section 111(a)(1). As noted above, a standard of 

performance is defined as “a standard for emissions of air 

pollutants which reflects the degree of emission limitation 

achievable through the application of the best system of 

emission reduction which ... the Administrator determines has 

been adequately demonstrated.” (Emphasis added.) By its terms, 

this provision provides that the EPA has the responsibility of 

determining whether the “best system of emission reduction” is 

 

456 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 

457 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 
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“adequately demonstrated.” By giving the EPA this 

responsibility, this provision is clear that Congress assigned 

the role of determining the “best system of emission reduction” 

to the EPA. Even if the provision may be considered to be silent 

or ambiguous on that question, the EPA reasonably interprets the 

provision to assign the responsibility of identifying the “best 

system of emission reduction” to the Administrator for the same 

reasons discussed in the preamble to the 1975 implementing 

regulations. 

In addition, in the legislative history of the 1977 CAA 

Amendments, when Congress replaced the term “emission standards” 

under CAA section 111(d)(1) with the term “standards of 

performance,” Congress endorsed the overall approach of the 

implementing regulations, which lends further credence to the 

proposition that the EPA has the responsibility for determining 

the “best system of emission reduction” and the amount of 

emission limitation from the existing sources. Specifically, in 

the House report that introduced the substantive changes to CAA 

section 111, the Committee explained that “[t]he Administrator 

would establish guidelines as to what the best system for each 

category of existing sources is.”458 States, on the other hand, 

 

458 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 

Deleted: While the provision does not 

explicitly assign authority for determining 

the “best system of emission reduction,” the 

logical implication is that Congress assigned 

that role to the Administrator b

Deleted: requiring the Administrator to 

determine whether the “best system of emission 

reduction” is also “adequately demonstrated

Deleted: .”

Deleted: under Chevron step 2
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“would be responsible for determining the applicability of such 

guidelines to any particular source or sources.”459 The use of 

the term “guidelines,” which does not appear in CAA section 

111(d), indicates Congress was aware of and approved of the 

approach taken in the EPA’s implementing regulations for 

establishing guidelines, which determine the BSER. At a minimum, 

if Congress disapproved of the EPA’s implementing regulations, 

we would not expect the House report to adopt the EPA’s 

terminology to clarify CAA section 111(d). 

In addition, Congress expressly referred to our 

“guidelines” in CAA section 129, added as part of the 1990 CAA 

Amendments. Congress added CAA section 129 to address solid 

waste combustion and specifically directed the Administrator to 

establish “guidelines (under section 111(d) and this section) 

and other requirements applicable to existing units.”460 This 

reference also indicates that Congress was aware of and approved 

the EPA’s regulations under section 111(d). 

The EPA has followed the same approach described in the 

implementation regulations in all its rulemakings under section 

111(d). Thus, in all cases, the EPA has identified the type of 

emission controls for the source category and the level of 

 

459 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 460 CAA section 129(a)(1)(A) (emphasis added). 
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emission limitation based on those controls.461 The EPA’s 

longstanding and consistent interpretation of CAA section 111(d) 

is also “evidence showing that the statute is in fact not 

 

461 See Part 60, Subpart Ca (large municipal waste combustors), 

56 Fed. Reg. 5514 (Feb. 11, 1991), 40 C.F.R. § 60.30a-.39a 

(subsequently withdrawn and superseded by Subpart Cb, see 60 

Fed. Reg. 65,387 (Dec. 19, 1995)); Subpart Cb (large municipal 

waste combustors constructed on or before September 20, 1994), 

60 Fed. Reg. 65,387 (Dec. 19, 1995), 40 C.F.R. § 60.30b-.39b (as 

amended in 1997, 2001, and 2006); Subpart Cc (municipal solid 

waste landfills), 61 Fed. Reg. 9905 (Mar. 12, 1996), 40 C.F.R. § 

60.30c-.36c (as amended in 1998, 1999, and 2000); Subpart Cd 

(sulfuric acid production units), 60 Fed. Reg. 65,387 (Dec. 19, 

1995), 40 C.F.R. § 60.30d-.32d; Subpart Ce 

(hospital/medical/infectious waste incinerators), 62 Fed. Reg. 

48,348 (Sept. 15, 1997), 40 C.F.R. § 60.30e-.39e (as amended in 

2009 and 2011); Subpart BBBB (small municipal waste combustion 

units constructed on or before August 30, 1999), 65 Fed. Reg. 

76,738 (Dec. 6, 2000), 40 C.F.R. § 60.1500-.1940; Subpart DDDD 

(commercial and industrial solid waste incineration units that 

commenced construction on or before November 30, 1999), 65 Fed. 

Reg. 75,338 (Dec. 1, 2000), 40 C.F.R. § 60.2500-.2875 (as 

amended in 2005, 2011, and 2013); Subpart FFFF (other solid 

waste incineration units that commenced construction on or 

before December 9, 2004), 70 Fed. Reg. 74,870 (Dec. 16, 2005), 

40 C.F.R. § 60.2980-.3078 (as amended in 2006); Subpart HHHH 

(coal-electric utility steam generating units), 70 Fed. Reg. 

28,606 (May 18, 2005) (subsequently vacated by the D.C. Circuit 

in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008)); Subpart 

MMMM (existing sewage sludge incineration units), 76 Fed. Reg. 

15,372 (Mar. 21, 2011), 40 C.F.R. § 60.5000-.5250; “Phosphate 

Fertilizer Plants, Final Guideline Document Availability,” 42 

Fed. Reg. 12,022 (Mar. 1, 1977) (not codified); “Kraft Pulp 

Mills; Final Guideline Document; Availability,” 44 Fed. Reg. 

29,828 (May 22, 1979) (not codified); and “Primary Aluminum 

Plants; Availability of Final Guideline Document,” 45 Fed. Reg. 

26,294 (Apr. 17, 1980) (not codified). 
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ambiguous,” and that the EPA’s interpretation should be 

adopted.462

Lastly, this interpretation is consistent with the Supreme 

Court’s reading of CAA section 111(d) in American Electric Power 

Co. There, the Court explained that “EPA issues emissions 

guidelines, see 40 C.F.R. § 60.22, .23 (2009); in compliance 

with those guidelines and subject to federal oversight, the 

States then issue performance standards for stationary sources 

within their jurisdiction, § 7411(d)(1).”463

As noted in the response to comment document, some 

commenters agreed with our interpretation, just discussed, while 

others argued that the states should be given the authority to 

determine the best system of emission reduction and, therefore, 

the level of emission limitation from their sources. For the 

reasons just discussed, this latter interpretation is an 

incorrect interpretation of CAA section 111(d)(1) and (a)(1), 

and we are not compelled to abandon our longstanding practice. 

2. Approach to subcategorization. 

 As noted above, in this rule, we are treating all fossil 

fuel-fired EGUs as a single category, and, in the emission 

 

462 Scalia, Antonin, Judicial Deference to Administrative 

Interpretations of Law, 1989 Duke L.J. 511, 518; see Riverkeeper 

v. Entergy, 556 U.S. 208, 235 (2009). 463 Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38 

(2011).

Deleted: .

Deleted: I

Deleted: Commenters 

Deleted: See Riverkeeper v. Entergy, [cite]; 
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guidelines that we are promulgating with this rule, we are 

treating steam EGUs and combustion turbines as separate 

subcategories. We are determining the BSER for steam EGUs and 

the BSER for combustion turbines, and applying the BSER to each 

subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. 

 This approach is fully consistent with the provisions of 

section 111(d), which simply require the EPA to determine the 

BSER, do not prescribe the method for doing so, and are silent 

as to subcategorization. This approach is also fully consistent 

with other provisions in CAA section 111, which require the EPA 

first to list source categories that may reasonably be expected 

to endanger public health or welfare464 and then to regulate new 

sources within each such source category,465 and which grant the 

EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.466 

For this rule, our approach of subcategorizing between 

steam EGUs and combustion turbines is reasonable because 

building blocks 1 and 2 apply only to steam EGUs. No further 

subcategorization is appropriate because each affected EGU can 

 

464 CAA section 111(b)(1)(A). 465 CAA section 111(b)(1)(B). 466 CAA section 111(b)(2). 

Deleted: Subcategorization may be appropriate 

when certain types of sources could not 

achieve the same emission limit as other types 

of sources

Moved (insertion) [22]

Deleted: O

Deleted: , but here, 
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achieve the performance rate by implementing the BSER. 

Specifically, as noted, each affected EGU may take a range of 

actions including investment in the building blocks, replacing 

or reducing generation, and emissions trading, as enabled or 

facilitated by the implementation programs the states adopt. 

Further, in the case of a rate-based state plan, several other 

compliance options not included in the BSER for this rule are 

also available to all affected sources, including investment in 

demand-side energy efficiency measures. Such compliance options 

help affected sources achieve compliance under a mass-based 

plan, even if indirectly. Our approach to subcategorization in 

this rule is consistent with our approach to subcategorization 

in previous section 111 rules for this industry, in which we 

determined whether or not to subcategorize on the basis of the 

ability of affected EGUs with different characteristics (e.g., 

size or type of fuel used) to implement the BSER and achieve the 

emission limits).467

 

467 Compare “Revision of Standards of Performance for Nitrogen 

Oxide Emissions From New Fossil-Fuel Fired Steam Generating 

Units; Revisions to Reporting Requirements for Standards of 

Performance for New Fossil-Fuel Fired Steam Generating Units: 

Final Rule,” 63 FR 49442 (Sept. 16, 1998) and “Proposed 

Revision of Standards of Performance for Nitrogen Oxide 

Emissions From New Fossil-Fuel Fired Steam Generating Units: 

Proposed Revisions,” 62 FR 36948, 36943 (July 9, 1997) 

(establishing a single NOx emission limit for new fossil-fuel 

fired steam generating units, and not subcategorizing, because 
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 In addition, there are numerous possible criteria to use in 

subcategorizing, including, among others, subcategorizing on the 

basis of age; size; steam conditions (i.e., subcritical or 

supercritical); type of fuel, including type of coal (i.e., 

lignite, bituminous, and sub-bituminous), and coal refuse; and 

method of combustion (i.e., fluidized bed combustion, pulverized 

coal combustion, and gasification). In addition, there are 

different possible combinations of those categories. At least 

 

the affected units could implement the BSER of SCR and achieve 

the promulgated emission limits) with “National Emission 

Standards for Hazardous Air Pollutants From Coal and Oil-Fired 

Electric Utility Steam Generating Units and Standards of 

Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units: Final Rule,” 77 FR 9304 

(Feb. 16, 2012) (MATS rule) and “National Emission Standards 

for Hazardous Air Pollutants From Coal and Oil-Fired Electric 

Utility Steam Generating Units and Standards of 

Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units: Proposed Rule,” 76 FR 

24976, 25036-37 (May 3, 2011) (subcategorizing coal fired units 

designed to burn coal with greater than or equal to 8,300 Btu/lb 

(for Hg emissions only), coal-fired units designed to burn coal 

with less than 8,300 Btu/lb (for Hg emissions only), IGCC units, 

liquid oil units, and solid oil-derived units; evaluating 

“subcategorization of lignite coal vs. other coal ranks; 

subcategorization of Fort Union lignite coal vs. Gulf Coast 

lignite coal vs. other coal ranks; subcategorization by EGU size 

(i.e., MWe); subcategorization of base load vs. peaking units 

(e.g., low capacity utilization units); subcategorization of 

wall-fired vs. T fired units; and subcategorization of small, 

non-profit-owned units vs. other units;” but deciding not to 

adopt those latter subcategorizations). 

Moved up [22]: Our approach of subcategorizing 

between steam EGUs and combustion turbines is 

reasonable because building blocks 1 and 2 

apply only to steam EGUs.
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some of those criteria do not have logical cut-points. 

Furthermore, we have not been presented with, nor can we 

discern, a method of subcategorizing based on these or other 

criteria that is appropriate in light of the BSER for the 

affected EGUs and their ability to meet the emission limits. 

Moreover, our approach of not further subcategorizing as between 

different types of steam EGUs or combustion turbines reflects 

the reasonable policy that affected EGUs with higher emission 

rates should reduce their emissions by a greater percentage than 

affected EGUs with lower emission rates, and can do so by 

implementing the BSER we are identifying. 

 In addition, a section 111(d) rule presents less of a need 

to subcategorize because the states retain great flexibility in 

assigning standards of performance to their affected EGUs. Thus, 

a state can, if it wishes, impose different emission reduction 

obligations on its sources, as long as the overall level of 

emission limitation is at least as stringent as the emission 

guidelines, as discussed below. This means that if a state is 

concerned that its different sources have different capabilities 

for compliance, it can adjust the standards of performance in 

imposes on its sources accordingly. 

3. Building blocks 2 and 3 as a “system of emission reduction”

Deleted: Of course

Deleted: , a

Deleted: s

Deleted: its 

Deleted: and
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a. Overview. As we explain above, the emission performance rates 

that we include in this rule’s emission guidelines are 

achievable by the affected EGUs through the application of the 

BSER, which includes the three building blocks. Commenters 

object that building blocks 2 (generation shift) and 3 

(renewable energy) cannot, as a legal matter, be considered part 

of the BSER under CAA section 111(d)(1) and (a)(1). These 

commenters explain that in their view, under CAA section 111, 

the emission performance rates must be based on, and therefore 

the BSER must be limited to, methods for emissions control that 

the owner/operator of the affected source can integrate into the 

design or operation of the source itself, and cannot be based on 

actions taken beyond the source or actions involving third-party 

entities.468 For these reasons, these commenters argue that the 

 

468 See, e.g., comments by UARG at 6-7 (“Standards promulgated 

under section 111 must be source-based and reflect measures that 

the source’s owner can integrate into the design or operation of 

the source itself. A standard cannot be based on actions taken 

beyond the source itself that somehow reduce the source’s 

utilization.”); comments by UARG at 31 (the building blocks 

other than building block 1 take a “‘beyond-the-source’ 

approach” and “impermissibly rely on measures that go beyond the 

boundaries of individual affected EGUs and that are not within 

the control of individual EGU owners and operators”); comments 

by UARG at 33 (the “system” of emission reduction “can refer 

only to reductions resulting from measures that are incorporated 

into the source itself;” section 111 is “designed to improve the 

emissions performance of new and existing sources in specific 

categories based on the application of achievable measures 

implemented in the design or production process of the source at 
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phrase “system of emission reduction” cannot be interpreted to 

include building blocks 2 and 3. 

We disagree with these comments, and note that other 

commenters were supportive of our determination to include 

building blocks 2 and 3. Under CAA section 111(d)(1) and (a)(1), 

the EPA’s emission guidelines must establish achievable emission 

limits based on the “best system of emission reduction ... 

adequately demonstrated.” While some commenters assert that 

emission guidelines must be limited in the manner summarized 

above, the phrase “system of emission reduction,” by its terms 

and when read in context, contains no such limits. To the 

contrary, its plain meaning is deliberately broad and is 

capacious enough to include actions taken by the owner/operator 

of a stationary source designed to reduce emissions from that 

affected source, including actions that may occur off-site and 

actions that a third party takes pursuant to a commercial 

relationship with the owner/operator, so long as those actions 

enable the affected source to achieve its emission limitation. 

Such actions include the measures in building blocks 2 and 3, 

 

reasonable cost.”); comments by American Chemistry Council et 

al. (“Associations”) at 60-61 (EPA’s proposed BSER analysis is 

unlawful because it “looks beyond the fence line of the fossil 

fuel-fired EGUs that are the subject of this rulemaking;” “the 

standard of performance must ... be limited to the types of 

actions that can be implemented directly by an existing source 

within [the appropriate] class or category.”). 

Deleted: , under Chevron,
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which, when implemented by an affected source, enable the source 

to achieve their emission limits because of the unique 

characteristics of the utility power sector. For purposes of 

this rule, we consider a “system of emission reduction” -- as 

defined under CAA section 111(a)(1) and applied under CAA 

section 111(d)(1) -– to encompass a broad range of pollutionreduction actions, which includes the measures in building 

blocks 2 and 3. 

Our interpretation that a “system of emission reduction” is 

broad enough to include the measures in building blocks 2 and 3 

is supported by the following: our interpretation of CAA section 

111(a)(1) is consistent with its plain meaning and statutory 

context; the phrase “system of emission reduction” accommodates 

the very design of CAA section 111(d)(1), which covers a range 

of source categories and air pollutants;470 the legislative 

history of CAA section 111(d)(1) and (a)(1), which indicates 

Congress’s intent to give the EPA broad discretion in 

determining the basis for CAA section 111 control requirements, 

particularly for existing sources, and Congress’s intent to 

authorize the EPA to consider measures that could be carried out 

 

470 Because it is designed to apply to a range of air pollutants 

not regulated under other provisions, CAA section 111(d) may be 

described as a “catch-all” or “gap-filler.” As such, a “system 

of emission reduction” as applied under CAA section 111(d) 

should be interpreted flexibly to accommodate this role. 

Deleted: 469
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by parties other than the affected sources; and through 

comparisons to CAA provisions that give the EPA similar 

authority to consider such measures and through comparisons to 

CAA provisions that would preclude the EPA from considering such 

measures. 

To the extent the phrase “system of emission reduction” is 

ambiguous, the EPA's interpretation is reasonable for the 

reasons stated above, as well as the following reasons: (i) 

Building blocks 2 and 3 fit well within the structure and 

economics of the utility power sector. (ii) Fossil fuel-fired 

EGUs are already implementing the measures in these building 

blocks for various reasons, including for purposes of reducing 

CO2 emissions. (iii) Interpreting the phrase “system of emission 

reduction” to incorporate building blocks 2 and 3 is consistent 

with (a) other provisions in the CAA, including the acid rain 

provisions in Title IV and the SIP provisions in CAA section 

110, along with the EPA’s regulations implementing the CAA SIP 

requirements concerning interstate transport and regional haze, 

each of which is based on at least some of the same measures 

included in building blocks 2 and 3; (b) prior EPA action under 

CAA section 111(d), including the 2005 Clean Air Mercury Rule,471

 

471 This rule was vacated by the D.C. Circuit on other grounds. 

New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), cert. 
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which is based on some of the same measures in building blocks 2 

and 3; (c) the various provisions of the CAA that authorize 

emissions trading, because emissions trading entails a source 

meeting its emission limitation based on the actions of another 

entity; and (d) the pollution prevention provisions of the CAA, 

which make clear that a primary goal of the CAA is to encourage 

federal and state actions that reduce or eliminate, through any 

measures, the amount of pollution produced at the source. (iv) 

Lastly, interpreting the phrase “system of emission reduction” 

to authorize the EPA, in formulating its BSER determination, to 

weigh a broad range of emission-reducing measures that includes 

building blocks 2 and 3 is consistent with Congress’s intent to 

address urgent environmental problems and to protect public 

health and welfare against risks, as well as Congress’s 

expectation that American industry would be able to develop the 

innovative solutions necessary to protect public health and 

welfare. 

Congress passed the CAA, including its several amendments, 

to protect public health and welfare from “mounting dangers,” 

including “injury to agricultural crops and livestock, damage to 

and the deterioration of property, and hazards to air and ground 

 

denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 

1169 (2009). 

Deleted: be precautionary in 

Deleted: ing
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transportation.”472 In doing so, Congress established numerous 

programs to address air pollution problems and provided the EPA 

with guidance and flexibility in carrying out many of those 

programs. In the context of this industry and this pollutant it 

is reasonable to reject the narrow interpretation urged by some 

commenters that the “system of emission reduction” applicable to 

the affected EGUs must be limited to only those measures that 

can be integrated into the design or operation of the source 

itself. The plain language of the statute does not support such 

an interpretation, and to adopt it would limit the “system of 

emission reduction” to measures that are either substantially 

more expensive or substantially less effective at reducing 

emissions than the measures in building blocks 2 and 3, 

notwithstanding the absence of any statutory language imposing 

such a limit. Such a result would be contrary to the goals of 

the CAA and would ignore the facts that sources in the electric 

generation industry routinely address planning and operating 

objectives on a broad, multi-source basis using the measures in 

building blocks 2 and 3 and would seek to use building blocks 2 

and 3 (as well as non-BSER measures) to comply with whatever 

emission standards are set as a result of this rule. Indeed, as 

already observed, building blocks 2 and 3 are already being used 

 

472 CAA section 101(a)(2). 

Deleted: Adopting such an interpretation 

Deleted: this 
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to reduce emissions, and to do so specifically by operation of 

the industry’s inherent multi-source functions. 

b. System of emission reduction as a broad range of measures. 

(1) Plain meaning and context of “system of emission 

reduction.” 

 The phrase “system of emission reduction” appears in the 

definition of a “standard of performance” under CAA section 

111(a)(1). That definition reads: 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated. 

Pursuant to this definition, it is clear that a “system of 

emission reduction” serves as the basis for emission limits 

embodied by CAA section 111 standards. For this reason, emission 

limits must be “achievable” through the “application” of the 

“best” “system of emission reduction” “adequately demonstrated.”

Under CAA section 111(d)(1), such a limit is established for 

“any existing source,” which is defined as any existing 

“building, structure, facility, or installation which emits or 

may emit any air pollutant.”473

 

473 See CAA section 111(d)(1) (applying a standard of performance 

to any existing source); (a)(6) (defining the term “existing 

Deleted: under Chevron step 1

Deleted: These provisions make clear that the 

purpose of the 

Deleted: is to 

Deleted: the emission limitation

Deleted: In addition

Deleted: because the 

Deleted: limitation 

Deleted: by the source,

Deleted: must be of a type that allows the 

source to achieve its emission limitation.
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Although a “system of emission reduction” lays the 

groundwork for CAA section 111 standards, the term “system” is 

not defined in the CAA. As a result, we look first to its 

ordinary meaning.

Abstractly, the term “system” means a set of things or 

parts forming a complex whole; a set of principles or procedures 

according to which something is done; an organized scheme or 

method; and a group of interacting, interrelated, or 

interdependent elements.474 As a phrase, “system of emission 

reduction” takes a broad meaning to serve a singular purpose: it 

is a set of measures that work together to reduce emissions. 

 When read in context, the phrase “system of emission 

reduction” carries important limitations: because the “degree of 

emission limitation” must be “achievable through the application

of the best system of emission reduction,” (emphasis added), the 

 

source” as any stationary source other than a new source); and 

(a)(3) (defining the term “stationary source” as “any building, 

structure, facility, or installation which emits or may emit any 

air pollutant,” however, explaining that “[n]othing in 

subchapter II [i.e., Title II] of this chapter relating to 

nonroad engines shall be construed to apply to stationary 

internal combustion engines.”) 

474 Oxford Dictionary of English (3rd ed.) (2010), available at

http://www.oxforddictionaries.com/us/definition/american_english

/system; see also American Heritage Dictionary (5th ed.) (2013), 

available at 

http://www.yourdictionary.com/system#americanheritage; and The 

American College Dictionary (C.L. Barnhart, ed. 1970) (“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”). 

Deleted: T

Deleted: that term should be given

Deleted: ,

Deleted: which is “a set of things working 

together as parts of a mechanism or 

interconnecting network; a complex whole.”475

With this definition, the phrase 

Deleted: things 
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“system of emission reduction” must be limited to a set of 

measures that work together to reduce emissions and that are 

implementable by the sources themselves. 

As a practical matter, the “source” includes the “owner or 

operator” of any building, structure, facility, or installation 

for which a standard of performance is applicable. For instance, 

under CAA section 111(e), it is the “owner or operator” of a 

source who is prohibited from operating “in violation of any 

standard of performance applicable to such source.”476

Thus, a “system of emission reduction” for purposes of CAA 

section 111(d) means a set of measures that source owners or 

operators can implement to achieve an emission limitation 

applicable to their existing source.477

In contrast, a “system of emission reduction” does not 

include actions that only a state or other governmental entity 

could take that would have the effect of reducing emissions from 

the source category, and that are beyond the ability of the 

 

476 While this section provides for enforcement in the context of 

new sources, a CAA section 111(d) plan must provide for the 

enforcement of a standard of performance for existing sources. 

477 Some commenters read the proposed rulemaking as taking the 

position that the phrase “system of emission reduction” includes 

anything whatsoever that reduces emissions, and criticized that 

interpretation as too broad. See UARG comment, at 3-4. We are 

not taking that interpretation here. In this final rule, we 

agree that the phrase should be limited to exclude, inter alia, 

actions beyond the ability of the owners/operators to control. 

Deleted: “

Deleted: things

Deleted: ”

Deleted: can be implemented 

Deleted: U

Deleted: “

Deleted: things

Deleted: ”

Deleted: 

Deleted: 

Deleted: take
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affected sources’ owners/operators to take or control. 

Additionally, actions that a source owner or operator could take 

that would not have the effect of reducing emissions from the 

source category, such as purchasing offsets, would also not 

qualify as a “system of emission reduction.” 

Building blocks 2 and 3 each fall within the meaning of a 

“system of emission reduction” because they consist of measures 

that the owners/operators of the affected EGUs can implement to 

achieve their emission limits. In doing so, the affected EGUs 

will achieve the overall emission reductions the EPA identifies 

in this rule. We describe these building block 2 and 3 measures 

in detail elsewhere in this rule, including the specific actions 

that owners/operators of affected EGUs can take to implement the 

measures. 

It should be noted that defining the scope of a “system of 

emission reduction” is not the end of our inquiry under CAA 

section 111(a)(1); rather, as noted above, a standard of 

performance must reflect the application of the “best system of 

emission reduction ... adequately demonstrated.” (Emphasis 

added.) Thus, in determining the BSER, the Administrator must 

first determine whether the available systems of emission 

reduction are “adequately demonstrated,” based on the criteria, 

described above, set out by Congress in the legislative history 

Deleted: .

Deleted: also 
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Page 518 of 1544

and the D.C. Circuit in case law. After identifying the 

“adequately demonstrated” systems of emission reduction, the 

Administrator then selects the “best” of these, based on several 

factors, including amount of emission reduction, cost, non-air 

quality health and environmental impact and energy requirements. 

Only after the Administrator weighs all of these considerations 

can she determine the BSER and, based on that, establish a 

standard of performance under CAA section 111(b) or an emission 

guideline under CAA section 111(d). 

Although we do not need to determine the overall scope of 

the phrase “system of emission reduction,” we recognize that 

commenters have raised extensive legal concerns about building 

block 4. We recognize that building block 4 is different from 

building blocks 1, 2, and 3 and the pollution control measures 

that we have considered under CAA section 111. Accordingly, in 

light of our past practice and current policy in implementing 

section 111, as well as the legal concerns raised in public 

comment, today’s final action excludes building block 4 from the 

BSER. 

Traditionally, CAA section 111 standards have been ratebased, allowing regulated entities to produce as much of a 

particular good as they desire provided that they do so through 

an appropriately clean (or low-emitting) process. CAA section 

Deleted: the 

Deleted: It should be noted that, a

Deleted: other limitationsCongress may not have 

intended every conceivable pollution reduction 

measure may to be considered for purposes of 

CAA section 111also apply. In particular, w

Deleted: fundamentally 

Deleted: other conventional

Deleted: been 

Deleted: EPA policy, 

Deleted: ,

Deleted: and the extensive 

Deleted: was not finalized as part of 

Deleted: -

Deleted: As a matter of policy, we believe S
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 519 of 1544

111 performance standards have primarily targeted the means of 

production in an industry and not consumers’ demand for the 

product. Thus, the focus for the BSER has been on how to most 

cleanly produce a good, not on how much of the good should be 

produced. Building blocks 1, 2 and 3 fall squarely within this 

paradigm; they do not require reductions in the total amount of 

electricity produced. Building block 4, however, is outside this 

paradigm as it targets consumer-oriented behavior and demand for 

the good, which would reduce the amount of electricity to be 

produced. 

Although numerous commenters urged us to include demandside energy efficiency measures as part of the BSER, as we had 

proposed to do, we conclude that we cannot do so under our 

historic and current interpretation of section 111. As explained 

above, including building block 4 in the BSER would require a 

paradigm shift in our interpretation and implementation of CAA 

section 111, which we are not making. 

Excluding demand-side energy efficiency measures from the 

BSER has the benefit of allaying legal and other concerns raised 

by commenters, including concerns that individuals could be 

“swept into” the regulatory process by imposing requirements on 

Deleted: the CAA

Deleted: s

Deleted: the consumption habits of individual 

consumers

Deleted: In other words,

Deleted: appropriate 

Deleted: is 

Deleted: best to

Deleted: something

Deleted: whether that good something should be 

produced at all or on 

Deleted: 478

Deleted: 

Deleted: blurs this line, and, after further 

consideration, may be more aptly viewed as 

Deleted: ing

Deleted: in this final rule

Deleted: 

Deleted: the 

Deleted: By making explicit our understanding 

that the CAA generally targets supply-side 

activities and not demand-side behavior, we 

continue our long-standing practice of 

promoting cleaner production measures “to 

protect and enhance the quality of the 

Nation’s air resources so as to promote the 

public health and welfare and the productive 

capacity of its population”.479 This principle 

is also consistent with promoting “reasonable 

... governmental actions ... for pollution 

prevention.”480¶

Lastly, w

Deleted: e recognize that the inclusion of 

Deleted: in regulating supply-side activities 

raises several complicated 
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Page 520 of 1544

“every household in the land.”481 While building block 4 could be 

implemented without imposing requirements on individual 

households, we are mindful of the unintended consequences that 

the Supreme Court cautioned against. Accordingly, this final 

rule resolves any doubt on this matter and is not based on the 

inclusion of demand-side energy efficiency as part of the BSER. 

Strong policy reasons also support our interpretation that 

CAA section 111 targets supply-side activities that allow 

continued production of a product through use of a cleaner 

process, rather than targeting consumer-oriented behavior. This 

continues our long-standing practice of promoting cleaner 

production measures “to protect and enhance the quality of the 

Nation’s air resources so as to promote the public health and 

welfare and the productive capacity of its population.” This 

principle is also consistent with promoting “reasonable ... 

governmental actions ... for pollution prevention.” 

The statute is clear, moreover, that the Administrator has 

discretion to interpret CAA section 111. Specifically, as we 

describe in detail above, Congress expected that the 

Administrator “should determine the achievable limits”482 and 

 

481 See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2436 

(2014).

482 Sen. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (explaining that the “[Administrator] 

Deleted: This was not our intention. 

Deleted: 

Deleted: . 

Deleted: [insert from Howard on Congressional 

intent – Congress delegated authority to the 

EPA to interpret 111, and this falls within 

that interpretation]
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“would establish guidelines as to what the best system for each 

such category of existing sources is.”483 As the D.C. Circuit 

explained, “[i]t seems likely that if Congress meant ... to 

curtail EPA’s discretion to weigh various policy considerations 

it would have explicitly said so in section 111, as it did in 

other parts of the statute.”484 The D.C. Circuit case law, 

discussed in section V.A., also is clear that the EPA has broad 

discretion to determine the appropriate BSER. 

 By the same token, we are not finalizing our proposed 

alternative identification of the BSER as reduced generation. 

Reduced generation focuses on the amount of electricity 

generation, rather than lower-emitting processes for producing 

electricity.485 

For purposes of this final rule, it is not necessary to 

enumerate all of the types of measures that do or do not 

constitute a “system of emission reduction.” What is relevant is 

that building blocks 2 and 3 each qualify as part of the “system 

of emission reduction.” As noted, they focus on supply-side 

 

should determine the achievable limits and let the owner or 

operator determine the most economic, acceptable technique to 

apply.”).

483 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 484 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981). 485 As discussed below, however, reduced generation remains 

important to this rule in that it is one of the methods for 

implementing the building blocks.

Deleted: For example, it is doubtful that 

payments by a source to a governmental entity 

to fund some type of pollution prevention or 

emission control program would qualify as a 

system of emission reduction because the 

source may not be able to assure that the 

governmental entity will take the requisite 

action.¶

Deleted: however, 

Deleted: methods of emission reduction

Deleted: 

Deleted: because, a
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activities and they each constitute measures that the affected 

EGUs can implement that will allow those EGUs to achieve the 

degree of emission limitation that the EPA has identified based 

on those building blocks. Further, these building blocks also 

satisfy the other statutory criteria enumerated in CAA section 

111(a)(1). 

(2) Other indications that the BSER provisions encompass a 

broad range of measures. 

The EPA’s plain meaning interpretation that the BSER 

provisions in CAA section 111(d)(1) and (a)(1) are designed to 

include a broad range of measures, including building blocks 2 

and 3, is supported by several other indications in the CAA and 

the legislative history of section 111. 

(a) Scope of CAA section 111(d)(1). 

First, the scope of CAA section 111(d)(1) supports our 

broad interpretation of the BSER because a wide range of control 

measures is appropriate for the wide range of source categories 

and air pollutants covered under CAA section 111(d). 

 In the 1970 CAA Amendments, Congress established a 

regulatory regime for existing stationary sources of air 

pollutants that may be envisioned as a three-legged stool, 

designed to address “three categories of pollutants emitted from 

stationary sources”: (1) criteria pollutants (identified under Deleted: statutory 
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CAA section 109 and regulated under section 110); (2) hazardous 

air pollutants (identified and regulated under section 112); and 

(3) “pollutants that are (or may be) harmful to public health or 

welfare but are not” criteria or hazardous air pollutants.486

Congress enacted CAA section 111(d) to cover this third category 

of air pollutants and, in this sense, Congress designed it to 

apply to any air pollutants that were not otherwise regulated as 

toxics or NAAQS pollutants.487 This would include air pollutants 

that the EPA might later, when more information became 

available, designate as NAAQS or hazardous air pollutants, as 

well as air pollutants that Congress may not have been aware of 

at the time.488 In addition, the indications are that Congress 

expected CAA section 111(d) to be a significant source of 

regulatory activity, by some measures, more active than CAA 

section 112. This is evident because Congress expected that CAA 

section 111(d) would cover more air pollutants than either CAA 

 

486 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 

implementing CAA section 111(d)). 

487 See Sen. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420 (“It should be noted that the emission 

standards for pollutants which cannot be considered hazardous 

(as defined in section 115 [i.e., the bill’s version of CAA 

section 112] could be established under section 114 [i.e., the 

bill’s version CAA section 111]. Thus, there should be no gaps 

in control activities pertaining to stationary source emissions 

that pose any significant danger to public health or welfare.”). 

488 See Sen. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420. 
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section 109/110 (criteria pollutants) or CAA section 112 

(hazardous air pollutants).489 In addition, in the 1990 CAA 

Amendments, Congress enacted CAA section 129 to achieve emission 

reductions from a major source category, solid waste 

incinerators, and established CAA section 111(d) as the basic 

mechanism for that provision. The EPA subsequently promulgated a 

number of CAA section 129/111(d) rulemakings.490 Finally, it 

should be noted that Congress designed CAA section 111(d) to 

cover a wide range of source categories –- including any source 

category that the EPA identifies under subsection 111(b)(1)(A) 

as meeting the criteria of, in general, causing or contributing 

significantly to air pollution that may reasonably be 

 

489 See Sen. Rep. No. 91-1196, at 9; 18-20, 1970 CAA Legis. Hist. 

at 418-20. The Senate Committee Report identified 14 substances 

as subject to the provision that became section 111(d), four 

substances as hazardous air pollutants that would be regulated 

under the provision that became section 112, and 5 substances as 

criteria pollutants that would be regulated under the provisions 

that became sections 109-110 (and more “as knowledge 

increases”). In particular, the Report recognized that in 

particular, relatively few air pollutants may qualify as 

hazardous air pollutants, but that other air pollutants that did 

not qualify as hazardous air pollutants would be regulated under 

what became section 111(d). 

490 See, e.g., Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: 

Hospital/Medical/Infectious Waste Incinerators, 62 Fed. Reg. 

48,348, 48359 (Sept. 15, 1997); Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources: 

Commercial and Industrial Solid Waste Incineration Units, 65 

Fed. Reg. 75338, 75341 (Dec. 1, 2000). 
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anticipated to endanger public health or welfare -- along with 

the wide range of air pollutants. 

Because Congress designed CAA section 111(d) to cover a 

wide range of air pollutants -- including ones that Congress may 

not have been aware of at the time it enacted the provision –- 

and a wide range of industries, it is logical that Congress 

intended that the BSER provision, as applied to CAA section 

111(d), have a broad scope so as to accommodate the range of air 

pollutants and source categories. 

(b) Legislative history of CAA section 111. 

(i) Breadth of “system of emission reduction.” 

The phrase “system of emission reduction,” particularly as 

applied under CAA section 111(d), should be broadly interpreted 

consistent with its plain meaning but also in light of its 

legislative history. The version of CAA section 111(d)(1) that 

Congress adopted as part of the 1970 CAA Amendments read largely 

as CAA section 111(d)(1) does at present, except that it 

required states to impose “emission standards” on any existing 

source. (Congress replaced that term with “standards of 

performance” in the 1977 CAA Amendments.) The 1970 CAA 

Amendments version of CAA section 111(d)(1) neither defined 
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Page 526 of 1544

“emission standards” nor imposed restrictions on the EPA in 

determining the basis for the emission standards.491 

For new sources, CAA section 111(b)(1)(B), as enacted in 

the 1970 CAA Amendments (and as it largely still reads), 

required the EPA to promulgate “standards of performance,” and 

defined that term, much like the present definition, as emission 

standards based on the “best system of emission reduction ... 

adequately demonstrated.” This quoted phrase was not included in 

either the House or Senate versions of the provision, and, 

instead, was added during the joint conference between the House 

 

491 Although not defined under CAA section 111, the term was used 

in other provisions and defined in some of them. The term was 

defined under the CAA’s citizen suit provision. See 1970 CAA 

Amendments, Pub. L. 91-604, § 12, 84 Stat. 1676, 1706 (Dec. 31, 

1970) (defined as “(1) a schedule or timetable of compliance, 

emission limitation, standard of performance or emission 

standard, or (2) a control or prohibition respecting a motor 

vehicle fuel or fuel additive....”). Congress also used it in the 

CAA’s NAAQS provisions and in CAA section 112. Under the CAA’s 

NAAQS provisions (i.e., the “Ambient Air Quality and Emission 

Standards” provisions), Congress directed the EPA to issue 

information on “air pollution control techniques,” and include 

data on “available technology and alternative methods of 

prevention and control of air pollution” as well as on 

“alternative fuels, processes, and operating methods which will 

result in elimination or significant reduction of emissions.” 

Id., § 4, 84 Stat. at 1679. Similarly, under CAA section 112, 

the Administrator was required to “from time to time, issue 

information on pollution control techniques for air pollutants” 

subject to emission standards. Id., 84 Stat. at 1685. These 

statements provide additional context for the term’s broad 

intent. 
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Page 527 of 1544

and Senate. The conference report accompanying the text offers 

no clarifications. 

The House and Senate bills do, however, provide some 

insights. The House bill, H.R. 17255, would have required new 

sources of non-hazardous air pollutants to “prevent and control 

such emissions to the fullest extent compatible with the 

available technology and economic feasibility, as determined by 

the Secretary.”492 The Senate bill, S. 4358, would have 

established “Federal standards of performance for new sources,” 

which, in turn, were to “reflect the greatest degree of emission 

control which the Secretary determines to be achievable through 

application of the latest available control technology, 

processes, operating methods, or other alternatives.”493 The 

Senate Committee Report explains that “performance standards 

should be met through application of the latest available 

emission control technology or through other means of preventing 

or controlling air pollution.”494 This Report further elaborates 

that the term “standards of performance” 

 

492 H.R. 17255, § 5, 1970 CAA Legis. Hist. at 921-22. The 

reference to “Secretary” was to the Secretary of Health 

Education and Welfare, which, at the time, was the agency with 

responsibility for air pollution regulations. 

493 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added). 494 Sen. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added). 
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refers to the degree of emission control which can be 

achieved through process changes, operation changes, 

direct emission control, or other methods. The 

Secretary should not make a technical judgment as to 

how the standard should be implemented. He should 

determine the achievable limits and let the owner or 

operator determine the most economic, acceptable 

technique to apply.495 

Thus, the Senate bill clearly envisioned that standards of 

performance would not be based on a particular technology or 

even a particular method to prevent or control air pollution.496

This vision contrasted with the House bill, which would have 

restricted performance standards to economically feasible 

technical controls. 

Following the House-Senate Conference, the enacted version 

of the legislation defined a “standard of performance” to mean 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated.497 

 

495 Sen. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added). 

496 Notably, the Senate report identifies pollution control and

pollution prevention as objectives of the Senate provision. 

Pollution prevention is discussed more generally below as a 

“primary purpose” of the CAA, however, the report makes clear 

that pollution prevention measures – which the EPA understands 

to include such measures as building blocks 2 and 3 -- are 

appropriate under CAA section 111. 

497 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis 

added). 
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While the phrase “system of emission reduction” was not 

discussed in the Conference Report, an exhibit titled “Summary 

of the Provisions of Conference Agreement on the Clean Air 

Amendments of 1970” was added to the record during the Senate’s 

consideration of the Conference Report and sheds some light on 

the phrase. According to the summary, “[t]he agreement 

authorizes regulations to require that new major industry plants 

such as power plants, steel mills, and cement plants achieve a 

standard of emission performance based on the latest available 

control technology, processes, operating methods, and other 

alternatives.”498 In light of this summary, the phrase “system of 

emission reduction” appears to blend the broad spirit of S. 4358 

(which required the “latest available control technology, 

processes, operating methods, or other alternatives”) with the 

cost concerns identified in H.R. 17255 (which required 

consideration of “economic feasibility” when establishing 

federal emission standards for new stationary sources). This 

history strongly suggests that Congress intended to authorize 

the EPA to consider a wide range of measures in calculating a 

standard of performance for stationary sources. At a minimum, 

there is no indication that Congress intended to preclude 

 

498 Sen. Muskie, Sen. Consideration of H.R. Conf. Rep. No. 91-

1783 (Dec. 17, 1970), 1970 CAA Legis. Hist. at 130.

Deleted: or discussed in either chamber during 

the debates over passage of the Conference 

agreement

Deleted: the 

Deleted: final text
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certain measures or actions from the EPA’s assessment of the 

BSER. 

In 1977, Congress amended CAA section 111 to reflect a 

narrower conception of CAA section 111(a)(1). Congress was 

clear, however, that existing source standards, which were no 

longer developed as “emission standards,” would not be limited 

to technological measures. Specifically, the 1977 CAA Amendments 

revised CAA section 111(a)(1) to require all new sources to meet 

emission standards based on the reductions achievable through 

the use of the ”best technological system of continuous emission 

reduction.”499 According to the legislative history, [t]his 

mean[t] that new sources may not comply merely by burning 

untreated fuel, either oil or coal.” 500 The new requirement 

stemmed in part from Congress’s concern over the shocks that the 

country experienced during the 1973-74 Arab Oil Embargo, which 

led Congress to revise CAA section 111 to “encourage and 

facilitate the increased use of coal, and to reduce reliance (by 

new and old sources alike), upon petroleum to meet emission 

requirements.”501 Imposing a new technological requirement (along 

with a new percentage reduction requirement) under CAA section 

 

499 CAA section 111(a)(1) (1977). 500 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

501 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 
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111 was designed to “force new sources to burn high-sulfur fuel 

thus freeing low-sulfur fuel for use in existing sources where 

it is harder to control emissions and where low-sulfur fuel is 

needed for compliance.” 502 Congress nonetheless recognized that 

despite narrowing new source standards to the best 

“technological system of continuous emission reduction,” many 

“innovative approaches may in fact reduce the economic and 

energy impact of emissions control,” and the Administrator 

should still be encouraged to consider other technologically 

based techniques for emissions reduction, including 

“precombustion cleaning or treatment of fuels.”503 This is 

discussed in more detail below. 

Despite these changes with respect to new sources, the 1977 

CAA Amendments further reinforce the notion that with respect to 

existing sources, the BSER was never intended to be narrowly 

applied. In 1977, Congress changed CAA section 111(d)(1) to 

require that states adopt “standards of performance” and made 

clear that such standards were to be based on the “best system 

of continuous emission reduction ... adequately demonstrated,”504

 

502 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 Fed. Reg. 33580, 33581-33582 

(June 11, 1979). 

503 H.R. Rep. No. 95-294, at 189 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2656. 

504 CAA section 111(a)(1)(C) under the 1977 CAA Amendments. 
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but generally maintained the breadth of that term. Although 

Congress inserted the word “continuous” into the phrase, 

Congress explained that “standards in the Section 111(d) state 

plan would be based on the best available means (not necessarily 

technological) for categories of existing sources to reduce 

emissions.”505 This was intended to distinguish existing source 

standards from new source standards, for which “the requirement 

for [BSER] has been more narrowly redefined as best 

technological system of continuous emission reduction.”506,507

 

505 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2662 (emphasis added). Congress also endorsed the EPA’s practice 

of establishing “emission guidelines” under CAA section 111(d). 

See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 

at 2662 (“The Administrator would establish guidelines as to 

what the best system for each such category of existing sources 

is. However, the state would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.”). 

506 Sen. Muskie, Sen. Consideration of the H.R. Conf. Rep. No. 

95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 

507 In 1977, Congress added a new substantive definition for 

“emission standard” generally applicable throughout the CAA. 

1977 CAA Amendments, Pub. L. 95-95, § 301, 91 Stat. 685, 770 

(Aug. 7, 1977) (defining “emission limitation” and “emission 

standard” as “a requirement established by the State or the 

Administrator which limits the quantity, rate, or concentration 

of emissions of air pollutants on a continuous basis, including 

any requirement relating to the operation or maintenance of a 

source to assure continuous emission reduction.”). Congress also 

added a generally applicable definition of standard of 

performance, defined as “a requirement of continuous emission 

reduction, including any requirement relating to the operation 

or maintenance of a source to assure continuous emission 

reduction.” Id. 
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In the 1990 CAA Amendments, Congress restored the 1970s 

vintage definition of a standard of performance as applied to 

both new and existing sources. With respect to existing sources, 

this had the effect of no longer requiring that the BSER be 

“continuous.”508 Further, nothing in the 1990 CAA Amendments or 

their legislative history indicates that Congress intended to 

impose new constraints on the types of systems of emission 

reduction that could be considered under CAA section 111(d)(1) 

and (a)(1). In contrast, Congress retained the definition of the 

term “technological system of continuous emission reduction,” 

which means 

(A) a technological process for production or operation by 

any source which is inherently low-polluting or 

nonpolluting, or 

(B) a technological system for continuous reduction of the 

pollution generated by a source before such pollution is 

emitted into the ambient air, including precombustion 

cleaning or treatment of fuels. 

That term continues to be used in reference to new sources in 

certain circumstances, under CAA section 111(b), (h), and (j).509

 

508 We note that the general definition of a standard of 

performance at CAA section 302(l) still uses “continuous.” Even 

if this provision applies to section 111, it does not affect our 

analysis in this rule, including our interpretation that BSER 

includes building blocks 2 and 3. 

509 In many respects, there are indications that Congress prefers 

CAA section 111(b) standards of performance to be based on 

technological control methods. This is due in part to the 

recognition that new sources have long operating lives over 

which initial capital costs can be amortized. Thus, new 
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However, it is not and never has been used to regulate existing 

sources. In this manner, the 1990 CAA Amendments further 

reinforce the breadth and flexibility of the phrase “system of 

emission reduction,” particularly as it applies to existing 

sources under CAA section 111(d). 

For these reasons, the 1970, 1977, and 1990 legislative 

histories support the EPA’s interpretation in this rule that the 

term is sufficiently broad to encompass building blocks 2 and 3. 

(ii) Reliance on actions taken by other entities. 

The legislative history supports the EPA’s interpretation 

of “system of emission reduction” in another way, as well: The 

legislative history makes clear that Congress intended that 

standards of performance for electric power plants could be 

based on measures implemented by other entities, for example, 

 

construction is the preferred time to drive capital investment 

in emission controls. See, e.g., Sen. Rep. No. 91-1196, at 15-

16, 1970 CAA Legis. Hist. at 416 (“[t]he overriding purpose of 

this section [concerning new source performance standards] would 

be to prevent new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of their 

construction is seen by the committee as the most effective and, 

in the long run, the least expensive approach.”); see also 1977 

CAA Amendments, § 109, 91 Stat. at 700, (redefining, with 

respect to new sources, CAA section 111(a)(1) to reflect the 

best “technological system of continuous emission reduction” and 

adding CAA section 111(a)(7) to define this new term). However, 

as a result of the 1990 revisions to CAA section 111(a)(1), 

which replaced the phrase “technological system of continuous 

emission reduction” with “system of emission reduction,” new 

source standards would not be restricted to being based on 

technological control measures.
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entities that “wash,” or desulfurize, coal (or, for oil-fired 

EGUs, that desulfurize oil). This legislative history is 

consistent with the EPA’s view that the “system of emission 

reduction” may include actions taken by an entity with whom the 

owner/operator of the affected source enters into a contractual 

relationship as long as those actions allow the affected source 

to meet its emission limitation. By the same token, this 

legislative history directly refutes commenters’ assertions that 

the phrase “system of emission reduction” must not include 

actions taken by entities other than the affected sources.510

As noted above, in the 1977 CAA Amendments, Congress 

revised the basis for standards of performance for new fossil 

fuel-fired stationary sources to be a “technological system of 

continuous emission reduction,” including “precombustion 

cleaning or treatment of fuels.”511 Precombustion cleaning or 

 

510 See, e.g., comments by UARG at 31 (the building blocks other 

than building block 1 take a “‘beyond-the-source’ approach” and 

“impermissibly rely on measures that go beyond the boundaries of 

individual affected EGUs and that are not within the control of 

individual EGU owners and operators”); comments by American 

Chemistry Council et al. (“Associations”) at 60-61 (EPA’s 

proposed BSER analysis is unlawful because it “looks beyond the 

fence line of the fossil fuel-fired EGUs that are the subject of 

this rulemaking;” “the standard of performance must ... be 

limited to the types of actions that can be implemented directly 

by an existing source within [the appropriate] class or 

category.”). 

511 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA 

section 111(a)(7). 
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treatment reduces the amount of sulfur in the fuel, which means 

that the fuel can be combusted with fewer SO2 emissions, and that 

in turn means that the source can achieve a lower emission 

limit. Congress understood that these fuel cleaning techniques 

would not necessarily be accomplished at the affected source 

and, in revising CAA section 111(a)(1), wanted to ensure that 

such techniques would not be overlooked. For example, the 1977 

House Committee report indicates that an assessment of the best 

technological system of continuous emission reduction for fossil 

fuel-fired power plants would include off-site or third-party 

pre-combustion techniques for reducing emissions at the source 

(“e.g., various coal-cleaning technologies such as solvent 

refining, oil desulfurization at the refinery”).512 Thus, the 

standard of performance reflecting the best technological system 

implementable by an affected source could be based, in part, on 

 

512 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2655 (emphasis added). Generally speaking, coal cleaning 

activities also are conducted by third parties. For instance, 

EPA recognized in a regulatory analysis of new source 

performance standards for industrial-commercial-institutional 

steam generating units that the technology “requires too much 

space and is too expensive to be employed at individual 

industrial-commercial-institutional steam generating units.” 

U.S. EPA, Summary of Regulatory Analysis for New Source 

Performance Standards: Industrial-Commercial-Institutional Steam 

Generating Units of Greater than 100 Million Btu/hr Heat Input, 

EPA-450/3-86-005, p. 4-4 (June 1986). 
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technologies used at off-site facilities owned and operated by 

third-parties. 

In the 1990 CAA Amendments, Congress eliminated many of the 

restrictions and other provisions added in the 1977 CAA 

Amendments by largely reinstating the 1970 CAA Amendments’ 

definition of “standard of performance.” Nevertheless, there is 

no indication that in doing so, Congress intended to preclude 

the EPA from considering coal cleaning by third parties (which 

had been considered within the scope of the best system of 

emission reduction even under the 1970 CAA Amendments),513 and in 

fact, the EPA’s regulations promulgated after the 1990 CAA 

Amendments continue to impose standards of performance that are 

based on third-party coal cleaning.514

(c) Consistency of a broad interpretation of CAA section 

111 with the overall structure of the CAA. 

 

513 See U.S. EPA, Background Information for Proposed New-Source 

Performance Standards: Steam Generators, Incinerators, Portland 

Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants, Office 

of Air Programs Tech. Rep. No. APTD-0711, p. 7 (Aug. 1971) 

(indicating the “desirability of setting sulfur dioxide 

standards that would allow the use of low-sulfur fuels as well 

as fuel cleaning, stack-gas cleaning, and equipment 

modifications” (emphasis added)). 

514 40 C.F.R. § 60.49b(n)(4); see also Amendments to New Source 

Performance Standards (NSPS) for Electric Utility Steam 

Generating Units and Industrial-Commercial-Institutional Steam 

Generating Units; Final Rule, 72 Fed. Reg. 32742 (June 13, 

2007). 
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Interpreting CAA section 111(d)(1) and (a)(1) to authorize 

the EPA’s consideration of the building block 2 and 3 measures 

is consistent with the overall structure of the CAA, 

particularly as it was amended in 1970, when Congress added CAA 

section 111 in much the same form that it reads today. 

 In the 1970 CAA Amendments, for the most part, and 

particularly for stationary source provisions, Congress painted 

with broad brush strokes, giving broad authority to the EPA or 

the states. That is, Congress established general requirements 

that were intended to produce stringent results, but gave the 

EPA or the states great discretion in fashioning the types of 

measures to achieve those results. 

For example, under CAA section 109, Congress authorized the 

EPA to promulgate national ambient air quality standards (NAAQS) 

for air pollutants, and Congress established general criteria 

and procedural requirements, but left to the EPA discretion to 

identify the air pollutants and select the standards. Under CAA 

section 110, Congress required the states to submit to the EPA 

state implementation plans (SIPs), required that the plans 

attain the NAAQS by a date certain, and established procedural 

requirements, but allowed the states broad discretion in 

determining the substantive requirements of the SIPs. 
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Under CAA section 111(b), Congress directed the EPA to list 

source categories that endanger public health or welfare, and 

established procedural requirements, but did not include other 

substantive requirements, and instead, gave the EPA broad 

discretion to determine the criteria for endangerment. 

Under CAA section 112, Congress required the EPA to 

regulate certain air pollutants and to set “emission standards” 

that meet general criteria, and established procedural 

requirements, but did not include other substantive requirements 

and instead, gave the EPA broad discretion in identifying the 

types of pollutants and in determining the standards.515 By and 

 

515 By comparison, under the 1990 CAA Amendments, Congress 

substantially transformed CAA section 112 to be significantly 

more prescriptive in directing EPA rulemaking, which reflected 

Congress’s increased knowledge of hazardous air pollutants and 

impatience with the EPA’s progress in regulating. 
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large, Congress left these provisions intact in the 1977 CAA 

Amendments.516,517

Congress drafted the CAA section 111(d) requirements in the 

1970 CAA Amendments, and revised them in the 1977 CAA 

Amendments, in a manner that is similar to the other stationary 

source requirements, just described, in CAA sections 109, 110, 

111(b), and 112. The CAA section 111(d) requirements are broadly 

phrased, include procedural requirements, no more than very 

general substantive requirements, and give broad discretion to 

the EPA to determine the basis for the required emission limits 

and to the states to set the standards. It should be noted that 

this drafting approach is not unique to the CAA; on the 

contrary, Congress "usually does not legislate by specifying 

 

516 In the 1977 CAA Amendments, Congress applied the same broad 

drafting approach to the stratospheric ozone provisions it 

adopted in CAA sections 150-159. There, Congress authorized the 

EPA to determine whether, “in the Administrator’s judgment, any 

substance, practice, process, or activity may reasonably be 

anticipated to affect the stratosphere, especially ozone in the 

stratosphere, and such effect may reasonably be anticipated to 

endanger public health or welfare,” and then directed the EPA, 

if it made such a determination, to “promulgate regulations 

respecting the control of such process practice, process, or 

activity....” CAA section 157(a). This provision does not further 

specify requirements for the regulations. 

517 On the other hand, in those instances in which Congress had a 

clear idea as to the emission limitations that it thought should 

be imposed, it mandated those emission limits, e.g., in Title II 

concerning motor vehicles. 
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examples, but by identifying broad and general principles that 

must be applied to particular factual instances."518 

In light of this statutory framework, it is clear that 

Congress delegated to the EPA the authority to administer CAA 

section 111, including by authorizing the EPA to apply the 

“broad and general principles” contained in CAA section 

111(a)(1) to the particular circumstances we face today. 

(3) Comments and responses. 

While some commenters support the EPA’s interpretation of 

section 111 to authorize the inclusion of building blocks 2 and 

3 in the BSER, other commenters assert that the emission 

standards must be based on measures that the sources subject to 

CAA section 111 –- in this rule, the affected EGUs -- apply to 

their own design or operations, and, as a result, in this rule, 

cannot include measures implemented at entities other than the 

affected EGUs that have the effect of reducing generation, and 

therefore emissions, from the affected EGUs. The commenters 

assert that various provisions in CAA section 111 make this 

limitation clear. We do not find those arguments persuasive. 

First, some commenters state that under CAA section 

111(d)(1) and (a)(1), the existing sources subject to the 

 

518 Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 

(1989) (Kennedy, J., concurring). 

Deleted: with 

Deleted: Some
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standards of performance must be able to achieve their emission 

limit, but that they are able to do so only through measures 

integrated into the source’s own design and operation. As a 

result, according to these commenters, those are the only types 

of measures that may qualify as a “system of emission reduction” 

that may form the basis of the emissions standards. We disagree. 

We see nothing in CAA section 111(d)(1) or (a)(1) which by its 

terms limits CAA section 111 to measures that must be integrated 

into the sources’ own design or operation. Rather, we recognize 

that in order for an emission limitation based on the BSER to be 

“achievable,” the BSER must consist of measures that can be 

undertaken by an affected source -- that is, its owner or 

operator. As noted elsewhere in the preamble, the affected 

sources subject to this rule are fully able to meet their 

emission standards by undertaking the measures described in all 

three building blocks. Moreover, as discussed, the measures in 

building blocks 2 and 3 are highly effective in achieving CO2

emission reductions from these affected EGUs, given the unique 

characteristics of the industry. This reinforces the conclusion 

that the term “system of emission reduction” is broad enough to 

include these measures. 

The broad nature of CAA section 111(d)(1) and (a)(1) is 

also confirmed by comparing it to CAA provisions that explicitly 

Deleted: , including building blocks 2 and 3. 
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require controls on the design or operations of an affected 

source. The most notable comparison is at CAA section 111(a)(7). 

The term “technological system of continuous emission 

reduction,” which was added in 1977 and remains as a separately 

defined term means, in part, “a technological process for 

production or operation by any source which is inherently lowemitting or nonpolluting.” (Emphasis added.) With respect to 

this portion of the definition (and ignoring the additional 

text, which includes “precombustion cleaning or treatment of 

fuels” and clearly encompasses off-site activities), it could be 

argued that between 1977 and 1990 new source performance 

standards should be restricted to measures that could be 

integrated into the design or operation of a source. However, 

commenters’ assertion that the BSER must be limited in a similar 

fashion ignores the deliberate change in 1990 to restore the 

broader definition of a standard of performance (i.e., that it 

be based on the BSER and not the TSCER). In any case, the 

narrower scope of CAA section 111(a)(7) was never applicable to 

the regulation of existing sources under CAA section 111(d). 

Several other examples of standard setting in the CAA shed 

light on ways in which Congress has constrained the EPA’s 

review. CAA section 407(b)(2) provides that the EPA base NOx

emission limits for certain types of boilers “on the degree of 
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Page 544 of 1544

reduction achievable through the retrofit application of the 

best system of continuous emission reduction.” (Emphasis added.) 

Likewise, in determining best available retrofit technology 

under CAA section 169A, the state (or Administrator) must “take 

into consideration the costs of compliance, the energy and 

nonair quality environmental impacts, any existing pollution 

control technology in use at the source, the remaining useful 

life of the source, and the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of 

such technology.”519 (Emphasis added.) These provisions make 

clear that Congress knew how to constrain the basis for emission 

limits to measures that are integrated into the design or 

operation of the affected source, and that its choice to base 

CAA section 111(d)(1) and (a)(1) standards of performance on a 

“system of emission reduction” indicates Congress’ intent to 

authorize a broader basis for those standards. 

Some commenters also argue that other provisions in CAA 

section 111 indicate that Congress intended that CAA section 

111(d)(1) and (a)(1) be limited to measures that are integrated 

 

519 Even under BART, the EPA is authorized to allow emissions 

trading between sources. See, e.g., 40 C.F.R. § 51.308(e)(1) & 

(2); Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 (D.C. 

Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 

2005); and Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th 

Cir. 1993). 

Deleted: C
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into the source’s design or operations. This argument is 

unpersuasive for several reasons. First, it would be 

unreasonable to presume that Congress intended to limit the 

BSER, indirectly through these other provisions, to measures 

that are integrated into the affected source’s design or 

operations, when Congress could have done so expressly, as it 

did for the above-discussed CAA section 407(b)(2) NOx

requirements. 

Second, the interpretations that commenters offer for these 

various provisions misapply the text. For example, commenters 

note that under CAA section 111(d)(1), (a)(3), and (a)(6), the 

standards of performance apply to “any existing source,” and an 

“existing source” is defined to include “any stationary source,” 

which, in turn, is defined as “any building, structure, 

facility, or installation which emits or may emit any air 

pollutant.” Commenters assert that these applicability and 

definitional provisions indicate that the BSER provisions in CAA 

section 111(d)(1) and (a)(1) must be interpreted to require that 

the control measures must be integrated into the design or 

operations of the source itself. 

We disagree. These applicability and definitional 

provisions are jurisdictional in nature. Their purpose is simply 

to identify the types of sources whose emissions are to be 

Deleted: Title IV 
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addressed under CAA section 111(d), i.e., stationary sources, as 

opposed to other types of sources, e.g., mobile sources, whose 

emissions are addressed under other CAA provisions (such as CAA 

Title II). This purpose is made apparent by the terms of CAA 

section 111(a)(3), which contains two sentences (the second of 

which commenters seem to ignore). The first sentence provides, 

“The term ‘stationary source’ means any building, structure, 

facility, or installation which emits or may emit any air 

pollutant.” The second sentence provides, “Nothing in subchapter 

II of this chapter relating to nonroad engines shall be 

construed to apply to stationary internal combustion engines.” 

This second sentence explains that stationary internal 

combustion engines are to be regulated under CAA section 111, 

and not Title II (relating to mobile sources), which confirms 

that the purpose of the definition of stationary source is 

jurisdictional in nature -- to identify the emissions that are 

to be regulated under section 111, as opposed to other CAA 

provisions. 

These applicability and definitional provisions say nothing 

about the system of emission reduction –- whether it is limited 

to measures integrated into the design or operation of the 

source itself or may be broader -- that may form the basis of 
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the standards for those emissions that are to be promulgated 

under CAA section 111. 

Third, this argument by commenters does not account for the 

commonsense proposition that it is the owner/operator of the 

stationary source, not the source itself, who is responsible for 

taking actions to achieve the emission rate, so that actions 

that the owner/operator is able to take should be considered in 

determining the appropriate standards for the source’s 

emissions. Again, it is commonsense that buildings, structures, 

facilities, and installations can take no actions -- only owners 

and operators can install and maintain pollution control 

equipment; only owners and operators can solicit precombustion 

cleaning or treatment of fuel services; and only owners and 

operators can apply for a permit or trade allowances.520 Other 

provisions in CAA section 111 make clear the role of the 

owner/operator. CAA section 111(e) provides that for new 

sources, the burden of compliance falls on the “owner or 

operator.”521 The same is necessarily true for existing sources. 

 

520 Industry commenters also acknowledged that it is the owner or 

operator that implements the control requirements. See UARG 

comment at 19 (section 111(d) “provides for the regulation of 

individual emission sources through performance standards that 

are based on what design or process changes an individual 

source’s owner can integrate into its facility”).

521 CAA section 111(e) provides: (“[I]t shall be unlawful for any 

owner or operator of any new source to operate such source in 

violation of any [applicable] standard of performance.”) 

Deleted: B
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This supports the EPA’s view that the basis for whether a 

control measure qualifies as a “system of emission reduction” 

under CAA section 111(d)(1) and (a)(1) is whether it is 

something that the owner/operator can implement in order to 

achieve the emissions standard assigned to the source –- if so, 

the control measure should qualify as a “system of emission 

reduction” –- and not whether the control measure is integrated 

into the source’s own design or operation. 

Commenters also argue that CAA section 111(h), which 

authorizes “design, equipment, work practice or operational 

standard[s]” (together, “design standards”) only when a source’s 

emissions are not emitted through a conveyance or cannot be 

measured, makes clear that CAA section 111 standards of 

performance must be based on measures integrated into a source’s 

own design or operations. We disagree. CAA section 111(h) 

concerns the relatively rare situation in which an emission 

standard, which entails a numerical limit on emissions, is not

appropriate because emissions cannot be measured, due either to 

the nature of the pollutant (i.e., the pollutant is not emitted 

through a conveyance) or the nature of the source category 

(i.e., the source category is not able to conduct measurements). 

CAA section 111(h) provides that imposing a design standard is 

appropriate under those circumstances, but only under those 
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circumstances. When an emissions standard is appropriate, 

including in the present rule, CAA section 111(h) is silent on 

which system of emissions reduction –- whether limited to a 

source’s own design or operations -- may form the basis of the 

emissions standard.522 In any event, CAA section 111(h) applies 

only to standards promulgated by the Administrator, and 

therefore appears by its terms to be limited to CAA section 

111(b) rulemakings for new, modified, or reconstructed sources, 

not CAA section 111(d) rulemakings for existing sources. 

Some commenters identify other provisions of CAA section 

111 that, in their view, prove that CAA section 111 is limited 

to control measures that are integrated within the design or 

operations of the source. We do not find those arguments 

persuasive, for the reasons discussed in the supporting 

documents for this rule. 

Commenters also argue, more generally, that Congress knew 

how to authorize control measures such as renewable energy, as 

indicated by Congress’s inclusion of those measures in Title IV 

(relating to acid rain), so the fact that Congress did not 

 

522 For this same reason, the fact that section 111(h) authorizes 

the EPA to impose certain types of standards –- such as work 

practice standards or operational standards that could include 

limits on production -- only in limited circumstances not 

present in this rulemaking, does not preclude the EPA from 

determining that those same measures are the BSER or means of 

implementing the BSER. 
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explicitly include these measures in the BSER provisions of CAA 

section 111(d)(1) and (a)(1) indicates that Congress did not 

intend that they be included as part of the BSER, and instead 

intended that the BSER be limited to measures integrated into 

the sources’ design or operations. This argument misses the 

mark. The provisions of CAA section 111(d)(1) and (a)(1) do not 

explicitly include any specific emission reduction measures –- 

neither renewable energy measures (like the ones Congress wanted 

to incentivize under Title IV), nor measures that are integrated 

into the sources’ design or operations (like the retrofit 

control measures Congress required under CAA section 407(b)). 

But this contrast with other CAA provisions does not mean that 

Congress did not intend the BSER to include any of those types 

of measures. Rather, this contrast supports viewing a “system of 

emission reduction” under CAA section 111 as sufficiently broad 

to encompass a wide range of measures for the purpose of 

emission reduction of a wide range of pollutants from a wide 

range of stationary sources.523

 

523 It should also be noted that Title IV is limited to 

particular pollutants (i.e., SO2 and NOx) and particular sources 

-– fossil fuel-fired EGUs –- and as a result, lends itself to 

greater specificity about the types of control measures. Section 

111(d), in contrast, applies to a wide range of source types, 

which, as discussed above, supports reading it to authorize a 

broad range of control measures. 
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c. Deference to interpret the BSER to include building blocks 2 

and 3. To the extent that it is not clear whether the phrase 

“system of emission reduction” may include the measures in 

building blocks 2 and 3, the EPA’s interpretation of CAA section 

111(d) and (a) is reasonable524 in light of our discretion to 

determine “whether and how to regulate carbon-dioxide emissions 

from power plants....”525 

 Our interpretation that a “system of emission reduction” 

for the affected EGUs may include building blocks 2 and 3 is a 

reasonable construction of the statute for the reasons described 

above and in this section below. 

(1) Consistency of building blocks 2 and 3 with the 

structure of the utility power sector. 

(a) Integration of the utility power sector. 

Certain characteristics of the utility power sector are of 

central importance for understanding why the measures of 

building blocks 2 and 3 qualify as part of the system of 

emission reduction. As discussed above, electricity is highly 

substitutable and the utility power sector is highly integrated, 

so much so that it has been likened to a big machine. 

 

524 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 1603 

(2014) (“We routinely accord dispositive effect to an agency’s 

reasonable interpretation of ambiguous statutory language.”). 

525 American Electric Power v. Connecticut, 131 S. Ct. 2527, 2538 

(2011) (“AEP”) (emphasis added). 

Deleted: Chevron step 2 d

Deleted: Under the familiar Chevron step 2 

analysis, t
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Specifically, the utility power sector is characterized by 

physical, as well as operational, interconnections between 

electricity generators themselves, and between those generators 

and electricity users. Because of the physical properties of 

electricity and the current low availability of large scale 

electricity storage, generation and load (or use) must be 

instantaneously balanced in real time. As a result, the utility 

power sector is uniquely characterized by extensive planning and 

highly coordinated operation. These features have been present 

for decades, and in fact, over time, the sector has become more 

highly integrated. Another important characteristics of the 

utility power sector is that although the states have developed 

both regulated and de-regulated markets, the generation of 

electricity reflects a least-cost dispatch approach, under which 

electricity is generated first by the generators with the lowest 

variable cost. 

These characteristics of the sector have facilitated the 

overall objective of providing reliable electric service at 

least cost subject to a variety of constraints, including 

environmental constraints. Moreover, in each type of market, the 

sector has developed mechanisms, including the participation of 

institutional actors, to safeguard reliability and to assure 

least cost service. 

Deleted: a 
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Congress,526 the Courts,527 the EPA in its regulatory 

actions,528 and states in their regulatory actions529 have 

recognized the integrated nature of the utility power sector. 

(b) Significance of integrated utility power sector for the 

BSER. 

The fungibility of electricity, coupled with the 

integration of the utility power sector, means that, assuming 

that demand is held constant, adding electricity to the grid 

from one generator will result in the instantaneous reduction in 

generation from other generators. Similarly, reductions in 

generation from one generator lead to the instantaneous increase 

in generation from other generators. Thus, the operation of 

individual EGUs is integrated and coordinated with the 

 

526 See CAA section 404(f)(2)(B)(iii)(I) (conditioning a 

utility’s eligibility for certain allowances on implementing an 

energy conservation and electric power plan that evaluates a 

range of resources to meet expected future demand at least 

cost); see also Sen. Rep. No. 101-228, at 319-20 (Dec. 20, 

1989)(recognizing that “utilities already engage in powerpooling arrangements to ensure maximum flexibility and 

efficiency in supplying power” to support the establishment of 

an allowance system under title IV). 

527 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

at 7 (2002) (citing Brief for Respondent FERC 4-5). 

528 “Stack Heights Emissions Balancing Policy,” 53 Fed. Reg. 480, 

482 (Jan. 7, 1988). 

529 See 79 FR 34830, 34880 (June 18, 2014) (discussing State of 

California Global Warming Solutions Act of 2006, Assembly Bill 

32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdf, and quoting December 27, 

2013 Letter from Mary D. Nichols, Chairman of California Air 

Resources Board, to EPA Administrator Gina McCarthy). 
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operations of other EGUs and other sources of generation, as 

well as with electricity users. This allows for locational 

flexibility across the sector in meeting demand for electricity 

services. The institutions that coordinate planning and 

operations routinely use this flexibility to meet demand for 

electricity services economically while satisfying constraints, 

including environmental constraints. Because of these 

characteristics, EGU owner/operators have long conducted their 

business, including entering into commercial arrangements with 

third parties, based on the premise that the performance and 

operations of any of their facilities is substantially dependent 

on the performance and operation of other facilities, including 

ones they neither own nor operate. For example, when an EGU goes 

off-line to perform maintenance, its customer base is served by 

other EGUs that increase their generation. Similarly, if an EGU 

needs to assure that it can meet its obligations to supply a 

certain amount of generation, it may enter into arrangements to 

purchase that generation, if it needs to, from other EGUs. 

Because of this structure, fossil fuel-fired EGUs can 

reduce their emissions by taking the actions in building blocks 

2 and 3. Specifically, fossil fuel-fired EGUs may generate or 

cause the generation of increased amounts of lower- or zeroemitting electricity –- through contractual arrangements, 
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investment, or purchase -- which will back out higher-emitting 

generation, and thereby lower emissions. In addition, fossil 

fuel-fired EGUs may reduce their generation, which, given the 

overall emission limits this rule requires, will have the effect 

of stimulating lower- or zero-emitting generation. 

It should also be noted that CO2 is particularly well-suited 

for building blocks 2 and 3 because it is a global, not local, 

air pollutant, so that the location where it is emitted does not 

affect its environmental impact. The U.S. Supreme Court in the 

UARG case highlighted the importance of taking account of the 

unique characteristics of CO2.530

In light of these characteristics of the utility power 

sector, as well as the characteristics of CO2 pollution, it is 

reasonable for the EPA to reject an interpretation of the term 

“system of emission reduction” that would exclude building 

blocks 2 and 3 from consideration in this rule and instead 

restrict consideration to measures integrated into each 

individual affected source’s design or operation, especially 

since the record and other publicly available information makes 

abundantly clear how effective the two building blocks are in 

reducing emissions and how widely those measures are already 

being used. 

 

530 See UARG v. EPA, 134 S. Ct. 2427, 2441 (2014). 
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As discussed above, no such restriction on the measures 

that can be considered part of a “system of emission reduction” 

is required by the statutory language, and the legislative 

history demonstrates that Congress intended a broad 

interpretation of the phrase. The narrow interpretation 

advocated by some commenters would permit consideration only of 

potential CO2 reduction measures that are either more expensive 

than building blocks 2 and 3 (such as the use of natural gas cofiring at affected EGUs or the application of CCS technology) or 

measures capable of achieving far less reduction in CO2 emissions 

(such as the heat rate improvement measures included in building 

block 1). Imposing such a restrictive interpretation –- one 

which is not called for by the statute -- would be inconsistent 

with CAA section 111’s specific requirement that standards be 

based on the “best” system of emission reduction and, as 

discussed below, would be inconsistent with Congressional design 

that the CAA be comprehensive and address the major 

environmental issues.531 

The unique characteristics of the sector described above 

require coordinated action in the fundamental, primary function 

of EGUs – and in meeting current pollution control requirements 

 

531 See King v. Burwell, No. 14-114 (2015) (slip op., at 21) 

(“But in every case we must respect the role of the Legislature, 

and take care not to undo what it has done.”). 

Deleted: even 

Deleted: nullify any serious efforts to fulfill 

the CAA’s overall environmental promise and 

address the most pressing 

Deleted: of our time
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to the extent that EGUs operate in dispatch systems that apply 

variable costs in determining dispatch -- and affected EGUs 

necessarily already plan and operate on a multi-unit basis. In 

doing so, they already make use of building blocks 2 and 3 to 

meet operational and environmental objectives in a costeffective manner, as further described below. CO2 is a global 

pollutant that is exceptionally well-suited to emission 

reduction efforts optimized on a broad geographic scale rather 

than on a unit-by-unit basis. It is also clear from both 

comments and communications received through the Agency’s 

outreach efforts that affected EGUs will seek to use building 

blocks 2 and 3 to achieve compliance with the emission standards 

set in the section 111(d) plans following promulgation of this 

rule. For these reasons –- and the additional reasons discussed 

below -- interpreting “system of emission reduction” so as to 

allow consideration in this rule of only the individual pieces 

of the “complex machine,” and to forbid consideration of the 

ways in which the pieces actually fit and work together as parts 

of that machine, such as building blocks 2 and 3, cannot be 

justified. This is particularly so in light of the dilemma 

presented by the types of control options that commenters argue 

are the only ones authorized under section 111(a)(1), which are 

controls that apply to the design or operation of the affected 
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EGUs themselves. On the one hand, the control measures in 

building block 1 yield only a small amount of emission 

reductions. On the other hand, control measures such as carbon 

capture and storage, or co-firing with natural gas, could yield 

much greater emission reductions, but are substantially more 

expensive than building blocks 2 and 3. 

(2) Current implementation of measures in building blocks 2 

and 3. 

The requirement that the “system of emission reduction” be 

“adequately demonstrated” suggests that we begin our review 

under CAA section 111(d)(1) and (a)(1) with the systems that 

sources are already implementing to reduce their emissions. As 

noted above, fossil fuel-fired EGUs have long implemented, and 

are continuing to implement, the measures in building blocks 2 

and 3 for various purposes, including for the purpose of 

reducing CO2 emissions532 –- and certainly always with the effect 

of reducing emissions. This is a strong indicator that these 

 

532 A number of utilities have climate mitigation plans. Examples 

include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 
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measures should be considered part of a “system of emission 

reduction” for CO2 emissions from these sources. The requirement 

that the “system of emission reduction” be “adequately 

demonstrated” indicates that the implementation of control 

mechanisms or other actions that the sources are already taking 

to reduce their emissions are of particular relevance in 

establishing the emission reduction requirements of CAA section 

111(d)(1) and (a)(1). As a result, such measures are a logical 

starting point for consideration as a “system of emission 

reduction” under CAA section 111. 

(3) Reliance in CAA Title IV on building block measures. 

Some of the building block approaches to reducing emissions 

in the utility power sector were first tested around the time 

that Congress adopted the 1970 CAA Amendments.533 Over time, 

these techniques have become more established within the 

industry, and by the 1990 CAA Amendments, Congress even based 

the Title IV acid rain program for existing fossil fuel-fired 

EGUs in part on the same measures that are considered here. This 

provides an important indication that Congress not only viewed 

such measures as effective emission control techniques but that 

 

533 See, e.g., Shepard, Donald S., A Load Shifting Model for Air 

Pollution Control in the Electric Power Industry, Journal of the 

Air Pollution Control Association, Vol. 20:11, pp. 756-761 

(November 1970). 
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these same measures had been implemented by the industry for at 

least twenty years. 

(a) Overview. 

It is logical that in determining whether the “system of 

emission reduction” that Congress established in CAA section 

111(d)(1) and (a)(1) is broad enough to include the measures in 

building blocks 2 and 3 as the basis for establishing emission 

guidelines for fossil fuel-fired EGUs, an inquiry should be made 

into the tools that Congress relied on in other CAA provisions 

to reduce emissions from those same sources. The most useful CAA 

provision to examine for this purpose is Title IV, which 

includes a nationwide cap-and-trade program under which coalfired power plants must have allowances for their sulfur dioxide 

emissions. 

Title IV includes several signals that it is especially 

relevant for interpreting and implementing CAA section 111(d) 

for purposes of this rule. Title IV applies to most of the same 

sources that this rule applies to -- existing coal-fired EGUs 

and other utility boilers, as well as NGCC units. In addition, 

Congress added Title IV in the 1990 CAA Amendments at the same 

time that Congress largely reinstated the 1970-vintage reading 

of section 111(a)(1) to adopt the currently applicable 

definition of a “standard of performance,” which is based on the 
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“best system of emission reduction ... adequately demonstrated.” 

Moreover, Congress linked Title IV and CAA section 111 in 

certain respects. Specifically, Congress conditioned the 

revisions to CAA section 111(a)(1), i.e., eliminating the 

percentage reduction and most of the other limitations under the 

1977 CAA Amendments, on the continued applicability of the Title 

IV SO2 cap, so that if the cap were eliminated, the changes 

would, by operation of law, also be eliminated, and the 1977 

version of section 111(a)(1) would be reinstated.534

Additionally, Congress authorized the EPA to establish standards 

of performance for new and existing industrial (non-EGU) sources 

of SO2 emissions if emissions from these sources might exceed 

1985 levels and failed to decline at the expected rate.535 While 

 

534 1990 CAA Amendments, § 403, 104 Stat. at 2631 (requiring 

repeal of amendments to CAA section 111(a)(1) upon any cessation 

of effectiveness of CAA section 403(e), which requires new units 

to hold allowances for each ton of sulfur dioxide emitted). 

Congress believed that mandating a technological standard 

through the percentage reduction requirement in section 

111(a)(1) would ensure the continued availability of low sulfur 

coal for existing sources. In other words, the percentage 

reduction requirement discouraged compliance with new source 

performance standards based solely on fuel shifting because it 

was much more costly to achieve the percentage reduction with 

lower sulfur coal. This belief was expressed during the 1977 CAA 

Amendments and is discussed above as part of the legislative 

history of section 111. 

535 1990 CAA Amendments, § 406, 104 Stat. at 2632-33; see also

Sen. Rep. No. 101-228, at 282 (industrial source emissions 

totaled 5.6 million tons of SO2 in 1985). 
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industrial sources were not required to participate under Title 

IV -- they could elect to do so, under CAA section 410(a) -- 

Congress believed SO2 reductions from these sources were “an 

essential component of the reductions sought under [Title IV]” 

and intended that Title IV would “assure[] that these projected 

reductions occur and will not be overcome by future growth in 

emissions.”536 As such, Congress viewed federal standards of 

performance as the appropriate backstop to Title IV even for 

sources that could not otherwise be regulated under CAA section 

111(d).537 Together, these signals suggest that it is reasonable 

for the EPA to consider Title IV when interpreting and 

implementing CAA section 111. 

For present purposes, the essential features of Title IV 

are that it regulates SO2 emissions from coal-fired EGUs by 

adopting a nationwide cap of 8.95 million tons to be achieved 

through a tradable allowance system. As we explain below, the 

provisions of Title IV and its legislative history make clear 

that Congress based the stringency of the emission limitation 

requirement (8.95 million tons) and the overall structure of the 

approach (a cap-and-trade system) on Congress’s recognition that 

 

536 Sen. Rep. No. 101-228, at 345 (Dec. 20, 1989). 537 To reiterate, ordinarily, standards of performance cannot be 

used to regulate SO2 emissions from existing sources because of 

the pollutant exclusions in CAA section 111(d). 
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the affected EGUs had a set of tools available to them to reduce 

their emissions, including through a shift to lower emitting 

generation and use of renewable energy, along with add-on 

controls and other measures. Thus, Title IV provides a close 

analogy to CAA section 111: generation shift and renewable 

energy were part of Congress’s basis for the Title IV emissions 

requirements, and that is analogous to building blocks 2 and 3 

serving as part of the “system of emission reduction” that is 

the EPA’s basis for the section 111(d) emission guidelines. For 

this reason, the fact that in Title IV, Congress relied on 

generation shift and renewable energy as the basis for the SO2

emission limitations for affected EGUs strongly supports 

interpreting CAA section 111(d)(1) and (a)(1) to include use of 

those same measures as part of the “system of emission 

reduction” as the basis for CO2 emission limitations for those 

same sources. 

(b) Title IV provisions. 

Several provisions of Title IV make explicit Congress’s 

reliance on some of the same measures as are in building blocks 

2 and 3. Title IV begins with a statement of congressional 

“findings,” including the following: 

§401(a). Findings 

The Congress finds that – 
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* * * * 

(4) strategies and technologies for the control of 

precursors to acid deposition exist now that are 

economically feasible, and improved methods are 

expected to become increasingly available over the 

next decade. 

(Emphasis added.) Title IV then includes the following statement 

of its “purposes:” 

§401(b). Purposes 

The purpose of this subchapter [Title IV] is to reduce 

the adverse effects of acid deposition through 

reductions in annual emissions of sulfur dioxide ... and 

nitrogen oxides.... It is the intent of this subchapter 

to effectuate such reductions by requiring compliance 

by affected EGUs with prescribed emission limitations 

by specified deadlines which limitations may be met 

through alternative methods of compliance provided by 

an emission allocation and transfer system. It is also 

the purpose of this subchapter to encourage energy 

conservation, use of renewable and clean alternative 

technologies, and pollution prevention as a long-range 

strategy, consistent with the provisions of this 

subchapter, for reducing air pollution and other 

adverse impacts of energy production and use. 

(Emphasis added). By its terms, this statement of Title IV’s 

purposes explicitly embraces the use of renewable energy. 

Moreover, the legislative history makes clear that the reference 

in the “findings” section quoted above to “strategies and 

technologies” includes generation shift to lower-emitting 

generation. Specifically, the Senate Report stated that an 
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Page 565 of 1544

“allowance system”538 would encourage such “technologies and 

strategies” as 

energy efficiency; enhanced emissions reduction or 

control technologies—like sorbent injection, cofiring 

with natural gas, integrated gasification combined 

cycles; fuel-switching and least-emissions dispatching

in order to maximize emissions reductions.”539 

Congress’s reliance on generation shifting and renewable energy 

to reduce acid rain precursors from affected EGUs in Title IV 

strongly supports the EPA’s authority to identify those same 

measures as part of the CAA section 111 “system of emission 

reduction” to reduce CO2 emissions from those same sources. 

 In addition, Title IV includes other provisions expressly 

concerning renewable energy. In CAA section 404(f) and (g), 

Congress set aside a special pool of allowances to encourage use 

of renewable energy. In order to obtain a special allowance 

(which would authorize emissions from a coal-fired utility), an 

electric utility needed to pay for qualifying renewable energy 

sources “directly or through purchase from another person.”540

These measures confirm Congress’s recognition that renewable 

energy was available to the industry, was desirable to encourage 

from a policy perspective, and was appropriate to consider in 

 

538 See Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989). 539 See Sen. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 

added). 

540 CAA section 404(f)(2)(B)(i). 
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determining the amount of pollution reduction the law should 

require. 

(c) Title IV legislative history. 

Numerous statements in the legislative history confirm that 

Congress based the Title IV requirements on the fact that 

affected EGUs could reduce their SO2 emissions through a set of 

measures, including shifting to lower-emitting generation as 

well as reliance on renewable energy. 

For example, the Senate Committee Report541 and Senator 

Baucus,542 a member of the Senate Committee on Environment and 

Public Works and Chairman of the House and Senate Clean Air 

Conferees, both emphasized that affected EGUs could rely on, 

among other things, “least-emissions dispatching in order to 

maximize emissions reductions.” Similarly, statements supporting 

the renewable energy reserve were included in the legislative 

history on the House side. 

We believe that this provision of the bill will 

establish a balanced and workable approach that will 

provide certainty for utility companies that are 

considering conservation and renewables, while at the 

 

541 Sen. Rep. No. 101-228 (Dec. 20, 1989), 1990 CAA Legis. Hist. 

at 8656 

542 Sen. Debates on Conf. Rep. to accompany S. 1630, H. Rep. 101-

952 (Oct. 27, 1990), 1990 CAA Legis. Hist. at 1033-35 (statement 

of Senator Baucus, inserting “the Clean Air Conference Report” 

into the record). 
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same time strengthening the environmental goals of 

this legislation.543 

 (4) Reliance on renewable energy measures to reduce carbon 

dioxide. 

The Title IV legislative history also makes clear that 

Congress viewed renewable energy measures as a means to reduce 

carbon dioxide for the purpose of mitigating climate change. By 

the time of the 1990 CAA Amendments, Congress had long been 

aware that emissions of carbon dioxide and other greenhouse 

gases put upward pressure on world temperatures and threatened 

to change the climate in destructive ways. In 1967, President 

Lyndon Johnson sent a letter to Congress recognizing that carbon 

dioxide was changing the composition of the atmosphere.544 The 

 

543 H.R. Rep. No. 101-490, at 368-69; 674-76 (May 17, 1990) 

(additional views of Reps. Markey and Moorhead) (“We believe 

that H.R. 3030, as amended, will create a strong and effective 

incentive for utilities to immediately pursue energy 

conservation and renewable energy sources as key components of 

their acid rain control strategies.”); see also Rep. Collins, H. 

Debates on H.R. Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA 

Legis. Hist. at 1307 (“The bottom line is that our Nation's 

utilities and production facilities must reach beyond coal, oil, 

and fossil fuels. The focus must shift instead toward 

conservation and renewables such as hydropower, solar thermal, 

photovoltaics, geothermal, and wind. These clean sources and 

energy, available in virtually limitless supply, are the way of 

the future.”). 

544 “Special Message to the Congress on Conservation and 

Restoration of Natural Beauty (Feb. 8, 1965). 

http://www.presidency.ucsb.edu/ws/?pid=27285 (“This generation 

has altered the composition of the atmosphere on a global scale 

through radioactive materials and a steady increase in carbon 

dioxide from the burning of fossil fuels.”). 
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record for the 1970 CAA Amendments include hearings545 and a 

report by the National Academy of Sciences noting that carbon 

dioxide emissions could heat the atmosphere.546 A 1976 report 

noting the phenomenon was included in the record for the 1977 

CAA Amendments.547 A 1977 Report by the National Academy of 

Sciences warned that average temperatures would rise due to the 

burning of fossil fuel.548 By the time of the 1990 CAA 

 

545 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381 (stating that “the carbon dioxide balance might result 

in the heating up of the atmosphere whereas the reduction of the 

radiant energy through particulate matter released to the 

atmosphere might cause reduction in radiation that reaches the 

earth”). 

546 1970 CAA Legis. Hist. at 244, 257 Sen. Debate on S. 4358 

(Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter 

IV of the Council on Environmental Quality’s first annual 

report, which states, “the addition of particulates and carbon 

dioxide in the atmosphere could have dramatic and long-term 

effects on world climate.”). 

547 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) (statement of 

Sen. Bumpers) (inserting into the record, “Summary of Statements 

Received from Professional Societies for the Hearings on Effects 

of Chronic Pollution (in the Subcommittee on the Environment and 

the Atmosphere),” which stated, “there is near unanimity that 

carbon dioxide concentrations in the atmosphere are increasing 

rapidly. Though even the direction (warming or cooling) of the 

climate change to be caused by this is unknown, very profound 

changes in the balance of climate factors that determine 

temperature and rainfall on the earth are almost certain within 

100 years”). 

548 National Academy of Sciences, “Energy and Climate: Studies in 

Geophysics” viii (1977), 

http://www.nap.edu/openbook.php?record_id=12024 (noting that a 

fourfold to eightfold increase in carbon dioxide by the latter 
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Amendments, the dangers had become more clearly evident. Senate 

hearings beginning in 1988 had presented testimony from Dr. 

James E. Hansen of the National Aeronautics and Space 

Administration and other scientists that described the dangers 

of climate change caused by anthropogenic carbon dioxide and 

other greenhouse gas emissions and asserted that as a result of 

those emissions, the climate was in fact already changing.549 

 In enacting the 1990 CAA Amendments, Congress identified 

reductions in carbon dioxide emissions as an important cobenefit of the reductions in coal use and stressed that the 

renewable energy measures would achieve those reductions. 

Senator Fowler, the author of the provision that established a 

renewable energy technology reserve within the allowance system, 

noted that renewable energy technologies, “can greatly reduce 

emissions of ... global warming gases. That makes them a potent 

 

part of the twenty-second century would increase average world 

temperature by more than 6 degrees Celsius). 

549 Sen. Rep. No. 101-228, at 322 (Dec. 20, 1989), at 1990 Leg. 

Hist. at 8662 (“In the last several years, the Committee has 

received extensive scientific testimony that increases in the 

human-caused emissions of carbon dioxide and other greenhouse 

gases will lead to catastrophic shocks in the global climate 

system.”); History, Jurisdiction, and a Summary of Activities of 

the Committee on Energy and Natural Resources During the 100th

Congress, Sen. Rep. No. 101-138, at 5 (Sept. 1989); “Global 

Warming Has Begun, Expert Tells Senate,” New York Times, June 

24, 1988, http://www.nytimes.com/1988/06/24/us/global-warminghas-begun-expert-tells-senate.html. 
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weapon against catastrophic climate change....”550 In addition, 

the 1990 CAA Amendments required EGUs covered by the monitoring 

requirements of the Title IV acid rain program to report their 

CO2 emissions.551 

(5) Other EPA actions that rely on the building block 

measures. 

Another indication that it is reasonable to interpret the 

CAA section 111(d)(1) and (a)(1) provisions for the BSER to 

include the measures in building blocks 2 and 3 is that the EPA 

and states have relied on these measures to reduce emissions in 

a number of other CAA actions. 

For example, in 2005, the EPA promulgated a rule to control 

mercury emissions from fossil fuel-fired power plants under 

section 111(d): the Clean Air Mercury Rule (CAMR).552 The EPA 

established a nationwide cap-and-trade program that took effect 

in two phases: In 2010, the cap was set at 38 tons per year, and 

in 2018, the cap was lowered to 15 tons per year. The EPA 

expected, on the basis of modeling, that sources would achieve 

the second phase, 15-ton per year cap cost-effectively by 

choosing among a set of measures that included shifting 

 

550 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 

Legis. Hist. at 7106. 

551 1990 CAA Amendments, § 821, 104 Stat. at 2699. 552 70 FR 28606 (May 18, 2005). 
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generation to lower-emitting units.553 CAMR was vacated by the 

D.C. Circuit on other grounds,554 but it shows that in the only 

other section 111(d) rule that the EPA attempted for affected 

EGUs, the EPA relied on shifting generation as part of the BSER 

in a CAA section 111(d) rulemaking for fossil fuel-fired EGUs. 

In 2011, the EPA promulgated the Cross State Air Pollution 

Rule (CSAPR),555 in which it set statewide emission budgets for 

NOx and SO2 emitted by fossil fuel-fired EGUs, and based those 

standards in part on shifts to lower-emitting generation. CSAPR 

established state-wide emissions budgets based on a range of 

cost-effective actions that EGUs could take, and set the 

stringency of the deadlines for some required reductions in part 

because of the availability of “increased dispatch of loweremitting generation which can be achieved by 2012.”556 The EPA 

developed a federal implementation plan (FIP) that established a 

 

553 70 FR 28606, 28619 (May 18, 2005) (“Under the CAMR scenario 

modeled by EPA, units [were] projected to meet their SO2 and NOx

requirements and take additional steps to address the remaining 

[mercury] reduction requirements under CAA section 111, 

including adding [mercury]-specific control technologies (model 

applies [activated carbon injection]), additional scrubbers and 

[selective catalytic reduction], dispatch changes, and coal 

switching.”). 

554 New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008),

cert. denied sub nom. Util. Air Reg. Group v. New Jersey, 555 

U.S. 1169 (2009). 

555 76 Fed. Reg. 48208 (Aug. 8, 2011). 556 76 Fed. Reg. at 48452. 
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trading program to meet the state-wide emission budgets set by 

CSAPR. The EPA projected that sources would meet their emission 

reduction obligations by implementing a range of emission 

control approaches, including the operation of add-on controls, 

switches to lower-emitting coal, and “changes in dispatch and 

generation shifting from higher emitting units to lower emitting 

units.”557 The U.S. Supreme Court upheld CSAPR in EPA v. EME 

Homer City Generation, L.P.558

 With respect to renewable energy, in 2004, the EPA provided 

guidance to states for adopting attainment SIPs under CAA 

section 110 that include renewable energy measures.559 Some 

 

557 76 FR at 48279-80. The exact mix of controls varied for 

different air pollutants and different time periods, but in all 

cases, shifting generation from higher to lower emitting units 

was one of the expected control strategies for the fossil fuelfired power plants. Prior to CSAPR, the EPA promulgated two 

other transport rules, the NOx SIP Call (1998) and the Clean Air 

Interstate Rule (CAIR) (2005), which similarly established 

standards based on analysis of the availability and cost of 

emission reductions achievable through the use of add-on 

controls and generation shifting, and also authorized and 

encouraged the implementation of renewable energy and demandside energy efficiency measures. CAIR: 70 Fed. Reg. 25162, 

25165, 25256, 25279 (May 12, 2005) (allowing use of allowance 

set-asides for renewables and energy efficiency); NOx SIP Call: 

63 Fed. Reg. 57356, 57362, 57436, 57438, 57449 (Oct. 27, 1998) 

(authorizing and encouraging SIPs to rely on renewables and 

energy efficiency to meet the state budgets). 

558 134 S. Ct. 1584 (2014). 559See, e.g., Guidance on SIP Credits for Emission Reductions 

from Electric-Sector Energy Efficiency and Renewable Energy 

Measures (Aug. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; 
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states have done so. For example, Connecticut included in its 

SIP reductions from solar photovoltaic installations.560 In 2012, 

the EPA provided additional guidance on this topic.561 In 

addition, the EPA has partnered with the Northeast States for 

Coordinated Air Use Management (NESCAUM) and three states 

(Maryland, Massachusetts, and New York) to identify 

opportunities for including renewable energy in a SIP and to 

provide real-world examples and lessons learned through those 

states’ case studies.562

(6) Other rules that relied on actions by other entities. 

The EPA has promulgated numerous actions that establish 

control requirements for affected sources on the basis of 

actions by other entities or actions other than measures 

 

Incorporating Emerging and Voluntary Measures in a State 

Implementation Plan (SIP) (Sept. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf. 560 CT 1997 8-hour ozone SIP Web site, 

http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1

619 (see Attainment Demonstration TSD, Chapter 8 at 31, 

http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_rep

orts/section_8.pdf). 561 “Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs” (July 2012), 

http://epa.gov/airquality/eere/manual.html.

562 States’ Perspectives on EPA’s Roadmap to Incorporate Energy 

Efficiency/Renewable Energy in NAAQS State Implementation Plans: 

Three Case Studies, Final Report to the U.S. Environmental 

Protection Agency (Dec. 2013), 

http://www.nescaum.org/documents/nescaum-final-rept-toepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf. 
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integrated into the design or operations of the affected 

sources. This section summarizes some of those actions. First, 

virtually all pollution control requirements require the 

affected sources to depend in one way or another on other 

entities, such as control technology manufacturers. Second, the 

EPA has promulgated numerous regulatory actions that are based 

on trading of mass-based emission allowances or rate-based 

emission credits, in which many sources meet their emission 

limitation requirements by purchasing allowances or credits from 

other sources that reduce emissions. 

(a) Third-party transactions. 

To reiterate, commenters argue that the “system of emission 

reduction” must be limited to measures taken by the affected 

source itself because only those measures are under the control 

of the affected source, as opposed to third parties, and 

therefore only those measures can assure that the affected 

source will achieve its emission limits. But this argument is 

belied by the fact that for a wide range of pollution control 

measures – including many that are indisputably part of a 

“system of emission reduction” – affected sources are in fact 

dependent on third parties. For example, to implement any type 

of add-on pollution control equipment that is available only 

from a third-party manufacturer, the affected source is 
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dependent upon that third party for developing and constructing 

the necessary controls, and for offering them for sale. Indeed, 

the affected sources may be dependent upon third parties to 

install the controls as well, and in fact, in the CAIR rule, the 

EPA established the compliance date based on the limited 

availability of the specialized workforce needed to install the 

controls needed by the affected EGUs.563 In addition, EGU owners 

and operators may be dependent on the actions of third parties 

to finance the controls and third-party regulators to assure the 

mechanism for repaying that financing. However, this dependence 

does not mean that the emission limit based on that equipment is 

not achievable. Rather, the fact that the owner or operator of 

the affected source can arrange with the various third parties 

to acquire, install, and pay for the equipment means that 

emission limit is achievable. 

In this rule, as noted, the affected EGUs may, in many 

cases, implement the measures in building blocks 2 and 3 

directly, and, in other cases, implement those measures by 

engaging in market transactions with third parties that are as 

much within the affected EGUs’ control as engaging in market 

 

563 70 Fed. Reg. 25162, 25216–25225 (May 12, 2005). The EPA noted 

that its view was “based on the NOX SIP Call experience.” Id. at 

25217. 
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transactions with the range of third parties involved in 

pollution control equipment. By the same token, the market 

transactions that the affected EGUs engage in with third parties 

to implement the measures in building blocks 2 and 3 are 

comparable to the market transactions that affected EGUs engage 

in as part of their normal course of business, which include, 

among many examples, transactions with RTOs/ISOs or balancing 

authorities, entities in organized markets. 

(b) Emissions trading. 

Additional precedent that the “system of emission 

reduction” may include the measures in building blocks 2 and 3 

and is not limited to measures that a source can integrate into 

its own design or operations, without being dependent on other 

entities, is found in the many rules that Congress has enacted 

or that the EPA has promulgated that allow EGUs and other 

sources to meet their emission limits by trading with other 

sources. In a trading rule, the EPA authorizes a source to meet 

its emission limit by purchasing mass-based emission allowances 

or rate-based emission credits generated from other sources, 

typically ones that implement controls that reduce their 

emissions to the point where they are able to sell allowances or 

credits. As a result, the availability of trading reduces 

overall costs to the industry by focusing the controls on the 
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particular sources that have the least cost to implement 

controls. For present purposes, what is relevant is that in a 

trading program, some affected sources choose to meet their 

emission limits not by implementing emission controls integrated 

into their own design or operations, but rather by purchasing 

allowances or credits. These affected sources, therefore, are 

dependent on the actions of other entities, which are the ones 

that choose to meet their emission limits by implementing 

emission controls, which permits them to sell allowances or 

credits. They are “dependent”, however, in exactly the same way 

that a source acquiring pollution control technology for the 

purposes of meeting a NSPS is “dependent” on a vendor of that 

technology to fulfill its contractual obligations. Just so for 

the source operator purchasing a credit or an allowance. In 

essence, the purchasing operator is acquiring an equity in the 

technology or action applied to the credit-selling source for 

purposes of achieving a reduction in emissions occurring at the 

selling source. Trading programs have been commonplace under the 

CAA, particularly for EGUs, for decades. They include the acid 

rain trading program in Title IV of the CAA, the trading 

programs in the transport rules promulgated by the EPA under the 

“good neighbor provision” of CAA section 110(a)(2)(D)(i)(I), the 

Clean Air Mercury Rule, and the regional haze rules. In each of 
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these actions, the Congress or the EPA recognized that some of 

the affected EGUs would implement controls or take other actions 

that would lower their emissions and thereby allow them to sell 

allowances to other EGUs, which were dependent on the purchase 

of those allowances to meet their obligations.564 For the reasons 

just described, these trading rules refute commenters’ arguments 

for limiting the scope of the “system of emission reduction.” 

 (c) NSPS rules for EGUs that depend on the integrated 

grid. The EPA has promulgated NSPS for EGUs that include 

requirements based on the fact that an EGU may reduce its 

generation, and therefore its emissions, because the integration 

of the grid allows another EGU to increase generation and 

thereby avoid jeopardizing the supply of electricity. For 

 

564 For example, in the enacting the acid rain program under CAA 

Title IV, Congress explicitly recognized that some sources would 

comply by purchasing allowances instead of implementing 

controls. Sen. Rep. No. 101-228, at 303 (Dec. 20, 1989). 

Similarly, in promulgating the NOx SIP Call in 1998, the EPA 

stated, “Since EPA's determination for the core group of sources 

is based on the adoption of a broad-based trading program, 

average cost-effectiveness serves as an adequate measure across 

sources because sources with high marginal costs will be able to 

take advantage of this program to lower their costs.” 63 FR at 

57399 (emphasis added). By the same token, in promulgating the 

Cross State Air Pollution Rule, the EPA stated, “the preferred 

trading remedy will allow source owners to choose among several 

compliance options to achieve required emission reductions in 

the most cost effective manner, such as installing controls, 

changing fuels, reducing utilization, buying allowances, or any 

combination of these actions.” 76 Fed. Reg. at 48272 (emphasis 

added). 
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example, in 1979, the EPA finalized new standards of performance 

to limit emissions of SO2 from new, modified, and reconstructed 

EGUs. In evaluating the best system against concerns of electric 

service reliability, the EPA took into account the unique 

features of power transmission along the interconnected grid and 

the unique commercial relationships that rely on those 

features.565

Additionally, in 1982, the EPA recognized that utility turbines 

could meet a NOx emission limit without unacceptable economic 

consequences because “other electric generators on the grid can 

restore lost capacity caused by turbine down time.”566 We 

describe the relevant parts of these rules in greater detail in 

the Legal Memorandum. 

(7) Consistency with the purposes of the Clean Air Act. 

Interpreting the term “system of emission reduction” 

broadly to include building blocks 2 and 3 (so that the “best 

system of emission reduction ... adequately demonstrated” may 

include those measures as long as they meet all of the 

 

565 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 

566 47 FR 3767, 3768 (Jan. 27, 1982). 
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applicable requirements) is also consistent with the purposes of 

the CAA. Most importantly, these purposes include protecting 

public health and welfare by comprehensively addressing air 

pollution, and, particularly, protecting against urgent and 

severe threats. In addition, these purposes include promoting 

pollution prevention measures, as well as the advancement of 

technology that reduces air pollution. 

(a) Purpose of protecting public health and welfare 

The first provisions in the Clean Air Act set out Congress’s 

findings and the CAA’s purposes. They provide as follows, in 

relevant part: 

Section 101. Congressional findings and declaration of 

purpose 

(a) The Congress finds— 

* * * * 

(2) that the growth in the amount and complexity of 

air pollution brought about by urbanization, 

industrial development, and the increasing use of 

motor vehicles, has resulted in mounting dangers to 

the public health and welfare * * * * 

(3) that air pollution prevention (that is, the 

reduction or elimination, through any measures, of the 

amount of pollutants produced or created at the 

source) and air pollution control at its source is the 

primary responsibility of States and local 

governments; and 

(4) that Federal financial assistance and leadership 

is essential for the development of cooperative 

Federal, State, regional, and local programs to 

prevent and control air pollution. 
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(b) The purposes of this title are— 

(1) to protect and enhance the quality of the Nation’s 

air resources so as to promote the public health and 

welfare and the productive capacity of its population; 

(2) to initiate and accelerate a national research and 

development program to achieve the prevention and 

control of air pollution; 

(3) to provide technical and financial assistance to 

State and local governments in connection with the 

development and execution of their air pollution 

prevention and control programs; and 

(4) to encourage and assist the development and 

operation of regional air pollution prevention and 

control programs. 

(c) POLLUTION PREVENTION.—A primary goal of this Act 

is to encourage or otherwise promote reasonable 

Federal, State, and local governmental actions, 

consistent with the provisions of this Act, for 

pollution prevention. 

As just quoted, these provisions are explicit that the 

purpose of the CAA is “to protect and enhance the quality of the 

Nation’s air resources so as to promote the public health and 

welfare and the productive capacity of its population.” 

Moreover, Congress designed the CAA to be “the comprehensive 

vehicle for protection of the Nation’s health from air 

pollution,”567 and, in fact, designed CAA section 111(d) to 

 

567 H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2509 (discussing a provision in the House Committee 

bill that became CAA section 122, requiring the EPA to study and 

regulate radioactive air pollutants and three other air 

pollutants). 
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address air pollutants not covered under other provisions, 

specifically so that “there should be no gaps in control 

activities pertaining to stationary source emissions that pose 

any significant danger to public health or welfare.”568

Furthermore, in these purpose provisions, Congress recognized 

that while pollution prevention and control are the primary 

responsibility of the States, “federal leadership” would be 

essential. 

At its core, Congress designed the CAA to address urgent 

and severe threats to public health and welfare. This purpose is 

evident throughout 1970 CAA Amendments, which authorized 

stringent remedies that were necessary to address those 

problems. By 1970, Congress viewed the air pollution problem, 

which had been worsening steadily as the nation continued to 

industrialize and as automobile travel dramatically increased 

after World War II,569 as nothing short of a national crisis.570

 

568 Sen. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420 (discussing section 114 of the Senate 

Committee bill, which was the basis for CAA section 111(d)). 

569 See Dewey, Scott Hamilton, Don’t Breathe the Air: Air 

Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 

University Press 2000).

570 1970 was a significant year in environmental legislation, but 

it was also marked as “a year of environmental concern.” Sen. 

Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. 

Hist. at 223. By mid-1970, Congress recognized that “[o]ver 200 

million tons of contaminants [were] spilled into the air each 

year in America.... And each year these 200 million tons of 

Deleted: in 1970 

Deleted: ,
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With the 1970 CAA Amendments, Congress enacted a stringent 

response, designed to match the severity of the problem. At the 

same time, Congress did not foreclose the EPA’s ability to 

address new environmental concerns; in fact, Congress largely 

deferred to the EPA’s expertise in identifying pollutants and 

sources that adversely affect public health or welfare. In doing 

so, Congress authorized the EPA to establish national ambient 

air quality standards for the most pervasive air pollutants -- 

including the precursors for the choking smog that blanketed 

urban areas571 --to protect public health with an ample margin of 

 

pollutants endanger the health of [the American] people.” Id. at 

224. “Cities up and down the east coast were living under clouds 

of smog and daily air pollution alerts.” Sen. Muskie, Sen. 

Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 

Legis. Hist. at 124. Put simply, America faced an “environmental 

crisis.” Sen. Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 224. The conference agreement, it was 

reported, “faces the air pollution crisis with urgency and in 

candor. It makes hard choices, provides just remedies, requires 

stiff penalties.” Sen. Muskie, Sen. Consideration of the 

Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

“[I]t represents [Congress’] best efforts to act with the 

knowledge available ... in an affirmative but constructive 

manner.” Id. at 150. 

571 See Dewey, Scott Hamilton, Don’t Breathe the Air: Air 

Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 

University Press 2000) at 230 (“By the mid-1960s, top federal 

officials showed an increasing sense of alarm regarding the 

health effects of polluted air. In June, 1966, Secretary of 

Health, Education, and Welfare John W. Gardner testified before 

the Muskie subcommittee: “We believe that air pollution at 

concentrations which are routinely sustained in urban areas of 

Deleted: and 
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safety. Disappointed that the states had not taken effective 

action to that point to curb air pollution, “Congress reacted by 

taking a stick to the States”572 and including within the 1970 

CAA Amendments both the requirement that the states develop 

plans to assure that their air quality areas would meet those 

standards by no later than five years, and the threat of 

imposition of federal requirements if the states did not timely 

adopt the requisite plans. Congress also required the EPA to 

establish standards for hazardous air pollutants that could 

result in shutting sources down. Congress added stringent 

controls on automobiles, overriding industry objections that the 

standards were not achievable. In addition, Congress added CAA 

section 111(b), which required the EPA to list categories based 

on harm to public health and regulate new sources in those 

categories. Congress then designed CAA section 111(d) to assure, 

as the Senate Committee Report for the 1970 CAA Amendments 

noted, that “there should be no gaps in control activities 

pertaining to stationary source emissions that pose any 

significant danger to public health or welfare.”573 

 

the United States is a health hazard to many, if not all, 

people.”). 

572 Train v. NRDC, 421 U.S. 60, 64 (1975). 573 Sen. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420 (discussing section 114 of the Senate 

Commented [A21]: Could this phraseology come back to bite 

EPA in a public relations context? 

Deleted: , and required 

Deleted: to 

Deleted: .
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Similarly, the 1977 and 1990 CAA Amendments were also 

designed to respond to new and/or pressing environmental issues. 

For example, in 1977 then-EPA Administrator Costle testified 

before Congress that the expected increase in coal use (in 

response to various energy crises, including the 1973-74 Arab 

Oil Embargo) “will make vigorous and effective control even more 

urgent.”574 Similarly, by 1990, Congress recognized that “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”575 Indeed, President 

George H. W. Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”576 

 

Committee bill, which was the basis for CAA section 111(d)). 

Note that in the 1977 CAA Amendments, the House Committee Report 

made a similar statement. H.R. Rep. No. 95-294, at 42 (May 12, 

1977), 1977 CAA Legis. Hist. at 2509 (discussing a provision in 

the House Committee bill that became CAA section 122, requiring 

EPA to study and then take action to regulate radioactive air 

pollutants and three other air pollutants). 

574 Statement of Administrator Costle, Hearings before the 

Subcommittee on Energy Production and Supply of the Senate 

Committee on Energy and Natural Resources (Apr. 5, 7, May 25, 

June 24 and 30, 1977), 1977 CAA Legis. Hist. at 3532 (discussing 

the relationship between the National Energy Plan and the 

Administration’s proposed CAA amendments). Some of the specific 

changes to the CAA include the addition of the PSD program, 

visibility protections, requirements for nonattainment areas, 

and stratospheric ozone provisions. 

575 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 576 H.R. Rep. No. 101-490, at 144 (May 17, 1990). Some of the 

changes adopted in 1990 include revisions to the NAAQS 

nonattainment program, a more aggressive and substantially 

revised CAA section 112, the new acid rain program, an operating 

permits program, and a program for phasing out of certain ozone 

depleting substances. 
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Much remains to be done with climate change. We are now at 

a critical juncture to take meaningful action to curb the growth 

in CO2 emissions and forestall the impending consequences of 

inaction. CO2 emissions from existing fossil fuel-fired power 

plants are by far the largest source of stationary source 

emissions. They emit almost 3 times as much CO2 as do the next 9 

stationary source categories combined, and approximately the

same amount of CO2 emissions from all of the nation’s mobile 

sources. The only controls available that can reduce CO2 

emissions from existing power plants in amounts commensurate 

with the problems they pose are the measures in building blocks 

2 and 3, or far more expensive measures such as CCS. 

Thus, interpreting the “system of emission reduction” 

provisions in CAA section 111(d)(1) and (a)(1) to allow the 

nation to meaningfully address the urgent and severe public 

health and welfare threats that climate change pose is 

consistent with what the CAA was designed to do.577 This 

 

577 In addition, as we have noted, in designing the 1970 CAA 

Amendments, Congress was aware that carbon dioxide increased 

atmospheric temperatures. In 1970, when Congress learned that 

“the carbon dioxide balance might result in the heating up of 

the atmosphere” and that particulate matter “might cause 

reduction in radiation,” the Nixon Administration assured 

Congress that “[w]hat we are trying to do, however, in terms of 

our air pollution effort should have a very salutary effect on 

either of these.” Testimony of Charles Johnson, Jr., 

Administrator of the Consumer Protection and Environmental 

Deleted: amount to

Deleted: of 

Deleted: emissions from 

Deleted: equal

Deleted: At present, however, no add-on 

controls are commercially available that will 

make anything other than small reductions in 

power plant CO2 emissions. 

Deleted: 
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interpretation is also consistent with the cooperative purpose 

of section 111(d) to assure that the CAA comprehensively address 

those threats through the mechanism of state plans, where the 

states assume primary responsibility under federal leadership. 

See King v. Burwell, 576 U.S. (2015), No. 14-114 (2015), slip 

op. at 15 (“We cannot interpret federal statutes to negate their 

own stated purposes” (quoting New York State Dept. of Social 

Servs. v. Dublino, 413 U.S. 405, 419-20 (1973)); id. at 21 (“A 

fair reading of legislation demands a fair understanding of the 

legislative plan.”).578

 

Health Service (Administration Testimony), Hearing of the House 

Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 

CAA Legis. Hist. at 1381. Many years later, scientific consensus 

has formed around the particular causes and effects of climate 

change; and the tools put in place in 1970 can be read fairly to 

address these concerns. 

578 This final rule is also consistent with the CAA’s purpose of 

protecting health and welfare. For example, the CAA authorizes 

the EPA to regulate air pollutants as soon as the EPA can 

determine that those pollutants pose a risk of harm, and not to 

wait until the EPA can prove that those pollutants actually 

cause harm. See H.R. Rep. No. 95-294, at 49 (May 12, 1977), 1977 

CAA Legis. Hist. at 2516 (describing the CAA as being 

designed... to assure that regulatory action can effectively 

prevent harm before it occurs; to emphasize the predominant 

value of protection of public health”). The protective spirit of 

the CAA extends to the present rule, in which the EPA regulates 

on the basis of building blocks 2 and 3 because the range of 

available and cost-effective measures in those building blocks 

achieves more pollution reduction than building block 1 alone. 

Indeed, add-on controls that are technically capable of reducing 

CO2 emissions at the scale necessitated by the severity of the 

environmental risk -– for example, CCS technology -- are not as 

cost-effective as building blocks 2 and 3 on an industry-wide 

Deleted: precautionary nature of the CAA.

Deleted: to have a “preventive or 

precautionary nature

Deleted: , i.e.,

Deleted: precautionary 

Deleted: nature 
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 (b) Purpose of encouraging pollution prevention. 

Interpreting “system of emission reduction” to include building 

blocks 2 and 3 is also consistent with the CAA’s purpose to 

encourage pollution prevention. CAA section 101(c) states that 

“[a] primary goal of [the CAA] is to encourage or otherwise 

promote reasonable federal, state, and local governmental 

actions, consistent with the provisions of this chapter, for 

pollution prevention.” Indeed, in the U.S. Code, in which the 

CAA is codified as chapter 85, the CAA is entitled, “Air 

Pollution Prevention and Control.”579 CAA section 101(a)(3) 

describes “air pollution prevention” as “the reduction or 

elimination, through any measures, of the amount of pollutants 

produced or created at the source”. (Emphasis added.) The 

reference to “any measures” highlights the breadth of what 

Congress considered to be pollution prevention, that is, any and 

all measures that reduce or eliminate pollutants at the 

source.580 

 

basis, and while the costs of the add-on controls can be 

expected to be reduced over time, it is not consonant with the 

protective spirit of the CAA to wait. 

579 See Air Quality Act of 1967, Pub. L. 90-148, § 2, 81 Stat. 

485 (Nov. 21, 1967) (adding “Title I—Air Pollution Prevention 

and Control” to the CAA, along with Congress’ initial findings 

and purposes under CAA section 101). 

580 Section 101 emphasizes the importance of air pollution 

prevention in two other provisions: CAA section 101(b)(4) states 

Deleted: precautionary 
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The measures in building blocks 2 and 3 qualify as 

“pollution prevention” measures because they are “any measures” 

that “reduc[e] or eliminate[e] ... the amount of pollutants 

produced or created at the [fossil fuel-fired affected] 

source[s].” Thus, consistent with the CAA’s primary goals, it is 

therefore reasonable to interpret a “system of emission 

reduction,” as including the pollution prevention measures in 

building blocks 2 and 3. 

(c) Purpose of advancing technology to control air 

pollution. 

This final rule is also consistent with the purpose of CAA 

section 111 to promote the advancement of pollution control 

technology, based on the expectation that American industry will 

be able to develop innovative solutions to the environmental 

problems. 

 The legislative history and case law of CAA section 111 

identify three different ways that Congress designed CAA section 

111 to authorize standards of performance that promote 

 

that one of “the purposes of [title I of the CAA, which includes 

section 111] are ... (b) to encourage and assist the development 

and operation of regional air pollution prevention and control 

programs.” CAA section 101(a)(3) adds: “The Congress finds -- 

... (3) that air pollution prevention ... and air pollution 

control at its source is the primary responsibility of states 

and local governments.” In fact, section 101 mentions pollution 

prevention no less than 6 times. 
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technological improvement: (i) the development of technology 

that may be treated as the “best system of emission reduction 

... adequately demonstrated;” under CAA section 111(a)(1);581

(ii) the expanded use of the best demonstrated technology;582 and 

(iii) the development of emerging technology.583 This rule is 

consistent with the second of those ways –- it expands the use 

of the measures in building blocks 2 and 3, which are already 

established and provide substantial reductions at reasonable 

cost. As discussed below, the use of the measures in these 

building blocks will be most fully expanded when organized 

markets develop, and our expectation that those markets will 

develop is consistent with the Congress’s view, just described, 

that CAA section 111 should promote technological innovation. 

This final rule is also consistent with Congress’s overall 

view that the CAA Amendments as a whole were designed to promote 

technological innovation. In enacting the CAA, Congress 

articulated its expectation that American industry would be 

 

581 See Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”). 

582 See Sen. Rep. No. 91-1196, at 15 (“The maximum use of 

available means of preventing and controlling air pollution 

is essential to the elimination of new pollution 

problems”). 

583 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 

standard of performance designed to promote the use of an 

emerging technology). 
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creative and come up with innovative solutions to the urgent and 

severe problem of air pollution. This is manifest in the wellrecognized technology-forcing nature of the CAA, and was 

expressed in numerous, sometimes ringing, statements in the 

legislative history about the belief that American industry will 

be able to develop the needed technology. For example, in the 

1970 floor debates, Congress recalled that the nation had put a 

man on the moon a year before and had won World War II a quarter 

century earlier, and attributed much of the credit for those 

singular achievements to American industry and its ability to be 

productive and innovative. Congress expressed confidence that 

American industry could meet the challenges of developing air 

pollution controls as well.584 

(d) Response to commenters concerning purpose. Commenters 

have stated that the proposed rule “would transform CAA section 

 

584 Sen. Muskie, Sen. Debates on S. 4358 (Sept. 21, 1970), 1970 

CAA Legis. Hist. at 227 (“At the beginning of World War II 

industry told President Roosevelt that his goal of 100,000 

planes each year could not be met. The goal was met, and the war 

was won. And in 1960, President Kennedy said that America would 

land a man on the moon by 1970. And American industry did what 

had to be done. Our responsibility in Congress is to say that 

the requirements of this bill are what the health of the Nation 

requires, and to challenge polluters to meet them.”). See 

Blaime, A.J., The Arsenal of Democracy: FDR, Detroit, and an 

Epic Quest to Arm an America at War (Houghton Mifflin Harcourt 

2014); Carew, Michael G., Becoming the Arsenal: The American 

Industrial Mobilization for World War II, 1938-1942 (University 

Press of America, Inc. 2010).

Deleted: earlier
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111 into something untethered to its statutory language and 

unrecognizable to the Congress that created it.”585 Commenters 

with this line of comments focused on the ramifications of 

building block 4, which the EPA has decided does not belong in 

BSER using EPA’s historic interpretation of BSER. Regardless of 

whether the comments are accurate with respect to building block 

4 measures, they are certainly not accurate with respect to the 

three building blocks that the EPA is defining as the BSER. 

This rule would be recognizable to the Congresses that created 

and amended CAA section 111 and is carefully fashioned to the 

statutory text in CAA section 111(d) and (a)(1). This final rule 

would be recognizable to the Congress that adopted CAA section 

111 in 1970 as part of a bold,far-reaching law designed to 

address comprehensively an air pollution crisis that threatened 

the health of millions of Americans; to have EPA and the States 

work cooperatively to develop state-specific approaches to 

address a national problem;; to challenge industry to meet that 

crisis with the same creative energy that won World War II; and 

to give the EPA broad authority –- under section 111 and other 

provisions –- to craft the needed emission limitations. This 

 

585 UARG comment at 31. See id. at 18, 29, 49. This comment 

appears to be a reference to the Supreme Court’s statement in 

UARG. See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 

(2014). 

Deleted: On the contrary, we believe that t

Deleted: stringent

Deleted: , comprehensive 

Deleted: the

Deleted: ,

Deleted: “tak[e] a stick to the States”586

Deleted: by including stringent timetables, 

with the threat of imposition of a Federal 

plan

Deleted: that 

Deleted: d

Deleted: ,

Deleted: that gave 
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final rule would be recognizable to the Congress that revised 

CAA section 111 in 1977 to explicitly authorize that standards 

be based on actions taken by third parties (fuel cleaners). And 

this final rule would be recognizable to the Congress that 

revised CAA section 111 in 1990 to be linked to the Acid Rain 

Program that Congress adopted at the same time, which regulated 

the same industry (fossil fuel-fired EGUs) through some of the 

same measures (generation shifts and renewable energy), and that 

explicitly acknowledged that those measures (renewable energy) 

would also reduce carbon dioxide and thereby address the dangers 

of climate change. To reiterate, for the reasons explained in 

this preamble, this rule is grounded in our reasonable 

interpretation of CAA section 111(d) and (a)(1). 

(9) Response to comments concerning building blocks 2 and 3 

as precedents. 

Commenters expressed concern that reliance on building 

blocks 2 and 3 would set a precedent for the EPA to rely on 

similar measures in promulgating future air pollution 

controls.587 For example, commenters asserted that the EPA could 

“develop standards of performance for tailpipe emissions from 

 

587 Most of the commenters’ concerns over what they viewed as the 

precedential effects of the building blocks concerned building 

block 4. Because the EPA is not finalizing building block 4 as 

part of the BSER, it is not necessary to address those concerns. 

Deleted: Above all
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motor vehicles” by “requiring car owners to shift some of their 

travel to buses,” which the commenters considered analogous to 

building block 2; “or by requiring there to be more electric 

vehicle purchases,” which the commenters considered analogous to 

building block 3.588

As discussed above, the emission limits in the CAA section 

111(d) emission guidelines that this rule promulgates are based 

on the EPA’s determination, for the affected EGUs, of the 

“system of emission reduction” that is the “best,” taking into 

account “cost” and other factors, and that is “adequately 

demonstrated.” Those components include certain interpretations 

and applications. For example, because the affected EGUs must be 

able to achieve their emission standards through application of 

the BSER, the BSER must be something that the EGUs themselves 

can implement. Likewise, because the emission standards must 

apply to the affected source category, actions taken by affected 

sources that do not result in emission reductions from the 

source category –- that is, offsets (e.g., the planting of 

forests to sequester CO2) –- do not qualify for inclusion in the 

BSER. Furthermore, under the EPA’s historic and continuing 

interpretation of section 111, BSER focuses on supply-side, not 

demand-side, measures for reducing emissions. Because the 

 

588 UARG comment at 2-3. 
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comment examples cited above are demand-side measures, they are 

not within the section 111 interpretive paradigm that underlies 

today’s action. Additionally, under this rule, the affected 

sources that are the subject of the emission guidelines can 

employ the BSER to achieve the emission limits that the 

guidelines prescribe. 

For the reasons discussed, building blocks 2 and 3 meet the 

definition of the BSER, as it has been interpreted and applied. 

As a result, they qualify as part of the basis for the emission 

limits in the emission guidelines promulgated in this rule. 

Moreover, as also discussed, the affected EGUs may meet those 

limits by implementing the BSER, including the measures in 

building blocks 2 and 3. Commenters’ concerns over precedential 

impact cannot be taken to mean that the building blocks should 

not be considered to meet the requirements of the BSER or that 

the affected EGUs cannot be considered to meet the emission 

limits by implementing those measures. 

Moreover, the application of building blocks 2 and 3 to 

affected EGUs has a number of unique characteristics that 

negate, or at least significantly limit their precedential 

impact. Building blocks 2 and 3 entail the production of the 

same amount of the same product -- electricity, a highly 

substitutable product that can be produced using a variety of 

Deleted: U
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generation processes -- through the cleaner (that is, less CO2-

intensive) processes of shifting dispatch from steam generators 

to existing NGCC units, and from both steam generators and NGCC 

units to renewable generators. 

The physical properties of electricity and the highly 

integrated nature of the electricity system allow the use of 

these cleaner processes to generate the same amount of 

electricity. In addition, the electricity sector is primarily 

domestic -- little electricity is exported outside the U.S. -- 

and there is low capacity for storage. In addition, the 

electricity sector is highly regulated, planned, and 

coordinated. As a result, holding demand constant, an increase 

in one type of generation will result in a decrease in another 

type of generation. Moreover, the higher-emitting generators, 

which are fossil fuel-fired, have higher variable costs than 

renewable generators, so that increased renewable generation 

will generally back out fossil fuel-fired generation. 

Because of these characteristics, the electricity sector 

has a long and well-established history of substituting one type 

of generation for another. This has occurred for a wide variety 

of reasons, many of which are directly related to the system’s 

primary purposes and functions, as well as for environmental 

reasons. As a result, at present, there is a well-established 
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network of business and operational relationships and past 

practices that supports building blocks 2 and 3. As noted 

elsewhere, a large segment of steam generators already have 

business relationships with existing NGCC units, and a large 

segment of all fossil fuel-fired EGUs already own, co-own, or 

have invested in renewable energy. 

Many of these characteristics are unique to the utility 

power sector. Moreover, this complex of characteristics, ranging 

from the physical properties of electricity and the integrated 

nature of the grid to the institutional mechanisms that assure 

reliability and the existing practices and business 

relationships in the industry, combine to facilitate the 

implementation of building blocks 2 and 3 in a uniquely 

efficient manner. This supports basing the emission limits on 

the ability of owners and operators of fossil fuel-fired EGUs to 

replace their generation with cleaner generation in other 

locations, sometimes owned by other entities. 

 Because many of these individual characteristics, and their 

inherent complexity, are unique to the utility power sector, 

building blocks 2 and 3 as applied to fossil fuel-fired EGUs 

will have a limited precedent for other industries and other 

types of rulemakings. For example, the commenter’s examples 

noted above are inapposite for several reasons. Title II 
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standards are based on “the application of technology which the 

Administrator determines will be available for the model 

year...,” which is a narrower standard than the “best system of 

emission reduction ... adequately demonstrated.” Moreover, the 

examples offered by commenters appear to be premised on 

government action mandating actions not implementable by 

emitting sources (e.g., that a government would “require[e] car 

owners to shift some of their travel to buses, or ... require[e] 

there to be more electric vehicle purchases”), whereas the 

measures in building blocks 2 and 3 can be implemented by the 

affected EGUs. 

4. Relationship between a source’s implementation of building 

blocks 2 and 3 and its emissions. 

In this section, we discuss the relationship between an 

affected EGU’s implementation of the measures in building blocks 

2 and 3 and that affected EGU’s own generation and emissions. As 

discussed above, an affected EGU subject to a CAA section 111(d) 

state plan that imposes an emission rate-based standard may 

achieve that standard in part by implementing the measures in 

building block 2 (for a steam generator) and building block 3 

(for a steam generator or combustion turbine). That is, an 

affected EGU may invest in low- or zero-emitting generation and 

may apply credits from that generation against its emission 
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rate. Those credits reduce the affected EGU’s emission rate and 

thereby help it to achieve its emission limit. 

In addition, the additional low- or zero-emitting 

generation that results from the affected EGU’s investment will 

generally displace higher-emitting generation. This is because, 

as described above, higher-emitting generation generally has 

higher variable costs, reflecting its fuel costs, than, at 

least, zero-emitting generation. Displacement of higher-emitting 

generation will lower overall CO2 emissions from the source 

category of affected EGUs. 

If an affected EGU implements building block 2 or 3 by 

reducing its own generation, it will reduce its own emissions. 

However, the affected EGU may also or alternatively choose to 

implement building block 2 or 3 by investing in lower- or zeroemitting generation that does not, in and of itself, reduce the 

amount of its own generation or emissions. Even so, 

implementation of building blocks 2 and 3 will reduce CO2 from 

some affected EGUs, and therefore reduce CO2 on a source 

category-wide basis. 

This outcome is, however, consistent with the requirements 

of CAA section 111(d)(1) and (a)(1). To reiterate, CAA section 

111(d)(1) requires that “any existing source” have a “standard 

of performance,” defined under CAA section 111(a)(1) as “a 
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standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the application 

of the best system of emission reduction ... adequately 

demonstrated [BSER] ....” These provisions require by their 

terms that “any existing source” must have a “standard of 

performance,” but nothing in these provisions requires a 

particular amount –- or, for that matter, any amount -- of 

emission reductions from each and every existing source. That 

the “standard of performance” is defined on the basis of the 

“degree of emission limitation achievable through the 

application of the [BSER]” does not mean that each affected EGU 

must achieve some amount of emission reduction, for the 

following reasons. 

The cornerstone of the definition of the term “standard of 

performance” is the BSER. In determining the BSER, the EPA must 

consider the amount of emission reduction that the system may 

achieve, and must consider the ability of the affected EGUs to 

achieve the emission limits that result from the application of 

the BSER. The EPA is authorized to include in the BSER, for this 

source category, the measures in building blocks 2 and 3 

because, when applied to the source category, these measures 

result in emission standards that may be structured to ensure 

overall emission reductions from the source category and remain 
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achievable by the affected EGUs. This remains so regardless of 

whether the “degree of emission limitation achievable through 

the application of the [BSER]” by any particular source results 

in actual emission reductions from that source. 

The application of the building blocks has an impact that 

is similar to that of an emissions trading program, under which, 

overall, the affected sources reduce emissions, but any 

particular source does not need to reduce its emissions and, in 

fact, may increase its emissions, as long as it purchases 

sufficient credits or allowances from other sources. In fact, we 

expect that that many states will carry out their obligations 

under this rule by imposing standards of performance that 

incorporate trading or other multi-entity generation-replacement 

strategies. Indeed, any emission rate-based standard may not 

necessarily result in emission reductions from any particular 

affected source (or even all of the affected sources in the 

category) as a result of the ability of the particular source 

(or even all of them) to increase its production and, therefore, 

its emissions, even while maintaining the required emission 

rate. 

5. Reduced generation and the BSER 

In the proposed rulemaking, we described the BSER as the 

measures included in building block 1 as well the set of 
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measures included in building blocks 2, 3 and 4 or, in the 

alternative, reduced generation or utilization by the affected 

EGUs in the amount of building blocks 2, 3 and 4. In this final 

rule, based on the comments and further evaluation, we are 

refining our approach to the BSER. Specifically, we are 

determining the BSER as the measures included in building block 

1, as well as the set of measures included in building blocks 2 

and 3, the latter of which sources may implement by choosing 

from a number of methods, including reduced generation. Reduced 

generation is a means of implementing building blocks 2 and 3 

because of the unique characteristics of this industry, which 

tie it closely to the measures in building blocks 2 and 3. The 

amount of generation from the increased utilization of existing 

NGCC units determines a portion of the amount of reduced 

generation that affected fossil fuel-fired steam EGUs could 

undertake to achieve building block 2, and the amount of 

generation from the use of expanded lower- or zero-emitting 

generating capacity that could be provided, determines a portion 

of the amount of reduced generation that affected fossil fuelfired steam EGUs, as well as the entire amount of reduced 

generation that affected NGCC units could undertake to implement 

building blocks 2 and 3. This section discusses the reasons that 

reduced generation is one of the set of reasonable and wellDeleted: viewing the BSER from either the 

source-category perspective or the individualsource perspective, 

Deleted: be 

Deleted: ed

Deleted: through

Deleted: incorporate 

Deleted: , among other methods., and with all 

building blocks incorporating the option of 

investing through the purchase of rate-based 

emission credits or mass-based emission 

allowances.

Deleted: is linked to the BSER 

Deleted: would 

Deleted: the generation reduction component of 

the BSER for 

Deleted: would 

Deleted: the 

Deleted: reduction component of the BSER for 

Deleted: 

Deleted: reduction component of the BSER for 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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established actions that an affected EGU can implement to 

achieve its emission limits. We are not finalizing our proposal 

that reduced generation may itself be considered the BSER, for 

the reason that reduced generation does not fit within our 

historic and current interpretation of the BSER. Specifically, 

reduced generation is about changing the amount of product 

produced rather than producing the same product with a process 

that has fewer emissions. 

a. Background. As noted, for both rate-based and mass-based 

state plans, affected EGUs may take a set of actions to comply 

with their emission standards. An affected EGU may comply with 

an emission rate-based standard (e.g., a limit on the amount of 

CO2 per MWh) by acquiring, through one means or another, credits 

from lower- or zero-emitting generation (building blocks 2 or 3) 

to reduce its emission rate for compliance purposes. In 

addition, the affected EGU may reduce its generation, and if it 

does so, it then needs to acquire fewer of those credits to meet 

its emission rate.589 Under these circumstances, the affected EGU 

would in effect replace part of its higher-emitting generation 

 

589 An affected EGU that is subject to an emission rate, e.g., 

pounds of CO2 per MWh generated, cannot achieve that rate simply 

by reducing its generation (unless it shuts down, in which case 

it would achieve a zero emission rate). This is because although 

reducing generation results in fewer emissions, it does not, by 

itself, result in fewer emissions per MWh generated. 

Deleted: s

Deleted: their

Deleted: It should be noted that 

Deleted: strictly speaking, because we are not 

identifying 

Deleted: as 

Deleted: because it

Deleted: Even though reduced generation is not 

part of the BSER, it is a measure that EGUs 

may choose to take to implement BSER, just as 

EGUs have used reduced generation from a 

specific facility to meet other CAA programs 

(e.g., the Mercury and Air Toxics Standards, 

the Cross-State Air Pollution Rule). Thus, it 

is not necessary to explain that reduced 

generation meets the criteria for the BSER, 

but having said that, we note that in fact, 

except for its focus on reducing supply of a 

product, reduced generation does meets the 

criteria for the BSER and, to highlight its 

reasonableness as a means for EGUs to achieve 

their emission limits, we explain why.
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with lower- or zero-emitting generation. On the other hand, an 

affected EGU that is subject to a mass-based standard -- for 

example, a requirement to hold enough allowances to cover its 

emissions (e.g., one allowance for each ton of emissions in any 

year) -- may comply at least in part by reducing its generation 

and, thus, its emissions. Therefore, one type of action that an 

affected EGU may take to achieve either of these emission limits 

is to reduce its generation. Further, reduced generation offers 

a pathway to compliance in-and-of-itself. That is, a state may 

adopt a mass-based goal, assign mass-based standards to its 

sources, and those sources may comply with their mass-based 

limits by, in addition to implementing building block 1 

measures, reducing their generation in the appropriate amounts, 

and without taking any other actions. 

b. Well-established use of reduced generation to comply with 

environmental requirements. Reduced generation is a wellestablished method for fossil fuel-fired power plants to comply 

with their emission limits. 

 Reduced generation in the amounts contemplated in this rule 

reduces emissions from the affected sources, but because of the 

integrated and interconnected nature of the power sector, can be 

accommodated without significant cost or disruption. The 

electric transmission grid interconnects the nation’s generation 
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resources over large regions. Electric system operators 

coordinate, control, and monitor the electric transmission grid 

to ensure cost-effective and reliable delivery of power. These 

system operators continuously balance electricity supply and 

demand, ensuring that needed generation and/or demand resources 

are available to meet electricity demand. Diverse resources 

generate electricity that is transmitted and distributed through 

a complex system of interconnected components to end-use 

consumers. 

The electricity system was designed to meet these core 

functions. The three components of the electricity supply system 

-- generation, transmission and distribution -- coordinate to 

deliver electricity from the point of generation to the point of 

consumption. This interconnectedness is a fundamental aspect of 

the nation’s electricity system, requiring a complicated 

integration of all components of the system to balance supply 

and demand and a federal, state and local regulatory network to 

oversee the physically interconnected network. Electricity from 

a diverse set of generation resources such as natural gas, 

nuclear, coal and renewables is distributed over high-voltage 

transmission lines. The system is planned and operated to ensure 

that there are adequate resources to meet electricity demand 

plus additional available capacity over and above the capacity 
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needed to meet normal peak demand levels. System operators have 

a number of resources potentially available to meet electricity 

demand, including electricity generated by electric generation 

units of various types as well as demand-side resources. 

Importantly, if generation is reduced from one generator, 

safeguards are in place to ensure that adequate supply is still 

available to meet demand. We describe these safeguards in the 

background section of this preamble. 

Both Congress and the EPA have recognized reduced 

generation as one of the measures that fossil fuel-fired EGUs 

may implement to reduce their emissions of air pollutants and 

thereby achieve emission limits.590 Congress, in enacting the 

allowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO2 emitted, 

explicitly recognized that fossil fuel-fired EGUs could meet 

this requirement by reducing their generation. In fact, Congress 

anticipated that fossil fuel-fired EGUs may choose to comply 

 

590 More generally, the D.C. Circuit has recognized that in 

certain circumstances, the EPA has authority to require 

reductions in production as a means of ensuring compliance with 

legal requirements: under the PSD program, the court has 

determined that EPA is authorized to require that SIPs contain 

provisions to correct any violations of the PSD increments and 

EPA “may even require, in appropriate instances, the relatively 

severe correctives of a rollback in operations....” Alabama Power 

v. Costle, 636 F.2d 323, 363 (D.C.Cir. 1980). 
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with the SO2 emission limits by reducing utilization, and 

included provisions that specifically addressed reduced 

utilization. For example, CAA section 408(c)(1)(B) includes 

requirements for an owner or operator of an EGU that meets the 

Phase 1 SO2 reduction obligations and the NOx reduction 

obligations “by reducing utilization of the unit as compared 

with its baseline or by shutting down the unit.” 

The EPA has also recognized in several rulemakings limiting 

emissions from fossil fuel-fired EGUs that reduced generation is 

one of the methods of emission reduction that the EGUs were 

expected to rely on to achieve their emission limitations. 

Examples include rulemakings to impose requirements that sources 

implement BART to reduce their emissions of air pollutants that 

cause or contribute to visibility impairment. As explained 

earlier, for certain older stationary sources that cause or 

contribute to visibility impairment, including fossil fuel-fired 

EGUs, states must determine BART on the basis of five statutory 

factors, such as costs and energy and non-air quality impacts.591

In 1980, the EPA promulgated a regulatory definition of BART: 

“an emission limitation based on the degree of reduction 

achievable through the best system of continuous emission 

 

591 CAA section 169A(g)(2). 
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reduction for each pollutant which is emitted by an existing 

stationary facility.”592 Both the statutory factors and the 

regulatory definition resemble the definition of the BSER under 

CAA section 111(a)(1) (although, as noted, the statutory 

definition of BART is more technology focused than the 

definition of BSER). In its regional haze SIP, the State of New 

York determined that BART for the NOX emissions from two coalfired boilers that served as peaking units was caps on baseline 

emissions rates and annual capacity factors of 5 percent and 10 

percent, respectively.593 

There have been numerous other instances in which fossil 

fuel-fired EGUs have reduced their generation, or placed limits 

on their generation, in order to achieve, or obviate, emission 

standards. In fact, there are numerous examples of EGUs that

take restrictions on hours of operation in their permits for the 

purpose of avoiding CAA obligations, including avoiding 

triggering the requirements of the Prevention of Significant 

Deterioration (PSD), Nonattainment New Source Review (NNSR), or 

Title V programs (including Title V fees), and avoiding 

triggering HAPs requirements. Such restrictions may also be 

 

592 40 C.F.R. § 51.301. 593 77 Fed. Reg. 24,794, 24,810 (Apr. 25, 2012). 

Deleted: it is common for these

Deleted: to
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taken to limit emissions of pollutants, such as limiting 

emissions of criteria pollutants for attainment purposes. 

More specifically, EPA’s regulations for a number of air 

programs expressly recognize that certain sources may take 

enforceable limits on hours of operation in order to avoid 

triggering CAA obligations that would otherwise apply to the 

source. Stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements.594

A source may voluntarily obtain a synthetic minor limitation –- 

that is, a legally and practicably enforceable restriction that 

has the effect of limiting emissions below the relevant level -- 

to avoid triggering a major stationary source requirement.595

Such synthetic minor limits may be based on restrictions on the 

hours of operation, as provided in EPA’s regulations defining 

 

594 See, e.g., CAA sections 112(a)(1), 112(d)(1), 165(a), 169(1), 

172(c)(5), 173(a) &(c), 501(2), 502(a), 302(j). 

595 See, e.g., Memorandum from Terrell Hunt, Assoc. Enforcement 

Counsel, U.S. EPA, & John Seitz, Director, Stationary Source 

Compliance Div., U.S. EPA, Guidance on Limiting Potential to 

Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), 

available at 

http://www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdf 

(“Restrictions on production or operation that will limit 

potential to emit include limitations on quantities of raw 

materials consumed, fuel combusted, hours of operation, or 

conditions which specify that the source must install and 

maintain controls that reduce emissions to a specified emission 

rate or to a specified efficiency level.”) (emphasis added). 
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“potential to emit,” as well as on air pollution control 

equipment. “Potential to emit” is defined, for instance, in the 

regulations for the PSD program for permits issued under federal 

authority as: “the maximum capacity of a stationary source to 

emit a pollutant under its physical and operational design. Any 

physical or operational limitation on the capacity of the source 

to emit a pollutant, including air pollution control equipment 

and restrictions on hours of operation ... shall be treated as 

part of its design if the limitation or the effect it would have 

on emissions is federally enforceable,”596 or “legally and 

practicably enforceable by a state or local air pollution 

control agency.”597 The regulations for other air programs 

similarly recognize that potential to emit may be limited 

through restrictions on hours of operations in their 

corresponding definitions of “potential to emit.”598 These 

regulatory provisions make clear that restrictions on potential 

 

596 40 CFR 52.21(b)(4)(emphasis added). 597 John Seitz, Director, Office of Air Quality Planning and 

Standards, and Robert Van Heuvelen, Director, Office of 

Regulatory Enforcement, Release of Interim Policy on Federal 

Enforceability of Limitations on Potential to Emit, at 3 (Jan. 

22, 1996), available at 

http://www.epa.gov/region07/air/nsr/nsrmemos/pottoemi.pdf. 

598 See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 

programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 

programs), 70.2 (addressing title V operating permit programs), 

and 63.2 (addressing hazardous air pollutants). 
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to emit include both “air pollution control equipment” and 

“restrictions on hours of operation,” and indicate that these 

are equally cognizable means of restricting emissions to comply 

with, or avoid, CAA requirements.599 

As one of many examples of a fossil-fuel fired EGU taking 

restrictions on hours of operation for the purpose of avoiding 

CAA obligations, Manitowoc Public Utilities in Wisconsin 

obtained a title V renewal permit that limited the operating 

hours of the single simple-cycle combustion turbine to not more 

than 194 hours per month, averaged over any consecutive 12 month 

period, as part of limiting its potential to emit for volatile 

organic compounds below the title V threshold of 100 tpy, and 

carbon monoxide, nitrogen oxides and sulfur dioxide below the 

PSD threshold of 250 tpy.600 As another example, Sunbury 

 

599 See, e.g., 52.21(b)(4). 600 See Final Operation Permit No. 436123380-P10 for Manitowoc 

Public Utilities -- Custer Street (Wis. Dept. Nat. Res., 

8/19/2013), Condition ZZZ.1.a(1) at p. 9 (Limiting potential to 

emit) and n. 11 (“These conditions are established so that the 

potential emissions for volatile organic compounds will not 

exceed 99 tons per year and potential emissions for carbon 

monoxide, nitrogen oxides and sulfur dioxide emissions from the 

facility will not exceed 249 tons per year.”). See also Analysis 

and Preliminary Determination for the Renewal of Operation 

Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/21/2013) at p. 5 

(noting that the “existing facility is a major source under Part 

70 because potential emissions of sulfur dioxide, nitrogen 

oxides and carbon monoxide exceed 100 tons per year. The 

existing facility is a minor source under PSD and an area source 

of federal HAP” and further noting that after renewal, “the 
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Generation LP in Pennsylvania obtained a minor new source 

preconstruction permit, called a plan approval, for a repowering 

project from the Pennsylvania Department of Environmental 

Protection in 2013 that limited the hours of operation of three 

combined cycle combustion turbines that were planned for 

construction in order to remain below the significance threshold 

for GHGs.601 The Legal Memorandum includes numerous other 

examples of power plants accepting permit limits that reduce 

generation to meet, or avoid the need to meet, emission limits. 

There are several ways that an affected EGU may implement 

reduced generation. For example, an EGU may accept a permit 

requirement that specifically limits its operating hours. In 

addition, an EGU may treat the cost of its generation as 

including an additional amount associated with environmental 

 

facility will continue to be a major source under Part 70 

because potential emissions of sulfur dioxide, nitrogen oxides 

and carbon monoxide exceed 100 tons per year. The facility will 

also continue to be a minor source under PSD and an area source 

of federal HAP.”). 

601 See Plan Approval No. 55-00001E for Sunbury Generation LP 

(Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 

24, 32 and 40 (limiting turbine units to operating no more than 

7955, 6920, or 8275 hours in any 12 consecutive month period 

depending on which of three turbine options was selected); 

Memorandum from J. Piktel to M. Zaman, Addendum to Application 

Review Memo for the Repowering Project (Pa. Dept. Env. 

Protection, 4/1/2013) at p. 2 of 10 (noting that source had 

“calculated a maximum hours per year (12 consecutive month 

period) of operation for the sources proposed for each of the 

turbine options in order to remain below the significance 

threshold for GHGs.”). 

Deleted: utilization
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impacts, which requires it to raise its bid price, so that the 

EGU is dispatched less. 

c. Other aspects of reduced generation. 

The amounts of increased existing NGCC generation and new 

renewables, in the amounts reflected in building blocks 2 and 3, 

can be substituted for generation at affected EGUs at reasonable 

cost. The NGCC capacity necessary to accomplish the levels of 

generation reduction proposed for building block 2 is already in 

operation or under construction. Moreover, it is reasonable to 

expect that the incremental resources reflected in building 

block 3 will develop at the levels requisite to ensure an 

adequate and reliable supply of electricity at the same time 

that affected EGUs may choose to reduce their CO2 emissions by 

means of reducing their generation. 

Reduced generation by affected EGUs, in the amounts that 

affected EGUs may rely on to comply with this rule, will not 

have adverse effects on the utility power sector. In light of 

the emission limits of this rule, because of the availability of 

the measures in building blocks 2 and 3, and because the grid is 

interconnected and the electricity system is highly planned, 

reductions in generation by fossil fuel-fired EGUs in the amount 

contemplated under this rule, and occurring over the lengthy 

time frames provided under this rule, will result in replacement 

Moved down [19]: 602

Deleted: At the levels

Deleted: the final 

Deleted: these measures 

Deleted: or be required 
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generation that generally is lower- or zero-emitting. Mechanisms 

are in place in both regulated and deregulated electricity 

markets to assure that substitute generation will become 

available and/or steps to reduce demand will be taken to 

compensate for reduced generation by affected EGUs. As a result, 

reduced generation will not give rise to reliability concerns or 

have other adverse effects on the utility power sector and are 

of reasonable cost for the affected source category and the 

nationwide electricity system.603 All these results come about 

because the operation of the electrical grid through integrated 

generation, transmission, and distribution networks creates 

substitutability for electricity and electricity services, which 

allows decreases in generation at affected fossil fuel-fired 

steam EGUs to be replaced by increases in generation at affected 

 

603 Although, as discussed in the text in this section of the 

preamble, we are not treating reduced generation as itself the 

BSER (because it does not meet our historic and current approach 

of defining the BSER to include methods that allow the same 

amount of production but with a lower-emitting process) we note 

that reduced generation meets the criteria for the BSER to the 

extent that, as the examples in the text and in the Legal 

Memorandum make clear, reduced generation is “adequately 

demonstrated” as a method of reducing emissions (because 

Congress and the EPA have recognized it and on numerous 

occasions, power plants have relied on it); is of reasonable 

cost; does not have adverse effects on energy requirements at 

the level of the individual affected source (because it does not 

require additional energy usage by the source) or the source 

category or the U.S.; and does not create adverse environmental 

problems. 

Moved (insertion) [19]
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NGCC units (building block 2) and allows decreases in generation 

at all affected EGUs to be replaced by increased generation at 

new lower- and zero-emitting EGUs (building block 3). Further, 

this substitutability increases over longer timeframes with the 

opportunity to invest in infrastructure improvements, and as 

noted elsewhere, this rule provides an extended state plan and 

source compliance horizon.604 

e. Comments concerning limiting principles. A commenter stated 

that “an interpretation of [‘system of emission reduction’] that 

relies primarily on reduced utilization has no clear limiting 

principle.”605 We disagree with this concern, for the following 

reasons. 

As discussed, in this final rule, we are identifying the 

BSER as the combination of the three building blocks. Building 

blocks 2 and 3 entail substitution of lower- or zero-emitting 

generation for higher-emitting generation, and one component of 

that substitution is reduced generation. Accordingly, our 

identification of the BSER in this final rule does not “rel[y] 

 

604 Although, as noted, it is not necessary to demonstrate that 

reduced generation meets the requirements for the BSER, this 

discussion make clear that reduced generation meets the BSER 

criteria of reducing emissions, being of reasonable cost, not 

having adverse implications for energy or non-air quality 

pollutants, and not resulting in adverse impacts on the utility 

power sector. 

605 EEI comment, at 284. 
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primarily” on reduced utilization as the BSER. Rather, the BSER 

is, in addition to building block 1, the substitution of loweror zero-emitting generation for higher emitting generation, and 

reduced utilization may be a way to implement that substitution 

and is one of numerous methods that affected EGUs may employ to 

achieve or help achieve the emission limits established by these 

emission guidelines.606 The commenter’s concerns over a perceived 

 

606 Indeed, load shifting -- as substitute generation is 

sometimes called -- is an “easy and fairly inexpensive strategy” 

that “may be used in conjunction with other control measures” 

for “emission reduction.” Donald S. Shepard, “A Load Shifting 

Model for Air Pollution Control in the Electric Power Industry,” 

Journal of the Air Pollution Control Association, Vol. 20, No. 

11, p. 760 (Nov. 1970). In fact, load shifting has been 

recognized as a pollution control technique as early as 1968, 

when it was included in the “Chicago Air Pollution System Model” 

for controlling incidents of extremely high pollution. E.J. 

Croke, et al., “Chicago Air Pollution System Model, Third 

Quarterly Progress Report,” Chicago Department of Air Pollution 

Control, p. 186 (1968) (discussing the feasibility of “Control 

by Load Reduction” in combination with load shifting as applied 

to the Commonwealth Edison Company), available at 

http://www.osti.gov/scitech/servlets/purl/4827809. The report 

also considered “combining fuel switching and load reduction” as 

a possible air pollution abatement technique. See id. at 188. 

The report recognized, as an initial matter, that the 

Commonwealth Edison Company (CECO) was “constrained to meet the 

total load demand” but that “load reduction at one plant or even 

a number of plants is usually feasible by shifting the power 

demand to other plants in the system.” Id. As a result, the 

report noted, “load shifting within the physical limits of the 

CECO system ... may be a highly desirable control mechanism.” 

Id. The report also predicted that “[i]n the future, it may be 

possible to form reciprocal agreements to obtain ‘pollution 

abatement’ power from neighbor companies during a pollution 

incident and return this borrowed power at some later date.” Id.

at 187. 
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lack of a limiting principle cannot be taken to mean that 

reduced generation cannot be considered to be a method for 

affected EGUs to achieve their emission limits.

Moreover, reduced generation, as applied to affected EGUs 

in this rule, is limited in a number of respects. The amount of 

reduced generation is the amount of replacement generation that 

is lower- or zero- emitting, that is of reasonable cost, that 

can be generated without jeopardizing reliability, and that 

meets the other requirements for the BSER. As discussed, that 

amount is the amount of generation in building blocks 2 and 3.607

Finally, as discussed, the integrated nature of the 

electricity system, coupled with the high substitutability of 

electricity, allows EGUs to reduce their generation without 

adversely affecting the availability of their product. Those 

characteristics facilitate replacement of generation that has 

been reduced, and for that reason, EGUs have a long history of 

reducing their generation and either replacing it directly or 

having it replaced through the operation of the interconnected 

electricity system through measures similar to those in building 

 

607 The EPA notes that affected EGUs are not actually required to 

collectively reduce generation by the amount represented in the 

BSER, and may collectively reduce generation by more or less 

than that amount. Individual affected EGUs are free to choose 

reduced generation or other means of reducing emissions, as 

permitted by their state plans, in order to achieve the 

standards of performance established for them by their states. 
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blocks 2 and 3. Thus, an EGU can either directly replace its 

generation, or simply reduce its generation, and in the latter 

case, the integrated grid, combined with the high degree of 

planning and various reliability safeguards, will result in 

entities providing replacement generation. This means that 

consumers receive exactly the same amount of the same product, 

electricity, after the reduced generation that they received 

before it. No other industry is both physically interconnected 

in this manner and manufactures such a highly substitutable 

product; as a result, the use of reduced generation is not 

easily transferrable to another industry. 

6. Reasons that this rule is within the EPA’s statutory 

authority and does not represent over-reaching. 

In this section, we respond to adverse comments that the 

EPA is overreaching in this rulemaking by attempting to direct 

the energy sector. These commenters construed the proposed 

rulemaking as the EPA proposing to mandate the implementation of 

the measures in the building blocks, including investment in 

renewable energy and implementation of a broad range of state 

and utility demand-side energy efficiency programs. Commenters 

added that in some instances, the affected EGUs and states would 

have no choice but to take the actions in the building blocks 

because they would not otherwise be able to achieve their Deleted: , the affected EGUs would not
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emission standards. Commenters also emphasized that with the 

proposed portfolio approach, the rule would impose federally 

enforceable requirements on a wide range of entities that do not 

emit CO2 and have not previously been subject to CAA regulation. 

Commenters cite the U.S. Supreme Court’s statements in Utility 

Air Regulatory Group v. EPA (UARG)608 that caution an agency 

against interpreting its statutory authority in a way that 

“would bring about an enormous and transformative expansion in 

[its] regulatory authority without clear congressional 

authorization,” and that add, “When an agency claims to discover 

in a long-extant statute an unheralded power to regulate ‘a 

significant portion of the American economy,’ ... we typically 

greet its announcement with a measure of skepticism.”609

Commenters assert that in this rule, the EPA is taking the 

actions that the UARG opinion cautioned against. For the reasons 

discussed below, these comments are incorrect and misunderstand 

fundamental aspects of this rule. In addition, to the extent 

these comments address either building block 4 or the portfolio 

approach they are moot, because the EPA is not finalizing those 

elements of the proposal. 

 

608 134 S. Ct. 2427 (2014). 609 Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014) (citations omitted). 
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In this rule, the EPA is following the same approach that 

it uses in any rulemaking under CAA section 111(d), which is 

designed to regulate the air pollutants from the source category 

at issue. First, the EPA identifies the BSER to reduce harmful 

air pollution. Second, based on the BSER, the EPA promulgates 

emission guidelines, which generally take the form of emission 

rates applicable to the affected sources. In this case, the EPA 

is promulgating a uniform CO2 emission performance rate for 

steam-generating EGUs and a uniform CO2 emission performance rate 

for combustion turbines, and the EPA is translating those rates 

into a combined emission rate and equivalent mass limit for each 

state. These emission guidelines serve as the guideposts for 

state plan requirements. The states, in turn, promulgate 

standards of performance and, in doing so, retain significant 

flexibility either to promulgate rate-based emission standards 

that mirror the emission performance rates in the guidelines, 

promulgate rate-based emission standards that are equivalent to 

the emission performance rates in the guidelines, or promulgate 

equivalent mass-based emission standards. The sources, in turn, 

are required to comply with their emission standards, and may do 

so through any means they choose. Alternatively, the state may 

adopt the state-measures approach, which provides additional 

flexibility. 

Deleted: emission standards or 

Deleted: to 

Deleted: the 

Deleted: limits

Deleted: limits
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Thus, the EPA is not requiring that the affected EGUs take 

any particular action, such as implementation of the building 

blocks. Rather, as just explained, the EPA is regulating the 

affected EGUs’ emissions by requiring that the state submit 

state plans that achieve specified emission performance levels. 

The states may choose from a wide range of emission limits to 

impose on their sources, and the sources may choose from a wide 

range of compliance options to achieve their emission limits. 

Those options include various means of implementing the building 

blocks as well as numerous other compliance options, ranging 

from -- depending in part on whether the state imposes a ratebased or mass-based emission limit -- implementation of demandside energy efficiency measures to natural gas co-firing.610 

As some indication of the diverse set of actions we expect 

to comply with the requirements of this rule, we note that 

demand-side energy efficiency programs, in particular, are 

 

610 In fact, the EPA is expressly precluded from mandating 

specific controls except in certain limited circumstances. See 

42 U.S.C. § 7411(b)(5). For instance, the EPA is authorized to 

mandate a particular “design, equipment, work practice, or 

operational standard, or combination thereof,” when it is “not 

feasible to prescribe or enforce a standard of performance” for 

new sources. 42 U.S.C. § 7411(h)(1). CAA section 111(h) also 

highlights for us that while “design, equipment, work practice, 

or operational standards” may be directly mandated by the EPA, 

CAA section 111(a)(1) encompasses a broader suite of measures 

for consideration as the BSER. 

Deleted: limitations
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expected to be a significant compliance method, in light of 

their low costs. In addition, the National Association of Clean 

Air Agencies (NACAA) has issued a report that provides a 

detailed discussion of 25 approaches to CO2 reduction in the 

electricity sector.611 In addition, we note that the nine RGGI 

states -- Connecticut, Delaware, Maine, Maryland, Massachusetts, 

New Hampshire, New York, Rhode Island and Vermont -– have 

indicated that they intend to maintain their current state 

programs, which this rule would allow, and there are reports 

that other states may seek to join RGGI.612 Similarly, California 

has indicated that it intends to maintain its current state 

program, which this rule would allow. Other states could employ 

the types of methods used in Oregon, Washington, Colorado, or 

Minnesota, described in the background section of this preamble. 

As a practical matter, we expect that for some affected 

EGUs, implementation of the building blocks will be the most 

attractive option for compliance. This does not mean, contrary 

 

611 NACAA, “Implementing EPA’s Clean Power Plan: A Menu of 

Options (May 2015) 

http://www.4cleanair.org/NACAA_Menu_of_Options. NACAA describes 

itself as “the national, non-partisan, non-profit association of 

air pollution control agencies in 41 states, the District of 

Columbia, four territories and 116 metropolitan areas.” Id. 612 Martinson, Erica, “Cap and trade lives on through the 

states,” Politico (May 27, 2014) 

http://www.politico.com/story/2014/05/cap-and-trade-states107135.html 
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to the adverse comments noted above, that this rule constitutes 

a redesign of the energy sector. As discussed above, the 

building blocks meet the criteria to be part of the best system 

of emission reduction ... adequately demonstrated. The fact that 

some sources will implement the building blocks and that this 

may result in changes in the electricity sector does not mean 

that the building blocks cannot be considered the BSER under CA 

section 111(d). 

In this rule, as with all CAA section 111(d) rules, the EPA 

is not directly regulating any entities. Moreover, the EPA is 

not finalizing the proposed portfolio approach. Accordingly, the 

EPA is neither requiring nor authorizing the states to regulate 

non-affected EGUs in their CAA section 111(d) plans.613

Moreover, contrary to adverse comments, this rule does not 

require the States to adopt a particular type of energy policy 

or implement particular types of energy measures. Under this 

rule, a state may comply with its obligations by adopting the 

emission standards approach to its state plan and imposing ratebased or mass-based emission standards on its affected EGUs. In 

this manner, this rule is consistent with prior section 111(d) 

rulemaking actions, in which the states have complied by 

 

613 A state may regulate non-EGUs as part of a state measures 

approach, but those measures would not be federally enforceable. 

Deleted: EPA 
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promulgating one or both of those types of standards of 

performance. In this rulemaking, as an alternative, the state 

may adopt the state measures approach, under which the State 

could, if it wishes, adopt particular types of energy measures 

that would lead to reductions in emissions from its EGUs. But 

again, this rule does not require the state to implement a 

particulate type of energy policy or adopt particular types of 

energy measures. 

It is certainly reasonable to expect that compliance with 

these air pollution controls will have costs, and those costs 

will affect the electricity sector by discouraging generation of 

fossil fuel-fired electricity and encouraging less costly 

alternative means of generating electricity or reducing demand. 

But for affected EGUs, air pollution controls necessarily entail 

costs that affect the electricity sector and, in fact, the 

entire nation, regardless of what BSER the EPA identifies as the 

basis for the controls. For example, had some type of add-on 

control such as CCS been available as the BSER for coal-fired 

EGUs, sources that complied by installing that control would 

incur higher costs. As a result, generation from coal-fired EGUs 

would be expected to decrease and be replaced at least in part 

by generation from existing NGCC units and new renewables 
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Page 625 of 1544

because those forms of generation would see their competitive 

positions improved. 

This basic fact that the EPA regulations of air pollutants 

from affected EGUs invariably affect the utility sector is wellrecognized and in no way indicates that such regulations exceed 

the EPA’s authority. In revising CAA section 111 in the 1977 CAA 

Amendments, Congress explicitly acknowledged that the EPA’s 

rules under CAA section 111 for EGUs would significantly impact 

the energy sector.614 The Courts have recognized that, too. The 

U.S. Supreme Court, in its 2011 decision that the CAA and the 

EPA actions it authorizes displace any federal common law right 

to seek abatement of CO2 emissions from fossil-fuel fired power 

plants, emphasized that CAA section 111 authorizes the EPA –- 

which the Court identified as the “expert agency” -– to regulate 

CO2 emissions from these sources in a manner that balances “our 

 

614 The D.C. Circuit acknowledged this legislative history in 

Sierra Club v. EPA, 657 F.2d 298, 331 (D.C. Cir. 1981). There, 

the Court stated: 

[T]he Reports from both Houses on the Senate and House 

bills illustrate very clearly that Congress itself was 

using a long-term lens with a broad focus on future 

costs, environmental and energy effects of different 

technological systems when it discussed section 111. 

[Citing S. Rep. No. 95-127, 95th Cong., 1st Sess. 

(1977), 3 Leg. Hist. 1371; H.R. Rep. No. 95-294, 95th 

Cong., 1st Sess. 188 (1977), 4 Leg. Hist. 2465.] 

Deleted: The legislative history clearly 

supports our reading of amended section 

111 as authorizing EPA to balance long 

term national and regional impacts of 

alternative standards. The Conferees 

defined the best technology in terms of 

“long-term growth,” “long-term cost 

savings,” effects on the “coal market,” 

including prices and utilization of coal 

reserves, and “incentives for improved 

technology.” [Citing CAA Conference 

Report: Statement of Intent; Clarification 

of Select Provisions, 123 Cong. Rec. 27071 

(1977), 3 Leg. Hist. at 324 (referring to 

H.R. Rep. No. 95-294, 95th Cong., 1st 

Sess. 188 (1977), at 183-95, 4 Leg. Hist. 

at 2651-62, Remarks of Senator Muskie 

introducing S. 252 for debate, 123 Cong. 

Rec. 18018 (1977), 3 Leg. Hist. at 717.) 

Indeed, t
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Nation’s energy needs and the possibility of economic 

disruption:” 

The appropriate amount of regulation in any particular 

greenhouse gas-producing sector cannot be prescribed 

in a vacuum: as with other questions of national or 

international policy, informed assessment of competing 

interests is required. Along with the environmental 

benefit potentially achievable, our Nation's energy 

needs and the possibility of economic disruption must 

weigh in the balance. 

The [CAA] entrusts such complex balancing to EPA 

in the first instance, in combination with state 

regulators. Each “standard of performance” EPA sets 

must “tak[e] into account the cost of achieving 

[emissions] reduction and any nonair quality health 

and environmental impact and energy requirements.” § 

7411(a)(1), (b)(1)(B), (d)(1); see also 40 C.F.R. § 

60.24(f) (EPA may permit state plans to deviate from 

generally applicable emissions standards upon 

demonstration that costs are “[u]n-reasonable”). EPA 

may “distinguish among classes, types, and sizes” of 

stationary sources in apportioning responsibility for 

emissions reductions. § 7411(b)(2), (d); see also 40 

C.F.R. § 60.22(b)(5). And the agency may waive 

compliance with emission limits to permit a facility 

to test drive an “innovative technological system” 

that has “not [yet] been adequately demonstrated.” § 

7411(j)(1)(A). The Act envisions extensive cooperation 

between federal and state authorities, see § 7401(a), 

(b), generally permitting each state to take the first 

cut at determining how best to achieve EPA emissions 

standards within its domain, see § 7411(c)(1), (d)(1)-

(2). 

It is altogether fitting that Congress designated 

an expert agency, here, EPA, as best suited to serve 

as primary regulator of greenhouse gas emissions. The 

expert agency is surely better equipped to do the job 

than individual district judges issuing ad hoc, caseby-case injunctions.615

 

615 American Electric Power v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011). 
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Similarly, the D.C. Circuit, in its 1981 decision upholding the 

EPA’s rules to reduce SO2 emissions from new coal-fired EGUs 

under the version of CAA section 111(b) adopted in the 1977 CAA 

Amendments, stated: 

[S]ection 111 most reasonably seems to require that 

EPA identify the emission levels that are “achievable” 

with “adequately demonstrated technology.” After EPA 

makes this determination, it must exercise its 

discretion to choose an achievable emission level 

which represents the best balance of economic, 

environmental, and energy considerations. It follows 

that to exercise this discretion EPA must examine the 

effects of technology on the grand scale in order to 

decide which level of control is best.... The standard 

is, after all, a national standard with long-term 

effects.616

The D.C. Circuit added: “Regulations such as those involved here 

demand a careful weighing of cost, environmental, and energy 

considerations. They also have broad implications for national 

economic policy.”617 This rule has “economic, environmental, and 

 

616 Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981). 617 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). The 

Court supported this statement with a lengthy quotation from a 

scholarly article, which stated, in part: 

Consider for a moment the chain of collective 

decisions and their effects just in the case of 

electric utilities. Petroleum imports can be conserved 

by switching from oil-fired to coal-fired generation. 

But barring other measures, burning high-sulfur 

Eastern coal substantially increases pollution. Sulfur 

can be “scrubbed” from coal smoke in the stack, but at 

a heavy cost, with devices that turn out huge volumes 

of sulfur wastes that must be disposed of and about 
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energy” impacts, as Congress and the Courts expect in a CAA 

section 111 rule, but those impacts do not mean that the EPA is 

precluded from promulgating the rule. 

 As noted above, in this rule, to control CO2 emissions from 

affected EGUs, the EPA first considered more traditional air 

pollution control measures, including supply-side efficiency 

improvements, fuel-switching (for CO2 emissions, that entails cofiring with natural gas), and add-on controls (for CO2 emissions, 

that entails CCS). However, it became apparent that even if the 

 

whose reliability there is some question. Intermittent 

control techniques (installing high smokestacks and 

switching off burners when meteorological conditions 

are adverse) can, at lower cost, reduce local 

concentrations of sulfur oxides in the air, but cannot 

cope with the growing problem of sulfates and 

widespread acid rainfall. Use of low-sulfur Western 

coal would avoid many of these problems, but this coal 

is obtained by strip mining. Strip-mining reclamation 

is possible, but substantially hindered in large areas 

of the West by lack of rainfall. Moreover, in some 

coal-rich areas the coal beds form the underground 

aquifer and their removal could wreck adjacent farming 

or ranching economies. Large coal-burning plants might 

be located in remote areas far from highly populated 

urban centers in order to minimize the human effects 

of pollution. But such areas are among the few left 

that are unspoiled by pollution and both 

environmentalists and the residents (relatively few in 

number compared with those in metropolitan localities 

but large among the voting population in the 

particular states) strongly object to this policy. 

Id. at 406 n. 526. 
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EPA could have finalized those controls as the BSER618 and 

established the same uniform CO2 emission performance rates, the 

affected EGUs would rely on less expensive ways to achieve their 

emission limits. Specifically, instead of relying on co-firing 

and CCS, the affected EGUs generally would replace their 

generation with lower- or zero-emitting generation– the measures 

in building blocks 2 and 3 -- because those measures are 

significantly less expensive and already well-established as 

pollution control measures. Indeed, some affected EGUs have 

stated that while they oppose including in the BSER generation 

shifts to lower- or zero-emitting sources (or, as proposed, 

demand-side energy efficiency), they request that those measures 

be available for compliance, which indicates their interest in 

implementing those measures.619

We expect that many sources will choose to comply with 

their emission limits through the measures in building blocks 2 

and 3, but contrary to the assertions of some commenters, this 

 

618 For the reasons explained, we did not finalize those measures 

because significantly less expensive control measures -- 

building blocks 2 and 3 -- are available for these affected 

EGUs. 

619 See the proposal for this rule, 79 FR at 34888 (“during the 

public outreach sessions, stakeholders generally recommended 

that state plans be authorized to rely on, and that affected 

sources be authorized to implement, re-dispatch, renewable 

energy measures, and demand-side energy efficiency measures in 

order to meet states’ and sources’ emission reduction 

obligations.”). 
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will not result in unprecedented and fundamental alterations to 

the energy sector. As discussed above, Congress relied on the 

same measures as those the EPA is including in building blocks 2 

and 3 as essential parts of the basis for the Title IV emission 

limits for fossil fuel-fired EGUs, and the EPA did the same for 

the emission limits in various rules for those same sources. 

In addition, reliance on the measures in building blocks 2 

and 3 is fully consistent with the recent changes and current 

trends in electricity generation, and as a result, would by no 

means entail fundamental redirection of the energy sector. As 

indicated in the RIA for this rule, we expect that the main 

impact of this rule on the nation’s mix of generation will be to 

reduce coal-fired generation, but in an amount and by a rate 

that is consistent with recent historical declines in coal-fired 

generation. Specifically, from approximately 2005 to 2014, coalfired generation declined at a rate that was greater than the 

rate of reduced coal-fired generation that we expect to result 

from this rulemaking from 2015 to 2030. In addition, under this 

rule, the trends for all other types of generation, including 

natural gas-fired generation, nuclear generation, and renewable 

generation, will remain generally consistent with what their 

trends would be in the absence of this rule. In addition, this 

Deleted: as discussed elsewhere, 
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rule is expected to result in increases in demand-side energy 

efficiency.

In addition, contrary to claims of some commenters, in this 

rule, the EPA is not attempting to expand its authorities by 

attempting to expand the jurisdiction of the CAA to previously 

unregulated sectors of the economy, in contravention of the UARG

decision. In UARG, the U.S. Supreme Court struck down the EPA’s 

interpretation of the PSD provisions of the CAA that had the 

effect of applying the PSD requirements to large numbers of 

small sources that previously had not been subject to PSD and 

with respect to which, according to the Court, the EPA 

acknowledged that Congress did not intend that such sources be 

subject to the PSD requirements.620 Commenters appear to 

interpret this decision to preclude the EPA from including at 

least building block 3 in the BSER because it includes measures 

that involve entities (such as renewable energy developers) that 

do not emit CO2 and have not previously been subject to the CAA. 

However, in this rule, the EPA is not attempting to subject any 

entity other than the affected EGUs in the source categories to 

CAA section 111 requirements. As discussed below, the EPA is not 

finalizing the proposed portfolio approach, under which states 

were authorized to include, in their CAA section 111(d) state 

 

620 Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2443 (2014). 
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plans, requirements on entities other than affected EGUs. Thus, 

as noted above, this final rule does not require or authorize 

the states to include entities other than affected EGUs in their 

CAA section 111(d) state plans, and as a result, those entities 

will not come under CAA jurisdiction621 and the parts of the 

economy that they represent will not be regulated by the EPA. 

7. Relative stringency of requirements for existing sources and 

new and modified sources. 

Commenters also objected that the proposed CAA section 

111(d) standards are more stringent than the standards for new, 

modified or reconstructed sources, and they assert that setting 

section 111(d) standards that are more stringent than 111(b) 

standards would be illogical, contrary to precedent, contrary to 

the intent of the remaining useful life exception, and arbitrary 

and capricious.622 We disagree with these comments. Comparing the 

control requirements of the two sets of rules, CAA section 

111(d) and 111(b), is an “apples-to-oranges” comparison and, as 

a result, it is not possible – and it is overly simplistic -- to 

conclude that the 111(d) requirements are more stringent that 

the 111(b) requirements. 

 

621 States may regulate non-affected EGUs through a state 

measures approach, but those regulations would not be federally 

enforceable. 

622 ACC et al. (Associations) comments at 40, Luminant comments 

at 89. 

Deleted: ¶

Deleted: -- 

Deleted: –- 
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 Most importantly, the two sets of rules become applicable 

at different points in time and have significantly different 

compliance periods. The CAA section 111(b) rule becomes 

applicable for new, modified and reconstructed sources 

immediately upon construction, modification, or reconstruction

and, in fact, by operation of section 111(e) and (a)(2), new,

modified, or reconstructed sources that commenced construction 

prior to the effective date of the section 111(b) rule must also 

be in compliance upon the effective date of the rule. In 

contrast, the requirements under the CAA section 111(d) rule do 

not become applicable to existing affected EGUs until seven 

years after promulgation of the rule, when the interim 

compliance period begins in 2022, and the final compliance 

period does not begin until 2030. Moreover, the compliance 

period for the interim requirements is eight years. This later 

applicability date and longer compliance period for existing 

sources accommodates a requirement that, on average, those 

sources have a lower nominal emissions limit than the standards 

for new or modified sources, which those latter sources must 

comply with immediately. 

In addition, the timetables for compliance with the section 

111(b) and 111(d) rules should be considered in light of the 8-

year review schedule required for section 111(b) rules under CAA 

Deleted: compliance times and 

Deleted: compliance time for the 

Deleted: both 

Deleted: and 

Deleted: is 

Deleted: or 

Deleted: or 

Deleted: compliance time

Deleted: for 

Deleted: es

Deleted: begin 

Deleted: time is not 

Deleted: time and compliance 

Deleted: requirements 

Deleted: compared not only with each other but 

also with 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 634 of 1544

section 111(b)(1)(B). Under CAA section 111(b)(1)(B), the EPA is 

required to “review and, if appropriate, revise” the section 

111(b) standards “at least every 8 years.” This provision 

obligates the EPA to review the section 111(b) rule for CO2 

emissions from new, modified, and reconstructed power plants by 

the year 2023. That mandatory review will reassess the BSER to 

determine the appropriate stringency for emission standards for 

new, modified, and reconstructed sources into the future. 

Therefore, for present purposes of comparing the stringency of 

the section 111(b) and 111(d) rules, the year 2023 presents an 

important point of comparison. 

Specifically, as noted above, the section 111(b) standards 

apply to new, modified and reconstructed sources beginning in 

2015, while the section 111(d) rule does not take effect until 

2022, which happens to fall on the cusp of the 8-year review for 

the 111(b) standards. 

 Even after the section 111(d) rule takes effect in 2022, 

the flexibility that this rule offers the states has important 

implications for its stringency and for any comparison to the 

section 111(b) rule. Although the requirements for the 111(d) 

rule begin in 2022, they are phased in, in a flexible manner,

over the 2022-2030 period. That is, states are required to meet 

interim goals for the 2022-2029 period by 2029, and the final 

Deleted: It is evident that the 111(b) 

requirements apply to new sources that 

construct beginning in 2015, whereas existing 

sources are uncontrolled until 2022. In 

addition, the EPA would be required to review 

and, if necessary, revise the CAA section 

111(b) rule in 2023

Deleted: , shortly after the interim compliance 

time for the CAA section 111(d) rule begins. 

As a result, application of 111(d) regulatory 

requirements will only just be beginning when 

the 111(b) standards will already be

Deleted: a mandatory review that will reassess 

the BSER factors to determine the appropriate 

stringency for new source emission standards 

into the future. This heightens the 

significance of the different compliance 

period.

Deleted: Because 

Deleted: of this 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 635 of 1544

goals by 2030, but states are not required to impose 

requirements on their sources that take effect in 2022. In 

fact, states may, if they prefer, apply the rate-based or massbased emission standards on their sources that take effect no 

earlier than 2023 (and, in the emission guidelines, have an 

annual compliance period), and thereby allow their sources to 

delay having to comply with these standards until the end of 

2023.623

Therefore, while the section 111(b) standards apply to new, 

modified, and reconstructed sources beginning in 2015, the 

section 111(d) standards may not apply to existing sources until 

2023. As a result, by 2023 – the year that the 111(b) standards 

are required to be reviewed for possible revision – affected 

EGUs subject to the 111(d) standards may remain uncontrolled.

Under those circumstances, the 111(d) rule cannot be said to be 

more stringent than the 111(b) rule.624 

 

623 A state that chooses to allow its sources to remain 

uncontrolled through 2023 would still be able to meet its 

interim goal by 2029, although it would need to impose more 

stringent requirements on its sources over the 2024-2029 period 

than it would if it had imposed requirements beginning in 2022.

624 In addition, because the section 111(d) requirements are 

phased in, states may choose to apply a gradual phase-in of the 

reductions. This means that the nominal emission rates for 

section 111(d) sources would be significantly less stringent for 

the first several years of the compliance period. We estimate 

that if states choose to impose the section 111(d) requirements 

in a proportional amount each year, beginning in 2022, the 

Deleted: 

Deleted: , the initial compliance obligations 

are significantly less stringent than the 

final compliance obligations. For example, 

because of the flexibility of the section 

111(d) requirements, states are not required 

to impose emission reduction requirements on 

their sources during the first years of the 

2022-2030 compliance period

Moved (insertion) [6]

Deleted: To reiterate, the fact that the new 

source standard applies immediately while the 

existing source standard does not apply for 7 

years is an important reason why the new 

source standard cannot be considered less 

stringent in fact.In addition, because the 

requirements are phased in,

Deleted: states may choose to apply a gradual 

phase-in of the reductions. We estimate that 

if states choose to impose the requirements in 

a proportional amount each year, the 

requirements for steam generators by 2022 

would result in an average emissions 

performance rate of 1,764 lb. CO2/MWh and by 

2023, an average emission rate of 1,698 lb. 

CO2/MWh. In fact, with that estimate, it is 

not until 2029 that the average rate drops 

below 1,400 (to 1,359), and it does not reach 

1,305 until 2030. These rates at these points 

in time provide important points of comparison 

with the standard of performance required for 

new steam EGUs under the section 111(b) rule, 

which, as noted, is 1400 lb. CO2/MWh. By no 

later than 2023, the EPA will be required 

under CAA section 111(b)(1)(B) to “review and, 

if appropriate, revise” that 1400 standard. 

Thus, at the latest time (2023) that the 1,400 

standard will apply to new steam EGUs before 

the EPA will be required to review it for 

possible revision, the section 111(b) standard 

will be more stringent than the existing 

source requirements, which, to reiterate, may 

not impose any emission reduction requirements 

on existing steam EGUs and which, if the 

states implement it proportionally, would 

result in emission limits of 1,698.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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Another reason why the section 111(d) rule cannot be said 

to be more stringent than the section 111(b) rule is that for 

any individual source, the 111(d) rule is applied more flexibly 

and includes more flexible means of compliance. Whereas the 

section 111(b) rule entails an emission rate that each affected 

EGU must meet on a 12-month (rolling) basis, the section 111(d) 

is more flexible. For example, states may adopt the state 

measures approach and refrain from imposing any requirements on 

their affected EGUs. In addition, under the section 111(d) rule, 

sources have more flexible means of compliance. For an emission 

standards approach, depending on the form of the state 

requirements (mass-based or rate-based), the state may be 

expected to authorize trading of mass-based emission allowances 

or rate-based emission credits, and in addition, the purchase of 

ERCs. These flexibilities are not included in the section 111(b) 

rule, rather, as noted, each new, modified, and reconstructed

EGU must individually meet its emission standard on a 12-month 

 

requirements for steam generators by 2022 would result in an 

average emissions performance rate of 1,764 lb. CO2/MWh net and 

by 2023, an average emission rate of 1,698 lb. CO2/MWh net (In 

2030, the rate falls to 1,305 lb. CO2/MWh net.) For existing 

NGCC units, if states choose to implement the 111(d) 

requirements proportionally, in 2022, the average rate would be 

910 lb. CO2/MWh net, and in 2023 it would be 899 lb. CO2/MWh 

net. (In 2030, this rate falls to 771 lb. CO2/MWh net.)

Deleted: The emission rate for existing NGCC 

units over the 2022-2030 period shows the same 

characteristics. States need not impose any 

emission reduction requirements on their 

existing NGCC units during the first years. If 

states choose to implement those requirements 

proportionally, in 2022, the average rate 

would be 910 lb. CO2/MWh, and in 2023 it would 

be 899.625 As a result, at the latest time 

(2023) that the 1,000 lb. CO2/MWh standard 

will apply to new NGCC units before the EPA 

will be required to review it for possible 

revision, the standard would not be less 

stringent than the existing source 

requirements, which do not necessarily entail 

any emission reduction requirements in a 

particular year from existing sources (so long 

as the interim goal is met), and, if the 

states choose to implement the requirements 

proportionally, would be less stringent than 

the average emission rate limit (899), but not 

substantially so. 

Moved up [6]: To reiterate, the fact that the 

new source standard applies immediately while 

the existing source standard does not apply 

for 7 years is an important reason why the new 

source standard cannot be considered less 

stringent in fact.

Deleted: In addition, 

Deleted: CAA section 

Deleted: The state may assign emission limits 

differently from the EPA’s guidelines, and 

Deleted: 

Deleted: . 

Deleted: CAA 

Deleted: and

Deleted: s

Deleted: the

Deleted: at all times
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 637 of 1544

(rolling) basis. The EPA has frequently required that sources 

meet a more stringent nominal limit when they are allowed 

compliance flexibility, particularly, the opportunity to 

trade.626 In addition, states have the discretion to allow their 

sources to meet emission standards over a longer time period. 

This distinction between the two rules is another reason why the 

section 111(d) rule cannot be said to be more stringent in fact 

than the section 111(b) rule.

 There are other reasons why the section 111(d) rule cannot 

be said to be more stringent. With respect to the 111(d) and 

111(b) rules for existing and new NGCC units, we note the 

following: As explained in the section 111(b) preamble, the 

standard for new NGCC units is designed to accommodate a wide 

range of unit types, including small units and rapid-start 

 

626 See, e.g., EPA, “Improving Air Quality with Economic 

Incentive Programs,” EPA-452/R-01-001, at 82 (2001) (requiring 

that Economic Incentive Programs show an environmental benefit, 

such as “reducing emission reductions generated by program 

participants by at least 10 percent”), available at 

http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf; “Economic 

Incentive Program Rules: Final Rule,” 59 FR 16690 (April 7, 

1994) (same); “Certification Programs for Banking and Trading of 

NOx and PM Credits for Heavy-Duty Engines: Final Rule,” 55 FR 

30584 (July 26, 1990) (requiring that for programs for banking 

and trading of NOx and PM credits for gasoline, diesel and 

methanol powered engines, all trading and banking of credits 

must be subject to a 20 percent discount “as an added assurance 

that the incentives created by the program will not only have no 

adverse environmental impact but also provide an environmental 

benefit.”) . 

Deleted: CAA 

Deleted: in fact 

Deleted: CAA 

Deleted: e

Deleted: i

Deleted: p
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 638 of 1544

units, which are a small part of the expected new NGCC 

generation capacity. As such, the 111(b) standard (1,000 lb 

CO2/MWh gross, which equates to 1,030 lb CO2/MWh net) will not 

constrain the emissions of the great majority of expected new 

NGCC generation capacity, which is expected to consist of larger 

base load units (with a capacity of 100 MW or greater) that are 

not designed to cycle frequently. Their initial emissions are 

expected to be below 800 lb. CO2/MWh gross, their emissions over 

time may be somewhat higher due to equipment deterioration, and 

as a result, their PSD permits are expected to include emission 

limits at approximately the 800 lb. CO2/MWh gross level. A very 

small amount of the new NGCC generation is expected to be small 

units (with a capacity of approximately 25 MW) or rapid-start 

units. Their initial emissions are expected to be approximately 

950 lb. CO2/MWh gross, their emissions over time are expected to 

be somewhat higher due to equipment deterioration, and it these 

units that the standard of 1,000 lb. CO2/MWh gross is designed to 

constrain.627 As a result, the 1,000 lb. CO2/MWh gross limit 

applies to all new NGCC units, including the great majority of 

the expected new capacity consisting of larger, non-rapid start 

units, even though, as just noted, the great majority of the 

 

627 As explained in the 111(b) preamble, any attempt to 

subcategorize and assign a lower emission limit to larger, nonrapid start NGCC units could cause market distortions.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 639 of 1544

units are expected to emit at significantly lower emission 

rates. The section 111(d) standard for existing sources, in 

contrast, is generally expected to constrain existing NGCC units 

on average. Moreover, very little of the existing NGCC 

generation includes small units or, in particular, rapid-start 

units because the latter are a recently developed technology. To 

some extent, the same is true for the 111(b) standards for 

modified or reconstructed NGCC units. The average NGCC rate was 

approximately 850 lb CO2/MWh gross in 2014 and, as a result, 

most sources are emitting below the section 111(b) standards for 

modifications and reconstructions. For these reasons, too, the 

111(b) standards for new, modified, and reconstructed NGCC units 

cannot be compared to the 111(d) standards for existing NGCC 

units.628

 Moreover, even if commenters were correct that the section 

111(d) requirements for existing sources are more stringent than 

the section 111(b) requirements for new sources, that would not, 

by itself, call into question the reasonableness of either 

standard. The stringency of the requirements for each source 

subcategory is, of course, a direct function of the BSER 

 

628 The section 111(b) standards for modified and reconstructed 

steam generation units are generally lower than the emission 

rates of existing stream generation units, but for the reasons 

explained earlier, those standards cannot be compared to the 

section 111(d) standards for existing steam generation units.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 640 of 1544

identified for that source subcategory. In this rulemaking, we 

explain the basis for the BSER for existing sources, and why we 

do not include certain measures, such as CCS; and in the section 

111(b) rulemaking, we explain the basis for the BSER for new 

sources, and why we do not include certain measures, such as the 

building blocks. As long as the BSER determination is reasonable 

and the resulting emission limits meet other applicable 

requirements, those emission limits are valid, even if the one 

for new sources is less stringent than the one for existing 

sources. No provision in section 111, nor any statement in its 

legislative history, nor any of its case law, indicates that the 

standards for new sources must be more stringent than the 

standards for existing sources. 

C. Building Block 1—Efficiency Improvements at Affected CoalFired Steam EGUs 

The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 

reduce the carbon intensity of generation at individual coalfired steam EGUs by improving their heat rate. Heat rate 

improvements are changes implemented at an EGU that increase the 

efficiency with which the EGU converts fuel energy to electric 

energy, thereby reducing the amount of fuel needed to produce 

the same amount of electricity and consequently lowering the 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 641 of 1544

amount of CO2 produced as a byproduct of fuel combustion. Heat 

rate improvements yield important economic benefits to affected 

EGUs by reducing their fuel costs. 

An EGU’s heat rate is the amount of fuel energy input 

needed (Btu, higher heating value basis) to produce 1 kWh of net 

electrical energy output.629 In 2012, the generation-weighted 

average annual heat rate of the 884 coal-fired EGUs included in 

EPA’s building block 1 analysis was approximately 9,732 Btu per 

gross kWh.630 Because an EGU’s CO2 emissions are driven primarily 

by the amount of fuel consumed, improving (i.e., decreasing) 

heat rate at a coal-fired EGU inherently reduces the carbonintensity of generation.

As discussed above in section V.A and in the June 2014 

proposal,631 it is critical to recognize that affected coal-fired 

EGUs operate in the context of the integrated electricity 

system. Because of this reality, applying building block 1 in 

isolation can result in a “rebound effect” that undermines the 

 

629 Typically, the units of measure used for heat rate (e.g., 

Btu/kWh-net) indicate whether a given value is based on the 

gross output or net output. Net heat rate is always higher than 

gross heat rate; in coal-steam units, net heat rate can be 5–10% 

higher than gross heat rate. 

630 Similarly, within each interconnection, the generationweighted average annual heat rates for those coal-fired EGUs in 

our study population were 9,700 Btu per gross kWh (Eastern); 

9,888 Btu per gross kWh (Western); and 9,789 Btu per gross kWh 

(Texas). 

631 See, e.g., 79 FR 34830, 34859 (June 18, 2014). 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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emissions reductions otherwise achieved by heat rate 

improvements. As already noted, the building block 1 measures 

described below cannot by themselves constitute the BSER because 

the quantity of emission reductions achieved -- which is a 

factor that the courts have required EPA to consider in 

determining the BSER -- would be of insufficient magnitude in 

the context of this pollutant and this industry. The potential 

rebound effect, if it occurred, would exacerbate the 

insufficiency of the emission reductions. However, applying 

building block 1 in combination with other building blocks can 

address this concern for the reasons stated in section V.A.4. 

We conducted several analyses to assess the potential for 

heat rate improvements from the coal-fired EGU fleet. As in the 

proposal, we employed a unit-specific approach that compared 

each EGU’s performance against its own historical performance in 

lieu of directly comparing an EGU’s performance against other 

EGUs with similar characteristics. Accordingly, as described 

below, our method effectively controls for the characteristics 

and factors of an EGU that typically remain constant over time 

(e.g., a unit is unlikely to dramatically increase or decrease 

in size). Our methodology for determining the amount of heat 

rate improvement appropriately included in the BSER as building 

block 1 is discussed in the next section, below. 

Deleted: ¶
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 643 of 1544

1. Summary of measures comprising the BSER in building block 1 

a. Measures under building block 1 - heat rate improvements. In 

finalizing the building block 1 portion of this rule, we 

considered over a thousand individual comments from the public, 

including individual EGUs and state agencies, on heat rate 

improvement, which are discussed below and also in the responses 

to comments document and the GHG Mitigation Measures TSD for the 

CPP Final Rule [Docket ID No. EPA-HQ-OAR-2013-0602]. Based on 

these public comments, we have refined the statistical analyses 

used in the proposal to identify the potential heat rate 

improvement that can be achieved on average by affected coalfired EGUs. 

In the proposal, we used two approaches to analyze the 

variability of an EGU’s gross heat rate using a robust dataset 

comprised of 11 years of hourly gross heat rate data for 884 

coal-fired EGUs -- over 11 million hours of data collected 

between 2002 and 2012. The foundation of our first approach was 

an analysis of the variability of each EGU’s gross heat rate, 

which was accomplished in large part by grouping each EGU’s 

hourly data by similar ambient temperature and capacity factor 

(i.e., hourly operating level as a percentage of nameplate 

capacity) conditions. The second approach analyzed the 

difference between an EGU’s average gross heat rate and its best 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 644 of 1544

historical gross heat rate performance. We proposed that, on a 

nationwide basis, affected coal-fired EGUs should be able to 

achieve 6-percent heat rate improvement: 4-percent improvement 

from best practices, and an additional 2-percent improvement 

from equipment upgrades. 

We received many comments asserting that the 11-year 

dataset we had used to determine the 4-percent best practices 

figure likely reflected some portion of the 2-percent equipment 

upgrades figure we had separately identified. Accordingly, these 

commenters claim that the EPA double-counted equipment upgrades 

in arriving at the full estimate of 6-percent heat rate 

improvement. Commenters also noted the difficulty, in some 

cases, of determining whether a heat rate improvement measure is 

an “equipment upgrade” or “best practice,” such as optimizing 

soot blowing with intelligent systems, using CO monitors for 

optimizing combustion, or applying air heater and duct leakage 

controls. 

As noted below in sections V.C.1.b and V.C.3, the EPA 

acknowledges that some equipment upgrades implemented by EGUs 

during the 11-year study period are reflected in the hourly heat 

rate data. Therefore, we made two refinements to our analyses of 

heat rate improvement potential. First, we refined our 

statistical approaches to use each EGU’s gross heat rate from 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 645 of 1544

2012 -- the final year of the 11-year study period -- as the 

baseline for calculating heat rate improvement potential. By 

comparing each EGU’s best historical gross heat rate with its 

2012 gross heat rate, our analyses account for the enduring 

effects on heat rate of any equipment upgrades or best practices 

that an EGU implemented during the study period. Heat rate 

improvement measures that an EGU maintains in 2012 are reflected 

in that baseline, and thus are not treated as evidence that the 

EGU can further improve heat rate. Additionally, in part because 

of limitations on the information available to us regarding 

which equipment upgrades have been or could be implemented at 

individual EGUs, as well concerns about double-counting, we have 

conservatively decided not to add a separate equipment upgrade 

component to our estimate of heat rate improvement potential. 

Nonetheless, we remain confident that additional equipment 

upgrades (including measures that are unambiguously equipment 

upgrades, such as turbine overhauls) are possible at many coalfired EGUs, as supported by numerous commenters, the Sargent & 

Lundy study632 (S&L) and other industry reports and studies. Many 

of these reports and studies are referenced in the TSD developed 

 

632 Sargent and Lundy 2009, Coal-Fired Power Plant Heat Rate 

Reductions, SL-009597, Final Report, January 2009, Docket ID No. 

EPA–HQ–OAR–2013–0602-XXXX, available at: 

http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf. Deleted: http://www.epa.gov/airmarkets/resource

/docs/coalfired.pdf
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 646 of 1544

for the proposed rule, as well as in the GHG Mitigation Measures 

TSD supporting the final CPP. 

Several commenters criticized the fact that the proposal 

assessed potential heat rate improvement on a nationwide basis. 

These commenters suggested instead that we narrow the geographic 

scope of our analysis, generally identifying a state-by-state 

approach as a preferred alternative. In light of commenters’ 

concerns about using a single nationwide approach, as well as 

for reasons described in Section V.A and elsewhere in this 

preamble, the final rule assesses potential heat rate 

improvement regionally, within the Eastern, Western and Texas 

Interconnections.633

For the final rule, we performed several analyses to 

determine what heat rate improvement was achievable in each 

interconnection from best practices and equipment upgrades. As 

in the proposal, these analyses used the 11-year dataset of EGU 

hourly gross heat rate data from 2002 to 2012. As discussed 

further in the GHG Mitigation Measures TSD, our reliance on 

these gross heat rate data was reasonable given that (1) these 

 

633 The geographic area within the Texas Interconnection 

generally corresponds to the portion of the state of Texas 

covered by ERCOT (the Electric Reliability Council of Texas). 

Additional portions of the state of Texas are located within the 

Eastern and Western Interconnections. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 647 of 1544

data are the only comprehensive data available to the EPA, and 

(2) heat rate is proportional to CO2 emission rate. 

As in the proposal, we used more than one analytical method 

to evaluate the opportunity for EGUs to reduce their CO2

emissions through heat rate improvements. Our final methodology 

uses three different analytical approaches based on refinements 

of the two approaches described at the proposal stage. We call 

these final approaches: (1) the “efficiency and consistency 

improvements under similar conditions” approach; (2) the “best 

historical performance” approach; and (3) the “best historical 

performance under similar conditions” approach. As described 

below and in the GHG Mitigation Measures TSD, each approach 

provides an independently reasonable way to estimate the 

potential for heat rate improvements by EGUs in each region. 

However, rather than select a potential heat rate improvement 

value supported by one or only some of these independently 

reasonable analytical approaches, we conservatively based our 

final determination for each region on the value for that region 

supported by all three approaches. 

The “efficiency and consistency improvements under similar 

conditions” approach is a slight refinement of an approach 

discussed at length in the proposal. As in the proposal, we 

distributed each hour of gross heat rate data for each EGU into 

Deleted: average 

Deleted: average 

Deleted: first approach, referred to here as 

the 

Deleted: ,
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 648 of 1544

a matrix comprised of 168 bins, based on the ambient temperature 

and hourly capacity factor of the EGU at the time that hour of 

gross heat rate data was generated. Each bin represented a 10-

degree Fahrenheit (oF) range in ambient temperature (from -20oF 

to greater than 110oF), and a 10-percent range in capacity factor 

(from 0 percent to greater than 110 percent634). Thus, for 

example, one bin would contain all of an EGU’s hourly gross heat 

rate data generated during the 11-year study period while that 

EGU was operating at 80- to 89-percent capacity while ambient 

temperatures were between 70oF and 79oF. 

As we explained at proposal and as discussed further in the 

GHG Mitigation Measures TSD, ambient temperature and hourly 

capacity factor are important conditions that influence heat 

rate at individual EGUs. By separating the EGU-specific data 

into bins based on these variables, and only directly comparing 

data within a bin, we were largely able to control for the 

influence of those variables on an EGU’s heat rate. Accordingly, 

having controlled for these two external factors, and having 

already controlled for unit-specific factors affecting heat rate 

by analyzing the data for each EGU in isolation, we are 

 

634 Because an EGU’s rated nameplate capacity is based on a 

maximum continuous rating, EGUs may operate for periods of time 

“over” 100 percent of their capacity factor. The EPA’s dataset 

of hourly operating data reflected some such instances. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 649 of 1544

confident that the remaining variation in each bin’s data was 

primarily driven by factors under the EGU operator’s control. 

After allocating an individual EGU’s data across the bins, 

we next established a benchmark for each bin based on the best 

hourly gross heat rate accounting for outliers (i.e., we set the 

benchmark at the 10th percentile hourly gross heat rate value) 

during any consecutive two-year period.635 We compared the hourly 

gross heat rate data within each bin to the EGU’s benchmark 

value. Similar to the proposal, within each bin we assessed the 

effect on heat rate of improving the consistency of that EGU by 

reducing hourly gross heat rate values that were greater than 

the benchmark by a percentage of the distance between each of 

those higher hourly values and the benchmark.636 We refer to this 

percentage improvement value as the “consistency factor,” 

because applying it results in values for heat rate that are 

more consistent with the EGU’s benchmark for that bin. In our 

proposal we evaluated the heat rate improvement that would 

result from applying consistency factors of 10, 20, 30, 40 and 

 

635 As described below, we also conducted this regionalized 

approach using a benchmark based on the best hourly gross heat 

rate accounting for outliers during any one-year period. See the 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 

636 In the proposal, we used heat input values rather than gross 

heat rate values. See the GHG Mitigation Measures TSD supporting 

the final CPP for more details. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

Page 650 of 1544

50 percent of the distance between those less-efficient hourly 

gross heat rate values and the benchmark; using engineering 

judgment, we selected a consistency factor of 30 percent, which 

produced results comparable to those obtained using other 

approaches for analyzing heat rate. For our final analysis under 

this approach, we refined the consistency factor based on a 

statistical assessment of the overall variability of heat rate 

in that EGU’s region, as described in the GHG Mitigation 

Measures TSD.637 As in the proposal, we applied the consistency 

factor to each bin of each EGU’s hourly gross heat rate data, 

and averaged the result across all bins in that EGU’s matrix. 

The net result was an improved gross heat rate reflecting what 

that EGU would have achieved between 2002 and 2012 if, under 

certain ambient temperature and capacity factor conditions, the 

EGU had improved its gross heat rate during less-efficient hours 

to be slightly more consistent with the relevant benchmark 

value. We then compared the improved gross heat rate for each 

EGU to its actual 2012 historic average gross heat rate. We 

 

637 For the Eastern Interconnection, the consistency factor is 

38.1 percent. For the Western Interconnection, the consistency 

factor is 38.4 percent. For the Texas Interconnection, the 

consistency factor is 37.1 percent. Conducting this analysis on 

a nationwide basis would have resulted in application of a 

consistency factor of 38.2 percent. As described below, we also 

conducted this regionalized approach using consistency factors 

determined based on one-year figures. See the GHG Mitigation 

Measures TSD supporting the final CPP for more details. 

Deleted: . Using 
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chose 2012 as the year of comparison because 2012 was the latest 

year for which the EPA had data at the time of the proposal, and 

because using the most recent data reflects the EGU’s current 

operating level and accounts for improvements the EGU may have 

undertaken over the 11-year study period. 

Applying this procedure to all units in our database and 

averaging the generation-weighted results, we determined that it 

would be reasonable to conclude that, through application of 

best practices and equipment upgrades, EGUs on average are at 

least capable of reducing their CO2 emissions by improving heat 

rate 4.3 percent in the Eastern Interconnection, 2.1 percent in 

the Western Interconnection, and 2.3 percent in the Texas 

Interconnection.638 

In addition to the statistical approach described above, we 

employed a “best historical performance” approach refined from 

the proposal, which compared each EGU’s best two-year rolling 

average gross heat rate to that EGU’s 2012 average annual gross 

heat rate.639 We then calculated the differences across all EGUs 

 

638 Conducting this analysis on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.0 percent. See the table in this section and the GHG 

Mitigation Measures TSD for the results of this approach using 

benchmarks and consistency factors based on one-year averages. 

639 As described below, we also conducted this regionalized 

approach using each EGU’s best one-year rolling average. See the 

Deleted: annual 
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in a region to determine the potential heat rate improvement 

that would result if, in 2012, each EGU had performed at the 

best two-year rolling average gross heat rate that the EGU 

achieved between 2002 and 2012. Under this analysis of 

historical gross heat rate, we determined that it would be 

reasonable to conclude that the average heat rate improvement 

potential from best practices and equipment upgrades is at least 

4.9 percent in the Eastern Interconnection, 2.6 percent in the 

Western Interconnection and 3.1 percent in the Texas 

Interconnection.640 

Finally, we employed the “best historical performance under 

similar conditions” approach, which combines aspects of the 

other two approaches. First, as with the “efficiency and 

consistency improvements under similar conditions approach,” we 

grouped hourly data for each EGU by ambient temperature 

conditions and hourly capacity factor. Next, we calculated each 

EGU’s best two-year gross heat rate for each of the 168 ambient 

 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 

640 Conducting this approach on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.6 percent. As described below, we also conducted this 

regionalized approach using one-year averages. See the GHG 

Mitigation Measures TSD supporting the final CPP for more 

details. 

Deleted: Our third and f

Deleted: inal approach, 

Deleted: annual 

Deleted: first two 
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temperature-capacity factor bins.641 Similar to the “best 

historical performance” approach, to calculate the potential 

heat rate improvement, the EPA then compared each EGU’s 2012 

gross heat rate for each of the ambient temperature-capacity 

factor bins to the EGU’s best two-year gross heat rate for the 

corresponding bin. Accounting for differences in ambient 

temperature and capacity factor, we determined that under this 

analytical approach the average heat rate improvement potential 

from best practices and equipment upgrades was at least 5.3 

percent in the Eastern Interconnection, 3.1 percent in the 

Western Interconnection and 3.5 percent in the Texas 

Interconnection.642

As in the proposal, we additionally analyzed the data with 

our analytical approaches using one-year averaging periods in 

place of the two-year averaging periods described above.643

However, because our conservative overall methodology adopts the 

lowest value that is identified for a region by any of our 

 

641 As described below, we also conducted this approach using 

one-year averages for each EGU instead of two-year averages. See 

the GHG Mitigation Measures TSD supporting the final CPP for 

more details. 

642 Conducting this approach on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

5.0 percent. 

643 The GHG Mitigation Measures TSD describes in more detail our 

rationale for using one- and two-year averaging periods in our 

analytical approaches and methodology as a whole. 

Deleted: average 
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reasonable analytical approaches, the inherently less 

conservative results obtained with one-year averaging periods 

(reproduced below) could not influence the outcome of our 

methodology as a whole. Overall, applying these three analytical 

approaches resulted in six heat rate improvement values 

generated for each region, each of which represents a reasonable 

estimate of the potential for heat rate improvements by EGUs in 

that region. Those values ranged from 4.3 to 6.9 percent in the 

Eastern Interconnection, from 2.1 to 4.7 percent in the Western 

Interconnection, and from 2.3 to 4.9 percent in the Texas 

Interconnection. In all three regions, the most conservative 

values were generated using the “efficiency and consistency 

improvements under similar conditions” approach with two-year 

averaging periods and consistency factors. As shown in Table 5, 

the values produced by that approach were the minimum values for 

each region produced by any of the three approaches: 

Table 6. Heat Rate Improvement Potential by Region and Averaging 

Period. 

Analytical approach 

Heat rate improvement potential 

(percent) 

by region and averaging period 

Western Texas Eastern 

1 

year 

2

year 

1

year 

2

year 

1

year 

2

year

Efficiency and 

consistency improvements 

under similar conditions 

3.5% 2.1%* 3.7% 2.3%* 5.6% 4.3%*

Deleted: 6

Deleted: 6
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Best historical 

performance 4.1% 2.6% 4.2% 3.1% 6.3% 4.9%

Best historical 

performance under 

similar conditions 

4.7% 3.1% 4.9% 3.5% 6.9% 5.3%

Accordingly, we have concluded that a well-supported and 

conservative estimate of the potential heat rate improvements 

(and accompanying reductions in CO2 emission rates) that EGUs can 

achieve on average through best practices and equipment upgrades 

is a 4.3-percent improvement in the Eastern Interconnection, a 

2.1-percent improvement in the Western Interconnection and a 

2.3-percent improvement in the Texas Interconnection. The 

decision to use these values as the building block 1 potential 

in each region is based on the weight of evidence that these are 

conservative values; for each region, each of the three 

analytical approaches in our methodology supports our 

determination that the heat rate improvement value we selected 

is achievable. Taken individually, each approach provides an 

independently reasonable estimate of the potential for heat rate 

improvement. Furthermore, as described in the GHG Mitigation 

Measures TSD, these approaches are conservative on even an 

individual basis because they do not account for the full extent 

of heat rate improvements available through additional equipment 

upgrades and best practices. Some EGUs may have faced 

Deleted: annual 

Deleted: annual 
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difficulties achieving significant heat rate improvement in the 

past and EGU owners may feel they face challenges in the future. 

Nevertheless, our methodology as a whole indicates that, on 

average, coal-fired EGUs can at least achieve the percentage 

heat rate improvement selected for their region through 

application of best practices and some of the available 

equipment upgrades. A more detailed discussion of the EPA’s 

analysis in determining the heat rate improvement potential for 

existing coal-fired EGUs may be found in the GHG Mitigation 

Measures TSD supporting the final CPP.

No affected coal-fired EGU is specifically required to 

improve heat rate by any amount as a result of this rule. 

Rather, as described in section VI, the potential for heat rate 

improvement is used to determine a CO2 emission performance rate. 

Those affected EGUs that have done the most to reduce their heat 

rate will tend to be closer to that CO2 emission rate. In this 

sense, our approach to determining potential CO2 reductions 

through heat rate improvements is similar to the way EPA 

ordinarily approaches standards of performance.644 

 

644 To give an illustrative example, imagine a population of 

sources that emit Pollutant X. Half of the sources emit 

Pollutant X at 2500 lbs/hour, while the other half of the 

sources have scrubbers installed that reduce their emission 

rates to 1500 lbs/hour. Because the sources are evenly divided 

between those with and without scrubbers, the average emission 
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In this final analysis, we do not delineate what proportion 

of the potential heat rate improvement can be expected from 

equipment upgrades versus best practices;645 only that these heat 

 

rate for the population as a whole is 2000 lbs/hour. In this 

hypothetical, EPA decides to base requirements on the emission 

rate achievable through use of a scrubber, meaning that all 

sources will have to meet an emission rate of 1500 lbs/hour. 

Because the fleet as a whole has an average emission rate of 

2000 lbs/hour, it would be accurate for EPA to say that the 

fleet as a whole can reduce its emission rate by 25 percent -- 

from 2000 lbs/hour on average (only half the sources with 

scrubbers), to 1500 lbs/hour on average (all the sources with 

scrubbers). This description of what is possible for the fleet 

as a whole -- a 25-percent reduction in emission rate -- should 

not be misinterpreted as a statement that every individual

source is capable of further reducing its emissions by 25 

percent. The sources that have already installed scrubbers, and 

which are thus already operating at 1500 lbs/hour, would not be 

required to further improve their emission rate. 

645 Examples of the many types of best practices and equipment 

upgrades available to coal-fired EGUs include adopting sliding 

pressure operation to reduce turbine throttling losses; 

installing intelligent sootblowing system software; upgrading 

the combustion control/optimization system; installing heat rate 

optimization software; installing a production cost optimization 

program that benchmarks plant thermal performance using 

historical plant data; establishing centralized remote 

monitoring centers with thermal performance software for 

monitoring heat rates systemwide; repairing steam and water 

leaks; automating steam system drains; performing an on-site 

performance appraisal to identify potential areas for improved 

performance; developing heat rate improvement procedures and 

training O&M staff on their use; aligning the cycle to isolate 

or capture high-energy fluid leakage from the steam cycle; 

repairing utility boiler air in-leakage; performing utility 

boiler chemical cleaning; installing condenser tube cleaning 

system; retubing condenser; repairing/upgrading flue gas 

desulfurization systems; cleaning air preheater coils; 

adjusting/replacing worn air heater seals; replacing corroded 

air heater baskets; replacing feed pump turbine steam seals; 

overhauling high pressure feedwater pumps; installing fan and 

Deleted: 

Deleted: 
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rate improvements are achievable in the regions through a 

combination of these methods. As discussed in section V.C.3 

below, we believe that a single heat rate improvement goal for 

each region incorporating both best practices and upgrades, 

based on the 11 years of hourly heat rate data for 884 coalfired EGUs available to the EPA, is a reasonable approach that 

is supported by our analysis, and is particularly conservative 

given that it does not account for the full range of heat rate 

improvements achievable through additional equipment upgrades 

and best practices. 

The performance rates quantified in section VI, below, 

reflect the region-specific values for heat rate improvement. 

Although the performance rates are based on the least stringent 

overall performance rate determined to be reasonable for any 

region, and are thus based in part on the percentage heat rate 

improvement identified for the region, this rule does not itself 

require any specific EGU to implement measures resulting in a 

specific percentage heat rate improvement. Rather, the 

percentage heat rate improvement value is merely reflected in 

the CO2 emission performance rates and corresponding mass-based 

 

pump variable speed/frequency drives; upgrading turbine steam 

seals; upgrading all turbine internals; and installing coal 

drying systems. These and additional heat rate improvement 

measures are discussed further in the GHG Mitigation Measures 

TSD for the CPP Final Rule. 
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and rate-based state goals. Each state has the flexibility to 

develop a plan that achieves those CO2 performance rates or 

emission goals by assigning the emission standards the state 

considers appropriate to its affected coal-fired EGUs. 

Similarly, depending on the content of the applicable plan, 

affected EGUs may achieve their emission standards through use 

of any of the building block measures described in this rule or 

any other measures permitted under the plan. 

b. Changes from the proposal. In the proposed rule, we 

determined that building block 1 measures could on average 

achieve a 6-percent heat rate improvement from coal-fired EGUs 

in the U.S. based on a 4-percent heat rate improvement from 

implementation of best practices and a 2-percent heat rate 

improvement from equipment upgrades. Based on comments received 

and refinements made to our methodology for determining 

potential heat rate improvement from the hourly gross heat rate 

dataset of 884 coal-fired EGUs, we have conducted our analysis 

on a regional basis and reduced the overall expected percent 

heat rate improvement for coal-fired EGUs to 4.3 percent in the 

Eastern Interconnection, 2.1 percent in the Western 

Interconnection, and 2.3 percent in the Texas Interconnection.646

 

646 Had the EPA maintained a nationwide approach to analyzing the 

potential reductions under building block 1, the result would 

have been 4.0 percent. 
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These values reflect improvements achievable through both best 

practices and equipment upgrades because, as described above, we 

also no longer include a separate estimation of the potential 

heat rate improvement achievable solely through equipment 

upgrades. 

We received comments on our proposed statistical 

methodology for determining the CO2 emission reductions 

opportunities achievable by coal-fired EGUs through heat rate 

improvements. We have closely reviewed those comments and, for 

the final rule, have made refinements to our methodology, as 

described above and explained in more detail in the GHG 

Mitigation Measures TSD supporting the final CPP. 

In the final rule, the EPA extends the implementation 

deadline from 2020 to 2022. This additional time will be helpful 

to the states seeking to conduct more targeted analyses of the 

nature and extent of heat rate improvements that specific coalfired EGUs can make, considering specific recent improvements or 

upgrades, planned retirements of older coal-fired EGUs, and 

other relevant considerations. The extended deadline will also 

provide additional time to accommodate changes to heat rate 

monitoring methods at EGUs and for the installation of new 

pollution controls that comply with other rules, as discussed 

below in the summary of key comments. 
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2. Costs of heat rate improvements 

By definition, any heat rate improvement made by EGUs for 

the purpose of reducing CO2 emissions will also reduce the amount 

of fuel that EGUs consume to produce the same electricity 

output. The cost attributable to CO2 emission reductions, 

therefore, is the net cost of achieving heat rate improvements 

after any savings from reduced fuel expenses. As summarized 

below, we estimate that, on average, the savings in fuel cost 

associated with the percentage heat rate improvements we 

identified for each region would be sufficient to cover much of 

the associated costs. Accordingly, the net costs of heat rate 

improvements associated with reducing CO2 emissions from affected 

EGUs are relatively low. We recognize that this cost analysis 

will represent the costs for some EGUs better than others 

because of differences in individual circumstances. We further 

recognize that reduced generation from coal-fired EGUs due to 

the implementation of other building block measures would tend 

to reduce the fuel savings associated with heat rate 

improvements, thereby raising the effective cost of achieving 

the CO2 emission reductions from the heat rate improvements. 

Nevertheless, we still expect that a significant fraction of the 

investment required to capture the technical potential for CO2

emission reductions from heat rate improvements would be offset 

Deleted: the 

Deleted: majority 
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by fuel savings, and that the net costs of implementing heat 

rate improvements as an approach to reducing CO2 emissions from 

affected EGUs are reasonable. Even if we conservatively estimate 

that EGUs will largely rely on equipment upgrades rather than 

cheaper best practices to reduce heat rate, those reductions can 

generally be achieved at $100 or less per kW, or approximately 

$23 per ton of CO2 removed, as described in detail in the GHG 

Mitigation Measures TSD supporting the final CPP.647 Depending on 

the balance between equipment upgrades and best practices, 

improving heat rate would even result in a net savings for some 

EGUs. 

Based on the analyses of technical potential and cost 

summarized above and in Chapter 2 of the GHG Mitigation Measures 

TSD, we find that heat rate improvements of 4.3, 2.1 and 2.3 

percent are reasonable and conservative estimates of what coalfired EGUs in the Eastern, Western and Texas Interconnections, 

respectively, can achieve at a reasonable cost. 

3. Response to key comments 

 

647 The $100/kW cost figure from the proposal is now particularly 

conservative because it included the cost of significant 

equipment upgrades that improve heat rate, whereas building 

block 1 is now largely quantified based on low- or no-cost best 

practices, with a smaller portion of the remainder comprised of 

equipment upgrades. 

Deleted: 5.81 to $11.63

Deleted: metric 

Deleted: previously estimated in the proposal 

and 

Deleted: se

Deleted: s

Deleted: are 

Deleted: they 
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Many commenters said that the EPA should have 

subcategorized by EGU design or operating characteristics for 

purposes of evaluating potential heat rate improvements under 

building block 1. 

Several studies categorize EGUs broadly by capacity, 

thermodynamic cycle, fuel rank or other characteristics. We 

considered subcategorizing the EGUs by their design and fuel 

characteristics under building block 1. Although grouping by 

categories does not account for all of the factors that may 

affect heat rate, it can provide a useful way of understanding 

the operating profile of classes of coal-fired EGUs and the 

fleet as a whole. However, as discussed above, our assessment of 

heat rate improvement potential uses a unit-specific data 

methodology that compares each EGU’s performance against its own 

historical performance. By substantially basing our analysis on 

these unit-specific assessments, we inherently factor in the 

effect of numerous design conditions. We also conducted a 

regression analysis that evaluated the effect of numerous 

factors on heat rate, and found that subcategorizing would 

generally make little difference in our analysis. Additionally, 

subdividing the EGUs into subcategories would reduce the 

quantity of EGUs used to calculate each average, which would 

increase the influence of random and atypical variations in the 
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data on the overall averages, and would thus decrease our 

confidence in the results. Furthermore, states are free to 

apportion reductions in a way that reflects any subcategories of 

their choosing when determining the emission standards for 

individual affected EGUs. For a more detailed explanation of our 

decision not to subcategorize for purposes of determining 

building block 1, see the GHG Mitigation Measures TSD supporting 

the final CPP. 

Many commenters told the EPA that EGUs already have 

undertaken significant efforts to operate efficiently to provide 

reliable electric service at the lowest reasonable cost; that 

they believe they cannot significantly improve heat rate; that 

best practice maintenance activities are performed on a daily 

basis, including during maintenance outages that allow for the 

inspection, cleaning and repair of all equipment; that extensive 

capital investments have been made to install state-of-the art 

equipment and replace equipment that is beyond repair; and that 

their employees continuously monitor and control operating 

levels in the combustion process to maintain maximum combustion 

of fuel and to avoid wasting available heat energy. In summary, 

these commenters say they have expended considerable effort and 

resources to maintain peak boiler efficiency at all times and, 

therefore, the 6-percent heat rate improvement proposed for 
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building block 1 is unreasonable to apply to EGUs across the 

board; the EPA should develop a rule that allows treatment of 

affected EGUs on a case-by-case basis. 

We commend the efforts of those who strive to operate and 

maintain EGUs in the best possible manner to minimize heat loss 

and CO2 emissions. This rule does allow for treatment of EGUs on 

a case-by-case basis. States may believe that individual 

considerations are appropriate in some cases and, accordingly, 

we have purposely allowed states to make decisions about how to 

implement specific CO2 reductions. Our determinations of 4.3-, 

2.1- and 2.3-percent heat rate improvement for EGUs in the 

Eastern, Western and Texas Interconnection, respectively, are 

conservatively based on the lowest value identified by any of 

our reasonable statistical analyses. If states choose to set 

limits on individual affected EGUs based in part on the 

availability of heat rate improvements, the states are free to 

assess heat rate improvements on a more targeted, case-by-case 

basis that takes into account an EGU’s previous heat rate 

improvement efforts, or lack thereof. The fact that states (or 

EGUs complying with state requirements) can make case-by-case 

decisions about how to achieve goals does not contradict our 

conservative estimates -- which are based on millions of hours 

of operating data reported to the EPA by EGUs -- of how much 
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EGUs are capable of improving their heat rate in each region 

overall. Opportunities to improve heat rate abound for affected 

EGUs as a whole, as evidenced by the fact that the approaches in 

our statistical methodology each included a comparison of an 

EGU’s historical heat rate to its 2012 heat rate. Our estimates 

of the potential heat rate improvement are additionally 

conservative because they are based purely on comparisons among 

historical gross heat rate data, and thus do not reflect 

available, cost-effective opportunities to improve heat rate 

that affected EGUs never implemented during the study period. 

Finally, to the extent that an affected EGU was in 2012 fully 

implementing every possible best practice for improving heat 

rate, it may still be capable of improving heat rate through 

equipment upgrades. 

Other commenters said that a 6-percent heat rate 

improvement overall is too high; that the heat rate improvement 

from upgrades are double-counted within the data used to 

determine heat rate improvements from best practices; and that 

the 2-percent heat rate improvement specifically for upgrades 

was inappropriately based on “conceptual” improvements from only 

one study. 

We have reduced the 6-percent heat rate improvement from 

the proposed rule to three regionalized figures of 4.3 percent 

Deleted: Furthermore
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(Eastern), 2.1 percent (Western) and 2.3 percent (Texas), as 

discussed above and described in detail in the GHG Mitigation 

Measures TSD supporting the final CPP. We expect that, on 

average, affected coal-fired EGUs can at a minimum improve heat 

rate in these amounts by implementing best practices and 

equipment upgrades identified in the GHG Mitigation Measures 

TSD. These overall heat rate improvement figures do not include 

an estimated percent heat rate improvement attributable 

specifically to upgrades. Although we are no longer including in 

our calculation of building block 1 a separate 2-percent heat 

rate improvement attributable solely to equipment upgrades, this 

decision is not because we believe that our initial 2-percent 

assessment of equipment upgrades was incorrect. To the contrary, 

the information presented in the S&L study was similar to that 

in other industry reports and studies -- many of which were 

referenced in the proposal TSD -- describing potential heat rate 

improvements at EGUs from all types of equipment upgrades. 

However, we recognized that the possibility existed that some 

limited portion of that 2 percent was also reflected in our 

statistical analyses of historical gross heat rate data. In 

order to ensure that our methodology did not double-count an 

indeterminate amount of heat rate improvement available through 

equipment upgrades, we conservatively set aside the entire 
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additional 2 percent attributable solely to equipment upgrades. 

Accordingly, we determined the amount of potential heat rate 

improvement in the BSER solely from the heat rate analyses 

described above, which account for improvements through best 

practices and equipment upgrades that were at some point 

achieved by an EGU, but not for the full range of best practices 

and equipment upgrades that are actually available. 

Commenters also said that the EPA did not look at important 

factors that affect heat rate such as coal type, boiler type, 

cooling water temperature, age, nameplate capacity or the use of 

post-combustion pollution controls. 

Our statistical methodology compared each unit to its own 

historical performance and, therefore, largely accounts for the 

effects that a unit’s design or fuel characteristics would have 

on heat rate. As discussed above, our methodology used hourly 

data from 884 units over an 11-year period (2002-2012) and 

compared the variability in the heat rate of each individual 

unit to that unit’s own performance. By assessing potential heat 

rate improvement by first looking at unit-specific data, our 

methodology inherently factors in the possible effects of design 

and fuel characteristics (e.g., coal type, boiler type, 

nameplate capacity, age, cooling water system, air pollution 

controls) on heat rate and heat rate variability. 
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Although cooling water temperature likely plays an 

important role in a coal-fired EGU’s heat rate, as stated by 

commenters, there are no consistent quality-assured hourly 

cooling water temperature data available to the EPA. However, in 

an effort to determine the potential effect of cooling water 

temperature on heat rate, we looked at a sample of 45 coal-fired 

EGUs at 19 facilities for which we had hourly surface water 

temperature data (used as a surrogate for cooling water) from 

monitors located nearby and upstream of cooling water intake 

points. Our analysis found that surface water temperature did 

explain some of the variation in heat rate, but that surface 

water temperature is strongly correlated with ambient air 

temperature -- a variable we did control for in our methodology. 

Because of the strong correlation between ambient air 

temperature and surface water temperature, the availability of a 

comprehensive dataset of nationwide hourly ambient air 

temperature, and the similar explanatory power of surface water 

temperature and ambient air temperature, it is unlikely that 

separately addressing cooling water temperature would 

significantly change the results. Rather, we are confident that 

our use of hourly ambient air temperature in our analyses 

adequately addressed any significant impact of cooling water 

temperature. See the GHG Mitigation Measures TSD supporting the 
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final CPP for further details about this analysis. As described 

further in that TSD, the other potentially relevant variables 

for which we did not directly control are unlikely to 

significantly affect the average heat rate. 

Commenters said that the heat rate improvement attributable 

to upgrades will degrade over time or require repeated and 

costly further upgrades. 

We are aware that some heat rate improvement measures can 

degrade over time. Like most power plant components, some heat 

rate improvement technologies require maintenance in order to 

sustain their efficacy over time. Therefore, to avoid 

degradation, personnel at EGUs will need to diligently apply 

“best practices” on a regular basis, a practice that numerous 

commenters say is standard operating procedure. The S&L study 

includes estimates of associated O&M costs for each heat rate 

improvement method that is discussed. As we explained in the 

proposal, the related O&M costs of diligently applying best 

practices are relatively small compared to the associated 

capital costs and would, therefore, have little effect on the 

economics of heat rate improvements. 

Commenters stated that heat rate improvement should be set 

on a basis that is narrower than nationwide -- for example, 

state-by-state or unit-by-unit. 
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The EPA did not propose and is not finalizing a rule that 

sets heat rate improvement goals for individual states or for 

individual coal-fired EGUs. Instead, in the approved state plans 

developed under this rule, each state will set the emission 

standards for its various coal-fired EGUs. In doing so, the 

state may take into account its own view of the amount of heat 

rate improvement needed (if any) at specific EGUs, and may look 

to the EPA’s analysis of heat rate improvement potential in the 

applicable region as a guide, while keeping in mind the CO2

emission performance rate. This broad-based approach is 

consistent with the traditional rules evaluating the potential 

for emission reductions on a source-category basis, and is 

consistent with the broader goal-setting purpose of this rule. 

Furthermore, the final rule establishes a uniform national 

performance rate based on the least stringent regional 

performance rate calculated with the building blocks. 

Accordingly, affected EGUs in regions not setting the national 

level have emission reduction opportunities beyond those 

reflected in the applicable performance rate. 

The heat rate improvement measures comprising building 

block 1 would ordinarily be evaluated on a nationwide basis. 

However, in this instance there are two good reasons to 

calculate building block 1 on a regionalized basis. First, a 

Deleted: T
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regionalized approach is consistent with the EPA’s approach to 

determining the other building blocks. For building block 1, 

this means that the heat rate improvement should reflect only as 

much potential for emission reduction from building block 1 as 

our analyses indicate can be achieved on average by the affected 

coal-fired EGUs in that region. This ensures that the BSER for 

each region is representative of the characteristics and 

opportunities available within that region, rather than a less 

logical combination of opportunities in the region and 

opportunities nationwide. Second, a regionalized approach 

provides a more representative average of the potential heat 

rate improvement that EGUs in a given region are capable of 

achieving. The populations of affected coal-fired EGUs in each 

region differ in some respects, as discussed in the GHG 

Mitigation Measures TSD, and the more nuanced regionalized 

approach thus indirectly accounts for some of those systemic 

differences. For these and other reasons described in Section 

V.A. of the preamble with respect to the BSER as a whole, we 

have reasonably based building block 1 on a regionalized 

approach. Applying this regionalized approach to building block 

1 strikes an appropriate balance between the proposed nationwide 

analysis and commenters’ suggested state-specific analysis, 
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which does not fully reflect the interconnected nature of the 

system within which affected coal-fired EGUs operate. 

The practical consequence of calculating building block 1 

on a regionalized versus nationwide basis is minimal. This is 

because the CO2 emission performance rates are based on the 

overall performance rate determined to be reasonable for EGUs in 

the Eastern Interconnection. Our methodology identifies a 4.3 

percent potential improvement in the Eastern Interconnection, 

compared to a 4.0 percent figure across all three 

interconnections.

We further note, along with some commenters, that sitespecific engineering studies or unit-by-unit analyses of heat 

rate improvement potential for coal-fired EGUs are not available 

to the EPA; only a small number of site-specific case studies 

are available in the public literature. We considered that for 

the EPA to develop a comprehensive, unit-by-unit heat rate 

improvement study of nearly 900 coal-fired EGUs from scratch, it 

would likely cost the Agency $50,000 to $100,000 to study each 

EGU (almost $50 to $100 million total) and require three to four 

years to complete. Such a granular analysis would not serve the 

broader goal-setting purpose of this rulemaking. We agree with 

commenters who have pointed out that a heat rate improvementestimating effort of that magnitude and duration would be 

Deleted: For affected coal-fired EGUs in the 

contiguous United States, a methodology that 

assesses potential heat rate improvement 

within each interconnection reflects the 

regional nature of the interconnected 

electricity system and the region-wide scope 

of opportunities available for those EGUs to 

access emission reduction measures through 

emissions trading.648

Deleted: For these and other reasons described 

in Section V.A of the preamble with respect to 

the BSER as a whole, we have reasonably based 

building block 1 on a regionalized approach. 

Applying this regionalized approach to 

building block 1 strikes an appropriate 

balance between the proposed nationwide 

analysis and commenters’ suggested statespecific analysis, which does not fully 

reflect the interconnected nature of the 

system within which affected coal-fired EGUs 

operate. 
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unnecessarily lengthy and expensive. Nor would such a granular 

analysis be a necessary predicate for states to develop emission 

standards, or for EGUs to comply with those emission standards. 

Rather, our methodology’s reliance on individualized, unit-byunit hourly performance data from 884 EGUs provides conservative 

and reasonable regional estimates of heat rate improvement 

potential. Indeed, given the conservative nature of our 

methodology, a unit-specific approach that evaluates the full 

range of best practices and equipment upgrades available at 

individual EGUs -- including upgrades not accounted for here -- 

would be more likely to result in higher overall heat rate 

improvement figures than we are finalizing for building block 1. 

Furthermore, site-specific information forms the foundation of 

the EPA’s estimated heat rate improvement potential, and similar 

data likely would be used in any site-specific heat rate 

improvement engineering study. Finally, EGU-specific detailed 

design and operation information is not consistently available 

for all the factors that influence heat rate. The EPA has used 

the comprehensive data that are available to reasonably and 

conservatively estimate potential heat rate improvement in each 

region. 

Commenters also said that shifting electricity generation 

from coal-fired EGUs to other EGUs because of measures 
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implemented under other building blocks will lower the capacity 

factors of coal-fired EGUs, and thus increase, not decrease, 

their heat rates. 

We expect that most states will develop plans that optimize 

the operation of existing coal-fired EGUs while utilizing the 

other building blocks and other measures to reduce emissions 

from carbon-intensive generation. From our IPM projections, the 

average annual capacity factor of existing coal-fired EGUs that 

are expected to remain in operation in 2030 will actually 

increase compared to 2012. This projection -- which is further 

described in the GHG Mitigation Measures TSD -- incorporates 

expected retirements of inefficient units and generation shifts 

away from using coal-fired EGUs as peaking units. 

Commenters also noted that the EPA used net heat rate in 

state goals, but used gross heat rate in its heat rate 

improvement analysis -- potentially ignoring the detrimental 

effect that parasitic load from air pollution control devices 

(APCD) and other equipment can have on net heat rate. 

The EPA’s variability analysis necessarily and reasonably 

used gross output data for each of the 884 EGUs in the EPA’s 

database because they are the only publicly available, unitspecific, hourly performance data. By definition, improvement in 

gross heat rate would be reflected in the net heat rate. Gross 
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heat rate is the total heat output from the EGU, in units of 

Btu/gross kWh, and includes the power used by auxiliary 

equipment required to operate the EGU itself. By contrast, net 

heat rate is the remaining Btu/kWh after subtracting the power 

used by the EGU’s own auxiliary equipment from the gross heat 

rate value, i.e., what the EGU is able to provide to the grid. 

Improvements in net heat rate alone (e.g., reducing parasitic 

load of on-site equipment) may be possible on many units. 

Therefore, our use of gross heat rate to estimate potential heat 

rate improvement was conservative because of the additional 

opportunities to achieve the uniform performance rate through 

improvements in net heat rate alone. 

Commenters also raised concerns that the EPA was not taking 

into account net heat rate increases due to additional add-on 

pollution controls that may, for some units, be required by 

other rules.649

The results of our statistical analysis are based on gross 

heat rates and would not change with installation of emission 

controls for CSAPR, MATS, or other rules because these controls 

will add parasitic load requirements and thereby have an impact 

on the net heat rates only. Furthermore, we conservatively 

consider region-wide net heat rate improvement potential to be 

 

649 See above for an explanation of gross versus net heat rate. 
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the same as that indicated for the region-wide gross heat rate, 

when in fact it is not. In order to check our assumptions 

concerning gross versus net heat rate, we used the IPM Power 

Sector Modeling Platform (version 5.14) and National Electric 

Energy Data System (NEEDS) (version 5.14) to analyze the 

anticipated incremental heat input required to operate 

additional add-on controls to comply with various EPA rules, 

including CSAPR, MATS, effluent guidelines for EGUs, and coal 

combustion residuals. From this analysis, we project that 

between 2012 and 2025, existing coal-fired EGUs are expected to 

install approximately 18.6 GW of wet flue gas desulphurization 

(FGD), 16.6 GW of dry FGD, 24.9 GW of selective catalytic 

reduction (SCR), and 3.9 GW of selective noncatalytic reduction 

(SNCR). The resulting impact from new pollution controls on 

existing coal-fired EGUs’ heat rate is expected to be very 

small, at conservatively less than 31 Btu/kWh, or less than 0.3 

percent in 2025.650 After 2025, this estimate is particularly 

conservative because the EPA’s cost performance models 

overestimate the parasitic load from individual add-on controls 

for future years. Furthermore, at some EGUs these newer 

 

650 When considered on a regional basis, we expect these controls 

to impact heat rate by approximately 0.3 percent in both the 

Eastern and Western Interconnections, and by less than 0.1 

percent in the Texas Interconnection. 

Deleted: Btu/kWh
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pollution control devices will replace existing pollution 

control devices. Accordingly, for these EGUs, the minimal 

increase in net heat rate due to power required to operate new 

controls will be at least partially offset by the decrease in 

net heat rate caused by removal of the control devices currently 

in place. For more information about this analysis, see the GHG 

Mitigation Measures TSD supporting the final CPP. 

Commenters contended that the 11 years of data used to 

evaluate potential heat rate improvement is too broad, and that 

the population of domestic coal-fired EGUs has changed 

significantly over this time period. 

The 11-year span for the hourly gross heat rate data is 

appropriate because it represents a wide variety of economic 

conditions, market conditions and fleet composition, while also 

capturing the relatively recent historical performance of 

affected coal-fired EGUs. We also noted in the proposal TSD that 

the population of coal-fired EGUs used in the analytical 

approaches to determine potential heat rate improvement is made 

up of coal-fired EGUs that operated in 2012. The gross heat rate 

data of any coal-fired EGUs that retired prior to 2012 were not 

included in the dataset. 

Commenters stated that many of the changes in heat rate 

reflected in the 11-year hourly gross heat rate dataset are 
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attributable to changes in monitoring methodology, and thus do 

not represent heat rate improvements attributable to best 

practices or equipment upgrades. In addition, commenters are 

concerned that changes to the monitoring methodology in the 

future could artificially alter the measured heat rate. 

Different stack gas flow monitoring methods can yield more 

or less accurate measurements of heat input and CO2 emissions. 

These differences depend on the characteristics of the stack gas 

flow where the monitoring and reference method measurements are 

taken, and which options under the Part 75 emission measurement 

rules are chosen in the application of the various flow rate 

reference methods. In general, more accurate stack gas flow 

monitoring methodologies yield lower values that, when used to 

calculate emissions or heat input, may lower the heat rate 

values reported to the EPA. 

Some EGUs adopted monitoring methodologies that have the 

potential to affect the exactness of the data we used for 

assessing heat rate improvements. However, as discussed in 

detail in the GHG Mitigation Measures TSD supporting the final 

CPP, our review of the data shows that a relatively small amount 

of the data are affected by these changes; we are confident that 

the values adopted for building block 1 are conservative and 

reasonable estimates of the potential for heat rate improvement 
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in each region. Some changes in monitoring methodology would 

have the result of tending to cause us to underestimate the 

potential for heat rate improvement. Furthermore, because our 

methodology analyzes percentage heat rate improvement based on 

2012 gross heat rate data, our results are unaffected by EGUs 

that used more accurate monitoring methodologies in 2012 or used 

the same monitoring methodologies consistently throughout the 

11-year study period. For these and other reasons discussed in 

detail in the GHG Mitigation Measures TSD, we remain confident 

in our results despite the marginal differences attributable to 

monitoring methodologies in some of the heat rate data for a 

subset of EGUs.651 

In terms of concerns with future methodological changes, 

the overwhelming majority of the 884 EGUs in the dataset we used 

to assess heat rate improvement have already changed their stack 

gas flow monitoring methodology in 2012 or earlier. Furthermore, 

extension of the compliance date to 2022 for this rule, as 

discussed above, more than adequately allows enough time for 

EGUs to determine how to actually improve their heat rates and 

 

651 Furthermore, on a fundamental level, our methodology accounts 

for a certain amount of any residual inexactness because we have 

conservatively adopted the lowest value identified by any of our 

reasonable approaches -- all three of which are themselves 

conservative because they do not account for the full extent of 

heat rate improvements achievable through equipment upgrades. 

Deleted: In many instances,

Deleted: actually underestimating 

Deleted: at some EGUs. 
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lower CO2 emissions while accommodating future changes to 

monitoring methodologies. For a more detailed explanation, see 

the GHG Mitigation Measures TSD supporting the final CPP. 

Commenters said that there is no proof that lowering the 

heat rate will reduce variability or that reduced variability 

will reduce heat rate, i.e., correlation does not prove 

causation. 

As an initial matter, it is important to note that for the 

final rule the EPA used three types of statistical analyses to 

evaluate and estimate potential heat rate improvements of coalfired EGUs, and only one of these analyses involved any 

consideration of heat rate variability. All three types of 

statistical analyses are described in the GHG Mitigation 

Measures TSD supporting the final CPP. 

These commenters are correct that, in the abstract, 

reducing heat rate variability only means that heat rate will be 

more consistent -- not necessarily lower or higher. However, our 

analysis is not an abstract evaluation of the potential to 

reduce variability, as commenters suggest, but rather is an 

evaluation of the potential heat rate improvement achievable 

through reducing variability -- i.e., reducing variability to 

achieve a more consistently low heat rate. See the more detailed 

discussion of the statistical procedures used for the final 
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rule, above. In particular, the application of a “consistency 

factor” in the analyses performed for both the proposed and 

final rule demonstrates the potential results if each individual 

EGU operated slightly more consistently with the lower heat 

rates that the EGU had itself previously achieved under similar 

conditions. 

The consequence of a reduced heat rate is, of course, a 

lower rate of CO2 emissions, which is the purpose of the BSER for 

building block 1. This way of thinking about reduced variability 

is consistent with the utility power sector’s own efforts to 

reduce variability, which are aimed at securing the economic 

benefits of a more consistently lower overall heat rate. 

Some commenters expressed concern that heat rate 

improvements could trigger applicability of new source review 

(NSR) provisions. The relationship of this final rule to other 

regulatory provisions, including NSR, is discussed in section X 

of the preamble. 

D. Building Block 2—Generation Shifts Among Affected EGUs 

The second element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which fossil 

steam EGUs can shift generation to existing NGCC EGUs. In this 

section, we define building block 2 as the gradual shifting of 

Deleted: 
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generation from existing fossil steam to existing NGCC within 

each region up to a maximum NGCC utilization of 75% on a net 

summer basis. In each year of the interim period, this 75% net 

summer maximum potential is subject to a regional limit informed 

by historical growth rates. This section summarizes the EPA’s 

analysis supporting that definition, including a discussion of: 

historical trends in the utility power sector, the gradual 

phase-in governed by historical growth rates, the technical 

feasibility of utilizing existing NGCC units at 75% net summer 

capacity, historical availability of and generation shifts to 

NGCC units, reliability, natural gas infrastructure, natural gas 

production, transmissions planning and construction, regulatory 

flexibility, and cost-effectiveness of CO2 reductions. 

1. Demonstration of ability to reduce CO2 emissions through 

shifting generation 

a. Background of utility power sector. The ability to shift 

generation from higher- to lower-emitting sources is compatible 

with the way EGUs are generally dispatched.652 The standard 

approach to dispatching generation is through Security 

Constrained Economic Dispatch (SCED), a well-established 

 

652 See Preamble, II.C.1, History of the Power Sector, for 

background to this discussion. 

Deleted: 

Deleted: A

Deleted: R

Deleted: E

Deleted: S

Deleted: G

Deleted: ¶
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practice in the electric power industry.653 As the name 

indicates, SCED has two defining components: economic operation 

of generating facilities and assurance that the electric system 

remains reliable and secure.654 Economic dispatch generally 

refers to shorter-term planning and operations from a day ahead 

through real time. During this period, generating units are 

committed – a process known as “unit commitment,” in which units 

are committed to be ready to provide generation to the system 

when they will be needed – and then dispatched in real time to 

meet the electricity demand of the system. Overall changes in 

the level of generation from different facilities are also 

planned over time periods longer than this two-day dispatch 

period. Over a calendar year, for example, units are planned and 

scheduled seasonally or monthly to ensure that sufficient 

capacity and energy will be available to meet expected loads in 

an area. Over a period of a week, units are committed to be 

prepared to start up or shut down to meet forecast loads, and 

dispatch is coordinated within this planning and unit commitment 

framework. This process enables system operators to respond 

 

653 “Economic Dispatch: Concepts, Practices and Issues”, FERC 

Staff Presentation to the Joint Board for the Study of Economic 

Dispatch”, Palm Springs, California, November 13, 2005. A copy 

of this presentation is available in the docket for this rule. 

654 “Security Constrained Economic Dispatch: Definitions, 

Practices, Issues and Recommendations: A Report to Congress”, 

Federal Energy Regulatory Commission, July 31, 2006. 
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quickly to short-term changes in demand, and also to shift 

generation among different generation types to match longer-term 

requirements and goals. 

 EGUs using technologies with relatively low variable 

costs, such as nuclear units, are for economic reasons generally 

operated at their maximum output whenever they are available. 

Renewable EGUs such as wind and solar units also have low 

variable costs, but the magnitude and timing of their output 

generally depend on wind and sun conditions rather than the 

operators' discretion. In contrast, fossil fuel-fired EGUs have 

higher variable costs and are also relatively flexible to 

operate. Fossil fuel-fired EGUs are therefore generally the 

units that operators use to respond to intra-day and intra-week 

changes in demand. Because of these typical characteristics of 

the various EGU types, the primary opportunities for switching 

generation among existing units available to EGU owners and grid 

operators generally consist of opportunities to shift generation 

among various fossil fuel-fired units, in particular between 

coal-fired EGUs (as well as oil- and gas-fired steam EGUs) and 

NGCC units. In the short term — that is, over time intervals 

shorter than the time required to build a new electric 

generation unit — fossil fuel-fired units consequently tend to 

compete more with one another than with nuclear and renewable 
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EGUs. The amount of generation shifting from coal-fired EGUs to 

NGCC units that takes place as a result of this competition is 

highly relevant to overall power sector GHG emissions, because a 

typical NGCC unit produces less than half as much CO2 per MWh of 

electricity generated as a typical coal-fired EGU. 

b. Trends in generation shifts from coal-fired to natural gasfired sources. Since at least 2000, fossil fuel-fired generation 

has been shifting from coal- and oil-fired EGUs to NGCC units, 

both as a result of construction of additional NGCC units, and 

also as a result of dispatch of pre-existing NGCC units at 

higher capacity factors. As a result, generation from NGCC EGUs 

in 2012 reached over four times the level of NGCC generation in 

2000, while generation from coal and oil/gas steam EGUs 

decreased by around one third.655 As we demonstrate in the GHG 

Abatement Measures TSD, NGCC units are capable of operating at 

higher annual capacity factors than they have historically, so 

there remains considerable opportunity for increased use of 

existing NGCC units to replace generation currently supplied by 

higher-emitting coal and oil/gas steam units. The electric 

utility industry is thus well-positioned to address the 

requirements of this building block by increasing use of 

existing NGCC units and correspondingly decreasing use of steam 

 

655 Ventyx Electric Power Database. 

Deleted: 
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units. The electric industry has been shifting generation to 

NGCCs in recent years and is expected to continue to retire coal 

capacity and add new NGCC. In the reference case without 111d, 

EIA forecasts 40 GW of coal retirements and 53 GW of NGCC 

additions from 2014 to 2030.656 An EPA review of state Integrated 

Resource Plans (IRPs) shows a pattern of shifting away from coal 

steam capacity to NGCC. For example, Ameren plans to add 600 MW 

of NGCC and convert two coal units and Duke plans to add 680 MW 

of NGCC and convert one coal unit. For further examples, see the 

IRP TSD. 

c. Mechanisms for dispatch shifts from coal-fired to natural 

gas-fired generation. There are a variety of patterns of 

ownership and operational control of EGUs; these ownership and 

operational structures influence how EGUs will respond to this 

building block. However, all owners and operators have the 

ability to comply by using this building block. In terms of 

ownership, investor-owned utilities (IOUs) serve about 75 

percent of the US population, while consumer-owned utilities 

serve the remaining 25 percent.657 In states that have maintained 

traditional regulation, IOUs are generally vertically integrated 

 

656 Energy Information Administration, Annual Energy Outlook 2015 

reference case, ref2015.d021915a. 

657 Regulatory Assistance Project, Electricity Regulation in the 

US: A Guide, Page 9, March 2011. 

Deleted: 

Deleted: 

Deleted: 
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(owning generating capacity as well as transmission and 

distribution infrastructure), and the wholesale sales of these 

EGUs are regulated by the state; in states that have deregulated 

their retail service, ownership of the EGU is separated from 

ownership of transmission, and wholesale sales of generation are 

regulated by FERC. Consumer-owned utilities comprise municipal 

utilities, public utility districts of various types owned by 

government agencies, nonprofit cooperative entities (co-ops), 

and a number of other entities such as Native American Tribes. 

Operational control of the dispatch of power over the 

electricity grid is superimposed on this pattern of ownership.

Prior to electricity restructuring, this dispatch was typically 

operated by major vertically-integrated utilities or by public 

power entities. Over the last 15 years, large portions of the 

power grid are now independently operated by Independent System 

Operators (ISOs) or Regional Transmission Operators (RTOs).

These entities are regulated by FERC and dispatch power from 

multiple owners to meet the loads on the bulk power grid.

The combination of multiple ownership and types of 

operational control adds to the complexity of electricity 

dispatch, but all affected EGUs, regardless of ownership and 

type of control, can use this building block to comply with the 

final rule. The principal difference among the differing 

Deleted: 

Deleted: 

Deleted: 
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entities lies in the types of methods that are available for the 

affected EGU owner to bring about the shift in generation that 

will make use of this building block for compliance. There are 

several alternatives to accomplish this result: the owner of the 

higher-emitting affected EGU may also own, or have affiliates 

that own, lower emitting generation and thus reduce its own 

generation and use its control over these other EGUs to increase 

their generation; an EGU may be able to reduce its generation 

and buy replacement power from the market that is lower 

emitting; or the EGU may be able to reduce its generation and 

procure generation from a separately-owned lower-emitting EGU. 

These alternatives will be available in states with either rate 

or mass-based state plans without any change in their general 

form. Under a rate-based state plan, an EGU owner may also be 

able to purchase ERCs and average the ERCs into its emission 

rate for purpose of demonstrating compliance with its standard 

of performance. Under standards of performance that incorporate 

emissions trading, an EGU owner may be able to purchase ratebased emission credits or mass-based emission allowances not 

needed by other EGUs and use those credits or allowances to help 

achieve its standard of performance.

The potential to shift generation identified for this 

building block is entirely consistent with the existing economic 

Deleted: 

Deleted: 

Deleted: ; or the EGU owner may be able to 

purchase an emissions credit. 

Deleted: With the exception of emissions 

crediting (discussed further below), these 
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dispatch protocols described above. State environmental policies 

can shift generation in two ways. The first is operational 

restrictions, such as permit limits on the number of hours that 

an EGU can operate in order to limit emissions. The second is 

changes in the relative costs of generation among different 

types of EGUs related to pollution reduction measures. For 

example, a regulation that necessitates the use of a control 

technology that requires the application of a reagent in a 

certain kind of EGU will increase the variable cost of operating 

that plant, which in turn may reduce the amount of generation it 

is called upon to deliver to the grid through securityconstrained economic dispatch procedures. 

In an organized market, where the system operator 

dispatches units partly based upon costs, an electric power 

plant that experiences an increase in its variable costs will 

tend to operate less than it otherwise would have. For example, 

market-based pollution control programs require units to hold 

tradable allowances to authorize their emissions of a regulated 

pollutant. Such an allowance-holding requirement puts a price on 

the act of emitting the regulated pollutant, which increases the 

operating costs of units that emit that pollutant, and thus such 

units will be dispatched less than they otherwise would without 

such an allowance-holding requirement. The Regional Greenhouse 

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Gas Initiative (RGGI) is an example of a state program that has 

this effect. In the present rule, although shifts in the mix of 

generation to address the costs of pollution control can lead to 

higher electricity generating costs overall, the EPA analysis 

shows these costs to be modest and well below their associated 

benefits.658

Many of the NGCC units are owned by the same companies or 

affiliates that also own steam units. In these cases, changes in 

EGU generation can be planned by the company or affiliate 

without the need to engage in separate market transactions with 

outside parties. Where the affected EGU owner is also the 

dispatch entity, as in most traditional market structures, the 

EGU owner will generally have operational control over the unit. 

Environmental conditions, such as compliance costs or limits on 

generation, can be factored in with fuel costs to determining 

when the unit is committed to be available, how the unit can be 

most efficiently cycled, and at what level the unit is 

dispatched. 

An analysis of generation data from steam and NGCC units in 

2012 shows that 77 percent of the steam generation occurred from 

an EGU that owned, or that had an affiliate that owned, NGCC 

generation. Eighty percent of the generation shift potential 

 

658 See the Regulatory Impact Analysis. 

Deleted: In the first alternative, m

Deleted: 80
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identified in this building block (increasing NGCC generation up 

to a 75 percent capacity factor on a net basis to replace steam 

generation) could occur among these entities that own (either 

directly or through affiliates) both steam and NGCC 

generation.659 These data show that most EGU generation relevant 

for this building block is produced by entities that own both 

steam and NGCC generation. 

Another alternative available to an affected EGU owner that 

does not also own NGCC generation is for the higher-emitting 

affected EGU to reduce its generation and purchase replacement 

power from the market. In organized markets such as RTOs, it is 

available through standard practice, because the owner impacts 

how its EGUs are dispatched based upon how it bids into the RTO 

market. In this case, the owner can exercise control over the 

levels of generation across units by when it offers generation 

to the market operator (the RTO or ISO), and the prices it bids 

for this generation. As in traditional economic dispatch by a 

utility, environmental conditions, compliance costs, or limits 

on generation can be incorporated by the owner into the 

determination of the cost-effective generation pattern of its 

EGUs. 

 

659 SNL Energy. Data used with permission. Accessed May 2015. 

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In regions with organized electricity markets (including, 

but not limited to, RTOs or ISOs), the various types of EGU 

owners of higher-emitting sources can reduce their generation, 

and any resulting deficit in generation on the system can be 

supplied from other EGUs in the region; for example, a coalfired unit can reduce generation that is then replaced through 

the operation of the market by generation from an NGCC unit, 

subject to dispatch by a regional operator to ensure the 

reliable delivery of the generation to loads within the region. 

To comply with this rule, higher-emitting steam units will need 

greater reductions relative to lower-emitting NGCC units which 

will, in turn, tend to raise steam unit costs compared to NGCC 

units. As a result, the bids that a steam unit provides a market 

operator will rise relative to NGCC units. This process of 

reducing generation from a higher-emitting unit will lead to 

substitution of lower-emitting generation. 

EGU owners that do not participate in an organized 

electricity market may nevertheless purchase power from the 

wholesale power market. Purchases in the wholesale power market 

can be spot purchases, which are typically general purchases of 

system power supplied by the EGUs across a region, or contract 

purchases, which may have more provider-specific characteristics 

(such as specifying the type of unit that is providing the 

Deleted: 

Deleted: 
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power). Purchases between EGUs through the wholesale power 

market will have similar emission-lowering properties as 

operation of the organized market discussed above, because 

dispatch in balancing areas outside RTOs and ISOs also follows a 

similar economic dispatch protocol that is informed by each 

unit’s production costs and environmental limitations. 

Under this alternative, the steam generators may, in 

effect, realize emission reductions from building block 2 simply 

by reducing their generation. Steam generators do not need to 

purchase replacement electricity as a prerequisite for realizing 

emission reductions from reducing their own generation because 

other generators already have an incentive to provide as much 

electricity as load-serving entities are willing to buy in order 

to satisfy electricity demand.660 As noted above, higher-emitting 

generation sources will have to incorporate correspondingly 

higher costs of pollution reduction into their supply bids 

compared to lower-emitting generation sources, and as a result, 

 

660 Some owners or operators of steam generators may have 

electricity supply obligations to which they may be applying 

power from those steam generators. However, such parties may 

fulfil those supply obligations using the wholesale power market 

in the exact same way described here that enables any other 

generator with economically attractive electricity to offer such 

supply. In other words, the ability of a steam generator to 

reduce its generation is not contingent on an associated 

purchase to replace that power, notwithstanding the possibility 

that the owner or operator of that steam unit may choose to make 

such a purchase to meet an electricity supply obligation. 

Deleted: 

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load-serving entities will seek to buy a greater share of 

electricity from the lower-emitting sources because their supply 

bids will be more economically attractive. Once the steam 

generators reduce their generation (and associated emissions), 

the other entities in the electricity system arrange for the 

replacement electricity. The outcome of this power market 

process will reduce both the mass and the rate of emissions 

across sources.

An owner of a source can also reduce the generation of an 

EGU by substituting generation from a lower-emitting NGCC 

directly. For an EGU owner without existing NGCC generation, 

this substitution can take the form of a bilateral contract 

purchase. In RTOs and ISOs, this alternative often takes the 

form of a contract for differences, where the replacement source 

could be an NGCC and the contract specifies a delivery location 

and the price of the power. In bilateral markets, the contract 

vehicle could be a Power Purchase Agreement from a replacement 

source. It is also possible that the owner of a steam unit could 

directly invest in an existing EGU by purchasing the asset or 

taking a partial ownership position, thus acquiring the 

generation from the unit through that means. The acquired 

generation and its associated emissions could be used for 

compliance by the higher-emitting EGU, in accordance with the 

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plan under which it is operating. The amount of generation that 

could be shifted using the approaches described in this 

paragraph will depend on the type and terms of the commercial 

arrangements, as well as the potential need for regulated 

entities to obtain approvals for contracts or for changes in 

asset positions. The wide range of approaches permitted by this 

rule provides flexibility, both within a year and across 

multiple years, for EGUs to fashion these arrangements to fit 

their circumstances.

An EGU is also able to meet its reduction obligations using 

emission rate credits or allowances. The particular nature of 

this alternative will depend on how a state elects to develop 

its plan. If a state chooses a mass-based approach, the EGU 

would simply need to hold allowances to cover its emissions. To 

realize an emission reduction from building block 2 under this 

approach, a steam generator would only need to reduce its 

emissions by reducing its generation, which would lead to that 

generator needing fewer allowances to cover its emissions under 

the program. In a rate-based state, the state may choose to 

provide for compliance by purchasing tradable emission rate 

credits. To realize an emission reduction from building block 2 

under this approach, a steam generator would be able to adjust 

its effective emission rate by purchasing emission rate credits 

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that are produced by other sources whose emission rates are 

lower than the applicable rate standard. In this fashion, a 

steam generator does not need to purchase lower-emitting 

replacement power per se in order to demonstrate an emission 

reduction from this building block; instead, the steam generator 

may purchase any emission rate credits that were produced from 

lower-emitting sources (see section VIII for more detail on how 

state plans can use an emission rate credit approach to 

facilitate a rate-based compliance demonstration of this type of 

emission reduction).661

The approaches shown here collectively demonstrate that all 

steam generators -- regardless of size, location, form of 

ownership, or type of market in which they operate -- can 

implement building block 2 through some or all of the mechanisms 

described.

2. Timing of generation shift 

The EPA received significant public comments expressing 

concern regarding the proposal’s incorporation of the full 

 

661 Stakeholders have recognized that emission rate credits and 

allowances are an effective tool for EGUs to implement the 

building blocks and achieve their standards of performance 

required under this rule. See “Clean Power Plan Implementation: 

Single-State Compliance Approaches with Interstate Elements,” 

Georgetown Climate Center (May 2015), 

http://www.georgetownclimate.org/sites/www.georgetownclimate.org

/files/GCC_ComplianceApproacheswithInterstateElements_May2015.pd

f. 

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building block 2 shift in generation by the first year of the 

interim period. These commenters perceived this approach as 

requiring states to achieve such a significant portion of the 

required CO2 emission reductions early in the interim period that 

states would lack flexibility in when and how they may achieve 

the required emission reductions. Other commenters expressed 

concern that the full extent of building block 2 would be 

difficult for some states to achieve by the first year of the 

interim period as a result of technical, engineering, and 

infrastructure limitations or other considerations; that such 

timing may crowd out other cost-effective options for emission 

reductions; and that such timing might have negative 

implications for reliability.

In the proposal, the EPA determined that emission 

reductions are feasible and achievable at fossil fuel-fired 

steam EGUs by shifting from more carbon-intensive EGUs to less 

carbon-intensive EGUs, as part of the BSER. More specifically, 

the EPA proposed that generation shifts from fossil fuel-fired 

steam units (which are primarily coal-fired) to NGCC units, up 

to a utilization of 70 percent on a nameplate capacity basis, 

could be achieved by 2020. In contrast, the EPA proposed that 

reductions in CO2 emissions from fossil fuel-fired units 

associated with other measures, such as increased utilization of 

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RE generating capacity and increased demand-side energy 

efficiency, would be achievable on a phased-in basis between 

2020 and 2029, reflecting the time needed for deployment.662 In 

light of the concerns noted above, the EPA solicited comment in 

the NODA on potential rationales for phasing in the potential to 

shift generation under building block 2.663

As described in section III of this preamble, the EPA has 

revised the interim compliance period to start in 2022, which 

itself is a meaningful response regarding the concerns expressed 

by commenters about the timing of building block 2’s generation 

shift potential. In addition, the EPA has evaluated the 

feasibility over time of building block 2 within the framework 

of BSER, and is finalizing a change to building block 2 that 

gradually phases in the shift from existing fossil steam to 

existing NGCC over the interim period. This phase-in allows for 

additional time to complete potential infrastructure 

improvements (e.g., natural gas pipeline expansion or 

transmission improvements) that might be needed to support more 

use of existing natural gas-fired generation, and provides 

states with the increased ability to coordinate actions taken 

 

662 (79 FR 34866) 663 (79 FR 64543) 

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under building block 2 with actions taken under building block 3 

(deployment of new renewable capacity). 

The phase-in schedule applies a limit to the maximum 

building block 2 potential in each year of the interim period 

based on two parameters. The first parameter defines an amount 

of generation shift to existing NGCC capacity that is feasible 

by 2022, and the second parameter defines how quickly that 

amount could grow until the full amount of NGCC generation could 

be achieved as part of the BSER. Both of these parameters are 

determined by examining the extent to which gas-fired generation 

has increased over historical time periods. The first parameter 

is based on the single largest annual increase in power sector 

gas-fired generation since 1990, which occurred between 2011 and 

2012 and is equal to 22 percent.664 We believe that this amount 

is a conservative estimate of the ability of the sector to 

increase utilization of NGCC capacity by 2022, given that this 

increase has already occurred in a single year. The second 

parameter is based on the average annual growth in gas-fired 

generation in the power sector between 1990 and 2012, which is 

approximately 5 percent per year. 

 

664 US EIA Monthly Energy Review, Table 7.2b Electricity Net 

Generation: Electric Power Sector (2015), available at

http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&

freq=m. 

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In the performance rate calculation methodology, these two 

parameters constrain the annual rate at which building block 2 

shifts generation from fossil steam units to NGCC units. The 

interim performance rate is an average of annual rates 

calculated over the 2022-2029 period. The two parameters above 

limit the extent to which NGCC generation is able to increase 

and replace fossil steam generation in each year of the interim 

period. In the first year, NGCC generation is limited to a 

maximum of a 22 percent increase from 2012 levels in each 

region. In each subsequent year, regional NGCC generation is 

limited to a maximum of a 5 percent increase from the previous 

year. This phase-in continues in the performance rate-setting 

methodology until the full building block 2 level of shifting 

from fossil steam generation to NGCC generation is reached. 

Under this approach, building block 2 is completely phased into 

the source category calculation of all regions by the end of the 

interim period. 

Table 7. BSER Maximum NGCC Generation by Region and Year (TWh).

NGCC Generation (TWh) 

Regio

n 

Maximu

m 

Potent

ial at 

75% 

2012 

(adjus

ted) 

BSER Maximum 

202

2 

202

3 

202

4 

202

5 

202

6 

202

7 

202

8 

202

9 

203

0 

Limit -- -- 22% 5% 5% 5% 5% 5% 5% 5% 5% 

Easte

rn 

Inter 988 735 896 941 988 988 988 988 988 988 988

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Deleted: 734

Deleted: 896

Deleted: 941

Deleted: 987

Deleted: 987

Deleted: 987

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conne

ction 

Weste

rn 

Inter

conne

ction 306 198 242 254 267 280 294 306 306 306 306

Texas 

Inter

conne

ction 204 137 167 176 185 194 203 204 204 204 204

This phase-in, in addition to the flexible nature of the goals, 

ensures that the overall framework of this final rule includes 

sufficient flexibility, particularly with respect to timing of 

and strategies for reducing emissions from the affected units, 

so that states can develop cost-effective strategies and allow 

for infrastructure improvements to occur should they prove 

necessary in some locations. 

3. Basis for magnitude of generation shift 

a. Technical feasibility of NGCC units to generate at 75% of 

their capacity. In order to estimate the potential magnitude of 

the opportunity to reduce power sector CO2 emissions through 

shifting generation among existing EGUs, the EPA first examined 

information on the design capabilities and availability of NGCC 

units. Availability is defined as the number of hours that 

generators are available to generate electricity, and it is 

typically expressed as a percentage of the total number of hours 

in a year. Since the value of NGCC capacity is related to how 

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much electricity the owner of that capacity can generate and 

sell, units are typically designed with very high availability 

ratings. Baseload units have annual average availabilities of 

approximately 91%-92%, and peaking units are generally available 

96% to 98% of peak hours.665 The EPA also examined information on 

the historical availability of NGCC units in practice. This 

examination showed that, although most NGCC units have 

historically been operated in intermediate-duty roles for 

economic reasons, they are technically capable of operating in 

baseload roles at much higher annual utilization rates. Average 

annual availability (that is, the percentage of annual hours 

when an EGU is not in a forced or maintenance outage) for NGCC 

units in the U.S. generally exceeds 85 percent, and can exceed 

90 percent for some groups.666

We also researched historical data to determine the 

utilization rates that NGCC units have already demonstrated 

their capability to sustain. Over the last several years, the 

 

665 Negotiating Availability Guarantees for Gas Turbine Plants, 

available at: http://www.power-eng.com/articles/print/volume105/issue-3/features/negotiating-availability-guarantees-forgas-turbine-plants.html 

666 See, e.g., North American Electric Reliability Corp., 2008-

2012 Generating Unit Statistical Brochure—All Units Reporting, 

http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher 

Availability of Gas Turbine Combined Cycle, Power Engineering 

(Feb. 1, 2011), http://www.power-eng.com/articles/print/volume115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html. 

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utilization patterns of fossil fuel-fired units have shifted 

relative to historical dispatch patterns, with NGCC units 

increasing generation and many coal-fired EGUs reducing 

generation. In fact, in April 2012, for the first time ever the 

total quantity of electricity generated nationwide from natural 

gas was approximately equal to the total quantity of electricity 

generated nationwide from coal.667 These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal. Although the relative 

fuel prices vary by location, as do the recent generation 

patterns, this trend holds across broad regions of the U.S. In 

the aggregate, the historical data provide ample evidence 

indicating that, on average, existing NGCC units can achieve and 

sustain utilization rates higher than their historical average 

utilization rates. 

Utilization of EGUs is often considered using the metric of 

a capacity factor, which is the percentage of total production 

potential that an electric generating unit achieves in a given 

time period. A capacity factor of 75 percent thus represents a 

unit producing three-quarters of the electricity it could have 

produced in that time had it utilized its entire capacity. The 

EPA received multiple comments regarding the proposed use of 

 

667 http://www.eia.gov/todayinenergy/detail.cfm?id=6990. 

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nameplate capacity in calculating the potential utilization 

level of existing NGCCs under building block 2. These comments 

stated that net summer capacity is a more meaningful and 

reliable metric than nameplate capacity, because net capacity 

best reflects the electric output available to serve load. The 

EPA agrees with these comments. The quantification of building 

block 2 as well as performance rate and state goal calculations 

in the final rule are all based on net summer generating 

capacity. An annual utilization rate of 75 percent on a net 

summer basis is similar to the proposed rule’s consideration of 

70 percent utilization on a nameplate basis.668

The experience of relatively heavily-used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. 

The EPA reexamined the historical NGCC plant utilization 

rate data reported to the EIA, and found that in 2012 roughly 15 

percent of existing NGCC plants operated at annual utilization 

rates of 75 percent or higher on a net summer basis.669 In 

 

668 For a given amount of net generation, a net summer capacity 

factor appears higher compared to a corresponding nameplate 

capacity factor because net summer capacity reflects a lower 

amount of total generation potential achievable by the unit in 

practice. 

669 Net summer capacity is defined as: “The maximum output, 

commonly expressed in megawatts (MW), that generating equipment 

can supply to system load, as demonstrated by a multi-hour test, 

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effect, these plants were providing baseload power. In addition 

to the 15 percent of NGCC plants that operated approximately at 

a 75 percent utilization rate on an annual basis, some NGCC 

plants operated at even higher utilization rates for shorter, 

but still sustained, periods of time in response to high 

cyclical demand. For example, on a seasonal basis, a significant 

number of NGCC plants have achieved utilization rates greater 

than 90 percent on a net summer basis; during the summer of 2012 

(June through August), about 30 percent of NGCC plants operated 

at utilization rates of 75 percent or more across the entire 

season. During the spring and fall periods when electricity 

demand levels are typically lower, these plants were sometimes 

idled or operated at much lower capacity factors. Nonetheless, 

the data clearly demonstrate that a substantial number of 

existing NGCC plants have proven the ability to sustain 75 

percent utilization rates for extended periods of time. We view 

this as strong evidence that increasing the annual average 

utilization rates of existing NGCC units to 75 percent on a net 

summer basis would be technically feasible. 

 

at the time of summer peak demand (period of June 1 through 

September 30.) This output reflects a reduction in capacity due 

to electricity use for station service or auxiliaries.” (EIA, 

http://www.eia.gov/tools/glossary). 
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Page 707 of 1544

The EPA believes that an annual average utilization rate of 

75 percent on a net summer basis is a conservative assessment of 

what existing NGCC plants are capable of sustaining for extended 

periods of time. In 2012, roughly 10 percent of existing NGCC 

plants operated at annual utilization rates of 80 percent or 

higher on a net summer basis. While the EPA believes this level 

is also technically feasible on average for the existing NGCC 

fleet, the EPA is quantifying building block 2 assuming an NGCC 

utilization level of 75% on a net summer basis in order to offer 

sources additional compliance flexibility, given that the extent 

to which they realize a utilization level beyond 75 percent will 

reduce their need to rely on other emission reduction measures 

or building blocks.

b. Historical generation shifts to NGCC generation. In 2012, 

total electric generation from existing NGCC units was 966 

TWh.670 After the application of the building block 2 potential 

(increasing NGCC utilization up to a 75 percent capacity factor 

on a net summer basis, including generation from NGCC units that 

were under construction in 2012), the total generation from 

these existing sources is assumed to be 1,070 TWh.671 

 

670 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule. 671 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule.

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The EPA believes that producing this quantity of generation 

from this set of NGCC units is feasible. To put this level of 

generation into context, NGCC generation increased by 

approximately 430 TWh (an 80 percent increase) between 2005 and 

2012. The EPA calculates that assumed NGCC generation in 2022 

through the quantification of building block 2 potential is 

approximately 16 percent higher than 2014 levels. This reflects 

a smaller growth rate in potential NGCC generation between 2015 

and 2022 than has been observed in practice from 2005 to 2012, a 

time period of the same duration. 

c. Reliability. We also expect that an increase in NGCC 

generation of this amount would not impair power system 

reliability. Sources can achieve increases in utilization of 

existing NGCCs that displace generation from steam sources 

without impacting reliability because this shift in average 

annual utilization across existing EGUs does not inhibit the 

power sector’s ability to maintain adequate dispatchable 

resources to continue to meet reserve margins and maintain 

reliability. Furthermore, sources are not required to achieve 

the exact or even the full extent of the building block 2 

generation shift itself, which means that sources will have 

ample flexibility to maintain reliability-relevant operations 

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while achieving emission reductions through a variety of 

measures.672

d. Natural gas infrastructure. 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. For several reasons, we conclude 

that these systems would be capable of supporting the degree of 

increased NGCC utilization potential in building block 2. First, 

the natural gas pipeline system is already supporting national 

average NGCC utilization rates of 60 percent or higher during 

peak hours, which are the hours when constraints on pipelines or 

electricity transmission networks are most likely to arise. NGCC 

unit utilization rates during the range of peak daytime hours 

from 10 a.m. to 9 p.m. are typically 15 to 20 percentage points 

above their average utilization rates (which have recently been 

in the range of 40 to 50 percent).673 Fleet-wide combined-cycle 

 

672 See section VIII for further discussion of electric 

reliability planning. 

673 EIA, Average utilization of the nation's natural gas 

combined-cycle power plant fleet is rising, Today in Energy, 

July 9,2011, 

http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, Today 

in Energy, Jan. 15, 2014, 

http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent 

data). 

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average monthly utilization rates have reached 65 percent,674

showing that the pipeline system can currently support these 

rates for an extended period. If the current pipeline and 

transmission systems allow these utilization rates to be 

achieved in peak hours and for extended periods, it is 

reasonable to expect that similar utilization rates should also 

be possible in other hours when constraints are typically less 

severe, and be reliably sustained for other months of the year. 

Furthermore, the NGCC utilization increase assumed in building 

block 2 could occur without a significant impact on peak demand 

for natural gas, including winter demand (when the power 

sector’s demand for natural gas competes with other sectors’ 

demands for natural gas), since increasing annual utilization of 

NGCCs could focus on non-peak periods when NGCC capacity factors 

are currently low. 

The second consideration supporting a conclusion regarding 

the adequacy of the gas supply infrastructure is that pipeline 

and transmission planners have repeatedly demonstrated the 

ability to methodically relieve bottlenecks and expand 

capacity.675 Natural gas pipeline capacity has regularly been 

 

674 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 675 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today 

in Energy; INGAA Foundation, Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market (2004 update); INGAA 
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added in response to increased gas demand and supply, such as 

the addition of large amounts of new NGCC capacity from 2001 to 

2003, or the delivery to market of unconventional gas supplies 

since 2008. These pipeline capacity increases have added 

significant deliverability to the natural gas pipeline network 

to meet the potential demands from increased use of existing 

NGCC units. Over a longer time period, much more significant 

pipeline expansion is possible. In previous studies, when the 

pipeline system was expected to face very large demands for 

natural gas use by electric utilities, the pipeline industry 

projected that increases of up to 30 percent in total 

deliverability out of the pipeline system would be possible.676

There have been notable pipeline capacity expansions over the 

past five years, and substantial additional pipeline expansions 

are currently under construction.677 Further, the phasing in of 

building block 2’s potential in the determination of the BSER; 

 

Foundation, North American Midstream Infrastructure Through 

2035—A Secure Energy Future Report (2011). 

676 Pipeline and Storage Infrastructure Requirements for a 30 Tcf 

Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas 

groups confident of 30-tcf market, Oil and Gas Journal, 1999. 

677 For example, between 2010 and April 2014, 118 pipeline 

projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) 

were placed in service, and between April 2014 and 2016 an 

additional 47 pipeline projects with 20,505 MMcf/day of capacity 

(1,567 miles of pipe) are scheduled for completion. Energy 

Information Administration, 

http://www.eia.gov/naturalgas/data.cfm. 

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system is undergoing substantial expansion.678
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the flexible nature of multi-year compliance with the ultimate 

emission reduction requirements of the rule; and the seven years 

between finalization of this rule and the first year of 

compliance provide time for infrastructure improvements to occur 

should they prove necessary in some locations. Combining these 

factors of currently observed average monthly NGCC utilization 

rates of up to 65 percent, the flexibility of the emission 

guidelines, the rates of historical growth, and the availability 

of time to address any existing pipeline infrastructure 

limitations, it is reasonable to conclude that the natural gas 

pipeline system can reliably deliver sufficient natural gas 

supplies to allow NGCC utilization to increase up to an average 

annual capacity factor of 75 percent on a net summer basis. 

e. Natural gas production. We recognize that an increase in NGCC 

utilization rates at existing units corresponds with an 

associated increase in natural gas production, consistent with 

the current trends in the natural gas industry. The EPA expects 

the growth in NGCC generation assumed for building block 2 to be 

feasible and consistent with the production potential of 

domestic natural gas supplies. Increases in the natural gas 

resource base have led to fundamental changes in the outlook for 

natural gas. There is general agreement that recoverable natural 

gas resources will be substantially higher for the foreseeable 

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can reliably accommodate changed generation 

patterns,

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future than previously anticipated, exerting downward pressure 

on natural gas prices. According to EIA, proven natural gas 

reserves have doubled between 2000 and 2012. Domestic dry gas 

production has increased by 25 percent over that same timeframe 

(from 19.2 TCF in 2000 to 24.0 TCF in 2012). EIA’s Annual Energy 

Outlook Reference Case for 2015 projects that production will 

further increase to 29.5 TCF by 2022 and 33 TCF by 2030, as a 

result of increased supplies and favorable market conditions. In 

the AEO 2015 high oil and gas resource case, production is 

projected to increase to 42.7 TCF in 2030. For comparison, 

building block 2 assumes NGCC generation growth of 235 TWh from 

2012 to reach the level assumed for 2022, and that NGCC 

generation growth would result in increased gas consumption of 

less than 2 TCF for the electricity sector, which is less than 

EIA’s projected increase in natural gas production of 5.5 TCF 

from 2012 to 2022. 

The EPA has also assessed the ability of the electricity 

and natural gas industries to achieve the potential quantified 

for building block 2 using the Integrated Planning Model (IPM). 

IPM is a multi-regional, dynamic, deterministic linear 

programming model of the U.S. electric power sector that the EPA 

has used for over two decades to evaluate the economic and 

emission impacts of prospective environmental policies. To 

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inform its projections of least-cost capacity expansion and 

electricity dispatch, IPM incorporates representations of 

constraints related to fuel supply, bulk power transmission 

capacity, and unit availability. The model includes a detailed 

representation of the natural gas pipeline network and the 

capability to project economic expansion of that network based 

on pipeline load factors. At the EGU level, IPM includes 

detailed representations of key operational limitations such as 

turn-down constraints, which are designed to account for the 

cycling capabilities of EGUs to ensure that the model properly 

reflects the distinct operating characteristics of peaking, 

cycling, and base load units. 

As described in more detail below, the EPA used IPM to 

assess the costs of increasing generation from existing NGCC 

capacity. IPM was able to meet average NGCC utilization rates of 

75 percent on a net summer basis, while observing the market, 

technical, and regulatory constraints represented in the model. 

This modeling also demonstrates the ability of domestic natural 

gas supplies to increase their production levels, and deliver 

that supply through the pipeline network, to support the level 

of NGCC generation quantified in building block 2. Such a result 

is consistent with the EPA's determination that increasing the 

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average utilization rate of existing NGCC units to 75 percent 

would be technically feasible. 

f. Transmission planning and construction. Achieving the 

generation shift quantified in building block 2 would not impose 

significant additional burden on the transmission planning 

process and does not necessitate major construction projects.

Two considerations are important for this conclusion: 

First, building block 2 applies only to increases in 

generation at existing NGCC facilities and does not contemplate 

any connection of new capacity to the bulk power grid. Second, 

regional grids are already supporting operation of the NGCC 

units for sustained periods of time at the capacity factors 

quantified in building block 2.679 Although some upgrades to the 

grid (including potential, but modest, expansions of 

transmission capacity) may be necessary to support the extension 

of the time that these capacity factors are sustained over the 

course of the annual time period on which building block 2 is 

based,, such upgrades are part of the normal planning process 

around the increased use of existing facilities. In fact, the 

electric transmission system is currently undergoing substantial 

 

679 See Greenhouse Gas Abatement Measures TSD for a discussion of 

regional NGCC capacity factors. 

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expansion.680 Consequently, EPA does not believe that achieving 

the generation shift potential in building block 2 would 

necessitate any significant additional requirements for 

transmission planning and construction beyond those already 

being addressed at routine intervals by the power sector.

Furthermore, the phasing in of building block 2’s potential in 

the determination of the BSER; the flexible nature of multi-year 

compliance with the ultimate emission reduction requirements of 

the rule; and the seven years between finalization of this rule 

and the first year of compliance all provide time for 

infrastructure improvements to occur should they prove necessary 

in some locations. 

g. Regulatory flexibility. The final consideration supporting 

our view that natural gas and electricity system infrastructure 

would be capable of supporting increased NGCC unit utilization 

rates at a maximum of 75% on a net summer basis is the 

substantial unit-level compliance flexibility of the emission 

 

680 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

approximately $60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). Construction of transmission lines 

of 345KV and above are generally major projects that are 

particularly effective at carrying power of large distances. 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 

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guidelines. The final rule does not require any particular NGCC 

unit to achieve any particular utilization rate in any specific 

hour or year. Thus, even if isolated natural gas or electricity 

system constraints were to limit NGCC unit utilization rates in 

certain locations in certain hours, this would not prevent an 

increase in NGCC generation overall across a state or broader 

region and across all hours on the order assumed in the 

generation shift potential quantified for building block 2. 

4. Cost 

Having established the technical feasibility and 

quantification of the potential to replace incremental 

generation at higher-emitting EGUs with generation at NGCC 

facilities as a CO2 emissions reduction strategy, we next turn to 

the question of cost. The cost of the power sector CO2 emission 

reductions that can be achieved through shifting generation 

among existing fossil fuel-fired EGUs depends on the relative 

variable costs of electricity production at EGUs with different 

degrees of carbon intensity. These variable costs are driven by 

the EGUs' respective fuel costs and by the efficiencies with 

which they can convert fuel to electricity (i.e., their heat 

rates). Historically, natural gas has had a higher cost per unit 

of energy content (e.g., MMBtu) than coal in most locations, but 

for NGCC units this disadvantage in fuel cost per MMBtu relative 
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to coal-fired EGUs is typically offset in significant part, and 

sometimes completely, by a technological heat rate advantage. 

To consider the cost implications of building block 2, the 

EPA expanded upon the proposal’s extensive analysis of the 

magnitude and cost of CO2 emission reductions through generation 

shifting within defined areas (consistent with the application 

of building blocks for performance rate- and state goalsetting), without consideration of the availability of other 

emission reduction ultimately available to units for compliance. 

To evaluate how EGU owners and grid operators could respond 

to a state plan's possible requirements, signals, or incentives 

to shift generation from more carbon-intensive to less carbonintensive EGUs, the EPA analyzed a series of scenarios in which 

the fleet of NGCC units within each of the regions considered 

for quantifying BSER (i.e., the three interconnections) was 

directed to achieve a specified average annual utilization rate 

across that region on a net basis while maintaining a fixed 

level of aggregate generation in that region across all existing 

fossil fuel-fired sources. The EPA conducted such scenarios to 

address average utilization rates of 70 percent, 75 percent and 

80 percent on a net basis, allowing for shifting of fossil 

generation between existing units within the regions described 

above. This scenario identifies a generation pattern that would 
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meet electricity demand at the lowest total cost, subject to all 

other specified operating and bulk power transfer constraints 

for the scenario, including the specified average NGCC unit 

utilization rate. 

The costs of the various scenarios were evaluated by 

comparing the total costs and emissions from each scenario to 

the costs and emissions from a base case scenario. For the 

scenario reflecting a 75 percent NGCC utilization rate on a net 

basis with regional fossil generation shifting, comparison to 

the base case indicates that the average cost of the CO2

reductions achieved over the 2022-2030 period was $24 per short 

ton of CO2. We view these estimated costs as reasonable and 

therefore as supporting the use of a 75 percent net utilization 

rate target for purposes of quantifying the emission reductions 

achievable at a reasonable cost through the application of 

building block 2 in the BSER. 

We also conclude from these analyses that potential impacts 

to fuel prices and electricity prices from achieving the extent 

of fossil generation shifting quantified for this building block 

are reasonably within the bounds of power sector experience. For 

example, in the 75 percent NGCC unit utilization rate scenario 

where generation shifting is limited to regional boundaries, the 

delivered natural gas price was projected to increase by an 

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average of 7 percent over the 2022-2030 period, which is well 

within the range of historical natural gas price variability.681

Projected wholesale electricity price increases over the same 

period were less than 4 percent, which similarly is well within 

the range of historical electric price variability. These 

projected impacts on prices were captured in the emission 

reduction costs of these scenarios already described above, 

which are reasonable and support use of a 75 percent NGCC 

utilization rate target for purposes of quantifying the emission 

reductions achievable through application of the BSER. 

However, we also note that the costs (and their 

incorporated price impacts) just described are higher than we 

would expect to actually occur in real-world compliance with the 

final rule’s compliance requirements for the following reasons. 

First, this analysis does not capture the building block 2 

phase-in, which assumes an average utilization rate over the 

interim period of less than 75 percent in all three 

interconnections. Second, the analysis overstates the extent to 

which building block 2 is ultimately reflected in the source 

category performance rates. While the performance rate 

computation procedure assumes a maximum NGCC utilization rate of 

 

681 According to EIA data, year-to-year changes in natural gas 

prices at Henry Hub averaged 29.9 percent over the period from 

2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm. 
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75 percent on a net summer basis, the Eastern Interconnection’s 

realization of this level of NGCC utilization yields higher 

source category performance rates for steam than what would have 

been calculated for units in the Western Interconnection and 

Texas Interconnection if they realized that maximum NGCC 

utilization rate in conjunction with the other building blocks.

In other words, there is substantial building block 2 potential 

in the Western Interconnection and Texas Interconnection that is 

not actually captured in the source category performance rates 

that are ultimately assigned to steam through this rate- and 

goal-setting approach (where the performance rates are 

ultimately determined by the BSER region with the highest rate 

outcome in the calculation). Therefore, the building block 2 

analysis overstates the cost of this component of BSER to the 

extent that it assumes achievement of this generation shift 

potential that is not reflected in the source category 

performance rates ultimately determined. Third, as a practical 

matter, sources will be able to achieve additional emission 

reductions through other measures that may prove to be less 

costly than generation shifting and could substitute for the 

reductions and costs considered here. These building block 2 

analyses were focused on evaluating the potential impacts of 

fossil generation shifting in isolation, and as a result, they 

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do not consider states’ and sources’ flexibility to choose among 

alternative CO2 reduction strategies that could offer lower-cost 

reductions, instead of relying on fossil generation shifting to 

the extent analyzed here. 

Based on the analyses summarized above, the EPA concludes 

that an average annual utilization rate for each region’s NGCC 

units of up to 75 percent is a technically feasible, costeffective, and adequately demonstrated building block for BSER. 

For further information on the analysis discussed in this 

section, see Chapter 3 of the GHG Mitigation Measures TSD for 

the CPP Final Rule. 

5. Major comments and responses 

The EPA received numerous comments regarding building block 

2. Many of these comments provided helpful information and 

insights and have resulted in improvements to the rule. This 

section summarizes some of these comments, and the remainder of 

the comments are responded to in the Response to Comment 

document, available in the docket. 

The EPA received comment regarding the potential for an 

increase in upstream methane emissions from increased 

utilization of natural gas. Our analysis found that the net 

upstream methane emissions from natural gas systems and coal 

mines and CO2 emissions from flaring of methane will likely 

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decrease under the Clean Power Plan. Furthermore, the changes in 

upstream methane emissions are small relative to the changes in 

direct emissions from power plants. The technical details 

supporting this analysis can be found in the Regulatory Impact 

Analysis. 

Commenters also expressed concern that neither a utility 

nor any state agency controls dispatch in most states. The EPA 

believes these comments fail to adequately appreciate that the 

utilities do control the dispatch of units that they own and/or 

operate, either by being the actual dispatch agent in many cases 

where there is no RTO or ISO that schedules the dispatch, or by 

the choice of units and bids they offer into an organized 

electricity market operated by an RTO or ISO. These entities 

currently control the dispatch of their units while respecting 

all existing requirements from environmental rules. This final 

rule does not change these current circumstances and makes clear 

that it is the EGU that is responsible for meeting the 

requirements in the state plan; the state is responsible for the 

development of that plan, but the state does not need to control 

the dispatch. 

Other comments object to the use of a single capacity 

factor for all existing NGCCs to quantify building block 2 

potential on the grounds that not all units may be able to 

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achieve this utilization level, and that some units may be 

designed for cycling and so may need upgrades to sustain such 

utilization. The EPA disagrees with these comments. The 75 

percent capacity factor establishes a regional potential for 

generation from existing NGCC capacity, and it does not 

establish any individual unit requirements. 

Some comments argue that generation limits in permits for 

some existing NGCC units will limit the amount by which these 

units can increase their generation and thereby limit the 

feasibility of building block 2. The EPA disagrees with these 

comments. Although permit limits can constrain the ability of 

individual units to operate above certain levels, building block 

2 was developed conservatively, with units operating on average 

at a level below the maximum levels at which some units have 

demonstrated the capability to operate. No individual unit is 

required to achieve the average generation levels used to 

quantify building block 2. Further, permit limits at individual 

units can be considered when state plans are developed. There 

are many flexibilities in the final rule, including the 

opportunity to establish standards of performance that 

incorporate emissions trading, that allow the development of 

plans that will not be constrained by existing permit limits at 

individual units. 
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The EPA also received comments asserting that increasing 

generation from new renewables would require increased use of 

natural gas capacity for back-up and ramping, and therefore it 

is not possible for NGCC units to run at BSER utilization rates 

and also be available to support the additional variable 

renewable generation resulting from building block 3. The EPA 

disagrees with this comment. The 75% net summer utilization 

rates defined by building block 2 is a conservative assessment 

and applied on an annual average basis. It is therefore possible 

for these existing units to both operate at higher annual 

utilization rates, and also to operate at higher rates during 

limited periods and still maintain a 75% net summer average 

annual utilization rate. While variable renewable generation 

does require additional load following and ramping resources and 

unit cycling, these requirements are generally a small part of 

the overall ramping costs of the system (see NREL, Relevant 

Studies for NERC’s Analysis of EPA’s Clean Power Plan 111(d) 

Compliance). Additionally, while existing NGCC units are an 

efficient source of ramping to support variable renewables, 

other units running in an intermediate mode can also provide 

load following and ramping.

E. Building Block 3 — New Zero-emitting Renewable Generating 

Capacity 

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 The third element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which generation 

at the affected EGUs can be replaced by using an expanded amount 

of zero-emitting renewable electricity generating capacity (RE)

to produce replacement generation. In this section we address: 

the history and trends in RE development, the importance of 

expanding the use of RE, the methods by which affected EGUs of 

all types can increase the deployment of RE, the adequate 

demonstration of this building block as a component of the BSER, 

changes made from the proposal, key comments, the method by 

which RE target generation levels are quantified, the magnitude 

and timing of increases in RE generation associated with this 

building block, the feasibility of deploying incremental amounts 

of RE and the reasonableness of costs associated with those 

increases. 

1. History of RE Development 

RE generating technologies are a well-established part of 

the U.S. power sector. These technologies generate electricity 

from renewable resources, such as wind, sun and water. While RE 

has been used to generate electricity for over a century, the 

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push to commercialize RE more broadly began in the 1970s.682

Following a series of energy crises, new federal organizations 

and initiatives were established to coordinate energy policy and 

promote energy self-sufficiency and security, including solar 

energy legislation, the Public Utility Regulatory Policies Act 

of 1978 (PURPA) and the 1980 Energy Security Act.683 

 PURPA was a key step in stimulating RE development. By 

requiring utilities to purchase generation from qualifying 

facilities (i.e., certain CHP and RE generators) at avoided 

costs, PURPA opened electricity markets to more RE generation 

and gave rise to non-utility generators that were willing to try 

new RE technologies.684 In addition, since 1992, federal tax 

policy has provided important financial support via tax credits 

for the production of RE and investments in RE. 

 States have also taken a significant lead in requiring the 

development of RE resources. In particular, a number of states 

have adopted renewable portfolio standards (RPS), which are 

 

682 Nearly all U.S. hydroelectric capacity was built before the 

mid-1970s. U.S. DOE. History of Hydropower. Accessed March 2015. 

Available at: http://energy.gov/eere/water/history-hydropower. 

683 U.S. DOE Office of Management, Timeline of Events: 1971-1980. 

Accessed March 2015. Available at: 

http://energy.gov/management/office-management/operationalmanagement/history/doe-history-timeline/timeline-events-1. 

684 “Restructuring or Deregulation?" Smithsonian Museum of 

American History. Accessed March 2015. Available at: 

http://americanhistory.si.edu/powering/dereg/dereg1.htm. 
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regulatory mandates to increase production of RE. As of 2013, 29 

states and the District of Columbia had enforceable RPS or 

similar laws.685 These RPS requirements continue to drive robust 

near-term growth of non-hydropower RE. 

2. Trends in RE Development 

Today, RE is tightly integrated with the utility power 

sector in multiple ways: states have set RE targets for 

electrical load serving entities; utilities themselves are 

diversifying their portfolios by contracting with RE generators; 

and new RE generators are being developed to provide more 

electrical power grid support services beyond just energy (e.g., 

modern electronics allow wind turbines to provide voltage and 

reactive power control at all times).686,687 

 Use of RE continues to grow rapidly in the U.S. In 2013, 

electricity generated from RE technologies, including 

conventional hydropower, represented 13 percent of total U.S. 

 

685 Energy Information Administration, Annual Energy Outlook 2014 

with Projections to 2040, at LR-5 (2014). 

686 IPCC, Renewable Energy Sources and Climate Change Mitigation, 

2012. Accessed March 2015. Available at: 

http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

687 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. p. 107. 

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electricity, up from 9 percent in 2005.688 In 2013, U.S. nonhydro RE capacity for the total electric power industry exceeded 

80,000 megawatts, reflecting a fivefold increase in just 15 

years.689 In particular, there has been substantial growth in the 

wind and solar photovoltaic (PV) markets in the past decade. 

Since 2009, U.S. wind generation has tripled and solar 

generation has grown twentyfold.690 

 The global market for RE is projected to grow to $460 

billion per year by 2030.691 RE growth is further spurred by the 

significant amount of existing natural resources that can 

support RE production in the United States.692 In the Energy 

Information Administration’s Annual Energy Outlook 2015, RE 

generation grows substantially from 2013 to 2040 in the 

 

688 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6 and Energy 

Information Administration, Monthly Energy Review, May 2015, 

Table 7.2b, Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 

689 Non-hydro RE capacity for the total electric power industry 

was more than 16,000 megawatts in 1998. Energy Information 

Administration, 1990-2013 Existing Nameplate and Net Summer 

Capacity by Energy Source Producer Type and State (EIA-860), 

Available at: http://www.eia.gov/electricity/data/state/. 

690 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b. Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf 

691 “Global Renewable Energy Market Outlook.” Bloomberg New 

Energy Finance, November 16, 2011, Available at: 

http://bnef.com/WhitePapers/download/53. 

692 Lopez et al., NREL, ‘‘U.S. Renewable Energy 

Technical Potentials: A GIS-Based Analysis,’’ (July 2012). 

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reference case and all alternative cases.693 In the reference 

case, RE generation increases by more than 70 percent from 2013 

to 2040 and accounts for over one-third of new generation 

capacity.694 

 The recent and projected growth of RE is in part a 

reflection of its increasing economic competitiveness. Numerous 

studies have tracked capital cost reductions and performance 

improvements for RE, particularly for solar and wind. For 

instance, Lazard’s analysis of wind and utility-scale solar PV 

levelized costs of energy (LCOE), on an unsubsidized basis, over 

the last five years found the average percentage decrease of 

high and low of LCOE ranges were 58 percent and 78 percent, 

respectively.695 Analyses of wind’s competitiveness found falling 

wind turbine LCOE while the wind industry developed projects at 

lower wind speed sites using new turbine designs (e.g., 

increased turbine hub heights and rotor diameters). Performance 

improvements have come from novel deployments of new turbines 

designed for lower quality wind sites that are deployed at 

 

693 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. 25. 

694 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6-7. 

695 Lazard, Levelized Cost of Energy Analysis-Version 8.0, 

September 2014, p. 9, Available at: 

http://www.lazard.com/media/1777/levelized_cost_of_energy_-

_version_80.pdf. 

Commented [A22]: ? Too many “of”s 
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higher quality wind sites, which have resulted in capacity 

factor increases for these locations.696,697 For utility-scale 

solar, cost and performance have also improved significantly. 

Analysis has shown that the installed price of solar 

photovoltaics (PV) systems, prior to any incentives, has 

declined substantially since 1998. Capacity-weighted average 

prices of solar PV in utility-scale deployments were 40 percent 

lower in 2013 than five years earlier.698699 Initially, price 

declines were partially driven by oversupply and manufacturers’ 

thin margins, but, in 2014, prices have remained low due to 

reductions in manufacturing costs.700 The capacity factors of new 

utility-scale installations have increased as systems are 

optimized to maximize energy production. For example, a growing 

number of utility-scale PV systems are increasing the direct 

current capacity of the solar array relative to the alternating 

 

696 “2013 Wind Technologies Market Report,” LBNL, August 2014. 

Available at: http://emp.lbl.gov/publications/2013-windtechnologies-market-report. 

697 “2013 Cost of Wind Energy Review,” NREL, Feb 2015. Available 

at: http://www.nrel.gov/docs/fy15osti/63267.pdf. 

698 “Tracking the Sun VII” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/tracking-sun-vii-historicalsummary-installed-price-photovoltaics-united-states-1998-20. 

699 “Photovoltaic System Pricing Trends,” NREL, 22 Sept 2014. 

Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf. 

700 “Revolution Now – The Future Arrives for Four Clean Energy 

Technologies – 2014 Update,” DOE, Oct 2014. Available at: 

http://energy.gov/sites/prod/files/2014/10/f18/revolution_now_ 

updated_charts_and_text_october_2014_1.pdf. 
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current rating of the array’s inverter to increase energy 

production and improve project economics.701 The cost and 

performance improvements for wind and solar are driven by 

increased scale of production, improved technologies, and 

advancements in system deployments. 

3. Importance of Increasing Use of RE 

Currently, the utility power sector accounts for 40 percent 

of total annual energy consumption in the U.S.702 Introducing 

more zero-emitting RE generation over the long term could 

significantly reduce CO2 emissions, as production of RE 

predominantly replaces fossil fuel-fired generation and thereby 

avoids the emissions from that replaced generation. 

 A number of studies and recent policy developments have 

acknowledged RE as an important means of achieving CO2

reductions. California cited the reduction of CO2 emissions from 

electrical generations as one of the reasons for increasing its 

RE target from 20 percent to 33 percent by 2020 (and potentially 

 

701 “Utility-Scale Solar 2013,” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/utility-scale-solar-2013-

empirical-analysis-project-cost-performance-and-pricing-trends 

702 U.S. Energy Information Administration Annual Energy Review, 

2011. Accessed March 2015. Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/flow/primary_ene

rgy.pdf. 
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50 percent by 2030).703 A recent IPCC report also concluded that 

RE has large potential to mitigate CO2 emissions.704

 Increased use of RE provides numerous benefits in addition 

to lower CO2 emissions. RE typically consumes less water than 

fossil fuel-fired EGUs. Wind power and solar PV systems do not 

require the use of any water to generate electricity; water is 

only needed for cleaning to ensure efficient operation. In 

contrast, utility boilers, in particular, require large 

quantities of water for steam generation and cooling.705

Increasing RE use will also continue to lower other air 

pollutants (e.g., fine particles, ground-level ozone, etc.), 

diversify energy supply, hedge against fossil fuel price 

increases and create economic development and jobs in 

manufacturing, installation, and other sectors of the economy. 

4. Access to RE by Owners of Affected EGUs 

The ability of affected EGUs to obtain incremental RE to 

reduce CO2 emissions is well-demonstrated, whether it is through 

 

703 California S.B. 2 (1X), 2011. Accessed March 2015. Available 

at: http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-

0050/sbx1_2_bill_20110412_chaptered.pdf.

704 IPCC, Renewable Energy Sources and Climate Change Mitigation, 

2012. Accessed March 2015. Available at: 

http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

705 EPA, Water Resource Use. Accessed on March 2015. Available 

at: http://www.epa.gov/cleanenergy/energy-and-you/affect/waterresource.html. 
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direct ownership, bilateral contracts, or procurement of the 

environmental attributes associated with RE generation.706

Consequently, the EPA believes that an increase in RE is a 

proven way to reduce CO2 emissions at affected EGUs of all types 

at a reasonable cost. 

Owners and operators of affected EGUs across the U.S. 

already have substantial opportunities to procure RE regardless 

of their organizational structure and/or business model. In many 

parts of the country, EGUs are owned and operated by vertically 

integrated utilities. These utilities can be investor-owned 

utilities that operate under traditional electricity regulation, 

municipal utilities (munis), or electric cooperatives (co-ops). 

These utilities have significant control over the types of 

generating capacity they develop or acquire, and over the 

electricity mix used to meet demand within their service 

territories. 

Even when EGU owners participating in organized markets do 

not directly determine dispatch among energy sources, such EGU 

owners make decisions about what types of capacity they choose 

to develop and thus what generation mix they can ultimately 

supply into that market’s dispatch choices. Because zero-

 

706 Refer to GHG Abatement Measures TSD for additional ownership 

statistics. 

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emitting RE technologies have relatively low variable costs, an 

EGU owner’s decision to install (or to finance the installation 

of) RE capacity will yield lower-cost electricity generation 

that, when available, a system dispatcher will prefer over 

higher-variable-cost generation from fossil fuel-fired capacity. 

Therefore, all owners of affected EGUs have a direct path for 

replacing higher-emitting generation with RE regardless of their 

organizational type and regardless of whether they operate in a 

cost-of-service framework or in a competitive, organized market. 

Many affected EGUs have already directly invested in RE. Of 

the 404 entities that owned part of at least one affected EGU 

under this rule, 178 also owned RE (biomass, geothermal, solar, 

water or wind). These 178 owners owned 82 percent of affected 

EGU capacity. As a whole, these entities’ share of RE capacity 

was equal to 25 percent of the total of their affected EGU 

capacity.707

Some of the largest owners of affected EGUs also owned RE 

(see Table 7). For example, NRG Energy, Inc. owns more than 

3,000 megawatts of RE capacity, over 20 percent of which (nearly 

800 megawatts) is solar, and almost 80 percent of which (over 

2,500 megawatts) is wind. Duke Energy Corporation owns 175 

 

707 SNL Energy. Data used with permission. Accessed on June 9, 

2015. 

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megawatts of solar and over 1,500 megawatts of wind. NextEra 

Energy, Inc.’s share of RE capacity approaches 40 percent of 

their total affected EGU capacity.708 Table [7] lists a sampling 

of affected EGUs that have large amounts of fossil fuel-fired 

capacity and RE capacity: 

 

TABLE 8. Sample of Owners of Affected EGUs and RE Capacity.709,710 

Ultimate Parent Affected EGU 

Capacity (MW)

Renewable 

Capacity (MW)

NRG Energy, Inc. 48,787 3,149

Duke Energy Corporation 39,028 5,526

Southern Company 37,168 3,245

American Electric Power 

Company, Inc. 

34,940 1,142

NextEra Energy, Inc. 29,471 11,626

Calpine Corporation 23,878 1,509

Tennessee Valley Authority 21,717 5,427

Berkshire Hathaway Inc. 18,899 6,650

FirstEnergy Corp. 16,175 1,371

Exelon Corporation 10,283 3,361

Nebraska Public Power 

District 

2,003 90

Basin Electric Power 

Cooperative 

1,526 275

American Municipal Power, 

Inc. 

1,112 53

Sacramento Municipal Utility 

District 

925 834

Golden Spread Electric 

Cooperative, Inc. 

521 78

 

708 Ibid. 709 SNL Energy. Data used with permission. Accessed on June 9, 

2015. 

710 eGRID, EPA. 2012 Unit-Level Data Using the eGRID Methodology. 

June 7, 2015 version. 

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Deleted: MW 

Deleted: 7

Deleted: Basin Electric Power Cooperative ... [14]
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 Large vertically integrated utilities generally have 

multiple options for investing in RE, including building their 

own RE capacity or procuring RE under a long-term power purchase 

agreement. Municipal utilities and rural cooperatives that own 

generating asset portfolios, particularly generation and 

transmission cooperatives and larger municipal utilities, have 

also used RE to reduce carbon emissions. Large generation and 

transmission cooperatives also purchase significant quantities 

of RE for their members. Federal power authorities own or 

contract for significant amounts of RE.711,712

The list of ten electric utilities with the largest amounts 

of wind power capacity on the system (owned or under contract) 

includes a variety of affected EGU organizational structures, 

including vertically integrated investor-owned utilities, 

municipal utilities, and federal power authorities. Xcel Energy 

and Berkshire Hathaway Energy rank first and second with 5,736 

megawatts and 4,992 megawatts of wind capacity, respectively. 

Tennessee Valley Authority, a federal power authority, had 1,572 

 

711 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. pp. 88-91. 

712 Solar Energy Industries Association. Comments to the EPA and 

States on the Proposed Clean Power Plan Regulating Existing 

Power Plants Under Section 111(d) of the Clean Air Act. pp. 98-

147. 

Deleted: the 

Deleted: largest 

Deleted: MW 

Deleted: MW
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megawatts and CPS Energy, a public utility, had 1,059 megawatts

of wind power capacity.713 Basin Electric Power Cooperative had 

716 megawatts and was the top ranked cooperative utility, but is 

not on the top ten utilities with wind power capacity list. 

Many affected EGUs are already planning on deploying 

significant amounts of RE according to their integrated resource 

plans (IRPs). Electric utilities use IRPs to plan operations and 

investments over long time horizons. These plans typically cover 

10 to 20 years and are mandated by public utility commissions 

(PUCs). A recent study of IRPs, included in the docket for this 

rulemaking, shows this trend. For instance, Dominion plans for 

over 800 megawatts of wind and solar in their 2015 to 2029 

planning period.714 Duke Energy Carolinas’ IRP has no plans for 

new coal, but describes plans for roughly 1,250 megawatts of 

 

713 American Wind Energy Association. U.S. Wind Industry Annual 

Market Report (2014 data). Accessed July 2015. Available at 

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDto

ken=64560&userID=. The ten largest electric utilities with wind 

power capacity on the system (owner or under contract) includes: 

Xcel Energy; Berkshire Hathaway Energy; Southern California 

Edison; American Electric Power; Pacific Gas & Electric; 

Tennessee Valley Authority; San Diego Gas & Electric; CPS 

Energy; Los Angeles Department of Water & Power; and Alliant 

Energy. 714 Dominion North Carolina Power's and Dominion Virginia Power's 

Report of Its Integrated Resource Plan, August 2014, Available 

at: 

https://www.dom.com/library/domcom/pdfs/corporate/integratedresource-planning/nc-irp-2014.pdf. 

Deleted: Basin Electric Power Cooperative had 

716 MW megawatts 

Deleted: MW

Deleted: MW 
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additional RE by 2021, and approximately 2,150 megawatts by 

2029. A significant portion (1,670 megawatts) of the planned RE 

is solar.715 Ameren is planning to retire one-third of the coal 

generating capacity, as well as installing an additional 400 

megawatts of wind, 445 megawatts of solar, and 28 megawatts of 

hydroelectric generating capacity.716 

Independent power producers (IPPs) also can and do own both 

RE and fossil generation. For example, NRG is a diversified IPP 

that operates substantial coal, natural gas, wind, solar, and 

nuclear capacity. NRG demonstrates the ability of IPPs to reduce 

utilization of fossil fuel-fired EGUs and replace that 

generation with RE. NRG announced a goal to cut CO2 emissions 

from its fleet by 50 percent by 2030 (from a 2014 baseline).717

NRG has already reduced CO2 emissions from its fleet by 40 

percent since 2005. This achievement demonstrates that when an 

IPP commits to shifting its generation portfolio, it can do so 

 

715 Duke Energy Carolinas’ 2014 Integrated Resource Plan, 

September 2014, Available at: 

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a9dfc-a43ec559d307. 

716 Integrated Resource Plan Update, October 2014, Available at: 

https://www.ameren.com/missouri/environment/renewables/amerenmissouri-irp. 717 NRG, “NRG Energy Sets Long-Term Sustainability Goals at 

Groundbreaking of “Ultra-Green” New Headquarters” (Nov. 20, 

2014), available at 

http://investors.nrg.com/phoenix.zhtml?c=121544&p=irolnewsArticl

e&ID=1991552.

Deleted: MW 

Deleted: MW 

Deleted: MW 

Deleted: [cite IRP TSD].
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at reasonable cost and without reliability impacts. The NRG 

example shows that reduced utilization of fossil fuel-fired EGUs 

that is replaced by RE also owned by the EGU owner is adequately 

demonstrated. 

EGU owners can also replace fossil fuel-fired generation 

with RE through bilateral contracts and renewable energy 

certificate (REC) purchases, as described below. Both the 

bilateral market for RE contracts and REC markets are well 

developed. There are no legal or technical obstacles to a fossil 

fuel-fired EGU owner acting as the counterparty of a bilateral 

contract for purchase of energy from a RE facility. Any type of 

EGU owner (utility or otherwise) can purchase and retire RECs. 

The fact that RECs are purchased by a diverse set of market 

participants — including residential consumers, commercial 

businesses, and industrial facilities — demonstrates that such a 

purchase for all EGU owners is adequately demonstrated. 

5. Renewable Energy Certificate Markets 

 Affected EGU owners do not need to directly invest in, or 

own, renewable generating capacity in order to replace fossil 

fuel-fired generation with RE as an emission reduction measure. 

Renewable energy certificates (RECs) are used to demonstrate 

compliance with state RE targets, such as state RPS, and also to 

substantiate claims stemming from RE use. RECs are tradable 

Deleted: f

Deleted: . 

Deleted: Instead, affected EGU owners can pay 

for any amount of RE generation, and claim its 

environmental attributes, through the purchase 

of renewable electricity certificates (RECs).¶
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instruments that are associated with the generation of one 

megawatt-hour of RE and represent certain information or 

characteristics of the generation, called attributes.718 RECs may 

be traded and transferred regardless of the actual energy flow. 

 The legal basis for RECs is established by state statutes 

and administrative rules. Nearly all states with a mandatory RPS 

have established RECs as a means of compliance. The Federal 

Energy Regulatory Commission (FERC) has observed that states 

created RECs to facilitate programs designed to promote 

increased use of RE, and that “attributes associated with the 

[RE] facilities are separate from, and may be sold separately 

from, the capacity and energy.”719 

 In complying with states’ RPS requirements, utilities have 

contracted for RECs from in-state and out-of-state resources in 

accordance with RPS requirements. Utilities may have sourced 

RECs from out-of-state to reduce the cost of compliance, to 

 

718 EPA Green Power Partnership, Renewable Energy Certificates 

July 2008). Available at 

http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf. 

719 FERC Docket No. EL03-133-000, Petition for Declaratory Order 

and Request for Expedited Consideration, American Ref-Fuel 

Company, Covanta Energy Group, Montenay Power Corporation, and 

Wheelabrator Technologies, Inc. June 16, 2003, Order Granting 

Petition for Declaratory Ruling, October 1, 2003. American RefFuel Co. et al., 105 FERC ¶ 61,004 (2003); and Order Denying 

Rehearing. April 15, 2004. 107 FERC ¶ 61,016 (2004). Available 

online at: http://www.ferc.gov/whats-new/comm-meet/041404/E28.pdf (accessed 11/7/2014). 

Deleted: (MWh)

Deleted: are 

Deleted: REC ownership confers the right to 

claim the generation attributes. 

Deleted: in 2012, 61 percent of RECs were 

sourced from in-state resources (65 percent on 

weighted average basis). When sourcing RECs 

from out-of-state, RPS requirements typically 

restrict eligible RECs to the state’s region 

(e.g., ISO or neighboring states)
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source RECs from specific generation types, or for other 

reasons.720

The development of REC markets to facilitate RPS compliance 

provides evidence that markets can develop to facilitate 

compliance with rate-base state plans. These markets will afford 

affected EGU owners an alternative to directly invest in, or 

own, renewable generating capacity in order to replace fossil 

fuel-fired generation with RE as an emission reduction measure. 

6. Quantification of Renewable Energy Generation Potential for 

BSER and Major Comments 

The methodology for quantifying RE generation levels under 

building block 3 is a modified version of the alternative RE 

approach from proposal, with adjustments that reflect the data 

and information the EPA collected through stakeholder comments 

and the EPA’s additional analysis and information collection. In 

evaluating the proposed and alternative RE approaches commenters 

observed that RPS, as the basis for quantifying RE generation 

levels under the proposed approach, are policy instruments that 

states may choose to implement for a variety of reasons not 

related to CO2 emission reductions. Additionally, differences 

across RPS policies in eligible resources, crediting mechanisms, 

 

720 Heeter, J. Quantifying the Level of Cross-State Renewable 

Energy Transactions. NREL 2015. Available at 

http://www.nrel.gov/docs/fy15osti/63458.pdf. 

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¶

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deliverability requirements, alternative compliance payments, 

and other policy elements made the regional averaging of statelevel RPS requirements challenging. Finally, commenters provided 

data demonstrating that RE resource potential can vary 

significantly within the regions identified under the proposed 

approach, producing state-level RE generation levels that may 

not be aligned with the opportunity to deploy incremental RE 

resources at reasonable cost. In contrast, commenters argued 

that a methodology similar to the alternative RE approach, which 

is based on economic potential, represents a more technically 

sound basis for quantifying building block 3 target generation 

levels that accounts for regional differences in RE resources 

and power market conditions, such as projected fuel prices, load 

growth and wholesale power prices. The EPA agrees with these 

comments. 

 Within the framework of the alternative RE approach, the 

EPA received significant comments on a number of issues, 

including the use of historical deployment rates, the interstate 

nature of RE and the power system, merits of total versus 

incremental RE generation as the metric by which building block 

3 generation levels are quantified, types of RE technologies 

that contribute to those generation levels, cost and performance 

estimates associated with those RE technologies, magnitude of 

Deleted: use

Deleted: to quantify building block 3 

generation levels, 
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the reduced cost applied to new RE capacity as an incentive to 

deploy, and application of a nationally uniform benchmark 

development rate to modeled projections of economic deployment. 

Based on commenter data and information, as well as further 

analysis and information collection, the primary adjustments the 

EPA made to the alternative RE approach are: 

 The basis for quantifying building block 3 generation has 

been modified to incorporate historical deployment patterns 

for RE technologies as well as the economic potential 

identified through modeling projections. The introduction 

of historical capacity additions to the final methodology 

further grounds building block 3 generation in demonstrated 

levels of RE deployment that have been successfully 

incorporated into the power system. This adjustment also 

serves to harmonize the approach across all three building 

blocks in which historical data is the primary basis for 

identifying emission reduction opportunities under the 

BSER. 

 The RE technologies used to quantify building block 3 

generation levels are onshore wind, utility-scale solar PV, 

concentrating solar power (CSP), geothermal and hydropower. 

Each of these technologies is a utility-scale, zeroemitting resource that was included under the alternative 

Deleted: technical potential limiter

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Deleted: . 

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RE approach at proposal. Additionally, the EPA received 

significant comments on the opportunities and challenges 

associated with distributed RE technologies. Distributed 

technologies, as a demand-side resource, present unique 

data and technical challenges (such as the role of 

evaluation, measurement and verification (EM&V) procedures

in verifying their production, the diverse economic 

incentives of different parties involved in their 

deployment, and the variety of grid integration policies 

and conditions across potential deployment sites) that 

complicate identifying a technically feasible and costeffective level of generation. Consequently, the EPA is, at 

this time, choosing not to include distributed technologies 

as part of the BSER (although, as explained in section 

VIII.K of this preamble, distributed RE technologies that 

meets eligibility criteria may be used for compliance). 

Finally, any RE technology that has not been deployed in 

the United States, including demonstrated RE technologies 

for which there is clear evidence of technical feasibility 

and cost-effectiveness (e.g., offshore wind), contributes 

no generation to building block 3 under this historicallybased methodology. These RE technologies are consequently 

reserved for compliance, which offers affected EGUs 

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Deleted: . 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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additional flexibility and will reduce their need to rely 

on other emission reduction measures or building blocks. 

 Building block 3 generation levels are expressed in terms 

of incremental, rather than total, RE generation. As a 

metric, incremental generation is better aligned with 

quantifying an amount of expanded RE to replace generation 

at affected EGUs.721 Specifically, the generation levels 

under building block 3 include generation from capacity 

that commenced operation subsequent to 2012 (the data year 

on which the BSER is evaluated). Commenters remarked that 

it is unnecessary to include generation from RE capacity 

that was already in operation by 2012 in building block 3 

because the impact of that generation on fossil fuel-fired 

EGUs is already reflected in the observed 2012 emissions 

and generation data of those EGUs. 

 Due to the interstate nature of RE and the power system, 

and consistent with the rationale provided in the October 

2014 Notice of Data Availability (NODA), building block 3 

generation levels are quantified for each of the three BSER 

 

721 Consistent with the November 2014 Notice of Data 

Availability, the final goal setting methodology assumes 

replacement of affected EGU generation by incremental building 

block 3 generation in calculating source-specific CO2 emission 

performance rates. For additional information on the goal 

setting methodology refer to Section VI. 

Deleted: potential of the RE technologies 

considered 

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regions – the Eastern Interconnection, Western 

Interconnection, and Texas Interconnection – rather than at 

the state-level. This regionalized approach, as described 

in the NODA, takes into account the opportunity to develop 

regional RE resources and thus better aligns building block 

3 generation levels with the rule’s approach to allowing 

the use of qualifying out-of-state renewable generation for 

compliance. 

 Commenters observed that the cost and performance estimates 

the EPA relied on at proposal from the Energy Information 

Administration’s Annual Energy Outlook 2013 do not reflect 

the decline in cost and increase in performance that have 

been demonstrated by current projects, particularly in 

regards to wind and solar technologies. Commenters provided 

data from a variety of sources to support these claims, 

including Lawrence Berkeley National Laboratory, the 

Department of Energy (DOE) and Lazard. Each of these 

sources supported the contention that RE technologies, 

particularly wind and solar, have realized gains in cost 

and efficiency at a scale that has altered the competitive 

dynamic between RE and conventional resources. As a result, 

it has become increasingly necessary for any long-term 

outlook of the utility power sector to continually assess 

Deleted: 

Deleted: . 

Deleted: Consequently, cost and performance 

estimates for onshore wind and utility-scale 

solar technologies were reevaluated. 

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the development of RE technology cost and performance 

trends. In performing this task, the EPA revised its data 

for onshore wind and solar technologies to reflect the midcase estimates from the National Renewable Energy 

Laboratory’s (NREL’s) 2015 Annual Technology Baseline. The 

EPA selected the NREL 2015 Annual Technology Baseline (ATB) 

estimates based on the quality of its data as well as 

NREL’s demonstrated success in both reflecting and 

anticipating RE cost and performance trends. In addition to 

wind and solar technologies, the EPA evaluated hydropower 

deployment potential based on the latest cost and 

performance data from NREL’s Renewable Economic Potential 

study.722

 The benchmark development rate that constrained costeffective RE deployment under the alternative RE approach 

in the proposal has been removed from the final 

methodology.723 Commenters detailed several issues with 

applying the benchmark development rate, including that it 

limits future performance to historical levels of 

 

722 For additional information on the updated RE cost and 

performance assumptions used to quantify building block 3 

generation, refer to the GHG Mitigation Measures TSD. 

723 The technical potential limiter was a nationally uniform, 

technology-specific limit on cost-effective RE deployment based 

on the amount of 2012 generation in a state as a share of that 

state’s total technical potential. 

Deleted: T

Deleted: nd

Deleted: consistency with recent

Deleted: . 

Deleted: considered

Deleted: DOE’s Hydropower Vision 

Deleted: technical potential

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Deleted: observed

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development, does not factor in the total size of the RE 

resource in a given state, and is inconsistent with a 

regional approach to quantifying target generation levels. 

EPA agrees with these comments and the benchmark 

development rate has been eliminated. 

In addition to the comments described above, the EPA 

received significant comments on a wide variety of topics 

related to building block 3. Many of these comments provided 

helpful information and insights, and have resulted in 

improvements to the final rule. These comments, as well as the 

EPA responses, are available in the Response to Comment 

document. 

The final methodology for quantifying incremental RE target 

generation levels contains seven steps. Each step is described 

below.724

First, the EPA collected data for each RE technology 

(onshore wind, utility-scale solar PV, CSP, geothermal and 

hydropower) to determine the annual change in capacity over the 

most recent five-year period. From these data, the EPA 

calculated the five-year annual average change in capacity and 

 

724 For supporting data, documentation, and examples for each 

step of the quantification methodology, refer to the GHG 

Mitigation Measures TSD.

Deleted: , relies on non-exclusive resource 

estimates where a single area of land may 

contribute to the technical potential of 

multiple RE technologies

Deleted: technical potential limiter 

Deleted: . 

Deleted: in detail

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Deleted: this 

Deleted: deployment for

Deleted: each technology as well as 

identifying the
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 

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the five-year maximum annual change in capacity for each 

technology. 

Second, the EPA determined an appropriate capacity factor 

to apply to each RE technology that would be representative of 

expected future performance from 2022 through 2030. For this 

purpose the EPA relied on NREL’s ATB. 

Third, the EPA calculated two generation levels for each RE 

technology. The first generation level is the product of each 

technology’s five-year average capacity change and the assumed 

future capacity factor. The second generation level is the 

product of each technology’s five-year maximum annual capacity 

deployment and the assumed future capacity factor. Table 9 below 

shows the data and assumptions used for these calculations. 

TABLE 9. Historical Capacity Changes and Associated Generation 

Levels. 

 Assumed 

Future 

Capacity 

Factor 

Five-Year 

Average 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Five 

Year-Average 

Capacity 

Change (MWh)

Maximum 

Annual 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Maximum 

Annual 

Capacity 

Change (MWh) 

UtilityScale Solar 

PV725

20.7% 1,927 

3,494,268 

3,934 

7,133,601 

CSP 34.3% 251 

754,175 767 2,304,590 

Onshore 

Wind 41.8% 6,200 

22,702,416 13,131 48,081,520 

 

725 Capacity values for utility-scale solar PV are expressed in 

terms of MWDC. The assumed future capacity factor for this 

utility-scale solar PV includes a DC-to-AC conversion, enabling 

the generation totals to be combined across all RE technologies.

Deleted: . 

Deleted: . 

Deleted: over the past five years 

Deleted: . 

Deleted: 8

Deleted: 8

Deleted: 1

Deleted: 3,544,909

Deleted: 7,236,986

Deleted: 45

Deleted: 989,442

Deleted: 3,023,514

Deleted: 2

Deleted: 22,811,040

Deleted: 48,311,575
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Geothermal 85.0% 142 

1,057,332 407 

3,030,522 

Hydropower 63.8% 141 

788,032 294 

1,643,131 

Total

Generation N/A N/A 28,796,222 N/A 62,193,363 

Fourth, the EPA quantified the RE generation from capacity 

commencing operation after 2012 that can be expected in 2021 

(the year before this rule’s first compliance period)without the 

imposition of this rule. Because building block 3 is focused on 

the ability of fossil fuel-fired EGUs to reduce their emissions 

by deploying incremental RE, it is reasonable to take into 

account the considerable amount of RE deployment that is already 

taking place and is projected to continue doing so before 

considering the additional deployment that would be motivated by 

this rule’s mandate to reduce emissions from affected EGUs. The 

EPA considered its base case power sector modeling projections 

using IPM to quantify this component of future-year RE 

generation, which the EPA assumes to be 213,084,125 megawatthours in 2021. 

 Fifth, the EPA applied the generation associated with the 

five-year average capacity change to the first two years of the 

interim period. Combining the projected 2021 RE generation from 

capacity starting operation after 2012 with the generation 

Deleted: 1

Deleted: 1,049,886

Deleted: 3,030,522

Deleted: 4

Deleted: 63

Deleted: 913,843

Deleted: 1,648,282

Deleted: 8,682

Deleted: 29,309,120

Deleted: 18,533

Deleted: 63,250,879

Deleted: by

Deleted: with or 

Deleted: . 

Deleted: additional

Deleted: commonly

Deleted: we

Deleted: . 

Deleted: 2

Deleted: 221

Deleted: 098

Deleted: . 

Deleted: 

Deleted: that was estimated above 
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increment associated with the five-year average change in 

capacity produces 241,880,347 megawatt-hours in 2022 and 

270,676,570 megawatt-hours in 2023. The EPA believes it is 

appropriate to apply the generation associated with the fiveyear average capacity change for the first two years of the 

interim period to ensure adequate opportunity to plan for and 

implement any necessary RE integration strategies and 

investments in advance of the higher RE deployment levels 

assumed for later years. 

Sixth, for all years subsequent to 2023 the EPA applied the 

generation associated with the maximum annual capacity change 

from the historical data analysis. In 2024, this produces a 

building block 3 generation level of 332,869,933 megawatt-hours 

(aggregated across all three BSER regions); by 2030, that 

generation level is 706,030,112 megawatt-hours. 

Seventh, to further evaluate the technical feasibility and 

cost-effectiveness of the building block 3 generation levels 

(aggregated across all three BSER regions), as well as to 

produce interconnection-specific levels of building block 3 

generation from the national totals described in steps 5 and 6, 

the EPA conducted analysis using IPM of a scenario directing the 

power sector to achieve those RE generation levels. IPM modeling 

projections assess opportunities for RE deployment in an 

Deleted: 530

Deleted: 219

Deleted: 839

Deleted: 339

Deleted: 4

Deleted: 090

Deleted: 218

Deleted: 13

Deleted: 595

Deleted: 494

Deleted: 

Deleted: . 
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integrated framework across power, fuel, and emission markets. 

The modeling framework incorporates a host of constraints on the 

deployment of RE resources, including resource constraints such 

as resource quality, land use exclusions, terrain variability, 

distance to existing transmission, and population density; 

system constraints such as interregional transmission limits, 

partial reserve margin credit for intermittent RE installations, 

minimum turndown constraints for fossil fuel-fired EGUs, and 

short-term capital cost adders to reflect the potential added 

cost due to competition for scarce labor and materials; and 

technology constraints such as construction lead times and 

hourly generation profiles for non-dispatchable resources by 

season.726 Additionally, the EPA assumes in this analysis that 

deployment of variable, non-dispatchable RE resources is limited 

to 20 percent of net energy for load by technology type and 30 

percent of net energy for load in total at each of IPM’s 64 U.S. 

sub-regions.727 The 30 percent constraint applied to variable, 

non-dispatchable RE resources reflects levels commonly modeled 

in grid integration studies at the level of the interconnection. 

These studies have demonstrated that impacts to the grid in 

 

726 Refer to GHG Abatement Measures TSD for more detail on 

modeling methodology. 

727 Regions that have already exceeded these limits are held at 

historical percent of net energy for load. 

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reaching levels as high as 30 percent of net energy for load are 

relatively minor.728 For example, the Western Wind and Solar 

Study Phase 2 found cycling costs ranged from $0.14 to $0.67 per 

megawatt-hour of added wind and solar generation. These 

integration cost levels are not impactful in determining costeffectiveness. As such, applying the 30 percent constraints at 

the IPM sub-region level provides a high degree of assurance 

that the RE capacity deployment pattern projected by the model 

would not incur significant grid integration costs.729 

In addition to facilitating the EPA’s assessment of the 

feasibility and cost of reaching the aggregate building block 3 

generation levels across all three BSER regions, the IPM 

projections also provide the EPA with a basis for apportioning 

those generation levels to each interconnection. The EPA 

considered the projected regional location of the evaluated RE 

deployment in this analysis, which shows the majority of such 

deployment occurring in the Eastern Interconnection. The GHG 

Abatement Measures TSD describes in greater detail the process 

 

728 Wind Technologies Market Report 2013. LBNL. Cochran, et al. 

2014; Grid Integration and the Carrying Capacity of the U.S. 

Grid to Incorporate Variable Renewable Energy. NREL. Cochran, et 

al. 2015; The Western Wind and Solar Integration Study Phase 2. 

NREL. Lew, et al. 2013. Refer to GHG Mitigation Measures TSD for 

further analysis. 

729 Refer to the GHG Abatement Measures TSD for additional 

information on constraints related to deployment of nondispatchable RE. 

Deleted: . 

Deleted: se

Deleted: does not represent a technical 

feasibility limit but rather a conservative 

view of deployment levels that 

Deleted: require

Deleted: . 

Deleted: .