### 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	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

1 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

2 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

3 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 CO 2 emission reductions from 2005 levels of 29% in 2025 and 30% in 2030. For the final rule, the EPA projects total CO 2 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.

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

4 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 CO 2 

### 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 CO 2 

### 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 CO 2 

### 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

5 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

6 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 CO 2 

### 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 CO 2 

### emission performance goals are the emissions directly represented in the numerator of the statewide rate

‐ based CO 2 

### 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 CO 2 

### emission performance rate, there are cost

‐ effective lower

‐ emitting generation opportunities quantified under the building blocks that are not necessary for affected EGUs i n 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.

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

7 “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 CO 2 

### emission standards at a single level that applies for all affected EGUs, consistent with the state rate

‐ based CO 2 

### 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.

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

8 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 2 nd 

### set

‐ aside on page 1365 says RE and EE is included in the federal plan, which is supported 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

9 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 CO 2 

### emission standard

– NGCC reported CO 2 

### emission rate)/ NGCC CO 2 

### emission standard) According to this equation, ERC issuance is assessed based on the difference between the CO 2 

### emission rate limit for the NGCC unit and the reported CO 2 

### 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 CO 2 

### 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 incentives to 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

# Summary	of	Interagency	Working	Com ments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

10 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	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

*** 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 (CO 2 ) goals reflecting CO 2 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

CO 2 emission performance rates. This final rule will continue Deleted: , U.S. territories, and tribes

Deleted: carbon dioxide (CO 2 )

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 CO 2 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://www 2 .epa.gov/dockets. Deleted: **OF**

Deleted: epahome/ Deleted: .htm*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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://www 2 .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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 CO 2 /MWh Pounds of CO 2 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]: ?*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 5 of 1544 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 PM 2.5 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 SO 2 Sulfur Dioxide Tg Teragram (one trillion (10 12 ) 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 6 of 1544

F. Congress ional Awareness of Climat e 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. Subc**  **ategory-Specific CO 2**  **Emission Performance Rates** A. Overview B. Emission Performance Rate Requirements C. Form of the Emission Performance Rates **VII. Statewide CO 2**  **Goals** A. Overview B. Translating Subc ategory-Specific Emission Performance Rates to Statewide CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 CO 2 emission guidelines for existing fossil fuel-fired electric generating units (EGUs) – the Clean

Power Plan. T hese final guidelines, when fully implemented, will achieve significant reductions in CO 2 emissions by 2030 , while

offer ing states and utilities substantial flexibility and latitude in achieving these reductions. In this final rule, the

EPA is formulating a CO 2 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

CO 2 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 CO 2 emission performance rates, either directly by means of source-specific emission standards or other requirements , or through measures that achieve equivalent CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 emission performance rates , and 4) provide for p eriodic state-level demonstrations prior to and during the 2022-2029 period that will ensure that required CO 2 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.

T he EPA is promulgating 1) sub category-specific CO 2 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 CO 2 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 *** Page 12 of 1544 3) state m ass-based CO 2 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 m easures 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 CO 2 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 CO 2 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 (CO 2 ), 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 CO 2 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 CO 2 emission standards of performance for new, modified, and reconstructed power plants. Together,

these rules will reduce CO 2 emissions by a substantial amount

while ensur ing th a t 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, t he 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, t his

final rule fully account s 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 CO 2 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 CO 2 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: CO 2

Deleted: CAA section 111(d) itself relies on a state-EPA partnership to accomplish the required CO 2 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 twosubcategories 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 16 of 1544 Nationwide, by 2030, this final CAA section 111(d) existing

source rule will achieve CO 2 emission reductions from the utility power sector of approximately [X] percent from CO 2 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 CO 2 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 CO 2 emission reductions. The second objective was to Commented [A4]: 32?

Deleted: , to which

Deleted: will lead,

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. T hese 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 reflec ting the unique interconnected and interdependent system within which EGUs operate. Thus, the BSER, as determined in these guidelines, incorporates a range of CO 2 -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 provide s states and utilities with time for planning and Deleted: maximum flexibility, control and choice in meeting their compliance obligations

Deleted: comment

Deleted: two crucial

Deleted: Though

Deleted: are Deleted: First, t

Deleted: United States ( Deleted: .) Deleted: Second, these guidelines Deleted: Deleted: t

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 CO 2 emission reduction requirements in terms of state goal s reflect ing 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

CO 2 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. A s 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 CO 2 emissions

. S tates , 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 CO 2 , 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 CO 2 reduction plans within that framework, while states with a more deregulated power sector system will be able to develop CO 2 reduction plans within that specific framework. Each state will have the opportunity to take advantage of a wide variety of strategies for reducing CO 2 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 CO 2 goals, expressed as both emission rates and as mass, that reflect the state’s fleet-weighted aggregate of

two sub category-specific CO 2 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 CO 2 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 fossilfuel-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 adopt s meet s its

state-level CO 2 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 concurrent ly 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 CO 2 reductions that will ensure that progress is being made in achieving CO 2 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. Determin ing the BSER. I n 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, CO 2 ) 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 CO 2 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 a vailable 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 CO 2 emissions from existing fossil fuel-fired EGUs either by (1) reducing the CO 2 emission rate at those units or (2) reducing the units’ CO 2 emission total to the extent that generation can be shifted from higher-emitting fossil fuel- f ired 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, CO 2 ) from affected sources (in this case, fossil fuel-fired EGUs). 8 ¶ To determine the BSER for reducing CO 2 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 CO 2 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 s ection V of this preamble.

e. CO 2 state-level goals and subcategory-specific emission performance rate. (1) Final CO 2 goals and emission performance rates

. I n this action, the EPA is establishing CO 2 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 lb CO 2 /MWh. For stationary combustion turbines, we are finalizing an emission performance rate of 7 71 lb CO 2 /MWh. As wedid at proposal, for each state, we are also promulgating ratebased CO 2 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: CO 2 emission performance rates for two subcategories of affected EGUs-- fossil fuel- ... [3] Deleted: 290 Deleted: of CO 2 Deleted: 80 Deleted: of CO 2 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 CO 2 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 CO 2 emission performance

rates , expressed via the state-specific rate- and massbased goals, by 2030. (2) Interim CO 2 emission performance rates and statespecific goals. The best system of emission reduction includes both the measures for reducing CO 2 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 CO 2 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 CO 2 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 CO 2 emission performance rates into equivalent statewide rate- b ased and mass-based CO 2 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 CO 2 emission performance rates, and by providing a translation ofthose performance rates to statewide rateand mass-based CO 2 goals, the rule allows states the flexibility to determine how to achieve the CO 2 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 CO 2 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, al ternatively, 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 CO 2 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, t o 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 CO 2 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- i ntensive 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 4 9.9 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 CO 2 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 sub category-specific CO 2 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 f or th e 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 CO 2 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 plac ing 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 CO 2 Emission Performance Rate and G oal C omputation 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 CO 2 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 CO 2 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 s ection 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 33 of 1544 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 CO 2 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 CO 2 emission goal of 2030 and beyond

 Demonstration that the plan submittal is projected to achieve the state ’ s CO 2 emission goal 14

 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 34 of 1544

 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 the ir plan submittal s, 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 *** Page 35 of 1544 (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 provid e 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 CO 2 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) Deleted: that Deleted: also Deleted: ing Deleted: August Deleted: 31*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 36 of 1544 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 CO 2 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 *** Page 37 of 1544 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 s ection 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 *** Page 38 of 1544 credits (ERCs) to adjust CO 2 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 CO 2 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 CO 2 emission guidelines. Deleted: participate in emission trading programs (e.g., as providers of emission rate credits, to adjust CO 2 emission rates for affected EGUs).

Deleted: that Deleted: that provide*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 39 of 1544 The EPA recognizes that the measures states and utilities have been and will be taking to reduce CO 2 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 CO 2 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 CO 2 emission performance rates or equivalent statewidegoals 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 CO 2 emission performance rates, or, following the emissions Deleted: affordability

Deleted: Based on a careful review of the comments and other material in the recor d*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 40 of 1544 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 CO 2 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 CO 2 reductions. The EPA recognizes that successfully achieving reductions by 2022 will be facilitated by actions and investments that yield CO 2 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 CO 2 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.¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 41 of 1544 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 CO 2 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. Deleted: partnership Deleted: p

Deleted: overburdened

Deleted: a limited number of

Deleted: limit

Deleted: Mt

Deleted: c Deleted: e Deleted: investment Deleted: p Deleted: Before Deleted: topics

Deleted: , Deleted: and the public*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 42 of 1544 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 t his rule will provide broad

benefit s 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, SO 2 , 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 CO 2 emission reductions during the 2022-2029 period will contribute toward meeting both the interim and final CO 2 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 CO 2 emission performance rate. ¶ Many commenters expressed concerns that regulatory mechanisms that states put in place to reduce CO 2 emissions could inadvertently create unwanted effects that could lead to increases in CO 2 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, CO 2 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, Deleted: also decrease Deleted: power Deleted: Deleted: coDeleted: significant

Deleted: threat Deleted: to Deleted: minority communities, Deleted: , 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 *** Page 44 of 1544 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. T he 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 commun i ties and for ... [9] Deleted: is Deleted: encouraging 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 Deleted: to

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 Deleted: start Deleted: of

Deleted: which,

Deleted: s

Deleted: These changes Deleted: provide

Deleted: of the*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 47 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 48 of 1544 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 CO 2 emissions under this program. (8) O utreach and resources for stakeholders. To provide states, U.S. territories, tribes, utilities, communities, and other interested stakeholders with*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 50 of 1544 sources to create a comprehensive training curriculum for those implementing th is 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 CO 2 from fossil fuel-fired EGUs in a manner

15 www.epa.gov/cleanpowerplantoolbox. Deleted: e Clean Power Plan

Deleted: the U.S. Department of Energy

Deleted: , U.S. territories

Deleted: 2

Deleted: A Deleted: H Deleted: The*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 51 of 1544 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

CO 2 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.

T o achieve these objectives, t he 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 Deleted: reflected

Deleted: over-riding Deleted: : Deleted: , Deleted: shape the standards set for EGUs to

Deleted: s Deleted: , and Deleted: ,

Deleted: comment

Deleted: considerations: T

Deleted: standard Deleted: s*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 52 of 1544 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 . I n the proposal, we expressed the emission limitation requirements reflecting the

BSER in terms of t he 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 programsand 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 Deleted: we are

Deleted: ing Deleted: it Deleted: better Deleted: thate fact that Deleted: are implemented Deleted:

- Deleted: bases Deleted: ¶ Deleted: s Deleted: T Deleted: reflected an approach to the BSER that 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 CO 2 emission reductions. Deleted: They also reflected Deleted: essential Deleted: the fact that Deleted: While retaining the state goals, expressed as emissions rates, t Deleted: also Deleted: y Deleted: and sets forth mass-based goals for each state as well as a rate-based goal Deleted: chief priorities Deleted: of Deleted: a Deleted: that made*** 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 Deleted: source

Deleted: A great m Deleted: commenters and Deleted: emphatically Deleted: target Deleted: was Deleted: goal Deleted: s

Deleted: would all but compel Deleted: w

Deleted: stymie

Deleted: target*** 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

. T his 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. Deleted: target

Deleted: the Deleted: ning

Deleted: utiliites

Deleted: As a result, In response to the EPA’s 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. Deleted: E Deleted: C Deleted: R Deleted: Together with the proposal, t

Deleted: and resulting in

Deleted: , Deleted: from*** 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 CO 2 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 ha ve 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 Deleted: As a result,

Deleted: these Deleted: reflect modifications

Deleted: , and that

Deleted: These final guidelines bear the stamp of the information and input the EPA gleaned from its extensive outreach process and from the comment record. Deleted: thinking and

Deleted: the Federal Energy Regulatory Commission ( Deleted: ) Deleted: the U.S. Department of Energy ( Deleted: ) Deleted: s*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 56 of 1544 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 electricityoperations over the three regional Interconnections, and up-todate information about the cost and availability of clean generation options, 3) the formulation of source-specific CO 2 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 emissiontrading, 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 CO 2 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. ¶ Deleted: I Deleted: resulting Deleted: highlighted b y Deleted: a new start date of Deleted: for the interim period Deleted: , 2) Deleted: 3 Deleted: a duo of changes – Deleted: inclusion Deleted: level Deleted: s Deleted: and mass- as well as Deleted: – intended Deleted: , Deleted: 34) in the BSER being derived from traditionaldetermination, a focus on a narrower generation options only and not fromthat do not include demand-side energy efficiencies, 4 Deleted: 5 Deleted: more complete incorporation in the 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) Deleted: as indicated in 3), above, sourcespecific CO 2 emission performance rates that 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 *** Page 57 of 1544 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

submit tal 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 explanation s 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 w ere both the subject s 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 Deleted: Deleted: 7

Deleted: 8 Deleted: for Deleted: to

Deleted: and 9 Deleted: 10

Deleted: ,

Deleted: This suite of changes is the product 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. Deleted: a high level Deleted: provide greater detail about

Deleted: Interim Period Start Date of

Deleted: The start date

Deleted: as*** 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 CO 2 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 CO 2 emission reductions beginning in 2020 , together with the stringency of

the interim CO 2 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 CO 2 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 Deleted: states, utilities, and grid operators

Deleted: would be

Deleted: ,

Deleted: and

Deleted: 2020 start date for achieving CO 2 reductions Deleted: bore

Deleted: (

Deleted: and

Deleted: )*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 59 of 1544 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 d etermination

. Deleted: guidelines’ approach

Deleted: .Revised2 Deleted: D*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 60 of 1544 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 illustrate s 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, t he 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 Deleted: charateristics

Deleted: (e.g.,

Deleted: )

Deleted: T*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 61 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 62 of 1544 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.

C ommenters 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

sub category-specific emission performance rates take into

account th e 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 Deleted: Since c

Deleted: ,

Deleted: of the same

Deleted:

Deleted: source

Deleted: at reality

Deleted: Due to Deleted: revised*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 63 of 1544 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 CO 2 reductions in 2030 than the proposal. With a date of 2022, instead of 2020, as proposed, for mandatory CO 2 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 foraffected sources, rather than by means of merely setting statespecific goals , and that these standards be uniform

. Still other Deleted: findings

Deleted: an energy

Deleted: revised start Deleted: for emission reductions

Deleted: After consideration of extensive 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.¶

Deleted: ’s

Deleted: Many Deleted: that the EPA must*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 64 of 1544 commenters observed that the effect of the approach taken in the proposal of applying the BSER to each state’s fleet was to put agreater burden of reductions on lower-emitting or less carbonintensive states and a lesser emission reduction burden onsources 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, wherethe 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 CO 2 emissions limitations with facility and grid-level operations. These sets of comments intersected at the point at which they focused on Deleted: s

Deleted: very much

Deleted: – a

Deleted: – Deleted: and

Deleted: benefited Deleted: , appropriately, Deleted: from having

Deleted: based

Deleted: both*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 65 of 1544

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.

T he 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 CO 2 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 Deleted: t

Deleted: , Deleted: particularly with respect to state goals,

Deleted: and, in Deleted: , maintains flexibilities for states throughstates through the state measures approach while also Deleted: category Deleted: at the fulcrum Deleted: both Deleted: sources Deleted: s

Deleted: ting uniform rates for sources

Deleted: In response to these and similar comments,

Deleted: issu

Deleted: , at the same time,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 66 of 1544 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, s tates 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 anapproach 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, e ach 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 Deleted: significantly increases flexibility for Deleted: and

Deleted: S

Deleted: for their sources Deleted: E*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 67 of 1544 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 CO 2 emission performance rates, as well as state-level goals , as a t proposal, each state will have a goal reflecting its particular mix of Deleted: by way of meeting Deleted: that is projected to achieve equivalent emission reductions as determined by Deleted: -level Deleted: state

Deleted: do no such thing

Deleted: B

Deleted: source

Deleted: y Deleted: y

Deleted: of performance

Deleted: , in fact, Deleted: fully Deleted: always Deleted: all Deleted: –

Deleted: individual sources can meet Deleted: confirm that Deleted: , therefore,

Deleted: now take a source-specific approach to setting both Deleted: and

Deleted: tailored to*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 68 of 1544 sources, and the final guidelines retain the flexibility inherent in the proposal’s state-specific goals approach (and,

as discussed in s ection 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

. C ommenters expressed support for the objectives served by the “portfolio” option in the state plan approaches included at proposal, b ut 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 CO 2 emission performance rates into equivalent statewide rate-based and mass

- b ased CO 2 g oals. 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 *** Page 69 of 1544 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

CO 2 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.

M any 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 CO 2 emission performance rates Deleted: tailoring required CO 2 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 supportstate 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 requiredemission 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 CO 2 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 CO 2 -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:

Deleted: c Deleted: investment Deleted: partnership p

Deleted: target*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 72 of 1544 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 CO 2 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 CO 2 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 *** Page 73 of 1544 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 undermin e 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 change s 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, t he 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) Initiative 17 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 *** Page 76 of 1544 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. T hefinal rule ensures that bill-lowering measures such as demandside EE continue to be a major compliance option. In addition tocarbon 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, w e 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 *** Page 77 of 1544 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 c ontext 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. CO 2 is the primary GHG pollutant, accounting for nearly three-quarters of global GHG emissions 19 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 *** Page 78 of 1544

U.S. GHG emissions. 20 The May 2014 report of the National Climate

Assessment 21 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

CO 2 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 *** Page 79 of 1544 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 CO 2 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 CO 2

. A mong 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 CO 2 emissions from power plants,

President Obama issued a Presidential Memorandum 23 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 PollutionStandards, 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 *** Page 80 of 1544 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.

T he utility power sector is unlike other industrial

sector s . 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, t he 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 *** Page 81 of 1544 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 *** Page 82 of 1544 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 *** Page 83 of 1544

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 *** Page 84 of 1544 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 SO 2 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 NO X 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 sub category-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 CO 2 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 CO 2 emission reductions from EGUs. Others reduce CO 2 emissions by increasing the use of lower and zero CO 2 emission alternatives such as renewable generation. For example, many states have adopted renewable portfolio standards (RPS). In other cases, utilities have chosen to construct renew a ble generation, at least in part, to reduce CO 2 emissions. These approaches take advantage of cost-effective opportunities for improving the efficiency offossil 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.

A t the same time, o wners/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 *** Page 87 of 1544 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 CO 2 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 CO 2 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 (SO 2 ), 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 CO 2 emissions from new, modified, and reconstructed fossil fuel- f ired 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). CO 2 q ualifies 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 CO 2 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 CO 2 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 *** Page 88 of 1544 (NO X ), and directly emitted fine particulate matter (PM 2.5 ). 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 CO 2 and other air pollutants, including

SO 2 , NO X , and directly emitted PM 2.5 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 scenariosdesigned to achieve these goals, which we term the “rateDeleted: 6*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 PM 2.5 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 $8.4 billion (2011$) underthe 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 *** Page 91 of 1544 **Table 1. Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Final Guidelines in 2020, 2025, and** 

**2030 a**  **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 **N et 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 NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , 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 **N et Monetized**  **Benefits e**  $17 to $27 $16 to $25

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 92 of 1544 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 **N et Monetized**  **Benefits e**  $26 to $45 $25 to $43

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2

Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , 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 CO 2 emission changes and does not account for changes in non-CO 2 GHG emissions. Also, different discount rates are applied to SC-CO 2 than to the other estimates because CO 2 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-CO 2 values. As shown in the RIA, climate benefits are also estimated using the other three SC-CO 2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). The SC-CO 2 estimates are year-specific and increase over time.

c The air pollution health co-benefits reflect reduced exposure to PM 2.5 and ozone associated with emission reductions of directly emitted PM 2.5 , SO 2 and NO X . 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 PM 2.5 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 *** Page 93 of 1544

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-CO 2 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 2030**  **a 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 **N et 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 NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , 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 *** Page 94 of 1544 **Total Compliance Costs**  **d** $3.0 $3.0 **N et Monetized**  **Benefits e**  $16 to $26 $15 to $24

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , 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 **N et Monetized**  **Benefits e**  $26 to $43 $25 to $40

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2

Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , 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 CO 2 emission changes and does not account for changes in non-CO 2 GHG emissions. Also, different discount rates are applied to SC-CO 2 than to the other estimates because CO 2 emissions are long-lived and subsequent damages occur over many years. The benefit estimates in this table are based on the average SC-CO 2 estimated for a 3 percent discount rate, however we emphasize the importance and value of considering the full range of SC-CO 2 values. As shown in the RIA, climate benefits are also estimated using the other three SC-CO 2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). The SC-CO 2 estimates are yearspecific and increase over time.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 95 of 1544

c The air pollution health co-benefits reflect reduced exposure to PM 2.5 and ozone associated with emission reductions of directly emitted PM 2.5 , SO 2 and NO X . 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 PM 2.5 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-CO 2 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 CO 2 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-CO 2 greenhouse gases (e.g., nitrous oxide and methane) 31 and co-

31 Although CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 96 of 1544 benefits from reducing direct exposure to SO 2 , NO X , 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, anet decrease in job-years of about 31,000 under the ratebased approach and 34,000 under the mass-based approach 32 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 optica lly when in fact overall there looks to be a gain.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 97 of 1544 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 CO 2 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 CO 2 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 sub category-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 *** Page 98 of 1544 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 XII I

. We note that this rulemaking is being promulgated concurrently with related rulemaking s: the final new source performance standards (NSPS) for CO 2 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 . Th ese rulemaking s ha ve their own rulemaking docket s . **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 *** Page 99 of 1544 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 CO 2 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 CO 2 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 CO 2 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 *** Page 100 of 1544 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 *** Page 101 of 1544 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 102 of 1544 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 21 st 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, CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 103 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 104 of 1544 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 mentalhealth, 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 CO 2 by itself can elevate production of plant-based allergens.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 105 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 106 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 107 of 1544 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, CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 108 of 1544 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 CO 2 reached will not be fully realized for several centuries, underscoring that emission activities today carry with them climate commitments far into

the future.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 109 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 110 of 1544 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 4 th 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 111 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 112 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 113 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 114 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 115 of 1544 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-20 th 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 116 of 1544 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 CO 2 as measured on top of Mauna Loa was 387*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 117 of 1544 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 20 th 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

45 ftp://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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 118 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 119 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 120 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 121 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 122 of 1544 highways, wetlands, fresh water supplies, and energy

infrastructure. In the Northwest, temperatures increased by about 1.3 o F 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

3.3 o F to 9.7 o F 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 123 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 124 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 125 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 126 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 127 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 128 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 129 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 130 of 1544 impacts occur across regions and landscapes in ways that do not follow political boundaries.

B. GHG Emissions from Fossil Fuel-fired EGUs 50 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 CO 2 , 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 Sinks 51 (the U.S. GHG Inventory). The EPA implements a separate program under 40 CFR Part 98 called the Greenhouse Gas Reporting Program 52 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 131 of 1544 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 sinks 53 of GHGs, including CO 2 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 CO**  **2 Eq.))**  **54**

**SECTOR 1990 2005 2013**

Energy 55 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 2 5.5 2 3.3

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 132 of 1544

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 CO 2 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 CO 2 emissions. 57 Table 3 below presents total CO 2 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 CO**  **2 )**  **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***** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 133 of 1544

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 CO 2 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, CO 2 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 CO**  **2 e)**  **59**

59 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do. Total CO 2 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 3 18.8 441.9 - from petroleum 97.5 9 7.9 22.4*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 134 of 1544

C. Challenges in Controlling Carbon Dioxide Emissions Carbon dioxide is a unique air pollutant and controlling it presents unique challenges. CO 2 is emitted in enormous quantities, and those quantities, coupled with the fact that CO 2 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 CO 2 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, CO 2 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 1 76.7 Onshore Oil & Gas Production 94.8 Municipal Solid Waste Landfills 9 3.0 Iron & Steel Production 8 4.2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 135 of 1544 greater than any other air pollutant. 60 In fact, CO 2 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 CO 2

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/) NO X 13.072 “ PM 10 20.651 “ SO 2 5.098 “ VOC 17.471 “ NH 3 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 PM 2.5 is included in the amounts for PM 10 . 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 (NH 3 ) is included because it is a precursor to PM 2.5 secondary formation. Note that one short ton is equivalent to 0.907185 metric ton. 62 In addition, emissions of non-CO 2 GHGs totaled 1.168 billion metric tons of carbon-dioxide equivalents (CO 2 e) in 2013. See Table ES-2, Executive Summary, 1990-2013 Inventory of U.S. Greenhouse Gas Emissions and Sinks.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 136 of 1544 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 CO 2 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-CO 2 GHG have been translated from metric tons of that gas into metric tons of CO 2 e 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 CO 2 .) 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/current 65 As another point of comparison, except for carbon dioxide, SO 2 and NO x 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 CO 2 as they have emitted SO 2 and NO x . 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, SO 2 and NO x 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 CO 2 as they have emitted SO 2 and NO x . 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: ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 137 of 1544

than 3 tons of CO 2 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, CO 2 is relatively unreactive and difficult to remove directly from the atmosphere. 67,68

CO 2 ’s huge quantities and lack of reactivity make it challenging to remove from the smokestack. Retrofitted equipment is required to capture the CO 2 before transporting it to a storage site. However, the scale of infrastructure required to directly mitigate CO 2 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 CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 138 of 1544 emitted in the largest quantities of any of the other air pollutants, except for CO 2 – each have more accessible mitigation options. Sulfur dioxide (SO 2 ) is the result of a contaminant inthe 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 (NO x ) can be mitigated relatively easily using combustion control techniques (e.g.,

low-NO x 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 CO 2 primarily because of the comparatively lower quantities that are produced, and also due to other attributes such as relatively greater reactivity and solubility.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 139 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 140 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 141 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 142 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 143 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 144 of 1544 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 athttp://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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 145 of 1544 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 utilities 96

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 146 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 147 of 1544 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 athttp://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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 148 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 149 of 1544 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 resources 104 , such as energy efficiency 105 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 150 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 151 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 152 of 1544 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 areconstantly 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 153 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 154 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 155 of 1544 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 athttp://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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 156 of 1544 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 athttp://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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 157 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 158 of 1544regional 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/RTOs 134 , 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-*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 159 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 160 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 161 of 1544 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 AEOnumbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 162 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 163 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 164 of 1544 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

facilities 150 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 165 of 1544 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 N on-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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 166 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 167 of 1544 early 1990s. Energy efficiency has been utilized to meet energy demand to varying levels since that time. As of April 2014, 25

states 161 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 168 of 1544 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., SO 2 and NO x ), in the atmosphere by targeting “the principal sources” of these pollutants through an

SO 2 cap-and-trade program for fossil-fuel fired power plants and through a technology based NO x emission limit for certain utility boilers. Altogether, Title IV was designed to achieve reductions

of ten million tons of annual SO 2 emissions, and, in combination with other provisions of the CAA, two million tons of annual NO x emissions. 164

The SO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 169 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 170 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 171 of 1544 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. NO x SIP Call. In 1998, the EPA promulgated the NO x SIP Call, which required 23 upwind states to reduce emissions of NO x 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 172 of 1544

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 NO x 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 NO x 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 NO x and SO 2 that would impact downwind areas with projected nonattainment and maintenance problems for ozone and

PM 2.5 . 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 NO x and SO 2 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 NO x 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 173 of 1544

FIP. 182 As relevant here, the D.C. Circuit remanded CAIR in North

Carolina v. EPA due to in part the structure of its interstatetrading 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 NO x and SO 2 that would impact downwind areas with projected nonattainment and maintenance problems for ozone and

PM 2.5 . 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 174 of 1544 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 SO 2 and

NO x 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 175 of 1544 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 SO 2 and NO x 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 SO 2 and selective catalytic reduction for NO x 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 176 of 1544 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 SO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 177 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 178 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 179 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 180 of 1544 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 Climat e Change in the Context of

the Clean Air Act Amendments 204

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 . T here 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 181 of 1544 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 T he 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 182 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 183 of 1544 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 yield ed 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 184 of 1544 be significant to human societies.” 213 I n 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. T he 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:

E nergy 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 CO 2 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: ”*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 185 of 1544 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 change 220 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 SO 2 to address acid rain. Deleted: F*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 186 of 1544 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 announce d 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 Protocol 222 , 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 187 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 188 of 1544 (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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 189 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 190 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 191 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 192 of 1544 pollution which cause s or contribute s 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:

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 193 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 194 of 1544

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 emissionstandards 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 195 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 196 of 1544

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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 197 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 198 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 199 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 200 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 201 of 1544

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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 202 of 1544 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 SO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 203 of 1544 performance standards for SO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 204 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 205 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 206 of 1544

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 country 275 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 207 of 1544 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. ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 208 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 209 of 1544 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 CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 210 of 1544 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 CO 2 emissions. Doing so results in a broader, forward-thinking approach to the design of programs to yield critical CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 211 of 1544 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 CO 2 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 electricgenerating units (EGUs). Specifically, the EPA proposed ratebased goals for carbon dioxide (CO 2 ) 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 EPApublished a supplemental proposal that proposed emission ratebased goals for CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 212 of 1544 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 CO 2 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 CO 2 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 CO 2 goal to total metric tons of CO 2 (a mass-based equivalent).

K . Stakeholder Outreach and Consultations Deleted: J*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 213 of 1544 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 PollutionStandards, 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 intothe 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 214 of 1544 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 areavailable at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 215 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 216 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 217 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 218 of 1544 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 th is 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 Deleted: e Clean Power Plan*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 219 of 1544 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 220 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 221 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 222 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 223 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 224 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 225 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 226 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 227 of 1544 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 CO 2 , 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 228 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 229 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 230 of 1544 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 CO 2 goal , through December 1, 2014. The EPA offered a separate 45-day comment period for Deleted: K*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 231 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 232 of 1544 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 233 of 1544 performance-based approach to establishing emission guidelines for affected sources and applying the BSER to two sourcesubcategories of existing fossil fuel-fired EGUs -- fossil fuelfired electric utility steam generating units and stationarycombustion 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

CO 2 . For stationary combustion turbines, we are finalizing a performance rate of 7 71 lb/MWh of CO 2 . The EPA has also translated the source subcategory-specific CO 2 emissionperformance rates into equivalent statewide rate-based and massbased CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 234 of 1544 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 CO 2 emission performance rates or the state-specific CO 2 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 CO 2 emission performance.

T he 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 235 of 1544 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.

A ffected 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 236 of 1544 into three steps, 2022-2024, 2025-2027, and 2028-2029, each

associated with its own interim CO 2 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 CO 2 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 CO 2 emission goal of 2030 and beyond

• Demonstration that the plan submittal is projected to achieve the state ’ s CO 2 emission goal

• State recordkeeping and reporting requirements

• Certificati o n of hearing on state plan

• Supporting documentation

A lso, 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. E ach state must use the established electronic submittal system to provide the EPA its complete plan submitta l 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 237 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 238 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 239 of 1544 matter, the EPA reasonably interprets the provisions identifying which air pollutants are covered under CAA section 111(d) to authorize the EPA to regulate CO 2 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 CO 2 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 CO 2 emissions for new affected EGUs that the EPA is promulgating concurrently withthis 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 240 of 1544 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 includesoperational 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 241 of 1544 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 environment al impacts orimpose 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 ofsubstituting 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 242 of 1544 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. T he 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 CO 2 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 Deleted: In addition, t*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 243 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 244 of 1544 have deployed or will deploy in the electricity sector that

reduce CO 2 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

CO 2 emission performance rate or state goal by the affected EGUs,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 245 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 246 of 1544 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 (CO 2 ) meets both criteria: (1) it is not a criteria pollutant regulated under section 108 nor a HAP regulated under CAA section 112, and (2)

CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 247 of 1544

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 E xclusion 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, 16029-3 2 (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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 248 of 1544 commenters that had previously endorsed the EPA’s interpretation

of the Section 112 Exclusion in other contexts 292 -- 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. Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 249 of 1544 regulation under CAA section 111(d) of CO 2 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 th e 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. ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 250 of 1544 “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. S ection 111 has two main components. First, section 111(b) requires the EPA to promulgate federal “standards of performance” addressing new Deleted: a

Deleted: CAA s

Deleted: CAA*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 251 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 252 of 1544 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 Deleted: between*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 253 of 1544 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

. T o 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 254 of 1544 cross reference to old section 112(b)(1)(A) with a crossreference to new section 112. Pub. L. No. 101-549, § 302(a), 104Stat. 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 255 of 1544 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 CO 2 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 Deleted: this

Deleted: the EPA from regulating*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 256 of 1544 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) Deleted: ”*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 257 of 1544 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 258 of 1544 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, 101 st 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 259 of 1544 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 a mendment

a. The House a mendment is a mbiguous. Before looking at the specific text of the House amendment, it is helpful to review some principles of statutory interpretation. First, s tatutory 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 260 of 1544 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]: ?*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 261 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 262 of 1544 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 CO 2 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 CO 2 and therefore whether CO 2 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) CO 2 emissions from power plants may be regulated under section 111(d)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 263 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 264 of 1544 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.

I f 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).

T he phrase “regulated under section 112” is ambiguous . A s 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 265 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 266 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 267 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 268 of 1544 short, it is not reasonable to interpret the S ection 112

E xclusion in section 111(d) to mean that the existence of CAA section 112 standards covering hazardous pollutants from asource 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

. T he 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 269 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 270 of 1544

The re are a number of reasons why the EPA’s interpretation

is reasonable and avoid s the issues discussed above. First, the EPA’s interpretation read s 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 further s – rather than

undermine s – the purpose of CAA section 111(d) within the longstanding structure of the CAA. That is, th is interpretation

support s 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 *** Page 271 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 272 of 1544 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, th is interpretation avoid s 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 273 of 1544

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 regulat ion 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 CO 2 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 CO 2 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 CO 2 emissions from affected EGUs concurrently with this CAA*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 276 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 277 of 1544 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)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 278 of 1544 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) emissionguidelines. 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.

F irst, 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 279 of 1544 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 5percent and only provide about 1 percent of the fossil fuelfired generation (GWh). Combustion turbine capacity can therefore only contribute CO 2 emissions amounting to approximately 2 percent of total coal-steam CO 2 emissions. Any single-digit percentage reduction in combustion turbine heat rates would therefore provide less than 1 percent reduction in

total fossil-fired CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 280 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 281 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 282 of 1544 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 CO 2 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 CO 2

306 The EPA is not codifying any of the requirements of this rulemaking in subparts Da or KKKK. Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 283 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 284 of 1544 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 CO 2 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 CO 2 emissions from existing EGUs*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 285 of 1544 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 CO 2 , 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 CO 2 pollution and the unique characteristics of the source category, particularly the exceptional degree of*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 286 of 1544 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 subjectincorporate 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 287 of 1544

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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 288 of 1544 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 CO 2 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 CO 2 emission performance rates as the standard of performance for its affected EGUs. The change

to uniform CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 289 of 1544

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 CO 2 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 CO 2 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 sub categor ies 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 290 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 291 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 292 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 293 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 294 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 295 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 296 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 297 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 298 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 299 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 300 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 301 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 302 of 1544

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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 303 of 1544

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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 304 of 1544 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 SO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 305 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 306 of 1544 (“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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 307 of 1544 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 SO 2 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 SO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 308 of 1544

and industrial sources. By substantially reducing SO 2 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 andenergy 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 309 of 1544 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 310 of 1544

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), i n 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 regulations 350 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 311 of 1544 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 312 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 313 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 314 of 1544 (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.”).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 315 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 316 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 317 of 1544 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 CO 2 -emitting generation. This measure involves two distinct actions: increasing the amount of non-emitting generation and reducing

the amount of CO 2 -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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 318 of 1544 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 CO 2 emission performance rates -- for steam generators and for combustion turbines. States must impose standards of performance on their sources that implement the CO 2 emissions performance rates, or, as an alternative method of compliance, in total, achieve the same emissions performance

level that the CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 319 of 1544 elements, reflect the critical criteria of feasibility, reasonable cost, and other BSER criteria, the BSER assures that there is at least one pathway –- the CO 2 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 CO 2 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’ CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 320 of 1544 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 blocksincorporates 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 321 of 1544 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 incorporatesemissions 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 322 of 1544 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 CO 2 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 323 of 1544 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 SO 2 from new, modified, and reconstructed EGUs. 365 In assessing the

final SO 2 standard, the EPA carried out extensive analyses of a range of alternative SO 2 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 SO 2 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 SO 2 ... 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 SO 2 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 SO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 324 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 325 of 1544 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 CO 2 pollution

. The salient facts include the global nature of CO 2 , which makes the specific location of emission reductions unimportant; the enormous quantities of CO 2 emitted by the utility power sector, coupled with the fact that CO 2 is relatively unreactive, which make CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 326 of 1544 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 t he 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 327 of 1544 management of environmental impacts are also carried out to agreat 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 futuretrends 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 328 of 1544 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 thereplacement 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 329 of 1544 address pollutants other than CO 2 emitted by the power sector. These programs include, among others, the CAA Title IV program

to reduce SO 2 and NO X , the MATS program to reduce mercury and air toxic emissions, and the CSAPR program to reduce SO 2 and NO X . 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 CO 2 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 CO 2 –emitting generating

379 Many of these programs are discussed in section V.B.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 330 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 331 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 332 of 1544 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 333 of 1544 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 thirdcategories, 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 ingeneration 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 CO 2 emissions, would result in increased demand for, and Deleted: in several different ways from the individual-source perspective,

Deleted: source-category perspective.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 334 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 335 of 1544 performance. As part of the EPA’s emission guidelines in this rule, and based on the BSER, the EPA is identifying CO 2 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 CO 2 emission performance rates for those subcategories set in the emission Deleted: represent*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 336 of 1544 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 CO 2 per MWh) or mass limits (e.g., tons of CO 2 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 –-*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 337 of 1544 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’ CO 2 emission rates. As described in the proposal, the measures that the affected EGUs could implement to improve their CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 338 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 339 of 1544 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 CO 2 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 CO 2 emissions that could partially or even entirely offset the CO 2 emission reductions achieved through the reductions in the amount of CO 2 emissions per MWh of generation. Deleted: or other multi-unit compliance

Deleted: source

Deleted: source. Deleted: individual-source perspective of

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 340 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 341 of 1544 power plants throughout the United States and in foreign nations are already using to reduce their CO 2 . 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 342 of 1544 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 CO 2 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 343 of 1544 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 CO 2 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 CO 2 , the EPA turned next to the set of measures that presented themselves as a result of the fact that the*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 344 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 345 of 1544 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 CO 2 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 CO 2 per MWh of generation than steam EGUs Deleted: a source-category perspective,

Deleted: or other multi-unit compliance

Deleted: individual-source perspective of*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 346 of 1544 –- typically less than half as much CO 2 as coal-fired steam EGUs, which account for most generation from steam EGUs –- this generation shift reduces CO 2 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 CO 2 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 issuesupports 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 347 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 348 of 1544 is another method for reducing CO 2 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-CO 2 generation that could replace higher-CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 349 of 1544 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 CO 2 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 CO 2 emissions. However,there are also important differences between these types of lowor zero-CO 2 generation. Investments in new nuclear capacity are very large, “lumpy,” capital-intensive investments and the*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 350 of 1544 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

CO 2 emissions from affected EGUs below current levels. Existing nuclear generation helps make existing CO 2 emissions lower than they would otherwise be, but will not further lower CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 351 of 1544 (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 CO 2 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 CO 2 emission reductions achieved through such actions would, on average, be more costly than CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 352 of 1544

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

CO 2 -emitting generating capacity, a consequence that is inconsistent with the long-term need to continue reducing CO 2 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 CO 2 emissions would initially be displaced be the generation from the new NGCC units. The new capacity is likely

to continue to emit CO 2 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 CO 2 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 CO 2 emissions that otherwise would not be created as inconsistent Deleted: In addition, we note that unlike*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 353 of 1544 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 CO 2 emissions would be subject to the CO 2 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 CO 2 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 CO 2 -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 CO 2 -emitting units at the expense of new zero- e mitting units, increasing overall emissions within a state. This effect would be exacerbated if state plans allowednew 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 und u e pressure on natural gas prices; and could create unfair disparities in the compliance opportunities afforded different states. ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 354 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 355 of 1544 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 CO 2 emission performance rate quantified for a given source subcategory for*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 356 of 1544 any of the three major Interconnections as the CO 2 emission performance rate for that source subcategory in all three

Interconnections 386 –- provides additional headroom within the

BSER for sources in the two Interconnections that did not set

the CO 2 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 andstakeholders 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 357 of 1544 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 CO 2 -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 CO 2 from affected EGUs. In addition, the EPA has relied on the measures in building blocks 2 and 3 in other rules.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 358 of 1544 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 CO 2 emission rate at the unit. An affected EGU may take steps to improve its CO 2 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 CO 2 emissions. The resulting improvement in an EGU’s CO 2 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

- s ource 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- f ired 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 *** Page 359 of 1544 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 incentiviz e 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

- s ource

Deleted: ing*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 360 of 1544 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 CO 2 -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 CO 2 - reducing effects of that increased generation. Alternatively, an owner/operator may, through bilateral transactions, purchase the

CO 2 -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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 361 of 1544 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 CO 2 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 SO 2 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 W hen 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 *** Page 362 of 1544 a liquid SO 2 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 (July2015), 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 *** Page 363 of 1544

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 CO 2 emission performance rates reflecting application of the BSER. In addition, if emission limits are set

at the CO 2 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 *** Page 364 of 1544 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 *** Page 365 of 1544 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 366 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 367 of 1544 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 ofthe 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 *** Page 368 of 1544 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 emission s trading. In making its BSER determination here, the EPA examined a number of technologies

and emissions reduction measures that result in lower levels of

CO 2 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., CO 2 ; (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-basedemission allowances) but include other multiunit compliance approaches that reflect the global nature of the CO 2 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 abilityfor 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 a p proaches 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 *** Page 369 of 1544 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 *** Page 370 of 1544

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 whichallow 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: ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 371 of 1544 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, investin 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 *** Page 372 of 1544 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 *** Page 373 of 1544 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 CO 2 is a global pollutant; the

location of its emission does not affect the location of the

environmental harm it causes. For CO 2 , 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 CO 2 pollution. In its character as a pollutant whose impacts extend beyond local areas, CO 2 pollution resembles to some extent the regional SO 2 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 CO 2 pollution, whose adverse*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 374 of 1544 effects are global rather than merely regional like the SO 2 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 375 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 376 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 377 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 378 of 1544 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 NO X SIP Call (currently referred to as the

NO X 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 379 of 1544 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 (CO 2 Deleted: the background

Deleted: credits*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 380 of 1544 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 CO 2 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 largerregions, 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 tocompliance. 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 381 of 1544 g. Measures that reduce CO 2 emissions or CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 382 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 383 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 384 of 1544 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 *** Page 385 of 1544

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 CO 2 emission reductions from 2005 levels of 29% in 2025 and 30% in 2030. For the final rule, the EPA projects total CO 2 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 *** Page 386 of 1544 the highest 2012 CO 2 emission rates and less stringent in states

with lower 2012 CO 2 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 CO 2 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 *** Page 387 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 388 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 389 of 1544 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 affectedEGUs 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 390 of 1544 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 CO 2 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 CO 2 emissions lower than they would otherwise be. Deleted: sources.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 391 of 1544 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-CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 392 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 393 of 1544 compliance as discussed below and in section VIII, will recognize the CO 2 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 CO 2 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 *** Page 394 of 1544 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 CO 2 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 CO 2 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 CO 2 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 othe r 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 *** Page 395 of 1544 sector and strongly supported the inclusion of such measures in

the BSER , other commenter s 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 heatrate 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 CO 2 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 werequested 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 CO 2 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 CO 2 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.) , CO 2 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 CO 2 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 plannedand 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 CO 2 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 CO 2 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 athttp://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),*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 1544and 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. 423 NREL, 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 transmissionconstraint 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 CO 2 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 CO 2 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 77 1 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 CO 2 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 CO 2 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 *** Page 416 of 1544 in the BSER to potentially serve as the basis for CO 2 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 CO 2 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 CO 2 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 CO 2 emission performance rate. Through the use of a

common CO 2 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, u sing the least stringent rate provide s 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 nation wide

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 CO 2 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 represent s 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 emission performance rate for NGCC units and

the CO 2 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 country 428 located in each of the three I nterconnections

are shown in the CO 2 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 Guam 429 –- 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 Guam 427 –- 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 isolate d 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 thatsources are able to replace coal-fired generation with naturalgas fired generation and add incremental amounts of renewableenergy (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 *** Page 426 of 1544

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

CO 2 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 *** Page 427 of 1544

 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 428 of 1544 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 CO 2 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 CO 2 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 CO 2 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 thenationwide rates, the state- or territoryspecific performance rates are used instead.)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 430 of 1544 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 CO 2 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 EGUs 432 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 CO 2 emissions with respect to generation. The EPA has analyzed the technical feasibility, costs, and magnitude of CO 2 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 CO 2 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 ofaffected 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 CO 2 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 CO 2 emissions (depending on the CO 2 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 CO 2 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 CO 2 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 CO 2 emissionsat, 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 435 of 1544 The EPA’s analysis and conclusions regarding the technical feasibility, costs, and magnitude of CO 2 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 byextensive 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 ofits 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 436 of 1544 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 ofemission 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 promote s 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 *** Page 440 of 1544 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 CO 2 emissions, while other affected EGUs –- NGCC units –- would increase their generation and CO 2 emissions. However, because for each MWh of generation, NGCC units produce fewer CO 2 emissions than coal-fired steam EGUs, the total quantity of CO 2 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 CO 2 emissions, where location is not a consideration, in contrast with other pollutants, a measure that takes advantage of that integration to reduce CO 2 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 *** Page 441 of 1544 the meaning of a “system of emission reduction” for CO 2 emissions

at affected EGUs even if the measure would increase CO 2 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 CO 2 as well as other pollutants, as discussed above.

c. Building block 3. Building block 3 –- reducing CO 2 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 *** Page 442 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 *** Page 445 of 1544 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 *** Page 446 of 1544 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 CO 2 emissions from affected EGUs at a reasonable cost; it also performs wellagainst the other BSER factors; and its components are wellestablished. The combination of the three building blocks will achieve greater CO 2 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

CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 *** Page 449 of 1544 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 EGUsconsistent 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 *** Page 450 of 1544 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 *** Page 451 of 1544 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- o r 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 *** Page 452 of 1544 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 CO 2 emission reductions achievable through heat rate improvements is low enough that the cost per ton of CO 2 emission reductions will remain reasonable even if

that cost is substantially increased. Second, although under aBSER 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 CO 2 emissions per unit of generation produces a smaller reduction in CO 2 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 CO 2 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 *** Page 453 of 1544 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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 CO 2 reductions through increased RE deployment. 438 Applying building blocks 2 and 3 together produces significantly

more CO 2 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 *** Page 455 of 1544 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 CO 2 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 CO 2 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 *** Page 456 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 457 of 1544 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 areconsidered 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 *** Page 458 of 1544

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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 460 of 1544 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 *** Page 461 of 1544 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 ofaffected 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 462 of 1544 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 77 1 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 463 of 1544 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)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 464 of 1544 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 *** Page 465 of 1544 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 CO 2 emissions through reductions in the quantity of generation rather than through reductions in the amount of CO 2 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 *** Page 466 of 1544 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 CO 2 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 *** Page 467 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 468 of 1544 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 CO 2 emissions associated with that qualifying generation –- is adequately monitored and that there is an adequateadministrative 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 CO 2 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 CO 2 emission rates, but their CO 2 emission rates are lower than the CO 2 e mission 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. ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 469 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 470 of 1544 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 CO 2 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. ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 471 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 472 of 1544 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

invest ment 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 473 of 1544 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 b e 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 474 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 475 of 1544 (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 CO 2 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 476 of 1544 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 invest ment 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 477 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 478 of 1544 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 measuresthat 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 479 of 1544

consistent with the BSER. The non-BSER measures either reduce

the amount of CO 2 emitted per MWh of generation from the set of affected EGUs or reduce the amount of generation, and therefore

associated CO 2 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

CO 2 emitted per MWh of generation at an affected EGU will reduce

the amount of CO 2 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 CO 2 emission rate but rather facilitate reductions in CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 480 of 1544 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 CO 2 emitted per MWh of generation,

and the second set discussed includes measures that can reduce

CO 2 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 481 of 1544 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 CO 2 emissions per MWh generated. In the June 2014 proposal, the EPA discussed several potential

measures that could reduce CO 2 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 482 of 1544 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 CO 2 reductions available from heat rate improvements at coal-fired steam EGUs are much larger than the potential CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 483 of 1544 Another approach for reducing CO 2 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 CO 2 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. CO 2 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 CO 2 emissions at an individual affected EGU by switching fuels at*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 484 of 1544 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 CO 2 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, CO 2 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 certaincircumstances, 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 485 of 1544 or cannot be completed quickly. CO 2 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 486 of 1544 feasible the potential CO 2 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 CO 2 emissions by reducing fossil fuel-fired generation. A second group of non-BSER measures has the potential to reduce CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 487 of 1544 this nature to help the source category as a whole and individual affected EGUs achieve their emission limits, because

the CO 2 -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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 488 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 489 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 490 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 491 of 1544 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 CO 2 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 CO 2 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 *** Page 492 of 1544 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 CO 2 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 CO 2 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 onsustainably-derived agriculture- and forestderived feedstocks may also be an approvable element of their state pl a ns. 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. B ecause it is likely that more than one MWh of incremental generation from these technologies would be required as the basis qualifying for theissuance 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 numb e r 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 493 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 494 of 1544 demonstrated means of reducing CO 2 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 CO 2 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 CO 2 emission reductions.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 495 of 1544 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 CO 2 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 496 of 1544 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 CO 2 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 497 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 498 of 1544

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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 499 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 500 of 1544 “adequately demonstrated.” B y 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 t hat 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 501 of 1544 “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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 502 of 1544

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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 503 of 1544 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];*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 504 of 1544 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 welfare 464 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, o ur 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 505 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 506 of 1544

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 ofPerformance 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 ofPerformance 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 507 of 1544 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 state s 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 508 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 509 of 1544 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 ,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 510 of 1544

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 CAAsection 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 511 of 1544 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

CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 512 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 513 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 514 of 1544 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” serve s 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 515 of 1544 Although a “system of emission reduction” lays the groundwork for CAA section 111 standards, t he 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 516 of 1544 “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,

u nder 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 517 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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).

A lthough 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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]*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 521 of 1544 “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

. ” A s 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 522 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 523 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 524 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 525 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 528 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 529 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 530 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 531 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 532 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 533 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 534 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 535 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 536 of 1544 treatment reduces the amount of sulfur in the fuel, which means

that the fuel can be combusted with fewer SO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 537 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 538 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 539 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 540 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 541 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 542 of 1544 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

th re e building blocks

. Moreover, as discussed, the measures in building blocks 2 and 3 are highly effective in achieving CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 543 of 1544 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 inherentlylowemitting 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 NO x emission limits for certain types of boilers “on the degree of*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 c ommenters 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 545 of 1544 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) NO x 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 546 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 547 of 1544 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 b uildings, 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 548 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 549 of 1544

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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 550 of 1544 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., SO 2 and NO x ) 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 551 of 1544

c. D eference to interpret the BSER to include building blocks 2

and 3. T o 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 reasonable 524 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 552 of 1544 Specifically, the utility power sector is characterized by physical, as well as operational, interconnection s 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 553 of 1544 Congress, 526 the Courts, 527 the EPA in its regulatory actions, 528 and states in their regulatory actions 529 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 554 of 1544 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 orcause the generation of increased amounts of lower- or zeroemitting electricity –- through contractual arrangements,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 555 of 1544 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 CO 2 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 CO 2 . 530 In light of these characteristics of the utility power sector, as well as the characteristics of CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 556 of 1544 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 CO 2 reduction measures that are either more expensivethan 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 CO 2 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 issue s . 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 557 of 1544 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 tomeet operational and environmental objectives in a costeffective manner, as further described below. CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 558 of 1544 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 CO 2 emissions 532 – - 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!/.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 559 of 1544 measures should be considered part of a “system of emission

reduction” for CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 560 of 1544 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, whichincludes 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 561 of 1544 “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 SO 2 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 SO 2 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 SO 2 in 1985).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 562 of 1544 industrial sources were not required to participate under Title IV -- they could elect to do so, under CAA section 410(a) -- Congress believed SO 2 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 SO 2 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 SO 2 emissions from existing sources because of the pollutant exclusions in CAA section 111(d).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 563 of 1544

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 SO 2 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 CO 2 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 –*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 564 of 1544

* * * * (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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 CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 566 of 1544 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 SO 2 emissions through a set of measures, including shifting to lower-emitting generation as well as reliance on renewable energy. For example, the Senate Committee Report 541 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 567 of 1544 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.”).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 568 of 1544 record for the 1970 CAA Amendments include hearings 545 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 569 of 1544 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 identifiedreductions 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 100 th Congress, Sen. Rep. No. 101-138, at 5 (Sept. 1989); “Global Warming Has Begun, Expert Tells Senate,” New York Times, June24, 1988, http://www.nytimes.com/1988/06/24/us/global-warminghas-begun-expert-tells-senate.html.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 570 of 1544 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

CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 571 of 1544 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

NO x and SO 2 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 partbecause 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 SO 2 and NO x 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 572 of 1544 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 unitswas one of the expected control strategies for the fossil fuelfired power plants. Prior to CSAPR, the EPA promulgated two other transport rules, the NO x 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 andencouraged 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); NO x 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). 559 See, 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;*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 573 of 1544 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

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 574 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 575 of 1544 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 NO X SIP Call experience.” Id. at 25217.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 576 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 577 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 578 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 579 of 1544 example, in 1979, the EPA finalized new standards of performance

to limit emissions of SO 2 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 NO x 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 580 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 581 of 1544

(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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 582 of 1544 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: ,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 583 of 1544 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 areas 571 -- 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 584 of 1544 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:

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 585 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 586 of 1544 Much remains to be done with climate change. We are now at a critical juncture to take meaningful action to curb the growth

in CO 2 emissions and forestall the impending consequences of

inaction. CO 2 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 CO 2 as do the next 9 stationary source categories combined, and approximately the

same amount of CO 2 emissions from all of the nation’s mobile sources. The only controls available that can reduce CO 2 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 CO 2 emissions.

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 587 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 588 of 1544 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 589 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 590 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 591 of 1544 creative and come up with innovative solutions to the urgent andsevere 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 592 of 1544 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.

T his 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 593 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 594 of 1544 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 CO 2 ) –- 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 595 of 1544 comment examples cited above are demand-side measures, they are not within the section 111 interpretive paradigm that underlies today’s action. Additionally, u nder 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 596 of 1544 generation processes -- through the cleaner (that is, less CO 2 - 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 597 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 598 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 599 of 1544

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 CO 2 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 toimplement 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 CO 2 from some affected EGUs, and therefore reduce CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 600 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 601 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 602 of 1544 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 determine s 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, determine s 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 thatreduced generation is one of the set of reasonable and wellDeleted: viewing the BSER from either thesource-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 *** Page 603 of 1544

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

CO 2 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 604 of 1544 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 withenvironmental 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 605 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 606 of 1544 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 theallowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 607 of 1544

with the SO 2 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 SO 2 reduction obligations and the NO x 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 608 of 1544 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 NO X 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 609 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 610 of 1544 “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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 611 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 612 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 613 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 614 of 1544 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]*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 615 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 616 of 1544 primarily” on reduced utilization as the BSER. Rather, the BSERis, 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 617 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 618 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 619 of 1544

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 CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 620 of 1544 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 CO 2 emission performance rate for steam-generating EGUs and a uniform CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 621 of 1544 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, rangingfrom -- 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 622 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 623 of 1544 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 theemission 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 624 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 625 of 1544 because those forms of generation would see their competitive positions improved. This basic fact that the EPA regulations of air pollutantsfrom 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 CO 2 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

CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 626 of 1544 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 jobthan individual district judges issuing ad hoc, caseby-case injunctions. 615

615 American Electric Power v. Connecticut , 131 S. Ct. 2527, 2539-40 (2011).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 627 of 1544 Similarly, the D.C. Circuit, in its 1981 decision upholding the

EPA’s rules to reduce SO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 628 of 1544 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 CO 2 emissions from affected EGUs, the EPA first considered more traditional air pollution control measures, including supply-side efficiency improvements, fuel-switching (for CO 2 emissions, that entails cofiring with natural gas), and add-on controls (for CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 629 of 1544

EPA could have finalized those controls as the BSER 618 and

established the same uniform CO 2 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.”).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 630 of 1544 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-firedgeneration. 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 631 of 1544 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 CO 2 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 632 of 1544 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 jurisdiction 621 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: –-*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 633 of 1544 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. Infact, 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 *** Page 636 of 1544

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. CO 2 /MWh net.) Deleted: The emission rate for existing NGCC units over the 2022- 2 030 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 E conomic I ncentive P rograms 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

CO 2 /MWh gross, which equates to 1,030 lb CO 2 /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. CO 2 /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. CO 2 /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. CO 2 /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. CO 2 /MWh gross is designed to

constrain. 627 As a result, the 1,000 lb. CO 2 /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 tosubcategorize 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 CO 2 emissions

at affected fossil fuel-fired EGUs consists of measures thatreduce 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 CO 2 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 CO 2 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 *** Page 642 of 1544 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 rateimprovement 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 equipmentupgrades, such as turbine overhauls) are possible at many coalfired EGUs, as supported by numerous commenters, the Sargent & Lundy study 632 (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 CO 2 emission rate. As in the proposal, we used more than one analytical method to evaluate the opportunity for EGUs to reduce their CO 2 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 ( o F) range in ambient temperature (from -20 o F to greater than 110 o F), and a 10-percent range in capacity factor (from 0 percent to greater than 110 percent 634 ). 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 70 o F and 79 o F. 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 651 of 1544 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 652 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 653 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 654 of 1544 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***** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 655 of 1544

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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 656 of 1544 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 CO 2 emission performance rate.

Those affected EGUs that have done the most to reduce their heat

rate will tend to be closer to that CO 2 emission rate. In this sense, our approach to determining potential CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 657 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 658 of 1544 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 CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 659 of 1544 and rate-based state goals. Each state has the flexibility to develop a plan that achieves those CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 660 of 1544 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 CO 2 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 thenature 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 661 of 1544 2. Costs of heat rate improvements By definition, any heat rate improvement made by EGUs for the purpose of reducing CO 2 emissions will also reduce the amount of fuel that EGUs consume to produce the same electricity output. The cost attributable to CO 2 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 CO 2 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 CO 2 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 CO 2 emission reductions from heat rate improvements would be offset Deleted: the Deleted: majority*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 662 of 1544 by fuel savings, and that the net costs of implementing heat rate improvements as an approach to reducing CO 2 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 CO 2 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 2.3percent 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 include d 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 663 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 664 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 665 of 1544 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 CO 2 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 666 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 667 of 1544 (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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 668 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 669 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 670 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 671 of 1544 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 CO 2 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, t he 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 672 of 1544 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 673 of 1544 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 CO 2 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 withcommenters 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 nationwideanalysis and commenters’ suggested statespecific analysis, which does not fully reflect the interconnected nature of the system within which affected coal-fired EGUs operate.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 674 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 675 of 1544 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’sdatabase 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 676 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 677 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 678 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 679 of 1544 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 CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 680 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 681 of 1544

lower CO 2 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 toevaluate 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 682 of 1544 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 CO 2 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 CO 2 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 683 of 1544 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 CO 2 reductions.

1. Demonstration of a bility to r educe CO 2 e missions through

s hifting g eneration 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: ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 684 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 685 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 686 of 1544 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 CO 2 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 687 of 1544 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 688 of 1544 (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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 689 of 1544 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 incorporateemissions 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 690 of 1544 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 itis 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 Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 691 of 1544 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

M any 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 692 of 1544 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. Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 693 of 1544 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 besupplied 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:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 694 of 1544 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:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 695 of 1544 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 Deleted:

Deleted:

Deleted:

Deleted:

Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 696 of 1544 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 Deleted:

Deleted:

Deleted: ¶ Deleted: be

Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 697 of 1544 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 g eneration s hift 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. Deleted:

Deleted: ¶

Deleted: ¶ ¶ ¶ ¶

Deleted:

Deleted: G Deleted: S*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 698 of 1544 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 CO 2 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 CO 2 emissions from fossil fuel-fired units associated with other measures, such as increased utilization of Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 699 of 1544 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) Deleted: ¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 700 of 1544 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. Deleted: between now and

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 701 of 1544 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 Deleted: 987 Deleted: 734 Deleted: 896 Deleted: 941 Deleted: 987 Deleted: 987 Deleted: 987 Deleted: 987 Deleted: 987 Deleted: 987 Deleted: 987*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 702 of 1544

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 m agnitude of g eneration s hift 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 CO 2 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 Deleted: 306 Deleted: 198 Deleted: 242 Deleted: 254 Deleted: 267 Deleted: 280 Deleted: 294 Deleted: 306 Deleted: 306 Deleted: 306 Deleted: 306 Deleted: 204 Deleted: 137 Deleted: 167 Deleted: 176 Deleted: 185 Deleted: 194 Deleted: 203 Deleted: 204 Deleted: 204 Deleted: 204 Deleted: 204 Deleted: 2. Deleted: M Deleted: G Deleted: S Deleted: ¶

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 703 of 1544 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. Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 704 of 1544 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. Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 705 of 1544 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, Deleted:

Deleted:

Deleted: ,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 706 of 1544 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).*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** 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, CO 2 Emission Performance Rate and Goal Computation Technical Support Document for CPP Final Rule

. 671 Appendix 1, CO 2 Emission Performance Rate and Goal Computation Technical Support Document for CPP Final Rule

. Deleted:

Deleted:

Deleted:

Deleted:

Deleted: 967

Deleted:

Deleted: 497*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 708 of 1544 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 Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 709 of 1544 while achieving emission reductions through a variety of

measures. 672

d. Natural g as i nfrastructure. 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). Deleted: G Deleted: I Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 710 of 1544 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 711 of 1544 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. Deleted: Similarly, the electric transmission system is undergoing substantial expansion. 678*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 712 of 1544 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 g as p roduction. 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 Deleted: , and the electric transmission system can reliably accommodate changed generation patterns,

Deleted: G Deleted: P Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 713 of 1544 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 Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 714 of 1544 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 Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 715 of 1544 average utilization rate of existing NGCC units to 75 percent would be technically feasible.

f. Transmission p lanning and c onstruction. 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. Deleted: P Deleted: C Deleted:

Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 716 of 1544 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 f lexibility. 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. Deleted:

Deleted:

Deleted: ¶ Deleted: F Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 717 of 1544 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 CO 2 emissions reduction strategy, we next turn to the question of cost. The cost of the power sector CO 2 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 718 of 1544 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 CO 2 emission reductions through generation shifting within defined areas (consistent with the applicationof 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 incentivesto 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 719 of 1544 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 CO 2 reductions achieved over the 2022-2030 period was $ 24 per short

ton of CO 2 . 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 Deleted: 27 Deleted: metric*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 720 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 721 of 1544 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 Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 722 of 1544 do not consider states’ and sources’ flexibility to choose among

alternative CO 2 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 NGCCunits 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 c omments and r esponses 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 CO 2 emissions from flaring of methane will likely Deleted: X

Deleted: C Deleted: R

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 723 of 1544 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 Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 724 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 725 of 1544 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 Deleted:

Deleted:

Deleted:

Deleted:

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 726 of 1544

The third element of the foundation for the EPA’s BSER determination for reducing CO 2 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 Deleted: solar*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 727 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 728 of 1544 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. Deleted: have*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 729 of 1544 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). Deleted: MW

Deleted: (MW)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 730 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 731 of 1544 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 732 of 1544 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 CO 2 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 CO 2 reductions. California cited the reduction of CO 2 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.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 733 of 1544 50 percent by 2030). 703 A recent IPCC report also concluded that RE has large potential to mitigate CO 2 emissions. 704 Increased use of RE provides numerous benefits in addition

to lower CO 2 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 CO 2 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. Availableat: http://www.epa.gov/cleanenergy/energy-and-you/affect/waterresource.html.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 734 of 1544 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 CO 2 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. Deleted:

. Deleted:

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 735 of 1544 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. Deleted: MW

Deleted: MW

Deleted: MW*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 736 of 1544

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) R enewable 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. Deleted: MW Deleted: MW

Deleted: **7**

Deleted: Basin Electric Power Cooperative ... [14]*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 737 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 738 of 1544

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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 739 of 1544 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 CO 2 emissions from its fleet by 50 percent by 2030 (from a 2014 baseline). 717 NRG has already reduced CO 2 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].*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 740 of 1544 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).¶*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 741 of 1544 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). Availableonline 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)*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 742 of 1544 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 CO 2 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. Deleted: ¶ ¶

Deleted: ,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 743 of 1544 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,*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 744 of 1544 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 a lternative Deleted: technical potential limiter

Deleted:

.

Deleted:

.

Deleted: A*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 745 of 1544 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) thatcomplicate 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), contributesno generation to building block 3 under this historicallybased methodology

. These RE technologies are consequently reserved for compliance, which offers affected EGUs Deleted:

.

Deleted:

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 746 of 1544 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

i t 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 CO 2 emission performance rates. For additional information on the goal setting methodology refer to Section VI. Deleted: potential of the RE technologies considered

Deleted:

.

Deleted: I

Deleted: its Deleted: s Deleted: are*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 747 of 1544 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 Berk e ley National Lab oratory , 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- s cale solar technologies were reevaluated.

Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 748 of 1544 the development of RE technology cost and performance trends. In performing this task, t he EPA revised its datafor 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 a s 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 Deleted: limiter

Deleted: observed

Deleted: technical potential limiter Deleted: this feature*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 749 of 1544 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 Deleted:

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 *** Page 750 of 1544

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 F ive-Year Average Capacity Change (MW) Generation Associated with Five Year-Average Capacity Change (MWh) Maximum Annual Capacity Change (MW) G eneration Associated with Maximum Annual Capacity Change (MWh)UtilityScale Solar PV 725 2 0.7 % 1,927 3,494,268 3,934 7,133,601 CSP 34.3 % 251 754,175 767 2,304,590 Onshore Wind 4 1.8 % 6,200 22,702,416 13,131 48,081,520

725 Capacity values for utility-scale solar PV are expressed in terms of MW DC . 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 751 of 1544

Geothermal 85 .0 % 14 2 1,057,332 407 3,030,522 Hydropower 6 3.8 % 1 41 788,032 294 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

consider ing 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 21 3 , 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*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 752 of 1544 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 isappropriate 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 33 2 , 869 , 933 megawatt-hours (aggregated across all three BSER regions); by 2030, that generation level is 7 06 , 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:

.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 753 of 1544 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. Deleted:*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review *** Page 754 of 1544 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

. Theseintegration 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 additionalinformation 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:

.