From: Vasu, Amy Sent: Friday, July 10, 2015 2:38 PM To: Frey, Nathan J. Cc: Szabo, Aaron; Culligan, Kevin; Harvey, Reid Subject: Supporting documents for Interagency Review of the Clean Power Plan Final Rule

Nathan,
I have attached the following three files for interagency review: 1. CO 2 Emission Performance Rate and State Goals TSD 2. Spreadsheet with Appendices 1-5 of the CO 2 Emission Performance Rate and State Goals TSD 3. Appendix 3A of the RIA (missing from earlier send)

Please let me know if you have any questions about these.

Thank you.

Amy

~~~~~~~~~~~~~~~~~~~~~~~ Amy B. Vasu U.S. EPA / OAQPS Sector Policies and Programs Division email: vasu.amy@epa.gov phone: 919.541.0107

<< CO2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule.pdf >> << Baseline, Category-specific rates, and State Goal Quantification (Draft OMB version 7- 10).xlsx >> << ch3a_upstream_methane.docx >>Technical Support Document (TSD) for the CAA Section 111(d) Emission Guidelines for Existing Power Plants

Docket ID No. EPA

- HQ

- OAR

- 20 13

- 0602



# CO 2 

# Emission Performance Rate and Goal Computation Technical Support Document for CPP Final Rule

U.S Environmental Protection Agency

Office of Air and Radiation

August 201 5Still Under Agency Review

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2

Category

- Specific Performance Rates and State G oal Setting under 111(d)

This Technical Support Document (TSD) provides information that supports the EPA’s determination of category

- specific performance rates for fossil steam and stationary combustion turbine technology categories as well as the state emission rate and mass goals that encompass the likely affected fossil units in a state. 1 Section VI of the preamble discusses the category

- specific performance rates more broadly along with some of the changes made between proposal and final based on comment. Section VII of the preamble describes the expression of t he category

- specific performance standards through a state goal metric reflecting likely covered fossil sources in a state. The Greenhouse G as ( GHG ) Mitigation Measures TSD for CPP Final Rule explains the technical basis for the development of the Best System of Emission Reductions (BSER) that inform the category

- specific performance rates and the subsequent state goals

. This TSD provides d etailed explanation of the data and the BSER

- based calculations used to determine the category

- specific performance rates and state goals The TSD is organized as follows:

1. BSER f

actors i nforming the c ategory

- specific p erformance r ates and state e mission r ate g oal s

a. Block 1

- Heat rate improvement in the coal steam fleet b. Block 2

- Substitute increased generation from lower emitting existing NGCC units for reduced generation from higher emitting fossil steam EGUs

c. Block 3

- Substitute generation from new zero emitting renewable energy (RE) generating capacity for reduced generation f rom higher emitting foss il EGUs 2. Form of the Category

- specific Performance Rates and State Goals 3. Baseline d ata u sed to d erive p erformance r ates and s tate g oals

a. Emissions & G eneration Int egrated Resource Database (eGRID ) b. Data sources for affected “ under construction ” units

c. Region

- level baseline 4. Methodology for d etermining c ategory

- specific p erformance r ate s 5. Methodology for c onverting c ategory

- specific p erformance r ates into s tate emission rate g oals 6. Methodology for converting state emission rate goals in to mass goals 7. Appendix (attached Excel Workbook)

 Appendix 1

– Underlying 2012 unit

- level baseline inventory and data

 Appendix 2

- Units that commence d operation post 2011 , but commenced construction prior to 1/8 /14

 A ppendix 3

– Underlying state

- level data, adjustments, and region

- level data

 Appendix 4

– Computation of the c ategory

- specific p erformance rates (Interim and Final)

 Appendix 5

- Computation of the State Goal (Interim and Final)

 Appendix 6

– State goal summary table

 Appendix 7

– Calculation for generation adjus tment in hydro

- intensive states

 Appendix 8

- Category

- specific emission rates reflecting BB severability

 Appendix 9

– Description of 111(d) baseline data sources and development

1 The only gas units currently considered likely affected units under the 111(d) applicability criteria are turbines at NGCC units (both the gas and steam turbines). The remainder of the document will use the term “NGCC” to collectively refer to the output from both the steam and gas turbines at a NGCC unit.Still Under Agency Review

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3

In EPA’s technical evaluation, it assessed the cost and potential o f each GHG reducing technology were identified (see GHG Mitigation Measures TSD). EPA relied on a similar building block structure as proposed, but revised the quantification of those building blocks based on comments. These revised building b locks levels were used to derive the category

- specific performance rates provided in this final rule. The category

- specific performance rates were then used to derive the state rate and mass goals.

1. BSER Factors Informing the Category

- specific Performance R ates and State Emission Rate Goals

The GHG Mitigation Measures TSD describes three categories of emission reduction measures (building blocks) used in determining the category

- specific performance rates . That document describes EPA’s historic al data review and analysis underlying each technology and informing EPA’s assessment of its feasibility and cost

- effectiveness as part of a BSER

. It also explains how EPA made adjustments to the building blocks based on comments The technology estimates d etermined through EPA’s analysis and documented in the GHG Mitigation Measures TSD are summarized below

.

Figure 1. 2030 Building Block Potential Identified for Each Region

BB1

- HRI Improvement for coal fleet BB2

- TWh o f total NGCC

Generation at 75% U tilization, (Amount of NGCC Generation Potential Incremental to Baseline) BB3

- Incremental RE Potential (TWh)
Eastern Interconnection 4.3% 98 8 , (253) 438
Western Interconnection 2.1% 306, (108) 1 6 1
Texas Interconnection 2.3% 204, (67) 107 *Totals are building block potential only. As evidenced in Section 4

- step 8, not all of the building block potential is utilized in establishing BSER category

- specific rates and state goals.

The building block data shown above are used to determine category

- speci fic performance rate s expressed in a lb/MWh rate

. As these building blocks reflect both fossil and non

- fossil measures, the corresponding category

- specific performance rates also reflect fossil and non

- fossil generation through the use of an adjusted emi ssion rate described in the preamble and below

.

2. Form of the Category

- specific Performance Rates and State Goals

As described in Section VI of the preamble, EPA is promulgating a separate emission rate that quantifies BSER for each technology category covered under 111(d) applicability . Therefore, while similar adjustments are made to the generation levels of affected fossil steam and NGCC generation reflecting the building blocks , the adjustments are made and expressed at the technology leve l rather than the combined affected source level:Still Under Agency Review

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Exhibit A

- Simplified formula demonstrating category

- specific emission performance rates

Final

– Affected fossil steam and NGCC Generation treated separately for quantifying BSER

BSER for Fossil Steam = BSER a djusted emissions for affected fossil steam source s BSER a djusted g eneration for affected fossil steam sources + replacement generation

BSER for NGCC = BSER a djusted emissions for affected NGCC sources BSER a djusted g eneration for affected NGCC sources + replacement generation

3. Baseline Data Used to Derive Performance Rates and State Goals

See Section VI.D.2 of the Preamble for a description of EPA’s identification of a baseline data

Adjustments that the EPA made to the 2012 historical data
EPA received sign ificant comments regarding unit

- level d ata and a pplicability status. It has reviewed these comments and updated its 2012 unit

- level data accordingly to better reflect unit

- level operation in that year and unit

- level applic ability status . The updated unit

- level data is available in Appendix One and reflects changes to unit data based on comment s

.
In addition to unit

- level data updates, the EPA also made some targeted baseline adjustments at the state

level to address commenter concerns about the representativeness of baseline year

- data , even where correctly reported . These are highlighted below, but discussed in more detail in the Preamble Section VI.

State

- level adjustments:

 EPA adjusted affected fossil baseline generation upwards in states with large hydro generation portfoli os (adjustment calculations in a ppendix 7 and applied in appendix 3 )

.
 EPA adjusted state

- level generation upwards in cases where a significant portion of the generation portfolio was off line for maintenance (adjustment calculations in appendix 7 and applied in appendix 3)

.
 EPA adjusted state

- level generation upwards to reflect under construction fossil steam and NGCC capacity operating at expected technology

- class levels (including units comm encing operation in 2012)

. (List of units available in appendix 2 and adjustment applied in appendix 3).
Once these adjustments were calculated, EPA summed the baseline data described above at the state and regional

- level for the following categories. These totals reflect the baseline from which the performance rates and state goals are assessed.

- State and regional

- level coal steam generation

- State and regional

- level coal steam emission s

- State and regional

- level oil/gas steam generation

- State and reg ional

- level oil/gas steam emission s

- State and regional

- level NGCC generation

- State and regional

- level NGCC emission s

- State and regional

- level NGCC capacityStill Under Agency Review

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5

All generation values are expressed as net generation. Emission rate values are net emission rate s and expressed as lbs/MWh. The NGCC capacity expressed i s net summertime capacity in m egawatts

. At proposal, there was a limited number of high utilization combustion turbines and i ntegrated gasification combined cycle units ( IGCCs ) determined to be likely affected by 111(d) and placed in a separate “other” category when calculating state goals . In this final rule, the applicability language has been revised , and EPA’s current assessment has not identified any simple

- cycle combustio n turbines that are likely affected units under this rule . The IGCC s that are likely affected by the r ule are included with the coal steam totals consistent with their fuel use and reporting under subpart Da

.

a. Emissions & Generation Integrated Resource Da tabase (eGRID)

eGRID is an inventory of environmental attributes of the U.S. electric power system. It is a comprehensive source of air emissions data for the electric power sector, based on available plant

- specific data for all U.S. electricity generating plants that provide power to the electric grid and report data to the U.S. government. eGRID i ntegrates many different da ta sources on power plants and power companies, including, but not limited to: the EPA, the Energy Information Administration (EIA), the North American Electric Reliability Corporation (NERC), and the Federal Energy Regulatory Commission (FERC). Emissions data from the EPA are carefully integrated with generation data from EIA to produce useful values like pounds per megawatt

- hour (lb/MWh) of emissions, which allows direct comparison of the environmental attributes of electricity generation. EPA applied its eGRID methodo logy for matching the publicly available and reported 2012 emissions and generation data. The EPA relies on this most recent data to calculate category

- specific performance rates and state goals

.

The s tate and region

- level totals for each technology category described in the above bullets are intended to reflect the baseline totals for electric generating units (EGUs) that likely meet the applicability criteria as described in Preamble Section IV.D. 2

i. b. Data sources for under construction units

At proposal, EPA relied on its National Electric Energy Data System (NEEDS). NEEDS includes b asic geographic, operating, capacity, and other data on existing or under construction generating units. NEEDS was updated for EPA's new power sector modeling platform v.5.1 5 reflecting some of the unit

level information EPA received in the comment period . For a description of the sources used in preparing NEEDS v.5.1 5 , see Documentation, Chapter 4: Generating Resources

. 3 Several commenters identified units that were under construction and likely covered under the rule’s applicability language, but that had not b een identified at Proposal. Per commenter suggestion, EPA performed an additional review of under construction units using EIA 860 data, NEEDS v.5.1 5
, and comments. In most cases, commenter and publically available data supported one another. There were several instances where commenter and

2 The historical baseline development is described in more detail in Appendix 9

3 Available at http://www.epa.gov/powersectormodeling/Still Under Agency Review

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6

reported data conflicted. In these cases, EPA generally relied on the publically available data to determine the likely affected units to ensure consistent treatment across the fleet.

EPA notes that this baseline inventory does not constitute a final applicability determination. The actual inventory of affected units in a future year may vary from the 2012 baseline inventory of likely affected units.

c. Region

- level data

The EPA aggregated unit

- level data to the state level for purposes of state

- specific emission rate and mass goal calculation discussed in Section VII of the Preamble

. However, before calculating the state goal and mass equivalents , it further aggregated unit

- level to the regional level to calculate the category

- specific performance standards. The reg ions reflect the Eastern, Western, and Texas Interconnections. These regions were used when quantifying the best system of emission reductions in order to capture t he interstate e ffects of th e building blocks

. The rationale for the regional structure is e xplained in preamble section V.A.3.e . For each region
, the EPA made BSER

- related adjustments to the baseline data to determine the e ffect the three building block abatement measures could have on the average fossil steam rate and the a verage NGCC rate in that region . In making adjustments to region

- level data, the EPA is simply identifying th e BSER reductions that can be achieved on average at the regional level relative to baseline level

. The EPA is not making an y assertion s about specific units or plant capability

. The EPA recognizes the uniqueness and complexity of individual power plants, and is aware that there are site

specific factors that may prevent some EGUs from achieving performance equal to region

- level assumptions for a given technology

. Likewise, the EPA also recognizes that some EGUs are capable of, and regularly do, achieve performance levels that surpass the BSER values assumed. In any case
, the EPA is not making those unit

- level evaluations in this exercise. The EPA is instead attempting to quantify what is feasible at the regional level based on application of t he BSER values to his toric al regional

- level data

. Affected sources can then meet that emission rate through any particular use of abatement measures and/or emission reduction credits that it chooses

. Therefore, the ability or inability of a specific EGU to under/overachieve the assumed technology value cannot be taken, on its own, as an indication of the appropriateness of the category

- specific performance standards and the state goals estimated using this approach.

The aggregate baseline generation and e mission rates constitute a representative baseline for the power fleet for units likely subject to 111(d) applicability criteria. As with other EPA regulations, there may be subsequent applicability determinations post rule finalization that arrive at a d ifferent status determination for a particular unit than the one assumed here. Moreover, the future year inventory of affected units will inherently vary due to scheduled fleet turnover. While EPA addressed unit

- level data comments, there may also be are as where stakeholders disagree over unit

- level representation in the baseline. However, it is the regional representation of the power sector based on historical data is what ultimately informs the category

- specific emissions rates. The large population size of units embedded in the aggregate regional

level values used to quantify emission performance rates limit the ability of any unit

- level inventory or data discrepancies to introduce a bias that alters this representation.Still Under Agency Review

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7

EPA received some comment suggesting that it should remove units schedul ed to retire from the baseline inventory. It also received comments suggesting that they should not be removed. Removing units scheduled for retirement would generally result in lower category

- specific emission rates and state goals. EPA is using 2012 as a representative year among the most rece ntly available data and does not try to forecast future generation and emission levels post fleet turnover

. Even where fleet turnover is certain, (e.g., a scheduled retirement), the impact of that retirement is not. Removing units and generation from the baseline inventory without accounting for the shift in generation to other units would understate the amount of fossil generation in the baseline and distort its representativeness. Accounting for the shift in generation would begin to shift the baseline from a historical

- data informed baseline to a projection

informed baseline. Factoring in retirements and replacing it with projected generation shifts would undermine the merits of relying on a historical data set and the certainty of reported data

.Still Under Agency Review

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8

4. Methodology for Determining Category

- specific Emission Performance Rates

EPA’s methodology for calculating category

- specific performance rates is described i n the steps below. The implementation of each step is illustrated

– using the Eastern Interconnection for year 2030 as an example

- in the table below its description. 4

Step 1 : Compile 2012 unit

- level data, aggregate to state

- level, make baseline adjustments, and sum to regional baseline totals

.

The EPA begins the category

- specific performance rate calculation by starting with 2012 historic al data

. The underlying unit

- level or plant

- level data reflects actual emissions and generation reported by the facility (See Appendix 9 for more detailed explanation)

. EPA categorized each unit, using the classification syst em described in Appendix 9 , as coal steam, O/G steam, or NGCC. It also flagged units that were considered to be under construction during the 2012 baseline year . EPA then aggregated the u nit

- level data to the state level and calculated the state

- specific emission rate for each technology category by dividing the total emissions into the total generation. This reflected the una djusted 2012 baseline data for units that comm enced operation prior to 2012. F or states that have likely affected sources in two different interconnections, EPA segmented th ese states into their relevant i nterconnect portions at this step (e.g., the Montana Eastern Interconnection and Montana W estern Interconnection). EPA then made the aforementioned adjustments to the state

- level values to address concerns addressed by commenters. This included adding in the expected generation and emissions from likely affected units considered under construction. The resulting state

- totals following these limited adjustments provided a baseline for all likely affected sources. Complete data for these steps is available in Appendix 1, 2 and 3. See the North Carolina example below illustrating the adjustment made to 2012 data reflecting under construction units.

EP A received stakeholder comment noting that the Lee and Dan NGCC plants and the Cliffside coal unit 6 commenced operation part way through 2012 and therefore should be treated as under construction since they were still under construction for part of the y e ar and 2012 data was not representative of a full year ’ s operation . EPA described in preamble section VI how it incorporated this type of adjustment into its baseline. The example below illustrates where EPA first identified 2012 data from likely affecte d units that were not under construction (columns B & C), then identified under construction capacity ( columns D and E), and then adjusted the baseline generation values up to reflect anticipated baseline generation values assuming a more representative fu ll

- year utilization for these units (columns F & G)

.

4 As described in the GHG Mitigation Measures TSD, the building blo cks have different assumed levels over the 2022

- 2030 time frame reflecting deployment assumptions. Therefore, the rates described below vary by year and the amount of building block specified for that year.Still Under Agency Review

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9 Table 1. Example of Adjustment to 2012 Data

A B C D E F G

2012 Data for likely affected units (excluding under construction) Adjustment for Under Construction Sources Adjusted Baseline Coal Generation (TWh) NGCC

Generation (TWh) Under Construction

Coal Capacity (MW) Under Construction

NGCC Capacity (MW) Coal Generation

(TWh) NGCC

Generation (TWh)
North Carolina 50.57 15.06 825 2,165 54.92 25.52

15.06 TWh + 8784 h ou rs*2,165 MW*55% capacity factor = 25.52 TWh 5

Step 2 : Aggregate the adjusted historical emissions and generation to a regional level for coal steam, OG steam, and NGCC technology categories

.

EPA keeps the fossil steam sources separate from the NGCC sources at this stage to evaluate BSER impacts separately for each source category. This distinction is illustrated in Exhibit A above. These category

- specific values become the basis for calculating the category

- specific performance emission rates and subsequen t state goals. All emission rates provided are on a net basis.

5 As described in the preamble section VI, EPA established a 55% capacity factor as representative of new NGCC units (60% for n ew coal) based on a review of utilization patterns for units that commenced operation during the previous five years. The 2,165 c apacity value reflects summertime capacity and includes the L.V Sutton Plant which was also under construction. 8,784 hours are used instead of 8,760 to be consistent with the numb er of hours in the 2012 leap year for which the baseline is premised. The under construction coal capacity in column D reflects Cliffside 6 which commenced operation in 2012, so was classified as under construction per comment recommendation.Still Under Agency Review

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10 Table 2

. Regional Baseline

A B C D E F G
Coal NGCC OG Steam

Interconnection Emissions

(1000 short tons) Net

Generation (GWh) Emissions

(1000 short tons) Net

Generation (GWh) Emissions

(1000 short tons) Net

Generation (GWh)

Eastern 1,356,050 1,230,434 3 28,233 734,542 52,979 74,241

Step 3 : Identify category

- specific baseline emission r ates for fossil steam and NGCC

Fos sil steam sources include both coal steam and oil/ gas steam affected sources , whose data is combined to arrive at a fossil steam emission rate and generation total for each interconnection. This emission rate (in column H) reflec ts the sum of coa l emissions from column B and O/G steam emissions from column F divided into the baseline generation for each technology from columns C & G. Because the BSER involves both reductions in emissions intensity of sources (e.g., heat rate impr ovements) and reductions in generation of sources (e.g., shifting from fossil to renewable generation ), the baseline emission rate and generation for each technology source category are utilized to assess the potential impact of the building blocks.

Table 3

. Baseline Category

- specific Emission Rates and Generation.

A B C D E F G H I J K

Coal NGCC OG Steam Fossil Steam NGCC

Interconnection Emissions

(1000 short tons) Net

Generation (GWh) Emissions

(1000 short tons) Net

Generation (GWh) Emissions

(1000 short tons) Net

Generation (GWh) Emission

Rate (lb/MWh) Net

Generation (MWh) Emission

Rate (lb/MWh) Net

Generation (MWh)

Eastern 1,356,050 1,230,434 3 28,233 734,542 52,979 74,241 2,160 1,30 4
, 674 894 734,542

Eastern Fossil Steam Rate = ( coal emissio ns + OG emissions ) = Eastern Fossil steam rate = 1,356,050 ,000 tons +52,979 ,000 tons Coal gen + OG gen ( 1,230,434 GWh + 74,241 G Wh)Still Under Agency Review

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Eastern NGCC Rate = NGCC emissions = Eastern NGCC Rate = 328,233 tons NGCC gen 734,542 GWh

Step 4 : Calcula te r egional fossil steam emission rate resulting from building block 1 heat rate improvement (HRI)

.

After this baseline data is aggregated for each region
, the EPA begins to adjust some of the data values t o reflect each building block element of BSER

. The EPA assumes a 2.1 % HRI in the Western Interconnection, a 2.3% HRI in the Texas Interconnection, and a 4.3 % HRI in the East ern Interconnection applied only to the coal steam fleet. This is reflected by adjusting the coal emissions down by the region

- specific HRI percentage and lea ving the generation level unchanged. Subsequently, the fossil steam rate for the region is calculated by adding the adjusted coal emissions post HRI assumption (column H) with the baseline OG steam emissions (column D) and dividing into the sum of the coa l stea m (column C) and OG steam generation (column E) . There is no change in the NGCC rate from this step

.

Table 4 . Adjusted Fossil Steam Rate Reflecting Building Block 1

A B C D E F G H I

Baseline Coal Baseline OG Steam Baseline Fossil Steam BB1

Interconnection Emissions

(1000 short tons) Net

Generation (GWh) Emissions

( 1000 short tons) Net

Generation (G Wh) Emission

Rate (lb/MWh) BB1

HRI Level Post BB1 Coal Emissions (1000 short tons) Fossil Steam

Emission Rate Post BB1 (lb/MWh)

Eastern 1,356,050 1,230,434 52,979 74,241 2,16 0 4.3% 1,297,740 2,07 1

W hen the technology emission rate is recalculated with building block 1 reflected in the adjustment to the region ’s coal emission s , the region’s
fossil steam emission rate drops below its baseline value. Note that the fossil steam rate reflects the aggregation of both coal and OG steam data. This is not the final category

- specific performance rate , rather it is an adjusted emission rate reflecting the application of building block 1 before moving on to the remaining building blocks . The bold areas in the equation below reflect the values that are adjus ted from the ir baseline level at this step

. In this example, the fossil steam rate drops from a baseline value of 2,16 0 lb/MWh to 2,07 1 lb/MWh after b uilding block 1 application.Still Under Agency Review

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Eastern f ossil Steam Rate = ( coal e missions *( 1

- HRI% ) + ( OG emission s ) = Eastern f ossil steam rate = ( 1,356,050 ,000 tons)* 0.95 7 + 52,979 ,000 tons Coal gen + OG gen ( 1,230,434 GWh + 74,241 G Wh)

Step 5 : Calculate regional fossil steam and NGCC generation levels resulting from building block 3 (incremental RE generation)

Building Block 3 is based on lower

- emitting generation replacing higher emitting generation. The GHG Mitigation Measures TSD describes how the incremental RE generation potential for each region was derived. As explained in the TSD, the BB3 potential is defined as only incremental
RE generation (incremental relative to 2012 levels). Therefore the computation of ca tegory

- specific performance rates and state goals for the final rule only re flect this incremental RE total. All incremental BB3 RE is assumed to emit zero tons of CO 2
.

For this final rule, EPA assumes that BB3 incremental generation replace s existing fossil generation from the baseline levels . The replacement impact on each technology category is estimated on a pro

- rata basis where the incremental BB3 generation is first identified (column F) , and then apportioned to replace either fossil st eam (column D * column F = column I) or NGCC generation (column E * column F = column J) based on the share of baseline generation each technology category represent s

. For example , if a region had 100 MWh of potential BB3 generation identified, and baseline fossil steam accounted for 7 0% of the region ’ s generation from affecte d units and NGCC accounted for 30%, then the 100 MWh of incremental RE identified would be assumed to replace 7 0 MWh of fossil steam generation and 3 0 MWh of NGCC generation. Th e fossil steam generation and NGCC generation are decreased by the amount of RE MWh apportioned to that technology (column B

– column I) and (column C

– column J). The total baseline generation (columns B & C) equal s the total remaining generation and ren ewable generation (columns F, H, I, and J) reflecting that replacement of fossil sources by incremental RE generation.

Table 5 . Adjusted Fossil Steam and NGCC Generation Refl ecting Building Block 3

A B C D E F G H I J

Baseline Gen. BB3

Interconnection Fossil

Steam Net Generation (GWh) NGCC

Net Generation (GWh) Fossil

Steam Share of Total Fossil Gen. NGCC

Share of Total Fossil Gen. Potential

BB3 (GWh) Remaining

Fossil Steam (GWh) Remaining

NGCC Gen (GWh) BB3

Replacing Fossil Steam (GWh) BB3

Replacing NGCC (GWh)

Eastern 1,30 4
, 674 734,542 64% 36% 43 8,445 1,024,161 576,611 280,513 157,931Still Under Agency Review

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Eastern Fossil Steam Gen = Baseline Fossil Steam Generation

- (Potential BB3 Gen x fossil steam share of total fossil generation)

E astern Fossil steam Gen = 1,30 4,674

– (438,445 * 64%) = 1,024, 161 G Wh

Eastern NGCC Gen = Baseline NGCC Generation

- (Potential BB3 Gen x NGCC share of total fossil generation)

Eastern NGCC Gen = = 734,542

– (438,445 * 36%) = 576,611 G Wh

Step 6 : Calculate regional fossil steam and NGCC generation resulting from building block 2 (incremental NGCC generation)

The “Remaining NGCC Generation” field in column C of the below table indicates that there is less NGCC generation

– relative to baseline levels

- following building block 3 incorporation due to the assumption that some of the incremental RE would replace baseline NGCC generation. Moreover, there is si gnificantly less generation than the potential identified in building block 2 that reflects a 75% utilization

. If only imple menting building block 3 , the NGCC generation levels would be assumed to decrease under a pro

- rata replacement approach. However, in the GHG Mitigation Measures TSD, the EPA described the abatement potential of replacing higher emitting fossil steam gener ation wit h lower emitting gas generation, identified as building block 2 . This step of the rate calculation ca ptures the change in source

- category generation levels associated with building block 2 potential of a 75% potential utilization for the NGCC fle et

.

To incorporate building block 2 , t he regional NGCC fleet summertime capacity is multiplied by 8
, 784 hours (the number of hours in the 2012 year) and then by 75 % to get total potential net NGCC generation at a 75 % capacity factor (column D)

. However, this 75 % capacity factor represent s a generation ceiling, and the region ’s NGCC genera tion is only adjusted up to this ceiling to the extent

- that such NGCC generation increases can replace remaining fossil steam generation

. 6 Note that the combined remaining fossil steam and NGCC generation from columns F and G in this table reflect the remaining fossil steam and NGCC generation total after BB3 (columns B and C). Moreover, columns F and G combined with the RE potential assigned to each technology in columns I and J in the previous table sum to the total baseline generation assumed for each region.

6 The ceiling in the interim period is less than the 75% utilization level. The BB2 de ployment schedule is discussed in the GHG Mitigation Measures TSD.Still Under Agency Review

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14 Table 6. Adjusted Fossil Steam and NGCC Generation Reflecting Replacement by Building Block 3 and Building Block 2 Generation

A B C D E F G

Post BB 3 BB2

Region Remaining

Fossil Steam (GWh) Remaining

NGCC Gen (GWh) NGCC Potential

at 75% CF (GWh) Difference between NGCC

generation levels at 75% utilization and Post BB3 NGCC levels (GWh) Remaining Fossil Steam (GWh) Remaining

NGCC Gen (GWh)

Eastern 1,024,16 1 576,611 987,956 41 1,345 612,816 987,95 6

I n the above example
, NGCC generation is adjusted upwards by approximately 4 11 TWh (column E) to 98 7
, 956 TWh (column G) (which equals the NGCC fleet generation at 75% utilization) and the fossil steam generation is adjusted down by that same amount ( column B

- column F).

Eastern Fossil Steam Gen = Post BB3 fossil steam gen.

- ( NGCC Potential at 75% CF

– Post BB3 NGCC Gen) 7

E astern Fossil steam Gen = 1,024,16 1

– (987,956

– 576,611 ) = 612,816 GWh

Eastern NGCC Gen = Post BB3 NGCC gen + (NGCC Potential at 75% CF

– Post BB3 NGCC Gen)

Eastern NGCC Gen = 576,611 + ( 98 7,956

– 576,611 ) = 987,95 6 GWh

Step 7 : Determine the adjusted category

- specific performance rates for each region.

7 If (NGCC Potential at 75% CF

– Post BB3 NGCC Gen) is greater than post BB3 fossil steam gen, then the fossil steam gen amount is adjusted to zero and the NGCC Gen amount is increased by t he Post BB3 fossil steam generation amount that it replaced.Still Under Agency Review

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15

Step four estimated the category

- specific emission rates post BB1. Steps five and six estimated the category

- specific generation levels post building block 3 and 2, respectively . Combining the adjusted emission rates with the adjusted generation allows EPA to calculate a category

specific adjusted emission rate reflecting the expression of BSER onto the baseline.

For the regional fossil steam rate, EPA first calculates the numerator. EPA multiplies the fossil steam emission rate from step four (column F ) (reflecting the heat rate improvement) by the remaining fossil steam generation following step six (column J) . For BB3, all replacement generation was assumed to equal zero so no numerator adjustment was made

. As described in the preamble, EPA also captures a portion of the NGCC generation in the fossil steam rate reflecting the incremental BB2 potential ; 8 this incremental NGCC generation is defined as the amount of remaining NGCC subsequent to both blocks 2 and 3 (column K) minus the amount of NGCC generation in the baseline (column E )

. 9 This amount of NGCC generation is multiplied by the NGCC emission rate from s tep three (column C) to get the amount of incremental NGCC em issions assigned to the fossil steam emission rate as part of BB2

.

These emissions from fossil steam sources along with emissions from its replacement sources are then divided by the total amount of r emaining fossi l steam generation, the RE generation assigned to fossil steam, and the incremental NGCC defined above. This generation is the sum of 1) remaining fossil steam generation post step six (column J) , 2) amount of RE generation assigned to fossil steam genera tion (column H ) , and 3) the

8 As described in the preamble, EPA reflected the incremental NGCC generation (and corresponding emission s ) in the fossil steam rate source category rate and created a parallel compliance struct ure for quantifying NGCC ERCs which fossil steam sources may use in compliance. This was necessary to create a fossil
steam source

- category rate that reflec ted generation shifting due to BB2.

9 EPA also considered quantifying the amount of NGCC generatio n assigned to fossil steam generation as post step 6 levels minus post step 5 levels which would have resulted in a lower fossil steam rate. However, this approach would not have resulted in a different stringency because a similar adjustment would be mad e when measuring and quantifying NGCC ERCs available for compliance. In other words, there would be a lower rate, but more cre dits available. EPA determined that measuring incremental NGCC generation to include in the fossil steam rate was more appropria tely done using a baseline level (premised on historical generation) as it would facilitate appropriate measurement and identification of NGCC ERCs. EPA took the more con servative approach of defining the amount of NGCC generation and emissions reassigned to the fossil steam rate as the difference between post BSER levels and baseline values to ensure consistency with potential ERC measurement and crediting from a historical baseline level and help ensure that enough ERCs wo uld be available if sources chos e that compliance route. Therefore, the remaining fossil steam and NGCC generation levels appropriately reflect the full building block two and three potential, and the portion of the NGCC emissions and generation levels included in the fossil steam rate appropriately reflect the hist orical measurement basis for ERC s.Still Under Agency Review

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amount of NGCC generation defined above (column K

- column E ) . Dividing this total emissions level by the total generation levels results in a regional fossil steam emission rate reflective of BSER.

For the regional NGCC emission rate, EPA performs a similar operation. The NGCC generation post step six (column K) is multiplied by the NGCC baseline emission rate from step three (column C) to estimate the total am ount of NGCC emissions post BB3 and BB2 . These emissions are then di vided into the sum of the NGCC generation post step six (column K) and the amount of BB3 generation apportioned to NGCC generation in step five (Column I)

. 10 This regional NGCC rate reflects the adjusted NGCC rate reflecting BSER.

Eastern Fossil Steam Gen = (Post BB3&2 fossil steam gen x Post BB1 fossil steam emission rate)+(Incremental NGCC Generation x baseline NGCC rate) (Post BB3&2 fossil steam gen + BB3 generation replacing fossil steam + incremental BB2 generation)

E astern Fossil steam Gen = (612,816 GWh * 2,07 1lb/MWh ) + (( 987,956 GWh

- 734,542 GWh )*894 lb/MWh ) 612,816 GWh + 280,513 GWh + ( 987,956 GWh

- 734,542 GWh)

Eastern NGCC Gen = (Post BB3 NGCC gen x NGCC baseline rate) (Post BB3 NGCC gen + BB3 generation replacing NGCC gen)

Eastern NGCC Gen = (987,956 GWh * 894 lb/MWh ) (98 7,9 5 6 GWh + 157, 931 GWh)

10 The full NGCC generation (and corresponding emissions) expected under the BSER calculation is included in the NGCC rate, even though a portion of it is also reflected in the fossil steam rate. Failing to do so would leave the NGCC sources with a lower rate than what is expected post BB2 and BB3. Keeping the full NGCC generation amount in the NGCC rate, in spite of its replacement impact on fossil steam, recognizes the dual role it has in terms of compliance responsibility as an affected source and a mitigation measure under building block 2 that that can offset fossil steam genera tion.Still Under Agency Review

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17

Step 8 : Identify the l east stringent r egional rate as the e mission performance rate for the technology source c ategory

After completing a regional assessment of building block potential impact on source category

- specific rates, EPA evaluated the fossil steam and NGCC rate for each region to identify the region with the least stringent emission rate. The least stringent (i.e., the highest) fossil steam rate and the least stringent NGCC emission rate among the three regions are identified and used to establish the source

- category emission performance rates described in the preamble

.

Table 7. Identify Least St ringent Rate for Each Technology Category (2030)

Adjusted Rates

Region Fossil Steam Rate (lb/MWh) NGCC Rate

(lb/MWh) Eastern Interconnection 1,305 771

Western Interconnection 260 660
Texas Interconnection 450 754

The completion of the previous steps result s in a 2030 emission performance rate for each source ca tegory. However, as described in the GHG Mitigation Measures TSD , the BB2 and BB3 assumed potential change s for each year from 2022 through 2030 . Thus this procedure is repeated for each of those years using the corresponding BB2 and BB3 assumptions for that year that reflect the deployment rate for those technologies

. 11
This results in a set of decreasing annual adjusted emission rates for the years 2022

- 2029

. However, this rulemaki ng issues category

- specific emission performance rates for an interim and a final rate . Thus, the interim rate is derived by averaging the annual adjusted emission rates for 2022

- 2029. Once the interim and final rates are determined, EPA rounds any fract ional number up to the nearest integer.

11 The region with the least stringent rate can differ by year. For the fossil steam rate, the Eastern Interconnection is the limiting region in all years. For the NGCC rate, the Texas Interconnection is the limiting region for 2022 through 2026, and the Eastern Interconnection is the lim iting region for 2027 through 2030.Still Under Agency Review

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For the F inal CPP Rule category

- specific rates: Interim c ategory

- specific rate

– Average of the adjusted yearly emission rates for the period 2022

- 2029 Final c ategory

- specific rate

– The 2030 emission rate (as calculated above) becomes the state goal for 2030 and each year thereafter

T he assumptions used to arrive at the category

- specific performance rates are not prescriptive of necessary actions that sources, states, or regions must take. As described in the preamble, these values are used only for calculating the emission performance rates and state goal s

. A state is not required to base its state plan on using the same set of measures or the same amount of any measure reflec ted in these assumptions. Likewise, the state plan, not these assumptions, determines the range of available measures a source may or must use to comply with the sta ndards of performance established for it in the state plan and the extent to which the sou rce may or must rely on any individual measure.

5. Methodology for Converting Category

- specific Rates into State Emission Rate Goals

To calculate a state goal in the final CPP, EPA estimates the affected fleet rate for a state if all likely affected baseline sources meet the respective category

- specific emission performance rates presented above while generating at the same baseline generation total

. For each state, EPA calculated a weighted average of the category

- specific fossil steam rate and the category

- specific NGCC using the state’s baseline generation levels for each source category. These aggregate state rates reflect the total emission rate from likely affected units in the state if they operated at baseline generation levels while meeting the category

- specific rates.

For example, the nation

- wide 111(d) source category rates determined at the regional level were 1305 lb/MWh and 771 lb/MWh respectively. The state of Arizona had baseline affected fossil generation consisting of 25.37 TWh of fossil steam generation and 26.78 TWh of NGCC generation

. Arizona’s 2030 state goal metric would be calculated as follows:

Arizona state g oal = (Fossil steam source category rate * Fossil steam baseline share of affected generation) + (NGCC so urce category rate * NGCC baseline share of affected generation)Still Under Agency Review

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19

Arizona State Goal = (48.65%*1,305) + (51.35%*771) = 1,031 lb/MWh

.

EPA uses the representative baseline and calculations described above to derive category

- specific rates and state emission r ate goals. Once calculated, the system

- wide impacts and feasibility of these state goals are further tested using EPA’s power sector modeling.

6. Methodology for Converting State Emission Rate Goals into State Mass Goals


# PlaceholderStill Under Agency Review

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20

7. APPENDIX

Appendix 1

– Underlying 2012 unit

- level baseline inventory and data

See “Appendix 1

- unit

- level data ” worksheet in the Excel a ttachment titled “ Baseline, Category

- specific rates, and State Goal Quantification ” Appendix 2

- Units that commenced operation post 201 1 , but began construction prior to 1/8 /14

See “Appendix 2

– Under construction ” worksheet in the Excel a ttachment titled “ Baseline, Category

- specific rates, and State Goal Quantification ” . Note, this is largely a subset of the Appendix 1 worksheet. Appendix 3

– Underlying state

- level data, adjustments

See “Appendix 3

– state

- level data ” worksheet in the Excel a ttachment titled “ Baseline, Category

- specific rates, and State Goal Quantification ” Appendix 4

– Computation of the c ate gory - specific performance r ates (Interim and Final)

See “Appendix 4

– category

- specific calc. ” worksheet in the Excel a ttachment titled “ Baseline, Category

- specific rates, and State Goal Quantification ” Appendix 5

- Computation of the s tate g oal (Interim and Final)

See “Appendix 5

– State Goals” worksheet in the Excel a ttachment titled “ Baseline, Category

- specific rates, and State Goal Quantification ”Still Under Agency Review

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21

Appendix 6

– State G oalsStill Under Agency Review

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22

Appendix 7

– Adjustments to state

- level 2012 baseline data

See the Excel a ttachment titled “ State

- level adjustments ”

Hydro adjustment

– States suggested that 2012 was an abnormal year for hydro, and because of the predominance of hydro in their state, this also made it an outlier year for other generation technologies in the st ate. EPA assessed this concern for all states using the following filters:

1) Using EIA 2012 data, identify the % share of total generation coming from hydro in each state 2) Using EIA 1990

- 2012 data, identify average hydro generation for a state from 1990

- 2012 and look at the % difference between 2012 hydro generation levels and the average hydro generation levels 3) Estimate the increase in affected fossil generation that would occur if the difference between the average hydro year and the 2012 hydro yea r was replaced with generation from affected fossil generation.

EPA determined that hydro intensive states (greater than 10% generation from hydro), that experienced an outlier year in 2012 (greater than 10% increase in hydro generatio n relative to observ ed average between 1990

- 2012) , and that would have their state’s affected fossil generation significantly affected when assuming average hydro generation levels (an adjustment > 5%) had baseline values that were sensi tive to fluctuations in hydro generatio n and thus increased the fossil generation in the state from observed 2012 levels to reflect potential generation levels in a n average hydro year.

Unit

- outage adjustment As explained in the Preamble Section VI, EPA did not generally view single unit

- outag es as problematic to its baseline for determining source

category rates or state goals. As regional load levels did not change subject to the unit outage, the decrease at a particul ar unit is generally offset by the increase in generation from other unit( s) in the same state or region. Therefore, EPA views the regional and state

- level aggregate generation totals as robust against unit

- level outages. However, it did test for outlier cases where the unit

- level outage was significant enough to potentially h ave a large impact on the state goals that EPA provided in section VII. EPA assess this concern for all units by identifying : 1) Units where the generation in 2012 was less than 2 5% of its 2010 and 2014 totals collectively (signaling a significant outage). 2) For units meeting the step 1 criteria, EPA identified those where the generation observed in the non

- outage years of 2010 and 2014 years was greater than 10% of the state ’ s total generation (suggesting the replacement generation may be difficult to find in state).

The only unit that met this criteria was the 900 MW Sherburne county unit 3 coal unit in Minnesota. EPA adjusted the state’s generation level value up to reflect this unit operating in a typical year.Still Under Agency Review

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Appendix 8

– Category

- specific emission ra tes under building block severability

See “Appe ndix 9 ” worksheet in the Excel a ttachment titled “ BB Severability ” which replicates EPA quantification of BSER assuming only building blocks 1 and 2Still Under Agency Review

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24

Appendix 9

- Description of 111(d) baseline data s ources and d evelopment

Introduction This section describes the methodology used by the EPA to develop the state and region

- level baselines used in the goal setting process.
The 111(d) baseline analysis methodology is based largely on the methodology used to develop the Emissions and Generation Resource Integrated Database (eGRID) 12 , with certain key differences, which are explained in Appendix A. The 111(d) baseline consists of emission rates in pounds of CO 2 per megawatt

- hour (MWh) of electricity generation. The baseline is constructed by matching electricity generation data reported to the Energy Information Administration (EIA) by power plants on forms EIA

- 860 13 and EIA

- 923 14 with data on CO 2 e missions submitted by power plants to the EPA under 40 CFR Part 75. 15
The process of matching emissions data to generation data and categorizing the EGUs is described in more detail below. The di fferences between the baseline released for the Clean Power Plan Proposed Rule 16 and the Final Rule are discussed in Section C

.

Data Sources The key data sources used in the construction of the 111(d) baseline are listed in Table 1

.

Table 1 . Key data sources used to construct the 111(d) baseline.

Data Source Key Data EIA

- 860 Contains key identifying information, including nameplate capacity, summer

capacity, unit operational status, prime mover type, and fuel type, as well as the plant’s name and location.

12 U.S. Environmental Protection Agency, Clean Air Markets Division, Emissions and Generation Resource Integrated Database (eGRID), available at http://www.epa.gov/cleanenergy/energy

- resources/egrid/

13 Energy Information Administration, Form EIA

- 860, available at http://www.eia.gov/electr icity/data/eia860/

14 Energy Information Administration, Form EIA

- 923, available at http://www.eia.gov/electricity/data/eia923/

15 40 CFR Part 75, available at http://www.ecfr.gov/cgi

- bin/text

- idx?tpl=/ecfrbrowse/Title40/40cfr75_main_02.tpl

16 https://www.fed eralregister.gov/articles/2014/06/18/2014

- 13726/carbon

- pollution

- emission

- guidelines

- for

- existing

- stationary

- sources

- electric

- utility

generatingStill Under Agency Review

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25

EIA

- 923 Contains information on net electricity generation and fuel use at the generator

level, boiler level, and/or prime mover level.
EPA Part 75 Data Contains information on CO 2 emissions and heat input.

EPA Part 75 emissions data is presented at the uni t level, where the unit is defined as the fossil fuel

- fired device, which could be a turbine or boiler (including any heat recovery steam generators (HRSG), if present) . EIA data on generation and fuel use is presented at the generator, boiler, prime mover , and plant levels.
The 111(d) baseline analysis methodology involves matching EPA emissions data at the unit level (i.e. emissions from boilers or turbines), with EIA generation data at the generator level. However, the data do not always match cleanly between the two data sources. While both data sources identify plants using the Office of Regulatory Information Systems Plant Location code (ORIS code), the EIA data iden tifies generators with a generator ID, and the EPA data identifies units with a unit ID. The ORIS code generally matches between data sources, but the generator ID from EIA must be matched to the unit ID from EPA based on ORIS code, nameplate capacity, fuel type, prime mover type, and year of operation.

Furthermore, because there are dif ferent regulations governing which plants and units must report data to the EIA and the EPA, there may be different numbers of units at each plant between the two data sets. Additionally, e xisting and proposed plants are required to submit Forms 860 and 9 23 to the EIA if the plant’s total generator nameplate capacity is 1 MW or greater and it is capable of supplying power to or drawing power from the electricity grid. Plants are required to submit emissions data to EPA under 40 CFR Part 75, generally if a unit serves a generator with a nameplate capacity of greater than 25 MW which produces electricity for sale.

Baseline Construction Process As discussed above, the construction of the 111(d) baseline involves matching net electricity generation data from EI A with data on CO 2 emissions from EPA. All of the existing, proposed, and retired units listed in the EIA

- 860 serve as the foundation for the baseline, establishing the universe of units. Electricity generation and CO 2 emissions are added to this foundat ion using the EIA

- 923 and EPA Part 75 data. 

### Electricity Generation For any given power plant, data on net electricity generation from the EIA

- 923 may be available at the unit level for some units or at the prime mover level for other units. If unit

- level data are available, the data are used in the baseline. If data are only available at the prime mover level, then these data are distributed proportionally based on nameplate capacity to the units at that plant with that prime mover.Still Under Agency Review

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26



### CO 2 

### Emissions
Part 75 emissions data from EPA are matched to the generator

- level data from EIA. When units can be matched exactly between the two data sources, the unit

- level emissions are used in the baseline. When one unit from the EPA data is associated with more than one g enerator from the EIA data (e.g. emissions from a boiler that supplies steam to more than one generator), or if units at a given plant cann ot be matched exactly between the two data sources, the total emissions may be distributed to generators based on the proportion of nameplate capacity. Combined cycle units are considered a single system and emissions from all component s are summed and distributed to all generators based on proportion of nameplate capacity.

Because there are different regulations governi ng which plants and units report data to EIA and EPA, there are more units listed in the EIA data than in the EPA data (for example, a unit under 25 MW may not be required to report emissions data under Part 75) . To estimate emissions for units that are li sted in the EIA data but not in the EPA data, a fuel

- specific emission factor is multiplied by unit

- level fuel consumption (million British thermal units (mmBtu)). This method is based on the methodology used by the Intergovernmental Panel on Climate Chang e (IPCC) 17 and in EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks. 18 CO 2 emission factors for year 2012 are obtained from two sources: EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2012, and the emission factors used in the Greenhouse Gas Reporting Program, which are listed in 40 CFR Part 98. 19 The emissions factors used in the 111(d) baseline analysis are listed in Section D . The fuel use is based on heat input data from EPA Part 75 data, boiler

- level data from the EIA

- 923, and prime mover level data from the EIA

- 923. Data are selected preferentially in that order (e.g. if heat input data are unavailable from EPA, then boiler

- level data from EIA are used).



### Data Corrections
When CO 2 emissions from EPA are matched with net electricity generation data from EIA, an emissions rate (lbs. CO 2 per MWh) is calculated. If the calculated emissions rate is unreasonably high (>10,000 lbs. CO 2 per MWh) or unreasonably low (<500 lbs. CO 2 per MWh) for a unit, the net electricity data are calculated based on gross generation data from EPA. Because the EPA data contain gross generation rather than net

17 IPCC, 2007: The Intergovernmental Panel on Climate Change (IPCC), “2006 IPCC Guidelines for National Greenhouse Gas Inventories”, volume 2 (Energy), April 2007. http://www.ipccnggip. iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf

18 EPA, 2014: U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990

- 2012, Washington, D.C., April 2014. http://epa.gov/climatechange/emissions/usinventoryreport.html

19 TCR, 2014: The Climate Registry 2014 Climate Registry Default Emiss ion Factors, Washington DC, January 10, 2014. http://www.theclimateregistry.org/tools

- resources/reporting

- protocols/generalreporting

protocol/Still Under Agency Review

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27

electricity generation, net generation must be calculated by multiplying gross generation by a unit

- specific net

- gross conversion factor. 20 In cases where a net

- gross conversion factor is not available for a specific unit, the calculation uses a net

- gross conversion factor from a plant in the same state and with the same prime mover. If the EPA data do not include gross generation for a specific unit, the calculation use s data on gross generation from EIA. 21 I f this correction still results in an emissions rate greater than 10,000 lbs./MWh or less than 500 lbs./MWh, then the net electricity generation data are left unchanged and the original calculated rate is retained.

In addition, for units that report negati ve net electricity generation (for example, the facility uses more electricity than it produces) and CO 2 emissions , the electricity generation is adjusted using gross electricity generation data as described above. This correction is inten ded to avoid
esti mating a negative emissions rate.

Limited adjustments are also made for several likely affected facilities that had reported summertime capacity significantly greater than nameplate capacity. For these units, EPA replaced the summer capacity value report ed in EIA 860 with the nameplate value.



### Inclusion Criteria
In order to calculate the state

- level emission rate for coal steam units, natural gas combined cycle units, and oil and gas steam units, the individual units are categorized according to the namepl ate capacity, prime mover type, fuel, and operating status, as shown in table 2.

Table 2

. C riteria for inclusion of units in the 111(d) baseline as likely affected sources

. Category Code Category Inclusion criteria COALST Coal steam

units Steam turbine units (prime mover = ST) with coal as primary fuel

source. Nameplate capacity must be greater than 25 MW.

20 These conversion factors were developed by Ventyx (now called ABB Enterprise Software), a consulting firm that provides infor mation and data related to the electricity generation sector. The factors are developed using North American Reliability Corporati on (NERC) Generating Availability Data System (GADS), which contains data on gross and net generation for units with a nameplate capacity greater than 20 MW. The data provided for this analysis are unit

- level ratios of net generation to gross generation.

21 EIA supplied the gross generation data for a subset of generators to EPA, as these data are not publicly available in the EIA

- 923 data.Still Under Agency Review

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Category Code Category Inclusion criteria NGCC Natural gas

combined cycle units Combined cycle units with natural gas as primary fuel source. If all of

the turbine components of the combined cycle unit (prime mover = CT) have a nameplate capacity greater than 25 MW, then all of the steam components (prime mover = CA) are included, regardless of whether they have a nameplate capacity greater than 25 MW. Otherwise, onl y components with a nameplate capacity greater than 25 MW are included. OGST Oil and gas

steam units Steam turbine units with oil or gas as primary fuel source. Nameplate

capacity must be greater than 25 MW. UC Coal

– Commenced in 2012 Coal steam

units that commenced operations in 2012 Units that would otherwise be classified as COALST, but which

commenced operations in 2012. Determination of when the unit commenced operations is based on the EIA

- 860 and public comments on the 111(d) baseline developed for the Proposed Rule.

UC NGCC

– Commenced in 2012 NGCC units

that commenced operations in 2012 Units that would otherwise be classified as NGCC, but which

commenced operations in 2012. Determination of when the unit commenced operations is based on the EIA

- 860 and public comments on the 111(d) baseline developed for the Proposed Rule.

UC

- Coal Coal steam

units that are under construction in 2012 or 2013 Units that are under construction in the data year ( EIA unit status = U,

V, or TS), but which would li kely be considered COALST units if operational. For the 2012 111(d) baseline, units can be listed as UC

Coal if they are under construction in 2012 or 2013.

UC

- NGCC NGCC units

that are under construction in 2012 or 2013 Units that are under construction in the data year ( EIA unit status = U,

V, or TS), but which would likely be considered NGCC units if operational. For the 2012 111(d) baseline, units can be listed as UC

NGCC if they are under construction in 2012 or 2013.Still Under Agency Review

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Category Code Category Inclusion criteria EXCLUDE Units excluded

from the 111(d) baseline Units may be excluded from the baseline for several reasons,

including :

 Internal combustion engine units;

 Non

- combustion prime movers, such as photovoltaics, wind turbines, and hydropower units;

 Units that used less than 10% fossil fuel on a heat input basis in 2012;

 Non

- operational units, such as units that have retired or are under construction according to EIA data; or

 Industrial or commercial units, including CHP units and non

CHP units that supply less than one

- third of their electric ity to the grid.

* Note also that the inclusion or exclusion of a particular unit in the 111(d) baseline analysis does not necessarily indicate that the unit will meet the applicability criteria in the Final Rule.

State

- level baseline The state

- level base line is created by summing the CO 2 emissions and net generation from the generator

- level baseline for units in the COALST, NGCC, and OGST categories. Units are also grouped by state and North American Electric Reliability Corporation (NERC) region.

NERC region data for each plant are taken from the EIA

- 860, which lists the Independent System Operator/Regional Transmission Organization (ISO/RTO) region at the plant level. ISO/RTO regions are matched to NERC regions using the relationships in Error! Reference source not found.

. 22

The emissions rate is calculated by converting the CO 2 emissions from tons to pounds by multiplying by 2,000 and then divi ding by the net generation.

Differences between 111(d) and eGRID Methodologies

22 There are at least two facilities in Texas (Tenaska Frontier Generating Station and Tenaska Gateway Generating Statio n) that can supply electricity either to the Eastern or ERCOT NERC regions. The region that these plants reported in the EIA

- 860 is used as the NERC region in the 111(d) baseline analysis.Still Under Agency Review

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The methodology used to develop the baseline state

- level emission rates for the 111(d) analysis is based largely on the methodology used to develop the annual editions of the Emissions and Generation Resource Integrated Database (eGRID), with certain key differences. In general, however, the methodologies are broadly similar: they both involve matching Part 75 CO 2 emissions data from the EPA Clean Air Markets Division (CAMD) wi th data on electricity generation from EIA. Nevertheless, there are specific criteria set forth in the Clean Power Plan that necessitate slight deviations from the eGRID methodology in the 111(d) baseline analysis.

In particular, the Clean Power Plan defi nes specific criteria that dictate which generating units are to be included in the baseline analysis. The eGRID methodology is altered slightly to accommodate these inclusion criteria. This Section explains those methodological dif ferences.

Emissions assi gned to boilers eGRID reports emissions at the boiler level and rolled up to the plant level, but the eGRID methodology does not attempt to a ssign emissions from boilers to individual generators. Because the baseline is based on generators (e.g. units with a nameplate capacity greater than 25 MW), the boiler

level emissions must be assigned to the generators in the 111(d) baseline analysis.

Where possible in the 111(d) baseline analysis, the emissions data from EPA are assigned to the generator directly associated with that boiler, according to data from EIA

- 860. When the emissions are only available at the plant level, or if one boiler is associated with more than one generator, or if it is unclear which generator is associated with which boiler, the em issions are proportionally distributed to generators based on nameplate capacity.

Similarly, in the 111(d) baseline analysis, combined cycle units are treated as a single system, and the total emissions from the combined cycle units are distributed to the components (the steam parts and turbine parts) based on proportion of nameplate capacity.

Inclusion criteria In order to decide which units are included in the estimation of state

- level rates, it is necessary to determine if they meet the inclusion crite ria based on unit size and type, operating status, fuel use, electricity sales, and capacity factor. For example, coal units with a nameplate capacity less than 25 MW or with a heat input capacity less than 250 mmBtu/hr. are excluded from the analysis, and therefore the emissions from these units are not used to calculate the state

- level rates. In addition, the 111(d) baseline analysis does not include units that use less than 10% fossil fuel on a heat input basis in 2012, units that are retired or under co nstruction, and certain commercial and industrial units that are not grid connected. However, the data files from the 111(d) baseline analysis still list all of these units, but the “Category” field for these units is l isted as “EXCLUDE.”

In addition, in the methodology to develop eGRID, units with zero generation are not included in the final eGRID files. Since the 111(d) base line files capture the entire universe of units, the files for the 111(d) baseline will list more units than the eGRID files.Still Under Agency Review

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31

Updat es to units with negative or zero generation In certain cases, when the emissions data from EPA are matched with generation data from EIA, it appears that a unit has posi tive emissions, but zero or negative generation. As a result, the emission rate calcul ated for this unit could result in a negative value, which would not make sense in the context of the 111(d) baseline analysis. To correct this issue, EPA estimated the net electricity generation from these u nits based on their gross generation and net

- gro ss conversion factors. In the development of eGRID, negative generation is not adjusted.

Outlier emission rates As discussed above, for some units the emissions data from EPA do not match up with generation data from EIA in ways that mak e sense, such as wh en CO 2 emissions are associated with negative net electricity generation. EPA also implemented a correction in the 111(d) baseline a nalysis for units with emission rates that are either too low or too high. For this analysis, EPA used rates less than 500 l bs. CO 2 /MWh as the cutoff for rates that are too low, and rates greater than 10,000 lbs. CO 2 /MWh as the cutoff for rates that are too high.

EPA applied a two

- step process for these units. If the EPA data for the unit in question also contained gross gener ation data, the gross generation was converted to net generation using net

- gross conversion factors as described above. If the EPA data did not include gross generation for that unit, EPA used gross generation from EIA, also as described above. If either o f these corrections would result in emissions rates that were still less than 500 lbs. CO 2 /MWh or greater than 10,000 lbs. CO 2 /MWh, EPA left the generation data unchanged and retained the original calculated rate. EPA does not use this quality assurance co rrection in eGRID.

Adjustments to emissions from biomass In eGRID, it is assumed that biomass is carbon neutral and therefore the emissions associated with biomass are adjusted to ze ro. While the eGRID plant file reports both the adjusted and unadjusted em issions, the summary tables are based on adjusted emissions.

This adjustment is not made in the 111(d) baseline analysis, although units that use less than 10% fossil fuel on a heat inpu t basis in 2012 are excluded from the analysis.

Tribal lands The 111(d ) analysis includes a total of 4 units from Navajo, Ute, and Fort Mojave tribal lands. These units are included in eGRID but are assigned to states, rather than the appropriate tribal lands.

Key Differences between Proposed and Final 111(d) BaselinesStill Under Agency Review

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This section outlines the differences between the 111(d) baseline file, created for the Proposed Rule (June 2014, hereafter “ proposed file”) and the version of the file created for the Final Rule (hereafter “final file”). EPA received public comment on the proposed file and made changes accordingly. Two changes to the methodology, based on comment, are used to create the final file are as follows:

1. Gap

- filling generation data at plants where EIA data listed the net electricity generation as zero or negative; and 2. Additional quality assurance checks to examine units with unusually high or low CO 2 emission rates.
In addition to these methodological changes, EPA also made non

- methodological changes to the proposed file when creating the final file, inclu ding:

3. Changes to unit characteristics; 4. Changes to the unit categorization; and 5. Changes to emissions data.
Each of these changes are described in more detail below.

Methodological Changes Based on Comment

1. Gap

- filling negative or zero generation In certai n cases, when EPA emissions data collected under 40 CFR Part 75 are matched with generation data from EIA, a unit can have po sitive emissions, but zero or negative generation. This would occur if a unit uses more power than it generates. As a result, the e mission rate calculated for this unit would be negative. To correct this issue, EPA estimated the net electricity generation from these units based o n their gross generation and net

- gross conversion factors

Using this methodology, EPA updated the generatio n for 16 units with zero or negative generation. Of these, 13 units satisfy the criteria for inclusion in the 111(d) baseline analysis.

2. Additional quality assurance methodology As discussed above, for some units, the EPA emissions data do not match up with EIA

- 923 generation data in ways that make sense in the context of the 111(d) baseline. We discuss above how we correct for this issue when the resulting estimated GHG emission rates are ne gative. EPA also implemented a correction for units with emission r ates that are either too low or too high. For this analysis EPA used 500 lbs. CO 2 /MWh as the cutoff for rates that are too low, and 10,000 lbs. CO 2 /MWh as the cutoff for rates that are too high.Still Under Agency Review

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For these units EPA applies a correction using a two

- step pr ocess. If the EPA data for the unit in question also contain gross generation data, EPA converts the gross generation to net generation using net

- gross conversion factors. If these corrections results in emissions rates that are still less than 500 lbs. CO 2 /MWH or greater than 10,000 lbs. CO 2 /MWh, EPA leaves the generation data unchanged and retains the original emissions rate.
Using this methodology, EPA updated the generation for 111 units that have “out

- of

- range” emission rates in the proposed file, all of which meet the criteria for inclusion in the 111(d) baseline analysis.

Non

- Methodological Changes Based on Comment

3. Changes to unit characteristics In addition to the methodological changes described above, EPA also responded to public comments received on the 111(d) baseline developed for the Proposed Rule. These comments include updating generation data that had been misreported to EIA, changing prime movers an d fuel types, and changing CHP flags. These changes are detailed for each unit in the unit

- le vel baseline files in the column titled “Changes from File for Proposed Rule.” EPA also added a column to the baseline files to indicate whether a unit had commenced operations in that dat a year. This column is populated using a combination of public comme nts and data from EIA on when the unit commenced operations.

4. Changes to unit categorization For the 2012 baseline final file, EPA made changes to the categorization for coal steam and natural gas combined cycle (NGCC) units that were under construction or commenced operations in 2012. In the proposed file, there are 9 units listed as COALST and 46 units listed as NGCC that commenced operations in 2012. In the final file, EPA changed the category of these units to “UC Coal

– commenced in 2012” or “UC NGCC

– commenced in 2012”, respectively. There are also 4 coal steam units and 55 NGCC units that were under construction in either 2012 or 2013 according to EIA data that are in the EXCLUDE category in the proposed file, but are now listed as “UC Coal” or “UC NG CC”, respectively, in the final file.

In addition, the proposed file contained additional categories, including simple

- cycle turbines (SST), which are not included in calculations for the Final Rule. EPA changed the category for these units to EXCLUDE.

5. Cha nges to the EPA emissions data EPA used an updated version of emissions data collected under 40 CFR Part 75 in the analysis. The EPA pulled the emissions da ta used to create the proposed file in February 2014, and the data used to create the final file in February 2015. This resulted in changes in emissions for 23 units between the proposed and final files.Still Under Agency Review

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Emission Factors

The emission factors listed in the table below are used in the 111(d) baseline analysis to estimate CO 2 emissions, if emissions for a given unit are not included in the EPA data. CO 2 emission factors for year 2012 are obtained from two sources: EPA’s Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990

- 2012, and the Greenhouse Gas Reporting Program (4 0 CFR Part 98).

Fuel Code Fuel Type Prime Mover Emission Factor (Tons CO 2 /mmBtu)
AB Agricultural byproducts ST 0.13027 BFG Blast furnace gas ST 0.05844 BG Bagasse ST 0.13027 BIT Bituminous coal ST 0.10282 BLQ Black liquor ST 0.10448 BU Butane ST 0.07182 COG Coke oven gas ST 0.05844 DFO Distillate fuel oil #2 ST 0.08152 DFO Distillate fuel oil #2 GT 0.08152 DFO Distillate fuel oil #2 OT 0.08152 DFO Distillate fuel oil #2 CS 0.08152 DFO Distillate fuel oil #2 CT 0.08152 DFO Distillate fuel oil #2 CC 0.08152 DFO Distillate fuel oil #2 IC 0.08152 DG Digester gas ST 0.05739 DG Digester gas GT 0.05739 DG Digester gas OT 0.05739 DG Digester gas CS 0.05739 DG Digester gas CT 0.05739 DG Digester gas CC 0.05739 DG Digester gas IC 0.05739 DG Digester gas FC 0.05739 GEO Geothermal BT 0Still Under Agency Review

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35 Fuel Code Fuel Type Prime Mover Emission Factor (Tons CO 2 /mmBtu)
GEO Geothermal ST 0 HY Hydrogen ST 0 HY Hydrogen GT 0 HY Hydrogen CT 0 HY Hydrogen OT 0 HY Hydrogen CS 0 HY Hydrogen CC 0

IGCC Integrated gasification combined cycle burning BIT IG 0.10282

JF Jet fuel GT 0.07962 JF Jet fuel IC 0.07962 JF Jet fuel CC 0.07962 KER Kerosene GT 0.08067 KER Kerosene IC 0.08067 LB Liquid byproduct ST 0.08209 LFG Landfill gas ST 0.05739 LFG Landfill gas GT 0.05739 LFG Landfill gas OT 0.05739 LFG Landfill gas CS 0.05739 LFG Landfill gas CT 0.05739 LFG Landfill gas CC 0.05739 LFG Landfill gas FC 0.05739 LIG Lignite coal ST 0.10771 MH Methanol ST 0.06984 MSB MSW biomass component ST 0.10339 NG Natural gas ST 0.05844 NG Natural gas GT 0.05844 NG Natural gas OT 0.05844 NG Natural gas CS 0.05844 NG Natural gas CT 0.05844Still Under Agency Review

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36 Fuel Code Fuel Type Prime Mover Emission Factor (Tons CO 2 /mmBtu)
NG Natural gas CC 0.05844 NG Natural gas IC 0.05844 NG Natural gas FC 0.05844 OBG Other biomass gas CC 0.05739 OBG Other biomass gas GT 0.05739 OBG Other biomass gas ST 2.01492 OBG Other biomass gas FC 0.05739 OBL Other biomass liquid ST 0.08989 OBL Other biomass liquid GT 0.08989 OBL Other biomass liquid CT 0.08989 OBL Other biomass liquid OT 0.08989 OBL Other biomass liquid CS 0.08989 OBL Other biomass liquid CC 0.08989 OBS Other biomass solid ST 0.11632 OG Other gas ST 0.05844 OG Other gas GT 0.05844 OG Other gas CC 0.05844 OO Other oil ST 0.08152 OTL Other liquid ST 0.08209 OTL Other liquid GT 0.08209 OTL Other liquid OT 0.08209 OTL Other liquid CS 0.08209 OTL Other liquid CT 0.08209 OTL Other liquid CC 0.08209 OTS Other solid ST 0.11289 PC Petroleum coke ST 0.11256 PC Petroleum coke GT 0.11256 PC Petroleum coke CT 0.11256 PC Petroleum coke OT 0.11256 PC Petroleum coke CS 0.11256Still Under Agency Review

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37 Fuel Code Fuel Type Prime Mover Emission Factor (Tons CO 2 /mmBtu)
PC Petroleum coke CC 0.11256 PG Propane gas ST 0.06774 PP Paper pellets ST 0.10339 PRG Process gas ST 0.05844 RFO Residual fuel oil #6 ST 0.08278 RFO Residual fuel oil GT 0.08278 RFO Residual fuel oil CC 0.08278 RG Refinery gas ST 0.07356 SC Synthetic coal ST 0.10529 SLW Sludge waste ST 0.11632 SUB Subbituminous coal ST 0.10711 SUN Sun PV 0 TDF Tire

- derived fuel ST 0.06376 WAT Water HY 0 WC Waste coal ST 0.10529 WDL Wood liquid ST 0.08989 WDS Wood solid ST 0.10339 WND Wind WS 0 WND Wind WT 0 WO Waste oil ST 0.08209 WO Waste oil CC 0.08209 WO Waste oil GT 0.08209Still Under Agency Review

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Data Codes

The following data codes are codes used by the EIA in the EIA

- 860 and EIA

- 923 forms to indicate a unit’s prime mover, fuel type, and status.

Prime Mover Code Prime Mover Description BA Energy Storage, Battery

BT Turbines Used in a Binary Cycle (including those used for geothermal

applications) CA Combined Cycle Steam Part

CC Combined Cycle Total Unit (use only for plants/generators that are in planning

stage, for which specific generator details cannot be provided) CE Energy Storage, Compressed Air CP Energy Storage, Concentrated Solar Power

CS Combined Cycle Single Shaft (combustion turbine and steam turbine share a

single generator) CT Combined Cycle Combustion Turbine Part ES Energy Storage, Other FC Fuel Cell FW Energy Storage, Flywheel

GT Combustion (Gas) Turbine (does not include the combustion turbine part of a

combined cycle; see code CT, below) HA Hydrokinetic, Axial Flow Turbine HB Hydrokinetic, Wave Buoy HK Hydrokinetic, Other

HY Hydroelectric Turbine (includes turbines associated with delivery of water by

pipeline) IC Internal Combustion Engine (diesel, piston, reciprocating) OT Other PS Energy Storage, Reversible Hydraulic Turbine (Pumped Storage) PV Photovoltaic

ST Steam Turbine, including nuclear, geothermal and solar steam (does not include

combined cycle) WS Wind Turbine, OffshoreStill Under Agency Review

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WT Wind Turbine, Onshore

Fuel Type Code Energy Source Description

AB Agricultural By

- Products ANT Anthracite Coal BFG Blast Furnace Gas BIT Bituminous Coal BLQ Black Liquor DFO Distillate Fuel Oil (including diesel, No. 1, No. 2, and No. 4 fuel oils) GEO Geothermal JF Jet Fuel KER Kerosene LFG Landfill Gas LIG Lignite Coal MSW Municipal Solid Waste MWH Electricity used for energy storage NG Natural Gas NUC Nuclear (including Uranium, Plutonium, and Thorium) OBG Other Biomass Gas (including digester gas, methane, and other biomass gases) OBL Other Biomass Liquids OBS Other Biomass Solids OG Other Gas OTH Other PC Petroleum Coke PG Gaseous Propane PUR Purchased Steam RC Refined Coal RFO Residual Fuel Oil (incl. Nos. 5 & 6 fuel oils, and bunker C fuel oil) SGC Coal

- Derived Synthesis Gas SGP Synthesis Gas from Petroleum Coke SLW Sludge Waste SUB Subbituminous Coal SUN SolarStill Under Agency Review

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Fuel Type Code Energy Source Description

TDF Tire

- derived Fuels

WAT Water at a Conventional Hydroelectric Turbine, and water used in Wave Buoy

Hydrokinetic Technology, Current Hydrokinetic Technology, and Tidal Hydrokinetic Technology

WC Waste/Other Coal (incl. anthracite culm, bituminous gob, fine coal, lignite waste,

waste coal)

WDL Wood Waste Liquids excluding Black Liquor (including red liquor, sludge wood,

spent sulfite liquor, and other wood

- based liquids)

WDS Wood/Wood Waste Solids (incl. paper pellets, railroad ties, utility poles, wood

chips, bark, and wood waste solids)

WH Waste heat not directly attributed to a fuel source (WH should only be reported

when the fuel source is undetermined, and for combined cycle steam turbines that do not have supplemental firing.) WND Wind

WO Waste/Other Oil (including crude oil, liquid butane, liquid propane, naphtha, oil

waste, re

- refined motor oil, sludge oil, tar oil, or other petroleum

- based liquid wastes)

Unit Status Code Status Code Description

IP Planned new generator canceled, indefinitely postponed, or no longer in resource

plan

L Regulatory approvals pending. Not under construction but site preparation could

be underway

OA Out of service

– was not used for some or all of the reporting period but is

expected to be returned to service in the next calendar year.

OP Operating

- in service (commercial operation) and producing some electricity.

Includes peaking units that are run on an as needed (intermittent or seasonal) basis.

OS Out of service

– was not used for some or all of the reporting period and is NOT

expected to be returned to service in the next calendar year. OT OtherStill Under Agency Review

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41

P Planned for installation but regulatory approvals not initiated; Not under

construction RE Retired

- no longer in service and not expected to be returned to service.

SB Standby/Backup

- available for service but not normally used (has little or no

generation during the year) for this reporting period.

T Regulatory approvals received. Not under construction but site preparation could

be underway

TS Construction complete, but not yet in commercial operation (including low power

testing of nuclear units)

U Under construction, less than or equal to 50 percent complete (based on

construction time to date of operation)

V Under construction, more than 50 percent complete (based on construction time to

date of operation)

Description of Baseline Data Fields The following table provides a description of the data fields in the 111(d) baseline file with an indication of the data sources used to populate each field.

Field Description Source
Category Category based on the inclusion criteria of each generator --
State State in which the plant is located EIA

- 860 Plant Name Plant name EIA

- 860

ORIS Code EIA Office of Regulatory Information Systems Plant Location plant or facility code EIA

- 860

Generator ID Generator identification code EIA

- 860 Fuel type Primary fuel type of the generator EIA

- 860

Prime mover type The engine, turbine, water wheel, or similar machine that drives an electric generator; or, for reporting purposes, a device that converts EIA

- 860Still Under Agency Review

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42

Field Description Source energy to electricity directly (e.g., photovoltaic solar and fuel cells). Nameplate Capacity (MW) The full capacity value of power output from the generator EIA

- 860
Summer Nameplate Capacity (MW) The full capacity value of power output from the generator during the summer EIA

- 860

Electric Generation (MWh) Net electricity generation of the unit EIA

- 923, EPA Pa rt 75 data Carbon Dioxide Emissions (tons) The annual carbon dioxide emissions from each generator in tons EPA Part 75 data, EIA

- 923

UNITKEEP (CA<25 part of CC with CT>25) If all of the turbine parts (prime mover =CT) of an NGCC system have a nameplate capacity > 25MW, then all of the steam parts (prime mover = CA) are included in the baseline, regardless of whether they have a nameplate capacity >25MW. In this case, the UNITKEEP field will be equal to 1. It will be blank otherwise. --

Source Category T he type of industry in which the generator is located. Options include electric utility, independent power producer (IPP), industrial, or commercial. EIA

- 860

Cogn Flag Y/N Indicates the cogeneration status of each generator

– yes (Y) or no (N). EIA

- 860

Unit Status The operating status of the generator EIA

- 860

Unit Retirement Year The actual or planned retirement year of the generator EIA

- 860

Exclusion Description Description of why the generator was excluded in the “Category” field --

Commenced Operations in Data Year If the generator commenced operations within the data year, the field is marked “Yes.” This field is left blank for all other generators. EIA

- 860

Changes from File for Proposed Rule Description of changes made to the data that differ from the baseline file created for the --Still Under Agency Review

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Field Description Source Proposed Rule, including changes made based on public comments. NERC Interconnection NERC region in which the plant is located EIA

- 860

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

3A-1 

## A PPENDIX 

## 3A: A NALYSIS OF 

## P OTENTIAL 

## U PSTREAM 

## M ETHANE 

## E MISSIONS


## C HANGES IN 

## N ATURAL 

## G AS 

## S YSTEMS AND 

## C OAL 

## M INING



### The purpose of this appendix is to desc ribe the methodology for estimating upstream methane emissions related to natural gas system s and coal mining sectors that may result from the illustrative plan approaches examined in the Regulatory Impact Analysis (RIA). The US Environmental Protection Agency (EPA) assessed whether the net change in upstream methane emissions from natural gas and coal production is likely to be positive or negative and also assessed the potential magnitude of th ese upstream changes relative to CO 2 

### emissions reductions anticipated at power plants from the illustrativ e plan approaches examined in the RIA. In addition to estimating changes in upstream me thane emissions, this assessment included estimating CO 2 

### from the flaring of methane, but did not examine other potential changes in other upstream greenhouse gas emissions changes from na tural gas systems and coal mining sectors.

The methodologies used to project upstream emissions were previously developed for the purpose of the 2014 U.S. Climate Action Report, a nd were subject to peer review and public review as part of the publication of that report. In s ection 3A.1, the overall approach is described in brief. In section 3A.2, results are pres ented. Section 3A.3 discu sses uncertainties and limitations of the analysis. Finally, section 3A.4 c ontains a bibliography of cited resources. In the RIA for the Clean Power Plan proposal (in th en section 3A.3), we presented the detailed methodologies for how methane and flaring-related CO 2 

### projections were estimated for coal mining and natural gas systems. We rely on the same methods in this RIA, so we refer the interested reader to the proposal RIA 1 

### for the detailed methodological discussion. The calculations have been updated to reflect input data from the most recent U.S. GHG Inventory, published in April 2015.

1 Clean Power Plan proposal RIA can be found at < http://www2.epa.gov/sites/production/files/2014-

06/documents/20140602ria-clean-power-plan.pdf>.

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

3A-2 3A.1 General Approach

3A.1.1 Analytical Scope

Upstream methane and flaring-related CO 2 

### emissions associated with coal mining and natural gas systems were estimated for 2025 through 2030 using methodologies developed for the 2014 U.S. Climate Action Report (U.S. Depart ment of State 2014). The base year for the projections is 2013, as reported in the 2015 U. S. GHG Inventory (EPA 2015a). The projection methodologies use activity driver data outputs such as coal and natural gas production from the base case and policy scenarios generated by th e Integrated Planning Model (IPM), which was

used in the RIA to model illu strative plan approaches. The pr ojection methodologies use similar activity data and emissions fact ors as are used in the U.S. Greenhouse Gas (GHG) Inventory.

The projection methodologies es timate reductions associated with both voluntary and regulatory programs affecting ups tream methane-related emissions . In the case of the voluntary programs, the rate of reductions is based on th e historical average decrease from these programs over recent years. In the case of regulatory re ductions, the reductions are based on the reduction

rates estimated in the RIAs of relevant regulations. The projec tions include emissions reductions projected to result from the 2012 Oil and Natu ral Gas New Source Performance Standards. The methodologies to estimate upstream emissions were subject to expert p eer review and public

review in the context of the 2014 U.S. Climate Action Report. For more information on the review, or for the detailed methodologies used for non-CO 2 

### source projections in that report, including methane-related emissions from co al production and natural gas systems, see “Methodologies for U.S. Greenhouse Gas Emissions Projections: Non-CO 2 

### and Non-Energy CO 2 

### Sources” (EPA, 2013). Uncertainties and limitations are discussed, including a side case which incorporates additional geographic informati on for estimating methane from coal mining.

The term “upstream emissions” in this document refers to vented, fugitive and flared emissions associated with fuel production, proces sing, transmission, storage, and distribution of fuels prior to fuel combustion in electricity plants. For this analysis, the EPA focused on upstream methane from the natural gas systems and coal mining sectors. In addition, the analysis

included CO 2 

### resulting from flaring in natural gas produc tion. This analysis does not assess other upstream GHG emissions changes, such as CO 2 

### emissions from the combustion of fuel used in

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

3A-3 natural gas and coal production ac tivities or other non-combustion CO 2 

### emissions from natural gas systems, such as vented CO 2 

### and CO 2 

### emitted from acid-gas removal processes.

Also, the EPA assessed potential upstream me thane emissions from natural gas systems and coal mining sectors within the domestic U.S ., but did not examine emissions from potential changes in upstream emissions generated by changes in natural ga s and coal production, processing, and transportation act ivities outside of the US. 2 

### Last, the EPA did not assess potential changes in other upstream non-GHG emi ssions, such as nitrogen oxides, volatile organic compounds, and particulate matter. Tabl e 3A-1 presents estimates of the upstream emissions discussed in this analyses for 2013, based on the 2015 U.S. GHG Inventory.

EPA defined the boundaries of this assessment in order to provide targeted insights into the potential net change in methane emissions from natural gas systems and coal production activities specifically. CO 2 

### emissions from flared methane are included because regulatory and voluntary programs influence the rate of methane flaring over time and the CO 2 

### remaining after flaring is a methane-related GHG. Because of th e multiple strategies ad opted in the illustrative plan approaches, a more comprehensive assessm ent of upstream GHG emissions would require examination of the broader power sector and rela ted input markets and their potential changes in response to the rule. This analys is would be complex and likely subject to data limitations and
substantial uncertainties. Rather, EPA chose to limit the scope of this upstream analysis to evaluate the potential for change s in GHG emissions that may be of significant scale relative to the impacts of the rule and for which EPA had previously-reviewed projection techniques, which are presented in detail below.

3A.1.2 Coal Mining Source Description

Within coal mining, this analysis covers f ugitive methane emissions from coal mining (including pre-mining drainage) and post-mining activities (i.e., coal handling), including both underground and surface mining. Emissions from abandoned mines are not included. Energy-

2 While the analysis does not estimate methane emissions changes outside of the United States, activity factors

include imports and exports of natural gas to help estimat e domestic methane emissions related to trade of natural gas, such as emissions from LNG terminals in the US or from pipelines transporting imported natural gas within the US (or transporting natural gas within the US while en route for export).

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

3A-4 related CO 2 

### emissions, such as emissions from mining equipment and vehicles transporting coal
are not included. Methane, which is contained w ithin coal seams and the surrounding rock strata, is released into the atmosphere when mini ng operations reduce the pressure above and/or surrounding the coal bed. The quantity of methane emitted from these operations is a function of two primary factors: coal rank and coal depth. Coal rank is a measure of the carbon content of the coal, with higher coal ranks corresponding to higher carbon content and generally higher methane content. Pressure increases with dept h and prevents methane from migrating to the surface; as a result, underground mining operations typically emit more methane than surface mining. In addition to emissions from undergr ound and surface mines, post-mining processing of

coal and abandoned mines also release methane. Po st-mining emissions refer to methane retained

in the coal that is releas ed during processing, storage, and transport of the coal.

3A.1.3 Natural Gas Systems Source Description

Within natural gas systems, this analysis covers vented and fugitive methane emissions from the production, processing, transmission and storage, and distribut ion segments of the natural gas system. It also includes CO 2 

### from flaring of natural gas. Not included are vented and fugitive CO 2 

### emissions from natural gas systems, such as vented CO 2 

### emissions removed during natural gas processing, or energy-related CO 2 

### such as emissions from stationary or mobile combustion. The U.S. natural gas system encompasses hundreds of thousands of wells, hundreds of processing facilities, and over a million m iles of transmission and distribution pipelines.

Methane and non-combustion 3 

### CO 2 

### emissions from natural gas systems are generally processrelated, with normal operations, routine mainte nance, and system upsets being the primary contributors. There are four primary stages of th e natural gas system which are briefly described

below.

Production: In this initial stage, we lls are used to withdraw raw gas from underground

formations. Emissions arise from the wells them selves, gathering pipelin es, and well-site gas treatment facilities (e.g., dehydrat ors, separators). Major emissions source categories within the

3 In this document, consistent with IPCC accounting term inology, the term “combustion emissions” refers to the

emissions associated with the combustion of fuel for useful heat and work, while “non-combustion emissions” refers to emissions resulting from other activities, including flaring and CO 2 removed from raw natural gas.

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

3A-5 production stage include pneuma tic devices, gas wells with liquids unloading, and gas well completions and re-completions (i.e., workovers ) with hydraulic fracturing (EPA 2013). Flaring emissions account for the majority of the non-combustion CO 2 

### emissions within the production
stage.
Processing: In this stage, natural gas li quids and various other const ituents from the raw gas are removed, resulting in “pipeline-quali ty” gas, which is then injected into the transmission system. Fugitive methane emissions from compressors, including compressor seals, are the primary emissions source from this stage. In the U.S. GHG Inventory, the majority of non-combustion

CO 2 

### emissions in the processing stage come from acid gas removal units, which are designed to

remove CO 2 

### from natural gas.

Transmission and Storage: Natural gas transmission involve s high-pressure, large-diameter pipelines that transport gas long distances from field production a nd processing areas to distribution systems or large-volume customers such as power plants or chemical plants. Compressor station facilities, which contain la rge reciprocating and turbine compressors, are used to move the gas throughout the U.S. transm ission system. Fugitive methane emissions from these compressor stations and from metering and re gulating stations account for the majority of the emissions from this stage. Pneumatic devi ces and non-combusted engi ne exhaust are also

sources of methane emissions from transmission faci lities. Natural gas is also injected and stored in underground formations, or liquefied and stor ed in above-ground tanks, during periods of lower demand (e.g., summer), and withdrawn, pro cessed, and distributed during periods of higher demand (e.g., winter). Compressors and dehydrators are the primary contributors to emissions from these storage facilities. Emi ssions from LNG import terminals are included within the transportation and storage stage.

Distribution: Distribution pipelines take the high-pressu re gas from the transmission system at “city gate” stations, reduce the pressure, a nd then distribute the gas through primarily underground mains and service lines to individual end users.

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

3A-6 Table 3A-1. Base Year Upstream Methane-Rel ated Emissions in the U.S. GHG Inventory

Emissions Source 2013 Emissions (million metric tons CO 2 Eq.) Methane from Coal Mining 64.6 Underground Mining and Post-Mining 52.8 Surface Mining and Post-Mining 11.8 Methane from Natural Gas Systems 157.4 Production 47.0 Processing 22.7 Transmission and Storage 54.4 Distribution 33.3 CO 2 from flaring of natural gas 15.5 Source: 2015 U.S. GHG Inventory (EPA, 2015). A Global Warming Potential of 25 was used to convert methane emissions to CO 2 Eq.


### In Table 3A-1, CO 2 

### -equivalent methane emissions are presented using the Fourth Assessment Report Global Warming Potential (GWP) of 25.

3A.1.4 Illustrative Plan Approaches Examined

States will ultimately determine optimal approaches to comply with the goals established in this regulatory action. The RIA depicts illu strative plan approaches for the final emissions guidelines.

3A.1.5 Activity Drivers

IPM-based activity driver projections from base case and illustrative plan approaches underlie the estimates of upstream methane emi ssions. These activity drivers include domestic coal and natural gas production, imports and expo rts, and natural gas consumption. Table 3A-2

and Table 3A-3 summarize the IPM-based coal and natural gas production activity driver results from the baseline and illustrative scenario for the final guidelines. 4



### Under the final guidelines, we estimate that the rate-based scenario will result in 5 percent, 12 percent and 22 percent reductions in coal production in 2020, 2025 and 2030, respectively, relative to base case coal production. Natural gas production in 2020 increases by about 1 percent relative to the base case , while natural gas production in 2025 and 2030 in unchanged under the final guidelines rela tive to production in the base case.

4 Uncertainties related to activity drivers are discus sed in the uncertainties and limitations section.

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

3A-7 Table 3A-2. Projected Coal Production Impacts

Coal Production (million short tons) Coal Production Change from Base Case (million short tons) Coal Production Percent Change from Base Case

2020 2025 2030 2020 2025 2030 2020 2025 2030
Base Case 832.4 827.2 859.1
Rate-based Scenario 791.5 724.8 673.1 -41.0 -102.0 -186.0 -5% -12% -22% Mass-based Scenario [X] [X] [X] [X] [X] [X] [X] [X] [X]



### Table 3A-3. Projected Natural Gas Production Impacts

Dry Gas Production (trillion cubic feet) Dry Gas Production Change from Base Case (trillion cubic feet) Dry Gas Production Percent Change from Base Case

2020 2025 2030 2020 2025 2030 2020 2025 2030
Base Case 28.9 30.8 33.0
Rate-based Scenario 29.1 30.7 32 .9 +0.2 -0.1 -0.1 +1% 0% 0% Mass-based Scenario [X] [X] [X] [X] [X] [X] [X] [X] [X]



### 3A.2 Results

The analytical results (Table 3A-4) for the fi nal guidelines indicates decreases in methane emissions from coal mining of 6.8 million metric tons CO 2 

### Eq. in 2025, and 12.7 million metric

tons CO 2 

### Eq. in 2030. Methane from natural gas system s decreases slightly relative to the base case in 2025 and 2030 (by less than 1 million metric tons CO 2 

### Eq. Following a similar pattern,

CO 2 

### from flaring in natural gas pr oduction does not show significan t change relative to the base

case.

Based on the actions modelle d in illustrative plan approaches, upstream methane

emissions and CO 2 

### emissions are predicted to decline (s ee Table 3A-4). The final guidelines are predicted to result in a net emissions reduction of 7.5 million metric tons CO 2 

### Eq. in 2025 and a

net emissions reduction of 13.4 million metric tons CO 2 

### Eq. in 2030. These net emissions changes represent the sum of changes in methan e from coal mining, methane from natural gas systems, and CO 2 

### from flaring in natural gas producti on. The projections include voluntary and regulatory activities to reduce emissions from coal mining and natural gas and oil systems,

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

3A-8 including the 2012 Oil and Natura l Gas NSPS. In addition, the EPA plans to issue a proposed

rule later this summer that would build on its 20 12 Oil and Gas NSPS. When these standards are finalized and implemented, they would further re duce projected emissions from natural gas and oil systems.

Table 3A-4. Potential Upstream Emissions Changes Emissions (million metric tons CO 2 Eq.)
2020 2025 2030
Rate-based Scenario

Methane from Coal Mining -2.7 -6.8 -12.7 Methane from Natural Gas Systems +1.0 -0.7 -0.5
CO 2 from NG flaring +0.1 -0.0 -0.1
Total Methane + CO 2 -1.6 -7.5 -13.4
Mass-based Scenario

Methane from Coal Mining [X] [X] [X] Methane from Natural Gas Systems [X] [X] [X]
CO 2 from NG flaring [X] [X] [X]
Total Methane + CO 2 [X] [X] [X] Note: A Global Warming Potential of 25 was used to convert methane emissions to CO 2 Eq.



### 3A.3 Uncertainties and Limitations
Projections of upstream methane emissions and CO 2 

### emitted from flaring of methane are subject to a range of uncertainties and limitations. These uncertainties and limitations include estimating the effect of the plan approach on activ ity drivers, uncertainty in base year emissions, and uncertainties in changes in emissions fact ors over relatively long periods of time. For example, EPA’s application of IPM relies on EI A projections for coal imports and exports. Consequently, coal imports and exports are not able to fully respond within the IPM framework to significant fluctuations in pow er sector coal demand. To the ex tent international markets may be expected to offset reduced domestic coal demand, changes in U.S. upstream emissions as a result of the policy scenarios would be smaller than what is presented here.

Discussion of uncertainty in historical es timates of emissions from coal mining and natural gas systems can be found in the 2015 U.S. GHG Inventory. Projected changes in activity

drivers and emissions factors are based on a combination of policy, macroeconomic, energy market, and technology factors which are uncerta in in both baseline and illustrative plan

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

3A-9 approaches. Relatively higher or lower economic gr owth, or changes in th e relative prices or availability of various technologi es could result in alternative es timates in the net change in upstream methane emissions and related CO 2 

### emissions.

3A.4 References

IPCC. 2006. 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Available at <http://www.ipcc-nggip.iges.or.jp/public /2006gl/>. Accessed June 4, 2015.
U. S. Department of State. 2014. 2014 U.S. Climate Action Report to the UNFCCC. Available at <http://www.state.gov/e/oes/rls/rpts/car6/index.htm>. Accessed June 4, 2015.
U. S. Environmental Protection Agency (U.S. EPA). 1993. Anthropogenic Methane Emissions in the United States, Estimates for 1990: Report to Congress. EPA-430-R-93-003.
U. S. Environmental Protection Agency (U.S. EPA). 2011. Oil and Natural Gas Sector: Standards of Performance for Crude O il and Natural Gas Production, Transmission, and Distribution: Background Technical Suppor t Document for the Proposed Standards

. Available at <http://epa.gov/ airquality/oilandgas/pdfs/20110728tsd.pdf>. Accessed June 4,
2015.
U. S. Environmental Protection Agency (U.S. EPA). 2012a. Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air
Pollutants Reviews . 40 CFR Parts 60 and 63 [EPA- HQ-OAR-2010-0505; FRL-9665-1], RIN 2060-AP76. Available at <http://www .gpo.gov/fdsys/pkg/FR-2012-08-16/pdf/2012- 16806.pdf>. Accessed June 4, 2015.
U. S. Environmental Protection Agency (U.S. EPA). 2012b. Oil and Natural Gas Sector: Standards of Performance for Crude O il and Natural Gas Production, Transmission, and Distribution: Background Supplemental Tech nical Support Document for the Final New Source Performance Standards . Available at <http://epa.gov/air quality/oilandgas/pdfs/20120418tsd.pdf>. Accessed June 4, 2015.
U. S. Environmental Protection Agency (U.S. EPA). 2015. Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990–2013 . EPA-430-R-15-004. Available at <http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html>. Accessed June 4,
2015.
U. S. Environmental Protection Agency (U.S. EPA). 2013. Methodologies for U.S. Greenhouse Gas Emissions Projections: Non-CO 2 

### and Non-Energy CO 2 

### Sources. Available at <http://www.state.gov/documents/organ ization/219472.pdf> Accessed June 4, 2015.