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. CO2 Emission Performance Rate and State Goals TSD 

2. Spreadsheet with Appendices 1-5 of the CO2 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-2013-0602

CO2 Emission Performance Rate and 

Goal Computation Technical Support 

Document for CPP Final Rule

U.S Environmental Protection Agency

Office of Air and Radiation

August 2015
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2

Category-Specific Performance Rates and State Goal 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 the category-specific performance standards through a state goal 

metric reflecting likely covered fossil sources in a state. The Greenhouse Gas (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 detailed 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 factors informing the category-specific performance rates and state emission rate goals

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 from higher emitting fossil EGUs 

2. Form of the Category-specific Performance Rates and State Goals

3. Baseline data used to derive performance rates and state goals

a. Emissions & Generation Integrated Resource Database (eGRID)

b. Data sources for affected “under construction” units

c. Region-level baseline

4. Methodology for determining category-specific performance rates

5. Methodology for converting category-specific performance rates into state emission rate goals

6. Methodology for converting state emission rate goals into mass goals

7. Appendix (attached Excel Workbook)

 Appendix 1 – Underlying 2012 unit-level baseline inventory and data

 Appendix 2 - Units that commenced operation post 2011, but commenced construction 

prior to 1/8/14

 Appendix 3 – Underlying state-level data, adjustments, and region-level data

 Appendix 4 – Computation of the category-specific performance 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 adjustment 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.
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3

In EPA’s technical evaluation, it assessed the cost and potential of 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 blocks 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 Rates 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 

historical 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 determined 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 of total NGCC 

Generation at 75% 

Utilization, (Amount of 

NGCC Generation Potential 

Incremental to Baseline)

BB3 - Incremental 

RE Potential (TWh)

Eastern Interconnection 4.3% 988, (253) 438

Western Interconnection 2.1% 306, (108) 161

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-specific performance rates 

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 emission 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 level rather than the combined 

affected source level:
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4

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 adjusted emissionsfor affected fossil steam sources

BSER adjusted generation for affected fossil steam sources + replacement generation

BSER for NGCC = BSER adjusted emissionsfor affected NGCC sources

BSER adjusted generation 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 significant comments regarding unit-level data and applicability 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 applicability status. The updated unit-level data is available in Appendix One and 

reflects changes to unit data based on comments.

In addition to unit-level data updates, the EPA also made some targeted baseline adjustments at the statelevel 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 

portfolios (adjustment calculations in appendix 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 commencing 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 emissions

- State and regional-level oil/gas steam generation

- State and regional-level oil/gas steam emissions

- State and regional-level NGCC generation

- State and regional-level NGCC emissions

- State and regional-level NGCC capacity
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5

All generation values are expressed as net generation. Emission rate values are net emission rates and 

expressed as lbs/MWh. The NGCC capacity expressed is net summertime capacity in megawatts. At 

proposal, there was a limited number of high utilization combustion turbines and integrated 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 combustion turbines that are likely affected 

units under this rule. The IGCCs that are likely affected by the rule are included with the coal steam 

totals consistent with their fuel use and reporting under subpart Da.

a. Emissions & Generation Integrated Resource Database (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 integrates many different data 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 methodology 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 state 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 basic 

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.5.15 reflecting some of the unitlevel information EPA received in the comment period. For a description of the sources used in preparing 

NEEDS v.5.15, 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 been identified at Proposal. Per commenter suggestion, EPA performed an additional review of under 

construction units using EIA 860 data, NEEDS v.5.15, 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/
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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 regions reflect the Eastern, Western, and Texas Interconnections. These 

regions were used when quantifying the best system of emission reductions in order to capture the 

interstate effects of the building blocks. The rationale for the regional structure is explained in preamble 

section V.A.3.e. For each region, the EPA made BSER-related adjustments to the baseline data to 

determine the effect the three building block abatement measures could have on the average fossil steam 

rate and the average NGCC rate in that region. In making adjustments to region-level data, the EPA is 

simply identifying the BSER reductions that can be achieved on average at the regional level relative to 

baseline level. The EPA is not making any assertions about specific units or plant capability. The EPA 

recognizes the uniqueness and complexity of individual power plants, and is aware that there are sitespecific 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 the BSER values to historical

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 emission 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 different 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 areas 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 regionallevel 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.
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EPA received some comment suggesting that it should remove units scheduled 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 recently 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 projectioninformed 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. 
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4. Methodology for Determining Category-specific Emission Performance Rates

EPA’s methodology for calculating category-specific performance rates is described in 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 historical 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 system 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 unit-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 unadjusted 2012 baseline 

data for units that commenced operation prior to 2012. For states that have likely affected sources in two different interconnections, EPA 

segmented these states into their relevant interconnect portions at this step (e.g., the Montana Eastern Interconnection and Montana Western 

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.

EPA 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 year 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 affected 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 full-year utilization for these units (columns F & G). 

 

4 As described in the GHG Mitigation Measures TSD, the building blocks 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.
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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 hours*2,165 MW*55% capacity factor = 25.52 TWh5

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 subsequent 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 new coal) based on a review of 

utilization patterns for units that commenced operation during the previous five years. The 2,165 capacity 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 number 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.
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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

 

328,233

 

734,542

 

52,979

 

74,241 

Step 3: Identify category-specific baseline emission rates for fossil steam and NGCC

Fossil 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) reflects the sum of coal 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 improvements) 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

 

328,233

 

734,542

 

52,979

 

74,241 

 

2,160

 

1,304,674 894

 

734,542

Eastern Fossil Steam Rate = (coal emissions + 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 GWh)
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Eastern NGCC Rate = NGCC emissions = Eastern NGCC Rate = 328,233 tons

 NGCC gen 734,542 GWh

Step 4: Calculate regional 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 to 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 Eastern 

Interconnection applied only to the coal steam fleet. This is reflected by adjusting the coal emissions down by the region-specific HRI percentage 

and leaving 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 coal steam (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 

(GWh)

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 

 

2,160 4.3%

 

1,297,740 

 

2,071

When the technology emission rate is recalculated with building block 1 reflected in the adjustment to the region’s coal emissions, 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 adjusted from their baseline level at 

this step. In this example, the fossil steam rate drops from a baseline value of 2,160 lb/MWh to 2,071 lb/MWh after building block 1 application.
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12

Eastern fossil Steam Rate = (coal emissions *(1-HRI%) + (OG emissions) = Eastern fossil steam rate = (1,356,050,000 tons)*0.957 + 52,979,000 tons

 Coal gen + OG gen (1,230,434 GWh + 74,241 GWh)

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 category-specific performance rates and state goals for the final 

rule only reflect this incremental RE total. All incremental BB3 RE is assumed to emit zero tons of CO2.

For this final rule, EPA assumes that BB3 incremental generation replaces 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 steam (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 represents. For example, if a region had 100 MWh of potential BB3 generation 

identified, and baseline fossil steam accounted for 70% of the region’s generation from affected units and NGCC accounted for 30%, then the 100 

MWh of incremental RE identified would be assumed to replace 70 MWh of fossil steam generation and 30 MWh of NGCC generation. The 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) equals the total remaining generation and renewable 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 Reflecting 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

 

1,304,674

 

734,542 64% 36%

 

438,445

 

1,024,161 576,611 280,513 157,931
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Eastern Fossil Steam Gen = Baseline Fossil Steam Generation - (Potential BB3 Gen x fossil steam share of total fossil generation)

Eastern Fossil steam Gen = 1,304,674 – (438,445 * 64%) = 1,024,161GWh

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 GWh

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 significantly less generation than the potential identified in building block 2 that reflects a 75% utilization. If only 

implementing 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 generation with lower 

emitting gas generation, identified as building block 2. This step of the rate calculation captures the change in source-category generation levels 

associated with building block 2 potential of a 75% potential utilization for the NGCC fleet.

To incorporate building block 2, the 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 

represents a generation ceiling, and the region’s NGCC generation 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 deployment schedule is discussed in the GHG Mitigation Measures TSD.
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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

 

1,024,161 576,611 987,956 411,345 612,816 987,956

In the above example, NGCC generation is adjusted upwards by approximately 411 TWh (column E) to 987,956 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

Eastern Fossil steam Gen = 1,024,161 – (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+ (987,956 – 576,611) = 987,956 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 the Post BB3 fossil steam generation amount that it replaced. 
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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 categoryspecific 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 step three (column C) to get the amount of incremental NGCC emissions 

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 remaining 

fossil 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 generation (column H), and 3) the 

 

8 As described in the preamble, EPA reflected the incremental NGCC generation (and corresponding emissions) in the fossil steam rate source category rate and 

created a parallel compliance structure for quantifying NGCC ERCs which fossil steam sources may use in compliance. This was necessary to create a fossil 

steam source-category rate that reflected generation shifting due to BB2.

9 EPA also considered quantifying the amount of NGCC generation 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 made 

when measuring and quantifying NGCC ERCs available for compliance. In other words, there would be a lower rate, but more credits available. EPA 

determined that measuring incremental NGCC generation to include in the fossil steam rate was more appropriately done using a baseline level (premised on 

historical generation) as it would facilitate appropriate measurement and identification of NGCC ERCs. EPA took the more conservative 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 would be available if sources chose 

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 historical measurement basis for ERCs. 
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16

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 amount of NGCC emissions post BB3 and BB2. These emissions 

are then divided 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)

Eastern Fossil steam Gen = (612,816 GWh * 2,071lb/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)

(987,956 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 generation.

A B C D E F G H I J K L M

Interconnection

Fossil 

Steam 

Rate

NGCC 

Rate

Fossil Steam 

Gen NGCC Gen

Fossil 

Steam 

Rate

NGCC 

Emission 

Rate

BB3 Replacing 

Fossil Steam

BB3 Replacing 

NGCC

Remaining 

Fossil Steam

Remaining 

NGCC Gen

Fossil 

Steam 

Rate

NGCC 

Rate

lb/MWh lb/MWh GWh GWh lbs/MWh lbs/MWh GWh GWh GWh GWh lb/MWh lb/MWh

Eastern 2,160 894 1,304,674 734,542 2,071 894 280,513 157,931 612,816 987,956 1,305 771

Table 7. Adjusted Fossil Steam and NGCC Generation Rates Reflecting all Three Building Blocks

Baseline BB1 HRI BB3 Apportioned to Fossil Post BB2 Final Rates
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Step 8: Identify the least stringent regional rate as the emission performance rate for the technology source category 

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 Stringent 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 results in a 2030 emission performance rate for each source category. However, as described in the GHG 

Mitigation Measures TSD, the BB2 and BB3 assumed potential changes 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 rulemaking 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 fractional 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 limiting region for 2027 through 

2030.
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For the Final CPP Rule category-specific rates:

Interim category-specific rate – Average of the adjusted yearly emission rates for the period 2022-2029 

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

The 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 goals. A state is not 

required to base its state plan on using the same set of measures or the same amount of any measure reflected 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 standards of 

performance established for it in the state plan and the extent to which the source 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 goal = (Fossil steam source category rate * Fossil steam baseline share of affected generation) + (NGCC source category rate * 

NGCC baseline share of affected generation)

2022 2023 2024 2025 2026 2027 2028 2029 2030 Interim Final

Fossil Steam 1,741 1,681 1,592 1,546 1,500 1,453 1,404 1,355 1,304 1,534 1,305

NGCC 898 877 855 836 817 798 789 780 771 832 771

Annual Category-specific Rates
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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 rate 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

Placeholder
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7. APPENDIX

Appendix 1 – Underlying 2012 unit-level baseline inventory and data

See “Appendix 1-unit-level data” worksheet in the Excel attachment titled “Baseline, Category-specific rates, and State Goal 

Quantification”

Appendix 2 - Units that commenced operation post 2011, but began construction prior to 1/8/14

See “Appendix 2 – Under construction” worksheet in the Excel attachment 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 attachment titled “Baseline, Category-specific rates, and State Goal 

Quantification”

Appendix 4 – Computation of the category-specific performance rates (Interim and Final)

See “Appendix 4 – category-specific calc.” worksheet in the Excel attachment titled “Baseline, Category-specific rates, and State 

Goal Quantification”

Appendix 5 - Computation of the state goal (Interim and Final)

See “Appendix 5 – State Goals” worksheet in the Excel attachment titled “Baseline, Category-specific rates, and State Goal 

Quantification”
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Appendix 6 –State Goals

State Interim Goal Final Goal State Interim Goal Final Goal

Alabama 1,156 1,018 Nebraska 1,522 1,296

Arizona 1,173 1,031 Nevada 941 855

Arkansas 1,304 1,130 New Hampshire 946 858

California 906 828 New Jersey 885 812

Colorado 1,362 1,174 New Mexico 1,325 1,146

Connecticut 851 786 New York 1,024 918

Delaware 1,022 916 North Carolina 1,311 1,136

Florida 1,026 919 North Dakota 1,534 1,305

Georgia 1,197 1,049 Ohio 1,383 1,190

Idaho 831 771 Oklahoma 1,222 1,068

Illinois 1,455 1,245 Oregon 963 871

Indiana 1,451 1,242 Pennsylvania 1,258 1,095

Iowa 1,505 1,283 Rhode Island 831 771

Kansas 1,518 1,293 South Carolina 1,337 1,156

Kentucky 1,509 1,286 South Dakota 1,351 1,166

Louisiana 1,292 1,121 Tennessee 1,410 1,211

Maine 841 779 Texas 1,187 1,042

Maryland 1,510 1,287 Utah 1,368 1,179

Massachusetts 901 824 Virginia 1,046 934

Michigan 1,354 1,169 Washington 1,110 983

Minnesota 1,413 1,213 West Virginia 1,534 1,305

Mississippi 1,060 945 Wisconsin 1,364 1,176

Missouri 1,490 1,272 Wyoming 1,526 1,299

Montana 1,534 1,305
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Appendix 7 –Adjustments to state-level 2012 baseline data

See the Excel attachment 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 state. 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 year 

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 generation relative to observed 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 sensitive to fluctuations 

in hydro generation and thus increased the fossil generation in the state from observed 2012 levels to reflect potential generation levels in an 

average hydro year.

Unit-outage adjustment

As explained in the Preamble Section VI, EPA did not generally view single unit-outages as problematic to its baseline for determining sourcecategory rates or state goals. As regional load levels did not change subject to the unit outage, the decrease at a particular 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 have 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 25% 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.
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Appendix 8 – Category-specific emission rates under building block severability

See “Appendix 9” worksheet in the Excel attachment titled “BB Severability” which replicates EPA quantification of BSER 

assuming only building blocks 1 and 2
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Appendix 9- Description of 111(d) baseline data sources and development

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 

CO2 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-86013 and EIA-92314 with data on CO2 emissions 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 differences between 

the baseline released for the Clean Power Plan Proposed Rule16 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/electricity/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.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electric-utilitygenerating
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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 CO2 emissions and heat input. 

EPA Part 75 emissions data is presented at the unit 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 identifies 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 different 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, existing and proposed plants are required to submit Forms 

860 and 923 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 EIA with data on CO2

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 CO2 emissions are added to this foundation 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. 
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CO2 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 generator 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 cannot 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 components are summed and distributed to all generators based on proportion 

of nameplate capacity.

Because there are different regulations governing 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 listed 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 Change (IPCC)17 and 

in EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks.18 CO2 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 CO2 emissions from EPA are matched with net electricity generation data from EIA, an emissions rate (lbs. CO2 per MWh) is calculated. If 

the calculated emissions rate is unreasonably high (>10,000 lbs. CO2 per MWh) or unreasonably low (<500 lbs. CO2 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 Sinks: 1990-2012, Washington, D.C., April 2014. http://epa.gov/climatechange/emissions/usinventoryreport.html

19 TCR, 2014: The Climate Registry 2014 Climate Registry Default Emission Factors, Washington DC,

January 10, 2014. http://www.theclimateregistry.org/tools-resources/reporting-protocols/generalreportingprotocol/
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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 uses data on gross 

generation from EIA.21 If 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 negative net electricity generation (for example, the facility uses more electricity than it produces) and CO2

emissions, the electricity generation is adjusted using gross electricity generation data as described above. This correction is intended to avoid 

estimating 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 reported 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 nameplate capacity, prime mover type, fuel, and operating status, as shown in table 2.

Table 2. Criteria 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 information and data related to 

the electricity generation sector. The factors are developed using North American Reliability Corporation (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.
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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, only 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 likely be considered COALST units if 

operational. For the 2012 111(d) baseline, units can be listed as UCCoal 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 UCNGCC if they are under construction in 2012 or 2013.
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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 nonCHP units that supply less than one-third of their electricity 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 baseline is created by summing the CO2 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 CO2 emissions from tons to pounds by multiplying by 2,000 and then dividing 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 Station) 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.
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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 CO2 emissions data from the EPA Clean Air Markets 

Division (CAMD) with 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 defines 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 differences.

Emissions assigned to boilers 

eGRID reports emissions at the boiler level and rolled up to the plant level, but the eGRID methodology does not attempt to assign 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 boilerlevel 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 emissions 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 criteria 

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 construction, 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 listed 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) baseline 

files capture the entire universe of units, the files for the 111(d) baseline will list more units than the eGRID files.
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Updates 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 positive emissions, but 

zero or negative generation. As a result, the emission rate calculated 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 units based on their gross 

generation and net-gross 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 make sense, such as 

when CO2emissions are associated with negative net electricity generation. EPA also implemented a correction in the 111(d) baseline analysis for 

units with emission rates that are either too low or too high. For this analysis, EPA used rates less than 500 lbs. CO2/MWh as the cutoff for rates 

that are too low, and rates greater than 10,000 lbs. CO2/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 generation 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 of these corrections would result in emissions rates that were still less 

than 500 lbs. CO2/MWh or greater than 10,000 lbs. CO2/MWh, EPA left the generation data unchanged and retained the original calculated rate. 

EPA does not use this quality assurance correction 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 zero. While the eGRID 

plant file reports both the adjusted and unadjusted emissions, 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 input 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) Baselines
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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 CO2 emission rates.

In addition to these methodological changes, EPA also made non-methodological changes to the proposed file when creating the final file, 

including:

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 certain cases, when EPA emissions data collected under 40 CFR Part 75 are matched with generation data from EIA, a unit can have positive 

emissions, but zero or negative generation. This would occur if a unit uses more power than it generates. As a result, the emission rate calculated 

for this unit would be negative. To correct this issue, EPA estimated the net electricity generation from these units based on their gross generation 

and net-gross conversion factors

Using this methodology, EPA updated the generation 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 negative. EPA also 

implemented a correction for units with emission rates that are either too low or too high. For this analysis EPA used 500 lbs. CO2/MWh as the 

cutoff for rates that are too low, and 10,000 lbs. CO2/MWh as the cutoff for rates that are too high. 
Still Under Agency Review – Do not Quote, Cite, or Share

33

For these units EPA applies a correction using a two-step process. 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. CO2/MWH or greater than 10,000 lbs. CO2/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 and fuel types, 

and changing CHP flags. These changes are detailed for each unit in the unit-level 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 data year. This 

column is populated using a combination of public comments 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 NGCC”, 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. Changes 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 data 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.
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Emission Factors

The emission factors listed in the table below are used in the 111(d) baseline analysis to estimate CO2 emissions, if emissions for a given unit are 

not included in the EPA data. CO2 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 (40 CFR Part 98).

Fuel 

Code Fuel Type Prime Mover

Emission 

Factor (Tons 

CO2/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 0
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Fuel 

Code Fuel Type Prime Mover

Emission 

Factor (Tons 

CO2/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 0.05844
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Fuel 

Code Fuel Type Prime Mover

Emission 

Factor (Tons 

CO2/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 0.11256
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Fuel 

Code Fuel Type Prime Mover

Emission 

Factor (Tons 

CO2/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 0.08209
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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, Offshore
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39

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 Solar
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40

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 Other
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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-860
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–Do not Quote, Cite, or Share

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 Part 

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

The 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 – Do not Quote, Cite, or Share

43

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 

APPENDIX 3A: ANALYSIS OF POTENTIAL UPSTREAM METHANE EMISSIONS 

CHANGES IN NATURAL GAS SYSTEMS AND COAL MINING

The purpose of this appendix is to describe the methodology for estimating upstream 

methane emissions related to natural gas systems 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 these upstream changes relative to CO2 emissions reductions 

anticipated at power plants from the illustrative plan approaches examined in the RIA. In 

addition to estimating changes in upstream methane emissions, this assessment included 

estimating CO2 from the flaring of methane, but did not examine other potential changes in other 

upstream greenhouse gas emissions changes from natural 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, and were subject to peer review and public 

review as part of the publication of that report. In section 3A.1, the overall approach is described 

in brief. In section 3A.2, results are presented. Section 3A.3 discusses uncertainties and 

limitations of the analysis. Finally, section 3A.4 contains a bibliography of cited resources. In the 

RIA for the Clean Power Plan proposal (in then section 3A.3), we presented the detailed 

methodologies for how methane and flaring-related CO2 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 RIA1 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 CO2 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. Department 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 the Integrated Planning Model (IPM), which was 

used in the RIA to model illustrative plan approaches. The projection methodologies use similar 

activity data and emissions factors as are used in the U.S. Greenhouse Gas (GHG) Inventory. 

The projection methodologies estimate reductions associated with both voluntary and 

regulatory programs affecting upstream methane-related emissions. In the case of the voluntary 

programs, the rate of reductions is based on the historical average decrease from these programs 

over recent years. In the case of regulatory reductions, the reductions are based on the reduction 

rates estimated in the RIAs of relevant regulations. The projections include emissions reductions 

projected to result from the 2012 Oil and Natural Gas New Source Performance Standards. The 

methodologies to estimate upstream emissions were subject to expert peer 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-CO2 source projections in that report, 

including methane-related emissions from coal production and natural gas systems, see 

“Methodologies for U.S. Greenhouse Gas Emissions Projections: Non-CO2 and Non-Energy CO2

Sources” (EPA, 2013). Uncertainties and limitations are discussed, including a side case which 

incorporates additional geographic information for estimating methane from coal mining. 

The term “upstream emissions” in this document refers to vented, fugitive and flared 

emissions associated with fuel production, processing, 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 CO2 resulting from flaring in natural gas production. This analysis does not assess other 

upstream GHG emissions changes, such as CO2 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 activities or other non-combustion CO2 emissions from natural 

gas systems, such as vented CO2 and CO2 emitted from acid-gas removal processes. 

Also, the EPA assessed potential upstream methane 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 gas and coal production, 

processing, and transportation activities outside of the US.2 Last, the EPA did not assess 

potential changes in other upstream non-GHG emissions, such as nitrogen oxides, volatile 

organic compounds, and particulate matter. Table 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. CO2 emissions from flared methane are included because regulatory and 

voluntary programs influence the rate of methane flaring over time and the CO2 remaining after 

flaring is a methane-related GHG. Because of the multiple strategies adopted in the illustrative 

plan approaches, a more comprehensive assessment of upstream GHG emissions would require 

examination of the broader power sector and related input markets and their potential changes in 

response to the rule. This analysis 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 changes 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 fugitive 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 estimate 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 CO2 emissions, such as emissions from mining equipment and vehicles transporting coal 

are not included. Methane, which is contained within coal seams and the surrounding rock strata, 

is released into the atmosphere when mining 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 depth 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 underground and surface mines, post-mining processing of 

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

in the coal that is released 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 distribution segments of the 

natural gas system. It also includes CO2 from flaring of natural gas. Not included are vented and 

fugitive CO2 emissions from natural gas systems, such as vented CO2 emissions removed during 

natural gas processing, or energy-related CO2 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 miles of transmission and distribution pipelines. 

Methane and non-combustion3

 CO2 emissions from natural gas systems are generally processrelated, with normal operations, routine maintenance, and system upsets being the primary 

contributors. There are four primary stages of the natural gas system which are briefly described 

below. 

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

formations. Emissions arise from the wells themselves, gathering pipelines, and well-site gas 

treatment facilities (e.g., dehydrators, separators). Major emissions source categories within the 

 

3

 In this document, consistent with IPCC accounting terminology, 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 CO2 removed from raw natural gas. 
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3A-5 

production stage include pneumatic 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 CO2 emissions within the production 

stage. 

Processing: In this stage, natural gas liquids and various other constituents from the raw gas are 

removed, resulting in “pipeline-quality” 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 

CO2 emissions in the processing stage come from acid gas removal units, which are designed to 

remove CO2 from natural gas. 

Transmission and Storage: Natural gas transmission involves high-pressure, large-diameter 

pipelines that transport gas long distances from field production and processing areas to 

distribution systems or large-volume customers such as power plants or chemical plants. 

Compressor station facilities, which contain large reciprocating and turbine compressors, are 

used to move the gas throughout the U.S. transmission system. Fugitive methane emissions from 

these compressor stations and from metering and regulating stations account for the majority of 

the emissions from this stage. Pneumatic devices and non-combusted engine exhaust are also 

sources of methane emissions from transmission facilities. Natural gas is also injected and stored 

in underground formations, or liquefied and stored in above-ground tanks, during periods of 

lower demand (e.g., summer), and withdrawn, processed, and distributed during periods of 

higher demand (e.g., winter). Compressors and dehydrators are the primary contributors to 

emissions from these storage facilities. Emissions from LNG import terminals are included 

within the transportation and storage stage. 

Distribution: Distribution pipelines take the high-pressure gas from the transmission system at 

“city gate” stations, reduce the pressure, and then distribute the gas through primarily 

underground mains and service lines to individual end users. 

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

Emissions Source 2013 Emissions (million metric tons CO2 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 

CO2 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 CO2 Eq. 

In Table 3A-1, CO2-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 illustrative 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 emissions. These activity drivers include domestic 

coal and natural gas production, imports and exports, 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 relative to production in the base case. 

 

4

 Uncertainties related to activity drivers are discussed in the uncertainties and limitations section. 
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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 final guidelines indicates decreases in methane 

emissions from coal mining of 6.8 million metric tons CO2 Eq. in 2025, and 12.7 million metric 

tons CO2 Eq. in 2030. Methane from natural gas systems decreases slightly relative to the base 

case in 2025 and 2030 (by less than 1 million metric tons CO2 Eq. Following a similar pattern, 

CO2 from flaring in natural gas production does not show significant change relative to the base 

case. 

Based on the actions modelled in illustrative plan approaches, upstream methane 

emissions and CO2 emissions are predicted to decline (see Table 3A-4). The final guidelines are 

predicted to result in a net emissions reduction of 7.5 million metric tons CO2 Eq. in 2025 and a 

net emissions reduction of 13.4 million metric tons CO2 Eq. in 2030. These net emissions 

changes represent the sum of changes in methane from coal mining, methane from natural gas 

systems, and CO2 from flaring in natural gas production. The projections include voluntary and 

regulatory activities to reduce emissions from coal mining and natural gas and oil systems, 
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including the 2012 Oil and Natural Gas NSPS. In addition, the EPA plans to issue a proposed 

rule later this summer that would build on its 2012 Oil and Gas NSPS. When these standards are 

finalized and implemented, they would further reduce projected emissions from natural gas and 

oil systems. 

Table 3A-4. Potential Upstream Emissions Changes 

Emissions (million metric tons CO2 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 

CO2 from NG flaring +0.1 -0.0 -0.1 

Total Methane + CO2 -1.6 -7.5 -13.4 

Mass-based Scenario 

Methane from Coal Mining [X] [X] [X] 

Methane from Natural Gas Systems [X] [X] [X] 

CO2 from NG flaring [X] [X] [X] 

Total Methane + CO2 [X] [X] [X]

Note: A Global Warming Potential of 25 was used to convert methane emissions to CO2 Eq. 

3A.3 Uncertainties and Limitations 

Projections of upstream methane emissions and CO2 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 activity drivers, uncertainty in base year emissions, 

and uncertainties in changes in emissions factors over relatively long periods of time. For 

example, EPA’s application of IPM relies on EIA 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 power sector coal demand. To the extent 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 estimates 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 uncertain in both baseline and illustrative plan 
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approaches. Relatively higher or lower economic growth, or changes in the relative prices or 

availability of various technologies could result in alternative estimates in the net change in 

upstream methane emissions and related CO2 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 Oil and Natural Gas Production, Transmission, and 

Distribution: Background Technical Support 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 Oil and Natural Gas Production, Transmission, and 

Distribution: Background Supplemental Technical Support Document for the Final New 

Source Performance Standards. Available at 

<http://epa.gov/airquality/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-CO2 and Non-Energy CO2 Sources. Available at 

<http://www.state.gov/documents/organization/219472.pdf> Accessed June 4, 2015.