Technical Support Document (TSD) for the CAA Section 111(d) Emission Guidelines for Existing Power 

Plants 

Docket ID No. EPA-HQ-OAR-2014-XXXX 

Goal Computation Technical Support 

Document

U.S Environmental Protection Agency 

Office of Air and Radiation 

June 2014 

 
State Emission Rate Goal Setting under 111(d) 

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

state-level emission rate goals under the proposed Rule. Section VII of the preamble discusses state 

emission rate goals more broadly, and the GHG Abatement Measures TSD explains the technical basis for 

the development of the Best System of Emission Reductions (BSER). This TSD provides detailed 

explanation of the data, the data underlying the state goal calculation, the BSER-based calculations used 

to determine the state goals, and the state goals. The TSD is organized as follows: 

1. BSER Factors Informing State Emission Rate Goals 

a. Heat rate improvement 

b. Coal to gas redispatch 

c. Renewable and nuclear 

d. End-use energy efficiency 

2. Data Used 

a. Rationale for historic data based targets 

b. Source of data 

i. Emissions & Generation Integrated Resource Database (eGRID) 

ii. Data sources for under construction units 

c. State-level data rationale and significance 

3. Example of State Goal Calculation and Discussion 

4. Appendix (attached Excel Workbook) 

 Appendix 1 - State level goals, underlying state level data, and calculations for Option 1 

 Appendix 2 - State level goals, underlying state level data, and calculations for Option 2 

 Appendix 3 – Summary table of state goals 

 Appendix 4 - Details of state-level data development 

Note – This TSD also contains an excel attachment that contains the aggregate state level data,

calculations, and proposed state emission rate goals.  The underlying unit‐level data is also available in

the Docket for this rulemaking.

   
In EPA’s technical evaluation, reasonable assumptions regarding application of each GHG reducing 

technology were identified (see GHG Abatement Measures TSD). The EPA used these assumptions to 

develop the two regulatory options provided in this proposal: (1) Option 1 with state emission rate goals 

based on reasonable assumptions related to BSER, and (2) Option 2 with more moderate assumptions 

relative to those used for Option 1. 

1. BSER Factors Informing State Emission Rate Goals

The GHG Abatement Measures TSD describes the four categories of emission reduction 

measures (building blocks) used in determining the state emission rate goals. That document 

describes EPA’s historic data review and analysis underlying each technology and informing 

EPA’s assessment of its feasibility and cost-effectiveness as part of a BSER. The technology 

estimates determined through EPA’s analysis and documented in the GHG Abatement Measures 

TSD are summarized below. These estimates were used in EPA’s calculation of state emission 

rate goals, as described in this TSD. 

a. Heat Rate Improvement 

Option 1 – A 6% heat rate improvement in the state’s coal fleet 

Option 2 – A 4% heat rate improvement in the states coal fleet 

b. Redispatch to Existing Natural Gas Combined Cycle Plants (NGCC) 

Option 1 – a 70% capacity factor (CF) ceiling for the state’s NGCC fleet 

Option 2 – a 65% capacity factor ceiling for the state’s NGCC fleet 

Note – These capacity factor values represent ceilings for NGCC utilization. The EPA 

used these ceilings while calculating state goal adjustments related to redispatching coal 

and/or oil and gas (og) steam generation in a state to the state’s NGCC capacity. 

c. Renewable and Nuclear 

Both option 1 and 2 include under construction (5.5 GW) and preserved nuclear capacity 

(~8% of existing nuclear capacity) 

Option 1 – Non-Hydro RE at 13% by start of 2030 and thereafter* 

Option 2 – Non-Hydro RE at 9.4% by start of 2025 and thereafter* 

d. End-use Energy Efficiency (EE)* 

Option 1 – 10.65% cumulative savings by start of 2030 and each year thereafter 

Option 2 – 5.17% cumulative savings by start of 2025 and thereafter 

*Note – The above values for non-hydro RE and EE saving rates are nationwide 

averages. Each state’s CO2 emission rate goal is informed by state-specific non-hydro RE 

and EE values that relate to its pre-existing non-hydro RE generation and EE savings 

rates respectively as described in the GHG Abatement Measures TSD. 
The technology assumptions described above are used to determine an emission rate (lb/MWh) 

for each state that constitutes the state goal. As these building blocks reflect both fossil and nonfossil measures, the corresponding state goal reflects a composite emission rate including fossil 

and zero emitting non-fossil technologies. The EPA proposed to use an emission rate metric for 

state goals, rather than a mass-based metric to promote state flexibility. See preamble section VII 

for more description on the rate based standard. 

2. Data Used 

A. Rationale for Historic Data Basis for Target Setting 

The EPA used 2012 state level data to determine each state’s emission rate goal. The EPA 

carefully considered using a historic year data set, a projected year data set, or a hybrid of the two 

as a starting point for applying the above technology assumptions and calculating the state’s 

emission rate goals.1

 Ultimately the EPA chose the historic data approach as it reflected actual 

historic performance at the state level. EPA chose the year 2012 as it represented the most recent 

year for which complete data were available at the time of the analysis. The EPA also considered 

the possibility of using average fossil generation and emission rate values over a baseline period 

(e.g., 2009 – 2012), but determined that there would be little variation in results compared to a 

2012 base year data set results due to the rate-based nature of the goal. The form of the goal is an 

emission rate representing the deployment of BSER measures, and that deployment level is 

largely a function of technology specific reduction capability and total capacity currently on the 

ground. Because these two critical variables do not vary significantly (the latter not at all) when 

looking at a larger baseline period, the benefits of an expanded baseline period are dampened, and 

overshadowed by the complexities introduced through creating a “hypothetical” year. 

Consequently, the EPA decided that using data from an actual year (for which facility 

representatives had reported the values as complete and accurate to the best of their knowledge) 

was preferable to using calculated values that did not reflect any real year supply/demand 

balance. For this work, the EPA used 2012 data compiled using the same methodology as in 

EPA’s Emissions and Generation Resource Integrated Database (eGRID) to determine the 

following 2012 values at the state level, which become the basis from which state emission rate 

goals are calculated. 

 State level coal generation 

 State level coal emission rate 

 State level oil/gas steam generation 

 State level oil/gas steam emission rate 

 State level NGCC generation 

 State level NGCC emission rate 

 State level NGCC capacity 

 “other” emissions2

                                                            

1 Data sources for future year or hybrid approach would be EPA Base Case Power Sector modeling. 2 “Other” includes fossil sources that are likely subject to 111(d) rulemaking, but not subject to building block

abatement measures.
 “other” generation 

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

and expressed as lbs/MWh. The capacity expressed is nameplate capacity in Megawatts. 

B. Source of Data 

i. Emissions & Generation Integrated Resource Database (eGRID) 

eGRID is a comprehensive inventory of environmental attributes of the U.S. electric power 

system. It is the preeminent 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. Although 2012 eGRID data had not yet been released, the 

EPA applied its eGRID methodology for matching the publically available and reported 2012 

emissions and generation data. The EPA relies on this most recent data to calculate state goals. 

The state level totals for each technology category described in the above bullets are intended to 

reflect the electric generating units (EGUs) meeting the following criteria:3

An EGU is a boiler or turbine that is: (1) capable of combusting more than 250 MMBtu/h heat 

input of fossil fuel, (2) constructed for the purpose of supplying more than one-third of its 

potential net- electric output capacity . . . to any utility power distribution system for sale (that is, 

to the grid), and (3) constructed for the purpose of supplying . . . more than 25 MW net-electric 

output. 

Integrated gasification combined cycles (IGCCs) and combustion turbines (CTs) operating at a 

capacity factor greater than 33% are not part of the inventory of units subjected to building blocks 

one and two. Although they are covered units under the rule, they are excluded from the 

technology that are considered eligible for blocks one and two, and instead designated as the 

“other” category. IGCCs and high capacity factor CTs present unique circumstances and are not 

subjected to building block application. IGCCs represent a very small sample size of 3 plants and 

                                                            

3 The set of sources used to compile state level totals and eventual state goal rates does not constitute an

applicability determination for any particular EGU.  The ultimate universe of EGUs subject to this rulemaking may

vary from that used in this goal setting exercise and will be determined by the rule’s applicability language and

actual operating conditions at that plant.
have a different utilization pattern and different capital cost profile than NGCCs that result in a 

different set of redispatch economics. Likewise, high capacity factors CTs that may be covered 

by the rule are generally less efficient and have higher emission rates than NGCCs, and are 

therefore generally less cost effective for redispatch purposes. Therefore, IGCCs and CTs were 

not considered for cost-effective deployment of BSER building blocks one and two (i.e., there are 

no redispatch, or heat rate improvements assumed to occur at these units). The historical 

generation and emissions from IGCCs and high capacity factor CTs are still averaged into the 

state goal rate to account for the notion that these units are affected sources and their generation 

and emissions would be averaged into the state emission rate for compliance purposes. This 

category of affected units that are covered under the 111(d) applicability language, but not 

subjected to BSER technologies is accounted for in an “other” category. This represents a small 

portion (i.e., less than 1%) of total generation and emissions relative to the other affected source 

categories and has a small impact on the state goal rates. 

Appendix A shows the state level aggregate data and corresponding calculations applied to 

achieve the state goal rate. 

ii. Data sources for under construction units 

Although the 2012 eGRID data described above forms the starting point for the goal calculation, 

the EPA’s BSER methodology also included under construction nuclear and NGCC capacity that 

was not existing in 2012. For this small subset of units, EPA relied on its National Electric 

Energy Data System (NEEDS). NEEDS includes basic geographic, operating, air emissions, and 

other data on existing or under construction generating units. NEEDS was completely updated for 

EPA's new power sector modeling platform v.5.13. For a description of the sources used in 

preparing NEEDS v.5.13, see Documentation, Chapter 4: Generating Resources.4

  In addition to 

those under construction NGCC units in NEEDS, the EPA identified three other NGCC plants 

that were under construction and would likely fit the rulemaking’s definition of “existing” unit. 

These were the Dominion Brunswick plant in Virginia (1,358 MW), the Cheyenne Generating 

Station in Wyoming (220 MW), and the Cane Run plant in Kentucky (640 MW). 

C. State-Level Data Rationale and Significance 

The EPA aggregated EGU-level data to the state level for purposes of state-specific emission rate 

goal calculation. Then, for each state, the EPA made BSER-related adjustments to the historical 

state-level data to derive a new emission rate that constitutes the state goal. In making 

adjustments to aggregate state-level data, the EPA is simply suggesting that BSER assumptions 

(e.g., 6% heat rate improvement) can be achieved on average at the state level. The EPA is not 

making any assertions about specific units or plants. The EPA recognizes the uniqueness and 

                                                            

4 http://www.epa.gov/powersectormodeling/BaseCasev513.html#needs
complexity of individual power plants, and is aware that there are site-specific factors that may 

prevent some EGUs from achieving performance equal to state-level assumptions. 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 

state level based on application of the BSER values to historic state-level data. 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 state goals estimated using this 

approach. 

 
3. Emission Rate Calculation 

EPA’s methodology for calculating state goals is described in the steps noted below. The implementation of each step is illbelow its description, using the state of Ohio as an example. Step 1: Calculation of unadjusted 2012 state fossil emission rate for covered sources As noted above, the EPA begins the state goal emission rate calculation by starting with actual historic data at the state leve

summed to state-level values describing: coal generation, coal emission rate, NGCC generation, NGCC emission rate, OG steam emission rate, “other” emissions, “other” generation, and NGCC capacity. These categories are identified as they rep

generation that is subject to building block application and/or would likely be subject to the state goal. For combined heat 

that are covered under the rule, the entire emissions and generation (including steam-based) from the facility are counted wemission rates because such facilities’ entire emissions and generation would be considered when determining compliance 

only the electricity generation portion of CHP is available for redispatch purposes, and therefore only this portion of the co

reflected in the generation totals. There are four coal facilities that co-fired biomass in 2012 that did not report emissions uncases an emission rate factor is used to estimate stack CO2 emissions attributable to the type of biomass reported.6 These te

values become the basis for calculating the state’s emission rate. All emission rates provided in the state goal determinatio

Therefore, they will appear slightly higher than the emission rates viewed on a gross generation basis. 

2012 Rate (lbs/MWh) 2012 mass (lbs) 2012 Generation (MWh) 2012 Capacit

A B C D E F G H I 

Coal Rate 

OG Steam 

Rate 

NGCC 

Rate Other Emissions Coal Gen OG Steam gen NGCC Gen Other Gen NGCC MW 

Ohio 2,187 2,196 963 0 84,726,936 343,627 20,907,183 0 4,343 

5 A separate state goal rate is calculated for IPM power sector modeling that reflects total emissions from CHP units, but just the elect

portion of their generation. This was necessary as IPM reflects total emissions associated with cogeneration operation, but only the g

meeting net electricity demand.

6 http://www.theclimateregistry.org/downloads/2013/04/2013‐Climate‐Registry‐Default‐Emissions‐Factors.pdf
Note, when the values in the above cells shaded green and blue are applied to the equation below, the state’s 2012 “unadjus

rate (or historical fossil rate) for likely covered sources is equal 1,946 lb/MWh. 

Historical emission rate = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) 

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. 

Step 2: BSER Block one - Calculation of state fossil emission rate goal for covered sources resulting from heat rate improAfter this historical data is collected for each state, the EPA begins to adjust particular variables to the data to reflect each b

of BSER. The EPA assumes that a 6% heat rate improvement at the facility will directly translate to a 6% reduction in the 

Therefore, in conjunction with determining state goals under option 1 in this proposal, the EPA adjusts the state-level coal A) downwards by 6% to reflect the 6% heat rate improvement. In the case of Ohio, this results in a drop from 2,187 lb/MWThis completes the building block 1 treatment for option 1.7

2012 Rate (lbs/MWh) 2012 mass (lbs) 2012 Generation (MWh) 2012 Capacit

A B C D E F G H I 

Coal Rate 

OG Steam 

Rate 

NGCC 

Rate Other Emissions Coal Gen OG Steam gen NGCC Gen Other Gen NGCC MW 

Ohio 2,056 2,196 963 0 84,726,936 343,627 20,907,183 0 4,343 

Note that when the total emission rate is recalculated with heat rate improvement reflected in the adjustment to the state’s c

state emission rate drops from 1,946 lb/MWh to 1,841 lbs/MWh. This is not the final state emission rate goal rate, rather areflecting building block 1 application before moving onto the remaining blocks. The bold areas in the equation below refl

adjusted from their historical level at this stage. 

7 EPA makes a similar adjustment for option 2, but uses a 4% HRI improvement assumption when reducing the coal rate
State Emission Rate Post Block 1 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” 

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. Step 3: BSER Block Two - Calculation of state fossil emission rate goal resulting from heat rate improvement and redispacapacityIn the GHG Abatement Measures TSD, the EPA described how historical 2012 data illustrated that a significant number of generation that was greater than or equal to its nameplate capacity x 8784 * .7 – in other words a 70% or greater net capaci

provided analysis supporting a 70% capacity factor as cost-effective and historical data that illustrated the ability to increas

combined cycle units under favorable market conditions. That portion of the TSD also describes the engineering analysis tavailability of a NGCC is greater than 70%. Building block 2 was intended to reflect the potential redispatch to the state’s e

to a 70% capacity factor level. To operationalize the 70% CF ceiling in the state goal setting, the state’s 2012 existing NGCC nameplate capacity is multip

(the number of hours in the 2012 year) and then by 70% to get total potential net NGCC generation at a 70% capacity facto

capacity factor represents a redispatch ceiling, and the state’s NGCC generation is only adjusted up to this ceiling if its hist

support such a level.8 Therefore, if this ceiling value (MWh) is less than the sum of the state’s 2012 coal, OG steam, and N

the historic NGCC generation is increased to this calculated ceiling value representing the NGCC fleet at a 70% capacity fa

and OG steam generation are ramped down by an equivalent amount of generation. If the generation of existing NGCC at greater than the sum of the state’s 2012 coal, OG steam, and NGCC net generation, the historical NGCC generation is only total of the 2012 net fossil generation from these sources. In summary, adjusted NGCC net generation is equal to the lesser 

fleet at 70% capacity factor or 2012 total fossil generation from BSER subjected sources. This preserves the historical total generation in the state for BSER subjected sources, but reapportions it assuming a 70% state-average net capacity factor ce

fleet. The increase in NGCC generation is subtracted from the coal and OG steam generation in proportion to the state’s hiexample, if coal historically accounted for 90% of the total coal and OG steam generation in the state, then its historic gene

8 Fossil sources here refers to those units subject to BSER redispatch building block treatment (i.e., coal, o/g steam, and NGCC)
reduced by 90% of the amount that NGCC generation increases. Likewise, the OG steam generation would be reduced by 

which NGCC generation is increased. 

2012 Rate (lbs/MWh) 2012 mass (lbs) 2012 Generation (MWh) 2012 Capacit

A B C D 

E 

F G H I 

Coal Rate 

OG Steam 

Rate 

NGCC 

Rate Other Emissions Coal Gen OG Steam gen NGCC Gen Other Gen NGCC MW 

Ohio 2,056 2,196 963 0 78,956,358 320,223 26,701,164 0 4,343 

Note – in the above example, the total covered fossil generation has not increased in the state from the historic totals shown been reapportioned assuming a 70% capacity factor for NGCC. NGCC generation is adjusted upwards by approximately 6

coal and O/G are adjusted downward by the same amount. This increase in NGCC generation reflects the existing fleet inchistorical level of approximately 55% CF up to the ceiling of 70% CF. When these updated generation values are folded in

calculation, the emission rate drops from 1,841 lb/MWh in Step 2 to 1,781 lb/MWh. This completes building block two apbold below reflect the historic data points that have been adjusted to reflect building block implementation at this point in t

State Emission Rate Post Block 2.1 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “O

Coal gen. + OG gen. + NGCC gen. + “Other” gen.

Step 4: BSER Block Two, cont. - Calculation of state fossil emission rate goal resulting from heat rate improvement and and “en route” NGCC capacityStep 3 is repeated for “en route” NGCC capacity that would also be considered an existing covered fossil source. For this s

defined as anything that came online in 2013 or that was under construction, site prep, or testing by January 8, 2014. The E

9 While a 70% capacity factor ceiling is assumed in the state goal setting exercise, the majority of states are not expected to operate thei

level in EPA’s projected compliance scenarios.

10 In option 2 state goal calculations, the EPA makes similar adjustments to the historic data but utilize a 65% capacity factor ceiling in 

shown above

4,343 MW x 8784 hours x 70% CF = 26,701
data for 2012 and calculated the average performance of NGCCs that came online in the past 5 years and observed that 55% 

capacity factor for these units under a business as usual scenario.11 Therefore, the EPA assumed that a 55% capacity factor 

representation for the expected generation of “en route” NGCCs capacity under a business as usual scenario. The EPA conthe generation associated with this 55% capacity factor as unavailable for redispatch to reduce CO2 (i.e., not qualifying for 

instead, reserving that amount of generation potential to meet other system needs presumed to have motivated the construc

NGCCs. Because these sources are nevertheless covered under the state emission rate goal, the emissions and generation 

generation are added to the “other” category and averaged into the state goal calculation. The EPA assumes that while thes

55% under a business as usual scenario, the average availability for these units is greater than 55%, and they too could ramon average, under a BSER framework and displace relatively higher CO2-emitting generation. Thus, 15% of their ultimate 

assumed to be available for redispatch purposes. The MWh associated with this 15% additional CF displaces coal and OG same manner as in step 3. The portion of the “en route” NGCC unit’s generation that is not considered subject to BSER abatement measures (i.e., the in the “other” category. The generation and emissions from these sources are still included in the ultimate emission rate qugoal by averaging in their unadjusted emissions and generation. For “en route” NGCC units that have no 2012 historical d

generation associated with the 55% baseline capacity factor is obtained by using the “en route capacity” and historical averNGCCs in the state.12 The emissions total for these units is based on multiplying the generation at a 55% CF by the averag

existing NGCCs in the state. 

11 http://ampd.epa.gov/ampd/12 Note, both Wyoming and Kentucky had “en route” NGCC capacity, but did not have existing covered NGCC in the state from which 

could be derived for the “en route” capacity. Therefore, the nationwide average NGCC emissions rate of 919 lb/MWh (net basis) beca

emission rate for the “en route” NGCC in these two states.
2012 Rate (lbs/MWh) 2012 mass (lbs) 2012 Generation (MWh) 

2012 Capacity 

"En Route" 

NGCC 

A B C 

D 

E F G H I J 

Coal Rate 

OG 

Steam 

Rate 

NGCC 

Rate Other Emissions Coal Gen 

OG Steam 

gen NGCC Gen Other Gen NGCC MW NGCC MW 

Ohio 2,056 2,196 963 2,506,741,578 78,249,041 317,354 27,411,350 2,604,017 4,343 539 

Note that when the total emission rate is recalculated to reflect the “en route” NGCC capacity, the state’s emission rate at th

1,781lb/MWh to 1,754 lbs/MWh. This is not the final state emission rate goal rate, rather an interim rate reflecting buildin

application before moving onto the remaining blocks. The bold areas in the equation below reflect the values that are adjus

level at this stage. 

State Emission Rate post block 2.2 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “O

Coal gen. + OG gen. + NGCC gen. + “Other” gen. 

Step 5: BSER Block Three - Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatcroute NGCC capacity, and new and preserved nuclear In Step 5, the total under construction nuclear capacity is determined.13 Additionally, an amount of existing nuclear capaci

being retired is identified as approximately 8% of the current nuclear fleet (see GHG Abatement Measures TSD for further percent assumption was derived). This new and preserved nuclear capacity was incorporated into the state goals as zero em

was achieved by applying a 90% capacity factor to the nuclear capacity identified as under construction or “at risk” and the

MWh figure into the denominator of the state goal calculation. Nuclear is not considered a “dispatchable” resource as is N

13 Watts Bar in TN, Vogtle in GA, and Summer in SC

4,343 MW x 8784 hours x 70% CF = 26,701

539 x 8784 x 15% CF = 710,186

Total = 27,411,350
its utilization will remain fairly constant in both a business-as-usual and policy scenario due to its low variable operating co

sources. The differing dispatch economics for NGCC and nuclear leads to a slightly different treatment in the goal setting. 

assumed to increase generation in the same manner as the NGCC fleet is assumed capable of in the above steps. Instead of 

coal to nuclear in the same fashion as the previous steps, the expected generation for new and preserved nuclear is simply a

denominator – resulting in a lover state goal emission rate. However, it is important to note that this “new and preserved” n

part of the inventory that the state can count towards compliance with its state goal (i.e., the zero emitting generation that c

that of the covered fossil sources in order to obtain a rate that is equal to or less than the state emission rate goal). Therefor

not necessarily have to lower their own emission rate to help the state achieve the lower state goal reflected subsequent to atechnology provided that the nuclear capacity continues to operate at a 90% capacity factor. 

2012 Rate (lbs/MWh) 2012 mass (lbs) 2012 Generation (MWh) 

2012 Capacity 

"En Route" 

NGCC 

New 

Pres

Nu

A B C D E F G H I J 

Coal 

Rate 

OG 

Steam 

Rate 

NGCC 

Rate Other Emissions Coal Gen 

OG Steam 

gen NGCC Gen Other Gen 

NGCC 

MW NGCC MW M

Ohio 2,056 2,196 963 2,506,741,578 78,249,041 317,354 27,411,350 2,604,017 4,343 

539 

 1

Ohio has 0 MW of under construction nuclear and 171 MW of “at risk” nuclear capacity share as described in the “GHG A

TSD”. This results in an expected nuclear generation amount of 1,351,239 MWh that is incorporated into the state goal calcapacity factor). When this value is added into the state goal calculation, the state’s emission rate drops from 1,754 lb/MW

State Emission Rate Post Block 3.1 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “O

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. 
Step 6: BSER Block Three, cont. - Calculation of state fossil emission rate goal resulting from heat rate improvement, red

en route NGCC capacity, new and preserved nuclear, and Renewable (RE)Existing and new renewable generation is incorporated into the state goal in a similar manner as the nuclear generation. Re

low variable operating cost and utilization that is dictated by the renewable resources available. Like nuclear generating cap

not expected to vary significantly between a business-as-usual scenario and a policy scenario. Therefore, the generation fro

added into the denominator in a similar fashion. Consequently, all non-hydro RE generation (existing and new build) woul

demonstrating compliance with the state goal. The GHG Abatement Measures TSD describes how the RE generation total for each state was derived from a combination generation in the state and target RE levels informed by existing Renewable Portfolio Standards (RPS) in the region. Altho

assumed RE generation varies by state to reflect the different existing portfolios of renewable resources and the amount of 

available in different regions of the country, the nationwide average assumed under Option 1 is approximately 13% non-hy

2029.14 A potential non-hydro RE generation value is calculated for each state annually for all years between 2020-2029 t

growth as states move toward a particular regional non-hydro RE benchmark. The state-specific non-hydro RE generation 

goal nationwide average are available in the Excel attachment to this TSD and the GHG Abatement Measures TSD. These 

totals include both existing non-hydro renewable resources in the state and new non-hydro renewable generation. 

2012 Rate (lbs/MWh) 

2012 mass (lbs) 2012 Generation (MWh) 

2012 Capacity 

"En 

Route" 

NGCC 

New and 

Preserved 

Nuclear 

Exi

Ne

Hy

A B C D E F G H I J K 

Coal 

Rate 

OG 

Steam 

Rate 

NGCC 

Rate 

Other 

Emissions Coal Gen 

OG 

Steam 

gen 

NGCC 

Gen 

Other 

Gen 

NGCC 

MW 

NGCC 

MW MWh 

Ohio 2,056 2,196 963 2,506,741,578 78,249,041 317,354 27,411,350 2,604,017 4,343 539 1,351,239 13

14 See “GHG Abatement Measures TSD”
Ohio had 1,738,622 MWh of non-hydro RE in 201215 (approximately 1% of total net generation) and would grow to 13,77

(approximately 10.6% of current net generation) under the building block three assumptions. This 13,775,594 MWh of non

would be added into the state goal by adding it in the denominator. The RE value and resulting state goal shown above ref

When this is added into the state goal calculation, the state’s emission rate drops from 1,733 lb/MWh to 1,540 lb/MWh.

State Emission Rate Post Block 3.2 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “O

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. + RE gen. 

Step 7: BSER Block 4 - Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to eroute”NGCC, under construction and preserved nuclear, RE, and demand-side EEA state-specific percent value is determined for each state reflecting the amount of total MWh sales that could potentially b

demand-side energy efficiency measures (see GHG Abatement Measures TSD). Annual percentage savings rates for MWh each state for all years between 2020 and 2029 in Option 1. A different set of annual percent savings are derived for 2020-2

Because of the temporal nature of demand-side energy efficiency, this building block, along with RE portion of building bl

BSER components that increase each year. The GHG Abatement Measures TSD explains the rationale and derivation of th

rates. Once these state-specific percent savings rates for MWh sales are derived, they are multiplied by the state’s 2012 his

scaled by a factor of 1.0751 to obtain an avoided generation value in MWhs.16 The 7.51% scaling factor effectively covert

into a corresponding total net generation value that accounts for transmission and distribution losses. 17 The lesser of 1) thi

value, or 2) the avoided net generation value multiplied by the state’s generation share of its sales is then applied to the den

step helps assure that building block four reductions for net importer states are linked to their in-state generation. This step further reduces the state goal. However, the state may also count any future EE measures towards compliance wi

Therefore, if a state achieves the assumed avoided generation based on EE, it does not have to further lower its emission ra

15 http://www.eia.gov/electricity/data/state/16 http://www.eia.gov/electricity/data/state/ “Retail Sales of Electricity by State and Sector”17 The 7.51% scaler represents the historical difference between total net generation of electricity (4,036 TWh) and retail sales of electr

http://www.eia.gov/electricity/state/pdf/sep2010.pdf
fuel fired generators determined in the previous steps. Instead, adding the avoided generation to the denominator (i.e., aver

generation at a 0 lbs/MWh emission rate) will lower the state’s emission rate used for compliance with the state goal. 

2012 Rate (lbs/MWh) 

2012 mass (lbs) 2012 Generation (MWh) 

2012 Capacity 

"En 

Route" 

NGCC 

New and 

Preserved 

Nuclear 

Existi

New 

Hydr

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

Coal 

Rate 

OG 

Steam 

Rate 

NGCC 

Rate 

Other 

Emissions Coal Gen 

OG 

Steam 

gen 

NGCC 

Gen 

Other 

Gen 

NGCC 

MW 

NGCC 

MW MWh MW

Ohio 2,056 2,196 963 2,506,741,578 78,249,041 317,354 27,411,350 2,604,017 4,343 539 1,351,239 13,77

As described in the Demand-side energy efficiency section of the GHG Abatement Measures TSD, the 2029 percent of gen

energy efficiency is assumed to be 11.56% in Ohio. This value is then multiplied by the retail electricity sales in the state (

and multiplied by 1.0751 to reflect the net generation commensurate with these sales (i.e., inclusive of transmission and disresults in 18,942,382 MWh of avoided generation. This value is then multiplied by 92.43% (Ohio’s share of sales coming 

generation) to reflect the amount of avoided in-state generation that results from the energy efficiency investments. This fiin 17,507,556 MWh of avoided generation for Ohio that is assumed for 2029. This avoided generation value is added into results in the state goal being decreased from 1,540 lbs/MWh to 1,349 lbs/MWh. This concludes the application of all four 

year 2029, and the 1,349 lb/MWh rate reflects Ohio’s Adjusted emission rate for the year 2029.

State Emission Rate Post Block 4 = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Oth

 Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. + RE gen. + EE gen

Step 8: Interim and Final State Goals The completion of the previous seven steps results in a 2029 emission rate for the state. However, as noted above, the RE a

change for each year from 2020 through 2029. Thus this procedure is repeated for each of those years using the correspond

assumption for that year. This results in a set of annual adjusted emission rates for the years 2020-2029. However, this rul

18 http://www.eia.gov/electricity/data/state/
two state goals – an interim and final state goal. Thus goals are derived by averaging or taken directly from and the annual 

values.  For Option 1:  Interim State Goal – Average of the adjusted yearly emission rates for the period 2020-2029  Final State Goal – The 2029 emission rate (as calculated above) becomes the state goal for 2030 and each year ther For Option 2:  Interim State Goal – Average of the adjusted yearly rates for the period 2020-2029  Final State Goal – The 2024 emission rate (as calculated above) becomes the state goal for 2030 and each year therThe EPA recognizes that the emission rate goals calculated here include measures that may yield reductions in mass emisemission rate reductions in practice when observing monitored and reported emission and generation data from affected fully informative to compare the state goals calculated here to observable emission rates across affected units either hist

years. For more discussion about how states can demonstrate compliance with these emission rate goals, please see the 

Considerations TSD”.

Finally, the assumptions used to arrive at each state’s goal are not prescriptive of necessary actions that a state must take

preamble, these values are used only for calculating a state goal. A state may chose to comply with that state goal throug

abatement measures that differ in class and magnitude from those assumed in the state goal calculation.

Example of Final State Goal Calculation for Ohio: Final State Goal Rate for Ohio, Option 1  – ((2,056 x 78,249,041) + (2,196 x 317,354) + (963 x 27,411,350) + 2,506,741,578) = 1,349  ((78,249,041 + 317,354 + 27,411,350 + 2,604,017 + 1,351,239 + 13,755,594 + 17,507,556) See the accompanying Excel Workbook for all state level data, calculations, and final state level emission rate goals used to and Final State Goals for Options 1 and 2. This workbook shows all the calculations used to transform the historical emiss

the Interim and Final State Goal (columns BB and BC) for option 1, and (columns AM and AN) for option 2. 

APPENDIX 

Appendix 1 ‐ State level goals, underlying state level data, and calculations for Option 1

See “Appendix 1” worksheet in the Excel Attachment titled “State Goal Data and

Computation”

Appendix 2 ‐ State level goals, underlying state level data, and calculations for Option 2

See “Appendix 2” worksheet in the Excel Attachment titled “State Goal Data and

Computation”

   
Appendix 3 – Summary of state goals

Option 1 State Goals

State

2020 State

Goal

Interim Goal

(2020‐2029)

Final Goal

(2030 and

after)     State

2020

State

Goal

Interim Goal

(2020‐2029)

Final Goal

(2030 and

after)

Alabama 1,196 1,113 1,024    Montana 2,034 1,900 1,781

Alaska 1,185 1,039 878     Nebraska 1,713 1,587 1,471

Arizona 767 724 691    Nevada 757 697 644

Arkansas 1,077 1,012 950     New Hampshire 630 542 485

California 618 580 558    New Jersey 783 657 531

Colorado 1,254 1,164 1,112     New Mexico 1,188 1,088 1,000

Connecticut 651 588 533    New York 749 647 557

Delaware 985 922 848     North Carolina 1,172 1,064 977

Florida 811 750 692    North Dakota 1,857 1,821 1,788

Georgia 962 885 826     Ohio 1,594 1,468 1,349

Hawaii 1,481 1,388 1,304    Oklahoma 984 916 879

Idaho 264 241 225     Oregon 472 408 375

Illinois 1,512 1,391 1,293    Pennsylvania 1,323 1,200 1,067

Indiana 1,723 1,627 1,549     Rhode Island 866 816 773

Iowa 1,409 1,351 1,310    South Carolina 880 802 736

Kansas 1,728 1,597 1,516     South Dakota 868 794 731

Kentucky 1,955 1,861 1,778    Tennessee 1,336 1,234 1,142

Louisiana 1,170 1,080 993     Texas 1,029 932 855

Maine 445 423 407    Utah 1,446 1,375 1,318

Maryland 1,521 1,325 1,166     Virginia 978 869 793

Massachusetts 732 646 567    Washington 376 294 235

Michigan 1,433 1,337 1,261     West Virginia 1,872 1,766 1,636

Minnesota 948 891 851    Wisconsin 1,363 1,265 1,185

Mississippi 775 717 673     Wyoming 1,897 1,801 1,701

Missouri 1,705 1,621 1,544

   
Option 2 State Goals

State

2020 State

Goal

Interim Goal

(2020‐2024)

Final Goal

(2025 and

after)     State

2020

State

Goal

Interim Goal

(2020‐2024)

Final Goal

(2025 and

after)

Alabama 1,274 1,243 1,208    Montana 2,084 2,031 1,980

Alaska 1,192 1,142 1,086     Nebraska 1,760 1,710 1,661

Arizona 785 767 751    Nevada 760 736 714

Arkansas 1,153 1,128 1,101     New Hampshire 632 593 553

California 630 611 599    New Jersey 788 740 688

Colorado 1,317 1,274 1,232     New Mexico 1,244 1,203 1,163

Connecticut 664 640 617    New York 799 756 715

Delaware 1,058 1,036 1,010     North Carolina 1,233 1,189 1,145

Florida 818 795 771    North Dakota 1,899 1,887 1,874

Georgia 1,025 992 958     Ohio 1,657 1,611 1,566

Hawaii 1,497 1,464 1,429    Oklahoma 1,061 1,022 986

Idaho 268 259 252     Oregon 483 449 418

Illinois 1,577 1,529 1,484    Pennsylvania 1,389 1,342 1,293

Indiana 1,774 1,738 1,704     Rhode Island 871 854 837

Iowa 1,468 1,447 1,428    South Carolina 921 889 858

Kansas 1,769 1,698 1,644     South Dakota 913 885 856

Kentucky 2,006 1,971 1,937    Tennessee 1,384 1,345 1,307

Louisiana 1,242 1,208 1,171     Texas 1,101 1,059 1,016

Maine 456 448 440    Utah 1,502 1,476 1,451

Maryland 1,573 1,495 1,417     Virginia 1,061 1,011 955

Massachusetts 741 708 675    Washington 389 350 316

Michigan 1,508 1,470 1,434     West Virginia 1,915 1,877 1,835

Minnesota 1,023 1,001 981    Wisconsin 1,444 1,404 1,366

Mississippi 777 754 729     Wyoming 1,941 1,902 1,862

Missouri 1,757 1,726 1,694   

   
Appendix 4 ‐ Details of state‐level data development

The unit‐level emissions and generation data derived using the eGRID methodology was relied upon for

determining state level totals ultimately used in the goal calculation.  One notable difference is that

published editions of eGRID match emissions and generation at the plant level, while the development

of the state‐level data matches emissions and generation at the unit level.  Also, the data for this state‐

level data goal setting were limited to the following elements at the unit level: CO2 emissions,

nameplate capacity, net generation, state location, and information used to place the unit in each

category.  The data sources are from reports from units that submit data to the EPA under 40 CFR Part

75, and Energy Information Administration data from forms EIA‐860 and EIA‐923.  The data were

assembled at the unit level and were aggregated to the state‐level generation totals, capacity totals, and

emission rates for the following categories: coal steam, Oil Gas Steam (O/G steam), Natural Gas

Combined Cycle (NGCC) and Simply Cycle Combustion Turbines (CTs), and Integrated Gasification

Combined Cycle (IGCC).  The year 2012 historical values for these categories were then modified for

each state to derive the state goal emission rates as described in the main body of the TSD.

Industrial units that are not grid connected are excluded.  Units for which fossil fuel was less than 10% of

the heat input in year 2012 were also excluded.

For units that report to the EPA under 40 CFR Part 75, reported CO2 emissions were used.  These

emissions are either determined from continuous emissions monitors that measure CO2 concentration

and stack gas volumetric flow or, for units that combust certain gaseous and liquid fuels, fuel flow

meters and fuel testing as required under appendix D and E of 40 CFR Part 75.     

For units that do not report to the EPA under 40 CFR Part 75, CO2 emissions are calculated from fuel use

reported in the EIA‐923 and emission factors under EPA’s Inventory of U.S. Greenhouse Gas Emissions

and Sinks or The Climate Registry Default Emission Factors.  If no unit level fuel use exists in the EIA‐923

dataset and prime mover fuel data exists, and there are more than one unit at a plant that have the

same prime mover (e.g. steam turbine, combustion turbine, etc.), then prime mover fuel level emissions

are distributed to each generator in the prime mover by proportionately by nameplate capacity.  For

most cases (where all units in the prime mover would likely be covered by the rule), this apportionment

does not matter because emissions are summed to the state level.  However, if there is a smaller unit in

the prime mover that would not likely be covered by the rule, then this apportionment may not exactly

match the amount of fuel actually burned and the associated emissions for each unit.   

Net generation is taken from EIA‐923 data.  If no unit level net generation exists in the EIA‐923 dataset

and prime mover fuel data exists, and there are more than one unit at a plant that have the same prime

mover (e.g. steam turbine, combustion turbine, etc.), then prime mover fuel level net generation is

distributed to each generator in the prime mover by proportionately by nameplate capacity.   

Logic for determination of source CATEGORY:
CATEGORY Category Name Includes

COALST Coal Steam ‐ likely covered by rule

Coal is designated as primary fuel.  Nameplate capacity 25

MW or greater or if heat input capacity is 250MMBtu/hr

or greater

OGST Oil Gas Steam ‐  likely covered by rule All steam units not in “Coal Steam” category.  Nameplate

capacity 25 MW or greater.

NGCC

Natural Gas Combined Cycle Units ‐ likely

covered by rule.  Duct burners and heat

recovery steam generators are included

with combustion turbines that are 25 MW.

NG is primary fuel or if actual fuel use is >90% NG.  

Combustion turbine parts having nameplate capacity 25

MW or greater. Any associated duct burners and heat

recovery steam generators are included.

SST Simple Cycle Combustion Turbines – 25

MW & likely covered by rule

Nameplate capacity 25 MW or greater& 33% capacity

factor & 219,000MWh

IGCC IGCC IGCCs at: Wabash, Polk, Edwardsport