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

Plants

Docket ID No. EPA

- HQ

- OAR

- 20 13

- 0602



# Goal Computation Technical Support

Document

U.S Environmental Protection Agency

Office of Air and Radiation

June 201 42

State Emission Rate Goal Setting under 111(d)

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

state emission rate goals under the P roposed Rule. Section VII of the preamble discusses state emission

rate goals more broadly , and the Green House Gas ( GHG ) Abatement Measures TSD explains the

technical basis for the development of the Best System of Emission Reductions (BSER) that inform the

state goals

. 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 a s follows:

1. BSER Factors Informing State Emission Rate Goal s

a. Heat rate improvement

b. Coal

- to

- gas redispatch

c. Renewable (RE) and nuclear generation

d. End

- use energy efficiency

2. Data Used

a. R ationale for historic data basis for state goal setting

b. Source of data

i. Emissions & G eneration Int egrated Resource Database (eGRID )

ii. Data sources for “ under construction ” units coming online post 2012

c. State

- level data rationale and significance

3. Example of State Goal Calculation and Discussion

4. Appendix (attached Excel Workboo k)

 Appendix 1

- State

- level g oals, underlying state

- level data, and calculations for Proposed

s tate g oals

 Appendix 2

- State

- level g oals, underlying state

- level data, and calculations for t he

Alternative state goals

 Appendix 3

- Summary table of state goals

 Appendix 4

- Block 1 & 2 only goals

 Appendix 5

- 2012 emission rates and building block application

 Appendix 6

- De scription of state

- level data development

 Appendix 7

- 2012 plant

- level data and unit

- level inventory

Note

– This TSD also contains an excel attachment that contains the aggregate state

- level data,

calculations, and proposed state emission rate goals. The underlying plant

- level data and unit

- level data

is also available in the Docket for this rulemaking.3

In EPA’s technical evaluati on, reasonable assumption s 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 propo sal: (1) Proposed s tate goals based on

reasonable assumptions related to BSER, and (2) Alternative state goals with less ambitious assumptions

relative to those used for the Proposed state goals

.

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 a re used in EPA’s calculation of state emissio n rate

goal s, as described in this TSD

.

a. Heat Rate Improvement

Proposed

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

Alternative

– A 4 % heat rate improvement in the state ’ s coal fleet

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

Proposed

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

Alternative

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

Note

– These capacity factor value s represent ceilings for NGCC utilization

. The EPA

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

and/or oil and gas ( O/G ) steam generation to the state’s NGCC capacity

.

c. Renewable and Nuclear

Both Proposed and Alternative state goals include under construction (5.5 GW) and at

ri sk nuclear capacity (~ 5. 8% of nuclear capacity )

Proposed

– RE at 13% by start of 2030 and thereafter *

Alternative

– RE at 9.4% by start of 2025 and thereafter *

d. End

- use Energy Efficiency (EE) *

Proposed

– 10.7 % cumulative savings by start of 2030 and each year thereafter

Alternative

– 5. 2 % cumulative savings by start of 2025 and thereafter

* Note

– The above RE values and EE saving rates are nationwide averages . Each state ’s

CO 2 emission rate goal is informed by state

- specific RE and EE value s that relate to its

pre

- existing RE generation and EE savings rate s respectively as described in the GHG

Abatement Measures TSD. Also, the RE estimates do not count existing hydro

generation.4

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 non

fossil measures, the corresponding state goal reflects a composite emission rate including fossil

and zero emi tting 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. R ationale for Historic Data Basis for State Goal 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 calcul ating 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 va lues 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 due to the rate

- based nature of the goal. The state goal is an emission rate

representing the deployment of BSER measure s , and that deployment level is largely a function

of te chnology

- specific emission rate reduction capability and total NGCC capacity installed to

date . Because these two critical variables do not vary significantly when looking at a larger

baseline period , the benefi ts of a n ex panded 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 rep resentative s had reported the

v alues as complete and accurate to the best of their knowledge) was preferable to using calculated

value s 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 em ission 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” generation

1 Data sources for future year or hybrid approach would be EPA Base Case Power Se ctor modeling.5  “ O ther” emissions 2

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

and expressed as lbs/MWh. The capacity expressed i s 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 i ntegrates 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 emi ssions, 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 an d generation data. The EPA relies on this most recent data to calculate state goals.

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

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

In general, a covered EGU is a stationary combustion turbine, steam generating unit or IGCC that

is: (1) capable of combusting more than 250 MMBtu/h heat input of fossil fuel and (2)

constructed for the purpose of supplying one

- third or more of its potential net

- electric output

capacity and more than 219,000 MWh to any utility power distribution system for sale (that is,

to the grid). In addition, for a stationary combustion turbine to be considered an EGU the heat

input must consist of over 90% natural gas

. 4

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

2 “Other” includes fossil sources that are likely subject to 111(d) rulemaking, but not subject to building block

abatement measures (e.g., IGCC, high utilization CTs, useful thermal output at cogeneration units)

. 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 s etting exercise and will be determined by the rule’s applicability language and

actual operating conditions at that plant.

4 See Preamble and Regulatory text for full description of 111(d) applicability criteria6

generating technologies that are considered eligible for blocks one and two, and instead

designated as the “other” category. IGCCs and high utilization CTs present unique circumstances

and are not subjected to bu ilding block application . IGCCs represe nt a very small sample size of

three operating plants and have a different utilization pattern and different capital cost profile than

NGCCs that result in a different set of redispatch economics. Likewise, high utilization CTs that

may be covered by the rule are generally less efficient and have higher emission rates than

NGCC s , and are therefore generally less cost effective for redispatch purposes. 5 Therefore,

IGCCs and CTs were not considered for cost

- effecti ve 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 emission s from IGCCs and high capacity factor CTs are still

ave raged into the state goal to account for these units as affected sources . Therefore, their

generation and emissions would be averaged into the state emission rat e for compliance purposes

.

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

subjected to BSER technologies

, is acco unted for in an “other” category. The IGCC and high

utilization CTs represent a small portion (i.e., less than 1%) of total generation and emissions

relative t o the oth er affected source categories

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

Appendix 1 shows the 2012 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 operating in 2012. For this small su bset of “existing ” units, EPA relied on its National

Electric Energy Data System (NEEDS)

. NEEDS includes b asic geographic, operating, capacity

, and other data on existing or under construction generating units. NEEDS was 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

. 6 In

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

NGCC plants and one IGCC plant 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), the Cane Run plant in

Kentucky (640 MW) , and the Kemper IGCC plant in Mississippi (582 MW).

C. State

- Level Data Rationale and Significance

5 “ H igh utilization” CTs are categorized as those with a capacity factor greater than 33% in 2012.

6 http://www.epa.gov/powersectormodeling/BaseCasev513.html#needs , also available in the Docket File titled

“NEEDSv.5. 13 Database”7

The EPA aggregated plant

- 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 historic al

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 for the coal fleet ) can be achieved on average at the state level.

The EPA is not making an y assertion s about specific units or plants. The EPA recognizes the

uniqueness and complexity of individual power plants, and is aware that there are site

- specific

factors that may prevent some EGUs from achieving performance equal to 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.8

3. Example of State Goal Calculation and Discussion

EPA’s methodology for calculating state goals is described i n the steps below. The implementation of each step is illustrated in the table below its

description, using the state o f Ohio as an example. The mathematical calculations are fundamental to translating the buildi ng blocks into a

quantifiable state goal.

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 level. Plant

- level data are

summed to state

- level values describing: coal gene ration, coal emission rate, NGCC generation, NGCC emission rate, OG steam generation, OG

steam emissi on rate , “other” emissions, “other” generation, and NGCC capacity

. These ca tegories are identified as they represen t the historical

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

. For combined heat and power (CHP) units

that are covered under the rule, the emissions and energy output associate d with the useful thermal output not used for electricity production are

included in the state goal and would be reported under the 111(d) reporting guidelines if the unit meets the 111(d ) applicability criteria. The

emissions and e nergy output associated with the useful thermal output are captured in the “o ther” category. The emission rates shown reflect total

emissions divided by total net energy output (e.g. net electricity gene ration + useful thermal output)

. 7 However, only th e electricity generation

portion of CHP is available for redispatch purposes, and therefore only this portion of the cogeneration operation is reflect ed in the technology

generation totals. 8 There are four coal facilities that co

- fire d biomass in 2012 that did not report emissions under Part 75 in these cases a n emission

rate factor is used to estimate stack CO 2 emissions attributable to th e type of biomass reported

. 9

, 10 These technology specific values become the

basis for calculating the state’s emis sion rate. All emission rates provided in the state goal determination are on a net basis.

7 A separate state goal rate is calculated for the EPA Integrated Planning Model (IPM) power sector analysis that reflects total emissions from CHP units, but just

their net electricity generation in the denominator. This was necessary as IPM is a dispatch model that optimizes around net electricity demand, so it reflects

total emissions associated with cogenera tion operation, but only the generation associated with meeting net electricity demand. These corresponding goals

expressed in lb/net MWh of electricity generation can be found in the docket file titled “State Goals (excluding useful therm al output)”.

8 T he useful thermal output is converted to a net MWh value and captured in the other generation

9 40 CFR, Part 98, Subpart C, Table C

- 1A has CO2 emission factors for stationary combustion of various fuels, including biomass. See here:

http://www.ecfr.gov/cgi

- bin/text

- idx?SID=834bf8d737d2100f8affa21bc7b13bbc&node=40:22.0.1.1.3.3.1.10.18&rgn=div9

10 Please see section VIII of the pream ble for more information on biomass in the context of this rulemaking.9 2012 Rate (lbs/MWh) 2012 mass

(lbs) 2012 Generation (MWh) 2012 Capacity Starting Covered

Fossil Rate

(lbs/MWh)

A B C D E F G H I J

Coa l Rate OG Steam

Rate NGCC Rate Other

Emissions Coal Gen OG Steam

Gen NGCC Gen Other Gen NGCC MW

Ohio 2,126 1,332 963 284,732,506 86,473,075 321,602 20,907,183 214,178 4,343 1,897

Note, wh en the values in the above cells shaded green and blue are applied to the equation below, the state ’ s 2012 “ unadjusted fossil” emission

rate (or historical fossil rate) for lik ely covered sources equals 1, 897 lb/MWh

.

Historical fossil emission rate = (coal gen. x co al emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissions

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

Step 2: BSER Block O ne

- Calculation of state fossil emission rate goal for covered sources resulting from heat rate improvement (HRI)

After this historical data is collected for each state, the EPA begins to adjust particular variables to the data to reflect each building block element

of BSER

. The EPA assumes that a 6% heat rate improvement at the facility wil l directly translate to a 6% reduction in the net CO 2 emission rate.

Therefore, in conjunction with determining state goals under the Proposed state goal assumptions in this proposal

, the EPA adjusts the state

- l evel

coal emission rate (column A) downwards by 6% to reflect the 6% heat rate improvement. In the case of Ohio, this results in a drop from 2,1 26

lb/MWh to 1,999 lb/MWh. This completes the building block 1 treatment for the Proposed state goals

. 11

11 EPA makes a similar adjustment for the Alternative state goals , but uses a 4% HRI improvement assumption when reducing the coal rate10 Emission Rate (lbs/MWh) Emissions

(lbs) Generation (MWh) 2012

Capacity State Goal

Post Block 1

(lbs/MWh)

A B C D E F G H I J

Coa l Rate OG Steam

Rate NGCC Rate Other

Emissions Coal Gen OG Steam Gen NGCC Gen Other Gen NGCC

MW

Ohio 1,999 1,332 963 284,732,506 86,473,075 321,602 20,907,183 214,178 4,343 1,795

N o te that when the total emission rate is recalculated with heat rate improvement reflected in the adjustment to the state’s coal emission rate , the

stat e emission rate drops from 1, 897 lb/MWh to 1, 795 lbs/MWh . This is not the final state emission rate goal rate, rather an emission rate

reflecting building block 1 application before moving onto the remaining blocks . The bold areas in the equation below reflect the values that are

adjus ted from the ir historica l level at this step

.

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” Emissions

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

Step 3 a : BSER Block Two

- Calculation of state fossil emission rate goal resulting from heat rate improvement and redispatch to existing NGCC

capacity

In the GHG Abatement Measures TSD, the EPA described how historic al 2012 data illustrated that a significant number of NGCC plants had a net

generation that was greater than or equal to its nameplate capacity x 8784 * 0 .7

– in other words a 70% or greater capacity factor. It also provided

analysis supportin g a 70% capacity factor as cost

- effective and historical data that illustrated the ability to increase utilization at NGCCs under

favorable market conditions. That portion of the TSD also describes the engineering analysis that suggest s the average availability of a NGCC i s

significantly greater than 70%. B uilding block 2 was intended to reflect the potential redispatch to the state’s existing NGCC fleet up to a 70%

capacity factor level.

To operationalize the 70% CF ceiling in the state goal setting , t he state’s 2012 existing NGCC nameplate cap acity is multiplied by 8

, 784 hours

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

capacity factor represent s a redispatch ceiling, and the state’s NGCC genera tion is only adjusted up to this ceiling if its historic fossil sources11

support such a level. 12 Therefore, i f this ceiling value (MWh) is less than the sum of the state’s 2012 coal, OG steam , and NGCC net generation,

the historic NGCC generation is in creas ed to this calculated MWh ceiling value representing the NGCC fleet at a 70% capacity factor

, and historic

coal and OG steam generation are ramped down by an equivalent amount of generation. If the generation of existing NGCC at a 70% capacity

factor is greater than the sum of the state’s 2012 coal, OG steam, and NGCC net generation, the historic al NGCC generation is only adjusted to

equal the total of the 201 2 net fossil generation from these sources . In summary , adjusted NGCC net generation is equal to the lesser of existing

NGCC fleet at 70% capacity factor or 2012 total fossil generation from BSER subjected sources. This preserves the historic al total covered fossil

generation in the state for BSER subjected sources , but reapportions it assuming a 70% state

- average capacity factor ceiling for the NGCC fleet.

The increase in NGCC generation is subtracted from the coal and OG steam generation in proportion to the state’s historic generation. For

example , if coal historically accounted for 90% of the total coal and OG steam generation in the state, then its historic generation would be

reduced by 90% of the amount that NGCC generat ion increases. Likewise, the OG steam generation would be reduced by 10% of the amount by

which NGCC generation is increas ed.

Emission Rate (lbs/MWh) Emissions (lbs) Generation (MWh) 2012

Capacity State Goal

Post Block

2.1

(lbs/MWh)

A B C D E F G H I J

Coa l Rate OG Steam

Rate NGCC

Rate Other

Emissions Coal Gen OG Steam Gen NGCC Gen Other Gen NGCC

MW

Ohio 1,999 1,332 963 284,732,506 80,700,563 300,133 26,701,164 214,178 4,34 2.5 1,739

Note

– in the above example, the total covered fossil generation has not increased in the state from the historic totals shown in step 1. It has only

been reapportioned assuming a 70% capacity factor for NG CC. NGCC generation is adjusted upwards by approximately 6,000,000 MWh, and

coal and O/G are ad

justed downward by the same amount. This increase in NGCC generation reflects the existing fleet increasing from a

12 Fossil sources here refers to those units subjec t to BSER redispatch building block treatment (i.e., coal, o/g steam, and NGCC) 4,342.5 MW x 8784 hours x 70% CF = 26,701,16412

historical level of approximately 55% CF up to the ceiling of 70% CF. When these updated generation values are folded into the state goal

c alculation, th e emission rate drops from 1, 795 lb/MWh in Step 2 to 1,7 39 lb/MWh

. The values in bold below reflect the historic data points that

have been adjusted to reflect building block implementation at this point in the process. 13 14

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) + “Other” emissions

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

Step 3b: BSER Block Two, cont.

- Calculation of state fossil emission rate goal resulting from heat rate improvement and redispatch to existing

and under construction NGCC capacity

Step 3 a is repeated for under construction NG C C capacity that would also be considered an existing covered fossil source. For this step, “ under

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

looked at report ed data for 2012 and calculated the average performa nce of NGCCs that c a me online in the past 5 years and observed that 55%

was the average capacity factor for these units

. 15 Therefore, the EPA assumed that a 55% capacity factor would be a reasonable representation for

the expected generation of “ under construction ” NG CCs capacity under a business as usual scenario. The EPA conservatively designated the

generation associated with this 55% capacity factor as unavailable for redispatch to reduce CO 2 (i.e., not qualifying for building block 2) , i nstead

, reserving that amount of generation potential to meet other system needs presumed to have motivated the construction of the “ under construction ”

NGCCs. Because these sources are nevertheless covered under the state emission rate goal, the emissions and gener ation from this 5 5%

generation are added to the “other” category and averaged into the state goal calculation

. The EPA assumes that while these units would operate at

55% CF under a business as usual scenario, the average availability for these units is greater than 55%, and they too could ramp up to 70% CF

ceiling, on average, under a BSER framework and displace relatively higher CO 2

- emitting generation. Thus, 15% of their ultimate CF (70%

-

55% ) is assumed to be available for redispatch purposes. The MWh associated with this 15% add itional CF displaces coal and OG steam

generation in the same manner as in step 3 a

.

13 While a 70% capacity factor ceiling is assumed in the state goal setting exercise, the majority of states are not expected to operate their existing fleet at this

level in EP A’s projected compliance scenarios.

14 In the Alternative state goal calculations, the EPA makes similar adjustments to the historic data but utilize s a 65% capacity factor ceiling in place of the 70%

CF shown above

. 15 http://ampd.epa.gov/ampd/ and available in docket file titled “NGCC capacity factor for units online in last 5 years”

.13

The portion of the “under construction ” NGCC unit’s generation that is not considered available for redispatch (i.e., the first 55%) is captured in

the “other” category. The generation and emissions from these sources ar e still included in the emission rate quantified as the state goal by

averaging in their unadjusted emission s and generat ion. For “under construction ” NGCC units that have no 2012 historical data, the generation

associated with the 55% baseline capacity fac tor is obtained by using the capacity and historical average emission rate for NGCCs in the state. 16

The emissions tota l for these units is calculated by multiplying the generation at a 55% CF by the average emission rate for existing NGCCs in the

state.

Emission Rate (lbs/MWh) Emissions (lbs) Generation (MWh) 2012

Capacity " Under

Construction "

NGCC State Goal

Post Block

2.2

(lbs/MWh)

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

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 1,715

Note that when the total emission rate is recalculated to reflect the “ under construction ” NGCC capacity, the state’s emission rate at this step drops

from 1,7 39 lb/MWh to 1,7 15 lbs/MWh. This is not the final state emission rate goal rate, rather an interim rate reflecting building blocks one and

16 Note, both Wyoming and Kentucky had “under construction” NGCC capacity, but did not have existi ng covered NGCC in the state from which a proxy

emission rate could be derived for the “under construction” capacity. Therefore, the nationwide average NGCC emissions rate of 907 lb/MWh (net basis)

. became the assumed emission rate for the “under construc tion” NGCC in these two states. EPA assumed 800 lb/MWh and 70% capacity factor for the Kemper

unit as it was not yet operating in 2012. This is reflected in Mississippi’s “Other” Generation and Emissions in step 2.

http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/4

- Thursday/25Aug11

- %20Nelson

- Kemper

Capture%20at%20Kempe r%20IGCC.pdf and available in the docket file titled “ CO2 capture at Kemper ”

. 4,343 MW x 8784 hours x 70% CF = 26,701,164

539 x 8784 x 15% CF = 710,186

Total NGCC = 27,411,350

539 x 8784 x 55% CF =2,604,017

Total “other”= 2,604,017 + 214,178 = 2,818,19514

two application before moving onto the remaining blocks. The bold areas in the equation below reflect the values that are ad justed fr om their

historical level at this stage. Note the “Other” category is bolded here as it reflects the addition of the 55% utilization of under construction

NGCC.

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) + “Other” emissions

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

Step 4a : BSER Block Three

- Calculation of state fossil emission rate goal resulting from heat rate improvement

, redispatch to existing and under

construction NGCC capacity

, and under construction and “at risk” nuclear capacity

In Step 4a , the total under construction nuclear capacity is determined

. 17 Additionally , an amount of the nuclear capacity that is “at risk” of being

retired is identified as approximately 5. 8% of the historical nuclear fleet (see GHG Abatement Measures TSD for further discussion on how the

percent assumption was derived)

. This under construction and “at risk” nuclear capacity was incorporate d into the state goals as zero emitting

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

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

NGCC capacity. That is, its utilization will remain fairly constant in both a business

- as

- usual and policy scenario due to both its low variable

operating cost relative to fossil sources and technical limitations regarding start

- up and shut

- down times . The differing dispa tch economics

between NGCC and nuclear plants leads to a different treatment in the goal setting. Existing nuclear is not assumed to increase generation in the

same manner as the NGCC fleet is assumed capable of in the above steps. Instead of redispatching from coal to nuclear in the same fashion as the

previous steps, the expected gen eration for new and “at risk” nuclear is simply added to the state goal denominator

– resulting in a lo w er state goal

emission rat e

. However, it is important to note that this “ under construction and at risk ” nuclear capacity is also part of the inventory that the state

can count towards compliance with its state goal (i.e., zero emitting generation that can be averaged with that of the covered fossil sources in order

to obtain a rate that is equal to or less than the state emission rate goal).

17 Watts Bar in TN, Vogtle in GA, and Summer in SC15 Emission Rate (lbs/MWh) Emissions

(lbs) Generation (MWh) 2012

Capacity " Under

Construction "

NGCC Under

Construction

and “at risk”

Nuclear State Goal

Post Block

3.1

(lbs/MWh)

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

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 993,077 1,699

Ohio has 0 MW of under construction nuclear and 1 25.617 MW of “at risk” nuclear capacity share as described in the “GHG Abatement Measures

TSD” (referred to as Nuclear gen

uc + ar . This results in an expected nuclear generation amount of 933,077 MWh that is incorporated into the state

goal calculation (based on 90% capacity factor)

. When this value is added into the state goal calculation, the state’s emission rate drops from

1,7 15 lb/MWh to 1, 699 lb/MWh

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 ther ” emissions

Coal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen uc + ar .

Step 4b : BSER Block Three, cont.

- Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to existing

and under construction NGCC capacity, new and “at risk” nuclear , and Renewable (RE)

The GHG Abatement Measures TSD describes how the RE generation total for each state was derived from a combination of existin g renewable

generation in the state and target RE levels informed by existing Renewable Portfolio Standards (RPS) in the region. A lthough the amount of

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

available in different regions of the country, the nationwide average assumed under t he Propos ed state goals is approximately 13% RE by the end16

of 2029

. 18 A potential RE generation value is calculated for each state annually for all years between 2020

- 2029 to reflect the annual growth as

states move toward a particular regional RE benchmark. The st ate

- specific RE generation values that relate to this goal nationwide average are

available in the Excel attachment to this TSD and the GHG Abatement Measures TSD. These RE MWh totals include both existing renewable

resources in the state and new renewa ble generation.

Emission Rate (lbs/MWh) Emissions

(lbs) Generation (MWh) 2012

Capacity " Under

Construction

" NGCC Under

Construction

and “at risk”

Nuclear Existing

and New

RE State Goal

Post Block

3.2

(lbs/MWh

)

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

Coal Rate OG Steam

Rate NGC

C Rate Other

Emissions Coal Gen OG Steam

Gen NGCC

Gen Other Gen NGCC

MW NGCC MW MWh MWh

Ohi

o 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 993,077 13,775,594 1,512

Ohio had 1,738,622 MWh of RE in 2012 19 (approximately 1% of total net generation) and would grow to 13,775,594 MWh by 2029

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

adde d into the state goal by adding it in the denominator. The RE value and resulting state goal shown above reflect the 2029 year. When this is

added into the state goal calculation, the state’ s emission rate drops from 1, 699 lb/MWh to 1, 512 lb/MWh

.

State Emission Rate Pos t Block 3.2 = ( coal gen. x coal emission rate ) + ( OG gen . x OG emission rate) + ( NGCC gen . x NGCC emission rate) + “Other” emissions

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

uc + ar + RE gen.

Step 5 : BSER Block 4

- Calculation of state fossil emission rate goal resulting from heat rate improvement, redispatch to existing NGCC, “ under

construction ” NGCC , under construction and at risk nuclear, RE, and demand

- side EE

18 See “GHG Abatement Measures” TSD available in the docket and on website . Value does not reflect existing hydro generation.

19 http://www.eia.gov/electricity/data/state/ and available in the docket file titled “2012 sales (EIA data)”.17

A state

- specific percent value is determined for each state reflecting the amount of total MWh sales that could potent ially be avoided through

demand

- side energy efficiency measures (see GHG Abatement Measures TSD). A nnual percentage savings rates for MWh sales are derived for

each st ate for all years between 2020 and 2029 in t he Proposed state goals

. A different set of annual percent savings are derived for 2020

- 2024 for

t he Alternative state goals

. Because of the temporal nature of demand

- side energy efficiency, this building block

, along with RE portion of

building block three, are the only BSER components that increase each year. The GHG Abatement Measures TSD explains the rationale and

derivation of these annual savings rates

. Once these state

- specific percent savings rates are derived , they are multiplied by the state’s 2012

historic al retail sales and scaled by a factor of 1.0751 to obtain an avoided generation value in MWhs

. 20 The 7.51% scaling factor effectively

co n verts the retail sales figure into a corresponding total net generation v alue that accounts for transmission and distribution losses

. 21 The lesser

of 1) this avoided net generation value, or 2) the avoided net generation value multiplied by the state’s generation share of its sales is then applied

to the denominator. This last step helps assure that building block four reductions for net importer states are linked to their own in

- state

generation. 22

This step further reduces the state goal. However, the state may also count EE measures towards compliance with its state goal . Therefore, if a

state achieves the assumed avoided generation based on EE, it does not have to further lower its emission rate from covered f ossil

- fuel fired

generators determined in the previous steps. Instead, a dding the avoided generation to the denominator (i.e., averaging in the avoided generation

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

20 http://www.eia.gov/electricity/data/state/ “Retail Sales of Electricity by State and Sector” and available in the docket file titled “2012 sales (EIA data)”.

21 The 7.51% scaler represents the historical difference between total net generation of electricit y (4,036 TWh) and retail sales of electricity (3,754 TWh).

http://www.eia.gov/electricity/state/pdf/sep2010.pdf and also available in the file titled “State

- level Generation

– Net Import er and Exporter Derivation for Goal

Calculation” in the docket.

22 Demand

- side energy efficiency measures may result in out

- of

- state emission reductions for states that consume more electricity than they produce (i.e., net

importer states). For these net i mporter states, the proposal’s approach assumes that each MWh of displaced generation from end

- use EE would have occurred in

part inside the state and in in part outside the state. The proportion of generation displaced inside the state is assumed t o be e quivalent to the ratio of generation

in the state to consumption in that state. For example, in a state that produces 75% of the level of electricity that the state consumes, this approach assumes that

each MWh of avoided generation from end

- use EE only y ields .75 MWh of avoided generation within that state. Only the portion of avoided generation assumed

to occur within that state is incorporated into the relevant state goal, on the premise that the proposed BSER is intended to quantify emission reduction potential

at the generators located in the state in question. For more explanation on how these percent values were derived and the un derlying data, See “State

- level

Generation

– Net Importer and Exporter Derivation for Goal Calculation” in the docket.18 Emission Rate (lbs/MWh) Emissions (lbs) Generation (M Wh) 2012

Capacity " Under

construction "

NGCC Under

Construction

and At risk

Nuclear Existing

and New

RE Avoided

Sales via

demand

side EE Post Block

4

(lbs/MWh)

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

Coal

Rate OG

Steam

Rate NGCC

Rate Other Emissions Coal Gen OG Steam

Gen NGCC Gen Other Gen NGCC

MW NGCC MW MWh MWh MWh

Ohio 1,999 1,332 963 2,791,474,084 79,993,008 297,502 27,411,350 2,818,195 4,343 539 993,077 13,775,594 16,284,584 1,338

As described in the d emand

- side energy efficiency section of the GHG Abatement Measures TSD , the 2029 percent of generation savings due to

energy efficiency is calculated to be 11.5 57 % in Ohio 23 . This value is then multiplied by the retail electricity sales in the state (152,456,864

MWh) 24 and multiplied by 1.0751 to reflect the net generation commensurate with these sales (i.e., inclusive of transmission and distribution

losses ) . This results in 18,942,382 MWh of avoided generation. This v alue is then multiplied by 85.97 % (Ohio’s share of sales coming from in

state power generation) to reflect the amount of avoided in

- state generation that results from the energy efficiency investments . This final

adjustment results in 16,284,584 MWh of av oided generation for Ohio that is assumed for 2029. This avoided generation value is added into the

denominator and results in the state goal being decreased from 1,5 12 lbs/MWh to 1,3 38 lbs/MWh. This concludes the application of all four

building blocks for the year 2029, and the 1,338 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) + “Other” emissions

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

uc + ar + RE gen. + EE gen.

Step s 6 & 7 : Interim and Final State Goals

The completion of the previous five steps results in a 2029 emission rate for the state. However, as noted above, the RE and EE assumptions

change for each year from 2020 through 2029. Thus this procedure is repeated for each of those years using the corresponding RE and EE

23 11.557% reflects rounded value. See Appendix 1 for actual calculated value of 11.55683...% used to arrive at MWh shown above. Most values shown

throughout this example are rounded for visual purposes. See Appendix for unrounded number.

24 http://www.eia.gov/electricity/data/state/ and available in the docket file titled “2012 sales (EIA data)”.19

assumption for that year. This results in a set of annual adjusted emission rates for the years 2020

- 2029. However, this rulemak ing only issues

two state goals

– an int erim and final state goal. Thus

, goals are derived by averaging

, or taken directly fr om and the annual adjusted emission rate

values.

For The Proposed state goals :

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 thereafter

For The Alternative state goals :

Interim State Goal

– Average of the adjusted yearly rates for the period 2020

- 202 4

Final State Goal

– The 2024 em ission rate becomes the state goal for 20 25 and each year thereafter

The EPA recognizes that the emission rate goals calculated here include measures that may yield reductions in mass emissions but may not yield

emission rate reductions in practice when observing monitored and reported emission an d generation data from affected units. As such, it is not

fully informative to compare the state goals calculated here to observable emission rates across affected units either histor ically or in future

years. For more discussion about how states can dem onstrate compliance with these emission rate goals, please see the “State Plans

Considerations TSD”. For more discussion on emission reductions, please see the Regulatory Impact Analysis.

Finally, the assumptions used to arrive at each state’s goal are no t prescriptive of necessary actions that a state must take. As described in the

preamble, these values are used only for calculating a state goal. A state may cho o se to comply with that state goal through any combination of

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 Proposed State Goal Rate for Ohio

– ( (1,999 x 79,993,008) + (1,332 x 297,502) + (963 x 27,411,350) + 2,791,474,084) = 1,338 lb/MWh

((79,993,008 + 297,502 + 27,411,350 + 2,818,195 + 993,077 + 13,775,594 + 16,284,585)20

See the accompanying Excel Workbook for all state level data, calculations, and final state level emission rate goals used to calculate t he Interim

and Final State Goals for Options 1 and 2. This workbook shows all the calculations used to transform the historical covered fossil emission rate

to the Interim and Final State Goal (columns BA and BB ) for the Proposed state goals , and (columns A L and AM ) for the Alternative state goals

.21 APPENDIX

Appendix 1

- State level g oals, underlying state level data, and calculations for The Proposed state

goals

See “Appendix 1” worksheet in the Excel a ttachment titled “ Appendix 1 & 2

- State Goal

Data and Computation”

Appendix 2

- State level g oals, underlying state level data, and calculations for The Alternative state

goals

See “Appe ndix 2” worksheet in the Excel a ttachment titled “ Appendix 1 & 2

- State Goal

Data and Computation”

*T he above referenced workbook has the data and formulas embedded for state goal calculations.

Therefore, a commenter suggesting an adjustment to a building block assumption or any historic state

level data can replace the current assumed values with the su ggested amount and see the resulting state

level goal under such assumptions.22

Appendix 3

– Summary of state g oals under the proposed Existing Source Performance Standard

Proposed State Goals

State Interim Goal

(2020

- 2029) Final Goal

(2030 and

after) State Interim

Goal

(2020

- 2029) Final Goal

(2030 and

after)

Alabama 1,147 1,059 Montana 1,882 1,771

Alaska 1,097 1,003 Nebraska 1,596 1,479

Arizona 735 702 Nevada 697 647

Arkansas 968 910 New

Hampshire 546 486

California 556 537 New Jersey 647 531

Colorado 1,159 1,108 New Mexico 1,107 1,048

Connecticut 597 540 New York 635 549

Delaware 913 841 North Carolina 1,077 992

Florida 794 740 North Dakota 1,817 1,783

Georgia 891 834 Ohio 1,452 1,338

Hawaii 1,378 1,306 Oklahoma 931 895

Idaho 244 228 Oregon 407 372

Illinois 1,366 1,271 Pennsylvania 1,179 1,052

Indiana 1,607 1,531 Rhode Island 822 782

Iowa 1,341 1,301 South Carolina 840 772

Kansas 1,578 1,499 South Dakota 800 741

Kentucky 1,844 1,763 Tennessee 1,254 1,163

Louisiana 948 883 Texas 853 791

Maine 393 378 Utah 1,378 1,322

Maryland 1,347 1,187 Virginia 884 810

Massachusetts 655 576 Washington 264 215

Michigan 1,227 1,161 West Virginia 1,748 1,620

Minnesota 911 873 Wisconsin 1,281 1,203

Mississippi 732 692 Wyoming 1,808 1,714

Missouri 1,621 1,54423

The Alternative State Goals

State Interim

Goal

(2020

- 2024) Final

Goal

(2025

and

after) State Interim

Goal

(2020

- 2024) Final

Goal

(2025

and

after)

Alabama 1,270 1,237 Montana 2,007 1,960

Alaska 1,170 1,131 Nebraska 1,721 1,671

Arizona 779 763 Nevada 734 713

Arkansas 1,083 1,058 New Hampshire 598 557

California 582 571 New Jersey 722 676

Colorado 1,265 1,227 New Mexico 1,214 1,176

Connecticut 651 627 New York 736 697

Delaware 1,007 983 North Carolina 1,199 1,156

Florida 907 884 North Dakota 1,882 1,870

Georgia 997 964 Ohio 1,588 1,545

Hawaii 1,446 1,417 Oklahoma 1,019 986

Idaho 261 254 Oregon 450 420

Illinois 1,501 1,457 Pennsylvania 1,316 1,270

Indiana 1,715 1,683 Rhode Island 855 840

Iowa 1,436 1,417 South Carolina 930 897

Kansas 1,678 1,625 South Dakota 888 861

Kentucky 1,951 1,918 Tennessee 1,363 1,326

Louisiana 1,052 1,025 Texas 957 924

Maine 418 410 Utah 1,478 1,453

Maryland 1,518 1,440 Virginia 1,016 962

Massachusetts 715 683 Washington 312 284

Michigan 1,349 1,319 West Virginia 1,858 1,817

Minnesota 1,018 999 Wisconsin 1,417 1,380

Mississippi 765 743 Wyoming 1,907 1,869

Missouri 1,726 1,69424

Appendix 4

– Blocks 1 & 2 only State Goals

The table below provides the interim and final goals from just block s 1 and 2, before the introduction of

nuclear, renewable, and EE into the denominator. Note

– there is no difference between the Interim and

Final rates through the first two building blocks as the increasing annual potential only applies to block 3

and block 4.

Proposed State Goals (lbs/MWh) Alternative State Goals (lbs/MWh)

State Interim Goal

(2020

- 2029

average) Final Goal

(2030 and

thereafter ) I nterim Goal (2020

-

2024 average) Final Goal ( 2025 and

thereafter )

Alabama 1,329 1,329 1,405 1,405

Alaska 1,252 1,252 1,252 1,252

Arizona 900 900 900 900

Arkansas 1,115 1,115 1,196 1,196

California 838 838 838 838

Colorado 1,521 1,521 1,586 1,586

Connecticut 809 809 812 812

Delaware 1,013 1,013 1,068 1,068

Florida 910 910 991 991

Georgia 1,296 1,296 1,375 1,375

Hawaii 1,751 1,751 1,762 1,762

Idaho 858 858 858 858

Illinois 1,865 1,865 1,924 1,924

Indiana 1,834 1,834 1,883 1,883

Iowa 1,846 1,846 1,900 1,900

Kansas 2,186 2,186 2,230 2,230

Kentucky 1,986 1,986 2,031 2,031

Louisiana 1,099 1,099 1,162 1,162

Maine 848 848 848 848

Maryland 1,868 1,868 1,908 1,908

Massachusetts 886 886 886 886

Michigan 1,511 1,511 1,574 1,574

Minnesota 1,369 1,369 1,446 1,446

Mississippi 843 843 843 843

Missouri 1,784 1,784 1,832 1,832

Montana 2,295 2,295 2,343 2,343

Nebraska 1,941 1,941 1,987 1,987

Nevada 882 882 882 882

New Hampshire 878 878 878 87825

New Jersey 905 905 905 905

New Mexico 1,447 1,447 1,511 1,511

New York 927 927 970 970

North Carolina 1,329 1,329 1,391 1,391

North Dakota 2,226 2,226 2,273 2,273

Ohio 1,714 1,714 1,766 1,766

Oklahoma 1,186 1,186 1,255 1,255

Oregon 852 852 852 852

Pennsylvania 1,480 1,480 1,537 1,537

Rhode Island 918 918 918 918

South Carolina 1,514 1,514 1,576 1,576

South Dakota 1,456 1,456 1,521 1,521

Tennessee 1,798 1,798 1,855 1,855

Texas 1,083 1,083 1,150 1,150

Utah 1,559 1,559 1,614 1,614

Virginia 1,135 1,135 1,216 1,216

Washington 811 811 811 811

West Virginia 1,933 1,933 1,974 1,974

Wisconsin 1,619 1,619 1,689 1,689

Wyoming 2,151 2,151 2,199 2,19926

Appendix 5

– 2012 Emission Rate and Building Block Application

The table below provides a block

- by

- block summary for each state and attempts to compare those r ates to

both the state’s 2012 fossil and fossil/RE/Nuclear

ar emission rate from relevant sources. It summarizes

the 2012 state emission rates (highlighted in y ellow) and the resulting emission rate following the

application of each successive BSER building block. Column C shows the 2012 emission rate from

existing sources that could count towards the state goal , including the state goal’s capture of useful

ther mal output at cogeneration units. Column C provide s an emission rate that may be helpful to compare

to the state goal as it co vers the same generating source types as those subject to the state goal (with the

exception of avoided generation via demand

- side energy efficiency)

.

These block

- by

- block values are purely illustrative and meant to assist in the understanding of the state

goals. For example, the table illustrates that block 1 & 2 application has no impact on Idaho’s state goal

relative to its current emission rate as the state does not have any covered coal sources to which a heat

rate improvement or redispatch assumption is applied. On the other hand, a state like Ohi o does see its

emission rate decrease based on blocks 1 and 2 assumptions.

The state goal development blocks are not prescriptive in terms of abatement measures or magnitude of

that measure. States have the flexibility to select their own portfolio of abatement measures to comp ly

with the state goal. It is also useful to recognize that many states have already moved, or have plans in

place to move below their 2012 rates provided in columns B and C due to scheduled retirement of certain

fossil units, new renewable and low emissi ons generation coming online, State RPS programs, and State

Energy Efficiency Resource Standards (EERS).

2012 Emission Rate and Building Block Application for Proposed Final State Goal (2030)

A B C D E F G

State 2012 Fossil

Rate

(lbs/MWh) 2012 1 Fossil,

RE,

Nuclear AR Block 1 Block s 1 & 2 Blocks 1, 2, &

3 Blocks 1,2,3

& 4 (i.e.,Final

State Goal)

Alabama 1,518 1,444 1,385 1,264 1,139 1,059

Alaska 1,368 1,351 1,340 1,237 1,191 1,003

Arizona 1,551 1,453 1,394 843 814 702

Arkansas 1,722 1,634 1,554 1,058 996 910

California 900 698 697 662 615 537

Colorado 1,959 1,714 1,621 1,334 1,222 1,108

Connecticut 844 765 764 733 643 540

Delaware 1,255 1,234 1,211 996 892 841

Florida 1,238 1,199 1,169 882 812 740

Georgia 2 1,598 1,500 1,433 1,216 926 834

Hawaii 1,783 1,540 1,512 1,512 1,485 1,306

Idaho 858 339 339 339 291 22827

Illinois 2,189 1,894 1,784 1,614 1,476 1,271

Indiana 1,991 1,924 1,817 1,772 1,707 1,531

Iowa 2,197 1,552 1,461 1,304 1,472 1,301

Kansas 2,320 1,940 1,828 1,828 1,658 1,499

Kentucky 2,166 2,158 2,028 1,978 1,947 1,763

Louisiana 1,533 1,455 1,404 1,043 978 883

Maine 873 437 437 425 451 378

Maryland 2,029 1,870 1,772 1,722 1,394 1,187

Massachusetts 1,001 925 915 819 661 576

Michigan 1,814 1,690 1,603 1,408 1,339 1,161

Minnesota 2,013 1,470 1,389 999 1,042 873

Mississippi 1,140 1,093 1,071 809 752 692

Missouri 2,010 1,963 1,849 1,742 1,711 1,544

Montana 2,439 2,246 2,114 2,114 1,936 1,771

Nebraska 2,162 2,009 1,889 1,803 1,652 1,479

Nevada 1,091 988 970 799 720 647

New Hampshire 1,119 905 887 710 532 486

New Jersey 1,035 928 916 811 616 531

New Mexico 1,798 1,586 1,513 1,277 1,163 1,048

New York 1,096 978 970 828 652 549

North Carolina 1,772 1,647 1,560 1,248 1,125 992

North Dakota 2,368 1,994 1,875 1,875 1,865 1,783

Ohio 1,897 1,850 1,751 1,673 1,512 1,338

Oklahoma 1,562 1,387 1,334 1,053 964 895

Oregon 1,081 717 701 565 452 372

Pennsylvania 1,627 1,531 1,458 1,393 1,157 1,052

Rhode Island 918 907 907 907 867 782

South Carolina 3 1,791 1,587 1,506 1,342 866 772

South Dakota 2,256 1,135 1,067 732 900 741

Tennessee 4 2,015 1,903 1,797 1,698 1,322 1,163

Texas 1,420 1,284 1,235 979 861 791

Utah 1,874 1,813 1,713 1,508 1,454 1,322

Virginia 1,438 1,302 1,258 1,047 894 810

Washington 1,379 756 728 444 298 215

West Virginia 2,056 2,019 1,898 1,898 1,687 1,620

Wisconsin 1,988 1,827 1,728 1,487 1,379 1,203

Wyoming 2,331 2,115 1,988 1,957 1,771 1,714

1. “2012 Fossil, RE, Nuclear AR ” includes all generation subject to the state goals for which data was reported in 2012. That

data includes generation from covered fossil fuel

- fired units (e.g., >25 MW), all RE generation except hydropower, and28 approximately 5.8% of nuclear generation (the “at

- risk” component of nuclear generation). The 2012 CO2 rates shown

here have not been adjusted for any incremental end

- use energy efficiency improvements that states may make as part

of their plans to reach these state goals.

2. As described above, G eorgia’s state goal includes expected generation from nuclear capacity currently under construction

at the Vogtle facility. Adding that expected nuclear generation in the “2012 Fossil, RE, Nuclear AR ” emission rate for

Georgia would yield a CO2 emission ra te of 1,243 lbs/MWh.

3. As described above, South Carolina’s state goal includes expected generation from nuclear capacity currently under

construction at the Summer facility. Adding that expected nuclear generation in the “2012 Fossil, RE, Nuclear AR ” emissi on rate for South Carolina would yield a CO2 emission rate of 1,147 lbs/MWh.

4. As described above, Tennessee’s state goal includes expected generation from nuclear capacity currently under

construction at the Watts Bar facility. Adding that expected nuclear generation in the “2012 Fossil, RE, Nuclear AR ”

emission rate for Tennessee would yield a CO2 emission rate of 1,581 lbs/MWh.29

Appendix 6

- Description of State

- level Data D evelopment

The unit

- level emissions and generation data derived using the eGRID methodology was re lied 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 in order to filter out units that are

not likely subject to the Rule’s applicability criteria

. Also, the state

- level data for goal setting were

limited to the following elements at the unit level: CO 2 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 C ombined 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 CO 2 e missions were used. These

emissions are either determined from continuous emissions monitors that measure CO 2 concentration and

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

fuel testing as req uired under appendix D and E of 40 CFR Part 75.

For units that do not report to the EPA under 40 CFR Part 75, CO 2 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 is more t han one unit at a plant that has 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 apportionme nt 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 t he associated emissions for each unit. Fuels categorized as

“other” that could not be defined and assigned an emissions factor were excluded from this task.

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 th e prime mo ver proportionally by nameplate capacity.

Logic for determination of source CATEGORY:30

CATEGORY Category Name Includes

COALST Coal Steam 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 All steam units not in “Coal Steam” category that have oil

or gas primary fuel . Nameplate capacity 25 MW or

greater.

NGCC Natural Gas Combined Cycle Units

- 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 Cy cle Combustion Turbines

– 25

MW Nameplate capacity 25 MW or greater & 33% capacity

factor & 219,000MWh

IGCC IGCC IGCCs at: Wabash, Polk, Edwardsport31

Appendix 7

– 2012 Plant

- level Data and Unit

- level I nventory

See Appendix 7 Excel a ttachment titled “ Appendix 7

– Plant

- level data and unit

- level

inventory” . The unit

- level data is available in the Docket and titled “2012 Unit

- level Data

Using the eGRID Methodology”.