### Technical Support Document (TSD) for the CAA Sec tion 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 in formation that supports EPA’s determination of

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

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

the development of the Best System of Emissi on Reductions (BSER). Th is TSD provides detailed

explanation of the data, the data underlying the stat e goal calculation, the B SER-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 stat e level data, and calculations for Option 1

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

 Appendix 3 – Summary table of state goals

 Appendix 4 - Details of stat e-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 assumpti ons regarding application of each GHG reducing

technology were identified (see GHG Abatement Meas ures 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, an d (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 anal ysis underlying each technology and informing

EPA’s assessment of its feasibility and cost-effe ctiveness 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 G as 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 repre sent 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 constructi on (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 CO 2 

### emission rate goal is informed by state-specific non-hydro RE

and EE values that relate to its pre-exis ting 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 re flect both fossil and nonfossil measures, the corresponding state goal reflect s 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 determin e 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 cho se the year 2012 as it represented the most recent

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

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

(e.g., 2009 – 2012), but determined that there woul d 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 reducti on capability and total capacity currently on the

ground. Because these two critical variables do not va ry 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 da ta 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 b ecome 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” emissions 2

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, incl uding, 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 allo ws direct comparison of the environmental

attributes of electricity generation. Although 201 2 eGRID data had not yet been released, the

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

emissions and generation data. Th e 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 pur pose 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 bl ocks 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 re present 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 ha ve 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 assume d to occur at these units). The historical

generation and emissions from IGCCs and high cap acity factor CTs are s till averaged into the

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

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

category of affected units that are covere d 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 da ta and corresponding calculations applied to

achieve the state goal rate.

ii. Data sources for under construction units

Although the 2012 eGRID data described above fo rms 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 sub set 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. N EEDS 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 w ould 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 Ca ne 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 ma de 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 pl ants. The EPA recognizes the uniqueness and

4 http://www.epa.gov/powersectormod eling/BaseCasev513.html#needs

### complexity of individual power plants, and is awar e 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/ove rachieve the assumed technology value cannot

be taken, on its own, as an indication of the appr opriateness of the state goals estimated using this

approach.3.Emission Rate CalculationEPA’s methodology for calculating state goals is described in thesteps noted below. The implementation of each step is illustrated in the tablebelow its description, using the state of Ohio as an example.Step 1:Calculation of unadjusted 2012 statefossil emission rate for covered sourcesAs noted above, the EPA begins the state goal emission rate calculation by starting with actual historic data at the state level. Unit-level data issummed to state-level values describing: coal generation, coalemission rate, NGCC generation, NGCC emission rate, OG steam generation, OGsteam emission rate, “other” emissions, “other” generation, and NGCC capacity. These categories are identified as they represent the historicalgeneration that is subject to building blockapplication and/or would likely be subject to the state goal. For combined heat and power (CHP) unitsthat are covered under the rule, the entire emissions and generation (including steam-based) from the facility are counted whendeterminingemission rates because such facilities’ entire emissions and generation would be considered whendetermining compliance with rule.5However,only the electricity generation portion of CHP is available forredispatch purposes, and therefore only this portion of the cogeneration operation isreflected in the generation totals. There are four coal facilities that co-fired biomass in 2012 that did not report emissionsunder Part 75, in thesecases an emission rate factor is used to estimate stack CO2emissions attributable to the type of biomass reported.6These technology specificvalues become the basis for calculating thestate’s emission rate. All emission rates provided in the state goal determinationare on a net basis.Therefore, they will appear slightly higher thanthe emission rates viewed on a gross generation basis.2012 Rate (lbs/MWh)2012 mass (lbs)2012 Generation (MWh)2012 CapacityStarting coveredsource rate (lbs/MWh)ABCDEFGHIJCoal RateOG SteamRateNGCCRateOther EmissionsCoal GenOG Steam genNGCC GenOther GenNGCC MWOhio2,1872,196963084,726,936343,62720,907,18304,3431,9465AseparatestategoalrateiscalculatedforIPMpowersectormodelingthatreflectstotalemissionsfromCHPunits,butjusttheelectricityprovidedtogridportionoftheirgeneration.ThiswasnecessaryasIPMreflectstotalemissionsassociatedwithcogenerationoperation,butonlythegenerationassociatedwithmeetingnetelectricitydemand.6http://www.theclimateregistry.org/downloads/2013/04/2013‐Climate‐Registry‐Default‐Emissions‐Factors.pdfNote, when the values in the above cells shaded green and blueare applied to the equation below, the state’s 2012 “unadjustedfossil” emissionrate (or historical fossil rate) for likelycovered sources is equal 1,946 lb/MWh.Historicalemission rate = (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” emissionsCoal gen. + OG gen. + NGCC gen. + “Other” gen.Step 2: BSER Block one- Calculation of state fossil emission rate goal for covered sources resultingfrom 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 elementof BSER. The EPA assumes that a 6% heat rate improvement atthe facility will directly translate to a 6% reduction in the netCO2emission rate.Therefore, in conjunction with determiningstate goals under option 1 in this proposal, the EPA adjusts the state-level coal emission rate (columnA) downwards by 6% to reflect the 6% heat rate improvement. Inthe case of Ohio, this results in a drop from 2,187 lb/MWh to 2,056 lb/MWh.This completes the building block 1 treatment for option 1.72012 Rate (lbs/MWh)2012 mass (lbs)2012 Generation (MWh)2012 CapacityState Goal Post Block 1(lbs/MWh)ABCDEFGHIJCoal RateOG SteamRateNGCCRateOther EmissionsCoal GenOG Steam genNGCC GenOther GenNGCC MWOhio2,0562,196963084,726,936343,62720,907,18304,3431,841Note that when the total emission rate isrecalculated with heat rate improvement reflected in the adjustment to the state’s coal emission rate, thestate emission rate drops from 1,946 lb/MWh to 1,841 lbs/MWh. This is not the final state emission rate goal rate, rather an emission ratereflecting building block 1 application before moving onto the remaining blocks. The bold areasin the equation below reflectthe values that areadjusted from their historical level at this stage.7EPAmakesasimilaradjustmentforoption2,butusesa4%HRIimprovementassumptionwhenreducingthecoalrateState Emission Rate Post Block 1= (coal gen.xcoal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) + “Other” EmissionsCoal 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 redispatch toexisting NGCCcapacityIn the GHG Abatement Measures TSD, the EPAdescribed how historical 2012 data illustrated that a significant number of NGCC units had a netgeneration that was greater than or equalto its nameplate capacity x 8784 * .7 – in other words a 70% or greater net capacityfactor. It alsoprovided analysis supporting a 70% capacity factor as cost-effective and historical data that illustrated the ability to increase utilization atcombined cycle units under favorable market conditions. That portion of the TSD also describes the engineering analysis that suggests the averageavailability of a NGCC is greater than 70%. Building block 2 wasintended to reflect the potential redispatch to the state’s existing NGCC fleet upto 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 multipliedby 8,784 hours(the number of hours in the 2012 year) and then by 70% to gettotal potential net NGCC generation at a 70% capacity factor. However, this 70%capacity factor represents a redispatch ceiling, and the state’s NGCC generation is only adjusted up to this ceiling if its historic fossil sourcessupport such a level.8Therefore, if this ceiling value (MWh) isless thanthe sum of the state’s 2012 coal, OG steam, and NGCC net generation,the historic NGCC generation is increased to this calculated ceiling value representing the NGCC fleet at a 70% capacity factor, and historic coaland OG steam generation are ramped down by an equivalent amountof generation. If the generation of existing NGCC at a 70% capacity factor isgreater thanthe sum of the state’s 2012 coal, OG steam, and NGCC net generation, the historical NGCC generation is only adjusted to equalthetotal of the 2012 net fossil generation from these sources. Insummary, adjusted NGCC net generation is equal to the lesser ofexisting NGCCfleet at 70% capacity factor or 2012 total fossil generation from BSER subjected sources. This preserves the historical total covered fossilgeneration in the state for BSER subjected sources, but reapportions it assuming a 70% state-average net capacity factor ceiling for the NGCCfleet. The increase in NGCC generation is subtracted from the coal and OG steam generation in proportion to the state’s historic generation. Forexample, if coal historically accounted for 90% of the total coaland OG steam generation in the state, then its historic generation would be8FossilsourcesherereferstothoseunitssubjecttoBSERredispatchbuildingblocktreatment(i.e.,coal,o/gsteam,andNGCC)reduced by 90% of the amount that NGCC generation increases. Likewise, the OG steam generation would be reduced by 10% of theamount bywhich NGCC generation is increased.2012 Rate (lbs/MWh)2012 mass (lbs)2012 Generation (MWh)2012 CapacityState Goal Post Block2.1 (lbs/MWh)ABCDEFGHIJCoal RateOG SteamRateNGCCRateOther EmissionsCoal GenOG Steam genNGCC GenOther GenNGCC MWOhio2,0562,196963078,956,358320,22326,701,16404,3431,781Note – in the above example, the total covered fossil generation has not increased inthe state from the historic totals shownin step 1. It has onlybeen reapportioned assuming a 70% capacity factor for NGCC. NGCC generation is adjusted upwards byapproximately 6,000,000 MWh, andcoal and O/G are adjusted downward by the same amount. Thisincrease in NGCC generation reflects the existing fleet increasingfrom ahistorical level of approximately 55% CF up to the ceiling of70% CF. When these updated generation values are folded into thestate goalcalculation, the emission rate drops from 1,841 lb/MWh in Step 2to 1,781 lb/MWh. This completes building block two application. The values inbold below reflect the historic data points that have been adjusted to reflect building block implementation at this point in the process.910State 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” emissionsCoal 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 redispatch to existingand“en route” NGCC capacityStep 3 is repeated for “en route” NGCC capacity that would alsobe considered an existing covered fossil source. For this step, “en route” isdefined as anything that came online in 2013 or that was under construction, site prep, or testing by January 8, 2014. The EPAlooked at reported9While a 70% capacity factor ceiling is assumed in the state goalsetting exercise, the majority of states are not expected to operate their existing fleet at thislevel in EPA’s projected compliance scenarios.10Inoption2stategoalcalculations,theEPAmakessimilaradjustmentstothehistoricdatabututilizea65%capacityfactorceilinginplaceofthe70%CFshownabove4,343MWx8784hoursx70%CF=26,701,164data for 2012 and calculated the average performance of NGCCs thatcame online in the past 5 years and observed that 55% was the averagecapacity factor for these units under a business as usual scenario.11Therefore, the EPA assumed that a 55% capacity factor would be a reasonablerepresentation for the expected generation of “en route” NGCCscapacity under a business as usual scenario. The EPA conservatively designatedthe generation associated with this 55% capacityfactor as unavailable for redispatch to reduce CO2(i.e., not qualifying for building block 2),instead, reserving that amount of generation potential to meet other system needs presumed to have motivated the construction of the “en route”NGCCs. Because these sources are nevertheless covered under the state emission rategoal, the emissions and generation from this 55%generation are added to the “other” category and averaged intothe state goal calculation. The EPA assumes that while these units would operate at55% under a business as usual scenario, the average availability forthese 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 CO2-emitting generation. Thus, 15% of their ultimate CF (70% - 55%) isassumed to be available for redispatch purposes. The MWh associated with this 15% additional CF displaces coal and OG steam generation in thesame 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 first55%) is capturedin the “other” category. The generation and emissions from these sources are still included in the ultimate emission rate quantified as the stategoal by averaging in their unadjusted emissions and generation. For “en route” NGCC units that have no 2012 historical data, the emissions andgeneration associated with the 55% baseline capacity factor is obtained by using the “en route capacity” and historical averageemission rate forNGCCs in the state.12The emissions total for these units is based on multiplying the generation at a 55% CF by the average emission rate forexisting NGCCs in the state.11http://ampd.epa.gov/ampd/12Note,bothWyomingandKentuckyhad“enroute”NGCCcapacity,butdidnothaveexistingcoveredNGCCinthestatefromwhichaproxyemissionratecouldbederivedforthe“enroute”capacity.Therefore,thenationwideaverageNGCCemissionsrateof919lb/MWh(netbasis)becametheassumedemissionrateforthe“enroute”NGCCinthesetwostates.2012 Rate (lbs/MWh)2012 mass (lbs)2012 Generation (MWh)2012Capacity"En Route"NGCCState Goal PostBlock 2.2(lbs/MWh)ABCDEFGHIJKCoal RateOGSteamRateNGCCRateOther EmissionsCoal GenOG SteamgenNGCC GenOther GenNGCC MWNGCC MWOhio2,0562,1969632,506,741,57878,249,041317,35427,411,3502,604,0174,3435391,754Note that when the total emission rate is recalculated to reflect the “en route” NGCC capacity, the state’s emission rate at this step drops from1,781lb/MWh to 1,754 lbs/MWh. This is not the final state emission rate goal rate, rather aninterim rate reflecting buildingblocks one and twoapplication before moving onto the remaining blocks. The bold areas in the equation below reflect the values that are adjustedfrom their historicallevel 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) +“Other” emissionsCoal gen. + OG gen. +NGCC gen. + “Other” gen.Step 5: BSER Block Three -Calculation of state fossil emission rate goal resulting fromheat rate improvement, redispatch to existing and enroute NGCC capacity, andnew and preserved nuclearIn Step 5, the total under construction nuclear capacity is determined.13Additionally, an amount of existing nuclear capacity that is “at risk” ofbeing retired is identified as approximately 8% of the currentnuclear fleet (see GHG AbatementMeasures TSD for further discussion on how thepercent assumption was derived). This new and preserved nuclearcapacity was incorporated into the state goals as zero emitting generation. Thiswas achieved by applying a 90% capacity factor to the nuclearcapacity identified as under construction or “at risk” and then applying the resultingMWh figure into the denominator of the state goal calculation.Nuclear is not considered a “dispatchable” resource as is NGCCcapacity. That is,13WattsBarinTN,VogtleinGA,andSummerinSC4,343MWx8784hoursx70%CF=26,701,164539x8784x15%CF=710,186Total=27,411,350its utilization will remain fairly constant in both a business-as-usual and policy scenario due toits low variable operating cost relative to fossilsources. The differing dispatch economics for NGCC and nuclear leads to a slightly different treatment in the goal setting. Existing nuclear is notassumed to increase generation in the same manner as the NGCC fleet is assumed capable ofin the above steps. Instead of redispatching fromcoal to nuclear in the same fashion as theprevious steps, the expected generation for new and preserved nuclear is simply added to the state goaldenominator – resulting in a lover state goal emission rate. However, it is important to note that this “new and preserved” nuclear capacity is alsopart of the inventory that the state can count towards compliance with its state goal (i.e., the zero emitting generation thatcan be averaged in withthat of the covered fossil sources in order to obtain a rate thatis equal to or less than the state emission rate goal). Therefore, the fossil sources donot necessarily have to lower their own emission rate to help thestate achieve the lower state goal reflected subsequent to adding in this nucleartechnology provided that the nuclear capacity continues to operate at a 90% capacity factor.2012 Rate (lbs/MWh)2012 mass (lbs)2012 Generation (MWh)2012Capacity"En Route"NGCCNew andPreservedNuclearState GoalPost Block 3.1(lbs/MWh)ABCDEFGHIJKLCoalRateOGSteamRateNGCCRateOther EmissionsCoal GenOG SteamgenNGCC GenOther GenNGCCMWNGCC MWMWhOhio2,0562,1969632,506,741,57878,249,041317,35427,411,3502,604,0174,3435391,351,2391,733Ohio has 0 MW of under construction nuclear and 171 MW of “atrisk” nuclear capacity share as described in the “GHG Abatement MeasuresTSD”. This results in an expected nuclear generation amount of1,351,239 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 1,754 lb/MWhto 1,733 lb/MWhState Emission Rate Post Block 3.1= (coal gen. x coal emission rate)+ (OG gen. x OG emission rate) + (NGCC gen. x NGCC emission rate) +“Other” emissionsCoal 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, redispatch to existing anden 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. Renewable generation haslow variable operating cost and utilization that is dictated by the renewable resources available. Like nuclear generating capacity, its utilization isnot expected to vary significantly between a business-as-usual scenario and a policy scenario. Therefore, the generation fromthese sources isadded into the denominator in a similar fashion. Consequently, all non-hydro RE generation (existing and new build) would be eligible fordemonstrating compliance with the state goal.The GHG Abatement Measures TSD describes how the RE generation total for each state was derived from a combination of existingrenewablegeneration in the state and target RE levels informed by existing Renewable Portfolio Standards (RPS) in the region. Althoughthe amount ofassumed RE generation varies by state to reflect the differentexisting portfolios of renewable resources and the amount of renewable fuelsavailable in different regions of the country, the nationwide average assumed under Option 1 is approximately 13% non-hydro REby the end of2029.14A potential non-hydro RE generation value is calculated for eachstate annually for all years between 2020-2029 to reflect the annualgrowth as states move toward a particular regional non-hydro REbenchmark. The state-specific non-hydro RE generation values that relate to thisgoal nationwide average are available in the Excel attachmentto this TSD and the GHG Abatement Measures TSD. These non-hydroRE MWhtotals 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)2012Capacity"EnRoute"NGCCNew andPreservedNuclearExisting andNew NonHydro REState GoalPost Block 3.2(lbs/MWh)ABCDEFGHIJKLMCoalRateOGSteamRateNGCCRateOtherEmissionsCoal GenOGSteamgenNGCCGenOtherGenNGCCMWNGCCMWMWhMWhOhio2,0562,1969632,506,741,57878,249,041317,35427,411,3502,604,0174,3435391,351,23913,775,5941,54014See“GHGAbatementMeasuresTSD”Ohio had 1,738,622 MWh of non-hydro RE in 201215(approximately 1% of totalnet generation) and would growto 13,775,594 MWh by 2029(approximately 10.6% of current net generation) under the building block three assumptions. This 13,775,594MWh of non-hydro RE generationwould be added into the state goal by adding it in the denominator. The RE value and resulting state goal shown above reflectthe 2029 year.When this is added into the state goal calculation, thestate’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) +“Other” emissionsCoal gen. + OG gen. + NGCC gen. + “Other” gen. + Nuclear gen. + RE gen.Step 7: BSER Block 4 -Calculation of state fossil emission rate goal resulting fromheat rate improvement, redispatch to existing NGCC, “enroute”NGCC, under construction and preserved nuclear, RE, anddemand-side EEA state-specific percent value is determined for each state reflecting the amount of total MWh sales that could potentially beavoided throughdemand-side energy efficiency measures (see GHG Abatement Measures TSD). Annual percentage savings rates for MWh sales are derived foreach state for all years between 2020 and 2029 in Option 1. A different set of annual percent savings are derived for 2020-2024under Option 2.Because of the temporal nature of demand-side energy efficiency,this building block,along with RE portionof building block three, are the onlyBSER components that increase each year. The GHG Abatement Measures TSD explains the rationale and derivation of these annualsavingsrates. Once these state-specific percent savings rates for MWhsales are derived, they are multiplied by the state’s 2012 historical retail sales andscaled by a factor of 1.0751 to obtain an avoided generation value in MWhs.16The 7.51% scaling factor effectively coverts the retails sales figureinto a corresponding total net generation value that accounts for transmission and distribution losses.17The lesser of 1) this avoided net generationvalue, or 2) the avoided net generation value multiplied by the state’s generation share of its sales is then applied to the denominator. This laststep helps assure that building block four reductions for netimporter 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 with itsstate goal.Therefore, if a state achieves the assumed avoided generation based on EE, it does not have to further lower its emission ratefrom covered fossil15http://www.eia.gov/electricity/data/state/16http://www.eia.gov/electricity/data/state/“RetailSalesofElectricitybyStateandSector”17The 7.51% scaler represents the historical difference between total net generation of electricity (4,036 TWh) and retail salesof electricity (3,754 TWh).http://www.eia.gov/electricity/state/pdf/sep2010.pdffuel fired generators determined in the previous steps. Instead, adding the avoided generationto the denominator (i.e., averaging in the avoidedgeneration 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)2012Capacity"EnRoute"NGCCNew andPreservedNuclearExisting andNew NonHydro REAvoidedSales viademandside EEPost Block4(lbs/MWh)ABCDEFGHIJKLMNCoalRateOGSteamRateNGCCRateOtherEmissionsCoal GenOGSteamgenNGCCGenOtherGenNGCCMWNGCCMWMWhMWhMWhOhio2,0562,1969632,506,741,57878,249,041317,35427,411,3502,604,0174,3435391,351,23913,775,59417,507,5561,349As described in the Demand-sideenergy efficiency section of theGHG Abatement Measures TSD, the 2029 percent of generation savings due toenergy efficiency is assumed to be 11.56% in Ohio. This value is then multiplied by the retail electricity sales in the state(152,456,864 MWh)18and multiplied by 1.0751 to reflect the net generation commensurate with these sales (i.e., inclusive of transmission and distribution losses). Thisresults in 18,942,382 MWh of avoided generation. This value is then multiplied by 92.43% (Ohio’s share of sales coming from instate powergeneration) to reflect the amount of avoidedin-state generation that results from the energy efficiency investments. This final adjustment resultsin 17,507,556 MWh of avoided generation for Ohio that is assumed for 2029. This avoided generation value is added into the denominator andresults in the state goal being decreased from 1,540 lbs/MWh to 1,349 lbs/MWh. This concludes the application of all four building blocks for theyear 2029, and the 1,349 lb/MWh rate reflects Ohio’sAdjustedemission 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” emissionsCoal gen. + OG gen. + NGCC gen.+ “Other” gen. + Nuclear gen. + RE gen. + EE gen.Step 8: Interim and Final State GoalsThe completion of the previous seven steps results in a 2029 emission rate for the state. However, as noted above, the RE andEE assumptionschange for each year from 2020 through 2029.Thus this procedure is repeated for each of those years using the corresponding RE and EEassumption for that year. This results ina set of annual adjusted emission rates for the years 2020-2029. However, this rulemaking only issues18http://www.eia.gov/electricity/data/state/two state goals – an interim and final state goal. Thus goalsare derived by averaging or taken directly from and the annual adjusted emission ratevalues.For Option 1:Interim State Goal – Average of the adjustedyearly emission rates for the period 2020-2029Final State Goal – The 2029 emission rate (as calculated above) becomes the state goal for2030 and each year thereafterFor Option 2:Interim State Goal – Average of the adjusted yearly rates for the period 2020-2029Final State Goal – The 2024 emission rate (as calculated above) becomes the state goal for2030 and each year thereafterTheEPArecognizesthattheemissionrategoalscalculatedhereincludemeasuresthatmayyieldreductionsinmassemissionsbutmaynotyieldemissionratereductionsinpracticewhenobservingmonitoredandreportedemissionandgenerationdatafromaffectedunits.Assuch,itisnotfullyinformativetocomparethestategoalscalculatedheretoobservableemissionratesacrossaffectedunitseitherhistoricallyorinfutureyears.Formorediscussionabouthowstatescandemonstratecompliancewiththeseemissionrategoals,pleaseseethe“StatePlansConsiderationsTSD”.Finally,theassumptionsusedtoarriveateachstate’sgoalarenotprescriptiveofnecessaryactionsthatastatemusttake.Asdescribedinthepreamble,thesevaluesareusedonlyforcalculatingastategoal.Astatemaychosetocomplywiththatstategoalthroughanycombinationofabatementmeasuresthatdifferinclassandmagnitudefromthoseassumedinthestategoalcalculation.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 lb/MWh((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 calculate to Interimand Final State Goals for Options 1 and 2. This workbook showsall the calculations used to transform the historical emissionrate (column B) tothe 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