FLAT F ILE GENERATION METHODOLOGY

Version : EPA Base Case v.5.13

November 2013

Content

SECTION I: INTRODUCTION

SECTION II: DATA SOURCES AND DESCRIPTIONS

SECTION III: DETAILED DATA PROCESSING

SECTION IV: FLAT FILE LAYOUT

Appendix A : Default Values

Appendix B: Temporal allocation of IPM emissions to hourly emissions for use in air quality modeling

Attachment: Flat File Inputs2 SECTION I: INTRODUCTION

This document provides the flat file generation methodology for EPA Base Case v.5.13

. The methodology takes

EPA Base Case v.5.13 using Integrated Planning Model (IPM ® ) run results (parsed outputs) and generates the

formatted flat file that the U.S. Environmental Protection Agency (U. S. EPA) uses as inp ut into air quality

modeling framework. Section II provides data descriptions and sources . Section III describes data processing

steps in detail . S ection I V describes the layout of the formatted flat file.

SECTION II: DATA SOURCES AND DESCRIPTIONS

IPM run results that have been disaggregated in to the unit, emission control technology and fuel type are the key

input

. The se results include records of fossil

- fired existing and retrofit units, along with committed and new

- build

aggregates. All fossil and biomass fired units are inc luded in the resultant formatted flat file as needed for air

quality modeling inputs. Other non fossil plant types that are part of the EPA Base Case v.5.13 modeled results

(nuclear, hydro, wind, solar PV, solar thermal, geot hermal, landfill gas, non

- fossil waste, municipal solid waste,

fuel cell, tires and pumped storage) are not included in the flat file

.

The committed and new

- build aggregates are hereafter referred to as “generic” aggregates. All records contain

the follo wing :

1. Population characteristics including state FIPS codes, county FIPS codes, recognized ORIS codes

(<80000) and unit ID s for existing and retrofit units. Generic aggregates have state level information only

. 2. Sulfur dioxide ( SO 2 )

, nitrogen oxides ( NO

x ) , and particulate matter (PM) control information for existing

and retrofit units as well as generic aggregates

. 3. Annual and seasonal heat input (TBtu).

4. Heat content s (MMBtu/ton, k

- gallon, MMcf) and SO 2 and ash contents (lb/MMBtu).

5. Annual and summer NO

x em issions (MTon)

, annual SO 2 emission s (MTon)

, HCL emissions (MTon), and

m ercury emission s (Ton).

Table 1 provides the rest of the input data ’s descriptions , sources and file locations. The FlatFile_Inputs

spreadsheet is included as an attachment to this documentation. The spreadsheet contains large amount of data

including NEEDS v

. 5

. 13 plant’s state FIPS code, county FIPS code, county’s most recent 8 hour ozone or PM2.5

attainment/non

- attainment status, ORIS code, latitud e

- longitude coordinates

, zip code

, Emission Inventory

System (EIS) unit

- specific data ( unit facility name, facility code, boiler ID, tribal code, reg code, NAICS, longitude,

latitude, facility ID, unit ID, rel point ID, process ID, agency facility ID, age ncy unit ID, agency rel point ID, agency

process ID, stack height, stack diameter, stack temperature, stack flow, and stack velocity ), filterable PM10 and

filterable PM2.5 control efficiencies and sulfur and ash contents by ORIS code

.

Table 1. Input Data Descriptions , Sources and Locations

No. Input Description Source Location

1 EIS This file contains Emission Inventory System ( EIS )

unit

- specific data that include u nit facility name,

facility code

, boiler ID, tribal code, reg code, NAICS,

longitude, latitude, facility ID, unit ID, rel point ID

, process ID, agency facility ID, agency unit ID,

agency rel point ID, agency process ID, stack

height, stack diameter, stack temperature, stack

flow, and stack velocity

. EPA FlatFile_Input

s .xls

2 GenericUnitSite This file contains all existing plants that serve as

sister plants in siting generic units. The data include

NEEDS v.5.13 plant ’ s state FIPS code, county FIPS

code, county’s most recent 8 hour ozone or PM 2.5 attainment/non

- attainment statu s, ORIS code

, latitude

- longitude coordinate s , and zip code. EPA FlatFile_Input

s .xls3 No. Input Description Source Location

3 L at L on Default This file contains latitude

- longitude coordinates by

ORIS code, state FIPS code and county FIPS code. EPA FlatFile_Input

s .xls

4 SCC This file contains Source Classification Codes

( SCCs ) by plant type, fuel type , c oal rank, firing and

bottom type (for boilers)

. EPA Table 6

5 PlantTypeStackPara

meters This file contains default stack parameters (height,

diameter, temperature and velocity) by plant type. EPA Table 7

6 SCCDefault StackPar

ameters This file contains default stack parameters (height,

diameter, temperature and velocity) by SCC. EPA Table 8

7 Control Devices This file contains post

- combustion control devices

and their associated control IDs. EPA Table 9

8 SCCDefaultHeatCont

ent This file contains default heat contents by SCC. EPA Table 10

9 SCCEmsFac This file contains emission factors for carbon

monoxide (CO), volatile organic compounds (VOC),

ammonia (NH 3 ), filterable particulate matter less

than or equal to 10 microns ( filterable PM 10 ),

filterable particulate matter less than or equal to 2.5

microns ( filterable PM 2.5 ) , primary PM 10 and primary

PM 2.5 by SCC. EPA Table 1 1

10 PMSulfurAshContent

Default This file contains default filterable PM 10 and

filterable PM 2.5 control efficiencies and sulfur and

ash contents by plant type and fuel type and coal

rank. EPA Table 1 2

11 PMCDEmsFac This file contains PM condensable emission factors

by SCC. EPA Table 1 3

12 PMAdjustmentRatio This file contains primary PM 10 and primary PM 2.5 emission factors (EF) by SCC for gas

- fired units

(including IGCC)

. EPA Table 1 4

13 PMSulfurAshContent This file contains filterable PM 10 and filterable PM 2.5 control efficiencies and sulfur and ash contents by

ORIS code, unit ID, plant type and fuel type. The

filterable PM 10 and filterable PM 2.5 control

efficiencies are based on 2001 data. EPA FlatFile_Input

s .xls4 SECTION III: DETAILED DATA PROCESSING

Flow Chart 1 describes general data processing steps. A more detailed description of each step is provided in the

subsections followed

.

Flow Chart 1

. D ata Processing Steps

I. II . Assign existing and retrofit units’ SCCs

, state FIPS codes, county FIPS codes, and

other EI S unit

- specific data that are required

for construction of the flat file. I . Disaggregate generic aggregates into generic

units, sit e the generic units’ states and counties

and assign them SCCs, ORIS codes, facility

IDs, u nit IDs , rel point IDs, and process IDs

.

V . Calculate CO, NO

x , VOC , SO 2 , NH 3 , primary PM 10 , primary PM 2.5 , Mercury (Hg),

and HCl emissions for all records

. III . Assign stack parameters and latitude

longitude/county centroid coordinates for all records.

IV

. Assign post

- combustion control device IDs

for all records.5 Generic unit data are prepared by transforming the generic aggregates into units similar to existing units in terms

of the available data. First, t he g eneric aggregates are disaggregated to create generic units. Second, t he

generic units are then sited and given state, count y and county

- centroid based latitude

- longitude coordinates

. Third, the generic units are assigned SCCs , ORIS codes, facility ID s

, unit ID s

, rel point ID s and process ID s

. This

process is performed in three steps as described in Flow Chart 2.

Flow Chart 2

. Generic Unit Processing

1. Create g eneric u nits : Generic aggregates are first disaggregated to create generic units. The process entails

two steps: i. T he generic aggregates are first aggregated by state

, plant type and , for coal steam and IGCC

, and

coal rank

. ii. T hey are then s plit into smaller generic units by dividing the aggregated capacity by a reference

capacity . T he result is the number of generic units to be created in a given state for each plant type and fuel type

. The reference capacity is varied by plant type as shown in T able 2

. Aggregated heat input and emissions are then

divided evenly among all generic units created in a given s tate for each plant type.

Table 2

. Generic Unit Reference Capacity

Plant Type Reference Capacity (MW)

Biomass 600

Coal Steam 600

Combined Cycle 250

Combustion Turbine 160

Fossil Waste 0 30

IGCC 550

Oil/Gas Steam 100

2. Site g eneric u nit s : The generic units are then given a state FIPS code, county FIPS code and latitude

longitude /county centroid based on an algorithm that sites generic units in counties within their respective states

. The generic unit siting data file

, GenericUnitSite

, is used in this algorithm to assign each generic unit a sister plant

that is in a county based on the county’s attainment/non

- attainment st atus. Within a state the hierarchy for

assignment of sister plant s in the order of county code then ORIS code is shown in Flow Chart 3

. All generic

units are sited so that their ORIS codes are unique, and the same ORIS code has the same county, latitude

longitude /county centroid across all runs of the same base case origin. 1. Create generic units

2. Site generic units

3. Assign g eneric u nits SCCs , ORIS codes,

facility IDs, u nit IDs , rel point IDs, and

process IDs

. I . Disaggregate generic aggregates into generic units, sit e the generic units’ states and counties

and assign them SCCs, ORIS codes, facility IDs, u nit IDs , rel poi nt IDs, and process IDs

.6 Flow Chart 3

. Generic Unit Siting Hierarchy

3. Assign g eneric u nits SCCs , ORIS codes, facility IDs

, unit IDs

, rel point IDs and process IDs

. i. SCC assignment is based on unit’s plant type, fuel type and coal rank as shown in T able 3

. i i. Generic unit’s ORIS code consists of a six

- digit number. The units are first sorted by plant type in the

order of combined cycle, fossil waste, combustion turbine, IGCC

, and coal steam. Generic units’ ORIS codes are

then assigned. The first digit of th e ORIS code represents the unit’s plant type as shown in Table 4. The next

three digits are a counter, starting with “000” and incrementing with each generic unit created within a given state

for each plant type. The last two digits are the state FIPS co de. For example, the first combined

- cycle generic

unit sited in Arizona, which has a state FIPS code of “04”, has an ORIS code of “700104”.

iii. Generic unit’s facility ID consists of a concatenation of the word “ORIS” and the unit’s ORIS code. For

example , the first combined

- cycle generic unit in Arizona used in the example above has a plant ID of

“ORIS700104”.

iv. Generic unit’s unit ID consists of a concatenation of a three

- letter unit ID code representing the unit’s

plant type as shown in Table 5 and th e unit’s state FIPS code. For example, the first combined

- cycle generic unit

in Arizona used in the example above has a unit ID of “ ORIS GCC04”.

v. Generic unit’s rel point ID is the same as the unit’s unit ID. For example, the first combined

- cycle generic

unit in Arizona in the example above has a point ID of “ ORIS GCC04”.

vi. Generic unit’s process ID is the same as the unit’s facility ID

.

Table 3

. Generic Unit SCC

Plant Type Fuel Type / Coal Rank SCC

Coal Steam Bituminous 10100202

Coal Steam Subbituminous 10100222

Coal Steam Lignite 10100301

Fossil Waste Process Gas 10100701

Biomass Biomass 10100902

Combined Cycle Natural Gas 20100201

Combined Cycle Oil 20100 1 01

Combustion Turbine Natural Gas 20100201

Combustion Turbine Oil 201001 01

IGCC Coal 20100301

IGCC Petroleum Coke 20100301

Oil/Gas Steam Natural Gas 10100601 S ister plants in attainment counties

S ister plants in PM non

- attainment

counties

S ister plants in 8

- hour ozone non

attainment counties7 Table 4

. Generic Unit 1 st Digit ORIS Code

Plant Type 1 st Digit of the ORIS Code

Biomass 3

Coal Steam 9

Combined Cycle 7

Combustion Turbine 8

Fossil Waste 5

IGCC 6

Oil/Gas Steam 4

Table 5

. Generic Unit ID Code

Plant Type Unit ID Code

Biomass GSC

Coal Steam GSC

Combined Cycle GCC

Combustion Turbine GGT

Fossil Waste GFW

IGCC IGC

Oil/Gas Steam GSC

1. Assign existing and retrofit units’ SCCs

. SCC, or Source Classification Code, describ es a generating unit's

characteristics. The assignment of SCC for existing and retrofit units is based on a unit’s configuration that

includes plant type, fuel type, and, if it’s a boiler, firing and bottom type

. The SCC is an eight

- digit numeric

code with sp ecific meaning (starting at the left) in the first, third, and fifth through eighth digits. For the flat

file, t he first digit of the SCC represents the type of unit (boiler [=1] or turbine [=2]). The third digit of the SCC

represents the economic sector of the unit (electric power sector=1). And the fifth through eight h digits of the

SCC represent the unit's attributes including fuel type and, if a boiler, bottom and firing type. The second

and fourth digits are zero

. Table 6 displays the SCCs.

2. Assig n existing and retrofit units’ state FIPS codes, county FIPS codes, facility IDs, rel point IDs and process

IDs. The units’ state FIPS codes, county FIPS codes, facility IDs, rel point IDs, and process IDs are

assigned from the EIS unit

- specific data file , EIS. Where the EIS provides no data, default values are used.

Appendix A describes the default values in detail.

Table 6. SCC Assignment for Existing and Retrofit Units

Plant Type Boiler / Generator Fuel Type / Coal Rank Firing Bottom SCC

Coal Steam Boiler/Generator Bituminous Wet 10100201

Coal Steam Boiler/Generator Bituminous Vertical Wet 10100201

Coal Steam Boiler/Generator Bituminous Wall Wet 10100201

Coal Steam Boiler/Generator Bituminous Vertical Dry 10100202

Coal Steam Boiler/Generator Bituminous Wall Dry 10100202

Coal Steam Boiler/Generator Bituminous Dry 10100202

Coal Steam Boiler/Generator Bituminous 10100202

Coal Steam Boiler/Generator Bituminous Wall 10100202

II . Assign existing and retrofit units’ SCCs , state FIPS codes, county FIPS codes, and other EI S

unit

- specific data that are required for construction of the flat file.8 Plant Type Boiler / Generator Fuel Type / Coal Rank Firing Bottom SCC

Coal Steam Boiler/Generator Bituminous Vertical 10100202

Coal Steam Bituminous Turbo 10100202

Coal Steam Boiler/Generator Bituminous Cyclone Wet 10100203

Coal Steam Boiler/Generator Bituminous Cyclone Dry 10100203

Coal Steam Boiler/Generator Bituminous Cyclone 10100203

Coal Steam Boiler/Generator Bituminous Stoker/SPR Wet 10100204

Coal Steam Boiler/Generator Bituminous Stoker/SPR 10100204

Coal Steam Boiler/Generator Bituminous Stoker/SPR Dry 10100204

Coal Steam Boiler/Generator Bituminous Tangential Wet 10100211

Coal Steam Boiler/Generator Bituminous Tangential 10100212

Coal Steam Boiler/Generator Bituminous Tangential Dry 10100212

Coal Steam Boiler/Generator Bituminous Cell Wet 10100215

Coal Steam Boiler/Generator Bituminous Cell 10100215

Coal Steam Boiler/Generator Bituminous Cell Dry 10100215

Coal Steam Boiler/Generator Bituminous FBC 10100218

Coal Steam Boiler/Generator Bituminous FBC Wet 10100218

Coal Steam Boiler/Generator Bituminous FBC Dry 10100218

Coal Steam Boiler/Generator Subbituminous Wet 10100221

Coal Steam Boiler/Generator Subbituminous Wall Wet 10100221

Coal Steam Boiler/Generator Subbituminous Vertical Wet 10100221

Coal Steam Boiler/Generator Subbituminous 10100222

Coal Steam Boiler/Generator Subbituminous Dry 10100222

Coal Steam Boiler/Generator Subbituminous Vertical Dry 10100222

Coal Steam Boiler/Generator Subbituminous Wall Dry 10100222

Coal Steam Boiler/Generator Subbituminous Wall 10100222

Coal Steam Boiler/Generator Subbituminous Cyclone Dry 10100223

Coal Steam Boiler/Generator Subbituminous Cyclone Wet 10100223

Coal Steam Boiler/Generator Subbituminous Cyclone 10100223

Coal Steam Boiler/Generator Subbituminous Stoker/SPR 10100224

Coal Steam Boiler/Generator Subbituminous Stoker/SPR Wet 10100224

Coal Steam Boiler/Generator Subbituminous Stoker/SPR Dry 10100224

Coal Steam Boiler/Generator Subbituminous Tangential Wet 10100226

Coal Steam Boiler/Generator Subbituminous Tangential Dry 10100226

Coal Steam Boiler/Generator Subbituminous Cell Wet 10100235

Coal Steam Boiler/Generator Subbituminous Cell Dry 10100235

Coal Steam Boiler/Generator Subbituminous Cell 10100235

Coal Steam Boiler/Generator Subbituminous FBC Dry 10100238

Coal Steam Boiler/Generator Subbituminous FBC Wet 10100238

Coal Steam Boiler/Generator Subbituminous FBC 10100238

Coal Steam Boiler/Generator Lignite Wall Dry 10100301

Coal Steam Boiler/Generator Lignite Wet 10100301

Coal Steam Boiler/Generator Lignite Tangential Wet 10100302

Coal Steam Boiler/Generator Lignite Tangential Dry 101003029 Plant Type Boiler / Generator Fuel Type / Coal Rank Firing Bottom SCC

Coal Steam Boiler/Generator Lignite Cyclone 10100303

Coal Steam Boiler/Generator Lignite Cyclone Wet 10100303

Coal Steam Boiler/Generator Lignite Stoker/SPR Wet 10100306

Coal Steam Boiler/Generator Lignite Stoker/SPR 10100306

Coal Steam Boiler/Generator Lignite Stoker/SPR Dry 10100306

Coal Steam Boiler/Generator Lignite FBC 10100318

Coal Steam Boiler/Generator Lignite FBC Wet 10100318

Coal Steam Boiler/Generator Lignite FBC Dry 10100318

O/G Steam Boiler/Generator Oil 10100401

O/G Steam Boiler/Generator Oil Wall Dry 10100401

O/G Steam Boiler/Generator Oil Tangential 10100404

O/G Steam Orimulsion Wall 10100409

O/G Steam Orimulsion Other 10100409

O/G Steam Boiler/Generator Natural Gas 10100601

O/G Steam Boiler/Generator Natural Gas Wall 10100601

O/G Steam Boiler/Generator Natural Gas Wall Dry 10100601

O/G Steam Natural Gas Wall Wet 10100601

O/G Steam Natural Gas Vertical Dry 10100601

O/G Steam Natural Gas Vertical 10100601

O/G Steam

_ Natural Gas Cell

_ 10100601

O/G Steam Natural Gas Cyclone Dry 10100601

O/G Steam Natural Gas Cyclone Wet 10100601

O/G Steam Natural Gas Cyclone 10100601

O/G Steam Natural Gas Other Dry 10100601

O/G Steam Natural Gas Tangential Dry 10100604

O/G Steam Natural Gas Tangential Wet 10100604

O/G Steam Boiler/Generator Natural Gas Tangential 10100604

Fossil Waste Boiler Process Gas 10100701

Coal Steam Boiler/Generator Petroleum Coke Vertical Dry 10100801

Coal Steam Petroleum Coke Wall 10100801

Coal Steam Boiler/Generator Petroleum Coke 10100801

Coal Steam Boiler/Generator Petroleum Coke FBC Dry 10100818

Coal Steam Boiler/Generator Biomass 10100902

Coal Steam Boiler/Generator Waste Coal 10102001

Coal Steam Boiler/Generator Waste Coal Wall 10102001

Coal Steam Boiler/Generator Waste Coal FBC 10102018

Combined

Cycle Generator Oil 20100101

Combustion

Turbine Boiler/Generator Oil 20100101

Combined

Cycle Boiler/Generator Natural Gas 20100201

Combined

Cycle Natural Gas 2010020110 Plant Type Boiler / Generator Fuel Type / Coal Rank Firing Bottom SCC

Combustion

Turbine Boiler/Generator Natural Gas 20100201

Fossil Waste Generator Process Gas 20100201

IGCC Boiler/Generator 20100301

1. Assign s tack p arameters for all u nits : Existing and retrofit unit’s stack parameters are assigned based on

the hierarchy described in Flow Chart 4

. Existing and retrofit units’ stack parameters are first assigned

based on a unit’s plant type as shown in Table 7. If Table 7 provides no plant type

- based stack

parameters, the units are assigned EIS stack parameters from the EIS. Where the EIS data file provides

no stack parameters, the units are assigned default stack parameters based on a unit’s SCC as shown in

Table 8. Generic units are assigned SCC

- based default stack parameters. Units’ stack flows are

assigned from the EIS data file, except for IGCC units which receive default stac k flow by plant type as

shown in Table 7. Where the EIS data file provides no stack flow data, stack flows are calculated as

follows:



### ) (ft/sec Velocity Stack *

2 (ft) Diameter Stack

* 3.141592 (cft/sec) Flow Stack 2 

###      

=

2. Assign latitude

- longitude coordinates : Latitude

- longitude coordinates are assigned from the EIS data file.

If the EIS data file provides no data, latitude

- longitude/county centroid coordinates are assigned based on

a unit’s sister ORIS code from the file “ LatLonDefault. ”

Flow Chart 4. Stac k Parameters Assignment Hierarchy

Table 7

. Plant Type

- Based Stack Parameters

Plant Type Stack Height

(ft) Stack Diameter

(ft) Stack Temperature

(degree F) Stack Velocity

(ft/sec) Stack Flow

(cft/sec)

IGCC 150 19 340 75.8 21491.48 Plant Type

- Based Stack Parameters

EIS Stack Parameters

SCC

- Based Default Stack Parameters III . Assign stack parameters and latitude

- longitude/county centroid coordinates for all records.11 Table 8. SCC

- Based Default Stack Parameters

SCC Stack

Height

(ft) Stack

Diameter

(ft) Stack

Temperature

(oF) Stack

Velocity

(ft/sec)

10100201 603.2 19.8 281.2 076.5

10100202 509.7 14.6 226.0 062.0

10100203 491.6 16.6 278.4 080.5

10100204 225.0 00.6 067.2 002.4

10100211 490.0 17.4 280.0 076.4

10100212 445.6 17.4 275.2 077.6

10100215 509.7 14.6 226.0 062.0

10100218 399.3 10.8 245.6 040.1

10100221 983.0 22.8 350.0 110.0

10100222 468.5 16.0 254.7 065.6

10100223 446.8 15.9 308.0 093.6

10100224 255.5 10.0 251.3 015.3

10100226 495.8 18.9 259.2 091.2

10100235 468.5 16.0 254.7 065.6

10100238 600.0 22.5 315.0 078.0

10100301 427.5 22.3 232.8 074.2

10100302 483.5 21.0 229.4 092.4

10100303 462.0 21.7 271.3 072.5

10100306 300.0 07.2 441.0 067.0

10100318 326.7 12.3 326.7 074.7

10100401 252.9 10.1 258.1 042.6

10100404 322.1 14.0 301.8 062.8

10100409 252.9 10.1 258.1 042.6

10100601 263.9 10.3 236.0 046.9

10100604 308.0 15.2 275.2 066.0

10100701 239.2 09.4 238.0 042.3

10100801 371.3 05.5 122.4 020.4

10100818 399.3 10.8 245.6 040.1

10100902 303.4 03.3 137.7 016.1

10102001 509.7 14.6 226.0 062.0

10102018 399.3 10.8 245.6 040.1

20100101 057.7 09.6 655.8 064.9

20100201 062.0 10.0 585.3 061.3

20100301 150.0 19.0 340.0 075.812 C ontrol I Ds are assigned to reflect all post

- combustion control devices installed at a unit. The control devices can

be installed at either existing or retrofit level, or both. Table 9 lists the control devices and their associated control

IDs.

Table 9 : Post

- Combustion Control Devices

Control ID Description

119 Dry FGD

139 SCR

140 SNCR or other N O

x

141 Wet FGD

206 DSI

207 ACI

Emissions are calculated at three levels: annual, season al and monthly emissions.

1. A nnual emission calculations

i. Annual NO

x , SO 2 , m ercury ( H g) , and HCl emissions (tons) are taken directly from IPM run results

.

ii. Annual CO, VOC and NH 3 emissions (tons) are calculated by multiplying the unit’s fuel use and

uncontrolled emission factor s for CO, VOC and NH 3 as follows:



### = (tons) Emissions Annual

Pollutant



### ton) (lb 2000 f) gallon,MMc (lb/ton,k Factor Emission * f) gallon,MMc (ton,k Use Fuel Annual

Pollutant



### / − −

W here :



### 2000 converts lb to short ton and the pollutants are CO, VOC, and NH 3

.



### )

, , ( MMcf gallon k ton Use Fuel Annual

− is calculated from IPM run results

, which are in

MMBtu of annual heat input and converted into physical units of annual fuel use as follows: IV

. Assign post

- combustion control device IDs for all records.

V . Calculate CO, NO

x , VOC , SO 2 , NH 3 , primary PM 10 , primary PM 2.5 , Mercury (Hg), and HCl emissions for

all records

.13 

### =

− )

, , ( MMcf gallon k ton Use Fuel



### )

, , / ( ) (

MMcf gallon k ton MMBtu Content Heat MMBtu Input Heat

−

Where 

### )

, , / ( MMcf gallon k ton MMBtu Content Heat

− is assigned using EPA Base

Case v.5.13 assumptions for coal a nd petroleum coke units. All other units are assigned

default heat contents based on the unit’s SCC as shown in Table 10

.

Table 10 : SCC

- Based Default Heat Content

(MMBtu/ton, K

- gallon, MMcft)

SCC Heat Content

10100401 0152

10100404 0152

10100409 0152

10100601 1024

10100604 1024

10100701 0671

10100902 0012

20100101 0138

20100201 1024



### f) gallon,MMc (lb/ton,k Factor edEmission Uncontroll

Pollutant 

### − is assigned for CO, VOC, NH 3

based on a unit’s SCC as shown in Table 1 1.

Table 1 1: SCC

- Based Emission Factors

( lbs/ton, k

- gal, MMcft)

SCC CO

EF VOC

EF NH 3

EF Filterable PM 10

EF Filterable PM 2.5

EF PM Flag 1

10100201 00.50 00.04 00.03 02.60 01.48 A

10100202 00.50 00.06 00.03 02.30 00.60 A

10100203 00.50 00.11 00.03 00.26 00.11 A

10100204 05.00 00.05 00.03 13.20 04.60

10100211 00.50 00.04 00.03 02.60 01.48 A

10100212 00.50 00.06 00.03 02.30 00.60 A

10100215 00.50 00.06 00.03 02.30 00.60 A

10100218 18.00 00.05 00.03 12.40 01.36

10100221 00.50 00.04 00.03 02.60 01.48 A

10100222 00.50 00.06 00.03 02.30 00.60 A

10100223 00.50 00.11 00.03 00.26 00.11 A

10100224 05.00 00.05 00.03 13.20 04.60

10100226 00.50 00.06 00.03 02.30 00.60 A

10100235 00.50 00.06 00.03 02.30 00.60 A

10100238 18.00 00.05 00.03 16.10 04.20

10100301 00.25 00.07 00.03 01.80 00.52 A

10100302 00.60 00.07 00.03 02.30 00.66 A14 SCC CO

EF VOC

EF NH 3

EF Filterable PM 10

EF Filterable PM 2.5

EF PM Flag 1

10100303 00.60 00.07 00.03 00.87 00.37 A

10100306 05.00 00.07 00.03 01.60 00.56 A

10100318 00.15 00.03 00.03 12.00 01.40

10100401 05.00 00.76 00.80 2 3

10100404 05.00 00.76 00.80 2 3

10100409 05.00 00.76 00.80 2 3

10100601 84.00 05.50 03.20 4 4

10100604 24.00 05.50 03.20 4 4

10100701 06.57 00.43 01.20 4 4

10100801 00.60 00.07 00.40 07.90 04.50 A

10100818 18.00 00.05 00.40 12.40 01.36

10100902 06.80 00.19 00.09 05.70 04.90

10102001 00.25 00.07 00.03 01.82 00.52 A

10102018 00.15 00.03 00.03 12.00 01.40

20100101 00.46 00.06 06.62 00.60 00.60

20100201 84.00 02.10 06.56 4 4

20100301 35.00 02.20 06.56 4 4

1 Multiply ash content % (A) by the PM EF numeric value to obtain the EF.

2 Filterable PM 10 EF = 5.9 * (1.12 * S + 0.37), where S=sulfur content %.

3 Filterable PM 2.5 EF = 4.3 * (1.12 * S + 0.37), where S=sulfur content %.

4 There are no EF for these SCC because of uncertainty due to an artifact of the test method used in the past.

PM 10 and PM 2.5 primary are calculated directly from their EF (see Table 1 3 ).

i i i. Annual primary PM 10 and PM 2.5 emissions (tons) are calculated for all but gas

- fired and IGCC units by

adding the filterable PM 10 and filterable PM 2.5 emissions to condensable PM emissions

. Filterable PM 10

and PM 2.5 emissions for each unit are based on historical information regarding existing emissions

controls and types of fuel burned and ash content of the fuel burned, as well as the projected emission

controls (e.g., scrubbers and fabric filters). Condensable PM emissions are based on plant type, sulfur

content of the fuel, and 

### SO 2 /HCl and PM control configurations. Although EPA’s analysis is based on the

best available emission factors, these emission factors do not account for the potential changes in

condensable PM emissions due to the installation and operation of SCRs. The formation o f additional

condensable PM (in the form of 

### SO 3 and H 2 SO

4 ) in units with SCRs depends on a number of factors,

including coal sulfur content, combustion conditions and characteristics of the catalyst used in the SCR,

and is likely to vary widely from unit t o unit. SCRs are generally designed and operated to minimize

increases in condensable PM. This limitation means that condensable PM emissions are potentially

underestimated for units with SCRs. In contrast, it is possible condensable PM emissions are

o verestimated in a case where the unit is combusting a low

- sulfur coal in the presence of a scrubber.15 

### = ) ( tons Emission Annual

10 PM Primary



# ( ) ) ( ) (

10 

### tons Emission Annual tons Emission Annual

e Condensabl PM PM Filterable 

### +

= ) ( tons Emission Annual

2.5 PM Primary



# ( ) ) ( ) (

5

. 2 

### tons Emission Annual tons Emission Annual

e Condensabl PM PM Filterable 

### +

Where :



### = ) (

10 

### tons Emission Annual

PM Filterable



###  

 

 

 

− −

) / ( 2000 )

, , / ( * )

, , (

10



### ton lb MMcf gallon k ton lb Factor Emission MMcf gallon k ton Use Fuel

PM Filterable



###  

 

 

 

− 100

1 * 10 PM 

### Efficiency Control Filterable 

# ( ) (%) * Content Ash

= ) (

5

. 2 

### tons Emission Annual

PM Filterable



###  

 

 

 

− −

) / ( 2000 )

, , / ( * )

, , (

5

. 2



### ton lb MMcf gallon k ton lb Factor Emission MMcf gallon k ton Use Fuel

PM Filterable



###  

 

 

 

− 100

1 * 5

. 2 PM 

### Efficiency Control Filterable 

# ( ) (%) * Content Ash

If 

### ) (

5

. 2 

### tons Emission Annual

PM Filterable 

### is greater than 

### ) (

10 

### tons Emission Annual

PM Filterable 

### ,



### ) (

5

. 2 

### tons Emission Annual

PM Filterable 

### is set equal to 

### ) (

10 

### tons Emission Annual

PM Filterable 

### .



### ) / ( 2000 ) / ( * ) (

ton lb MMBtu lb Factor Emission MMBtu Input Heat Annual

e Condensabl PM 

### = ) ( tons Emission Annual

e Condensabl PM16 W here :



### 2000 converts lb to short ton and the pollutants are CO, VOC, and NH 3

.

10 PM 

### Efficiency Control Filterable and

5

. 2 PM 

### Efficiency Control Filterable are assigned

based on a unit’s ORIS code, unit ID, plant type and fuel type from the data file

PMSulfurAshContent. Where PMSulfurAshContent provides no data, default values based on a

unit’s plant type and fuel type and coal rank as s hown in Table 1 2 are used. 1

Table 1 2 : Default PM Control Efficiencies and Sulfur and Ash Contents

Plant Type Fuel Type /

Coal Rank Filterable

PM 10 Control

Efficiency (%) Filterable

PM 2.5 Control

Efficiency (%) Sulfur

Content

(%) Ash

Content

(%)

Biomass Biomass 99.2 99.2 1.67 10.8

Coal Steam Bituminous 99.2 99.2 1.67 10.8

Coal Steam Subbituminous 99.2 99.2 0.32 05.6

Coal Steam Lignite 99.2 99.2 0.87 13.9

Coal Steam Petroleum Coke 99.2 99.2 5.30 00.1

Coal Steam Waste Coal 99.2 99.2 2.38 43.7

Coal Steam Biomass 99.2 99.2 1.67 10.8

IGCC Bituminous 1.67 10.8

IGCC Subbituminous 0.32 05.6

IGCC Lignite 0.87 13.9

IGCC Petroleum Coke 5.30 00.1

O/G Steam Oil 99.2 99.2 0.89 00.0

O/G Steam Orimulsion 99.2 99.2 0.89 00.0

Combustion

Turbine Oil 0.11 00.0

Combined Cycle Oil 0.11 00.0



### ) / ( ) / (

2 

### MMBtu lb Content Ash and MMBtu lb Content SO are assigned using EPA Base

Case v .5.13 assumptions. The EPA Base Case v.5.13 SO 2 and ash contents are in lb/ MMBtu

and converted into percentage

- of

- fuel sulfur and ash contents as follows:

i. Sulfur content conversion

If fuel type is coal, waste coal or petroleum coke :



### = (%) Content Sulfur



### 100 * ) / ( 2000 * 2 ) / ( * ) / (

2



### ton lb ton MMBtu Content Heat MMBtu lb Content SO

1 For units with existing ESPs but still not able to meet their MATS filterable PM requirement, unit

- specific

filterable PM incremental reductions needed to meet the requirement are incorporated into the units’

10 PM 

### Efficiency Control Filterable and

5

. 2 PM 

### Efficiency Control Filterable . For information on the unit

specific incremental filterable PM reductions needed and incorporated here, see Document for EPA Base Case

v.5.13 Using Integrated Planning Model, Chapter 5, Section 5.6.1.17 where 2000 converts lb to short ton.

If fuel type is oil:



### = (%) Content Sulfur



### 100 * ) / ( 7882 * 2 ) / ( * ) / (

2 

### gallon k lb gallon k MMBtu Content Heat MMBtu lb Content SO

− −

where 7882 converts lb to k

- gallon of oil.

If fuel type is fossil waste and the unit uses process gas SCC “101007”:



### = (%) Content Sulfur



### 100 * ) / ( 52794 * 2 ) / ( * ) / (

2



### MMcf lb MMcf MMBtu Content Heat MMBtu lb Content SO

where 52794 converts lb to MMcf of fossil waste 2

.

If fuel type is fossil waste and the unit uses natural gas SCC "201002":



### = (%) Content Sulfur



### 100 * ) / ( 44000 * 2 ) / ( * ) / (

2



### MMcf lb MMcf MMBtu Content Heat MMBtu lb Content SO

where 44000 converts lb to MMcf of natural gas.

No sulfur content conversion is performed for natural gas as the sulfur content for natural

gas is assumed to be zero.

ii. Ash content conversion for coal



### = (%) Content Ash

100 *

2000 ) / ( * ) / ( ton MMBtu Content Heat MMBtu lb Content Ash

where 2 000 is the number of lb per short ton.

I f no sulfur and ash content assumptions from EPA Base Case v.5.13 are available, default values based

on a unit’s ORIS code, unit ID, plant type and fuel type from the data file PMSulfurAshContent are used

first ; default values based on plant type and coal rank in Table 1 2 are used second. This hierarchy is

s ummarized in Flow Chart 5

.

2 Fossil waste using process gas SCC is assumed to be a combination of coke

- oven gas and blast

- furnace gas.18 Flow Chart 5

. Sulfur and Ash Contents Assignment Hierarchy



### ) / ( MMBtu lb Factor Emission

e Condensabl PM is assigned for all units based on units’

SCCs and whether they have either a n SO 2 control or PM scrubber installed as shown in

Table 1 3

.

Table 1 3 : SCC

- Based PM Condensable Emission Factors

(lbs/MMBtu)

SCC SO 2 Control 1 PM Control 1 PM Condensable EF 2

10100201 Wet Scrubber PM Scrubber 0.0200

10100201 Dry Scrubber PM Scrubber 0.0200

10100202 Wet Scrubber PM Scrubber 0.0200

10100202 Dry Scrubber PM Scrubber 0.0200

10100203 Wet Scrubber PM Scrubber 0.0200

10100203 Dry Scrubber PM Scrubber 0.0200

10100204 0.0400

10100211 Wet Scrubber PM Scrubber 0.0200

10100211 Dry Scrubber PM Scrubber 0.0200

10100212 Wet Scrubber PM Scrubber 0.0200

10100212 Dry Scrubber PM Scrubber 0.0200

10100215 Wet Scrubber PM Scrubber 0.0200

10100215 Dry Scrubber PM Scrubber 0.0200

10100218 0.0100

10100221 Wet Scrubber PM Scrubber 0.0200

10100221 Dry Scrubber PM Scrubber 0.0200

10100222 Wet Scrubber PM Scrubber 0.0200

10100222 Dry Scrubber PM Scrubber 0.0200

10100223 Wet Scrubber PM Scrubber 0.0200

10100223 Dry Scrubber PM Scrubber 0.0200

10100224 0.0400

10100226 Wet Scrubber PM Scrubber 0.0200

10100226 Dry Scrubber PM Scrubber 0.0200

10100235 Wet Scrubber PM Scrubber 0.0200 1. EPA Base Case v.5.13 SO 2 and ash content (lb/MMBtu) assumptions,

converted into percentage

- of

- fuel sulfur and ash contents

2. Default percentage

- of

- fuel sulfur and ash contents by ORIS code, unit

ID, plant type and fuel type

3. Default percentage

- of

- fuel sulfur and ash contents by plant type and

fuel rank19 SCC SO 2 Control 1 PM Control 1 PM Condensable EF 2

10100235 Dry Scrubber PM Scrubber 0.0200

10100238 0.0100

10100301 Wet Scrubber PM Scrubber 0.0200

10100301 Dry Scrubber PM Scrubber 0.0200

10100302 Wet Scrubber PM Scrubber 0.0200

10100302 Dry Scrubber PM Scrubber 0.0200

10100303 Wet Scrubber PM Scrubber 0.0200

10100303 Dry Scrubber PM Scrubber 0.0200

10100306 0.0400

10100318 0.0100

10100401 0.0100

10100404 0.0100

10100409 0.0100

10100801 0.0100

10100818 0.0100

10100902 0.0170

10102001 Wet Scrubber PM Scrubber 0.0200

10102001 Dry Scrubber PM Scrubber 0.0200

10102018 0.0100

20100101 0.0072

1 For the given SCC, only one of the controls need be present for the EF to be assigned.

2 For SCCs that have non

- blank controls for both SO 2 and PM, then EF = (0.1 * S)

- 0.03,

(where S=sulfur content %), but if the EF is less than 0.01, set it equal t o 0.01.

For the SCCs in Table 1 3 that have non

- blank controls for both SO 2 and PM, their PM condensable emission

factor can be calculated using the equation below:



# ( ) 03

. 0 (%) * 1

. 0

− = Content Sulfur Factor Emission e Condensabl PM

If the calculated value is less than the floor of 0.01 lb/ MMBtu, then 0 .01 is assigned as the PM condensable

E mission F actor in place of the calculated value.

Also, u nits hav ing a n SO 2 control are assigned the lower of the PM condensable emission factor from Table 1 3

and the calculated PM condensable emission factor using the above equation.

Primary PM 10 and p rimary PM 2.5 cannot be estimated for gas

- fired units (including IGCCs) using the same

methodology as the other fuels sin c e there are no accurate filter able em ission factors for them. Thus, their

emission s are estimated di rectly. Primary PM 10 and p rimary PM 2.5 emission factors in lb/MMBtu are assigned

based on each unit’s SCC as shown in Table 1 4

.20 Table 1 4 : Primary PM 10 and Primary PM 2.5 Emission Factors for Gas

- Fired and IGCC Units

(lb/MMBtu)

SCC Primary PM 10 EF Primary PM 2.5 EF

10100601 0.532 0.440

10100604 0.532 0.440

10100701 0.043 0.035

20100201 0.317 0.195

20100301 11.263 11.263

2

. Season al emission calculations:

Summer is considered to be the 153 days between May 1 and Septem b er 30 inclusive

. Summer NO

x emissions

are taken directly from IPM run results. For all other pollutants, summer emissions are calculated by multiplying

the annual emissions by the ratio of the summer to annual heat input.



### * ) ( ) ( tons Emissions Annual tons Emissions Summer

= 

###  

 

 

 

MMBtu Input Heat Annual MMBtu Input Heat Summer

( ) (

Winter is considered to be the 212 days between October 1 and April 30 inclusive that are not considered to be

summer days. Winter emissions are calculated by subtracting the summer emissions from the annual emissions.



### ) ( ) ( tons Emissions Summer tons Emissions Annual (tons) Emissions Winter

− =

3

. Monthly emission calculations:

Summer monthly emissions for are calculated as follows:



### = ) ( tons Emissions Monthly Summer Month in Day of Number tons Emissions Summer

*

153 ) (

Winter monthly emissions are calculated as follows:



### = ) ( tons Emissions Monthly Winter Month in Day of Number tons Emissions Winter

*

212 ) (21 SECTION I V : FLAT FILE LAYOUT

The processed data are then converted into a flat file for U.S. EPA to use in air quality modeling work

. Both

c riteria and HAP emissions are provided in the same file. The pollutants are provided in the following order: CO,

NO

x , VOC, SO 2 , NH 3 , primary PM 10 , primary PM 2.5 , Mercury (Hg), and HCl.

The f ile ’ s naming convention is as follows:

FlatFile _<ipm run alpha

- numeric only>_<year4>_<date created using yyyy mmdd >.txt

where:

year4 = 4

- digit year of the emissions (e.g., 20 30 )

yyyy = 4

- digit year

mm = 2

- digit month number (e.g. 01 through 12)

dd = 2

- digit date number (e.g., 01 through 31)

F or example : ' FlatFile

_ EPA 513

_ BC_ 7c

_ 20 18

_ 201311 08 .txt ’

.

All data fields are comma

- delimited and c haracter data, i ncluding comma s , semi

- colon s

, and space s , are

enclosed in double

- quotes.

The file contains the following h eader line s :

#FORMAT=ff10_POINT

#COUNTRY=US

#YEAR= <year of emissions>

#VALUE_UNITS=TON

#CREATION_DATE= < date created >

#CREATOR_NAME=US EPA

- CAMD

#DATA_SET_ID=1,US EPA IPM

#COUNTRY_CD,REGION_CD,TRIBAL_CODE,EIS_FACILITY_ID,EIS_UNIT_ID,EIS_REL_P OINT_ID,EIS_PRO

CESS_ID,AGY_FACILITY_ID,AGY_UNIT_ID,AGY_REL_POINT_ID,AGY_PROCESS_ID,SCC,POLL,ANN_VALU

E,ANN_PCT_RED,FACILITY_NAME,ERPTYPE,STKHGT,STKDIAM,STKTEMP,STKFLOW,STKVEL,NAICS,LON

GITUDE,LATITUDE,LL_DATUM,HORIZ_COLL_MTHD,DESIGN_CAPACITY,DESIGN_CAPACITY_ UNITS,REG_

CODES,FAC_SOURCE_TYPE,UNIT_TYPE_CODE,CONTROL_IDS,CONTROL_MEASURES,CURRENT_COST

,CUMULATIVE_COST,PROJECTION_FACTOR,SUBMITTER_FAC_ID,CALC_METHOD,DATA_SET_ID,FACIL_

CATEGORY_CODE,ORIS_FACILITY_CODE,ORIS_BOILER_ID,IPM_YN,CALC_YEAR,DATE_UPDATED,FUG_

HEIG HT,FUG_WIDTH_YDIM,FUG_LENGTH_XDIM,FUG_ANGLE,ZIPCODE,ANNUAL_AVG_HOURS_PER_YE

AR,JAN_VALUE,FEB_VALUE,MAR_VALUE,APR_VALUE,MAY_VALUE,JUN_VALUE,JUL_VALUE,AUG_VALU

E,SEP_VALUE,OCT_VALUE,NOV_VALUE,DEC_VALUE,JAN_PCTRED,FEB_PCTRED,MAR_PCTRED,APR_P

CTRED,MAY_PCTRED,JUN _PCTRED,JUL_PCTRED,AUG_PCTRED,SEP_PCTRED,OCT_PCTRED,NOV_PCT

RED,DEC_PCTRED,COMMENT

The last header line contains comma

- delimited field names identifying the data contained in each data field

.22 Appendix A

Default Values

Field Name Defa u lt Value

COUNTRY_CD 

### N/A

REGION_CD 

### N/A

TRIBAL_CODE 

### N/A

EIS_FACILITY_ID "ORIS" followed by the ORIS_FACILITY_CODE. For example,

ORIS55177.

EIS_UNIT_ID "ORIS" followed by the ORIS_BOILER_ID. For example, ORISST1.

EIS_REL_POINT_ID "ORIS" followed by the ORIS_BOILER_ID. That is, the same as the

unit ID default value.

EIS_PROCESS_ID Use the same value as in the [IPM Y/N] field. That is, the NEEDS

UniqueID.

AGY_FACILITY_ID Blank

AGY_UNIT_ID Blank

AGY_REL_POINT_ID Blank

AGY_PROCESS_ID Blank

SCC N/A

POLL N/A

ANN_VALUE N/A

ANN_PCT_RED Blank

FACILITY_NAME NEEDS Plant Name

ERPTYPE Blank

STKHGT SCC

- based default stack parameters from

SCCDefaultStackParameters file.

STKDIAM SCC

- based default stack parameters from

SCCDefaultStackParameters file.

STKTEMP SCC

- based default stack parameters from

SCCDefaultStackParameters file.

STKFLOW SCC

- based default stack parameters from

SCCDefaultStackParameters file.

STKVEL SCC

- based default stack parameters from

SCCDefaultStackParameters file.

NAICS Blank

LONGITUDE County

- centroid based longitude by ORIS code, state FIPS code and

country FIPS code from LatLonDefault file.

LATITUDE County

- centroid based longitude by ORIS code, state FIPS code and

country FIPS code from LatLonDefault file.

LL_DATUM Blank

HORIZ_COLL_MTHD Blank

DESIGN_CAPACITY N/A

DESIGN_CAPACITY_UNITS N/A

REG_CODES Blank

FAC_SOURCE_TYPE "125"

UNIT_TYPE_CODE "100" for Boiler, "120" for Turbine, "140" for combined cycle

(boiler/gas turbine).23 Field Name Defa u lt Value

CONTROL_IDS N/A

CONTROL_MEASURES Blank

CURRENT_COST Blank

CUMULATIVE_COST Blank

PROJECTION_FACTOR Blank

SUBMITTER_ID N/A

CALC_METHOD N/A

DATA_SET_ID N/A

FACIL_CATEGORY_CODE N/A

ORIS_FACILITY_CODE NEEDS ORIS Code

ORIS_BOILER_ID NEEDS Unit ID

IPM_YN N/A

INV_YEAR N/A

DATE_UPDATED N/A

FUG_HEIGHT Blank

FUG_WIDTH_YDIM Blank

FUG_LENGTH_XDIM Blank

FUG_ANGLE Blank

ZIPCODE N/A

ANNUAL_AVG_HOURS_PER_YEAR N/A

JAN_VALUE N/A

FEB_VALUE N/A

MAR_VALUE N/A

APR_VALUE N/A

MAY_VALUE N/A

JUN_VALUE N/A

JUL_VALUE N/A

AUG_VALUE N/A

SEP_VALUE N/A

OCT_VALUE N/A

NOV_VALUE N/A

DEC_VALUE N/A

JAN_PCTRED Blank

FEB_PCTRED Blank

MAR_PCTRED Blank

APR_PCTRED Blank

MAY_PCTRED Blank

JUN_PCTRED Blank

JUL_PCTRED Blank

AUG_PCTRED Blank

SEP_PCTRED Blank24 Field Name Defa u lt Value

OCT_PCTRED Blank

NOV_PCTRED Blank

DEC_PCTRED Blank

COMMENT Blank25 Appendix B

Temporal A llocation of IPM Projected Seasonal E missions to H ourly E missions for U se in A ir Q uality

M odeling

IPM provides u nit level emission projections of average winter (representing October through April) and average summer (representing May through September) values. These annualized emissions are allocated to hourly

emissions using a 3

- step methodology : annualized summe r/ winter value to month, month to day, and day to hour.

The first two steps are done outside of SMOKE and the third step is done by SMOKE using daily emissions files

created from the first two steps. For each of these three temporal allocation steps, NO

x and SO 2 CEM S data are

used to allocate NO

x and SO 2 emissions, while CEM S heat input data are used to allocate all other pollutants.

The approach defined here gives priority to temporalization based on the air quality analysis year CEMS data to

the maximum extent possible.

For units defined by CAMD as peaking units, the NO

x and SO 2 emissions are temporalized according to the

pattern followed in the base year, while emissions of other pollutants are temporalized by heat input. For non

peaking units for whi ch CEMS data is avai lable, the emissions are tempora lized based on the CEMS data for that

unit and pollutant. For non

- peaking units for which CEMS data is not available, the allocation of the IPM seasonal

emissions to months is done using average fuel

- spe cific season

- to

- month factors generated for each of the 64

IPM regions shown in the Figure. These factors are based on a single year of CEMS data for the modeling base

year associated with the air quality modeling analysis being performed, such as 2011. The fuels used for creating

the profiles for a region are coal, natural gas, and other. Separate profiles are computed for NO

x , SO 2 , and heat

input. An overall composite profile is also computed and can be used in the event that a fuel

- specific profile is too

irregular or in the case when a unit changes fuels between the base and future year and there were previously no

units with that fuel in the region containing the unit.

Units with year

- specific impacts in the season

- to

- month allocations, such as long

- duration downtimes for

maintenance or installation of controls that occur only in one year are temporalized with average profiles instead

of using the anomalous profile for the base year. These situations are determined by analysis of the base and

future year data. Note that IPM uses load data (reflecting the shape of demand) corresponding to the load in each

IPM region that occurred in the base year of the air quality modeling analysis, such as 2011.

For units with CEMS data, emissions are allocated from month to day according to profiles based on the CEMS

data. For units without CEMS data, emissions are allocated from month to day using IPM

- region and fuel

- specific

average month

- to

- day factors based on CEM S data from the base year of the air quality modeling analysis.

Separate allocations are computed for NOx

, SO 2 , and heat input for the fuels coal, natural gas, and other

.

Hourly allocation for i nventory units with associated CEMS data use values apportioned according to the same

pattern as the hourly CEMS values. For units without CEMS data, temporal profiles from days to hours are

computed based on the region and fuel

- specific average day

- to

- hour factors derived from the CEMS data for

thos e fuels and regions using heat input data from the entire year. SMOKE allocates the daily emissions data to

hours using these profiles obtained from the analysis base year.

Special cases to consider for IPM temporalization:

- When emissions go up substanti ally for unit s with limited hours of operation in the base year, an

averaged profile will be used

- When a unit switches fuels in the future year to a fuel not used in the base year, the profile is selected

according to the new type of fuel

.

- New units coming on line will need to use region and fuel

- specific profiles

- Units that are not new with future year emissions but no emissions in 2011 will be treated like new units

- Consider that installation of a control device might affect a unit ’ s load curve26 F igure 1. EPA Base Case v.5.13 IPM Regions (64 in all)