FLAT FILE 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 Inputs 
2

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 input into air quality 

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

steps in detail. Section IV describes the layout of the formatted flat file.

SECTION II: DATA SOURCES AND DESCRIPTIONS

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

input. These results include records of fossil-fired existing and retrofit units, along with committed and new-build 

aggregates. All fossil and biomass fired units are included 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, geothermal, 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 following:

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

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

2. Sulfur dioxide (SO2), nitrogen oxides (NOx), 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 contents (MMBtu/ton, k-gallon, MMcf) and SO2 and ash contents (lb/MMBtu).

5. Annual and summer NOx emissions (MTon), annual SO2 emissions (MTon), HCL emissions (MTon), and 

mercury emissions (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, latitude-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, agency 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 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, 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 PM2.5

attainment/non-attainment status, ORIS code, 

latitude-longitude coordinates, and zip code.

EPA FlatFile_Input

s.xls
3

No. Input Description Source Location

3 LatLonDefault 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, coal 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 SCCDefaultStackPar

ameters

This file contains default stack parameters (height, 

diameter, temperature and velocity) by SCC.

EPA Table 8

7 ControlDevices 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 (NH3), filterable particulate matter less 

than or equal to 10 microns (filterable PM10), 

filterable particulate matter less than or equal to 2.5 

microns (filterable PM2.5), primary PM10 and primary 

PM2.5 by SCC.

EPA Table 11

10 PMSulfurAshContent

Default

This file contains default filterable PM10 and 

filterable PM2.5 control efficiencies and sulfur and 

ash contents by plant type and fuel type and coal 

rank.

EPA Table 12

11 PMCDEmsFac This file contains PM condensable emission factors 

by SCC.

EPA Table 13

12 PMAdjustmentRatio This file contains primary PM10 and primary PM2.5

emission factors (EF) by SCC for gas-fired units

(including IGCC).

EPA Table 14

13 PMSulfurAshContent This file contains filterable PM10 and filterable PM2.5

control efficiencies and sulfur and ash contents by 

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

filterable PM10 and filterable PM2.5 control 

efficiencies are based on 2001 data.

EPA FlatFile_Input

s.xls
4

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. Data Processing Steps

I. II. Assign existing and retrofit units’ SCCs, 

state FIPS codes, county FIPS codes, and 

other EIS unit-specific data that are required 

for construction of the flat file.

I. Disaggregate generic aggregates into generic 

units, site the generic units’ states and counties 

and assign them SCCs, ORIS codes, facility 

IDs, unit IDs, rel point IDs, and process IDs.

V. Calculate CO, NOx, VOC, SO2, NH3, 

primary PM10, primary PM2.5, Mercury (Hg), 

and HCl emissions for all records.

III. Assign stack parameters and latitudelongitude/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, the generic aggregates are disaggregated to create generic units. Second, the 

generic units are then sited and given state, county and county-centroid based latitude-longitude coordinates. 

Third, the generic units are assigned SCCs, ORIS codes, facility IDs, unit IDs, rel point IDs and process IDs. This 

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

Flow Chart 2. Generic Unit Processing

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

two steps: i. The generic aggregates are first aggregated by state, plant type and, for coal steam and IGCC, and 

coal rank. ii. They are then split into smaller generic units by dividing the aggregated capacity by a reference 

capacity. The 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 Table 2. Aggregated heat input and emissions are then 

divided evenly among all generic units created in a given state 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 030

IGCC 550

Oil/Gas Steam 100

2. Site generic units: The generic units are then given a state FIPS code, county FIPS code and latitudelongitude/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 status. Within a state the hierarchy for 

assignment of sister plants 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, latitudelongitude/county centroid across all runs of the same base case origin.

1. Create generic units

2. Site generic units

3. Assign generic units SCCs, ORIS codes, 

facility IDs, unit IDs, rel point IDs, and 

process IDs.

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

and assign them SCCs, ORIS codes, facility IDs, unit IDs, rel point IDs, and process IDs.
6

Flow Chart 3. Generic Unit Siting Hierarchy

3. Assign generic units 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 Table 3.

ii. 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 the 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 code. 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 the 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 “ORISGCC04”.

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 “ORISGCC04”.

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 20100101

Combustion Turbine Natural Gas 20100201

Combustion Turbine Oil 20100101

IGCC Coal 20100301

IGCC Petroleum Coke 20100301

Oil/Gas Steam Natural Gas 10100601

Sister plants in attainment counties

Sister plants in PM non-attainment 

counties

Sister plants in 8-hour ozone nonattainment counties
7

Table 4. Generic Unit 1st Digit ORIS Code

Plant Type 1st 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, describes 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 specific meaning (starting at the left) in the first, third, and fifth through eighth digits. For the flat

file, the 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 eighth 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. Assign 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 EIS

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 10100302
9

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 20100201
10

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 stack parameters for all units: 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 stack 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:

* Stack Velocity (ft/sec) 2

Stack Diameter (ft) Stack Flow(cft/sec) 3.141592 *

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. Stack 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 19.0 340.0 075.8
12

Control IDs 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 NOx

141 Wet FGD

206 DSI

207 ACI

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

1. Annual emission calculations

i. Annual NOx, SO2, mercury (Hg), and HCl emissions (tons) are taken directly from IPM run results.

ii. Annual CO, VOC and NH3 emissions (tons) are calculated by multiplying the unit’s fuel use and 

uncontrolled emission factors for CO, VOC and NH3 as follows:

Annual EmissionsPollutant (tons) =

2000 (lb ton)

Annual Fuel Use (ton,k gallon,MMcf)* Emission Factor (lb/ton,k gallon,MMcf) Pollutant

/

− −

Where:

2000 converts lb to short ton and the pollutants are CO, VOC, and NH3.

Annual Fuel Use (ton, k − gallon, MMcf )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, NOx, VOC, SO2, NH3, primary PM10, primary PM2.5, Mercury (Hg), and HCl emissions for 

all records.
13

Fuel Use (ton, k − gallon, MMcf ) =

( / , , )

( )

Heat Content MMBtu ton k gallon MMcf

Heat Input MMBtu

−

Where Heat Content (MMBtu /ton, k − gallon,MMcf )is assigned using EPA Base 

Case v.5.13 assumptions for coal and 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

UncontrolledEmission Factor (lb/ton,k gallon,MMcf) Pollutant − is assigned for CO, VOC, NH3

based on a unit’s SCC as shown in Table 11.

Table 11: SCC-Based Emission Factors

(lbs/ton, k-gal, MMcft)

SCC CO 

EF

VOC 

EF

NH3 

EF

Filterable PM10 

EF

Filterable PM2.5 

EF PM Flag1

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 A
14

SCC CO 

EF

VOC 

EF

NH3 

EF

Filterable PM10 

EF

Filterable PM2.5 

EF PM Flag1

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 PM10 EF = 5.9 * (1.12 * S + 0.37), where S=sulfur content %.

3 Filterable PM2.5 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. 

 PM10 and PM2.5 primary are calculated directly from their EF (see Table 13).

iii. Annual primary PM10 and PM2.5 emissions (tons) are calculated for all but gas-fired and IGCC units by 

adding the filterable PM10 and filterable PM2.5 emissions to condensable PM emissions. Filterable PM10

and PM2.5 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 SO2/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 of additional 

condensable PM (in the form of SO3 and H2SO4) 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 to 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 

overestimated in a case where the unit is combusting a low-sulfur coal in the presence of a scrubber.
15

Annual Emission (tons) = Primary PM10

( ( ) ( )) 10 Annual Emission tons Annual Emission tons Filterable PM + PM Condensable

Annual Emission (tons) = Primary PM2.5

( ( ) ( )) 2.5 Annual Emission tons Annual Emission tons Filterable PM + PM Condensable

Where:

( ) = 10 Annual Emission tons Filterable PM















 − −

2000 ( / )

( , , ) * ( / , , ) 10

lb ton

Fuel Use ton k gallon MMcf Emission Factor lb ton k gallon MMcf Filterable PM















 − 100

* 1 PM10 Filterable Control Efficiency * (Ash Content (%))

( ) = 2.5 Annual Emission tons Filterable PM















 − −

2000 ( / )

( , , ) * ( / , , ) 2.5

lb ton

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















 − 100

* 1 PM 2.5 Filterable Control Efficiency * (Ash Content (%))

If ( ) 2.5 Annual Emission tons Filterable PM is greater than ( ) 10 Annual Emission tons Filterable PM ,

( ) 2.5 Annual Emission tons Filterable PM is set equal to ( ) 10 Annual Emission tons Filterable PM .

2000 ( / )

( ) * ( / )

lb ton

Annual Heat Input MMBtu Emission Factor lb MMBtu PM Condensable

Annual EmissionPM Condensable (tons) =
16

Where:

2000 converts lb to short ton and the pollutants are CO, VOC, and NH3.

PM10 Filterable Control Efficiency and PM2.5 Filterable Control Efficiency 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 shown in Table 12 are used.1

Table 12: Default PM Control Efficiencies and Sulfur and Ash Contents

Plant Type Fuel Type / 

Coal Rank

Filterable 

PM10 Control 

Efficiency (%)

Filterable 

PM2.5 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

( / ) ( / ) SO2 Content lb MMBtu and Ash Content lb MMBtu are assigned using EPA Base 

Case v.5.13 assumptions. The EPA Base Case v.5.13 SO2 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:

Sulfur Content (%) =

*100

2 * 2000 ( / )

( / ) * ( / ) 2

lb ton

SO Content lb MMBtu Heat Content MMBtu ton

 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’ 

PM10 Filterable Control Efficiency and PM2.5 Filterable Control Efficiency . For information on the unitspecific 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:

Sulfur Content (%) =

*100

2 * 7882 ( / )

( / ) * ( / ) 2

lb k gallon

SO Content lb MMBtu Heat Content MMBtu k gallon

−

−

where 7882 converts lb to k-gallon of oil.

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

 

Sulfur Content (%) =

*100

2 * 52794 ( / )

( / ) * ( / ) 2

lb MMcf

SO Content lb MMBtu Heat Content MMBtu MMcf

where 52794 converts lb to MMcf of fossil waste2

. 

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

Sulfur Content (%) =

*100

2 * 44000 ( / )

( / ) * ( / ) 2

lb MMcf

SO Content lb MMBtu Heat Content MMBtu MMcf

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

Ash Content (%) =

*100

2000

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

where 2000 is the number of lb per short ton.

If 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 12 are used second. This hierarchy is 

summarized 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

Emission Factor (lb / MMBtu) PM Condensable is assigned for all units based on units’ 

SCCs and whether they have either an SO2 control or PM scrubber installed as shown in 

Table 13.

Table 13: SCC-Based PM Condensable Emission Factors

(lbs/MMBtu)

SCC SO2 Control1 PM Control1 PM Condensable EF2

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 SO2 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 rank
19

SCC SO2 Control1 PM Control1 PM Condensable EF2

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 SO2 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 to 0.01. 

For the SCCs in Table 13 that have non-blank controls for both SO2 and PM, their PM condensable emission 

factor can be calculated using the equation below:

PM Condensable Emission Factor = (0.1* Sulfur Content (%))− 0.03

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

Emission Factor in place of the calculated value.

Also, units having an SO2 control are assigned the lower of the PM condensable emission factor from Table 13

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

Primary PM10 and primary PM2.5 cannot be estimated for gas-fired units (including IGCCs) using the same

methodology as the other fuels since there are no accurate filterable emission factors for them. Thus, their 

emissions are estimated directly. Primary PM10 and primary PM2.5 emission factors in lb/MMBtu are assigned 

based on each unit’s SCC as shown in Table 14.
20

Table 14: Primary PM10 and Primary PM2.5 Emission Factors for Gas-Fired and IGCC Units

(lb/MMBtu)

SCC Primary PM10 EF Primary PM2.5 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. Seasonal emission calculations:

Summer is considered to be the 153 days between May 1 and September 30 inclusive. Summer NOx 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.

Summer Emissions (tons) = Annual Emissions (tons) * 















Annual Heat Input MMBtu

Summer Heat Input MMBtu

(

( )

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.

Winter Emissions(tons) = Annual Emissions (tons) − Summer Emissions (tons)

3. Monthly emission calculations:

Summer monthly emissions for are calculated as follows:

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

153

( )

Winter monthly emissions are calculated as follows:

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

212

( ) 
21

SECTION IV: 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 

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

NOx, VOC, SO2, NH3, primary PM10, primary PM2.5, Mercury (Hg), and HCl.

The file’s naming convention is as follows:

FlatFile_<ipm run alpha-numeric only>_<year4>_<date created using yyyymmdd>.txt

where:

year4 = 4-digit year of the emissions (e.g., 2030)

yyyy = 4-digit year

mm = 2-digit month number (e.g. 01 through 12)

dd = 2-digit date number (e.g., 01 through 31)

For example: 'FlatFile_EPA513_BC_7c_2018_20131108.txt’.

All data fields are comma-delimited and character data, including commas, semi-colons, and spaces, are 

enclosed in double-quotes.

The file contains the following header lines:

#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_POINT_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_

HEIGHT,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 Default 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 Default 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 Blank
24

Field Name Default Value

OCT_PCTRED Blank

NOV_PCTRED Blank

DEC_PCTRED Blank

COMMENT Blank
25

Appendix B

Temporal Allocation of IPM Projected Seasonal Emissions to Hourly Emissions for Use in Air Quality 

Modeling

IPM provides unit 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 summer/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, NOx and SO2 CEMS data are 

used to allocate NOx and SO2 emissions, while CEMS 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 NOx and SO2 emissions are temporalized according to the 

pattern followed in the base year, while emissions of other pollutants are temporalized by heat input. For nonpeaking units for which CEMS data is available, the emissions are temporalized 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-specific 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 NOx, SO2, 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 CEMS data from the base year of the air quality modeling analysis. 

Separate allocations are computed for NOx, SO2, and heat input for the fuels coal, natural gas, and other. 

Hourly allocation for inventory 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 

those 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 substantially for units 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 curve
26

Figure 1. EPA Base Case v.5.13 IPM Regions (64 in all)