ORL FILE GENERATION METHODOLOGY

EPA v.4.10_PTox

March 2011

SECTION I: INTRODUCTION

This document provides the ORL file generation methodology for EPA Base Case v4.10_PTox. The methodology 

takes Integrated Planning Model (IPM®

) run results and generates ORL-formatted files that the U.S. 

Environmental Protection Agency (U.S. EPA) uses as inputs 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 ORL-formatted files.

SECTION II: DATA SOURCES AND DESCRIPTIONS

1. IPM run results:

This file contains IPM run results that have been disaggregated to the unit, emission control technology 

and fuel type level. The file provides records of fossil-fired existing and retrofit units, and committed and 

new-build aggregates1

. The committed and new-build aggregates are hereafter referred to as “generic” 

aggregates. All records contain:

i. 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.

ii. Sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM) control information 

for existing and retrofit units as well as generic aggregates.

iii. Annual and seasonal heat input (TBtu).

iv. Heat contents (MMBtu/ton, k-gallon, MMcf) and SO2 and ash contents (lb/MMBtu).

v. Annual and summer NOx emissions (MTon), annual SO2 emissions (MTon), and mercury 

emissions (Ton).

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

Table 1. Input Data Descriptions, Sources and Locations

No. File Name Description Source Location

1 NEI This file contains National Emission Inventory (NEI) 

unit-specific data that include units IPM ORL flag, 

data source, unique ID, ORIS plant ID, ORIS boiler 

ID, tribal code, SIC, MACT source type, MACT, 

NAICS, FIPS5, plant name, plant ID, point ID, stack 

ID, segment ID, stack default flag, stack type, stack 

height, stack diameter, stack temperature, stack 

flow, stack velocity, location default flag, coordinate 

system type, latitude, longitude, UTM zone, control 

efficiency, rule effectiveness, primary control 

equipment code, secondary control equipment 

code, year, horizontal area fugitive and release 

height fugitive.

EPA ORLSupport

Files.xls

 1 Biomass (standalone or co-firing) is considered fossil and therefore included in this process.
2

No. File Name Description Source Location

2 GenericUnitSite This file contains all existing plants that serve as 

sister plants in siting generic units. The data include 

NEEDS 4.10 Final plant’s state FIPS code, county 

FIPS code, county’s most recent 8 hour ozone or

PM2.5 attainment/non-attainment status, ORIS code 

and latitude-longitude coordinates.

EPA ORLSupport

Files.xls

3 LatLonDefault This file contains updated latitude-longitude 

coordinates by ORIS code, state FIPS code and 

county FIPS code.

EPA ORLSupport

Files.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 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 HgBIN This file contains mercury speciation fractions 

associated with each combination of plant type, coal 

rank, fluidized bed combustion firing type, SO2

control, fabric filter/bag house, ESP, NOx post 

combustion control, particulate matter scrubber and 

burner type. The order is hierarchical for Hg bin 

assignment.

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 ORLSupport

Files.xls
3

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

and assign them SCCs, ORIS codes, plant IDs, unit IDs, point IDs and segment IDs.

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 latitudelongitude coordinates. Third, the generic units are assigned SCCs, ORIS codes, plant IDs, unit IDs, point 

IDs and segment IDs. This process is performed in three steps as described in Flow Chart 2.

Flow Chart 2. Generic Unit Processing

II. Assign existing and retrofit units’ SCCs, 

state FIPS codes, county FIPS codes, plant 

IDs, point IDs, segment IDs and other NEI 

unit-specific data that are required for 

construction of the ORL files.

I. Disaggregate generic aggregates into 

generic units, site the generic units’ states 

and counties and assign them SCCs, ORIS 

codes, plant IDs, unit IDs, point IDs and 

segment IDs.

III. Assign stack IDs and parameters and latitudelongitude/county centroid coordinates for all records.

1. Create generic units

2. Site generic units

3. Assign generic units SCCs, ORIS codes, 

plant IDs, unit IDs, point IDs and segment 

ID’s

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

primary PM10, primary PM2.5 and Hg 

emissions for all records.

V. Populate control efficiency percentage 

(CEFF) and primary control equipment code 

(CPRI) fields for SO2, NOx and speciated Hg..
4

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,

coal rank and mercury speciation fractions as shown in Table 9.

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.

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

Aggregated heat input and emissions are then divided evenly among all generic units created in a 

given State for each plant type.

2. Site generic units

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 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:

Flow Chart 3. Generic Unit Siting Hierarchy

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.

Sister plants in attainment counties

Sister plants in PM non-attainment 

counties

Sister plants in 8-hour ozone nonattainment counties
5

3. Assign generic units SCCs, ORIS codes, plant IDs, unit IDs, point IDs and segment IDs:

i. SCC assignment is based on unit’s plant type, fuel type and coal rank as shown in Table 3.

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

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.

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

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 plant 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.
6

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

For example, the first combined-cycle generic unit in Arizona used in the example above has 

a unit ID of “GCC04”.

v. Generic unit’s 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 “GCC04”.

vi. Generic unit’s segment ID is equal to 1.

II. Assign existing and retrofit unit SCCs, state FIPS codes, county FIPS codes, plant IDs, point

IDs, segment IDs and other NEI unit-specific data that are required for construction of the ORL 

files.

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 ORL files, 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.

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

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
7

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

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

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
8

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

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

Combustion 

Turbine Boiler/Generator Natural Gas 20100201

Fossil Waste Generator Process Gas 20100201

IGCC Boiler/Generator 20100301
9

2. Assign existing and retrofit units’ state FIPS codes, county FIPS codes, plant IDs, point IDs and 

segment IDs

The units’ state FIPS codes, county FIPS codes, plant IDs, point IDs, and segment IDs are 

assigned from the NEI unit-specific data file, NEI. Where the NEI provides no data, default 

values are used. Appendix A describes the default values in detail.

III. Assign stack IDs and parameters and latitude-longitude/county centroid coordinates for all 

units

1. Assign stack ID and parameters for all units

i. Existing and retrofit units’ stack IDs are assigned from the NEI data file. If the NEI data file 

provides no stack ID data, default stack IDs are assigned as follows:

a. The units are first sorted by ORIS code and unit ID in alphanumeric order.

b. Default stack IDs are then assigned, starting with “41” and incrementing for the rest 

of the units that do not have NEI stack IDs within the same ORIS Code.

c. All generic units are assigned default stack IDs.

ii. Existing and retrofit unit’s stack parameters are assigned based on the hierarchy described in 

Flow Chart 4.

Flow Chart 4. Stack Parameters Assignment Hierarchy

Existing and retrofit units’ stack parameters are first assigned based on a unit’s plant type as 

shown in Table 7.

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

If Table 7 provides no plant type-based stack parameters, the units are assigned NEI stack 

parameters from the NEI.

Where the NEI data file provides no stack parameters, the units are assigned default stack 

parameters based on a unit’s SCC as shown in Table 8.

Plant Type-Based Stack Parameters

NEI Stack Parameters

SCC-Based Default Stack Parameters
10

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

iii. Generic units are assigned SCC-based default stack parameters.

iv. All units’ stack flows are assigned from the NEI data file, except for IGCC units which receive 

default stack flow by plant type as shown in Table 7. Where the NEI data file provides no stack 

flow data, stack flows are calculated as follows:
11

* 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 NEI data file. If the NEI data file provides 

no data, latitude-longitude/county centroid coordinates are assigned based on a unit’s sister 

ORIS code from the file LatLonDefault.

IV. Calculate CO, NOx, VOC, SO2, NH3, primary PM10, primary PM2.5 and mercury (Hg) emissions for all 

units

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

1. Annual emission calculations

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

annual mercury emissions are separated into elemental, ionic and particulate species as follows:

Annual EmissionsMercuy Species (tons) =

Annual EmissionMercury FractionMercury Species*

Where FractionMercury Species are mercury speciation fractions for elemental, ionic and particulate.

The hierarchy for the assignment of mercury speciation fractions is shown in Flow Chart 5. This

hierarchy, in conjunction with the mapping from Table 9, determines the assignment of 

associated speciation fractions.
12

Flow Chart 5. Mercury Speciation Fraction Assignment Hierarchy

1. Plant Type (Coal Steam, Coal 

Gasification (IGCC))

2. Coal Rank (Bituminous, Subbituminous, 

Lignite, Waste Coal, Petroleum Coke)

3. Fluidized Bed Combustion (FBC) Firing 

Type

4. SO2 Control (Wet Scrubber (FGD), Dry 

Scrubber (FGD))

5. Spray Dry Absorber (SDA)/Fabric Filter 

(FF) Baghouse Particulate Control

6. ESP (Cold-Side (CS), Hot Side (CS)) 

Particulate Control

7. NOx Control (SCR, SNCR, Other Post 

Combustion Control such as Cyclone, 

Mechanical Collector)

8. Particulate Matter (PM) Scrubber

9. Boiler/Burner Type (Cyclone, Pulverized 

Coal (PC), Stoker)
13

Table 9: Mercury Speciation Fractions

Category Particulate Ionic Elemental

Bituminous Coal and Pet. Coke, PC Boiler with ESP-CS 0.0117 0.4656 0.5227

Bituminous Coal, Coal Gasification 0.0051 0.0847 0.9102

Bituminous Coal, PC Boiler with Dry Sorbent Injection and ESP-CS 0.0016 0.6710 0.3274

Bituminous Coal, PC Boiler with ESP-CS 0.0611 0.6820 0.2570

Bituminous Coal, PC Boiler with ESP-CS and Wet FGD 0.0022 0.0778 0.9200

Bituminous Coal, PC Boiler with ESP-HS 0.0490 0.5784 0.3726

Bituminous Coal, PC Boiler with ESP-HS and Wet FGD 0.0063 0.2068 0.7870

Bituminous Coal, PC Boiler with FF Baghouse 0.0398 0.6258 0.3344

Bituminous Coal, PC Boiler with FF Baghouse and Wet FGD 0.0648 0.3300 0.6052

Bituminous Coal, PC Boiler with PM Scrubber 0.0180 0.1951 0.7869

Bituminous Coal, PC Boiler with SCR and SDA/FF Baghouse 0.0506 0.4604 0.4890

Bituminous Coal, PC Boiler with SDA/FF Baghouse 0.0917 0.2886 0.6197

Bituminous Coal, PC Boiler with SNCR and ESP-CS 0.2032 0.2712 0.5256

Bituminous Coal, Stoker Boiler with SDA/FF Baghouse 0.1996 0.1794 0.6211

Bituminous Coal/Pet. Coke, Cyclone with ESP-CS and Wet FGD 0.0007 0.1130 0.8863

Bituminous Coal/Pet. Coke, PC Boiler with FF Baghouse 0.0220 0.7841 0.1939

Bituminous Coal/Pet.Coke, Fluidized Bed Combustor with SNCR and FF 

Baghouse 0.4244 0.2787 0.2970

Bituminous Waste, Fluidized Bed Combustor with FF Baghouse 0.0212 0.3881 0.5907

Lignite Coal, Cyclone Boiler with ESP-CS 0.0004 0.1699 0.8297

Lignite Coal, Cyclone Boiler with SDA/FF Baghouse 0.0995 0.1707 0.7298

Lignite Coal, Fluidized Bed Combustor with ESP-CS 0.0137 0.1164 0.8700

Lignite Coal, Fluidized Bed Combustor with FF Baghouse 0.0042 0.7118 0.2840

Lignite Coal, PC Boiler with ESP-CS 0.0009 0.0362 0.9629

Lignite Coal, PC Boiler with ESP-CS and FF Baghouse 0.0019 0.6449 0.3532

Lignite Coal, PC Boiler with ESP-CS and Wet FGD 0.0082 0.1345 0.8574

Lignite Coal, PC Boiler with PM Scrubber 0.0016 0.0298 0.9686

Lignite Coal, PC Boiler with SDA/FF Baghouse 0.0036 0.1262 0.8702

Subbituminous Coal, Fluidized Bed Combustor with SNCR and FF 

Baghouse 0.0027 0.0342 0.9632

Subbituminous Coal, Fluidized Bed Combustor 0.0611 0.6820 0.2570

Subbituminous Coal, PC Boiler with ESP-CS 0.0016 0.3083 0.6901

Subbituminous Coal, PC Boiler with ESP-CS and Wet FGD 0.0043 0.0294 0.9663

Subbituminous Coal, PC Boiler with ESP-HS 0.0006 0.1252 0.8741

Subbituminous Coal, PC Boiler with ESP-HS and Wet FGD 0.0117 0.0446 0.9437

Subbituminous Coal, PC Boiler with FF Baghouse 0.0149 0.8283 0.1568

Subbituminous Coal, PC Boiler with PM Scrubber 0.0145 0.0511 0.9344

Subbituminous Coal, PC Boiler with SDA/ESP 0.0032 0.0382 0.9586

Subbituminous Coal, PC Boiler with SDA/FF Baghouse 0.0099 0.0435 0.9467

Subbituminous Coal/Pet. Coke, Cyclone Boiler with ESP-HS 0.0093 0.0752 0.9155
14

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:

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 4.10 Final 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.
15

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

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. 
16

SCC CO 

EF

VOC 

EF

NH3 

EF

Filterable PM10 

EF

Filterable PM2.5 

EF PM Flag1

 PM10 and PM2.5 primary are calculated directly from their EF (see Table 16).

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.

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
17















 − 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

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.

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

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

Annual EmissionPM Condensable (tons) =
18

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

Case v4.10 assumptions. The EPA Base Case v4.10 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

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

 2 Fossil waste using process gas SCC is assumed to be a combination of coke-oven gas and blast-furnace gas.
19

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 4.10 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 6.

Flow Chart 6. 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

1. EPA Base Case v4.10 Final 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
20

SCC SO2 Control1 PM Control1 PM Condensable EF2

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

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.

In addition, DSI is considered a scrubber for estimating PM emissions.

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. 
21

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 .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. .

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. Seasonal average-day emission calculations:

Summer average-day emissions are calculated by dividing the summer emissions by the 153 days in the summer.

Summer Average Day Emissions (tons) = 153

Summer Emissions (tons)
22

Winter average-day emissions are calculated by dividing the winter emissions by the 212 days in the winter.

Winter Average Day Emissions (tons) = 212

Winter Emissions (tons)

 

V. Populate control efficiency percentage (CEFF) and primary control equipment code (CPRI) fields:

1. Control Efficiency Percentage (CEFF) Field:

The CEFF field for SO2, NOx and elemental, ionic and particulate mercury species is calculated using the 

following methodology:

For all existing units:

i) SO2:

a) =2 CEFFSO 













 − ( / )

( / ) 1

2

2

Inlet SO Emission Rate lb MMBtu

Outlet SO Emission Rate lb MMBtu

∗ 100

Where:

Outlet SO2 Emission Rate (lb / MMBtu) = ( )

( ) 2

Annual Heat Input MMBtu

Annual SO Emission lbs

SO Content lb MMBtu of the Fuel Consumed at theUnit

Inlet SO Emission Rate lb MMBtu

( / )

( / )

2

2 =

b) Weighted average 2 CEFFSO value, weighting on capacity (MW), is reported when aggregating 

ORL records to SCC level.

ii) Elemental, ionic and particulate mercury species:

a) CEFFMercury Species = 













 − ( / )

( / ) 1

Inlet Mercury Emission Rate lb TBtu

Outlet Mercury Emission Rate lb TBtu

∗ 100

Where:

Outlet Mercury Emission Rate (lb /TBtu) = ( )

( )

Annual Heat Input TBtu

Annual Mercury Emission lbs

Mercury Content lb TBtu of the Fuel Consumed

Inlet Mercury Emission Rate lb TBtu

( / )

( / ) =

b) Weighted average CEFFMercury Species value, weighting on capacity (MW), is reported when 

aggregating ORL records to SCC level.

iii) NOx:
23

1) = Winter NOx CEFF 













 − Inlet Winter NO Emission Rate (lb/MMBtu)

Outlet Winter NO Emission Rate (lb/MMBtu)

x

x 1 ∗ 100

Where:

Winter Heat Input (MMBtu)

Winter NO Emission (lbs)

Outlet Winter NO Emission Rate (lb/MMBtu)

x

x =

Winter NEEDS NO Rate (lb/MMBtu)

Inlet Winter NO Emission Rate (lb/MMBtu)

x

x = 3

2) = NOx CEFFSummer 













 − ( / )

( / ) 1

Inlet Summer NO Emission Rate lb MMBtu

Outlet Summer NO Emission Rate lb MMBtu

x

x ∗ 100

Where:

( )

( )

( / )

Summer Heat Input MMBtu

Summer NO Emission lbs

Outlet Summer NO Emission Rate lb MMBtu

x

x =

( / )

( / )

Summer NEEDS NO Rate lb MMBtu

Inlet Summer NO Emission Rate lb MMBtu

x

x =

4

3) = NOx CEFF ( ) x x WinterNO CEFFSummerNO Max CEFF ,

The NOx CEFF is used in both winter and summer ORL files.

4) Weighted average NOx CEFF value, weighting on capacity (MW), is reported when 

aggregating ORL records to SCC level. If the SCC aggregate has no primary control 

equipment code (CPRI), no NOx CEFF value is reported, unless any portion of the SCC 

aggregate has a NOx control equipment.

If the calculated SO2, NOx or mercury species CEFF value is less than one percent, no CEFF value is 

reported. Also, no CEFF value is reported for repowering units.

For all generic units:

All generic units have default CEFF value by plant type as described in Table 15:

 3 The Winter NEEDS NO Rate (lb / MMBtu) x is without post-combustion control removal.

4 The Summer NEEDS NO Rate (lb / MMBtu) x is without post-combustion control removal.
24

Table 15. Default CEFF by Plant Type

Plant Type Default 2 CEFFSO Value Default Mercury Species CEFF Value Default NOx CEFF Value

Conventional 

Pulverized Coal

90% 90% 90%

Integrated 

Gasification 

Combined Cycle

99% 90% 90%

2. Primary Control Equipment Code (CPRI) Field:

For all existing units:

The CPRI field for existing units is populated in two steps:

i. CPRI value is assigned based on the final post-combustion control information, i.e. accounting for both 

existing and retrofit investment post-combustion control(s) installed at the unit as shown in Table 16.

Table 16. CPRI by Pollutant and Post-Combustion Control

Pollutant Post-Combustion Control CPRI (1)

NOx SCR 0001

NOx SNCR or other Post Combustion NOx control 0002

SO2 Wet Scrubber 0003

SO2 Dry Scrubber 0004

SO2 Wet or Dry Scrubber (2) 0005

Hg Activated Carbon Injection 0006

NOx, SO2, Hg Repowering 0007

(1) If no emission control information is available, no CPRI value is reported.

(2) Used for generic units only.

ii. Simple-majority rule, based on capacity (MW), is applied to select dominant CPRI value when 

aggregating ORL records to SCC level.

For all generic units:

All generic units have default CPRI value by plant type as described in Table 17:

Table 17. Default CPRI by Plant Type for Generic Units

Plant Type NOx CPRI SO2 CPRI Mercury CPRI

Conventional 

Pulverized Coal 0001 0005

Integrated Gasification 

Combined Cycle 0001

Combined Cycle 0001
25

SECTION IV: ORL-FORMATTED FILES LAYOUT:

The processed data are then converted into two ORL-formatted files, one for summer and one for winter, for U.S. 

EPA to use in air quality modeling framework. Both winter and summer ORL-formatted files contain annual 

emissions and they each contain their respective seasonal average day emissions.

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, 200 (elemental mercury), 201 (ionic mercury) and 202 

(particulate mercury).

The files’ naming convention is as follows:

PTINV_<ipm run and winter/summer alpha-numeric only>_<year4>_<date created using 

ddmmmyyyy>_ORL.txt

where:

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

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

mmm = 3-char lowercase month (jan, feb, mar, apr, may, jun, jul, aug, sep, oct, nov, dec)

yyyy = 4-digit year

For example: 'PTINV_EPA410_Final_BC_42l_summer_2030_12DEC2010_ORL.txt’.

All data fields are comma-delimited and character data, including comma, semi-colon and space, are enclosed in 

double-quotes.

Each file contains the following header lines:

#ORL

#TYPE Point Source Inventory for CAPS and Mercury

#COUNTRY US

#YEAR <year of emissions>

#DESC Annual and Summer Average Day

#DESC US excluding AK and HI, not including PR nor VI

#DESC For some sources, these data have multiple entries that

#DESC appear to be "duplicates", but are not. These entries have

#DESC the same source IDs across all entries, but different emissions.

#DESC To use this data properly in SMOKE, the run script should use

#DESC the setting RAW_DUP_CHECK = N. This setting will cause SMOKE

#DESC to provide a warning about "duplicate records" and sum the

#DESC emissions to create a single SMOKE source.

#DESC <IPM run name>

#DESC FIPS,PLANTID,POINTID,STACKID,SEGMENT,PLANT,SCC,ERPTYPE,SRCTYPE,

STKHGT,STKDIAM,STKTEMP,STKFLOW,STKVEL,SIC,MACT,NAICS,CTYPE,XLOC,YLOC,

UTMZ,POLCODE,ANN_EMIS,AVD_EMIS,CEFF,REFF,CPRI,CSEC,NEI_UNIQUE_ID,

ORIS_FACILITY_CODE,ORIS_BOILER_ID,IPM_YN,DATA_SOURCE,STACK_DEFAULT_FLAG,LOCATION_DE

FAULT_FLAG,YEAR,TRIBAL_CODE,HORIZONTAL_AREA_FUGITIVE,

RELEASE_HEIGHT_FUGITIVE

The last header line contains comma-delimited field names identifying the data contained in each data field. The 

field name, description, type and length of each data field are described in Appendix B.
26

Appendix A

Default Values

Field Name Description Default Value

FIPS FIPS code for state and county N/A

PLANTID State Plant Identification Code Concatenation of "ORIS" and 

NEEDS ORIS Code

POINTID Point Identification Code NEEDS Unit ID

STACKID Stack Identification Code

Start with “41” and increment for 

the rest of the units that do not 

have NEI stack IDs within the 

same ORIS Code

SEGMENT SEGMENT ID "1"

PLANT Plant Name N/A

SCC Source Classification Code N/A

ERPTYPE

Emissions release point type; indicates type of 

stack: 01 = fugitive, 02 = vertical stack, 03 = 

horizontal stack, 04 = goose neck, 05 = 

vertical with rain cap, 06 = downward-facing 

vent

"02"

SRCTYPE Source type; 01 = major, 02 = Section 112 

area source, 03 = non-road source "01"

STKHGT Stack Height (ft)

SCC-based default stack 

parameters from 

SCCDefaultStackParameters file.

STKDIAM Stack Diameter (ft)

SCC-based default stack 

parameters from 

SCCDefaultStackParameters file.

STKTEMP Stack Gas Exit Temperature (°F)

SCC-based default stack 

parameters from 

SCCDefaultStackParameters file.

STKFLOW Stack Gas Flow Rate (cft/sec)

SCC-based default stack 

parameters from 

SCCDefaultStackParameters file.

STKVEL Stack Gas Exit Velocity (ft/sec)

SCC-based default stack 

parameters from 

SCCDefaultStackParameters file.

SIC Standard Industrial Classification Code "4911"

MACT

Maximum Achievable Control Technology 

Code which identifies a source categories 

defined by Maximum Achievable Control 

Technology rules or rules that are done under 

other programs such as Section 129 standards

Blank

NAICS North American Industrial Classification 

System Code "22"
27

Field Name Description Default Value

CTYPE Coordinate system type; U = Universal 

Transverse Mercator ; L = Latitude/longitude "L"

XLOC

X location, If CTYPE = U, Easting value 

(meters); If CTYPE = L, Longitude (decimal 

degrees)

County-centroid based longitude 

by ORIS code, state FIPS code 

and country FIPS code from 

LatLonDefault file.

YLOC

Y location, If CTYPE = U, Northing value 

(meters), If CTYPE = L, Latitude (decimal 

degrees)

County-centroid based latitude 

by ORIS code, state FIPS code 

and country FIPS code from 

LatLonDefault file.

UTMZ UTM zone (required if CTYPE = U) Blank

POLCODE Code representing the pollutant contained in 

the inventory N/A

ANN_EMIS Annual Emissions (ton/year) N/A

AVD_EMIS Average-day Emissions (ton/average day) N/A

CEFF Control Efficiency percentage (give value of 0-

100) Blank

REFF Rule Effectiveness percentage (give value of 

0-100) 100

CPRI Primary Control Equipment Code Blank

CSEC Secondary Control Equipment Code Blank

NEI_UNIQUE_ID

Unique ID that ties together HAP and CAP 

emissions within a common facility ID, and ties 

together emissions obtained from multiple data 

sources (e.g., TRI, State, ESD) which may 

have different state facility identifiers but really

belong to a single facility

Blank

ORIS_FACILITY_CODE ORIS code matching with the 2005 NEI ORL 

CAP corresponding ID NEEDS ORIS Code

ORIS_BOILER_ID Boiler ID matching with the 2005 NEI ORL 

CAP corresponding ID in relation to above ID NEEDS Boiler ID

IPM_YN Y or N single character flag indicating whether 

the point source belongs in the IPM sector "Y"

DATA_SOURCE

Flag indicating the source of the data (e.g., 

state-submitted, toxics release inventory, 

Clean Air Markets Division, etc.)

"IPM"

STACK_DEFAULT_FLAG Flag indicating how NEI defaulted stack 

parameters Blank

LOCATION_DEFAULT_FLAG Flag indicating how NEI defaulted locations Blank

YEAR Year of emissions 4-digit year of the emissions 

TRIBAL_CODE Indicates the particular tribe that submitted the 

data Blank

HORIZONTAL_AREA_FUGITIVE Related to AXLEN, AYLEN which are optional 

parameters for ISCST3/AERMOD Blank

RELEASE_HEIGHT_FUGITIVE Related to optional parameters for 

ISCST3/AERMOD Blank
28

Appendix B

ORL-Formatted Files Layout

Field Name Description Type and Length

FIPS FIPS code for state and county Character (5)

PLANTID State Plant Identification Code Character (15)

POINTID Point Identification Code Character (6)

STACKID Stack Identification Code Character (6)

SEGMENT SEGMENT ID Character (6)

PLANT Plant Name Character (80)

SCC Source Classification Code Character (10)

ERPTYPE

Emissions release point type; indicates type of stack: 

01 = fugitive, 02 = vertical stack, 03 = horizontal stack, 

04 = goose neck, 05 = vertical with rain cap, 06 = 

downward-facing vent

Character (2)

SRCTYPE Source type; 01 = major, 02 = section 112 area source, 

03 = non-road source Character (2)

STKHGT Stack Height (ft) Number (10)

STKDIAM Stack Diameter (ft) Number (10,2)

STKTEMP Stack Gas Exit Temperature (°F) Number (10)

STKFLOW Stack Gas Flow Rate (cft/sec) Number (10,2)

STKVEL Stack Gas Exit Velocity (ft/sec) Number (10,2)

SIC Standard Industrial Classification Code Number (4)

MACT

Maximum Achievable Control Technology Code which 

identifies a source categories defined by Maximum 

Achievable Control Technology rules or rules that are 

done under other programs such as Section 129 

standards

Character (6)

NAICS North American Industrial Classification System Code Character (6)

CTYPE Coordinate system type; U = Universal Transverse 

Mercator ; L = Latitude/longitude Character (8)

XLOC X location, If CTYPE = U, Easting value (meters); If 

CTYPE = L, Longitude (decimal degrees) Number (11,6)

YLOC Y location, If CTYPE = U, Northing value (meters), If 

CTYPE = L, Latitude (decimal degrees) Number (11,6)

UTMZ UTM zone (required if CTYPE = U) Number (2)

POLCODE Code representing the pollutant contained in the 

inventory Character (9)

ANN_EMIS Annual Emissions (tons/year) Number (20,8)

AVD_EMIS Average-day Emissions (tons/average day) Number (20,8)

CEFF Control Efficiency percentage (give value of 0-100) Number (5,2)

REFF Rule Effectiveness percentage (give value of 0-100) Number (5,2)

CPRI Primary Control Equipment Code Number (4)

CSEC Secondary Control Equipment Code Number (4)

NEI_UNIQUE_ID

Unique ID that ties together HAP and CAP emissions 

within a common facility ID, and ties together emissions 

obtained from multiple data sources (e.g., TRI, State, 

ESD) which may have different state facility identifiers 

but really belong to a single facility

Character (20)

ORIS_FACILITY_CODE ORIS code matching with the 2005 NEI ORL CAP 

corresponding ID Character (6)

ORIS_BOILER_ID Boiler ID ID matching with the 2005 NEI ORL CAP 

corresponding ID in relation to above ID Character (5)
29

Field Name Description Type and Length

IPM_YN Y or N single character flag indicating whether the point 

source belongs in the IPM sector Character (1)

DATA_SOURCE

Flag indicating the source of the data (e.g., statesubmitted, toxics release inventory, Clean Air Markets 

Division, etc.)

Character (10)

STACK_DEFAULT_FLAG Flag indicating how NEI defaulted stack parameters Character (10)

LOCATION_DEFAULT_F

LAG Flag indicating how NEI defaulted locations Character (10)

YEAR Year of emissions Character (4)

TRIBAL_CODE Indicates the particular tribe that submitted the data Character (3)

HORIZONTAL_AREA_FU

GITIVE

Related to AXLEN, AYLEN which are optional 

parameters for ISCST3/AERMOD Number (8)

RELEASE_HEIGHT_FUGI

TIVE Related to optional parameters for ISCST3/AERMOD Number (8)