DEVELOPMENT OF EMISSION BUDGET INVENTORIES
FOR REGIONAL TRANSPORT NOx SIP CALL
TECHNICAL AMENDMENT VERSION
A-96-56 : X-B-ll
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
December 1999

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Chapter I
Introduction
Table of Contents
l
Chapter II
Electric Generating Unit Point Source Emissions 		3
A.	Development of Base Year Emissions 		3
B.	2007 Base Case		7
C.	2007 Budget Case		7
D.	EGU Emission Summary		8
Chapter III
Non-EGU Point Source Emissions 		11
A.	Development of Base Emissions 		11
B.	2007 Base Case		11
C.	2007 Budget Case		12
D.	Non-EGU Emission Summary 		14
Chapter IV
Stationary Area and Nonroad Source Emissions 	 25
A.	Development of Base Year Emissions 	 25
B.	2007 Base Case	 25
C.	2007 Budget Case	 25
D.	Stationary Area and Nonroad Emission Summary	 26
Chapter V
Highway Vehicle Source Emissions 		29
A.	Development of Base Year Emissions 		29
B.	2007 Base Case		30
C.	2007 Budget Case		31
D.	Highway Vehicle Emission Summary		31
Chapter VI
Statewide NOx Budgets 	 37
APPENDIX A
2007 BASE CASE CONTROLS
APPENDIX B
NON-EGU POINT SOURCE CONTROL CATEGORY CODES
APPENDIX C
SOURCE SPECIFIC EGU BASE AND BUDGET EMISSIONS FILE
APPENDIX D
SOURCE SPECIFIC NON-EGU POINT SOURCE BASE AND BUDGET EMISSIONS FILE
APPENDIX E
COUNTY LEVEL STATIONARY AREA BASE AND BUDGET EMISSIONS FILE
APPENDIX F
COUNTY LEVEL NONROAD MOBILE BASE AND BUDGET EMISSIONS FILE
APPENDIX G
COUNTY LEVEL HIGHWAY VEHICLE BASE AND BUDGET EMISSIONS FILE
APPENDIX H
MOBILE MODEL HIGHWAY VEHICLE COUNTY CORRESPONDENCE FILE

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Chapter I
Introduction
The purpose of this document is to describe the development of the emissions and control
data used in the United States (U.S.) Environmental Protection Agency's (EPA) Regional
Transport NOx State Implementation Plan (SIP) Call Notice of Final Rulemaking (NFR) and to
describe the process for calculation of the associated Statewide budgets.
Chapter II of this document describes the development of the electric generating unit
(EGU) point source data and budget, Chapter III describes the development of the non-EGU
point source data and budget, Chapter IV describes the stationary area and nonroad mobile source
data and budget, and Chapter V describes the highway vehicle data and budget.
It should be noted that there were several comment periods during which EPA received
comments on various aspects of the SIP Call emissions inventories. As a result of the Notice of
Proposed Rulemaking (NPR) and Supplemental Notice of Proposed Rulemaking (SNPR) public
comment periods, EPA revised the inventories with approved data addressing issues such as
emission estimate revisions, missing sources, retired sources, incorrect source sizes, base year
control levels, and facility name changes. Details of these comments and their affect on the base
inventory can be found in the response to significant comments document for the NFR (EPA,
1998a).
In addition to the NPR and SNPR public comment periods, in the NFR (63 FR 57427)
EPA allowed commenters an additional opportunity to request revision to the source specific data
used to establish each State's budget in the SIP Call. This opportunity for comments ended on
November 23, 1998.
When EPA published its correction and clarification notice to the NFR (63 FR 71220),
EPA reopened the comment period for emissions inventory revisions. This comment period was
restricted to comments related to the baseline sub-inventory information used to establish the
State's budgets. This comment period ended on February 22, 1999.
The EPA is proceeding to final action now on a second technical amendment based on
further comments received from the public in response to the SIP call and the request for
comments on inventory revisions as well as the May 14, 1999 technical amendment.
The emissions inventories described in this document reflect the public comments accepted
by EPA. The EPA's review and acceptance/rejection of specific comments is contained in EPA's
"Responses to the 2007 Baseline Sub-Inventory Information and Significant Comments for the
Final NOx SIP Call and Proposed Rulemakings for Section 126 Petitions and Federal
Implementation Plans - Technical Amendment Version," (EPA, 1999b) and "Responses to the
2007 Baseline Sub-Inventory Information and Significant Comments for the Final NOx SIP Call,"
(EPA, 1999).

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Chapter II
Electric Generating Unit Point Source Emissions
A. Development of Base Year Emissions
The base year electric generating unit (EGU) emissions were developed to provide the
EGU data necessary for determining the 2007 budget case and to supply data for use in air quality
modeling of the budget case. A base year EGU inventory was developed using the higher of 1995
or 1996 heat input (determined at the State-level) for the purpose of calculating the 2007 budget
case (as explained below). A 1996 base year EGU inventory was developed for the air quality
modeling. For each base year inventory, both seasonal and daily emissions estimates were
developed.
The base year EGU inventories consist of both electric utility units and nonutility
electricity generating units. The nonutility electricity generating units include independent power
producers (IPPs) and nonutility generators (NUGs).
Eight data sources were used to develop the base year EGU emissions data:
1.	EPA's Acid Rain Data Base (ARDB) (Pechan, 1997c);
2.	EPA's 2007 Integrated Planning Model Year 2007 (IPM);
3.	EPA's Emission Tracking System/Continuous Emissions Monitoring System
(ETS/CEM) (EPA, 1997b);
4.	DOE's Form EIA-860 (DOE, 1995a);
5.	DOE's Form EIA-767 (DOE, 1995b);
6.	EPA's National Emissions Trends Data Base (NET) (EPA, 1997c);
7.	DOE's Form EIA-867 (DOE, 1995c); and
8.	The OTAG Emission Inventory (Pechan, 1997a).
Each of these data sources is described below.
EPA's Acid Rain Data Base (ARDB) was developed in response to the Acid Rain
Program authorized under Title IV. The data base was originally an update to the boiler-based
National Allowance Data Base Version 3.11 (NADBV311) which was used in the calculation of
the S02 allowances as specified in Title IV. Over the last few years, the data base has been
expanded to include ETS/CEM 1994-1996 S02, NOx, C02, and heat input; as well as 1985-1995
NET utility data, boiler identification, characteristics, and locational data. The existing boilers
and planned turbines (as of 1990) in the ARDB are used as units for the EGU.
EPA's 2007 Integrated Planning Model Year 2007 (IPM) data base represents a unit-level
disaggregated IPM Clean Air Act (CAA) baseline simulation developed for OTAG air quality
modeling. The IPM includes over 7,000 units (nationally) with data on existing electricity
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generating units. This information is maintained in EPA's National Electric Energy Data System
(NEEDS). In general, the generator-level utility turbines and engines, as well as nonutility units
that are not required to report to EPA under the Title IV program, are included in IPM. However
for purposes of developing the EGU base year inventory, IC engines were included in the non-
EGU inventory, rather than in the EGU inventory. This is because emissions and emission
reductions for all IC engines (including both engines used for purposes of generating electricity
and engines used for other purposes such as powering pumps on gas lines) were determined in the
same way (see Chapter 3 for a more complete discussion of the treatment of IC engines).
Supplemental data, provided by EPA, including the start year, the base year (1994) NOx rate, and
type of ownership, were added to the IPM data base. This information was used to obtain NOx
emissions and heat input data for these units. Where units could be matched to other inventories,
actual locational data are included in the IPM; otherwise, county centroids are used.
EPA's Emission Tracking System/Continuous Emissions Monitoring System (ETS/CEM)
data contains hourly S02, C02, NOx rate, and heat input data at the monitoring stack level and
boiler level for all boilers included in the Acid Rain Program that was mandated by Title IV of the
Clean Air Act Amendments of 1990 (CAAA). In 1994, data were collected from the 263 Phase I
boilers; beginning in 1995, data are collected from Phase II as well as Phase I affected boilers.
These data were used to provide NOx emissions and heat input.
DOE's Form EIA-860 is an annual utility survey, "Annual Electric Generator Report,"
that provides utility data on a generator level. Both existing and planned generators are reported.
The data include generator identification, status, capacity, prime mover, and fuel type(s). Units
reported on this form were generally only included in the EGU file if they also were included in
the IPM file since NOx emissions and heat input are not derivable from Form EIA-860 alone. This
form was useful, however, in providing other information, such as prime mover and unit status.
DOE's Form EIA-767 is an annual utility survey, "Steam-Electric Plant Operation and
Design Report," that contains data for fossil fuel steam boilers such as fuel quantity and quality;
boiler identification, locational, status, and design information; and flue gas Desulfurization
scrubber and particulate collector device information. Note that boilers in plants with less than 10
MW do not report all data elements. The relationship between boilers and generators is also
provided, along with generator-level generation and nameplate capacity. Note that boilers and
generators are not necessarily in a one-to-one correspondence.
EPA's NET fossil fuel steam data base is developed annually by EPA. The data base was
initially based on DOE's Form EIA-767 data, but the coal NOx emissions have been superseded
by calculations using EPA NOx rates, and the NOx, S02 and heat input data from ETS/CEM, if
available. Source Classification Codes (SCCs) are assigned to each boiler based on boiler and fuel
characteristics; AP-42 emission factors are used to calculate VOC, CO, PM10, and PM2.5
emissions. The 1990 and 1995 NET data bases were used to obtain SCCs, stack parameters, NOx
emissions and heat input.
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DOE's Form EIA-867 "Annual Nonutility Power Producer Report" is similar in content
to, although more limited than, the utility Forms EIA-860 and EIA-767. The EIA-867, however,
is a confidential form, and aside from the facility identification data (which includes State and
capacity), EIA can only provide most data from this form on an aggregated basis. Only a few of
the units in this file were ultimately used since it was difficult to obtain NOx emissions, heat input,
or locational data unless they could be matched to another source.
The OTAG data base was developed by collecting and compiling electric utility emission
inventory data from States in the OTAG domain. This 1990 inventory contains summer day
emission estimates, as well as variables required for air quality modeling. This data base was used
to obtain NOx emissions and locational data.
In general, the operating units in the ARDB identified the steam boilers, while the IPM
data base identified the generator-level utility turbines and engines, as well as the nonutility units.
While some units were obtained from the other data bases, the primary purpose of the other data
bases was to add variables required for modeling to the units identified by the ARDB or IPM
data.
In order for a unit to be used, it had to have enough data to estimate emissions. Data had
to be available on either daily or seasonal heat input or daily or seasonal NOx emissions. The NOx
emission rate was also required, but a default NOx emission rate from AP-42 was assigned to units
that had data on heat input or emissions, but no NOx rate. The emissions from 421 units could
not be estimated because there was no NOx emissions or heat input information available to EPA
for these units. This suggests that these units may not have operated in the summer seasons of
1995 and 1996.
The first step in developing the base year data was to develop a file containing all available
heat input, NOx emissions and NOx rate information. The second step involved assigning SCCs.
In the third step stack parameters needed for air quality modeling were added to the inventory.
Step 1. Seasonal NOx Emissions and Heat Input
The hierarchy for obtaining seasonal NOx emissions and heat input for a particular unit identified
from the above sources of information is provided below.
For the 1995/1996 base year:
a Determine what year of data to use for a given boiler, based on the State that the
boiler is in and whether 1996 or 1995 heat input was higher for that State.
b. Based on that boiler year information, use ETS/CEM data to obtain 1995 seasonal
NOx rate and 1995 seasonal heat input, or 1996 seasonal NOx rate and 1996
seasonal heat input to calculate seasonal NOx emissions.
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c.	Based on that boiler year information, use the 1995 NET data base (or 1996 data
projected from the 1995 NET) for annual NOx emissions and heat input, then
convert to seasonal emissions.
d.	Use 1990 OTAG file for ozone season day (OSD) NOx emissions and OSD heat
input (or July month heat input and divide by 31), then convert to seasonal
emissions and forecast to the base year.
e.	Use IPM NOx rate and 2007 July heat input, calculate NOx emissions, convert to
seasonal emissions, and backcast to the base year.
f.	If there is a heat input and no NOx emissions or rate, assign an AP-42 default NOx
rate based on SCC and convert to seasonal emissions.
For the 1996 base year:
a.	Use ETS/CEM 1996 file for seasonal NOx emissions and 1996 seasonal heat input.
b.	Use the 1996 projected from thel995 NET data base for annual NOx emissions
and heat input, then convert to seasonal emissions.
c.	Use 1990 OTAG file for OSD NOx emissions and OSD heat input (or July month
heat input and divide by 31), then convert to seasonal and forecast to the base
year.
d.	Use IPM NOx rate and 2007 July heat input, calculate NOx emissions, convert to
seasonal emissions, and backcast to the base year.
f. If there is a heat input and no NOx emissions or rate, assign an AP-42 default NOx
rate based on SCC and convert to seasonal emissions.
Step 2. Source Classification Codes (SCCs)
The methodology for assigning SCC is as follows:
a.	Match the unit to the NET 1995 or 1990 inventory and assign the major SCC
(based on heat input) to the boiler.
b.	Match the unit to the OTAG data and assign the major SCC.
c.	Assign default SCCs based on prime mover, fuel type, and (in the case of steam
units) boiler bottom and firing types.
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Step 3. Stack Parameters
The methodology for obtaining stack parameters is as follows:
a.	Match the unit to the NET 1995 or 1990 inventory and use the NET stack data.
b.	Match the unit to the OTAG data base and use the OTAG stack data.
c.	Assign default stack parameters, based on prime mover and fuel type, that were
originally developed for the Regional Oxidant Model (ROM). (Note that since
stack parameters in IPM were originally developed by matching with the OTAG
and NET inventories, followed by defaults, any stack parameters obtained from
IPM are likely to be default parameters.)
B.	2007 Base Case
The 2007 base case summer season emissions were determined using the IPM. Note that
no changes were made as a result of the extended emissions inventory comment period to the data
or methods used for the IPM projection of the 2007 base case summer season emissions. The
2007 base case includes all applicable controls required by the CAAA. Applicable controls
required for EGUs include Title IV Acid Rain controls and NOx RACT. Details regarding the
IPM model and the method can be found in the Regulatory Impact Analysis (RIA) of the final SIP
call (EPA, 1998c). Appendix A presents the EGU source controls included in the 2007 base case.
The growth factors used in the 2007 base case were obtained from the IPM projections.
The growth factors are at the State-level (i.e., there was a single growth factor for each State that
was applied to all units in that State). The estimates were interpolated to 2007 using the average
annual growth of each State as forecasted by EPA using the IPM and EPA's baseline electric
generation forecast. In calculating the average annual growth, EPA relied on unit-specific
summer energy use from 2000 to 2010 as forecasted by the IPM. The growth factors are shown
in Table II-1.
C.	2007 Budget Case
The 2007 budget case was developed by unit by applying IPM growth factors and an
emission rate to the 1995/1996 base year heat input. Units greater than 25 MWe in each of the
SIP call States had a uniform emission rate of 0.15 lb NOx/MMBtu applied to them. Units
25MWe or smaller were left at their 2007 base case NOx emission rate. A description of the data
file structure for EGU sources including emissions, growth, and control information used to
estimate the 2007 EGU budget is provided in Appendix C of this document.
The growth factors were applied to the 1995/1996 heat input to get 2007 projected heat
input. Emissions of NOx were then calculated by multiplying the 2007 projected heat input by the
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2007 budget-applicable NOx rate.
D. EGU Emission Summary
Table II-2 is a State-level summary of the EGU data. It contains seasonal NOx emissions
for the 2007 base and budget cases.
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Table II-l
IPM Growth Factors
State
1996-2007
Growth Factor
Alabama
1.10
Connecticut
0.60
District of Columbia
1.36
Delaware
1.27
Georgia
1.13
Illinois
1.08
Indiana
1.17
Kentucky
1.16
Massachusetts
1.59
Maryland
1.35
Michigan
1.13
Missouri
1.09
North Carolina
1.21
New Jersey
1.29
New York
1.05
Ohio
1.07
Pennsylvania
1.15
Rhode Island
0.47
South Carolina
1.43
Tennessee
1.21
Virginia
1.32
Wisconsin
1.12
West Virginia
1.03
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Table II-2
2007 Seasonal Base and Budget NOx Emissions for EGUs
State
2007 Base
2007 Budget
Alabama
76,926
29,022
Connecticut
5,636
2,652
Delaware
5,838
5,250
District of Columbia
3
207
Georgia
86,455
30,402
Illinois
119,311
32,372
Indiana
136,773
47,731
Kentucky
107,829
36,503
Maryland
32,603
14,656
Massachusetts
16,479
15,146
Michigan
86,600
32,228
Missouri
82,097
24,216
New Jersey
18,352
10,250
New York
39,199
31,036
North Carolina
84,815
31,821
Ohio
163,132
48,990
Pennsylvania
123,102
47,469
Rhode Island
1,082
997
South Carolina
36,299
16,772
Tennessee
70,908
25,814
Virginia
40,884
17,187
West Virginia
115,490
26,859
Wisconsin
51,962
17,381
Total *
1,501,775
544,961
* Totals may not sum due to rounding.

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Chapter III
Non-EGU Point Source Emissions
A. Development of 1995 Base Year Emissions
The non-EGU point source emissions were based on data sets originating with the OTAG
1990 base year inventory. The OTAG prepared these base year inventories with 1990 State
ozone nonattainment SIP emission inventories. These data were supplemented with either other
State inventory data, if available, or EPA's NET data, if State data were not available.
The non-EGU point source emissions for 1990 were then grown to 1995 using Bureau of
Economic Analysis (BEA) historical growth estimates of industrial earnings at the State 2-digit
Standard Industrial Classification (SIC) applied to emissions at the Source Classification Code
(SCC) level. These emissions were grown to 1995 for the purposes of modeling and to maintain
a consistent base year inventory with the EGU data.
NOx RACT controls were applied to major sources in ozone nonattainment areas (NAA)
and the Ozone Transport Region (OTR) unless the area received a NOx waiver. Information on
the application of NOx RACT came from the OTAG data base which was developed by surveying
applicable States on their implementation of NOx RACT (Pechan, 1997b). These data include
unit specific NOx RACT control efficiencies for many units. For units without specific control
information either ozone nonattainment area/SCC NOx RACT efficiencies collected from the
States or national/SCC NOx RACT default efficiencies were applied. Table III-l presents the
national/SCC NOx RACT default efficiencies used in the base calculation.
B. 2007 Base Case
To obtain the 2007 Base Case emissions, the 1995 data were projected to 2007 using
BEA projections of Gross State Product (GSP) at the 2-digit SIC level and supplemented with
State, local, and industry provided growth factors. Where SICs were not provided, an SIC-SCC
cross-reference file was used to apply these factors.
In addition to NOx RACT, Maximum Achievable Control Technology (MACT) control
assumptions were applied to large municipal waste combustors (MWC) in the base case. A 30
percent NOx reduction was assumed for sources identified by the MACT rule (EPA, 1998b).
Appendix A presents the non-EGU point source controls included in the 2007 base case.
Seasonal 2007 base case emissions were calculated by multiplying the seasonal 1995 base
year emissions by the applicable growth rate and emission controls applicable for 2007.
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C. 2007 Budget Case
Budget controls were applied to large sources in the following non-EGU categories:
boilers, turbines, cement manufacturing plants, and internal combustion engines. To determine
control efficiencies for these sources for purposes of calculating the budget, emissions were first
totaled at each source to a primary fuel (SCC). For sources using more than one fuel, a primary
fuel was assigned based on the emission segment with the largest heat input or NOx emissions
from the base year inventory. This was done to prevent the application of multiple control
strategies to units firing multiple fuels. A control category was then assigned to this primary fuel
from which NOx controls were selected for application to the source. Appendix B presents a list
of these control categories.
For each of the categories to which budget level controls were applied, an additional
distinction was needed between large and small units for non-EGU point sources. For the
following affected categories, the characteristics shown below were used to determine if the
sources were considered large.
Category	Large Size Determinant
Boilers	> 250 MMBtu/hr
Turbines	> 250 MMBtu/hr
Cement Manufacturing Plants	> 1 ton NOx / typical ozone season day
Internal Combustion Engines	> 1 ton NOx / typical ozone season day
1. Boilers and Turbines
If heat input capacity data were available for a unit, these data were used in determining
the source's size. However, a majority of the non-EGU point source units in the inventory did not
include boiler capacity data. For these cases, data from the NET inventory were used to
determine whether a non-EGU boiler or turbine was assumed as a large or small source.
Using data from the NET data base, a default boiler capacity file that contained the mean
and median boiler capacities by the first 6-digits of SCCs was developed. For each 6-digit SCC,
the file also contained the average daily NOx emissions for units with boiler capacities closest to
250 MMBtu/hr. These data are listed in Table III-2.
As an example, for the 6-digit SCC "202001", the boiler capacity closest to 250
MMBtu/hr is listed in Table III-2 as 276 MMBtu/hr. If there was only one unit with a boiler
capacity of 276 MMBtu/hr, the daily NOx emissions from that unit were used. If more than one
unit had a boiler capacity of 276 MMBtu/hr, the mean daily emissions of those units was used.
Each non-EGU unit in the inventory was matched to the default file described above based on the
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first 6-digits of its SCC.
The following rules were then used to determine if a unit's boiler capacity was considered
greater than, equal to, or less than 250 MMBtu/hr. For each unit:
a.	If boiler capacity data were provided for the unit, size determination was made
based on those data.
b.	If both the mean and median boiler capacity in the file were greater than
300 MMBtu/hr, it was assumed that the unit's boiler capacity was greater than
250 MMBtu/hr.
c.	If either the mean or median boiler capacity was between 200 and 300 MMBtu/hr,
then the daily NOx emissions were used to determine the boiler size. If the daily
NOx emissions were greater than the average daily NOx emissions in the default
boiler capacity file, it was assumed that the boiler capacity was greater than 250
MMBtu/hr. If the daily NOx emissions were less than the average daily NOx
emissions in the default boiler capacity file, it was assumed that the boiler capacity
was less than 250 MMBtu/hr.
d.	If both the mean and median boiler capacity in the file were less than 200
MMBtu/hr, it was assumed that the boiler capacity was less than 250 MMBtu/hr.
e.	If the boiler could not be matched to the default boiler capacity file, it was assumed
that the boiler capacity was less than 250 MMBtu/hr.
Units for which the boiler capacity was estimated to be greater than 250 MMBtu/hr were
categorized as large sources.
2.	Cement Manufacturing Plants and Internal Combustion Engines
For cement manufacturing plants and internal combustion engines, boiler capacity was not
used to determine source size. Instead 1995 typical ozone season daily emissions were used as a
determinant. If the 1995 point-level emissions were more than 1 ton/day, the unit was
categorized as a large source. Otherwise the unit was categorized as a small source.
3.	Calculation of Reductions
Emissions reductions for the budgets were calculated only for large sources in the specific
source categories listed in Table III-3. Sources not meeting the large source requirements from
these affected categories were considered small and not subject to additional budget control.
Emissions from sources smaller than the heat input capacity cutoff level, and that emit less than 1
ton of NOx per typical ozone season day are included in the budget inventory at their 2007 base
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case level. Additionally, those sources without adequate information to determine potentially
applicable control techniques are included in the budget at 2007 base case levels.
Emissions reductions for the budget case were estimated from first calculating 2007
uncontrolled emission levels by removing base case control efficiency and rule effectiveness
values. The new budget control efficiency and 2007 base rule effectiveness were then applied to
the 2007 uncontrolled emissions as in the 2007 base case. As noted above, no additional
reductions (beyond those in the base case) were applied to small sources.
It should be noted that the budget reductions were applied to all applicable sources even if
these reductions were less stringent than the existing 2007 base case controls. Although
uncommon, this resulted in an increase in emissions from the 2007 base case to the 2007 budget
case for some sources. This method is consistent with the EGU budget calculation. The
description of the data file structure for non-EGU sources including NOx emissions, growth, and
control information is provided in Appendix D of this document.
D. Non-EGU Emissions Summary
Table III-4 is a State-level summary of the seasonal non-EGU emissions data. It contains
five month ozone season NOx emissions for the 2007 base case and the 2007 budget case.
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Table III-l
Default NOx RACT Control Assumptions
Default NOx
RACT
Control Efficiency
SCC	NOy RACT Control Group	(Percent)
10200101 Industrial Boiler - PC	50
10200104 Industrial Boiler - Stoker - Overfeed	55
10200201	Industrial Boiler - PC - Wet	50
10200202	Industrial Boiler - PC - Dry	50
10200203	Industrial Boiler - Cyclone	53
10200204	Industrial Boiler - Stoker - Spreader	55
10200205	Industrial Boiler - Stoker - Overfeed	55
10200206	Industrial Boiler - Stoker	55
10200210 Industrial Boiler - Stoker - Overfeed	55
10200212	Industrial Boiler - PC - Dry	50
10200213	Industrial Boiler - PC - Wet	50
10200217 Industrial Boiler - PC	50
10200219 Cogeneration - Coal	50
10200222	Industrial Boiler - PC - Dry	50
10200223	Industrial Boiler - Cyclone	53
10200224	Industrial Boiler - Stoker - Spreader	55
10200225	Industrial Boiler - Stoker - Overfeed	55
10200229 Cogeneration - Coal	50
10200301 Industrial Boiler - PC	50
10200306 Industrial Boiler - Stoker - Spreader	55
10200401	Industrial Boiler - Residual Oil	50
10200402	Industrial Boiler - Residual Oil	50
10200403	Industrial Boiler - Residual Oil	50
10200404	Industrial Boiler - Residual Oil	50
10200405	Cogeneration - Oil Turbines	68
10200501	Industrial Boiler - Distillate Oil	50
10200502	Industrial Boiler - Distillate Oil	50
10200503	Industrial Boiler - Distillate Oil	50
10200504	Industrial Boiler - Distillate Oil	50
10200505	Cogeneration - Oil Turbines	68
10200601 Industrial Boiler - Natural Gas	50
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Table III-l
Default NOx RACT Control Assumptions
Default NOx
RACT
Control Efficiency
see
NOy RACT Control Group
(Percent)
10200602
Industrial Boiler - Natural Gas
50
10200603
Industrial Boiler - Natural Gas
50
10200604
Cogeneration - Natural Gas Turbines
84
10200699
Industrial Boiler - Natural Gas
50
10200701
Industrial Boiler - Natural Gas
50
10200704
Industrial Boiler - Natural Gas
50
10200707
Industrial Boiler - Natural Gas
50
10200710
Cogeneration - Natural Gas Turbines
84
10200799
Industrial Boiler - Natural Gas
50
10200802
Industrial Boiler - PC
50
10200804
Cogeneration - Coal
50
10201001
Industrial Boiler - Natural Gas
50
10201002
Industrial Boiler - Natural Gas
50
10201402
Cogeneration - Coal
50
10300101
Industrial Boiler - PC
50
10300102
Industrial Boiler - Stoker - Overfeed
55
10300103
Industrial Boiler - PC
50
10300205
Industrial Boiler - PC - Wet
50
10300206
Industrial Boiler - PC - Dry
50
10300207
Industrial Boiler - Stoker - Overfeed
55
10300208
Industrial Boiler - Stoker
55
10300209
Industrial Boiler - Stoker - Spreader
55
10300211
Industrial Boiler - Stoker - Overfeed
55
10300217
Industrial Boiler - PC
50
10300221
Industrial Boiler - PC - Wet
50
10300222
Industrial Boiler - PC - Dry
50
10300224
Industrial Boiler - Stoker - Spreader
55
10300225
Industrial Boiler - Stoker - Overfeed
55
10300309
Industrial Boiler - Stoker - Spreader
55
10300401
Industrial Boiler - Residual Oil
50
10300402
Industrial Boiler - Residual Oil
50
17

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Table III-l
Default NOx RACT Control Assumptions
Default NOx
RACT
Control Efficiency
see
NOy RACT Control Group
(Percent)
10300404
Industrial Boiler - Residual Oil
50
10300501
Industrial Boiler - Distillate Oil
50
10300502
Industrial Boiler - Distillate Oil
50
10300503
Industrial Boiler - Distillate Oil
50
10300504
Industrial Boiler - Distillate Oil
50
10300601
Industrial Boiler - Natural Gas
50
10300602
Industrial Boiler - Natural Gas
50
10300603
Industrial Boiler - Natural Gas
50
10300701
Industrial Boiler - Natural Gas
50
10300799
Industrial Boiler - Natural Gas
50
10301001
Industrial Boiler - Natural Gas
50
10301002
Industrial Boiler - Natural Gas
50
10500205
Process Heaters - Distillate Oil
74
10500206
Process Heaters - Natural Gas
75
10500210
Process Heaters - Other
74
20100101
Gas Turbines - Oil
68
20100102
IC Engines - Oil - Reciprocating
25
20100201
Gas Turbines - Natural Gas
84
20100202
IC Engines - Natural Gas - Reciprocating
30
20100702
Industrial Boiler - Other
50
20100801
Industrial Boiler - Other
50
20100802
Industrial Boiler - Other
50
20100901
Industrial Boiler - Other
50
20200101
Gas Turbines - Oil
68
20200102
IC Engines - Oil - Reciprocating
25
20200103
Cogeneration - Oil Turbines
68
20200104
Cogeneration - Oil Turbines
68
20200201
Gas Turbines - Natural Gas
84
20200202
IC Engines - Natural Gas - Reciprocating
30
20200203
Cogeneration - Natural Gas Turbines
84
20200204
Industrial Cogeneration - Nat. Gas
50
18

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Table III-l
Default NOx RACT Control Assumptions
Default NOx
RACT
Control Efficiency
see
NOy RACT Control Group
(Percent)
20200301
Industrial Boiler - Other
50
20200401
Industrial Boiler - Other
50
20200402
Industrial Boiler - Other
50
20200403
Cogeneration - Oil Turbines
68
20200501
IC Engines - Oil - Reciprocating
25
20200901
Industrial Boiler - Other
50
20200902
Industrial Boiler - Other
50
20201001
IC Engines - Natural Gas - Reciprocating
30
20201002
IC Engines - Natural Gas - Reciprocating
30
20300101
IC Engines - Oil - Reciprocating
25
20300102
Gas Turbines - Oil
68
20300201
IC Engines - Natural Gas - Reciprocating
30
20300202
Gas Turbines - Natural Gas
84
20300203
Cogeneration - Natural Gas Turbines
84
20300204
Cogeneration - Natural Gas Turbines
84
20300301
Industrial Boiler - Other
50
20301001
IC Engines - Natural Gas - Reciprocating
30
20400301
Gas Turbines - Natural Gas
84
20400302
Gas Turbines - Oil
68
20400401
IC Engines - Oil - Reciprocating
25
20400402
IC Engines - Oil - Reciprocating
25
30100101
Adipic Acid Manufacturing Plant
81
30101301
Nitric Acid Manufacturing Plant
95
30101302
Nitric Acid Manufacturing Plant
95
30190003
Process Heaters - Natural Gas
75
30190004
Process Heaters - Natural Gas
75
30390001
Process Heaters - Distillate Oil
74
30390003
Process Heaters - Natural Gas
75
30390004
Process Heaters - Other
74
30490001
Process Heaters - Distillate Oil
74
30490003
Process Heaters - Natural Gas
75
19

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Table III-l
Default NOx RACT Control Assumptions
Default NOx
RACT
Control Efficiency
see
NOy RACT Control Group
(Percent)
30490004
Process Heaters - Other
74
30590001
Process Heaters - Distillate Oil
74
30590002
Process Heaters - Residual Oil
73
30590003
Process Heaters - Natural Gas
75
30600101
Process Heaters - Distillate Oil
74
30600102
Process Heaters - Natural Gas
75
30600103
Process Heaters - Distillate Oil
74
30600104
Process Heaters - Natural Gas
75
30600105
Process Heaters - Natural Gas
75
30600106
Process Heaters - Natural Gas
75
30600107
Process Heaters - Natural Gas
75
30600111
Process Heaters - Residual Oil
73
30600199
Process Heaters - Other
74
30790001
Process Heaters - Distillate Oil
74
30790002
Process Heaters - Residual Oil
73
30790003
Process Heaters - Natural Gas
75
30890003
Process Heaters - Natural Gas
75
30990001
Process Heaters - Distillate Oil
74
30990002
Process Heaters - Residual Oil
73
30990003
Process Heaters - Natural Gas
75
31000401
Process Heaters - Distillate Oil
74
31000403
Process Heaters - Residual Oil
73
31000404
Process Heaters - Natural Gas
75
31000405
Process Heaters - Natural Gas
75
31390003
Process Heaters - Natural Gas
75
39990001
Process Heaters - Distillate Oil
74
39990002
Process Heaters - Residual Oil
73
39990003
Process Heaters - Natural Gas
75
39990004
Process Heaters - Natural Gas
75
40201001
Process Heaters - Natural Gas
75
40201002
Process Heaters - Distillate Oil
74
20

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Table III-l
Default NOx RACT Control Assumptions


Default NOx


RACT
see
NOy RACT Control Group
Control Efficiency
(Percent)
40201003
Process Heaters - Residual Oil
73
40201004
Process Heaters - Natural Gas
75
21

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Table III-2
Default Boiler Capacity Data From the NET



Boiler
Daily NOx (tpd)

Mean
Median
Capacity
of Boiler with

Boiler
Boiler
Closest to
Capacity
6-Digit
Capacity
Capacity
250
Closest to 250
see
(MMBtu/hr) (MMBtu/hr)
MMBtu/hr
MMBtu/hr
102001
75.97
55
264
2.6597
102002
236.65
150
250
0.7282
102003
150.44
58
87
0.4796
102004
393.35
73
250
0.3292
102005
299.63
80
250
0.1365
102006
251.96
86
250
0.2127
102007
268.49
198
250
0.1313
102008
515.30
420
241
1.0534
102009
348.64
132
250
0.2103
102010
123.57
45
224
0.0848
102011
193.00
193
193
0.1606
102012
252.00
180
246
0.4668
102013
194.81
172
250
0.0351
102014
287.62
297
267
0.1636
103001
49.45
43
137
0.2052
103002
90.28
74
248
1.1403
103003
85.00
93
101
0.1194
103004
113.01
59
245
0.0417
103005
89.05
71
249
0.0468
103006
152.38
97
249
0.0468
103007
211.00
197
197
0.7150
103009
65.18
66
166
0.0132
103010
138.00
138
138
0.0179
103012
240.33
75
200
0.5335
103013
93.45
59
250
0.5194
202001
228.87
62
276
1.2046
202002
294.62
9
271
0.5596
202005
62.00
62
62
0.1882
202009
70.00
70
70
0.3557
203001
75.00
35
256
8.0303
203002
29.47
8
197
0.7150
22

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Table III-3
Budget Reduction Levels From Uncontrolled Emissions
Budget Reduction
Source Category	Percentage
ICI Boilers* - Coal/Wall	60
ICI Boilers - Coal/FBC	60
ICI Boilers - Coal/Stoker	60
ICI Boilers - Coal/Cyclone	60
ICI Boilers - Residual Oil	60
ICI Boilers - Distillate Oil	60
ICI Boilers - Natural Gas	60
ICI Boilers - Process Gas	60
ICI Boilers - LPG	60
ICI Boilers - Coke	60
Gas Turbines - Oil	60
Gas Turbines - Natural Gas	60
Gas Turbines - Jet Fuel	60
Internal Combustion Engines - Oil	90
Internal Combustion Engines - Gas	90
Internal Combustion Engines - Gas, Diesel, LPG	90
Cement Manufacturing - Dry	30
Cement Manufacturing - Wet	30
In-Process; Bituminous Coal; Cement Kiln	30
* Industrial/Commercial/Institutional Boilers
23

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Table III-4
Base and Budget Ozone Season NOx Emissions
Non-EGU Point Sources
State
1995 Base
2007 Base
2007 Budget
Reduction
Alabama
49,515
60,465
43,415
28%
Connecticut
5,221
5,397
5,216
3%
Delaware
2,313
2,821
2,473
12%
District of Columbia
398
300
282
6%
Georgia
28,926
37,245
29,716
20%
Illinois
71,316
70,948
59,577
16%
Indiana
57,837
69,011
47,363
31%
Kentucky
23,843
29,486
25,669
13%
Maryland
15,988
16,216
12,585
22%
Massachusetts
11,801
11,210
10,298
8%
Michigan
58,938
68,801
60,055
13%
Missouri
24,297
25,964
21,602
17%
New Jersey
15,733
15,975
15,464
3%
New York
29,997
32,678
25,477
22%
North Carolina
27,397
33,114
26,434
20%
Ohio
42,250
50,001
40,194
20%
Pennsylvania
75,827
82,107
70,132
15%
Rhode Island
1,611
1,635
1,635
0%
South Carolina
27,228
37,960
27,787
27%
Tennessee
41,286
53,262
39,636
26%
Virginia
37,955
42,108
35,216
16%
West Virginia
27,169
24,473
20,238
17%
Wisconsin
18,431
23,734
19,853
16%
Total *
695,277
794,911
640,317
19%
* Totals may not sum due to rounding.
24

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25

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Chapter IV
Stationary Area and Nonroad Source Emissions
A.	Development of 1995 Base Year Emissions
The stationary area and nonroad mobile source emissions were derived from data sets
originating with the OTAG 1990 base year inventory. These base year inventories were prepared
with 1990 State ozone nonattainment SIP emission inventories supplemented with either other
State inventory data, if available, or the NET data, if State data were not available. The OTAG
1990 nonroad emission inventories were based primarily on estimates of 1990 nonroad emissions
found in the 1995 NET. The area and nonroad mobile source inventory data for 1990 were then
grown to 1995 using BEA historical growth estimates of industrial earnings at the State 2-digit
SIC level.
The initial starting set of 1995 base year emission estimates were in the form of typical
ozone season daily emission estimates. Base year seasonal emissions were developed by
multiplying these typical ozone season daily emissions by the 153 days in the season.
B.	2007 Base Case
The 1995 area and nonroad emissions were projected to 2007 using BEA projections of
GSP at the 2-digit SIC level and supplemented with growth rates provided by State and local
agencies. Because these source categories do not generally report SICs, an SIC-SCC cross-
reference file was used to apply these factors.
Emissions reductions from certain nonroad mobile controls were included in the 2007 base
case. These control programs include the Federal Small Engine Standards, Phase II; Federal
Marine Engine Standards (for diesel engines of greater than 50 horsepower); Federal Locomotive
Standards; and the Nonroad Diesel Engine Standards. Appendix A presents the stationary area
and nonroad mobile control measures included in the 2007 base case.
Seasonal 2007 base case emissions were calculated by multiplying the 1995 seasonal base
year emissions by the applicable growth rate and emission reductions for 2007. A description of
the file structure for the county-level stationary area and nonroad mobile source emissions and
growth is provided in Appendices E and F of this document.
C.	2007 Budget Case
For stationary area and nonroad mobile sources, 2007 base case emissions were used for
the budget case. No additional emissions reductions (beyond those in the 2007 base case) were
applied to these sources.
26

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D. Stationary Area and Nonroad Emission Summary
Table IV-1 is a State-level summary of the seasonal stationary area and nonroad mobile
data. It contains five month ozone season NOx emissions for the 1995 base year and 2007 base
and budget cases (which are the same for these sources).
27

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Table IV-1
Base and Budget Ozone Season NOx Emissions (Tons)
Stationary Area and Nonroad Mobile

1995
1995
2007
2007

Stationary
Nonroad
Stationary
Nonroad
State
Area
Mobile
Area
Mobile
Alabama
24,247
29,497
28,762
20,146
Connecticut
4,258
13,101
4,821
10,736
Delaware
1,728
5,334
1,129
5,651
District of Columbia
838
1,924
830
3,135
Georgia
10,694
37,007
13,212
26,467
Illinois
9,845
78,783
9,369
56,724
Indiana
18,009
44,942
29,070
26,494
Kentucky
25,711
20,001
31,807
15,025
Maryland
4,055
20,463
4,448
20,026
Massachusetts
9,984
25,662
11,048
20,166
Michigan
22,289
35,899
31,721
26,935
Missouri
6,540
36,256
7,341
20,829
New Jersey
10,602
30,629
12,431
23,565
New York
17,294
48,675
17,423
42,091
North Carolina
9,330
30,744
11,067
22,005
Ohio
16,899
62,715
21,860
43,380
Pennsylvania
15,002
50,303
17,842
30,571
Rhode Island
373
3,076
448
2,455
South Carolina
6,748
18,829
9,415
14,637
Tennessee
9,881
66,783
13,333
52,920
Virginia
21,301
35,786
27,738
27,859
West Virginia
5,358
15,471
5,459
10,433
Wisconsin
9,111
25,772
11,253
17,965
Total
260,097
737,652
321,827
540,215
28

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29

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Chapter V
Highway Vehicle Source Emissions
A. Development of 1995 Base Year Emissions
The 1995 base year highway vehicle emissions inventory was developed from data sets
originating with annual 1995 VMT levels from the Federal Highway Administrations (FHWA)
Highway Performance Monitoring System (HPMS). These data are specified by State, HPMS
vehicle type, and roadway type. The VMT data were then supplemented with data provided by
the States. These data were distributed from a statewide level to a county level using population
data from the 1990 census. The data were then apportioned from the HPMS vehicle categories to
EPA vehicle types using data provided by EPA's Office of Mobile Sources.
The 1995 emissions inventories reflect the type and extent of inspection and maintenance
programs (I/M) in effect as of that year and the extent of the Federal reformulated gasoline
program. The 1995 highway vehicle emission factors were based on EPA's MOBILE5b emission
factor model with corrected default inputs. The 1995 highway vehicle emissions were calculated
at the county level using the 1995 VMT and applicable emissions factors.
Highway vehicle emission factors were modeled for each month in the ozone season
(May-September) for each unique type of mobile source control area within a State. The file
XREFV5, listed in Appendix H, provides the MOBILE5b file used for each county. This file also
indicates the files used to determine vehicle speed input to MOBILE5b for each county. A blank
in the column SPEEDSCC denotes the use of the EPA default speeds. These default speeds can
be found in Table V-l. Additional columns in XREFV5 show the RVP modeled, I/M flags and
files, REG (2=yes, l=no), and other relevant data input to MOBILE5b for each county.
State-specific monthly average minimum and maximum daily temperatures were used in
calculating highway vehicle emissions factors. Temperature data over the period from 1970 to
1997 were used in calculating the average temperatures. These temperature data were obtained
from the National Climatic Data Center. Table V-2 presents the monthly temperatures by State.
The 1995 base year emissions include the effects of so-called "defeat devices" on highway
heavy-duty diesel engines. These devices cause engines to function differently when in actual use
than they do when being tested for emissions according to the Federal Test Procedure. Under
certain operating conditions typical of actual use, the computer software in these engines cause
them to function in a way that reduces the effectiveness of the engines' emission control systems
compared to how the engines operate when being tested for emissions according to the Federal
Test Procedure. In essence, the computer software alters the fuel injection timing when the
engine operates in certain modes (such as highway driving), causing the engine to emit higher
levels of NOx than suggested by their certification standards or by EPA's existing emission
models.
At the time of proposal of the NOx SIP Call, EPA had not yet completed its evaluation of
30

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the impact of these defeat devices on NOx emissions. As a result, EPA did not include the excess
emissions from their use in the SIP Call emissions inventories. Since that time, EPA has
completed its evaluation and entered into proposed consent decrees with the manufacturers of
diesel engines equipped with these devices. The effects of the heavy duty excess are included in
the emissions inventories by applying correction factors to the MOBILE5b highway vehicle
emissions factors. Additional information regarding the defeat device consent decrees can be
found at 63 FR 59330-59334 (November 3, 1998, Notices of Filing of Consent Decree under the
Clean Air Act).
B. 2007 Base Case
The EPA used the growth methods developed by OTAG for the purpose of projecting
VMT growth from 1995 and 2007. VMT growth factors were developed using data from the
MOBILE4.1 Fuel Consumption Model. This model estimates national VMT by vehicle type
through the year 2020. To calculate the VMT growth factors, the 1995 and 2007 Fuel
Consumption Model VMT were first allocated to MS As and "rest-of-state" areas using 1995
population and projected 2007 population estimates, respectively. The VMT growth factors were
calculated by vehicle type as the ratio of the 2007 VMT to the 1995 VMT for each MSA and
rest-of-state area.
The 1995 county annual VMT were projected to 2007 using the VMT growth factors.
These annual projections were allocated to each for the four seasons using seasonal temporal
factors. Monthly VMT data were then obtained using a ratio between the number of days in a
month and the number of days in the corresponding season. The VMT for the months of May,
June, July, August, and September were then summed to determine the ozone season total VMT.
The 2007 highway vehicle emissions were calculated by multiplying the county-specific
2007 monthly VMT by MOBILE5b emissions factors calculated for 2007.
Highway vehicle controls included county-specific I/M programs, reformulated gasoline
in mandated and opt-in areas, Phase 2 RVP elsewhere, the new heavy duty engine standard, and
National Low Emission Vehicle (NLEV)program. The NLEV implementation schedule modeled
for each county is found in XREFV5. Areas with NOx waivers that have a high enhanced I/M
programs were modeled without a NOx cutpoint in their I/M program (i.e., the NOx cutpoint was
modeled as 999). Appendix A presents the highway vehicle control measures included in the
2007 base case.
The effects on emissions of the heavy-duty vehicle defeat devices peaks in the late 1990s
and then declines rapidly as newer engines that would not be equipped with defeat devices replace
defeat device-equipped engines and as manufacturers undertake the mitigation commitments
required under the proposed consent decrees. The 2007 base case emissions include the effects of
defeat devices and the commitments made by diesel engine manufacturers in the settlement to
introduce diesel engines meeting the 2004 standards prior to 2004. Table V-3 presents the defeat
device correction factors used in the 2007 base case calculation.
A description of the file structure for monthly 2007 base county-level highway vehicle
31

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VMT and emissions is provided in Appendix G of this document.
C.	2007 Budget Case
Highway vehicle emissions from the 2007 base case were used in the budget case
inventory. No additional reductions (beyond those in the 2007 base case) were applied to the
budget highway vehicle emissions.
D.	Highway Vehicle Emission Summary
Table V-4 is a State-level summary of the seasonal highway vehicle data. It contains five
month ozone season VMT and NOx emissions for the 2007 base and the budget case with the
heavy duty diesel excess emissions.
32

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Table V-l
Average Speeds by Road Type and Vehicle Type
Rural Road Speeds (MPH)
Vehicle
Type"
Interstate
Principal
Arterial
Minor
Arterial
Major
Collector
Minor
Collector
Local
LDV
60
45
40
35
30
30
LDT
55
45
40
25
30
30
HDV
40
35
30
25
25
25
Urban Road Speeds (MPH)
Vehicle
Type"
Interstate
Principle
Arterial
Minor
Arterial
Major
Collector
Minor
Collector
Local
LDV
45
45
20
20
20
20
LDT
45
45
20
20
20
20
HDV
35
35
15
15
15
15
^Vehicle Type: LDV - light duty vehicles; LDT - light duty trucks; HDV - heavy duty
vehicles.

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Table V-2
Historical Statewide Average Monthly Minimum and Maximum Temperatures
(Degrees Fahrenheit)

May
May
June
June
July
July
August
August
September
September
State
Max
Min
Max
Min
Max
Min
Max
Min
Max
Min
Alabama
80.8
57.9
87.4
65.7
90.5
70.0
89.8
69.2
84.5
63.3
Connecticut
71.9
49.0
80.0
57.0
85.0
62.6
82.7
60.8
74.3
52.1
Delaware
74.9
53.3
83.0
61.9
87.5
67.5
85.9
66.1
79.7
59.2
DC
75.9
56.4
84.5
65.9
88.7
71.1
86.7
69.4
80.0
62.7
Georgia
79.9
59.3
86.4
66.9
89.3
70.6
87.7
69.9
82.4
64.5
Illinois
74.6
52.5
83.8
61.9
87.0
66.0
84.7
64.0
78.3
55.6
Indiana
73.4
51.9
82.2
61.4
85.6
65.5
83.8
63.6
77.3
55.6
Kentucky
76.0
55.3
84.1
64.3
87.8
68.6
86.4
67.2
79.8
60.0
Maryland
74.2
52.8
83.1
62.1
87.5
67.5
85.6
65.9
78.7
59.0
Massachusetts
66.8
50.2
76.7
59.4
82.3
65.5
80.3
64.6
72.5
56.8
Michigan
69.8
50.1
78.8
59.8
83.3
65.2
81.0
63.5
73.3
56.1
Missouri
75.3
53.5
84.3
62.3
89.4
66.9
88.7
65.7
80.0
57.9
New Jersey
72.6
54.1
81.4
63.6
86.3
69.4
84.6
68.0
76.9
60.1
New York
70.4
54.1
79.2
63.6
84.5
69.4
82.9
68.6
75.1
61.4
North Carolina
76.8
54.6
83.8
63.3
87.7
67.9
85.6
66.5
79.6
60.2
Ohio
72.4
50.5
80.8
59.5
84.5
64.0
83.0
62.5
76.1
55.3
Pennsylvania
72.4
51.6
80.9
60.9
85.7
66.2
83.8
64.7
75.9
56.9
Rhode Island
68.4
48.7
77.2
57.8
82.5
64.3
81.0
62.8
73.3
54.4
South Carolina
83.5
58.4
89.2
66.4
92.5
70.7
90.2
69.7
85.5
64.0
Tennessee
78.4
56.6
86.0
65.0
89.6
69.4
88.5
68.2
82.3
61.5
Virginia
77.7
54.6
85.4
63.2
89.2
68.4
87.2
66.8
81.3
60.0
West Virginia
75.0
51.8
81.8
60.0
85.9
65.5
84.3
63.6
77.9
56.8
Wisconsin
65.1
45.8
75.5
56.3
80.5
62.8
78.5
62.0
70.9
54.0

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Table V-3
Adjustment Factor for 2007 MOBILE5 Emission Factors to Account for Defeat Devices
and the Pull-Ahead of the 2 g/bhp-hr Standard
Speed
Facility
Description
5
10
15
20
25
30
35
40
45
50
55
60
65
Interstate
Rural Interstate
0.9953
1.0872
1.1754
1.2525
1.3114
1.3463
1.3538
1.3329
1.2858
1.2174
1.1341
1.0432
0.9518
Interstate
Rural Other Prin Arterial
0.9953
1.0873
1.1754
1.2525
1.3114
1.3464
1.3538
1.3329
1.2859
1.2174
1.1341
1.0433
0.9518
Interstate
Urban Interstate
0.9955
1.0878
1.1764
1.2538
1.3130
1.3481
1.3555
1.3346
1.2873
1.2186
1.1349
1.0436
0.9518
Interstate
Urban Other Freeways
0.9953
1.0874
1.1757
1.2528
1.3118
1.3468
1.3543
1.3334
1.2863
1.2177
1.1343
1.0433
0.9518
Arterial
Rural Minor Arterial
0.9713
1.0012
1.0299
1.0550
1.0741
1.0855
1.0879
1.0811
1.0658
1.0436
1.0165
0.9869
0.9572
Arterial
Rural Major Collector
0.9713
1.0012
1.0299
1.0549
1.0741
1.0854
1.0878
1.0811
1.0658
1.0435
1.0164
0.9869
0.9572
Arterial
Rural Minor Collector
0.9712
1.0008
1.0291
1.0539
1.0729
1.0841
1.0865
1.0798
1.0646
1.0426
1.0159
0.9866
0.9572
Arterial
Rural Local
0.9715
1.0015
1.0303
1.0555
1.0747
1.0861
1.0885
1.0817
1.0664
1.0440
1.0168
0.9872
0.9573
Urban
Urban Other Prin
Arterial
0.9660
0.9678
0.9695
0.9710
0.9722
0.9729
0.9730
0.9726
0.9717
0.9704
0.9687
0.9670
0.9652
Urban
Urban Minor Arterial
0.9659
0.9677
0.9694
0.9709
0.9721
0.9727
0.9729
0.9725
0.9716
0.9702
0.9686
0.9668
0.9651
Urban
Urban Collector
0.9662
0.9680
0.9697
0.9712
0.9724
0.9731
0.9732
0.9728
0.9719
0.9705
0.9689
0.9671
0.9653
Urban
Urban Local
0.9658
0.9676
0.9693
0.9708
0.9720
0.9727
0.9728
0.9724
0.9715
0.9701
0.9685
0.9667
0.9649
35

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Table V-4
VMT and 2007 Budget Ozone Season NOx Emissions
Highway Vehicle

Seasonal
Final Budget With

2007 VMT
HDD Excess
State
(thousands)
(tons/season)
Alabama
23,642
51,274
Connecticut
14,960
19,424
Delaware
4,207
8,358
District of Columbia
1,944
2,204
Georgia
49,822
88,775
Illinois
52,897
112,518
Indiana
33,843
79,307
Kentucky
24,590
53,268
Maryland
24,840
30,183
Massachusetts
23,207
28,190
Michigan
40,187
78,763
Missouri
31,772
51,615
New Jersey
32,442
35,166
New York
68,689
124,261
North Carolina
42,240
73,695
Ohio
52,640
94,850
Pennsylvania
47,953
91,578
Rhode Island
3,614
3,843
South Carolina
22,025
54,494
Tennessee
31,546
66,342
Virginia
38,787
72,195
West Virginia
9,161
20,844
Wisconsin
28,561
69,319
Total *
703,569
1,310,466
* Totals may not sum due to rounding.
36

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37

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Chapter VI
Statewide NOx Budgets
The Statewide base case and budget emissions were calculated by summing the individual
base case and budget emissions components. Table VI-1 shows the seasonal Statewide base case
and budget NOx emissions and the percent reduction between the base case and the budget. Table
VI-2 presents the base and budget cases by major source category component.
38

-------
Table VI-1
Seasonal Statewide NOx Base and Budgets
(Tons/Season)
State
Final Base
Final Budget
Reduction
Alabama
237,573
172,619
27%
Connecticut
46,015
42,849
7%
Delaware
23,798
22,861
4%
District of Columbia
6,471
6,658
-3%
Georgia
252,154
188,572
25%
Illinois
368,870
270,560
27%
Indiana
340,654
229,965
32%
Kentucky
237,415
162,272
32%
Maryland
103,476
81,898
21%
Massachusetts
87,092
84,848
3%
Michigan
292,820
229,702
22%
Missouri
187,845
125,603
33%
New Jersey
105,489
96,876
8%
New York
255,653
240,288
6%
North Carolina
224,697
165,022
27%
Ohio
373,223
249,274
33%
Pennsylvania
345,201
257,592
25%
Rhode Island
9,463
9,378
1%
South Carolina
152,805
123,105
19%
Tennessee
256,765
198,045
23%
Virginia
210,784
180,195
15%
West Virginia
176,699
83,833
53%
Wisconsin
174,234
135,771
22%
Total
4,469,196
3,357,786
25%
39

-------
Table VI-2
Seasonal Statewide NOx Base and Budgets by Major Source Category
(Tons/Season)
2007 Base NOx Emissions (tons/season)	2007 Budget NOx Emissions
(tons/season)
State
EGU
Non-EGU
Area
Nonroad
Highway
Total
EGU
Non-EGU
Area
Nonroad
Highway
Total
Alabama
76,926
60,465
28,762
20,146
51,274
237,573
29,022
43,415
28,762
20,146
51,274
172,619
Connecticut
5,636
5,397
4,821
10,736
19,424
46,015
2,652
5,216
4,821
10,736
19,424
42,849
Delaware
5,838
2,821
1,129
5,651
8,358
23,798
5,250
2,473
1,129
5,651
8,358
22,861
District of Columbia
3
300
830
3,135
2,204
6,471
207
282
830
3,135
2,204
6,658
Georgia
86,455
37,245
13,212
26,467
88,775
252,154
30,402
29,716
13,212
26,467
88,775
188,572
Illinois
119,311
70,948
9,369
56,724
112,518
368,870
32,372
59,577
9,369
56,724
112,518
270,560
Indiana
136,773
69,011
29,070
26,494
79,307
340,654
47,731
47,363
29,070
26,494
79,307
229,965
Kentucky
107,829
29,486
31,807
15,025
53,268
237,415
36,503
25,669
31,807
15,025
53,268
162,272
Maryland
32,603
16,216
4,448
20,026
30,183
103,476
14,656
12,585
4,448
20,026
30,183
81,898
Massachusetts
16,479
11,210
11,048
20,166
28,190
87,092
15,146
10,298
11,048
20,166
28,190
84,848
Michigan
86,600
68,801
31,721
26,935
78,763
292,820
32,228
60,055
31,721
26,935
78,763
229,702
Missouri
82,097
25,964
7,341
20,829
51,615
187,845
24,216
21,602
7,341
20,829
51,615
125,603
New Jersey
18,352
15,975
12,431
23,565
35,166
105,489
10,250
15,464
12,431
23,565
35,166
96,876
New York
39,199
32,678
17,423
42,091
124,261
255,653
31,036
25,477
17,423
42,091
124,261
240,288
North Carolina
84,815
33,114
11,067
22,005
73,695
224,697
31,821
26,434
11,067
22,005
73,695
165,022
Ohio
163,132
50,001
21,860
43,380
94,850
373,223
48,990
40,194
21,860
43,380
94,850
249,274
Pennsylvania
123,102
82,107
17,842
30,571
91,578
345,201
47,469
70,132
17,842
30,571
91,578
257,592
Rhode Island
1,082
1,635
448
2,455
3,843
9,463
997
1,635
448
2,455
3,843
9,378
South Carolina
36,299
37,960
9,415
14,637
54,494
152,805
16,772
27,787
9,415
14,637
54,494
123,105
Tennessee
70,908
53,262
13,333
52,920
66,342
256,765
25,814
39,636
13,333
52,920
66,342
198,045
Virginia
40,884
42,108
27,738
27,859
72,195
210,784
17,187
35,216
27,738
27,859
72,195
180,195
West Virginia
115,490
24,473
5,459
10,433
20,844
176,699
26,859
20,238
5,459
10,433
20,844
83,833
Wisconsin
51,962
23,734
11,253
17,965
69,319
174,234
17,381
19,853
11,253
17,965
69,319
135,771
Total
1,501,775
794,911
321,827
540,215
1,310,466
4,469,196
544,961
640,317
321,827
540,215
1,310,466
3,357,786

-------
References
DOE, 1995a: U.S. Department of Energy, Energy Information Administration, "Steam-Electric Plant
Operation and Design Report, "Form EIA-767, 1995.
DOE, 1995b: U.S. Department of Energy, Energy Information Administration, "Annual Electric
Generator Report," Form EIA-860, 1995.
DOE, 1995c: U.S. Department of Energy, Energy Information Administration, "Annual Nonutility
Power Producers Report, "Form EIA-867, 1995.
EPA, 1997b: U.S. Environmental Protection Agency, Data files received from EPA Acid Rain Division,
Washington DC, December 1997.
EPA, 1997c: U.S. Environmental Protection Agency, "National Air Pollutant Emission Trends, 1900-
1996, " EPA-454/R-97-011, Research Triangle Park, NC, December, 1997.
EPA, 1998a: U.S. Environmental Protection Agency, "Responses to Significant Comments on the
Proposed Finding of Significant Contribution and Rulemaking for Certain States in the Ozone
Transport Assessment Group (OTAG) Region for Purposes of Reducing Regional Transport of
Ozone (62 FR 60318, November 7,1997 and 63 FR 25902, May 11, 1998), " Docket A-96-56, VI-
C-01, September, 1998.
EPA, 1998b: U.S. Environmental Protection Agency, "Technical Support Document for Municipal Waste
Combustors (MWCs), " Docket A-96-56, VI-B-12, September, 1998.
EPA, 1998c: U.S. Environmental Protection Agency, "Regulatory Impact Analysis for the Regional N0X
SIP Call," Docket A-96-56, VI-B-09, September, 1998.
EPA, 1999: U.S. Environmental Protection Agency, "Responses to the 2007 Baseline Sub-Inventory
Information and Significant Comments for the Final NOx SIP Call (63 FR 57356, October 27,
1998), " Docket A-96-56, X-C-01, May, 1999.
EPA, 1999b: U.S. Environmental Protection Agency, "Responses to the 2007 Baseline Sub-Inventory
Information and Significant Comments for the Final NOx SIP Call and Proposed Rulemakings
for Section 126 Petitions and Federal Implementation Plans - Technical Amendment Version, "
December, 1999.
Pechan, 1997a: E.H. Pechan & Associates, Inc., "Ozone Transport Assessment Group (OTAG)
Emissions Inventory Development Report - Volume I: 1990 Base Year Development, " (revised
draft) prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, NC, February, 1997.
Pechan, 1997b: E.H. Pechan & Associates, Inc., "Ozone Transport Assessment Group (OTAG)
Emissions Inventory Development Report - Volume III: Projections and Controls, " (draft)
prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards, Research Triangle Park, NC, June, 1997.
Pechan, 1997c: E.H. Pechan & Associates, Inc., "The Acid Rain Data Base for 1996
(ARDB96) Technical Support Document, " (draft) prepared for U.S. Environmental Protection
Agency, Office of Atmospheric Programs, September 1997.

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APPENDIX A
2007 BASE CASE CONTROLS

-------
Table A-l
2007 Base Case Controls
EGU
-	Title IV Controls [ phase 1 & 2 ]
-	250 Ton PSD and NSPS
-	RACT & NSR in non-waived NAAs
Non-EGU Point
Stationary Area
Nonroad Mobile
Highway Vehicles
-	NOx RACT on major sources in non-waived NAAs
-	CTG & Non-CTG VOC RACT at major sources in NAAs & OTR
-	NOx MACT standards to municipal waste combustors (MWCs)
-	Two Phases of VOC Consumer and Commercial Products & One Phase
of Architectural Coatings controls
-	VOC Stage 1 & 2 Petroleum Distribution Controls in NAAs
-	VOC Autobody, Degreasing & Dry Cleaning controls in NAAs
-	Fed Phase II Small Eng. Stds
-	Fed Marine Eng. Stds.
-	Fed Nonroad Heavy-Duty (>=50 hp) Engine Stds - Phase 1
-	Fed RFGII (statutory and opt-in areas)
-	9.0 RVP maximum elsewhere in OTAG domain
-	Fed Locomotive Stds (not including rebuilds)
-	Fed Nonroad Diesel Engine Stds - Phases 2 & 3
-	On-board vapor recovery
-	National LEV
-	Fed RFG II (statutory and opt-in areas)
-	Phase II RVP limits elsewhere in OTAG domain
-	High Enhanced, Low Enhanced, or Basic I/M in areas specified by State
-	Clean Fuel Fleets (mandated NAAs)
-	HDV 2 gm std

-------
APPENDIX B
NON-EGU POINT SOURCE CONTROL CATEGORY CODES

-------
Table B-l
Non-EGU Point Source Category Codes and Descriptions
POD' Source Category	
0	No Match
11	ICI Boilers - Coal/Wall
12	ICI Boilers - Coal/FBC
13	ICI Boilers - Coal/Stoker
14	ICI Boilers - Coal/Cyclone
15	ICI Boilers - Residual Oil
16	ICI Boilers - Distillate Oil
17	ICI Boilers - Natural Gas
18	ICI Boilers - Wood/Bark/Stoker
19	ICI Boilers - Wood/Bark/FBC
20	ICI Boilers - MSW/Stoker
21	Internal Combustion Engines - Oil
22	Internal Combustion Engines - Gas
23	Gas Turbines - Oil
24	Gas Turbines - Natural Gas
25	Process Heaters - Distillate Oil
26	Process Heaters - Residual Oil
27	Process Heaters - Natural Gas
28	Adipic Acid Manufacturing
29	Nitric Acid Manufacturing
30	Glass Manufacturing - Container
31	Glass Manufacturing - Flat
32	Glass Manufacturing - Pressed
33	Cement Manufacturing - Dry
34	Cement Manufacturing - Wet
35	Iron & Steel Mills - Reheating
36	Iron & Steel Mills - Annealing
37	Iron & Steel Mills - Galvanizing
38	Municipal Waste Combustors
39	Medical Waste Incinerators
40	Open Burning
41	ICI Boilers - Process Gas
42	ICI Boilers - Coke
43	ICI Boilers - LPG
44	ICI Boilers - Bagasse
45	ICI Boilers - Liquid Waste
46	IC Engines - Gas, Diesel, LPG
47	Process Heaters - Process Gas
48	Process Heaters - LPG
49	Process Heaters - Other Fuel
50	Gas Turbines - Jet Fuel
51	Engine Testing - Natural Gas
52	Engine Testing - Diesel GT

-------
Table B-l
Non-EGU Point Source Category Codes and Descriptions
POD"
Source Category
53
Engine Testing - Oil IC
54
Space Heaters - Distillate Oil
55
Space Heaters - Natural Gas
56
Ammonia - NG-Fired Reformers
57
Ammonia - Oil-Fired Reformers
58
Lime Kilns
59
Comm./Inst. Incinerators
60
Indust. Incinerators
61
Sulfate Pulping - Recovery Furnaces
62
Ammonia Prod; Feedstock Desulfurization
63
Plastics Prod-Specific; (ABS) Resin
64
Starch Mfg; Combined Operations
65
By-Product Coke Mfg; Oven Underfiring
66
Pri Cop Smel; Reverb Smelt Furn
67
Iron Prod; Blast Furn; Blast Htg Stoves
68
Steel Prod; Soaking Pits
69
Fuel Fired Equip; Process Htrs; Pro Gas
70
Sec Alum Prod; Smelting Furn/Reverb
71
Steel Foundries; Heat Treating Furn
72
Fuel Fired Equip; Furnaces; Natural Gas
73
Asphaltic Cone; Rotary Dryer; Conv Plant
74
Ceramic Clay Mfg; Drying
75
Coal Cleaning-Thrml Dryer; Fluidized Bed
76
Fbrglass Mfg; Txtle-Type Fbr; Recup Furn
77
Sand/Gravel; Dryer
78
Fluid Cat Cracking Units; Cracking Unit
79
Conv Coating of Prod; Acid Cleaning Bath
80
Natural Gas Prod; Compressors
81
In-Process; Bituminous Coal; Cement Kiln
82
In-Process; Bituminous Coal; Lime Kiln
83
In-Process Fuel Use;Bituminous Coal; Gen
84
In-Process Fuel Use; Residual Oil; Gen
85
In-Process Fuel Use; Natural Gas; Gen
86
In-Proc;Process Gas; Coke Oven/Blast Furn
87
In-Process; Process Gas; Coke Oven Gas
88
Surf Coat Oper;Coating Oven Htr;Nat Gas
89
Solid Waste Disp;Gov;Other Incin;Sludge
* A POD is an grouping of sources categories for which a common control technology is
applicable.

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APPENDIX C
SOURCE SPECIFIC EGU BUDGET
EMISSIONS FILE

-------
Table C-l
Source Specific EGU Budget Emissions File
Filename: NFRUT3
Description: Regional NOx SIP Call Budget Determination EGU Point Source File
Variable	Type Length Decimal Description
ST
C
2
0
State Abbreviation
FIPSST
c
2
0
FIPS State Code
FIPSCNTY
c
3
0
FIPS County Code
PLANT
c
45
0
Plant Name
PLANTID
c
15
0
Plant ID Code
POINTID
c
15
0
Point ID Code
NAMEPLCAP
N
8
2
Capacity (MW) of Largest Generator the Unit Serves
FSIPHEAT
N
15
4
Final Heat Input (mmBtu) Used to Calculate Budget (Based on




Year to Use)
F95HEAT
N
15
4
1995 Ozone Season Heat Input (mmBtu)
F96HEAT
N
15
4
1996 Ozone Season Heat Input (mmBtu)
FSIPNOXRT
N
8
5
NOx Rate Used to Calculate Budget
FSIPHTYR
C
4
0
Year to Use for Heat Input to Calculate Individual State Budget
F95NOXRT
N
8
5
1995 NOx Emission Rate (lbs/mmBtu)
F96NOXRT
N
8
5
1996 NOx Emission Rate (lbs/mmBtu)
NOX MASS
N
15
4
2007 Ozone Season Budget NOx Emissions (pounds)

-------
APPENDIX D
SOURCE SPECIFIC NON-EGU POINT SOURCE BASE AND
BUDGET EMISSIONS FILE

-------
Table D-l
Source Specific Non-EGU Point Source Base and Budget Emissions File
Filename: NFRPT3
Description: Regional NOx SIP Call Non-EGU Point Source File
Variable	Type Length Decimal Description
FIPSST
C
2
0
FIPS State Code
FIPSCNTY
c
3
0
FIPS County Code
PLANTID
c
15
0
Plant ID Code
PLANT
c
40
0
Plant Name
SIC
N
4
0
Standard Industrial Classification Code
POINTID
c
15
0
Point ID Code
STACKID
c
15
0
Stack ID Code
SEGMENT
c
15
0
Segment ID
see
c
10
0
Source Classification Code
POD
c
3
0
Source Category Association
SIZE
c
1
0
Budget Size
BOILCAP
N
8
0
Boiler Design Capacity (MMBtu/hr)
STKHGT
N
4
0
Stack Height (ft)
STKDIAM
N
6
2
Stack Diameter (ft)
STKTEMP
N
4
0
Stack Temperature (degrees F)
STKFLOW
N
10
2
Stack Flow (cu. ft./min)
STKVEL
N
9
2
Stack Velocity (ft/sec)
WINTHRU
N
3
0
Winter Throughput Percentage
SPRIHRU
N
3
0
Spring Throughput Percentage
SUMTHRU
N
3
0
Summer Throughput Percentage
FALTHRU
N
3
0
Fall Throughput Percentage
HOURS
N
2
0
Operating Hours/Day
DAYS
N
1
0
Operating Days/Weeks
WEEKS
N
2
0
Operating Wccks/Year
LATC
N
9
4
Latitude (degrees)
LONC
N
9
4
Longitiude (degrees)
NOXCE95
N
5
2
1995 NOx Control Efficiency
NOXRE95
N
5
2
1995 NOx Rule Effectiveness
DNOX95
N
16
4
1995 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX95
N
16
4
1995 Ozone Season NOx Emissions (tons)
GF9507
N
7
2
1995 - 2007 Growth Factor
NOXCE07
N
5
2
2007 Base NOx Control Efficiency
NOXRE07
N
5
2
2007 NOx Rule Effectiveness
DNOX07
N
16
4
2007 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX07
N
16
4
2007 Ozone Season Base NOx Emissions (tons)
NOXCE07B
N
5
2
2007 Budget NOx Control Efficiency
DBNOX
N
16
4
2007 Typical Ozone Season Daily Budget NOx
Emissions (tons)
SBNOX
N
16
4
2007 Ozone Season Budget NOx Emissions (tons)

-------
APPENDIX E
COUNTY LEVEL STATIONARY AREA BASE AND
BUDGET EMISSIONS FILE

-------
Table E-l
County Level Stationary Area Base and Budget Emissions File
Filename: NFRAR3
Description: Regional NOx SIP Call Stationary Area Source File
Variable	Type Length Decimal Description
FIPSST
C
2
0
FIPS State Code
FIPSCNTY
c
3
0
FIPS County Code
see
c
10
0
Source Classification Code
DNOX95
N
10
4
1995 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX95
N
10
4
1995 Ozone Season NOx Emissions (tons)
GR9507
N
7
3
1995 - 2007 Growth Factor
NOXCE07
N
5
2
2007 Base NOx Control Efficiency
NOXCRE07
N
5
2
2007 NOx Rule Effectiveness
NOXRP07
N
5
2
2007 NOx Rule Penetration
PUGR
N
7
3
2007 Process Units Growth Rate
SCF
N
7
3
2007 Source Conversion Factor
DNOX07
N
10
4
2007 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX07
N
10
4
2007 Ozone Season NOx Emissions (tons)

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APPENDIX F
COUNTY LEVEL NONROAD MOBILE BASE AND
BUDGET EMISSIONS FILE

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Table E-l
County Level Nonroad Mobile Base and Budget Emissions File
Filename: NFRNR3
Description: Regional NOx SIP Call Nonroad Mobile Source File
Variable	Type Length Decimal Description
FIPSST
C
2
0
FIPS State Code
FIPSCNTY
c
3
0
FIPS County Code
see
c
10
0
Source Classification Code
DNOX95
N
10
4
1995 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX95
N
10
4
1995 Ozone Season NOx Emissions (tons)
GR9507
N
7
3
1995 - 2007 Growth Factor
NOXCE07
N
5
2
2007 Base NOx Control Efficiency
NOXCRE07
N
5
2
2007 NOx Rule Effectiveness
NOXRP07
N
5
2
2007 NOx Rule Penetration
PUGR
N
7
3
2007 Process Units Growth Rate
SCF
N
7
3
2007 Source Conversion Factor
DNOX07
N
10
4
2007 Typical Ozone Season Daily NOx Emissions
(tons)
SNOX07
N
10
4
2007 Ozone Season NOx Emissions (tons)

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APPENDIX G
COUNTY LEVEL HIGHWAY VEHICLE BASE AND
BUDGET EMISSIONS FILE

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Table G-l
County Level Highway Vehicle Base and Budget Emissions File
Filename: NFRMB3
Description: Regional NOx SIP Call Highway Vehicle File
Variable
Tvoe
Length
Decimal
DescriDtion
FIPSST
C
2
0
FIPS State Code
FIPSCNTY
C
3
0
FIPS County Code
see
c
10
0
Source Classification Code
VTYPE
c
5
0
Vehicle Type
VOC07SEAS
N
13
6
2007 Ozone Season VOC Emissions (tons)
NOX07SEAS
N
13
6
2007 Ozone Season NOx Emissions (tons)
CO07SEAS
N
13
6
2007 Ozone Season CO Emissions (tons)
VOC07MAY
N
13
6
2007 May VOC Emissions (tons)
VOC07JUN
N
13
6
2007 June VOC Emissions (tons)
VOC07JUL
N
13
6
2007 July VOC Emissions (tons)
VOC07AUG
N
13
6
2007 August VOC Emissions (tons)
VOC07SEP
N
13
6
2007 September VOC Emissions (tons)
NOX07MAY
N
13
6
2007 May NOx Emissions (tons)
NOX07JUN
N
13
6
2007 June NOx Emissions (tons)
NOX07JUL
N
13
6
2007 July NOx Emissions (tons)
NOX07AUG
N
13
6
2007 August NOx Emissions (tons)
NOX07SEP
N
13
6
2007 September NOx Emissions (tons)
CO07MAY
N
13
6
2007 May CO Emissions (tons)
CO07JUN
N
13
6
2007 June CO Emissions (tons)
CO07JUL
N
13
6
2007 July CO Emissions (tons)
CO07AUG
N
13
6
2007 August CO Emissions (tons)
CO07SEP
N
13
6
2007 September CO Emissions (tons)
VMT07MAY
N
16
3
2007 May VMT
VMT07JUN
N
16
3
2007 June VMT
VMT07JUL
N
16
3
2007 July VMT
VMT07AUG
N
16
3
2007 August VMT
VMT07SEP
N
16
3
2007 September VMT
VMT07 SEAS
N
16
3
2007 Ozone Season VMT

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APPENDIX H
MOBILE MODEL HIGHWAY VEHICLE COUNTY
CORRESPONDENCE FILE

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Table H-l
Regional NOx SIP Call MOBILE Model Highway Vehicle County Correspondence
File Format
Filename: XREFV5
Description: Regional NOx SIP Call Highway Mobile Source File
Variable
Type
Length
Decimal Description
FIPSST
C
2
FIPS State code
FIPSCNTY
C
3
FIPS county code
STATECD
c
2
State abbreviation
COUNTYNAME
c
30
County name
M5BFILE
c
12
Name of MOBILE5b input file used to model county
emission factors
ASTM
c
1
Fuel ASTM class (only needed when reformulated gasoline
is modeled)
SPDFLG
c
1
Flag indicating whether user-supplied trip length
distributions were modeled (l=MOBILE5b defaults, 3 or
4=user-supplied trip length distributions)
MYMRFG
c
1
Flag indicating whether user-supplied registration
distributions and/or mileage accumulation rates were
modeled (l=MOBILE5b defaults, 3=user-supplied
registration distributions, 4=user-supplied registration
distributions and mileage accumulation rates)
IMFLAG
c
1
Flag indicating whether I/M program modeled in county
(l=no I/M, all other flag values indicate I/M program
modeled)
ATPFLG
c
1
Flag indicating whether ATP, pressure, or purge tests were
modeled for this county (l=no ATP, pressure, or purge,
2=ATP modeled, 5=ATP and pressure test modeled,
8=ATP, pressure, and purge tests modeled)
SPDFILE
c
10
Name of file containing trip length distribution modeled
for this county
MYMRFILE
c
10
Name of file containing registration distributions and/or
mileage accumulation rates modeled for this county
IMATPFILE
c
8
Name of file with I/M, ATP,pressure, and purge program
inputs modeled in this county (EPA high enhanced
performance standard = HEIMPS and NHEIMPS, EPA
low enhanced performance standard = LEIMPS and
NLEIMPS, EPA basic I/M performance standard =
BSIMPS, NBS
OPMODE
c
16
Operating mode fractions (default = " 20.6 27.3 20.6 ")
RVPJUL
N
4
1 Fuel RVP value modeled (psi)
REFORMFLG
c
1
Reformulated gasoline flag: l=no RFG, 2=RFG
OXYDAT
c
21
Oxygenated/alcohol fuel data for county: ether blend
market share, alcohol blend market share, oxygen content
of ether blends, oxygen content of alcohol blends, RVP
waiver switch (l=no RVP waiver, 2=1 psi RVP waiver)
LEV_MINMAX
c
1
Flag indicating whether minimum (1) or maximum (2)
LEV credits were applied in this county
LEVSTART
c
2
Start year of LEV program in this county
LEVIMPFILE
c
12
LEV implementation schedule file used to run MOBILE5b
for this county
SPEEDSCC
c
12
Name of file containing vehicle speeds modeled in this
county (default file is SCCSPD.DBF)

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