DEVELOPMENT OF MODELING INVENTORY AND BUDGETS FOR REGIONAL NOx SIP CALL U. S. Environmental Protection Agency Office of Air Quality Planning and Standards September 24, 1998 ------- This page intentionally left blank. ------- Chapter I Introduction Table of Contents l Chapter II Electric Generating Unit Point Source Data 3 A. Development of Base Year Data 3 B. 2007 Base Case 7 C. 2007 Budget Case 7 D. EGU Emission Summary 8 Chapter III Non-EGU Point Source Data 11 A. Development of Base Year Data 11 B. 2007 Base Case 11 C. 2007 Budget Case 12 D. Non-EGU Emission Summary 14 Chapter IV Stationary Area and Nonroad Source Data 29 A. Development of Base Year Data 29 B. 2007 Base Case 29 C. 2007 Budget Case 30 D. Stationary Area and Nonroad Emission Summary 30 Chapter V Highway Vehicle Source Data 33 A. Development of Base Year Data 33 B. 2007 Base Case 33 C. 2007 Budget Case 34 D. Highway Vehicle Emission Summary 34 Chapter VI Statewide NOx Budgets 37 APPENDIX A 2007 BASE CASE CONTROLS APPENDIX B NON-EGU POINT SOURCE 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 MOBILE BASE AND BUDGET EMISSIONS FILE ------- This page intentionally left blank. ------- 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 NOx State Implementation Plan (SIP) Call 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 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 mobile source data and budget. ------- This page intentionally left blank. ------- Chapter II Electric Generating Unit Point Source Data A. Development of Base Year Data The base year electric generating unit (EGU) data base developed for this modeling effort consists of both electric utility units and nonutility electricity generating units. The nonutility electricity generating units include independent power producers (IPPs) and nonutility generators (NUGs). Two alternative base year data sets were developed: one using the higher of 1995 or 1996 heat input (determined at the State-level) and one using 1996 heat input. For each base year data set both seasonal (for budget determination) and daily emission estimates (for modeling) were developed. Eight data sources were used to develop the base year EGU 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 modeling. The IPM includes over 7,000 records (nationally) with data on existing electricity generating units. The records are maintained in EPA's National Electric Energy Data System (NEEDS). In general, 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 used as units for the EGU. Supplemental data, provided by EPA, including the start year, the base year (1994) NOx rate, and 3 ------- type of ownership, were added to the IPM data base. This file 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 for NOx tons and heat input. Data were provided in a variety of files from EPA. 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 data, 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 tons 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 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 FGD 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 has been developed for EPA for many years. The data base is 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 are always used if available. Source Classification Codes (SCCs) are assigned to each boiler based on boiler and fuel characteristics; AP-42 emission factors are always used to calculate VOC, CO, PM10, and PM2.5 emissions. The 1990 and 1995 Trends data bases were used to obtain SCCs, stack parameters, and NOx tons and heat input. 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 records from this file were ultimately used since it was difficult to obtain NOx tons, heat input, or locational data unless they matched to another source. The OTAG data base was developed by collecting and compiling electric utility emission 4 ------- inventory data from States in the OTAG domain. This inventory is for the year 1990 and contains summer day emission estimates, as well as variables required for photochemical modeling. This data base was used to obtain NOx 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 originated in the other data bases, their primary purpose was to add variables required for modeling to the units identified by the ARDB or IPM data. The data from the above sources was further refined by the consideration of comments submitted to the NOx SIP call NPR. 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, and 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. 1. Seasonal NOx Tons and Heat Input The hierarchy for obtaining seasonal NOx tons and heat input for a particular unit is provided below. For the 1995/1996 base year: 1. 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. 2. Based on that boiler year information, use ETS/CEM data to obtain 1996 seasonal NOx tons and 1996 seasonal heat input, or 1995 seasonal NOx rate and 1995 seasonal heat input to calculate 1995 seasonal NOx tons. 3. Based on that boiler year information, use the 1996 projected or 1995 NET data base (Both of which include annual boiler-level ETS/CEM data) for annual NOx tons and heat input, then convert to seasonal. 4. Use 1990 OTAG file for ozone season day (OSD) NOx tons and OSD heat input (or July month heat input and divide by 31), then convert to seasonal and forecast. 5 ------- 5. Use IPM N0X rate and 2007 July heat input, calculate NOx tons, convert to seasonal, and backcast. 6. If there is a heat input and no NOx tons or rate, assign an AP-42 default NOx rate based on SCC and convert to seasonal. For 1996 base year: 1. Use ETS/CEM 1996 file for seasonal NOx tons and 1996 seasonal heat input. 2. Use the 1996 projected or 1995 NET data base (both of which include annual boiler-level ETS/CEM data) for annual NOx tons and heat input, then convert to seasonal. 3. Use 1990 OTAG file for OSD NOx tons and OSD heat input (or July month heat input and divide by 31), then convert to seasonal and forecast. 4. Use IPM NOx rate and 2007 July heat input, calculate NOx tons, convert to seasonal, and backcast. 5. If there is a heat input and no NOx tons or rate, assign an AP-42 default NOx rate based on SCC and convert to seasonal. 2. Source Classification Codes (SCCs) The methodology for assigning SCC is as follows: 1. Match with NET 1995 or 1990 inventory and assign the major SCC (based on heat input) to the boiler. 2. Match with OTAG and assign the major SCC. 3. Assign default SCCs based on prime mover, fuel type, and (in the case of steam units) boiler bottom and firing types. 3. Stack Parameters The methodology for obtaining stack parameters is as follows: 1. Match with NET 1995 or 1990 inventory and use the stack data. 2. Match with OTAG and use the stack data. 3. Assign default stack parameters, based on prime mover and fuel type, that were 6 ------- originally developed for the Regional Oxidant Model (ROM). (Note that since stack parameters in IPM were originally developed by matching with 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 for 2007 were determined using the Integrated Planning Model (IPM). The 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). The seasonal unit-specific data for 2007 output from the IPM model was processed using the Emissions Modeling System-95 (EMS) to generate typical ozone season weekday, Saturday, and Sunday allocations for episodic modeling. Appendix A presents the EGU source controls included in the 2007 base case. C. 2007 Budget Case The 2007 budget case was developed by applying growth factors and an emission rate to the 1995/1996 base year heat input. Units greater than 25 MWe in the SIP call region 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 detailed file of EGU sources including emissions, growth, and control information used to estimate the 2007 EGU budget is provided in Appendix C of this document. 1. Growth Factors The growth factors used in the 2007 base case were supplied by EPA and came 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). Since publication of the SNPR, EPA has revised its estimates of State-specific growth rates from 1996 to 2007. The estimates were interpolated from the average annual growth of each State as forecasted by EPA using the IPM and EPA's baseline electric generation forecast. In developing the average annual growth, EPA relied on unit-specific summer energy use from 2000 to 2010 as forecasted by the IPM. The final growth factors are shown in Table II-1. The growth factors were applied to the 1995/1996 heat input to get 2007 projected heat input. Emissions were then estimated by multiplying the 2007 projected heat input by the 2007 budget-applicable NOx rate. D. EGU Emission Summary Table II-2 is a State-level summary of the EGU data. It contains both daily and seasonal heat input and NOx emissions for the 1995/1996 base year, the 1996 base year, and the 2007 budget 7 ------- case. 8 ------- Table II-l IPM Growth Factors 1996-2007 State Growth Factor Alabama 1.10 Connecticut 0.60 District of 1.36 Columbia 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 9 ------- Table II-2 Base and Budget Daily and Seasonal Heat Input and NOx Emissions of EGU Data 1995/1996 1996 2007 Heat Input Emissions Heat Input Emissions Heat Input Budget ST Daily Seasonal (MMBtu/day) (MMBtu/season) Daily (tons/day) Seasonal (tons/season) Daily Seasonal (MMBtu/day) (MMBtu/season) Daily (tons/day) Seasonal (tons/season) Daily Seasonal (MMBtu/day) (MMBtu/season) Daily (tons/day) Seasonal (tons/season) AL 2,503,648 352,462,502 699 26,387 2,503,648 352,425,386 699 99,156 2,754,013 387,708,752 206 29,051 CT 500,695 57,963,067 53 4,304 500,695 57,963,067 53 6,045 300,417 34,777,840 22 2,583 DE 291,168 36,929,685 57 2,774 291,168 36,929,685 57 7,341 369,784 46,900,700 28 3,523 DC 31,698 2,026,082 0 152 2,006 128,205 0 23 43,110 2,755,472 3 207 GA 2,623,259 356,189,138 585 26,774 2,447,655 336,016,010 585 80,736 2,964,282 402,493,727 223 30,255 IL 2,629,757 380,831,882 942 29,672 2,629,757 380,831,882 900 113,741 2,840,138 411,298,433 21 32,045 IN 3,663,468 536,397,099 1,173 41,897 3,663,468 536,397,099 1,173 156,317 4,286,258 627,584,606 335 49,020 KY 2,817,630 418,293,392 1,066 30,106 2,817,630 418,293,392 1,066 150,225 3,268,450 485,220,335 248 36,753 MD 1,088,379 146,326,807 333 10,948 991,312 140,309,532 333 44,779 1,469,311 197,541,191 110 14,807 MA 849,027 124,714,270 108 9,455 849,027 113,610,193 108 14,755 1,349,953 198,295,689 103 15,033 MI 2,125,769 317,207,481 538 24,925 2,125,769 316,869,141 538 79,692 2,402,119 358,444,454 189 28,165 MO 2,000,402 286,136,866 561 21,948 2,000,402 278,158,320 561 79,565 2,180,437 311,889,185 168 23,923 NJ 816,787 102,386,614 135 8,421 793,851 88,723,256 122 14,445 1,053,655 132,078,731 78 10,863 NY 2,704,128 380,092,043 294 28,832 2,370,956 294,737,106 294 37,377 2,839,335 399,096,648 215 30,273 NC 2,575,405 343,950,596 941 25,946 2,575,405 343,950,596 941 125,237 3,116,241 416,180,221 235 31,394 OH 4,157,537 578,736,962 1,644 45,297 4,157,537 578,736,962 1,644 229,886 4,448,564 619,248,549 348 48,468 PA 3,937,388 563,665,148 853 45,218 3,937,388 563,665,148 853 116,304 4,527,996 648,214,923 364 52,000 RI 217,610 31,701,944 17 2,378 217,610 31,701,944 17 2,145 102,277 14,899,914 8 1,118 SC 1,128,591 151,900,826 385 11,391 1,128,591 151,900,826 385 51,822 1,613,885 217,218,182 121 16,290 TN 1,976,188 279,738,759 801 20,980 1,899,491 268,877,789 801 113,329 2,391,187 338,483,899 179 25,386 VA 1,480,154 183,906,327 348 13,832 1,266,114 155,553,455 348 44,508 1,953,803 242,756,353 147 18,258 WV 2,216,129 342,257,483 847 25,669 2,216,129 342,755,795 843 116,758 2,282,613 352,525,208 171 26,439 WI 1,395,215 210,372,259 314 16,046 1,342,849 201,659,868 294 42,407 1,562,641 235,616,930 121 17,972 Total 43,730,032 6,184,187,232 12,692 473,351 42,728,458 5,990,194,657 12,613 1,726,590 50,120,470 7,081,229,940 3,839 543,825 ------- Chapter III Non-EGU Point Source Data A. Development of Base Year Data The non-EGU point source inventory was based on data sets originating with the OTAG 1990 base year inventory. The OTAG prepared these base year inventories with 1990 State ozone SIP emission inventories, and EPA supplemented them with either State inventory data, if available, or EPA's National Emission Trends (NET) data if State data were not available. For the SNPR, non-EGU point source inventory data 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) 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. The data to model 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. Based on comments submitted during the NPR and SNPR public comment periods, EPA revised the 1995 non-EGU point source inventory 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. Where 1990 base year data were submitted and accepted, the methods described earlier in this section were utilized to account for growth to 1995 levels. 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). B. 2007 Base Case The inventory data for 1995 was projected to 2007 using BEA projections of Gross State Product (GSP) at the 2-digit SIC level and the Emissions Modeling System-95 (EMS) to generate typical ozone season weekday, Saturday, and Sunday allocations for episodic modeling. Consistent with the SNPR 2007 projection methodology, the growth factors developed were based on the change in projected GSP between 1990 and 2007. The amount of growth estimated to have occurred between 1990 and 1995 was factored out of the 1990 to 2007 growth factors using the following formula: 11 ------- _ 1990 to 2007 1995 to 2007 rT7 1990 to 1995 where: GF1995to2oo7 = the 1995 to 2007 growth factor used to project from 1995 to 2007 GF1990to2oo7 = the 1990 to 2007 growth factor used in OTAG to project from 1990 to 2007 GF1990tol995 = the 1990 to 1995 growth factor used to project the 1990 OTAG emissions to 1995 for the SIP Call base year data. The resulting 1995 to 2007 growth factors were applied to the 1995 base year emissions to project 2007 emissions. In addition to NOx RACT, MACT control assumptions were applied to large municipal waste combustors (MWC) in the base case. As demonstrated in the supporting TSD, a 30 percent NOx reduction is attainable and assumed for sources identified by this rule (EPA, 1998b). Appendix A presents the non-EGU point source controls included in the 2007 base case. Seasonal emissions were calculated by multiplying the weekday emissions by 109 days, and each of the weekend allocations by 22 days to estimate a 153-day ozone season. This seasonal value was then divided by 153 days to estimate the typical ozone day for summary purposes. C. 2007 Budget Case To determine assumed control strategy reduction for non-EGU point sources for purposes of calculating the budget, emissions were initially totaled at each source to a primary fuel (SCC) based on decreasing daily NOx emissions from the base year inventory. This was done to prevent the application of multiple control strategies, and the costs associated with those controls, to units firing multiple fuels. A source category was then assigned to this primary fuel from which NOx reduction strategies were associated and where deemed applicable. Appendix B presents a list of these categories which are identified in the emissions files by the field name [POD], For the 2007 budget case calculation, an additional distinction was needed between large (>250 MMBtu/hr or greater than 1 ton NOx/day) and small (<=250 MMBtu/hr and emitting less than or equal to 1 ton NOx/day) points for non-EGU sources. Where 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 records in the inventory did not include boiler capacity data. For these cases, data from EPA's NET Inventory were used to determine whether a non- EGU source was assumed as a large or small source as was similarly done for NPR budget calculation purposes. 12 ------- 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 records 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 record with a boiler capacity of 276 MMBtu/hr, the daily NOx emissions from that unit were included from that record. If more than one record had a boiler capacity of 276 MMBtu/hr, the mean daily emissions of those records was used. Each non-EGU record in the inventory was matched to the file described above based on the 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. 1. If boiler capacity data were provided for the unit, size determination was made based on those data. 2. If boiler capacity data were not provided for the unit and a match could be made to the SNPR non-EGU inventory, the default identification of large sources developed for the SNPR budget calculation was used. 3. If both the mean and median boiler capacity in the file were greater than 300 MMBtu/hr, it was assumed that the record's boiler capacity was greater than 250 MMBtu/hr. 4. If either the mean or median boiler capacity was in between 200 and 300 MMBtu/ hr, then the daily NOx emissions were used to determine the boiler size. If the record's daily NOx emissions were greater than the average daily NOx emissions in the default boiler capacity file, it was assumed that the record's boiler capacity was greater than 250 MMBtu/hr. If the record's daily NOx emissions were less than the average daily NOx emissions in the default boiler capacity file, it was assumed that the record's boiler capacity was less than 250 MMBtu/hr. 5. If both the mean and median boiler capacity in the file were less than 200 MMBtu/hr, it was assumed that the record's boiler capacity was less than 250 MMBtu/hr. 6. If the record could not be matched to the default boiler capacity file, it was assumed that the record's boiler capacity was less than 250 MMBtu/hr. Records for which the boiler capacity was estimated to be greater than 250 MMBtu/hr were categorized as large sources. Additionally, 1995 point-level emissions were checked for each record where the boiler capacity was estimated to be less than 250 MMBtu/hr. If the 1995 13 ------- point-level emissions were more than 1 ton/day, the record was categorized as a large source. Otherwise the record was categorized as a small source. In contrast to the NPR and SNPR methods of applying a 70 percent control to all large sources and RACT to all medium sources within the affected SIP Call domain, assumed budget reductions were assigned only to large sources in the specific source categories listed in Table III-3. RACT requirements are not assumed for medium or small-sized sources in the budget calculation of the NFR. Emission decreases from sources smaller than the heat input capacity cutoff level, and that emit less than 1 ton of NOx per ozone season day, are not assumed as part of the budget calculation; these sources are included in the budget at baseline levels. Additionally, those sources without adequate information to determine potentially applicable control techniques are included in the budget at baseline levels. Budget reductions were estimated from 2007 uncontrolled emission levels first calculated by removing base case control efficiency and rule effectiveness values. The budget reduction percentage was then applied with the same rule effectiveness to estimate budget level emissions. No emission reduction in addition to base case controls are assumed for small sources. No additional VOC or CO controls were applied in the 2007 budget case. It should be noted that the budget reductions were applied to all sources even if they were less stringent than the existing 2007 base case controls. This resulted in an increase in emissions from the 2007 base case to the 2007 budget case for some sources, but is consistent with the EGU budget calculation. A detailed file of non-EGU sources including emissions, growth, and control information is provided in Appendix D of this document. D. Non-EGU Emission Summary Table III-4 is a State-level summary of the seasonal non-EGU data. It contains five month ozone season NOx emissions for the 2007 base case and the 2007 budget case. 14 ------- Table III-l Default NOx RACT Control Assumptions Default NOx RACT Control Efficiency see 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 15 ------- 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 16 ------- 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 17 ------- 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 18 ------- 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 19 ------- 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 20 ------- 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 105001 68.22 58 200 0.0035 105002 106.77 108 115 0.0108 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 204001 567.14 390 210 0.1043 204004 6.00 6 6 0.0223 21 ------- 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 301001 288.00 288 288 0.6520 301003 760.62 782 445 1.0585 301005 30.50 31 43 0.0143 301006 100.00 100 134 0.1488 301009 31.00 31 31 0.0335 301018 42.00 50 70 0.1422 301021 68.00 68 68 0.0902 301023 149.00 168 168 0.0031 301024 310.00 310 310 2.5889 301026 62.00 40 247 0.3385 301030 45.80 29 75 0.0668 301032 17.33 10 60 0.0005 301033 4.00 4 4 0.0030 301035 65.50 52 130 0.9466 301050 1.50 2 2 0.6707 301125 399.50 56 105 0.2021 301140 86.00 86 86 0.1106 301250 189.33 178 230 0.5717 301800 170.00 170 170 1.1550 301888 103.00 103 156 1.1209 301900 9.36 13 16 0.0166 301999 1027.50 40 74 0.5594 302002 5.00 5 5 0.1122 302004 36.00 36 36 0.0633 302007 17.75 17 35 0.1559 302009 95.20 66 260 0.0059 302010 123.00 123 123 0.6380 302999 17.50 18 30 0.0030 303000 4.50 5 6 0.0019 303003 338.27 160 260 0.6746 303008 355.60 227 227 0.6253 303009 244.23 105 263 0.5550 303014 37.74 21 310 0.1934 303999 10.00 10 10 0.0195 304001 11.00 11 11 0.0092 22 ------- 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 304003 51.33 33 89 0.0127 304004 20.50 21 24 0.0023 304007 24.25 25 36 0.0013 304008 41.00 41 41 0.0624 304020 82.25 93 93 0.1393 304999 28.00 28 52 0.0110 305001 9.20 6 26 0.1109 305002 37.87 21 190 0.0488 305003 17.13 15 29 0.0204 305005 7.00 7 7 0.0033 305006 196.75 230 250 0.4356 305007 724.00 724 248 4.2005 305008 42.00 42 42 0.3154 305009 30.00 30 30 0.0129 305010 106.30 100 221 0.1372 305014 55.53 49 150 3.0135 305015 18.11 10 58 0.0506 305016 100.13 103 172 0.4122 305019 76.33 70 89 1.3739 305020 4.00 4 4 0.0283 305021 19.00 19 19 0.0124 305040 110.00 110 110 0.1642 305999 43.00 43 43 0.1661 306001 127.20 63 250 0.2181 306002 243.83 235 238 0.2882 306003 172.00 232 249 0.3476 306011 5.00 5 5 0.0231 306012 126.00 126 126 0.0888 306099 12.50 13 15 0.0303 306888 41.00 41 41 0.4362 306999 21.17 21 31 0.0814 307001 403.92 338 248 0.1822 307002 340.00 340 52 0.0193 307007 44.67 32 160 0.1408 307008 40.00 40 40 0.4065 23 ------- 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 307013 58.50 59 112 0.0478 307020 24.00 24 37 0.0039 307900 77.33 61 110 0.1716 307999 30.00 25 40 0.1038 308999 46.00 46 46 0.0050 309999 143.17 178 269 0.0564 310002 16.99 6 289 0.1779 310004 39.56 29 118 0.0616 313999 26.00 36 36 0.0013 314999 26.00 36 36 0.0013 390001 5.00 5 5 0.0418 390002 121.50 101 248 4.2005 390004 174.36 71 250 0.3908 390005 32.16 28 141 0.0014 390006 152.17 36 250 0.3908 390007 310.48 80 231 0.1690 390008 4.00 4 4 0.0125 390009 88.60 28 357 0.3891 390010 9.57 11 15 0.0032 390013 14.25 8 39 0.0682 399999 30.00 30 30 0.0475 401002 56.00 56 56 0.0224 402001 30.60 5 133 0.0285 402006 2.00 2 2 0.0032 402008 7.13 8 12 0.0035 402009 69.50 70 133 0.0285 402010 6.67 5 12 0.0035 402013 56.00 56 56 0.1172 402017 3.17 5 5 0.0036 402025 46.00 46 46 0.0050 403001 10.00 10 10 0.0099 403011 1.00 1 1 0.0047 404001 20.00 20 20 0.0035 405001 3.33 4 5 0.0017 405005 3.00 3 3 0.0022 24 ------- 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 406001 56.50 57 70 0.3557 490999 21.00 21 21 0.0348 501001 3345.82 37 375 1.3650 502001 17943.33 245 245 0.0485 502005 1.00 1 1 0.0085 503001 1347.94 10 140 0.3322 503005 276.25 361 361 0.3686 25 ------- 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 26 ------- Table III-4 Base and Budget Ozone Season NOx Emissions Non-EGU Point Sources State 1995 Base* 2007 Base 2007 Budget Reduction Alabama 42,190 49,781 37,696 24% Connecticut 5,674 5,273 5,056 4% Delaware 1,443 1,781 1,645 8% District of Columbia 395 310 292 6% Georgia 28,370 33,939 27,026 20% Illinois 67,391 55,721 42,011 25% Indiana 60,348 71,270 44,881 37% Kentucky 15,736 18,956 14,705 22% Maryland 14,228 10,982 7,593 31% Massachusetts 11,611 9,943 9,763 2% Michigan 65,758 79,034 48,627 38% Missouri 12,892 13,433 11,054 18% New Jersey 21,930 22,228 19,804 11% New York 24,240 25,791 24,128 6% North Carolina 28,150 34,027 25,984 24% Ohio 47,014 53,241 35,145 34% Pennsylvania 78,588 73,748 65,510 11% Rhode Island 338 327 327 0% South Carolina 25,675 34,740 25,469 27% Tennessee 49,794 60,004 35,568 41% Virginia 36,000 39,765 27,076 32% West Virginia 41,102 40,192 31,286 22% Wisconsin 17,852 22,796 17,973 21% Total 696,718 757,281 558,618 26% * 1995 Base emissions estimated by multiplying typical ozone season daily emissions by 153 days. 27 ------- This page intentionally left blank. 28 ------- Chapter IV Stationary Area and Nonroad Source Data A. Development of Base Year Data The stationary area and nonroad mobile source inventory was based on data sets originating with the OTAG 1990 base year inventory. These base year inventories were prepared with 1990 State ozone SIP emission inventories supplemented with either State inventory data, if available, or EPA's National Emission Trends (NET) data if State data were not available. The OTAG 1990 nonroad emission inventories were based primarily on estimates of actual 1990 nonroad activity levels found in the October 1995 edition of EPA's annual report, "National Air Pollutant Emission Trends." These 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. Based on comments submitted during the NPR and SNPR public comment periods, the 1995 stationary area and nonroad mobile source inventories were revised with data addressing issues such as emission estimate revisions, spacial allocation revisions, and base year control levels. Where 1990 base year data were used, the method described above was utilized to account for growth to 1995 levels. 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). B. 2007 Base Case The inventory data for 1995 was projected to 2007 using BEA projections of Gross State Product (GSP) at the 2-digit SIC level and the Emissions Modeling System-95 (EMS) to generate typical ozone season weekday, Saturday, and Sunday allocations for episodic modeling. Consistent with the SNPR 2007 projection methodology, the growth factors developed were based on the change in projected GSP between 1990 and 2007. The amount of growth estimated to have occurred between 1990 and 1995 was factored out of the 1990 to 2007 growth factors using the following formula: /-yjp _ ^1990 to 2007 1995 to 2007 rj7 1990 to 1995 where: GF1995to2oo7 = the 1995 to 2007 growth factor used to project from 1995 to 2007 GF199„to2oo7 = the 1990 to 2007 growth factor used in OTAG to project from 1990 to 2007 GF1990tol995 = the 1990 to 1995 growth factor used to project the 1990 OTAG emissions to 1995 for the SIP Call base year data. The resulting 1995 to 2007 growth factors were applied to the 1995 base year emissions to 29 ------- project 2007 emissions. In contrast to the SNPR, reductions from certain nonroad mobile controls were assumed to occur in the base case as a result of measures implemented between promulgation of the final rule and base year 2007. These measures 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. Controls previously reflected in the budget were not included in the base case in the original SNPR calculations. These measures were included in the base case, rather than the budgets, because the measures would be implemented even in the absence of the final rulemaking. Appendix A presents the stationary area and nonroad mobile control measures included in the 2007 base case. Resulting seasonal emissions were calculated by multiplying the weekday emissions by 109 days, and each of the weekend allocations by 22 days to estimate a 153-day ozone season. This seasonal value was then divided by 153 days to estimate the typical ozone day for summary purposes. C. 2007 Budget Case For stationary area and nonroad mobile sources, no additional reduction was incurred between the base and budget cases. A detailed file of county-level stationary area and nonroad mobile source emissions and growth is provided in Appendices E and F of this document. 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 2007 base and budget cases. 30 ------- Table IV-1 Base and Budget Ozone Season NOx Emissions Stationary Area and Nonroad Mobile 1995 1995 2007 2007 Stationary Nonroad Stationary Nonroad State Area* Mobile* Area Mobile Alabama 24,247 29,497 25,225 16,594 Connecticut 4,258 13,101 4,588 9,584 Delaware 1,728 4,355 963 4,261 District of Columbia 838 1,924 741 3,470 Georgia 10,694 37,007 11,902 21,588 Illinois 8,824 76,957 7,822 47,035 Indiana 18,009 44,942 25,544 22,445 Kentucky 35,584 30,979 38,773 19,627 Maryland 4,055 20,463 4,105 17,249 Massachusetts 9,984 25,662 10,090 18,911 Michigan 22,289 35,899 28,128 23,495 Missouri 6,540 36,256 6,603 17,723 New Jersey 10,602 30,629 11,098 21,163 New York 17,294 43,706 15,587 29,260 North Carolina 9,330 30,744 10,651 17,799 Ohio 16,899 62,715 19,425 37,781 Pennsylvania 15,002 50,303 17,103 25,554 Rhode Island 373 3,076 420 2,073 South Carolina 6,748 18,829 8,359 11,903 Tennessee 9,881 66,783 11,990 44,567 Virginia 21,301 35,786 18,622 21,551 West Virginia 5,358 15,471 4,790 10,220 Wisconsin 9,111 25,772 8,160 12,965 Total 268,949 740,856 290,689 456,818 * 1995 Base emissions estimated by multiplying typical ozone season daily emissions by 153 days. 31 ------- This page intentionally left blank. 32 ------- Chapter V Highway Vehicle Source Data A. Development of Base Year Data The highway vehicle source inventory was based on data sets originating with historical 1995 VMT levels from the Highway Performance Monitoring System (HPMS). The HPMS data were used to estimate States' 1995 VMT by vehicle category, except in those cases where EPA accepted revisions per the NPR and SNPR comment periods. These VMT estimates reflect the growth in overall VMT from 1990 to 1995, as well as the increase in light truck and sport-utility vehicle use relative to light-duty vehicle use. The 1995 NOx emissions inventories also reflect the type and extent of inspection and maintenance programs in effect as of that year and the extent of the Federal reformulated gasoline program. The 1995 highway vehicle budget components are based on EPA's MOBILE5a emission inventory model with corrected default inputs. B. 2007 Base Case The EPA is continuing to use the growth methods developed by OTAG for the purpose of projecting VMT growth between 1995 and 2007. Growth in highway mobile sources was modeled by growing the 1995 vehicle miles traveled (VMT). 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 MOBILE4.1 Fuel Consumption Model VMT was first allocated to MSAs and rest-of-state areas using 1995 population and projected 2007 population estimates. The actual growth factors were calculated as the ratio of the allocated 2007 VMT to the allocated 1995 VMT by MSA or rest-of-state area and road type. Based on comments submitted during the NPR and SNPR public comment periods, EPA revised the base VMT and VMT growth factors were revised with appropriately explained and documented growth estimates. Details of these comments are their affect on the base inventories can be found in the response to significant comments document for the NFR (EPA, 1998a). Emissions were calculated using average minimum and maximum monthly historical (1970 to 1997) State-level temperatures and NOx RFG correction in RFG areas. Table V-l presents these monthly temperatures by State. In contrast to the SNPR, reductions from certain highway mobile controls were assumed to occur in the base case as a result of measures implemented between promulgation of the final rule and base year 2007. These measures include National Low Emission Vehicle Standards and the 2004 Heavy-Duty Engine Standards. Controls previously reflected in the budget were not included in the base case in the original SNPR calculations. These measures were included in the base case, rather than the budgets, because the measures would be implemented even in the absence of the final rulemaking. Appendix A presents the highway mobile control measures included in the 2007 base case. 33 ------- C. 2007 Budget Case For highway mobile sources, no additional reduction was incurred between the base and budget cases. A detailed file of county-level highway mobile source VMT, growth, and emissions is provided in Appendix G of this document. D. Highway Vehicle Emission Summary Table V-2 is a State-level summary of the seasonal highway vehicle data. It contains five month ozone season NOx emissions for the 2007 base and budget cases. 34 ------- Table V-l 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 ------- Table V-2 VMT and 2007 Budget Ozone Season NOx Emissions Highway Mobile Daily Daily Seasonal 1995 VMT 2007 VMT 2007 VMT Final Budget State (thousands) (thousands) (thousands) (tons/season) Alabama 134,341 165,931 23,642,476 50,111 Connecticut 85,823 105,884 14,960,237 18,762 Delaware 23,101 29,621 4,206,684 8,131 District of Columbia 10,473 13,742 1,946,068 2,082 Georgia 261,911 350,942 49,777,317 86,611 Illinois 258,319 329,567 46,967,435 81,297 Indiana 165,944 200,011 30,253,176 60,694 Kentucky 126,429 155,617 22,133,666 45,841 Maryland 137,769 175,807 24,837,510 27,634 Massachusetts 146,732 181,366 25,608,187 24,371 Michigan 262,502 311,904 44,258,682 83,784 Missouri 182,783 228,386 32,349,941 55,230 New Jersey 186,381 229,501 32,442,260 34,106 New York 351,902 412,077 58,360,433 80,521 North Carolina 190,514 267,983 38,191,543 66,019 Ohio 308,982 371,334 52,640,487 99,079 Pennsylvania 289,803 350,345 49,759,266 92,280 Rhode Island 21,158 25,694 3,611,724 4,375 South Carolina 119,181 154,748 22,025,312 47,404 Tennessee 172,476 222,304 31,546,130 64,965 Virginia 214,559 273,737 38,789,952 70,212 West Virginia 53,765 64,272 9,160,525 20,185 Wisconsin 157,966 196,343 27,941,500 49,470 Total 3,862,814 4,817,116 685,410,511 1,173,164 36 ------- 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. 37 ------- Table VI-1 Seasonal Statewide NOx Base and Budgets (Tons/Season) State Final Base Final Budget Reduction Alabama 218,637 158,677 27% Connecticut 43,843 40,573 7% Delaware 20,974 18,523 12% District of Columbia 6,606 6,792 -3% Georgia 240,495 177,382 26% Illinois 311,186 210,210 32% Indiana 316,726 202,584 36% Kentucky 231,026 155,699 33% Maryland 92,573 71,388 23% Massachusetts 79,794 78,168 2% Michigan 301,041 212,199 30% Missouri 175,086 114,533 35% New Jersey 106,947 97,034 9% New York 190,358 179,769 6% North Carolina 213,311 151,847 29% Ohio 372,658 239,898 36% Pennsylvania 331,787 252,447 24% Rhode Island 8,277 8,313 0% South Carolina 138,705 109,425 21% Tennessee 252,434 182,476 28% Virginia 191,034 155,719 18% West Virginia 190,877 92,920 51% Wisconsin 145,353 106,540 27% Total 4,179,728 3,023,116 28% 38 ------- Table VI-1 Seasonal Statewide NOx Base and Budgets by Major Source Category (Tons/Season) State EGU Non-EGU Area 2007 Base NOx Emissions (tons/season) Nonroad Highway Total EGU Non-EGU 2007 Budget NOx Emissions (tons/season) Area Nonroad Highway Total Alabama 76,926 49,781 25,225 16,594 50,111 218,637 29,051 37,696 25,225 16,594 50,111 158,677 Connecticut 5,636 5,273 4,588 9,584 18,762 43,843 2,583 5,056 4,588 9,584 18,762 40,573 Delaware 5,838 1,781 963 4,261 8,131 20,974 3,523 1,645 963 4,261 8,131 18,523 District of Columbia 3 310 741 3,470 2,082 6,606 207 292 741 3,470 2,082 6,792 Georgia 86,455 33,939 11,902 21,588 86,611 240,495 30,255 27,026 11,902 21,588 86,611 177,382 Illinois 119,311 55,721 7,822 47,035 81,297 311,186 32,045 42,011 7,822 47,035 81,297 210,210 Indiana 136,773 71,270 25,544 22,445 60,694 316,726 49,020 44,881 25,544 22,445 60,694 202,584 Kentucky 107,829 18,956 38,773 19,627 45,841 231,026 36,753 14,705 38,773 19,627 45,841 155,699 Maryland 32,603 10,982 4,105 17,249 27,634 92,573 14,807 7,593 4,105 17,249 27,634 71,388 Massachusetts 16,479 9,943 10,090 18,911 24,371 79,794 15,033 9,763 10,090 18,911 24,371 78,168 Michigan 86,600 79,034 28,128 23,495 83,784 301,041 28,165 48,627 28,128 23,495 83,784 212,199 Missouri 82,097 13,433 6,603 17,723 55,230 175,086 23,923 11,054 6,603 17,723 55,230 114,533 New Jersey 18,352 22,228 11,098 21,163 34,106 106,947 10,863 19,804 11,098 21,163 34,106 97,034 New York 39,199 25,791 15,587 29,260 80,521 190,358 30,273 24,128 15,587 29,260 80,521 179,769 North Carolina 84,815 34,027 10,651 17,799 66,019 213,311 31,394 25,984 10,651 17,799 66,019 151,847 Ohio 163,132 53,241 19,425 37,781 99,079 372,658 48,468 35,145 19,425 37,781 99,079 239,898 Pennsylvania 123,102 73,748 17,103 25,554 92,280 331,787 52,000 65,510 17,103 25,554 92,280 252,447 Rhode Island 1,082 327 420 2,073 4,375 8,277 1,118 327 420 2,073 4,375 8,313 South Carolina 36,299 34,740 8,359 11,903 47,404 138,705 16,290 25,469 8,359 11,903 47,404 109,425 Tennessee 70,908 60,004 11,990 44,567 64,965 252,434 25,386 35,568 11,990 44,567 64,965 182,476 Virginia 40,884 39,765 18,622 21,551 70,212 191,034 18,258 27,076 18,622 21,551 70,212 155,719 West Virginia 115,490 40,192 4,790 10,220 20,185 190,877 26,439 31,286 4,790 10,220 20,185 92,920 Wisconsin 51,962 22,796 8,160 12,965 49,470 145,353 17,972 17,973 8,160 12,965 49,470 106,540 Total 1,501,775 757,282 290,689 456,818 1,173,164 4,179,728 543,826 558,619 290,689 456,818 1,173,164 3,023,116 ------- This page intentionally left blank. ------- 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 receivedfrom 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 NOx SIP Call," Docket A-96-56, VI-B-09, September, 1998. Pechan, 1997a: E.H. Pechan & Associates, Inc., "Ozone Transport Assessment Group (OTAG) Emissions Inventory Development Report - Volume I: 1990 Base Year Development, " (revised draft) preparedfor 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) preparedfor 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) preparedfor U.S. Environmental Protection Agency, Office of Atmospheric Programs, September 1997. ------- 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 - 250 Ton PSD and NSPS - NSR in non-waived NAAs - CTG & Non-CTG VOC RACT at major sources in NAAs & OTR - New Source LAER - 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 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; FeedstockDesulfurization 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; CementKiln 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 ------- APPENDIX C SOURCE SPECIFIC EGU BASE AND BUDGET EMISSIONS FILE ------- Table C-l Regional NOx SIP Call EGU Point Source File File Format Filename: Description: Location: NFREGU.TXT Regional NOx SIP Call Base and Budget Determination EGU Point Source File ftp.epa.gov/pub/scram001/modelingcenter/budget/ Variable Type Length Decimal Description FIPSST C 2 0 FIPS State Code FIPSCNTY C 3 0 FIPS County Code ORISID C 6 0 ORIS ID Code PLANTID C 15 0 Plant ID Code PLANT C 35 0 Plant Name BLRID C 15 0 Boiler ID Code POINTID C 15 0 Point ID Code STACKID C 15 0 Stack ID Code SEGMENT C 15 0 Segement ID see C 10 0 Source Classification Code SIC N 4 0 Standard Industrial Classification Code HEAT RATE N 10 2 Heat Rate 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) LAT N 9 4 Latitude (degrees) LON N 9 4 Longitude (degrees) BOILCAP N 8 2 Boiler Capacity (MW) YEAR9596 N 4 0 Indicates 1995 or 1996 data used for Base File SHEAT95 N 15 1 1995 Ozone Season Heat Input (MMBtu) SHEAT96 N 15 1 1996 Ozone Season Heat Input (MMBtu) SHEAT9596 N 15 1 Base Ozone Season Heat Input (MMBtu) based on YEAR9596 DHEAT95 N 15 1 1995 Typical Ozone Season Daily Heat Input (MMBtu) DHEAT96 N 15 1 1996 Typical Ozone Season Daily Heat Input (MMBtu) DHEAT9596 N 15 1 Base Typical Ozone Season Daily Heat Input (MMBtu) based on YEAR9596 RATE95 N 15 5 1995 NOx Emission Rate (Ibs/MMBtu) RATE96 N 15 5 1996 NOx Emission Rate (Ibs/MMBtu) DN0X9596 N 11 5 Base Typical Ozone Season Daily NOx Emissions (tons) SN0X9596 N 11 5 Base Ozone Season NOx Emissions (tons) SNOX95 N 13 5 1995 Ozone Season NOx Emissions (tons) SVOC95 N 13 5 1995 Ozone Season VOC Emissions (tons) SC095 N 13 5 1995 Ozone Season CO Emissions (tons) SNOX96 N 13 5 1996 Ozone Season NOx Emissions (tons) SVOC96 N 13 5 1996 Ozone Season VOC Emissions (tons) SC096 N 13 5 1996 Ozone Season CO Emissions (tons) DNOX95 N 13 5 1995 Typical Ozone Season Daily NOx Emissions (tons) DVOC95 N 13 5 1995 Typical Ozone Season Daily VOC Emissions (tons) DC095 N 13 5 1995 Typical Ozone Season Daily CO Emissions (tons) DNOX96 N 13 5 1996 Typical Ozone Season Daily NOx Emissions (tons) DVOC96 N 13 5 1996 Typical Ozone Season Daily VOC Emissions (tons) DC096 N 13 5 1996 Typical Ozone Season Daily CO Emissions (tons) GRX07 N 5 3 IPM 2007 Projected Growth Rate DHEAT07 N 15 1 2007 Typical Ozone Season Daily Projected Heat Input (MMBtu) SHEAT07 N 15 1 2007 Ozone Season Projected Heat Input (MMBtu) DVOC07 N 13 5 2007 Typical Ozone Season Daily VOC Emissions (tons) DCO07 N 13 5 2007 Typical Ozone Season Daily CO Emissions (tons) SVOC07 N 13 5 2007 Ozone Season VOC Emissions (tons) SCO07 N 13 5 2007 Ozone Season CO Emissions (tons) BRATE07 N 15 5 2007 Budget NOx Emission Rate (Ibs/MMBtu) BDNOX07 N 13 5 2007 Typical Ozone Season Daily Budget NOx Emissions (tons) BSNOX07 N 13 5 2007 Ozone Season Budqet NOx Emissions (tons) ------- APPENDIX D SOURCE SPECIFIC NON-EGU POINT SOURCE BASE AND BUDGET EMISSIONS FILE ------- Table D-l Regional NOx SIP Call Non-EGU Point Source File File Format Filename: NFRPT.TXT Description: Regional NOx SIP Call Non-EGU Point Source File Location: ftp.epa.gov/pub/scram001/modelingcenter/budget/ 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 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 NEWSIZE 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 SPRTHRU 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 Weeks/Year SIC N 4 0 Standard Industrial Classification Code LATC N 9 4 Latitude (degrees) LONC N 9 4 Longitiude (degrees) NOXCE95 N 5 2 1995 NOx Control Efficiency COCE95 N 5 2 1995 CO Control Efficiency VOCCE95 N 5 2 1995 VOC Control Efficiency NOXRE95 N 5 2 1995 NOx Rule Effectiveness CORE95 N 5 2 1995 CO Rule Effectiveness VOCRE95 N 5 2 1995 VOC Rule Effectiveness DNOX95 N 16 4 1995 Typical Ozone Season Daily NOx Emissions (tons) DC095 N 16 4 1995 Typical Ozone Season Daily CO Emissions (tons) DVOC95 N 16 4 1995 Typical Ozone Season Daily VOC Emissions (tons) GF9507 N 7 2 1995 - 2007 Growth Factor THU NOX07 N 16 5 2007 Ozone Season Weekday NOx Emissions (tons) THU_CO07 N 16 5 2007 Ozone Season Weekday CO Emissions (tons) THU_VOC07 N 16 5 2007 Ozone Season Weekday VOC Emissions (tons) SAT_NOX07 N 16 5 2007 Ozone Season Saturday NOx Emissions (tons) SAT_CO07 N 16 5 2007 Ozone Season Saturday CO Emissions (tons) SAT_VOC07 N 16 5 2007 Ozone Season Saturday VOC Emissions (tons) SUN_NOX07 N 16 5 2007 Ozone Season Sunday NOx Emissions (tons) SUN_CO07 N 16 5 2007 Ozone Season Sunday CO Emissions (tons) SUN_VOC07 N 16 5 2007 Ozone Season Sunday VOC Emissions (tons) NOXRE07 N 5 2 2007 NOx Rule Effectiveness CORE07 N 5 2 2007 CO Rule Effectiveness VOCRE07 N 5 2 2007 VOC Rule Effectiveness NOXCE07 N 5 2 2007 Base NOx Control Efficiency COCE07 N 5 2 2007 Base CO Control Efficiency ------- Table D-l Regional NOx SIP Call Non-EGU Point Source File File Format Variable Type Length Decimal Description VOCCE07 N 5 2 2007 Base VOC Control Efficiency SNOX07 N 16 4 2007 Ozone Season Base NOx Emissions (tons) SCO07 N 16 4 2007 Ozone Season Base CO Emissions (tons) SVOC07 N 16 4 2007 Ozone Season Base VOC Emissions (tons) DNOX07 N 16 5 2007 Typical Ozone Season Daily NOx Emissions (tons) DCO07 N 16 5 2007 Typical Ozone Season Daily CO Emissions (tons) DVOC07 N 16 5 2007 Typical Ozone Season Daily VOC Emissions (tons) NOXCE07B N 5 2 2007 Budget NOx Control Efficiency SBNOX N 16 4 2007 Ozone Season Budget NOx Emissions (tons) DBNOX N 16 5 2007 Typical Ozone Season Daily Budget NOx Emissions (tons! ------- APPENDIX E COUNTY LEVEL STATIONARY AREA BASE AND BUDGET EMISSIONS FILE ------- Table E-l Regional NOx SIP Call Stationary Area Source File File Format Filename: NFRAR.TXT Description: Regional NOx SIP Call Stationary Area Source File Location: ftp.epa.gov/pub/scram001/modelingcenter/budget/ 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 NOX95 N 10 4 1995 Typical Ozone Season Daily NOx Emissions (tons) C095 N 10 4 1995 Typical Ozone Season Daily CO Emissions (tons) VOC95 N 10 4 1995 Typical Ozone Season Daily VOC Emissions (tons) GR9507 N 7 2 1995 - 2007 Growth Factor THU_NOX07 N 10 4 2007 Ozone Season Weekday NOx Emissions (tons) THU_CO07 N 10 4 2007 Ozone Season Weekday CO Emissions (tons) THU_VOC07 N 10 4 2007 Ozone Season Weekday VOC Emissions (tons) SAT_NOX07 N 10 4 2007 Ozone Season Saturday NOx Emissions (tons) SAT_CO07 N 10 4 2007 Ozone Season Saturday CO Emissions (tons) SAT_VOC07 N 10 4 2007 Ozone Season Saturday VOC Emissions (tons) SUN_NOX07 N 10 4 2007 Ozone Season Sunday NOx Emissions (tons) SUN_CO07 N 10 4 2007 Ozone Season Sunday CO Emissions (tons) SUN_VOC07 N 10 4 2007 Ozone Season Sunday VOC Emissions (tons) SNOX07 N 10 4 2007 Ozone Season NOx Emissions (tons) SCO07 N 10 4 2007 Ozone Season CO Emissions (tons) SVOC07 N 10 4 2007 Ozone Season VOC Emissions (tons) DNOX07 N 10 4 2007 Typical Ozone Season Daily NOx Emissions (tons) DCO07 N 10 4 2007 Typical Ozone Season Daily CO Emissions (tons) DVOC07 N 10 4 2007 Typical Ozone Season Daily VOC Emissions (tons) ------- APPENDIX F COUNTY LEVEL NONROAD MOBILE BASE AND BUDGET EMISSIONS ------- Table F-l Regional NOx SIP Call Nonroad Mobile Source File File Format Filename: NFRNR.TXT Description: Regional NOx SIP Call Nonroad Mobile Source File Location: ftp.epa.gov/pub/scram001/modelingcenter/budget/ 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 NOX95 N 10 4 1995 Typical Ozone Season Daily NOx Emissions (tons) C095 N 10 4 1995 Typical Ozone Season Daily CO Emissions (tons) VOC95 N 10 4 1995 Typical Ozone Season Daily VOC Emissions (tons) GR9507 N 7 2 1995 - 2007 Growth Factor THU_NOX07 N 10 4 2007 Ozone Season Weekday NOx Emissions (tons) THU_CO07 N 10 4 2007 Ozone Season Weekday CO Emissions (tons) THU_VOC07 N 10 4 2007 Ozone Season Weekday VOC Emissions (tons) SAT_NOX07 N 10 4 2007 Ozone Season Saturday NOx Emissions (tons) SAT_CO07 N 10 4 2007 Ozone Season Saturday CO Emissions (tons) SAT_VOC07 N 10 4 2007 Ozone Season Saturday VOC Emissions (tons) SUN_NOX07 N 10 4 2007 Ozone Season Sunday NOx Emissions (tons) SUN_CO07 N 10 4 2007 Ozone Season Sunday CO Emissions (tons) SUN_VOC07 N 10 4 2007 Ozone Season Sunday VOC Emissions (tons) SNOX07 N 10 4 2007 Ozone Season NOx Emissions (tons) SCO07 N 10 4 2007 Ozone Season CO Emissions (tons) SVOC07 N 10 4 2007 Ozone Season VOC Emissions (tons) DNOX07 N 10 4 2007 Typical Ozone Season Daily NOx Emissions (tons) DCO07 N 10 4 2007 Typical Ozone Season Daily CO Emissions (tons) DVOC07 N 10 4 2007 Typical Ozone Season Daily VOC Emissions (tons) ------- APPENDIX G COUNTY LEVEL HIGHWAY MOBILE BASE AND BUDGET EMISSIONS FILE ------- Table G-l Regional NOx SIP Call Highway Mobile Source File File Format Filename: NFRMB.TXT Description: Regional NOx SIP Call Highway Mobile Source File Location: ftp.epa.gov/pub/scram001/modelingcenter/budget/ Variable Tvoe Lenath Decimal Description FIPSST C 2 0 FIPS State Code FIPSCNTY C 3 0 FIPS County Code see c 10 0 Source Classification Code V TYPE c 5 0 Vehicle Type DVMT95 N 16 3 1995 Typical Ozone Season Daily Vehicle Miles Traveled (VMT) GR9507 N 5 3 1995 to 2007 VMT Growth Factor DVMT07 N 16 3 2007 Typical Ozone Season Daily VMT SVMT07 N 16 3 2007 Ozone Season VMT SNOX07 N 13 6 2007 Ozone Season NOx Emissions (tons) SCO07 N 13 6 2007 Ozone Season CO Emissions (tons) SVOC07 N 13 6 2007 Ozone Season VOC Emissions (tons) MAY VOC07 N 13 6 2007 May VOC Emissions (tons) JUN VOC07 N 13 6 2007 June VOC Emissions (tons) JUL VOC07 N 13 6 2007 July VOC Emissions (tons) AUG VOC07 N 13 6 2007 August VOC Emissions (tons) SEP VOC07 N 13 6 2007 September VOC Emissions (tons) MAY NOX07 N 13 6 2007 May NOx Emissions (tons) JUN NOX07 N 13 6 2007 June NOx Emissions (tons) JUL NOX07 N 13 6 2007 July NOx Emissions (tons) AUG NOX07 N 13 6 2007 August NOx Emissions (tons) SEP NOX07 N 13 6 2007 September NOx Emissions (tons) MAY CO07 N 13 6 2007 May CO Emissions (tons) JUN CO07 N 13 6 2007 June CO Emissions (tons) JUL CO07 N 13 6 2007 July CO Emissions (tons) AUG CO07 N 13 6 2007 August CO Emissions (tons) SEP CO07 N 13 6 2007 September CO Emissions (tons) MAY VMT07 N 16 3 2007 May VMT JUN VMT07 N 16 3 2007 June VMT JUL VMT07 N 16 3 2007 July VMT AUG VMT07 N 16 3 2007 August VMT SEP VMT07 N 16 3 2007 September VMT ------- |