1

Technical Support Document (TSD)

for the Cross-State Air Pollution Rule for the 2008 Ozone NAAQS

Docket ID No. EPA-HQ-OAR-2014-0289

Assessment of Non-EGU NOx Emission Controls, Cost of 

Controls, and Time for Compliance

U.S. Environmental Protection Agency

Office of Air and Radiation

October 2015
2

1 Introduction/Purpose

The purpose of this Technical Support Document (TSD) is to discuss the currently available 

information on emissions and control measures for sources of NOx other than electric 

generating units (EGUs). This information provides more detail about why EGUs are the 

focus of the proposed rulemaking, namely the uncertainty that exists regarding whether 

significant aggregate NOx mitigation is achievable from non-EGU point sources by the 2017

ozone season, and the fact that the limited available information points to an apparent 

scarcity of non-EGU reductions that could be accomplished in this timeframe.

Notwithstanding these conclusions as regards the 2017 ozone season, the EPA continues to 

assess the role of NOx emissions from non-EGU sources to downwind nonattainment 

problems, and welcomes comments on the information in this TSD both as it relates to the 

current rule and for future use.

This TSD begins by briefly discussing the non-EGU emissions inventories used in this 

proposed rule, both for the 2011 base year and 2017 future baseline assessed for this 

proposed rule. The TSD then presents an evaluation of whether non-EGU emissions can be 

reduced in a cost-effective manner for particular categories. Then, it assesses the available 

NOx emission reductions from such categories and presents the category-by-category 

emissions reduction potential. This assessment considers and presents the costs per ton of 

these reductions, with a focus on technologies that achieve cost-effective reductions within 

a range of costs similar to that evaluated for EGUs. Finally, the TSD presents estimates of 

the time required to install and implement the control measures, both for comparison to 

the 2017 compliance timeframe, and for discussion of installation time should such 

measures be required in the future. 

For the reasons stated in the preamble, the data and discussion in this TSD are intended to 

focus on the eastern states that are the focus of the Cross-State Air Pollution Rule (CSAPR).

Information inclusive of western states1 is presented where available and appropriate.

 

1 For the purpose of this action, the western U.S. (or the West) consists of the 11 western contiguous states of Arizona, 

California, Colorado, Idaho, Montana, New Mexico, Nevada, Oregon, Utah, Washington, and Wyoming.
3

2 Background

In this section we present annual and ozone-season NOx emission inventory totals and the 

relative percentages for non-EGU source categories statewide and/or nationally. This 

information is summary in nature and is not meant to replace other, more detailed

information available from the EPA, such as the EPA’s 2011v6.2 Emissions Modeling 

Platform TSD2 as well as the Notice of Data Availability3 (NODA) and Regulatory Impact 

Analysis4 (RIA) for this proposed rulemaking.

Table 1 lists 2011 and 2017 projected NOx emissions by sector, in summary form, for the 

48 contiguous states of the U.S. (CONUS).

Table 1: 2011 Base Year and 2017 Projected NOx Emissions by 

Sector (tons), for the 48 CONUS

Sector 2011 NOx, 

annual

2017 NOx, 

annual

2011 NOx, ozone 

season

2017 NOx, ozone 

season

EGU-point 2,000,000 1,500,000 942,000 689,000

NonEGU-point 1,200,000 1,200,000 515,000 502,000

Point oil and gas 500,000 410,000 213,000 172,000

Wild and prescribed fires 330,000 330,000 165,000 165,000

Nonpoint oil and gas 650,000 690,000 275,000 293,000

Residential wood 

combustion 34,000 35,000 3,000 3,000

Other nonpoint 760,000 730,000 204,000 211,000

Nonroad 1,600,000 1,100,000 825,000 582,000

Onroad 5,700,000 3,200,000 2,417,000 1,329,000

C3 Commercial marine 

vessel (CMV) 130,000 130,000 58,000 58,000

Locomotive and C1/C2 

CMV 1,100,000 910,000 451,000 384,000

Biogenics 1,000,000 1,000,000 630,000 630,000

TOTAL 15,000,000 11,200,000 6,698,000 5,018,000

It is clear from Table 1 that NOx emissions are projected to remain constant or decrease for 

most sectors in the 48 states between 2011 and 2017. Emissions from the non-EGU point 

source sector and the other nonpoint source sector are not projected to change

significantly, while emissions from the nonpoint oil and gas source sector are projected to 

grow (approximately 6%), during this time period. Based on the values in Table 1, Figures 

 

2 Technical Support Document (TSD), Preparation of Emissions Inventories for the Version 6.2, 2011 Emissions Modeling 

Platform, August 2015, available at: 

http://www3.epa.gov/ttn/chief/emch/2011v6/2011v6_2_2017_2025_EmisMod_TSD_aug2015.pdf

3 Notice of Availability of the Environmental Protection Agency’s Updated Ozone Transport Modeling Data for the 2008 

Ozone National Ambient Air Quality Standard (NAAQS). The official version is available in the docket for this proposed 

rulemaking.

4 Regulatory Impact Analysis for the Proposed Cross-State Air Pollution Rule (CSAPR) for the 2008 Ozone National 

Ambient Air Quality Standards (NAAQS). The official version is available in the docket for this proposed rulemaking.
4

1 and 2 show the relative contributions of the various sectors to overall NOx emissions (left 

panel) and for the non-EGU sectors (right panel) for 2011 and 2017, respectively.

Figure 1: 2011 NOx emissions by sector, with further non-EGU

breakout (48 states)

Figure 2: Projected 2017 NOx emissions by sector, with further 

non-EGU breakout (48 states)

13%

16%

2%

0%

60%

9%

2011 v2 NEI - NOx by Sector

(TOTAL 6.7M os TONS)

EGU

Non-EGU total

Fires

Residential wood

Mobile

Biogenics

42%

15%

25%

18%

2011 V2 NEI - NOx IN 

NON-EGU SECTOR

Non-EGU

point

Point oil &

gas

Nonpoint oil

& gas

Other

nonpoint

12%

21%

3%

0%

53%

11%

2017 PROJECTIONS - NOx BY 

SECTOR 

(TOTAL 5.0M os TONS)

EGU

Non-EGU total

Fires

Residential wood

Mobile

Biogenics

42%

18%

23%

17%

2017 PROJECTION -

NOx IN NON-EGU 

SECTOR

Non-EGU

point

Point oil &

gas

Nonpoint oil

& gas

Other

nonpoint
5

Figure 1 depicts total ozone season NOx emissions of 6,698,000 tons in 2011 and Figure 2 

depicts total ozone season NOx emissions of 5,018,000 tons in 2017. In both 2011 and 

2017, the mobile source sector has the largest NOx emissions. Substantial reductions in 

mobile source NOx are projected to occur by 2017. Mobile sources are projected to 

decrease because of sector-specific standards related to fuels, fuel economy, pollution 

controls, and repair and replacement of the existing fleet. Because these reductions are 

already expected to occur, mobile source emission reductions are not included in this 

analysis of non-EGU emission reductions achievable by the 2017 ozone season. 

For the purposes of preliminary analysis in this TSD, “non-EGU total” refers to four 

separate categories of sources: non-EGU point, point oil and gas, nonpoint oil and gas, and 

other nonpoint (and does not include mobile sources). The oil and gas point and nonpoint 

sources are separated from the remaining non-EGU point and nonpoint sources due to the 

magnitude of their contribution to the inventory and other aspects related to the inventory 

development, emissions modeling, and future year projections for that industry. The point 

oil and gas sources are also separated out from the other non-EGU point sources according 

to the NAICS code specified for the various sources. Note that point oil and gas sources 

include a variety of types of processes, and there is overlap with the processes included in 

the rest of the non-EGU point inventory. More information on the emissions sectors is 

available in the 2011v6.2 Emissions Modeling Platform TSD.

Comparing the proportions of the total inventory for non-EGUs (Figures 1 and 2), it 

becomes clear that, although they are decreasing in the absolute sense, non-EGU NOx 

emissions are becoming a larger share of overall ozone-season NOx emissions (16% in 

2011 compared with 21% in 2017).

Table 2 compares statewide projected total anthropogenic NOx emissions (inclusive of all 

sectors listed in Table 1 with the exception of fires and biogenics) for the 2017 ozone 

season to non-EGU NOx emissions for the 2017 ozone season for each of the 48 contiguous 

states of the U.S. Totals are given for the 48 contiguous United States (the 37 eastern states 

plus D.C. that are addressed in the proposed rulemaking are highlighted below in blue).

Non-EGU sources in this table are broken down into two groups (non-EGU point sources,

including point oil & gas sources, and other nonpoint and nonpoint oil & gas sources).
6

Table 2: Projected Total Anthropogenic Ozone-Season NOx 

Emissions vs. Projected Non-EGU Source Group NOx Emissions, 

2017 Projections, Tons5

State

Total 

Anthropogenic

Non-EGU 

Point + Oil & 

Gas Point

% 

Anthro

Oil & Gas 

Nonpoint+ Other 

Nonpoint

% 

Anthro

Oil & Gas 

Point + Oil 

& Gas

Nonpoint

% 

Anthro

Alabama 88,805 22,187 25 7,952 9 7,442 8

Arizona 71,906 5,015 7 2,310 3 612 1

Arkansas 69,737 13,400 19 5,308 8 9,164 13

California 236,322 29,342 12 20,220 9 3,105 1

Colorado 90,756 19,594 22 16,899 19 27,284 30

Connecticut 17,672 1,105 6 2,626 15 98 1

Delaware 7,786 628 8 615 8 0 0

District of 

Columbia 2,252 212 9 312 14 0 0

Florida 177,514 16,293 9 7,543 4 1,112 1

Georgia 103,536 18,816 18 4,559 4 1,495 1

Idaho 27,893 3,752 13 1,989 7 503 2

Illinois 148,178 24,668 17 15,409 10 9,424 6

Indiana 139,133 27,222 20 6,864 5 5,931 4

Iowa 70,467 7,888 11 3,861 5 153 0

Kansas 79,939 6,968 9 12,619 16 10,697 13

Kentucky 106,830 11,456 11 11,905 11 12,251 11

Louisiana 173,330 45,506 26 30,160 17 31,503 18

Maine 17,576 4,639 26 809 5 26 0

Maryland 46,029 6,213 13 3,508 8 522 1

Massachusetts 35,369 4,144 12 4,807 14 105 0

Michigan 131,486 21,867 17 12,245 9 9,398 7

Minnesota 89,328 15,541 17 6,414 7 46 0

Mississippi 54,832 11,684 21 2,122 4 6,557 12

Missouri 101,035 9,238 9 3,594 4 122 0

Montana 38,504 2,948 8 3,630 9 3,390 9

Nebraska 70,005 3,884 6 1,163 2 467 1

Nevada 28,192 4,018 14 1,003 4 115 0

New Hampshire 8,932 680 8 1,028 12 0 0

New Jersey 52,743 4,544 9 5,506 10 173 0

New Mexico 65,263 10,559 16 19,940 31 27,759 43

New York 109,910 13,738 12 14,624 13 904 1

North Carolina 98,064 15,711 16 3,657 4 1,203 1

North Dakota 74,118 4,047 5 18,125 24 19,185 26

Ohio 160,110 21,280 13 11,617 7 2,906 2

Oklahoma 131,763 32,203 24 33,178 25 51,257 39

Oregon 40,507 6,130 15 4,348 11 365 1

Pennsylvania 174,664 23,735 14 33,508 19 26,713 15

 

5 EGUs are not provided a separate breakout in Table 2 since state-level emissions are presented in the emissions 

modeling platform TSD and other TSDs for this proposal.
7

State

Total 

Anthropogenic

Non-EGU 

Point + Oil & 

Gas Point

% 

Anthro

Oil & Gas 

Nonpoint+ Other 

Nonpoint

% 

Anthro

Oil & Gas 

Point + Oil 

& Gas

Nonpoint

% 

Anthro

Rhode Island 5,845 544 9 1,370 23 12 0

South Carolina 55,897 10,144 18 3,980 7 348 1

South Dakota 22,192 1,241 6 432 2 75 0

Tennessee 85,759 13,494 16 5,846 7 1,922 2

Texas 467,245 95,671 20 115,180 25 145,285 31

Tribal Data 26,717 3,799 14 0 0 3,700 14

Utah 66,486 8,004 12 9,781 15 9,349 14

Vermont 5,473 163 3 937 17 0 0

Virginia 87,754 14,039 16 7,318 8 4,775 5

Washington 75,833 8,666 11 1,150 2 164 0

West Virginia 64,839 9,678 15 12,642 19 16,723 26

Wisconsin 75,047 11,181 15 5,351 7 178 0

Wyoming 68,864 26,488 38 4,018 6 10,905 16

Eastern States 3,411,193 545,649 16 418,692 12 378,171 11

US Total 4,248,436 673,964 16 503,980 12 465,421 11

Table 2 indicates that, in the projected 2017 inventory, non-EGU sources comprising nonEGU point and point oil and gas sources are estimated to make up 16% of anthropogenic 

NOx emissions in the 48 contiguous United States. In individual states, the percentage of 

anthropogenic emissions contributed by these two non-EGUs categories range from 3% to 

26% (eastern states) and from 7% to 38% (western states).

We also note that in the projected 2017 inventory, non-EGU sources comprising nonpoint 

oil & gas and other nonpoint sources are estimated to make up 12% of anthropogenic NOx 

emissions in the entire continental U.S. In individual states, the percentage of 

anthropogenic emissions contributed by these non-EGUs ranges from 2% to 25% (eastern 

states) and from 4% to 31% (western states). 

The EPA’s preliminary analysis indicates that NOx emissions from oil and gas sources

(inclusive of emissions from the point oil and gas and nonpoint oil and gas sectors) 

comprise an average of 11% of the total ozone season NOx emissions inventory. For some

states, this percentage increases up to 43%, with oil and gas emissions exceeding non-EGU 

point totals in a number of states. The key sources of NOx emissions in the oil and gas 

sector are from the combustion of fossil fuel (primarily drilling rigs, internal combustion 

(IC) engines and pipeline compressors) and flares. Please refer to the EPA’s 2011v6.2

Emissions Modeling Platform TSD for more information on emissions from these sectors.

3 Preliminary Analysis

For the purposes of this proposed rule, the EPA performed a preliminary analysis to 

characterize whether there are non-EGU source groups with a substantial amount of 

available cost-effective NOx reductions achievable by the 2017 ozone season.
8

3.1 Methodology

The EPA’s preliminary analysis of potential non-EGU NOx emission reductions was 

performed using the Control Strategy Tool (CoST). CoST is the software tool the EPA uses 

to estimate the emission reductions and costs associated with future-year control 

strategies, and then to generate emission inventories that result from the control strategies 

applied. CoST tracks information about control measures, their costs, and the types of 

emissions sources to which they apply. The purpose of CoST is to support national- and 

regional-scale multi-pollutant analyses, primarily for Regulatory Impact Analyses (RIAs) of 

the National Ambient Air Quality Standards (NAAQS). CoST is also a component of the 

Emissions Modeling Framework (EMF) that was used to generate the 2017 non-EGU 

emissions presented above and in the Emissions Modeling Platform TSD for this proposal. 

Further discussion and documentation of CoST is available on the EPA’s website at 

http://www.epa.gov/ttnecas1/cost.htm.

Appendices to this TSD discuss recommendations for updates to CoST, including 

corrections for inapplicable controls, sources already controlled by state rules, sources 

with permit limits or that clearly identified controls in place, and sources subject to future 

NOx emission limits. Appendix A summaries RTI’s work to review estimates for lean burn

IC engines, glass manufacturing, ammonia reformers, and gas turbines.

6 Appendix B 

discusses SRA’s work on a variety of other categories including many of the others 

evaluated in this TSD.7

It should be noted that all of the NOx measures included in this report are currently in the 

Control Measure Data Base (CMDB) used by CoST, and do not reflect the updates suggested 

in these contractor reports. Obstacles to full incorporation of the recommended changes 

include availability of accurate costs for these measures, and to have cost equations rather 

than average cost/ton to estimate costs. Control efficiencies are readily available for 

measures, but costs, particularly those that can be estimated using equations that consider 

source size or capacity, often are not. The EPA plans to incorporate these recommendations 

for changes or additions to the NOx controls for non-EGUs to support NOx control efforts 

for future rules and other efforts. Nonetheless, the information from these reports helped 

inform our assessment in terms of uncertainty surrounding non-EGU emission reduction 

potential. Further details on the CMDB can be found on the CoST web site.

For the purpose of identifying a list of non-EGU NOx source groups with controls available, 

the EPA ran CoST including non-EGU sources for the 37 eastern U.S. with NOx emissions of 

greater than 25 tons/year in 2017. These reports are included in the Appendices of this 

TSD. Through a contractual agreement with EPA, SRA International and RTI International 

provided reports which CoST examined a number of source categories of non-EGUs with

control costs up to $10,000 per ton (in 2011 dollars). CoST selected particular control 

 

6 “Update of NOx Control Measure Data in the CoST Control Measure Database for Four Industrial Source Categories: 

Ammonia Reformers, NonEGU Combustion Turbines, Glass Manufacturing, and Lean Burn Reciprocating Internal 

Combustion Engines,” Revised Draft Report, RTI International, 2014.

7 “Review of CoST Model Emission Reduction Estimates,” SRA International, 2014; “Summary of State NOx Regulations for 

Selected Stationary Sources,” SRA International, 2014.
9

technologies based on application of a least-cost criterion for control measures applied as 

part of control strategy. Other NOx control measures are available for some of these 

categories, but on average annualized costs for these measures were at higher cost. 

3.2 Uncertainties and Limitations

The EPA acknowledges several important limitations of the non-EGU cost analysis included 

in this TSD, which include the following: 

Boundary of the cost analysis: In this engineering cost analysis we include only the impacts 

to the regulated industry, such as the costs for purchase, installation, operation, and 

maintenance of control equipment over the lifetime of the equipment. Recordkeeping, 

reporting, testing and monitoring costs are not included. Additional profit or income may 

be generated by industries supplying the regulated industry, especially for control 

equipment manufacturers, distributors, or service providers. These types of secondary 

impacts are not included in this cost analysis. 

Cost and effectiveness of control measures: Our application of control measures reflect 

nationwide average retrofit factors and equipment lives. We do not account for regional or 

local variation in capital and annual cost items such as energy, labor, materials, and others. 

Our estimates of control measure costs may over- or under-estimate the costs depending 

on how the difficulty of actual retrofitting and equipment life compares with our control 

assumptions. In addition, our estimates of control efficiencies for control measures 

included in our analysis assume that the control devices are properly installed and 

maintained. There is also variability in scale of application that is difficult to reflect for 

small area sources of emissions. 

Discount (Interest) rate: Because we obtain control cost data from many sources, we are 

not always able to obtain consistent data across original data sources. If disaggregated 

control cost data are not available (i.e., where capital, equipment life value, and operation 

and maintenance [O&M] costs are not shown separately), the EPA assumes that the 

estimated control costs are annualized using a 7 percent discount rate, which is the 

discount (interest) rate used in accordance with OMB guidance in Circular A-94. In general, 

we have some disaggregated data available for non-EGU point source controls. In addition, 

while these interest rates are consistent with OMB guidance, the actual interest rates may 

vary regionally or locally. 

Accuracy of control costs: We estimate that there is an accuracy range of +/- 30 percent for 

non-EGU point source control costs. This level of accuracy is described in the EPA Air 

Pollution Control Cost Manual, which is a basis for the estimation of non-EGU control cost 

estimates included in this TSD. This level of accuracy is consistent with either the budget or 

bid/tender level of cost estimation as defined by the AACE International. 
10

3.3 CoST Results

The results of the CoST analysis are displayed in Table 3. In this table, we display the 

source groups selected by CoST, the Source Classification Codes (SCCs) included in those 

groups8, the least-cost control technology for a given source group (also selected by CoST), 

the current estimate (in dollars per ton, using 2011 dollars) of the annualized cost per ton 

NOx reduced of the control technology, the current estimate of the time necessary to install 

the selected control technology (not including permitting time), the estimated ozone 

season emissions in the East from the non-EGU source group in 2017 in the absence of the 

installation of the selected controls, and the estimated potential ozone season reductions in 

the East from the non-EGU source group in 2017 assuming the selected controls could be

fully installed and operational prior to the 2017 ozone season (which as discussed in more 

detail later, is not the case for many of the categories examined). Note that CoST does not 

account for installation time or time required for the permitting process. Instead it 

provides information on the control measures applicable to sources in the inventory, along 

with the cost of installation and operation of the selected measures.

 

 

8 The CoST results do not indicate applicability of the recommended control technology to all sources in the source group

but only to the specific SCCs for which control technologies are applicable. For example, for the cement kilns source 

group, BSI is applicable only for the types of cement kilns covered by the listed SCCs.
11

Table 3: CoST Results: Non-EGU Source Groups with NOx Reductions 

 

9 Time to install is not an output of CoST, but are rather estimates determined by EPA based on research from a variety of sources. See “Typical Installation Timelines for 

NOx Emissions Control Technologies on Industrial Sources,” Institute of Clean Air Companies, December 2006 (all sources except cement kilns and RICE), “Cement Kilns 

Technical Support Document for the NOx FIP,” EPA, January 2001 (cement kilns), and “Availability and Limitations of NOx Emission Control Resources for Natural GasFired Reciprocating Engine Prime Movers Used in the Interstate Natural Gas Transmission Industry,” Innovative Environmental Solutions Inc., July 2014 (prepared for 

the INGAA Foundation).

10 In general, for control retrofits to non-EGU sectors, it appears that the full sector-wide compliance time is uncertain, but is longer than the installation time shown 

above for a typical unit. We have insufficient information on capacity and experience within the OEM suppliers and major engineering firms supply chain to offer 

conclusions on their availability to execute the project work for non-EGU sectors.

11 Non-EGUs of any type – boiler or turbine – that are not currently required to monitor and report in accordance with 40 CFR Part 75 and/or not currently participating 

in the existing CSAPR program will require additional time relative to EGUs that are currently equipped with Part 75 monitoring and reporting and/or participating in 

the current CSAPR program. Installation of NOx monitors for the reporting of NOx mass requires the construction of platforms, CEM shelters, procurement of 

equipment, certification testing, and electronic data reporting programming of a data handling system. These added timing considerations for infrastructure on the nonEGU sources combined with the additional programmatic adoption measures necessary make installation of controls by the 2017 timeframe established in this rule less 

likely and more uncertain for industrial sources.

12 Emissions and potential reductions for Gas Turbines ($163/ton grouping), Cement Kiln/Dryer (Bituminous Coal) ($942/ton grouping), Coal Cleaning – Thermal Dryer 

(2), Spreader Strokers, Petroleum Refinery Process Heaters, Incinerators, Boilers & Process Heaters, Gas-Fired Process Heaters, Coal Boilers, By-Product Coke 

Manufacturing, ICI Boilers – Residual Oil, Ammonia Production, Glass Manufacturing, ICI Boilers, Iron & Steel - In-Process Combustion - Bituminous Coal, Industrial 

Processes Miscellaneous, Catalytic Cracking, Process Heaters, & Coke Ovens, Petroleum Refinery Gas-Fired Process Heaters, Glass Manufacturing – Pressed, Glass 

Manufacturing – Container, Petroleum Refinery Gas-Fired Process Heaters, and RICE source groups were calculated for 2018, however they are likely to be virtually 

identical to projections for 2017. Non-EGU source groups with projected aggregate 2017 NOx emissions below 100 OS tons are excluded from this table.

13 Potential reductions assume fully implemented controls by the start of the 2017 ozone season.

Non-EGU Source 

Group

SCCs Control 

Technology

Recommended 

by CoST

Current 

estimate of 

NOx $/ton, 

CoST (2011 $)

Time to install9

10(excluding 

permitting, reporting 

preparation, 

programmatic and 

administrative 

considerations11)

201712

NOx 

Emissions 

(37 States 

+ DC), OS 

tons, CoST

2017 Potential 

Reductions13 (37 

States + DC), OS 

tons, CoST

Cement Kilns 30500622 (preheater kiln), 30500623 

(preheater/precalciner); 39000201 

(kiln/dryer); 39000288 (kiln in process 

coal)

Biosolid 

Injection 

Technology 

(BSI)

$410 Uncertain 24,760 4,207

Cement Mfg (dry) 30500606 Industrial Processes, Mineral 

Products, Cement Manufacturing (Dry 

Process), Kilns

Selective NonCatalytic 

Reduction 

(SNCR)

$1,255 42-51 weeks 13,006 6,501

Cement Mfg (wet) 30500706 Industrial processes, mineral 

products, Cement Manufacturing (Wet 

Process), Kilns

Mid-Kiln Firing $73 5-7 months 7,971 2,287
12

Coal Cleaning –

Thermal Dryer (1)

30502508 Construction Sand & Gravel, 

Dryer; 30501001 Industrial Processes, 

Mineral Products, Coal Mining, Cleaning, 

and Material Handling, Fluidized Bed 

Reactor

Low NOx Burner 

(LNB)

$1,125 6-8 months 503 165

Coal Cleaning –

Thermal Dryer (2)

30501001 Industrial Processes, Mineral 

Products, Coal Mining, Cleaning, and 

Material Handling, Fluidized Bed Reactor

Low NOx Burner 

(LNB)

$1,640 6-8 months 154 63

Cement 

Kiln/Dryer 

(Bituminous Coal)

39000201 Industrial Processes, In-process 

Fuel Use, Bituminous Coal, Cement 

Kiln/Dryer (Bituminous Coal)

SNCR $942 42-51 weeks 520 260

Iron and Steel 

Mills - Reheating

30300934 (303015) Primary Metal 

Production: Steel; 30300933

Low NOx Burner 

(LNB) & Flue 

Gas 

Recirculation 

(FGR)

$620 6-8 months 1,064 664

Steel Production 30490033 Industrial Processes, 

Secondary Metal Production, Fuel Fired 

Equipment, Natural Gas: Furnaces; 

30400704 Industrial Processes, 

Secondary Metal Production, Steel 

Foundries, Heat Treating Furnace

Low NOx Burner 

(LNB)

$928 6-8 months 281 141

Nitric Acid Mfg 30101301 Chemical Manufacturing, 

Nitric Acid, Absorber Tail Gas (Pre-1970 

Facilities); 30101302 Chemical 

Manufacturing, Nitric Acid, Absorber 

Tail Gas (Post-1970 Facilities)

NSCR $900 6-14 weeks 1,290 724

Petroleum 

Refinery Process 

Heaters

30600106 Industrial Processes, Petroleum 

Industry, Process Heaters, Process Gasfired

SCR-95% $940-$1101 28-58 weeks 179 177

Gas Turbines 20200201 Natural Gas, Turbine; 20200203 

Natural Gas, Turbine: Cogeneration; 

20300202 Natural Gas, Turbine

Low NOx Burner 

(LNB)

$163 12 months 945 793

Gas Turbines 20200201 Natural Gas, Turbine; 

20200203 Natural Gas, Turbine: 

Cogeneration; 20300202 Natural Gas, 

Turbine; 20300203 Natural Gas, 

Turbine: Cogeneration

Low NOx Burner 

(LNB)

$800 6-8 months 16,036 4,713

Natural Gas RICE 

Pipeline 

Compressors

20200202 Internal Combustion Engines, 

Industrial, Natural Gas, Reciprocating

Adjust Air to 

Fuel Ratio and 

Ignition Retard

$249 Uncertain 10,099 2,958
13

Natural Gas RICE 

Miscellaneous

20100202 Internal Combustion Engines, 

Electric Generation, Natural Gas, 

Reciprocating; 20200202 Internal 

Combustion Engines, Industrial, Natural 

Gas, Reciprocating; 20200204, Internal 

Combustion Engines, Industrial, Natural 

Gas, Reciprocating: Cogeneration; 

20300201, Internal Combustion 

Engines, Commercial/Institutional, 

Natural Gas, Reciprocating

Adjust Air to 

Fuel Ratio and 

Ignition Retard

$447 Uncertain 27,600 8,085

Natural Gas RICE 

Pipeline 

Compressors, 

Rich Burn

20200253 Internal Combustion Engines, 

Industrial, Natural Gas, 4-cycle Rich 

Burn

NSCR $517 Uncertain 11,758 10,571

Natural Gas RICE 

Pipeline 

Compressors, 

Lean Burn / Clean 

Burn

20200252 Internal Combustion Engines, 

Industrial, Natural Gas, 2-cycle Lean 

Burn; 20200254 Internal Combustion 

Engines, Industrial, Natural Gas, 4-cycle 

Lean Burn; 20200255 Internal 

Combustion Engines, Industrial, Natural 

Gas, 2-cycle Clean Burn; 20200256 

Internal Combustion Engines, Industrial, 

Natural Gas, 4-cycle Clean Burn

Low Emission 

Combustion 

(LEC)

$649 Uncertain 47,321 41,169

Diesel / Dual Fuel 

RICE

20200401 Internal Combustion Engines, 

Industrial, Large Bore Engine, Diesel; 

20200402 Internal Combustion Engines, 

Industrial, Large Bore Engine, Dual Fuel 

(Oil/Gas)

Ignition Retard $1,255 Uncertain 865 216

Catalytic Cracking 

(1)

30600201 Industrial Processes, Petroleum 

Industry, Catalytic Cracking Units, Fluid 

Catalytic Cracking Unit

Low NOx Burner 

(LNB) & Flue 

Gas Recirculation 

(FGR)

$1,375 6-8 months 255 140

Spreader 

Strokers

10100204 External Combustion Boilers, 

Electric Generation, 

Bituminous/Subbituminous Coal, 

Spreader Stroker (Bituminous Coal)

SNCR $1,390 42-51 weeks 394 158

Petroleum 

Refinery Process 

Heaters

30600106 Industrial Processes, Petroleum 

Industry, Process Heaters, Process Gasfired

SCR-95% $1,406-$1,501 28-58 weeks 161 157
14

Incinerators 50200102, 50200103, 50200104, 

50200504, 30190013, 30190014, 

50300101, 50300106, 50300112, 

50300113, 50300501, 50300503, 

50300504, 50300599, 50100101, 

50100102,

50100103, 50100506, 50100515, 

50100516, 39990024 Incineration

SNCR $1,842 42-51 weeks 6,556 2,950

Boilers & Process 

Heaters

10200203, 10200217, 10300216, 

10200204, 10200205, 10300207, 

10300209, 10200799 External Combustion 

Boilers; 30190002, 30600103 Industrial 

Process Heaters

SCR $2,235 28-58 weeks 13,146 10,358

Natural Gas RICE 

Electric 

Generation

20100206 Internal Combustion Engines, 

Electric Generation, Natural Gas, 

Reciprocating: Evaporative Losses (Fuel 

Delivery System)

Adjust Air to 

Fuel Ratio and 

Ignition Retard

$2,347 Uncertain 107 32

Catalytic Cracking 

(2)

30600201 Industrial Processes, Petroleum 

Industry, Catalytic Cracking Units, Fluid 

Catalytic Cracking Unit; 30600202 

Industrial Processes, Petroleum Industry, 

Catalytic Cracking Units, Catalyst 

Handling System

Low NOx Burner 

(LNB) & Flue 

Gas Recirculation 

(FGR)

$2,369 6-8 months 274 97

Gas-Fired Process 

Heaters (1)

30600104 Industrial Processes, Petroleum 

Industry, Process Heaters, Gas-fired

SCR-95% $2,376 28-58 weeks 211 204

Coal Boilers 10200206, 10200224, 10200225, 

10300102, 10300208, 10300224, 

10300225

SNCR $2,413 42-51 weeks 1099 495

Gas-Fired Process 

Heaters (2)

30600104 Industrial Processes, Petroleum 

Industry, Process Heaters, Gas Fired

Ultra-Low NOx 

Burners

$2,419-$2,638 6-8 months 137 64

By-Product Coke 

Manufacturing

30300306 Industrial Processes, Primary 

Metal Production, By-Product Coke 

Manufacturing, Oven Underfiring

SNCR $2,673 42-51 weeks 2,366 1,420

ICI Boilers –

Residual Oil

10200401, 10200402, 10200404, 

10300401, 10300402 External Combustion 

Boilers, Residual Oil

LNB & SNCR $2,850 6-8 months 991 689

Ammonia 

Production

30100306 Industrial Processes, Chemical 

Manufacturing, Ammonia Production, 

Primary Reformer: Natural Gas Fired

SCR $2,896 28-58 weeks 2,508 2,257

Glass 

Manufacturing -

Flat

30501403 Industrial Processes, Mineral 

Products, Glass Manufacture, Flat Glass: 

Melting Furnace

OXY-Firing $3,097 Uncertain 9,721 7,880
15

ICI Boilers 10200201, 10200202, 10200212, 

10300205, 10200501, 10200504, 

10200601, 10200602, 10200603, 

10200604, 10201401, 10300601, 

10300602, 10200701, 10200704, 

10200707, 10201402 External Combustion 

Boilers

Low NOx Burner 

& SCR

$3,456 6-8 months (LNB)

28-58 weeks (SCR)

31,005 28,204

Iron & Steel - InProcess 

Combustion - 

Bituminous Coal

30300819, 30300824, 30300913, 

30300914, 30301522 Industrial Processes, 

Primary Metal Production

SCR $3,705 28-58 weeks 829 746

Diesel RICE 

Miscellaneous

20100102 Internal Combustion Engines, 

Electric Generation, Distillate Oil 

(Diesel), Reciprocating; 20100107 

Internal Combustion Engines, Electric 

Generation, Distillate Oil (Diesel), 

Reciprocating: Exhaust; 20200102 

Internal Combustion Engines, Industrial, 

Distillate Oil (Diesel), Reciprocating;

20200106 Internal Combustion Engines, 

Industrial, Distillate Oil (Diesel), 

Reciprocating: Evaporative Losses (Fuel 

Storage and Delivery System);

20200107 Internal Combustion Engines, 

Industrial, Distillate Oil (Diesel), 

Reciprocating: Exhaust;

20300101 Internal Combustion Engines, 

Commercial/Institutional, Distillate Oil 

(Diesel), Reciprocating;

20400403 Internal Combustion Engines, 

Engine Testing, Reciprocating Engine, 

Distillate Oil

SCR $3,814 28-58 weeks 1,091 869

Catalytic 

Cracking, Process 

Heaters, & Coke 

Ovens

30600201, 30390004, 39000701, 

39000702, 39000797

LNB & FGR $5,199 6-8 months 1,989 1,094

Petroleum 

Refinery GasFired Process 

Heaters (3)

30600104 Industrial Processes, Petroleum 

Industry, Process Heaters, Gas-fired, 

30600106 Industrial Processes, Petroleum 

Industry, Process Heaters, Process Gasfired

SCR-95% $8,885-$9,140 28-58 weeks 370 316

Glass 

Manufacturing -

Pressed

30501404 Industrial Processes, Mineral 

Products, Glass Manufacture, Pressed and 

Blown Glass: Melting Furnace

OXY-Firing $6,356 Uncertain 1,001 851
16

Petroleum 

Refinery GasFired Process 

Heaters (2)

30600104 Industrial Processes, 

Petroleum Industry, Process Heaters, 

Gas-fired, 30600106 Industrial 

Processes, Petroleum Industry, Process 

Heaters, Process Gas-fired 

SCR-95% $7,533-$8,120 28-58 weeks 362 304

Industrial 

Processes 

Miscellaneous

30600201 Industrial Processes, 

Petroleum Industry, Catalytic Cracking 

Units, Fluid Catalytic Cracking Unit; 

39000701 Industrial Processes, Inprocess Fuel Use, Process Gas, Coke 

Oven or Blast Furnace

LNB & FGR $4,026 6-8 months 871 479

Glass 

Manufacturing -

Container

30501402 Industrial Processes, Mineral 

Products, Glass Manufacture, Container 

Glass: Melting Furnace

OXY-Firing $7,481 Uncertain 3,107 2,628

Petroleum 

Refinery GasFired Process 

Heaters (1)

30600104 Industrial Processes, 

Petroleum Industry, Process Heaters, 

Gas-fired; 30600106 Industrial 

Processes, Petroleum Industry, Process 

Heaters, Process Gas-fired

SCR-95% $5,609-$5,884 28-58 weeks 372 338

Taconite Ore 

Processing

30302351, 30302352, 30302359 

Industrial Processes, Primary Metal 

Production, Taconite Ore Processing, 

Induration

SCR $6,449 28-58 weeks 1,188 991

Diesel RICE 

Electric 

Generation

20200102 Internal Combustion Engines, 

Electric Generation, Distillate Oil 

(Diesel), Reciprocating

SCR $1,499 28-58 weeks 778 622
17

3.4 Discussion of Non-EGU Source Groups 

The below discussion utilizes the information in Table 3 in order to assess whether 

significant aggregate NOx mitigation is achievable from non-EGU sources by the 2017 

ozone season.

It is clear that a number of source categories have been identified by CoST that have the 

potential for non-EGU stationary source emissions reductions. There are some notable 

source categories below $10,000 per ton that have the potential for substantial non-EGU 

stationary source emissions reductions. However, for the purposes of this analysis, the 

EPA did not further examine control options above $3,300 per ton. This is consistent with 

the range we analyzed for EGUs in this proposal, and is also consistent with what the EPA 

has identified in previous transport rules as highly cost-effective, including the NOx SIP 

call.14 Again, this was done because the objective of this analysis is to characterize whether 

significant aggregate NOx mitigation is achievable from non-EGU sources by the 2017

ozone season, so we focused the search on categories with highly cost-effective 

technologies. This focus excludes several source groups with high reduction potential, 

including as SCR & LNB from ICI boilers, LNB & FGR on Catalytic Cracking, Process Heaters, 

& Coke Ovens, and OXY-Firing on Pressed and Container Glass Manufacturing, because 

reductions from those source groups are not available for $3,300 per ton or less.

At a cost level of $3,300 per ton or less, there are a number of remaining source groups

with substantial reduction potential. However the table also identifies several source 

groups whose reduction potential is not significant, and which EPA did not weigh heavily in 

assessing the aggregate non-EGU NOx reduction potential. This is because the aggregate 

potential reductions from these “insignificant” source groups is small. These “insignificant” 

source groups comprise those with many small sources, as well those containing a limited 

number of larger sources; for either of these types of groups, potential aggregate emission

reductions are small relative to reductions available from other source categories. The EPA 

does not believe that small sources have significant potential in the aggregate because most 

small sources emit less than 100 tons of NOx per year. (It is worth noting that small sources 

account for a significant percentage of the total number of non-EGU point sources. Please 

see Appendix A/B for more information on the number of sources within certain states.) 

The EPA therefore excludes from the focus of this analysis these insignificant source 

groups, namely, those with aggregate potential reductions of 1,000 tons per year or less

(which represents less than 0.1 percent of the anthropogenic ozone season inventory).

The EPA will now focus on the several source groups with significant cost-effective 

reductions identified in Table 3. These source groups include cement kilns, two types of 

cement manufacturing (dry and wet), gas turbines, four separate groups of natural gas 

RICE, incinerators, boilers & process heaters, by-product coke manufacturing, ammonia 

production, and flat glass manufacturing. These remaining source groups are listed below 

with their control technologies, estimated control costs, and estimated installation time.

 

14 $3,300 per ton represents the $2,000 per ton value (in 1990 dollars) used in the NOx SIP call, adjusted to the 2011 

dollars used throughout this proposal. 
18

These groups have been organized into 7 categories for clarity, based on either common 

control technologies (categories 1 through 6) or similarity of source groups (category 7).

Category 1

Cement Mfg (dry) SNCR $1,255 42-51 weeks

Incinerators SNCR $1,842 42-51 weeks

By-Product Coke Manufacturing SNCR $2,673 42-51 weeks

Category 2

Cement Kilns Biosolid Injection Technology (BSI) $410 Uncertain

Category 3

Gas Turbines Low NOx Burner (LNB) $800 6-8 months

Category 4

Cement Mfg (wet) Mid-Kiln Firing $73 5-7 months

Category 5

Boilers & Process Heaters SCR $2,235 28-58 weeks

Ammonia Production SCR $2,896 28-58 weeks

Category 6

Glass Manufacturing - Flat OXY-Firing $3,097 Uncertain

Category 7

Gas RICE Pipeline Compressors Adjust AFR and Ignition Retard $249 Uncertain

Gas RICE Miscellaneous Adjust AFR and Ignition Retard $447 Uncertain

Gas RICE Pipeline Compressors, Rich Burn NSCR $517 Uncertain

Gas RICE Pipeline Compressors, Lean/Clean Burn 

Low Emission Combustion (LEC) $649 Uncertain

The EPA makes the following observations about the potential reductions from these 

significant cost-effective categories. 

The source groups listed in Category 1 would utilize SNCR as the recommended control 

technology. The time necessary to install SNCR equipment is generally well known. A 

typical installation timeline of 42-51 weeks is generally needed to complete an SNCR 

project going from the bid evaluation through startup. Based on this fact alone (which does 

not consider additional time likely necessary for permitting or installation of monitoring 

equipment), the ability for SNCR technology to be installed and operational in time for the 

2017 ozone season seems very unlikely.

The source group listed in Category 2 contains a specific source of uncertainty in regards to

biosolid injection technology (BSI). Due in large part to the lack of widespread use of this 
19

control technology, research performed by the EPA has been unable to uncover any reliable 

information on the time required to install the necessary BSI equipment on cement kilns. 

Compliance timing with regard to biosolid injection technology should therefore be 

considered extremely uncertain. Based on this fact alone (and aside from additional time 

likely necessary for permitting or installation of monitoring equipment), the ability for this 

technology to be installed and operational at all facilities in this category in time for the 

2017 ozone season is unknown.

The source group listed in Category 3 would utilize LNB as the recommended control 

technology, with a necessary installation time of approximately 6-8 months. Some of the 

LNB combustion control technology identified for non-EGU sources reflects a different 

technology that may have different timing considerations than that considered for EGU 

boilers. For instance, LNB at non-EGU combustion turbines in this assessment refers to 

“dry low-NOx burners” (DLNB) which, in addition to the usual diffusion burner, typically 

also include provisions to “premix” natural gas and combustion air prior to combustion. In 

spite of the similarity in naming, this is a different technology than the LNB technology 

examined and assumed for reductions at EGU boilers. Therefore, the same timing 

assumptions assumed and demonstrated on the EGU side are not necessarily applicable to 

combustion control technology for non-EGU sources. Moreover, non-EGUs of any type –

boiler or turbine – that are not currently required to monitor and report in accordance 

with 40 CFR Part 75 will require additional time relative to EGUs that are currently 

equipped with Part 75 monitoring and reporting (such as those EGUs covered under 

federal transport rulemakings and this one). Installation of NOx monitors for the reporting 

of NOx mass requires the construction of platforms, CEM shelters, procurement of 

equipment, certification testing, and electronic data reporting programming of a data 

handling system. These added timing considerations on the non-EGU sources make 

installation of controls by the 2017 timeframe established in this rule less likely and more 

uncertain for industrial sources.

The source group listed in Category 4 would utilize mid-kiln firing as the recommended 

control technology. A fairly well-known aspect is the time necessary to install this 

equipment; typically, 5-7 months is needed to complete a mid-kiln firing project going from 

the bid evaluation through startup. However, the above-discussed issues regarding 

monitoring and reporting of NOx mass on non-EGU sources that currently lack such 

monitoring equipment make installation of controls by the 2017 timeframe proposed in 

this rule less likely and more uncertain for industrial sources such as those in the cement 

manufacturing (wet) source group.

The source groups listed in Category 5 would utilize SCR as the recommended control 

technology, with an installation time of 28-58 weeks for SCR (dependent on exhaust gas 

flow rates; larger systems require longer installation times). Based on the installation time 

frame alone (which does not consider additional time likely necessary for permitting or 

installation of monitoring equipment), the ability for SCR technology to be installed and 

operational in time for the 2017 ozone season seems unlikely. In addition to this 

uncertainty, the above-discussed issues regarding monitoring and reporting of NOx mass 

on non-EGU sources that currently lack such monitoring equipment make installation of 
20

controls by the 2017 timeframe established in this rule less likely and more uncertain for 

industrial sources such as those in Category 5 source groups.

The source group listed in Category 6 would utilize OXY-Firing as the recommended 

control technology, with an uncertain necessary installation. A specific source of 

uncertainty with regard to the estimated installation time of this control technology is that 

OXY-Firing is generally installed only at the time of a furnace rebuild, which rebuilds may 

occur at infrequent intervals of a decade or more.15 In addition to this uncertainty, the 

above-discussed issues regarding monitoring and reporting of NOx mass on non-EGU 

sources that currently lack such monitoring equipment make installation of controls by the 

2017 timeframe established in this rule less likely and more uncertain for industrial 

sources such as those in Category 6 source group.

Finally, the source groups listed in Category 7 are all RICE. While some of the 

recommended control technologies may involve installation timelines that are relatively 

short on a per-engine basis, there is substantial uncertainty in large-scale installation over 

numerous sources. References indicate that implementation of NOx controls of any type on 

a large number of RICE will require significant lead time to train and develop resources to 

implement emission reduction projects; market demand could significantly exceed the 

available resource base of skilled professionals.16 Additionally, in order not to disrupt 

pipeline capacity, engine outages must be staggered and scheduled during periods of low 

system demands for those engines involved in natural gas pipelines (as is the case with 3 of 

the 4 RICE source groups with significant cost-effective reductions). In addition to this 

uncertainty, the above-discussed issues regarding monitoring and reporting of NOx mass 

on non-EGU sources that currently lack such monitoring equipment make installation of 

controls by the 2017 timeframe established in this rule less likely and more uncertain for 

industrial sources such as RICE.

4 Conclusion

The above preliminary analysis performed by the EPA indicates that uncertainty exists 

regarding whether significant aggregate NOx mitigation is achievable from non-EGU point

sources by the 2017 ozone season.

While a number of source groups with control options were identified, the EPA did not 

further examine control options above $3,300 per ton, consistent with the range analyzed 

for EGUs in this proposal and with what the EPA has identified in previous transport rules 

as highly cost-effective. At a cost level of $3,300 per ton or less, a number of source groups 

remained, however the EPA believes several of these source groups are not significant. Of 

the remaining source groups, a variety of considerations indicated the ability for control 

technology to be installed and operational in time for the 2017 ozone season seemed

 

15 See Appendix B.

16 “Availability and Limitations of NOx Emission Control Resources for Natural Gas-Fired Reciprocating Engine Prime 

Movers Used in the Interstate Natural Gas Transmission Industry,” Innovative Environmental Solutions Inc., July 2014.
21

unlikely, with an overarching consideration being that non-EGUs of any type that are not 

currently required to monitor and report in accordance with 40 CFR Part 75 will require 

additional time relative to EGUs that are currently equipped with Part 75 monitoring and 

reporting. These added timing considerations on the non-EGU sources make installation of 

controls by the 2017 timeframe established in this rule less likely and more uncertain for 

industrial sources.

With all of these factors being considered, the limited available information points to an 

apparent scarcity of non-EGU reductions that could be accomplished by the beginning of 

the 2017 ozone season. As noted in the proposed rule, this conclusion has led EPA to focus 

the current proposed FIPs on EGU reductions. The proposal acknowledges that this may 

not be the full remedy that is ultimately be needed to eliminate an upwind state’s 

significant contribution to nonattainment or interference with maintenance of the 2008 

ozone NAAQS (or, for that matter, the 2015 ozone NAAQS). Emissions reductions from the 

non-EGU categories discussed above may be necessary, though on a longer timeframe than 

the 2017 compliance deadline being proposed in this rulemaking. EPA intends to explore 

this question further in the near future and welcomes comment on any of the information 

in this TSD to assist with that effort.