### 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 201 5

### 2



# 1 Introduction/Purpose

Th e purpose of this Technical Support Document (TSD) is to discuss the currently available
information on emissions and control measures for sources of NO x 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 regard ing 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

, t he 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 evaluat ion 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 EGU s

. 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 e astern states that are the focus of the Cross

- State Air Pollution Rule (CSAPR).
Information inclusi ve of w estern states 1 

### is presented w here 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 per centages 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 TSD 2 

### as well as the Notice of Data Availability 3 

### (NODA) and Regulatory Impact Analysis 4 

### (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 NO x , annual 2017 NO x ,

annual 2011 NO x , ozone

season 2017 NO x , ozone

season
EGU

- point 2,000,000 1,500,000 942, 000 6 89,000

NonEGU

- point 1,200,000 1,200,000 515

, 000 5 02,000 Point oil and gas 500,000 410,000 213,000 172,000

Wild and p rescribed f

ires 330,000 330,000 165,000 1 65,000 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 2 11,000

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

Onroad 5,700,000 3,200,000 2,41 7

, 000 1,3 29,000

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 3 84,000

Biogenics 1,000,000 1,000,000 630,000 6 30,000

TOTAL 15,000,000 11,200,000 6,6 98,000 5,01 8

, 00 0



### 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

. E missions from the n on

- 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 In ventories 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_Em isMod_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 propos ed 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 5,01 8

, 00 0 tons in 2017. In both 2011 and 2017, t he 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” refer s to four separate categories of sources : non

- EGU point, point oil and gas, nonpoint oil and gas, and other nonpoi nt (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 an d 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.

Com paring 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 e astern states plus D.C. that are addressed in the proposed rulemaking are highlighted below in blue )

. N on

- 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, Tons 5

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 non

EGU 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

- EGU s categor ies range from 3% to
2 6 % ( e astern states) and from 7 % to 3 8 % ( w estern 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 continen tal U.S . In individual states, the percentage of anthropogenic emissions contributed by these non

- EGUs ranges from 2 % to 25 % ( e astern states) and from 4 % to 3 1 % ( w estern 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, inter nal combustion ( IC ) engines and pipeline compressors) and flares. Please refer to the EPA’s 2011 v6.2 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 gen erate 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 Analys e s (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 presen ted 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

.

Appendice s to this TSD discuss recommendations for updates to CoST, including

c orrections 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 l imits

. 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
C ontrol Measure Data Base (CMDB) used by CoST , and do not reflect the updates suggested in these contractor reports. Obstacles to full incorporation of the recomme nded 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 ou r 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 e astern 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 So urce 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 Interna tional, 2014; “Summary of State NOx Regulations for Selected Stationary Sources,” SRA International, 2014.

### 9



### technologies based on a pplication 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 Uncertain ties 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 re gulated industry, such as the costs for purchase, installation, operation, and maintenance of control equipment over the lifetime of the equipment. Recordkeeping, reporting, testing and moni toring 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 measu res: 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 cont rol 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 mainten ance [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 so me 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 a n 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 le vel 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

groups 8 

### , 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 sea son (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 S ource Groups with NOx Reductions

9 Time to install is not an output of CoST, but a re 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 excep t cement kilns and RICE), “Cement Kilns Technical Support Document for the NOx FIP,” EPA, January 2001 (cement kilns), and “Availability and Limitations of NOx Emiss ion Control Resources for Natural Gas

Fired Reciprocating Engine Prime Movers Used in the Interstat e Natural Gas Transmission Industry,” Innovative Environmental Solutions Inc., July 2014 (prepared for the INGAA Foundation)

. 10 In general, f or 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 cha in to offer conclusions on their availability to execute the projec t 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 r elative 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, procureme nt of equipment, certification testing, and electronic data reporting programming of a data handling system. These added timing co nsiderations for infrastructure on the non

EGU 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 groupi ng), Coal Cleaning

– Thermal Dryer (2), Spreader Strokers, Petroleum Refinery Process Heaters , Incinerators, Boilers & Process Hea ters, 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, Ca talytic 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, ho wever 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 install 9

10 ( excluding permitting, reporting preparation, programmatic and
administrative
considerations 11 ) 2017 12
NOx
Emissions (37 States + DC), OS tons, CoST 2017 Potential

Reductions 13 (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 Non

Catalytic
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

Pro ducts, 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

- Reheat i ng 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 Proc esses, Petroleum

Industry, Process Heaters, Process Gas

fired 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, N atural Gas, Reciprocating; 20200202 Internal Combustion Engines, Industrial, Natural Gas, Reciprocating; 20200204, Internal Combustion Engines, Industrial, Natural Gas, Reciprocating: Cogeneration; 20300201, Internal Combustion Engines, Commercial/Institut ional, 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 Proce sses, 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 Gas

fired SCR

- 95% $1,406

- $1,501 28

- 58 week s 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 Recirculat ion (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 $2,8 50 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

- In

Process
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, Dist i llate Oil (Diesel), Reciprocating; 20100107 Internal Combustion Engines, Electric Generation, Dist i llate Oil (Diesel), Reciprocating: Exhaust; 20200102 Internal Combustion Engines, Industrial,

Dist i llate Oil (Diesel), Reciprocating; 20200106 Internal Combustion Engines, Industrial, Dist i llate Oil (Diesel), Reciprocating: Evaporative Losses (Fuel Storag e and Delivery System); 20200107 Internal Combustion Engines, Industrial, Dist i llate Oil (Diesel), Reciprocating: Exhaust; 20300101 Internal Combustion Engines, Commercial/Institutional, Dist i llate 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 Gas

Fired Process Heaters (3) 30600104 Industrial Processes, Petroleum

Industry, Process Heaters, Gas

- fired, 30600106 Industrial Processes, Petroleum Industry, Process Heaters, Process Gas

fired SCR

- 95% $8,885

- $9,140 28

- 58 weeks 370 316

Glass
Manufacturin g
- 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 Gas

Fired 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 Ind ustrial Processes,

Petroleum Industry, Catalytic Cracking Units, Fluid Catalytic Cracking Unit; 39000701 Industrial Processes, In

process Fuel Use, Process Gas, Coke
Oven or Blast Furnace LNB & FGR $4,026 6

- 8 months 871 479

Glass Manufacturing

- Containe r 30501402 Industrial Processes, Mineral

Products, Glass Manufacture, Container Glass: Melting Furnace OXY

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

Petroleum Refinery Gas

Fired 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, Dist i llate 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 wit h 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

oz one season, so we focused the search on categories with highly cost

- effective technologies. This focus excludes several source groups with hig h reduction potential, including as SCR & LNB from ICI boilers, LNB & FGR on Catalytic Cracking, Process Heaters,
& Coke Ovens

, and O XY

- 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 wi th substantial reduction potential. H owever 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 ag gregate 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, po tential aggregate emission
reduction s are small relative to reductions available from other source categories

. T he EPA
does not believe that small sources have significant potential in the aggregate because m ost small sourc es emit less than 100 tons of N O x per year . (It is worth noting that s mall sources account for a significant percentage of the total num ber 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 fr om 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 o n 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, b oilers & 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 make s 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

. T he 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 relia ble 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 additio nal 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 d ifferent 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 provis ions 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 a ssumed 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 CF R 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 t hose 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 requi re 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 t ime 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 inte rvals 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 esta blished 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 reduct ions)

. 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 transp ort 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 indi cated the ability for control technology to be installed and operational in time for the 2017 ozone season seem ed

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 accordanc e with 40 CFR Part 75 will require additional time relative to EGUs that are currently equipped with P art 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, t he 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 sig nificant 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 th an 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

.