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Technical Support Document (TSD)

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

Docket ID No. EPA-HQ-OAR-2015-0500

EGU NOX Mitigation Strategies Proposed Rule TSD

U.S. Environmental Protection Agency

Office of Air and Radiation
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September 2015

Abstract:

This Technical Support Document (TSD) discusses costs and emission reduction potential for common 

electric generating unit (EGU) NOx emission control systems. Specifically, this TSD explores three 

topics: (1) the appropriate representative cost resulting from “widespread” implementation of a particular 

NOx emission control technology; (2) the NOx emission rates commonly achievable by “fully operating”

emission control equipment; and, (3) the time required to install and/or restore an emission control system 

to full operation. These estimates form the basis for modeling costs and emission reductions within IPM v

5.14 and 5.15. 

Introduction:

Evaluation of power sector NOx emissions data within the CSAPR region identified units emitting NOx at 

higher rates than previously demonstrated after commissioning post combustion controls. The agency 

acknowledges an EGU owner retains latitude regarding operational decisions for compliance with 

CSAPR, which include: operating existing NOx control equipment, installing new or upgrading NOx

controls, purchasing allowances, or shifting generation. As described in the preamble, the compliance 

timeline for implementing the updated CSAPR led the agency to focus on the following compliance 

options: 

 Returning to full operation existing SCRs operating at fractional design capability.

 Restarting inactive SCRs and returning to full operation. 

 Restarting inactive SNCRs and returning to full operation. 

 Replacing outdated combustion controls (LNB/OFA) with newer advanced technology. 

 Changing dispatch from high to low-emitting units.

Preliminarily, EPA sought to understand each unit’s cost and emission reduction potential for these 

compliance options. The agency used the capital expenses, fixed and variable operation and maintenance 

costs for installing and fully operating emission controls researched by a nationally recognized architect / 

engineering firm (A/E firm)1familiar with the EGU sector.2 Finally, EPA used the Integrated Planning 

Model (IPM) to analyze power sector response while accounting for electricity market dynamics such as 

generation shifting.

Results and Discussion:Emission and Cost Estimates for Full Operation of SCR and SNCR 

SCR and SNCR are post-combustion controls that reduce NOx emissions through reacting this pollutant 

with either ammonia or urea either in presence or absence of a catalyst. The SCR technology utilizes a 

catalyst and produces high conversion of NOx while SNCR technology forgoes catalyst but with greatly 

reduced efficiency. Fully operating an emission control device includes maintenance costs, labor, 

auxiliary power, capital recovery, catalyst (if utilized), and reagent cost; the chemical reagent (typically 

ammonia or urea) costs become a significant portion of costs for operating these controls. 

Minimum Cost: Returning Partially Operating SCRs and SNCRs to Full Operation

 

1 Sargent & Lundy

2 See: http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf
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Since units that are partially running their SCR or SNCR system have already incurred the fixed operating 

costs (which are associated with having the controls functioning at any level), the remaining cost to 

achieve full design capability is the cost of additional reagent. Changing NOx removal rates following 

commencement of operations does not affect fixed operation and maintenance (FOM) costs; likewise, the 

variable operation and maintenance (VOM) components of catalyst replacement and auxiliary power are 

indifferent to reagent consumption or NOx removal. In short, for SCRs and SNCRs, the marginal cost to 

increase from partial operation to full operation reflects the cost of additional reagent. 

In an SCR, the chemical reaction consumes approximately 0.57 tons of ammonia or 1 ton of urea for 

every ton of NOx removed. During development of CAIR and CSAPR, the agency identified a marginal 

cost threshold of $500 per ton of NOx removed (1999$) with reagent costing $190 per ton of ammonia, 

which equated to $108 / ton of NOx removed for the reagent procurement portion of operations.

3 The 

remaining balance reflected other operating and capital recovery costs. Over the years, these commodity 

prices changed, affecting the operational cost in relation to reagent procurement. To understand the 

relationship between reagent price and its associated cost regarding NOx reduction, see Appendix A:

Table 1; “Anhydrous Ammonia and Urea Costs and their Associated Cost per NOx ton Removed.” 

Today, based on pure chemistry and theoretically achieving 100 percent reagent consumption towards 

NOx reduction, the reagent portion of operations costs $503 per ton NOx removed. This represents a 

reasonable estimate of the cost for operating these post combustion controls based on current market 

ammonia prices. For purposes of the IPM modeling, the agency assumes that $500 per ton of NOx

removed is a broadly available cost point for units that currently are partially-operating SCRs and SNCRs 

to fully operate their NOx controls, which in fact, represents procuring additional reagent. 

Cost Estimates for Returning an Inactive SCR to Full Operation

For a unit with an idled, bypassed, or mothballed SCR, all FOM and VOM costs such as auxiliary fan 

power, catalyst costs, and additional administrative costs (labor) are realized upon resuming operation 

through full potential capability. Some of these expenses, as modeled by the Sargent & Lundy cost tool,

vary depending on factors such as unit size, NOx generated from the combustion process, and reagent 

utilized. The EPA performed multiple assessments with this tool’s parameters to investigate sensitivity 

relating to cost per ton of NOx removed. Additionally, the agency conservatively modeled costs with urea 

reagent, the higher costing raw material for NOx mitigation. 

Assessed on a per ton basis, the FOM and VOM costs assumed in IPM modeling are generally 

independent of unit size; however, cost estimates are sensitive to unit uncontrolled4 NOx rate. For a wide 

range of potential NOx rates anticipated, a bounding analysis was performed to identify reasonable high 

and low costs. For a hypothetical unit with a high uncontrolled NOx rate (e.g., 0.7 lb NOx / MMBtu and 

80 percent removal efficiency), VOM and FOM costs were around $700/ton of NOx removed. 

Conversely, a unit with a low uncontrolled NOx rate (e.g., 0.2 lb NOx / MMBtu and 60 percent removal)

experienced a higher cost range revealing VOM and FOM costs about $1,650/ton of NOx removed. Next,

the analysis applied these equations to all coal-fired units equipped with SCRs in 2014 with collected 

emissions data. For the SCR input NOx rate, each unit’s maximum monthly emission rate was examined 

from the period 2002-2014 (inclusively) for the purpose of identifying the unit’s maximum emission rate

prior to the control’s installation or alternatively during time-periods when the control was not operating. 

 

3 EPA Memorandum to Docket; “Analysis of the Marginal Cost of SO2 and NOx Reductions”, Jan 28, 2004

4 For these hypothetical cases, the “uncontrolled” NOx rate includes the effects of existing combustion controls 

present (i.e., low NOx burners).
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The long time frame allowed examination prior to the onset of annual NOx trading programs (e.g., CAIR 

and CSAPR) with units expected to be operating their SCRs year-round. The analysis made the following 

assumptions: a NOx removal efficiency of 87.6 percent,

5

a capacity factor of 85 percent, and combustion 

of bituminous coal with a heat rate reflecting the median annual heat rate over the time-period. This 

assessment found 223 of the 249 units (about 90 percent) demonstrated VOM plus FOM costs lower than

$1,300/ton of NOx removed. The units with higher costs exhibited low uncontrolled NOx rates 

suggesting the SCR operated year-round.

Examining the results, the EPA concludes that a cost of $1,300/ton of NOx removed would be sufficient 

for owners with installed SCRs to resume and fully operate their controls.

NOx Emission Rate Estimates for Full SCR Operation

The agency examined the ozone-season average NOx rates for 272 coal-fired units with an installed SCR 

over the time-period 2003-2014, then identified each unit’s lowest, second lowest, and third-lowest 

ozone-season average NOx rate. The EPA selected 0.075 lbs NOx/MMBtu as a reasonable, representation 

for full operational capability of an SCR noting that over half of the 272 EGUs examined in this case 

study achieved this rate over an entire ozone season. This average rate represents the second-lowest 

ozone-season NOx rate over the time period investigated; the median value was 0.065 lbs NOx/MMBtu 

(see Figure 1, top panel). The selection of the second-lowest ozone-season rate avoids a possible issue

associated with the best level of performance in an ozone season; namely, accounting for the nonrepeatable performance related with commissioning, or “breaking in,” a newly constructed SCR. For the 

next step, the agency examined each ozone-season over the time period and identified the lowest monthly 

average NOx emission rates. The second-lowest historical monthly NOx rate analyzed illustrated 218 of 

262 units displayed NOx rates below 0.08 lb/MMBtu (see Figure 1, bottom panel) and 208 units (or 79%) 

achieved monthly emission rates below 0.075 lbs NOx/MMBtu. Based on these monthly demonstrated 

emission rates, the agency concludes a 0.075 lb NOx / MMBtu average rate is widely achievable by the 

EGU fleet. 

 

5 A NOx removal efficiency of 87.6 percent is based on the median ratio of the month with the highest NOx rate to 

the second best ozone season value for the time-period 2003-2014. The agency selected the median value to ensure 

exclusion of outliers.
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Figure 1. “Frequency” distribution plots for 272 coal-fired units with an SCR showing their NOx

emission rates (lbs/MMBtu) during ozone seasons from 2003-2014. For each unit, the best, second best, 

and third best ozone-season average NOx rate (top panel) and minimum monthly average NOx rate 

(bottom panel) are illustrated.

Cost Estimates for Returning an Inactive SNCR to Full Operation

SNCR removes NOx but with significantly lower removal rates than an SCR system. Conducting the NOx

reaction without catalyst typically requires three to four times the amount of reagent per percent NOx

removed. Furthermore, an SNCR system is incapable of achieving the low emission rates of 0.07 lb NOx
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/MMBtu which an SCR achieves. That said, SNCR can serve as a cost-effective strategy for some 

owners with particularly low capacity factors or short time horizons. The agency conservatively sets

SNCR reduction potential at 25 percent, noting some installations achieved superior results. For the 

SNCR analysis, as with the SCR analysis, the agency used the Sargent & Lundy cost tool to perform a 

bounding analysis for examining operating expenses associated with returning a “generic” unit to full 

operation. For units with an idled SNCR returning to full operation, the owner incurs the full suite of 

VOM and FOM costs, however these costs are relatively insensitive to unit size. On the other hand, 

reagent consumption represented the largest portion of the VOM component. A step change in costs 

occurs at an uncontrolled NOx rate below 0.30 lb / MMBtu which results in significantly higher costs per 

ton removed. For the bounding analysis, the agency examined two cases6: first, a unit with a high NOx

rate 0.70 lb / MMBtu; secondly, a unit with a low NOx rate 0.20 lb /MMBtu – both with 25 percent 

removal efficiency. For the high rate case, VOM and FOM costs approximated $1950/ton NOx with 

about $1,600/ton associated with urea cost. For the low rate case, VOM and FOM costs approached 

$3,400/ton NOx with nearly $2,700/ton associated with urea reagent cost. 

Cost Estimates for Installing Low NOx Burners and / or Over Fire Air

Combustion control technology has existed for many decades with improvements occurring over the 

years. Today’s combustion controls are superior to those controls installed two decades ago. While 

many units contain some form of this technology, some units can reduce NOx creation in the furnace by 

modernizing their combustion controls without having to install SCR or SNCR. Modern combustion 

control technologies routinely achieve rates from 0.20 – 0.25 lb NOx / MMBtu and, depending on unit 

type, can achieve rates well below 0.20 lb NOx / MMBtu. Installation or upgrade of low NOx burners can 

be a highly cost-effective strategy to substantially reduce NOx emissions. Agency staff checked the 

National Electric Energy Data System, or NEEDs, to verify installed vintage, and then developed an 

upgrade path based on the options available within IPM for estimating cost. Below, Table 1 “Combustion 

Control Upgrade Path for Vintage Systems” lists the upgrade paths available with cost estimating 

utilizing Chapter 5, Table 5-4 “Cost (2011$) of NOxCombustion Controls for Coal Boilers (300 MW 

Size)” from IPM documentation.7

The agency reasonably assumes for these units:

- Modern Low NOx burner technology, or LNB, replaces old existing burners;

- Over Fire Air, or OFA, is preserved, if it exists;

- Tangential fired units8 not currently at LNC3 level receive LNC1 or LNC2 depending on their 

current configuration.

Table 1: Combustion Control Upgrade Path for Vintage Systems

Current Combustion Controls

(NEEDS 5.14)

Retrofit / Install Projection Final Configuration

- None - LNB + OFA LNB + OFA

OFA LNB LNB + OFA

 

6 For both cases, we examined a 500 MW unit with a heat rate of 10,000 Btu/kWh operated at an 85% annual 

capacity factor while burning bituminous coal.

7 http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf

8 Definitions of Low NOx controls available for Tangentially-fired units include: Low NOx Coal-and-Air Nozzles 

with Close-Coupled Overfire Air (LNC1), Low NOx Coal-and-Air Nozzles with Separated Overfire Air (LNC2), 

Low NOx Coal-and-Air Nozzles with Close-Coupled and Separated Overfire Air (LNC3).
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LNB LNB + OFA LNB + OFA

LNB + OFA LNB LNB + OFA

LNC1 LNC2 LNC3

LNC2 LNC1 LNC3

BF, LA, CO, LNB + OFA LNB + OFA

With the wide range of LNB configurations available and furnace types present within the fleet, the 

agency decided to provide a range of estimated compliance costs based on an illustrative unit used in the 

previous section.9 For this unit, the agency calculated the costs for each combustion control path listed 

above and determined that costs ranged from $430 to $1200 per ton NOx removed. ($2011) 

Retrofitting with SCR and Related Costs 

The agency also examined the cost for retrofitting a unit with SCR technology, which typically attains 

extremely low controlled NOx rates of 0.07 lb NOx / MMBtu, or less, but with a greater expense. For 

owners desiring to drive NOx emissions to their lowest potential, SCR retrofit becomes a prime choice for 

coal-fired units. The tool developed by Sargent & Lundy illustrates the point; a unit with an uncontrolled 

rate of 0.35 lb NOx / MMBtu, retrofitted with an SCR to lower emissions to 0.07 lb NOx / MMBtu, results 

in a compliance cost of $5000 / ton of NOx removed. Installation of SCR involves substantial expenditure 

of capital. Consequently, SCR installation is most often seen for units which generate substantial 

electricity and have high capacity factors. Because of the substantial capital cost of an SCR, for a unit 

with low utilization, owners may adopt SNCR as a more appropriate choice for NOx control, thereby 

reducing the “cost per ton” of NOx reduction. 

Retrofitting with SNCR and Related Costs 

The agency examined SNCR retrofit technology costs with the Sargent & Lundy tool, and conservatively 

set the NOx emission reduction rates at 25 percent. This technology gives owners a low capital cost 

option for reducing NOx emissions for units with anticipated short lives or low utilization, albeit at a 

higher cost per ton of NOx removed, reflecting this technology’s lower removal efficiency. For the unit 

examined above, but with a 40 percent capacity factor, the cost is $6500 / ton of NOx removed. Capital 

costs reflecting this unit represent $46 / kW (unlike the SCR above which represented $292 / kW). In 

short, the lower removal efficiency consumes greater amounts of reagent which escalates the VOM cost 

component. 

 

9 assumed 500 MW unit, heat rate of 10,000 Btu/kWh, 85% annual capacity factor, bituminous coal, 0.50 lb NOx / 

MMBtu initial rate with 41 percent reduction after upgrades 
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Shifting Generation to Lower Emitting Units

Shifting generation to lower NOx -emitting EGUs, similar to operating existing post-combustion 

controls, uses investments that have already been made, can be done quickly, and can significantly reduce 

EGU NOx emissions.

Since CSAPR was promulgated, electricity generation has trended toward lower NOx -emitting 

generation due to market conditions (e.g., low natural gas prices) and state and federal environmental 

policies. For example, new NGCC facilities, which represented 45% of new 2014 capacity, can achieve 

NOx emission rates of 0.0095 lb/MMBtu, compared to existing coal steam facilities, which emitted at an 

average rate across the 23 states included in this proposal of 0.18 lbs/MMBtu of NOx in 2014. This 

substantial difference in NOx emission performance between existing coal steam and new NGCC 

generation is due both to higher nitrogen content in coal compared to natural gas, as well as to the 

substantially lower generating efficiency of steam combustion technology compared to combined cycle 

combustion technology. Shifting generation to lower NOx -emitting EGUs would be a cost-effective, 

timely, and readily available approach for EGUs to reduce NOx emissions and the EPA included this NOx

mitigation strategy in quantifying EGU NOx obligations for this proposal.

Shifting generation to lower NOx -emitting EGUs occurs in response to economic factors. As the 

cost of emitting NOx increases, combined with all other costs of generation, it becomes increasingly costeffective for units with low NOx rates to increase generation, while units with higher NOx rates to reduce 

generation. Because the cost of generation is unit-specific, as the cost of emitting NOx increases with 

increasing cost thresholds, this generation shifting occurs incrementally. Consequently, there is more 

generation shifting at higher cost NOx thresholds. This generation shifting occurs on a continuum in 

response to costs. Because we have identified discrete cost thresholds resulting from the full 

implementation of particular types of emission controls, it is reasonable to simultaneously quantify the

reduction potential from generation shifting strategy at each cost level. Including these reductions is 

important, ensuring that other cost-effective reductions (e.g., fully operating controls) can be expected to 

occur.

The EPA limited shifting generation to units with lower NOx emission rates within the same state 

due to the near-term 2017 implementation timing for this proposed rule. 

Feasibility Assessment: Compliance Time for Each Option

The agency assessed the time needed for implementation of each option to assess the feasibility of 

achieving reductions during the 2017 ozone-season. 

For SCRs and SNCRs currently operating at partial design capability, these functioning systems require 

increasing reagent flow rate and ensuring sufficient chemical reagent exists to sustain higher reagent flow 

operations. Considering that system design likely already supports higher throughput, increasing control 

operation requires procurement of additional reagent. Stocking-up additional reagent for sustaining 

increased operation may require one to two weeks.

For inactive SCRs and SNCRs, restoring functionality may require three months. As mentioned 

previously, power plant management needs to inform operations and maintenance of upcoming changes. 

Personnel need to retrain and become familiarized with emission controls operating procedures for their 

plant site. Reagent needs to be ordered and stock-piled. Maintenance needs to bring the system out of 
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protective lay-up, perform inspections, and correct deficiencies (if present). Operations will test run, and 

re-tune the system before compliance season. The EGU sector is very familiar with restarting SNCR and

SCR systems since the original NOx SIP Call program allowed these systems to shut-down during nonozone season. Typically, utilities restarted these systems the following season on time and without 

incident.

Since Low NOx burner and / or overfire air is a mature technology requiring a short time to complete

installation, the Agency concludes that sufficient time exists for EGU owners to select this option for 

compliance. Construction time requirements for installing combustion controls were examined by the 

EPA during CSAPR development and are reported in the TSD for prior CSAPR rulemaking entitled; 

“Installation Timing for Low NOx Burners (LNB)”, Docket ID No. EPA-HQ-OAR-2009-0491-0051.

10

 

The estimates and conclusions of that assessment are included here.

Retrofitting with SCR and SNCR are not being considered for this rule as a compliance option. The time 

requirements for an SCR retrofit exceed 18 months from contract award through commissioning. SNCR 

is similar to ACI and DSI installations and requires 12 months from contract award through 

commissioning. For both technologies, conceptual design, permitting, financing, and bid review require 

additional time. Detailed analysis can be found in: “Final Report: Engineering and Economic Factors 

Affecting the Installation of Control Technologies for Multipollutant Strategies”, EPA-600/R-02/073, Oct 

2002.11 The estimates and conclusions of that assessment are included here.

 

10 http://www.epa.gov/airmarkets/airtransport/CSAPR/pdfs/TSD_Installation_timing_for_LNBs_07-6-10.pdf

11 http://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf
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Appendix A: Ammonia / Urea Costs and their Associated Cost per NOx ton Removed

Minimum Cost to Operate

Anhydrous NH3 & Urea costs ($/ton) [from USDA]

year NH3 (anh)

Cost / ton 

NOx Urea cost

Cost / ton 

NOx

1999 $ 190 $ 108 $ 165 $ 165 

2000 $ 209 $ 118 $ 194 $ 194 

2001 $ 385 $ 218 $ 277 $ 277 

2002 $ 228 $ 129 $ 179 $ 179 

2003 $ 374 $ 212 $ 258 $ 258 

2004 $ 366 $ 207 $ 264 $ 264 

2005 $ 394 $ 223 $ 319 $ 319 

2006 $ 489 $ 277 $ 345 $ 345 

2007 $ 500 $ 283 $ 445 $ 445 

2008 $ 731 $ 414 $ 537 $ 537 

2009 $ 640 $ 363 $ 450 $ 450 

2010 $ 474 $ 269 $ 421 $ 421 

2011 $ 744 $ 422 $ 501 $ 501 

2012 $ 812 $ 460 $ 547 $ 547 

2013 $ 877 $ 497 $ 574 $ 574 

2014 $ 888 $ 503 $ 550 $ 550 

USDA

http://www.neo.ne.gov/statshtml/181.htm