Page 1 of 10 

### Technical Support Document (TSD)

for the Cross

- State Air Pollution Rule for the 2008 Ozone NAAQS

Docket ID No. EPA

- HQ

- OAR

- 2015

- 0 5 0 0



## EGU NO X 

## Mitigation Strategies Proposed Rule TSD

U.S. Environmental Protection Agency

Office of Air and RadiationPage 2 of 10 September 2015



### Abstract :
This Technical Support Document ( TSD ) discusses costs and emission reduction potential for common electric generating unit ( EGU ) NO x emission control systems

. Specifically, this TSD explores three topics: (1) the appropriate representative cost resulting from “widespread” implementation of a particular NO x emission control technology; (2) the NO x emission rates commonly achievable by “ fully operating ” emission control equipment; and, (3) the time required to install and/or restore a n 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 NO x emissions data within the CSAPR region identified units emitting NO x at higher rates than previously demonstrated after commissioning post combustion controls. The agency acknowledges an EGU owner retains latitude regarding opera tional decisions for compliance with CSAPR , which include : operating existing NO x control equipment
, installing new or upgrading NO x 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 opera tion existing SCRs operating at fractional design capability

.

 Restarting inactive SCRs and returning to full opera tion.

 Restarting inactive SNCRs and returning to full opera tion.

 Replacing outdated combustion controls (LNB/OFA) with newer advanced technology.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 research ed by a nationally recognized architect / engineering firm (A/E firm) 1 familiar with the EGU sector. 2 Finally, EPA u sed the Integrated Planning Model (IPM) t o 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 ar e post

- combustion controls that reduce NO x 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 NO x while SNCR technology forgoes catalyst but with greatly reduced efficiency. F

ully operating an emission control device includes maintenance costs, labor, auxiliary power, capital recovery , catalyst (if utilized), and reagent cost ; the chemical reagent (ty pically ammonia or urea) costs become a significant portion of costs for operating these controls.

Minimum Cost : Retur

ning Partially Operating SCR s and SNCRs to Full Operation

1 Sargent & Lundy

2 See: http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdfPage 3 of 10

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 addition al reagent. Changing NO x removal rates following

commenc ement of operations does not affect fixed operation and maintenance ( FOM ) costs ; l ikewise, the variable operation and maintenance ( VOM ) components of catalyst replacement and auxiliary power are indifferent to reagent consum ption or NO x remov al. 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 NO x removed . During development of CAIR and CSAPR, the agency identified a marginal cost threshold of $500 per ton of NO x removed (1999 $ ) with reagent cost ing $190 per ton of ammonia
, which equate d to $108 / ton of NO x 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 i n relation to reagent procurement. To understand the relationship between reagent price and its associated cost regarding NO x reduction, s ee Appendix A : Table 1 ; “Anhydrous Ammonia and Urea Costs and their Associated Cost per NO x ton Removed

. ” Today, b ased on pure chemistry and theoretically achieving 100 percent reagent consumption towards NO x reduction, the reagent portion of operations costs $503 per ton NO x removed. This represents a reasonable estimate of the cost for operating these post combusti on controls based on current market ammonia prices. For purposes of the IPM modeling, the agency assume s that $500 per ton of NO x removed is a broadly available cost point for units that currently are partially

- operating SCRs and SNCRs to fully operate th eir NO x 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

. S ome of these expenses , as modeled by the Sargent & Lundy cost tool,
vary depend

ing on factors such as unit size
, NO x 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 NO x removed

. Additionally, the agency conservatively modeled costs with urea reagent, th e higher costing raw material for NO x mitigation.
Assessed on a per ton basis, t he FOM and VOM cost s assumed in IPM modeling are generally independent of unit size; h owever, cost estimates are sensitive to unit uncontrolled 4 NO x rate

. For a wide range of potential NO x rates anticipated , a bounding analysis was performed to identif y reasonable high and low costs

. For a hypothetical unit with a high uncontrolled NO x rate (e.g., 0.7 lb NO x / MMBtu and 80 percent removal efficiency )
, VOM and FOM costs were around $700/ton of NO x removed

. Conversely, a unit with a low uncontrolled NO x rate (e.g., 0.2 lb NO x / MMBtu and 60 percent removal ) experienced a higher cost range reveal ing VOM and FOM costs about $1

, 650/ton of NO x removed

. Next, the analysis applied these equations to all coal

- fired unit s equipped with SCR s in 2014 with collected emission s data

. For the SCR input NO x rate, each unit ’ s maximum monthly emission rate was examined from the period 2002

- 2014 (inclusively) for th e purpose of identif ying 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” NO x rate includes the effects of existing combustion controls present (i.e., low NO x burners).Page 4 of 10

The long time frame allowed examin ation prior to the onset of annual NO x trading programs (e.g., CAIR and CSAPR) with units expected to be operating their SCR s year

- round. The analysis made the following assumptions : a NO x removal efficiency of 8 7.6 percent , 5 a capacity factor of 85 percent, and combustion of bituminous coal w ith a heat rate reflecting the median annual heat rate over the time

- period. This
assessment found 2 23 of the 249 units (about 9 0 percent) demonstrated VOM plus FOM costs lower than $1,300/ton of NO x removed. The units with higher costs exhibited low uncontrolled NO x rates suggesting the SCR operat ed year

- round.
Examining the results, the EPA concludes that a cost of $1,300/ton of NO x removed would be sufficient for owners with installed SCRs to resume and fully operate their controls.

NO x Emission Rate Estimates for Full SCR Operation
The agency examined the ozone

- season average NO x 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 av erage NO x rate. The EPA selected 0.075 lbs NO x /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. Th is average rate represents the second

- lowest

ozone

- season NO x rate over the time period investigated; the median value was 0.065 lbs NO x /MMBtu (see Figure 1, top panel). The select ion of the second

- lowest ozone

- season rate avoids a possible issue associated with the best level of performance in an ozone season; namely, account ing for the non

repeatable 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 NO x emission rate s. T he second

- lowest historical monthly NO x rate analyzed illustrated 218 of 262 units displayed NO x rates below 0.08 lb/MMBtu (see Figure 1, bottom panel) and 208 units (or 79%) achieved monthly emis sion rates below 0.075 lbs NO x /MMBtu

. Based on these monthly demonstrated emission rates, the agency concludes a 0.075 lb NO x / MMBtu average rate is widely achievable by the EGU fleet.

5 A NO x 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.Page 5 of 10

Figure 1. “Frequency” distribution plots for 272 coal

- fired units with an SCR showing their NO x emission rates (lbs/MMBtu) during ozone seasons from 2003

- 2014. For each unit, the best, second best, and third best ozone

- season average NO x rate ( top pane l) and minimum monthly average NO x rate ( bottom panel) are illustrated

. Cost Estimates for Returning an Inactive S N CR to Full Operation

SNCR removes NO x but with significantly lower removal rates than an SCR system. Conducting the NO x reaction without catalyst typically requires three to four times the amount of reagent per percent NO x removed. Furthermore, an SNCR system is in capable of achieving the low emission rates of 0.07 lb NO xPage 6 of 10

/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. T he agency conservatively sets SNCR reduction potential at 25 percent, noting some installations achieve d 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 NO x rate below 0.30 lb / MMBtu which results in s ignificant ly higher costs per
ton removed. For the bounding analysis, the agency examined two cases 6 : f irst, a unit with a high NO x rate 0.7 0 lb / MMBtu; secondly, a unit with a low NO x rate 0.2 0 lb /MMBtu

– both with 25 percent removal efficiency. For the high rate case, VOM and FOM costs approximated $19 5 0/ton NO x with about $ 1,600/ton associated with urea cost . For the low rate case, VOM and FOM costs approached $3

, 4 00/ton NO x 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 unit s can reduce NO x 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 NO x / MMBtu and
, depending on unit type, can achiev e rates well below 0.20 lb NO x / MMBtu. Installation or upgrade of lo w NO x burner s can be a highly cost

- effective strategy to substantially reduce NO x 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 c ost

. Below, Table 1 “Combustion Control Upgrade Path for Vintage Systems” lists the upgrade paths available with cost estimating utiliz ing Chap ter 5, Table 5

- 4 “Cost (2011$) of NO x Combustion 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 units 8 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 f

actor while burning bituminous coal.

7 http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf
8 Definitions of Low NO x controls available for Tangentially

- fired units include: Low NO x Coal

- and

- Air Nozzles with Close

- Coupled Overfire Air (LNC1), Low NO x Coal

- and

- Air Nozzles with Separated Overfire Air (LNC2), Low NO x Coal

- and

- Air Nozzles with Close

- Coupled and Separated Overfire Air (LNC3)

.Page 7 of 10

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 rang e of estimated compliance costs based on an illustrative unit used in the previous section. 9 For this unit, the agency calc ulated the costs for each combustion control path listed above and determined that costs range d from $430 to $1200 per ton NO x 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 NO x rates of 0.07 lb NO x / MMBtu , or less , but with a greater expense

. For owners desiring to drive NO x 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 NO x / MMBtu , retrofitted with an SCR to lower emissions to 0.07 lb NO x / MMBtu
, results in a compliance cost of $50 00 / ton of NO x 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 NO x control , thereby red ucing the “cost per ton” of NO x reduction

. Retrofitting with SNCR and Related Costs
The agency examined SNCR retrofit technology costs with the Sargent & Lundy tool, and conservatively
set the NO x emission reduction rates at 25 percent. This technology gives owners a low capital cost option for reducing NO x emissions for units with anticipated short lives or low utilization, albeit at a higher cost per ton of NO x 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 NO x 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 NO x / MMBtu initial rate with 41 percent reduction after upgradesPage 8 of 10

Shifting Generation to Lower Emitting Units
Shifting generation to lower NO x - emitting EGUs, similar to operating existing post

- combustion controls, uses investm

ents that have already been made, can be done quickly, and can significantly reduce EGU NO x emissions.

Since CSAPR was promulgated, electricity generation has trended toward lower NO x - emitting generation due to market conditions (e.g., low natural gas p rices) and state and federal environmental policies. For example, new NGCC facilities, which represented 45% of new 2014 capacity, can achieve NO x emission rates of 0.0095 lb/ MM Btu, compared to existing coal steam facilities, which emitted at an
average ra te across the 23 states included in this proposal of 0.18 lbs/ MM Btu of NO x in 2014. This substantial difference in NO x 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 NO x - emitting EGUs would be a cost

- effective, timely, and readily available approach for EGUs to reduce NO x emissions and the EPA included this NO x mitigation strategy in quantifying EGU NO x obliga tions for this proposal.

Shifting generation to lower NO x - emitting EGUs occurs in response to economic factors. As the cost of emitting NO x increases, combined with all other costs of generation, it becomes increasingly cost

effective for units with low NO x rates to increase generation, while units with higher NO x rates to reduce generation. Because the cost of generation is unit

- specific, as the cost of emitting NO x increases with increasing cost thresholds, this generation shifting occurs incrementally. Consequently, there is more generation shifting at higher cost NO x 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 NO x 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 fe asibility of achieving reductions during the 2017 ozone

- season

. For SCRs and SNCRs currently operating at partial design capability, these functioning systems require increas ing 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 requi re one to two weeks

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

. As mentioned previously, power plant man agement needs to inform operations and maintenance of upcoming changes

. Personnel need to retrain and be come famil iarized with emission controls operating procedures for their plant site . Reagent needs to be ordered and stock

- piled. Maintenance needs to bring the system out ofPage 9 of 10

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 S CR systems since the original NO x SIP Call program allowed these systems to shut

- down during non

ozone season. Typically, u tilities restarted these systems the following season on time and without incident.

Since Low NO x burner and / or overfire air is a mature technology requiring a short time to complete installation , the Agency concludes that sufficient time exists for EG U owners to select this option for compliance. C onstruction t ime 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 Lo w NO x Burners (LNB)”, Do cket 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 a n 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, c onceptual 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

- 02/0 73 , Oct 2002. 11 The estimates and conclu sions 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.pdfPage 10 of 10

Appendix A: Ammonia / Urea Costs and their Associated Cost per NO x ton Removed

Minimum Cost to Operate Anhydrous NH 3 & Urea costs ($/ton) [from USDA]

year NH 3 (anh) Cost / ton NO x Urea cost Cost / ton NO x 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