P.O. Box 52025                                                                                                                                                                     Baseload Generation

Phoenix, AZ 85072‐2025                                                 Mail Station:  POB002

(602) 236‐5900                                                            Direct Line:  (602) 236‐5385

www.srpnet.com                                                                  Fax:  (602) 236‐3809                        

                                             E‐mail:jim.pratt@srpnet.com

Submitted via Overnight FedEx Delivery

August 24, 2012

Deborah Jordan

Air Division Director

U.S. EPA Region IX

Mail Code: AIR‐1

75 Hawthorne Street

San Francisco, CA 94105  

RE:   SRP Response to EPA Letter Dated July 27, 2012

Dear Ms. Jordan:

This letter is submitted in response to your letter to Ms. Kelly Barr dated July 27, 2012

regarding the proposed emission limit for nitrogen oxides (NOx) for Coronado Generating

Station (CGS) Unit 2. The Salt River Project Agricultural Improvement and Power District (SRP)

appreciates the opportunity to provide additional information regarding the difficulty of

implementing an even more stringent NOx emission limit for CGS Unit 2.  

As you know, SRP is currently installing a new selective catalytic reduction (SCR) system on Unit

2 at CGS as a result of a 2008 Consent Decree between SRP and EPA. In addition to a new SCR

system on Unit 2, SRP agreed under the Consent Decree to install low‐NOx combustion systems

on Units 1 and 2 and that CGS would meet a plant‐wide rolling NOx limit of 7,300 tons per year

beginning on July 1, 2014. SRP further agreed to install new flue gas desulfurization (FGD)

systems on both units to reduce sulfur dioxide (SO2) emissions by 95%. Implementation of

these control technologies and emission limitations resulted in a NOx and SO2 emission

reduction settlement for the entire site and a significant reduction in haze producing emissions

at a total investment of more than $500 million.

Once the SCR system is commissioned, CGS Unit 2 will be required to meet a NOx emission limit

of 0.080 pounds per million British thermal units (lb/MMBtu), on a 30‐day rolling average.

Based on the discussions that occurred at the time the Consent Decree was negotiated, this SCR

system and emission limit represented the best available control technology (BACT) for NOx

emissions for Unit 2, and they still do today. The NOx emission limit for CGS Unit 2 also takes

into consideration the unit’s ability to meet other requirements set forth in the Consent

Decree, including operating and emission limits related to particulate matter emissions. Altering
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 2

the NOx emission limit for CGS Unit 2 would call into question SRP’s ability to meet these other

mandatory requirements, which were evaluated and discussed in detail during the Consent

Decree negotiations. In fact, SRP is so concerned about the potentially disruptive impact of a

lowered NOx emission limit on its ability to meet the requirements of the Consent Decree that

SRP recently submitted to the Department of Justice and EPA a notice of potential Force

Majeure under the Consent Decree.1

BACT is a more stringent technology‐based standard than the best available retrofit technology

(BART) standard specified by the Regional Haze Rules. This is clear on the face of the statute:

BACT is the “maximum degree of reduction” of a regulated pollutant that “is achievable for [a]

facility” taking into account energy, environmental, and economic impacts and other costs.2

BART accounts for the same factors as BACT, as well as some others, but it is not the “maximum

degree of reduction ... achievable.”3 Therefore, BART for CGS Unit 2 cannot be more stringent

than the current BACT limit of 0.080 lb/MMBtu. Indeed EPA’s BART rules state that emission

limits imposed on a facility as the result of “NSR/PSD settlement agreements,” such as the CGS

Consent Decree, should generally be considered sufficient to satisfy any applicable BART

obligation for that facility.4 However, to comply with EPA’s request, SRP has completed further

analysis regarding whether, and if so to what extent, Unit 2 may have the capability to achieve

an even lower NOx emission limit.

After modeling and other analysis of the SCR equipment currently being installed on CGS Unit 2,

SRP and its consultant have determined that a NOx emission limit of 0.050 lb/MMBtu on a 30‐

day rolling average cannot be achieved at CGS Unit 2.  Even with modifications to the existing

SCR design, which are described in more detail below, a NOx emission limit of 0.050 lb/MMBtu

on a 30‐day rolling average cannot be achieved when it is necessary to account for emissions

during cycling and startup and shutdown events. The Consent Decree requires SRP to

demonstrate compliance with the NOx emission limits at all times, including during these types

of events.

In your letter, you requested the following information:

 Documentation of specific “sunk costs” expended by SRP to comply with the

requirements of the Consent Decree.

                                                           

1 August 9, 2012 Letter from Makram B. Jaber, Hunton & Williams LLP, counsel for SRP, to the U.S. Department of

Justice and the U.S. EPA, pursuant to Consent Decree in U.S. v. Salt River Project Agricultural Improvement and

Power District, No. 2:08‐CV‐1479 (JAT) (D. Ariz.).

2 See Clean Air Act (CAA) §169(3).

3 See CAA §169A(g)(2).

4 See 70 Fed. Reg. 39104, 39164 (July 6, 2005).
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 3

 Documentation of the technically feasible design changes to the SCR system that SRP is

currently installing that would be required in order to meet a NOx emission limit of

0.050 lb/MMBtu for Unit 2.

 SRP’s plan for managing the SCR catalyst layers to meet the Consent Decree limit of

0.080 lb/MMBtu, and how that plan might change in order to meet a limit of 0.050

lb/MMBtu.

 The amount of spare space for catalyst layers and the expected frequency of catalyst

replacement.  

 Vendor recommendations and guarantees.

This letter contains the information that SRP was able to gather in the timeframe provided, as

well as additional information that SRP believes EPA should consider when evaluating a BART

emissions limit for Coronado Unit 2. Please note that SRP may supplement the information in

future written comments SRP will submit on the proposed regional haze rulemaking.5

  

“Sunk Costs” Associated with Current SCR Design and Installation

Actual costs for the SCR on Unit 2, as it is currently designed, are expected to be approximately

$90 million. SRP has awarded contracts to date that represent a total commitment of $44.9

million, and has been invoiced for $15.8 million as of August 20, 2012 (refer to Attachment A).

SRP’s spend curve related to these contracts is ramping up quickly as we move further into the

construction and equipment delivery phase of the project.

It must also be noted that many of the contracts that SRP has entered into include premiums

for contract cancellations and yet‐to‐be invoiced labor and material costs, which are not

included in this “spent” amount. The amounts of these premiums are vendor‐dependent and

are negotiated on a case‐by‐case basis based on each vendor’s specific scope of work and the

current status of the vendor’s work under each contract. At this time, we estimate that the

irretrievable, “sunk costs” associated with the current SCR project are approximately $17.1

million. These costs are continuing to accumulate each day, and at an accelerating pace.   

Scheduling Concerns

Under the Consent Decree, SRP is required to install and operate an SCR system for the control

of NOx emissions from one unit at CGS by June 1, 2014. SRP has elected to install the SCR

                                                           

5 Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze State and

Federal Implementation Plans; Proposed Rule. Volume 77, Number 140 of the Federal Register dated July 20, 2012.
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 4

system on CGS Unit 2. Because the design and installation of an SCR system is a massive

undertaking that requires a long lead time, SRP has already started this work, and barring

unexpected circumstances, will meet the deadline imposed by the Consent Decree.  

As stated in the August 9, 2012 letter to the United States Department of Justice and EPA from

SRP’s counsel addressing a potential Force Majeure Event concerning the installation of

emission controls required by the Consent Decree, the SCR project is over 40% complete and on

schedule to meet the Consent Decree requirements.   

 The engineering design effort is approximately 91% complete. The foundations,

mechanical components, and structural steel designs are all complete. The design for

the electrical and controls systems is almost complete.   

 The overall procurement efforts for the project are approximately 76% complete. The

SCR and associated ammonia system have already been purchased, and delivery of the

SCR components is scheduled to begin this fall. SRP has also issued the contract for the

steel supply. The vendor has purchased the material, and steel fabrication is underway.

 The construction phase of the project has begun, and the concrete foundations are

currently being installed. The construction phase of the project is about 5% complete

and is ramping up quickly to meet the required operational date. Installation of the

mechanical and structural systems will commence this October.

In short, SRP has made irrevocable financial and operational commitments to be in a position to

comply with the requirements of the Consent Decree to install and operate an SCR at one CGS

unit by June 1, 2014, so as to meet a 30‐day rolling average NOx emission rate limit of 0.080

lb/MMBtu.   

If SRP were required to modify the current design of the Unit 2 SCR to meet a lower NOx

emission limit as discussed below, the construction delay associated with incorporating and

commissioning these major pieces of equipment with this modification would range from 14 to

30 months if a fabric filter baghouse is not required. If SRP is required to install a fabric filter

baghouse, this would add an additional 36 to 42 months to the construction schedule since SRP

would not know whether a fabric filter baghouse was required until after the SCR was installed

and operating. Clearly, such steps would prevent SRP from meeting the compliance schedule

and emission limits in the Consent Decree.  

Potential Technically Feasible SCR Design Changes to Meet a Lower NOx Emission Limit

SRP contracted the SCR feasibility analysis related to potentially meeting an even lower NOx

emission limit to Sargent & Lundy LLC (S&L), a company that has provided comprehensive
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 5

consulting, engineering, design, and analysis for electric power generation and power delivery

projects worldwide.6 S&L was selected as SRP’s consultant based on their involvement in the

various engineering activities associated with the Consent Decree control improvements at

CGS. A full copy of S&L’s analysis is provided in Attachment B of this letter.  

For the feasibility analysis, SRP asked S&L to examine options to modify the current SCR design

considering the operational parameters agreed to by SRP and EPA in the Consent Decree. As

such, SRP stipulated that the following items could not change as a result of any contemplated

SCR design modifications: physical size of the control system, CGS’ planned maintenance cycle,

and structural steel designs, foundations, and balance‐of‐plant tie‐ins.

As reflected in the attached report, S&L concluded that the current SCR system, as designed,

can meet the 0.080 lb/MMBtu NOx emission limit on a 30‐day rolling average, but it cannot

meet a NOx emissions limit of 0.050 lb/MMBtu on a 30‐day rolling average. S&L reached these

conclusions after modeling each emission limit. This modeling demonstrated that including low

load cycling periods and startup and shutdown events in a 30‐day rolling average emissions

calculation will cause exceedances of a 0.050 lb/MMBtu NOx emissions limit.   

Evaluation of Design Changes

Given the Consent Decree operational parameters, S&L determined that physical changes to

the current system design could be made to reduce emissions during steady‐state operations.  

These changes would be extensive, however, and would require SRP to do the following:  

 Install a low‐load temperature control system to allow the SCR control system to

operate at lower loads.

 Add additional catalyst and increase the ammonia injection rate.

 Install a dry sorbent injection control system to address increased sulfuric acid mist and

condensable particulate matter emissions.

 Install a fabric filter baghouse and ID fans to address increased filterable particulate

matter emissions if further detailed design analysis indicates SRP would not be able to

meet its current particulate matter emission limits. It is important to note the recently

                                                           

6 EPA used S&L to perform a complete bottom‐up engineering reassessment of the cost and performance

assumptions for SO2 and NOx emission controls for use in EPA’s Integrated Planning Model (IPM). Refer to Section

VII.A.1 on page 42852. Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Arizona;

Regional Haze State and Federal Implementation Plans; Proposed Rule. Volume 77, Number 140 of the Federal

Register dated July 20, 2012.
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 6

installed ID fans associated with the new FGD system on Unit 2 will most likely not be

able to overcome the additional pressure drop associated with a new fabric filter

baghouse.  

There are significant cost implications with adjusting the current SCR system design to attempt

to meet a lower NOx limit. EPA estimated that a limit of 0.050 lb/MMBtu could be achieved at

an incremental cost‐effectiveness value of $583 per ton. As shown in Table 2 below, this

estimate is considerably lower than the estimate based on S&L’s research.

Table 1: Cost Ranges Associated with NOx Emission Reduction Approach

Total Capital Cost1 Operation &

Maintenance Cost1 Annual Cost2 Cost Effectiveness3

$8,350,000 ‐ 

$117,850,000

$1,461,000 ‐ 

$3,881,000

$2,249,181 ‐ 

$15,005,206

$4,827/ton ‐ 

$32,200/ton

1. S&L provided a range to account for uncertainties related to project timing and the need for additional

engineering and design.

2.Annual costs were calculated assuming an interest rate of 7 percent over 20 years.

3. Cost effectiveness is based on the amount of NOx emissions that are reduced by implementing a 0.050 lb/MMBtu

limit rather than a 0.080 lb/MMBtu limit. Per EPA’s analysis in the proposed rule, the emission reduction was

assumed to be 466 tons per year.7

While cost effectiveness on a dollar per ton basis is appropriate in a BACT analysis, in a BART

analysis it is also necessary to examine and consider the degree of visibility improvement that

can be expected from the investment. EPA’s own analysis in the proposed rule demonstrates

that the visibility improvement from reducing the emission limit from 0.080 lb/MMBtu to 0.050

lb/MMBtu ranges from no improvement whatsoever to only a 0.09 deciview improvement.8

  

Optimistically assuming that these changes will result in at most a 0.09 deciview improvement

overall, the cost of this visibility improvement would range from approximately $25 million ‐ 

$167 million per deciview. This amount is entirely unreasonable, especially given the fact that

the overall visibility improvements are only a small fraction of the deciview improvement that

EPA believes is at the bare threshold of perceptibility to the human eye (i.e., 1 deciview).  

                                                           

7 Refer to Table 22–Coronado Units 1 and 2: EPA’s Control Cost Summary (page 42862). Approval, Disapproval and

Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze State and Federal Implementation Plans;

Proposed Rule. Volume 77, Number 140 of the Federal Register dated July 20, 2012.

8 Refer to Table 23–Coronado Units 1 and 2: EPA’s Visibility Improvements from NOx Controls (page 42863‐42864).

Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze State and

Federal Implementation Plans; Proposed Rule. Volume 77, Number 140 of the Federal Register dated July 20, 2012.
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 7

Even without considering the minuscule or nonexistent modeled visibility improvements

realized by this significant investment, there are other issues with obtaining a lower NOx limit

for Unit 2 that disqualify this approach as BART. Specifically, the potential requirement for a

fabric filter baghouse was a significant point of discussion between EPA and SRP during

negotiations leading to agreement on and entry of the Consent Decree. As a result of this

discussion, SRP was required to specify and procure a low oxidation catalyst for use in the SCR

system in order to avoid the need for dry sorbent injection and a fabric filter baghouse to

mitigate sulfuric acid mist concerns. SRP was required to optimize the performance of the

existing electrostatic precipitators (ESPs) to achieve a particulate matter emission limit of 0.030

lb/MMBtu, which coincidentally is the same limit that EPA is proposing as BART for particulate

matter at CGS. If SRP were required to modify the SCR currently being built to meet a lower  

NOx emission limit of 0.050 lb/MMBtu, SRP may be required to install a fabric filter baghouse

on Unit 2 to ensure that the increased filterable particulate matter emissions do not result in

SRP’s failure to comply with the existing emission limit.  

Modeling of Emissions Limits

While the design changes identified by S&L could achieve a NOx emission limit of 0.050

lb/MMBtu during steady‐state operations under ideal conditions, further analysis by S&L of

realistic operating conditions demonstrates SRP would not be able to meet this limit at all

times, including during periods encompassing low‐load cycling and startup and shutdown

events.     

Specifically, S&L conducted modeling with and without the use of a low‐load temperature

control system while accounting for typical operating scenarios. This modeling demonstrated

that Unit 2 could not comply with a 0.050 lb/MMBtu NOx limit if there was even one start

during the 30‐day averaging period, as shown in Table 1 below.  

Table 2: 30‐Day Rolling Average NOx Emissions Including Unit Startups and Low‐Load Cycling

Modeled Scenario 1 Start Per 30

Operating Days

2 Starts Per 30

Operating Days

3 Starts Per 30

Operating Days

SCR system without low‐load

temperature control system

0.075 lb/MMBtu 0.083 lb/MMBtu 0.091 lb/MMBtu

SCR system with low‐load

temperature control system

0.053 lb/MMBtu 0.063 lb/MMBtu 0.072 lb/MMBtu

S&L rightfully concluded that even with a low‐load temperature control system Unit 2 could not

consistently achieve a NOx emission limit of 0.050 lb/MMBtu when periods of low‐load cycling,

startup, and shutdown are taken into account. These types of operating scenarios are typical

for CGS Unit 2 as documented in Attachment 1b of the S&L report.
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 8

SRP is concerned that the operational changes that would be necessitated by a lower NOx limit

would curtail necessary cycling of Unit 2. As outlined in SRP and EPA discussions during Consent

Decree negotiations, SRP intended to moderate Unit 2 cycling by cycling Unit 1 more

frequently, but this operations strategy could not be implemented if EPA also imposes an SCR‐

based BART limit on Unit 1.9 This issue was one of the reasons that a plant‐wide NOx emissions

cap was instituted in addition to emission limits for each unit. At the time, EPA recognized that

CGS Units 1 and 2 play an important role in ensuring that SRP meets its system reliability needs.  

SCR Catalyst Layer Management Plan & Replacement Schedule

SRP’s current SCR Catalyst Layer Management Plan is based on a catalyst life of 25,000 hours,

which corresponds with SRP’s 3‐year planned outage schedule. Under this plan, catalyst

changes would be scheduled for replacement during these planned outages. Based on SRP’s

design parameter that CGS’ planned maintenance cycle must remain unchanged, SRP does not

envision any changes to the plan as a result of the SCR modifications that would be required to

meet a limit of 0.050 lb/mmBtu.  

SCR Catalyst Design

The current SCR system design utilizes a 3+1 design that includes an extra layer of catalyst

space that is used to maintain compliance with the current NOx emission limit (i.e., 0.080

lb/MMBtu). While the current SCR system design does include a spare layer, this extra layer

was not included with the intention of moving to a lower NOx emission rate at some time in the

future. The spare layer is intended to provide SRP with a measure of redundancy in the SCR

system so as to mitigate non‐compliance risks related to cycling, startup and shutdown.

Because the current NOx emission rate was set as part of the Consent Decree and reflects BACT‐

level emissions, SRP did not imagine that the limit would be ratcheted down even before the

control device was installed.  

Vendor Recommendations and Guarantees

Catalyst volume was determined by SRP’s SCR vendor (Riley) to achieve a full load, steady state

guarantee value NOx emission rate of 0.040 lb/MMBtu with an ammonia slip of 2 parts per

million at 25,000 hours catalyst life. The full load guaranteed NOx emission rate provided by

SRP’s SCR vendor does not include periods of startup, shutdown, load cycling, or upset

conditions. This design margin is necessary to meet the Consent Decree emission limits on a

continuous basis.

   

                                                           

9 Imposing such a limit would also be inconsistent with the Consent Decree and with EPA’s BART rules. Therefore,

it would not represent an appropriate BART determination for Unit 1.
SRP Response to EPA Letter Dated July 27, 2012

August 24, 2012

Page 9

Conclusion

SRP strongly believes that the current low‐NOx burner and overfire air systems on Units 1 and 2

represent BART, as will be discussed further in our future comments on EPA’s proposed

regional haze federal implementation plan. However, if EPA continues to pursue its current

SCR‐based proposal, then EPA must honor the 0.080 lb/MMBtu NOx limit for Unit 2 in the CGS

Consent Decree. We are confident that you will find that the attached analysis by S&L, in

conjunction with the other information supplied with this letter, supports this conclusion.  

If you have any questions or need additional information, please contact me at

Jim.Pratt@srpnet.com or by telephone at (602) 236‐5385.

Sincerely,

Jim Pratt

Senior Director, Baseload Generation

cc:   Colleen McKaughan, EPA Region IX

Henry Darwin, Arizona Department of Environmental Quality

Mike Hummel, SRP

John Sullivan, SRP

Kelly Barr, SRP

Attachments:

Attachment A:  Coronado Unit 2 SCR Equipment Cost Summary

Attachment B:  Coronado Generating Station Unit 2 SCR Review (by S&L)   
ITEM COST (in $1,000s)

CONTRACTS

Contracted Commitments $44,957

Invoiced as of 08/24/12 $15,762

Pending Commitments $24,043

Planned Commitments $6,935

Sub‐Total $75,935

SRP COSTS1

SRP Costs as of 08/24/12 $1,325

Remaining Planned SRP Costs $9,275

Sub‐Total $10,600

Total Costs Incurred to date $17,087

TOTAL COSTS $86,535

1

SRP costs include contract administration, project

management, quality control, and construction

management.

ATTACHMENT A:

CORONADO UNIT 2 SCR EQUIPMENT COST SUMMARY

(as of 08/24/2012)

Pg 1 of 1
Salt River Project (SRP) 

Coronado Generating Station 

Coronado Generating Station Unit 2 SCR Review 

Prepared for: 

Salt River Project 

 FINAL REPORT 

SL-011433 

August 24, 2012 

Prepared by: 

Sargent & Lundy LLC 

55 East Monroe Street 

Chicago, IL 60603-5780 USA 

Page ES-1 

SRP Coronado Generating Station 

Operating the Unit 2 SCR to Achieve a Reduced NOx Emission Limit 

August 24, 2012 

Executive Summary 

Salt River Project (SRP) plans to install a selective catalytic reduction (SCR) nitrogen oxide (NOx) 

control system on its Coronado Generating Station (CGS) Unit 2. The Unit 2 SCR control system, 

which has been engineered, designed, and is currently being fabricated for installation, was designed to 

achieve an enforceable permit limit of 0.080 pounds per million British thermal units (lb/MMBtu) on a 

30-day rolling average, applicable at all times including periods of unit cycling, startup, and shutdown. 

As part of the Arizona Regional Haze rulemaking process, the U.S. Environmental Protection Agency 

(EPA) Region IX requested further documentation from SRP regarding the technical feasibility and 

costs associated with reducing the Unit 2 NOx emission limit from 0.080 lb/MMBtu to 0.050 

lb/MMBtu (30-day rolling average). In response to EPA’s request for additional information, SRP 

requested that Sargent & Lundy LLC (S&L): (1) evaluate CGS Unit 2 operating data to determine the 

feasibility of meeting a controlled NOx emission limit of 0.050 lb/MMBtu (30-day rolling average) 

including periods of unit cycling, startup, and shutdown; and (2) identify physical and operational 

changes to the current SCR design that may allow SRP to meet an enforceable NOx emission limit 

more stringent than its current limit of 0.080 lb/MMBtu (30-day rolling average). 

To address these questions, S&L modeled expected NOx emissions from CGS Unit 2 by applying 

NOx removal efficiencies based on the current SCR design to historical Unit 2 operating data. NOx 

emissions were modeled for several operating scenarios, including full load operation, high-load 

cycling, low-load cycling, unit startups and shutdowns. Based on emissions modeling, S&L found the 

following: 

a. The CGS Unit 2 SCR control system, as currently designed, can achieve a controlled 

NOx emission rate of 0.080 lb/MMBtu (30-day rolling average) including periods of unit 

cycling, startups, and shutdown. 
 Salt River Project (SRP) 

Coronado Unit 2 SCR Review 

August 24, 2012 

 

Page ES-2 

b. The CGS Unit 2 SCR control system, as currently designed, cannot meet an emission 

limit of 0.050 lb/MMBtu (30-day rolling average) due to unit cycling, startups, and 

shutdowns. 

c. At a minimum, SRP would be required to install a low-load temperature control system 

designed to increase flue gas temperatures at the SCR inlet during periods of low-load 

cycling to achieve any additional reduction in average NOx emissions. 

d. Emissions modeling showed that even with the addition of a low-load temperature 

control system, the CGS Unit 2 SCR could not meet an emission limit of 0.050 

lb/MMBtu (30-day rolling average) due to low-load cycling and unit startups. 

e. Additional catalyst would have to be added to the SCR reactor box to achieve additional 

NOx reductions. Consequences of increasing the catalyst volume include, but are not 

necessarily limited to, increased pressure drop across the SCR, increased sulfur-dioxide 

(SO2) to sulfur-trioxide (SO3) oxidation, and increased sulfuric acid mist formation and 

condensible particulate matter (PM) emissions. 

f. Increasing the catalyst volume in the SCR significantly increases the likelihood that SRP 

would be required to install a dry sorbent injection (DSI) control system to reduce 

sulfuric acid mist emissions. 

g. In the event particulate matter (PM) emissions generated in the SCR and DSI control 

systems are not effectively captured in the unit’s existing wet flue gas desulfurization 

(FGD) control system, SRP would also be required to install a fabric filter baghouse 

control system to meet its PM emissions limit. 

h. Capital costs associated with control system modifications vary significantly depending 

on the control systems needed to address increased sulfuric acid mist and particulate 

matter emissions, but are expected to range from a minimum of $8,350,000 (including the 

additional catalyst, low-load temperature control system, and DSI control system, but no 

fabric filter baghouse) to as much as $117,850,000 (including a fabric filter baghouse). 

i. Increased operating and maintenance (O&M) costs will also be incurred to operate the 

SCR control system to achieve lower NOx emissions, and are expected to range from a 

minimum of $1,461,000/yr (including the additional catalyst, increased ammonia 

consumption, and operation of the DSI control system, but no baghouse) to as much as 

$3,881,000/yr (with the baghouse). 
Page i 

ABBREVIATIONS AND ACRONYMS 

Abbreviation or Acronym Explanation 

BART Best Available Retrofit Technology 

BOP Balance of Plant 

Btu British thermal unit 

CEMS Continuous Emissions Monitoring System 

CGS Coronado Generating Station 

DSI Dry Sorbent Injection 

EPA U.S. Environmental Protection Agency 

ESP Electrostatic Precipitator 

FGD Flue Gas Desulfurization 

FIP Federal Implementation Plan 

H2SO4 Sulfuric Acid 

HSESP Hot-Side Electrostatic Precipitator 

hr Hour 

lbs Pounds 

lb/MMBtu Pound per Million British thermal units 

MMBtu Million British thermal unit 

MMBtu/hr Million British thermal units per hour 

MW Megawatt 

MWg Megawatt Gross Output 

NH3 Ammonia 

NOx Nitrogen Oxides 

OEM Original Equipment Manufacturer 

O&M Operations and Maintenance 

PM Particulate Matter 

ppm parts per million 

RH Regional Haze 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

S&L Sargent & Lundy LLC 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

SRP Salt River Project 

w.c. water column 
Page 1 

Introduction 

On July 20, 2012, the U.S. EPA published a rule proposing to approve in part and disapprove in part a 

revision to Arizona’s State Implementation Plan (SIP) to implement the regional haze program. The 

proposed Regional Haze Federal Implementation Plan for the state of Arizona (referred to as the 

“Proposed RH FIP”) addressed provisions in the SIP related to Arizona’s determination of Best 

Available Retrofit Technology (BART) at three generating stations, including CGS. In the Proposed 

RH FIP, EPA proposed a NOx BART emission limit for Coronado Unit 2 of 0.080 lb/MMBtu (30-day 

rolling average). This emission rate is consistent with the NOx emission rate Coronado Unit 2 is 

required to achieve pursuant to an August 12, 2008 consent decree entered into between SRP and 

EPA. 

In the Proposed RH FIP, EPA noted that it was evaluating a more stringent NOx BART emission limit 

for Coronado Unit 2, and EPA calculated the cost-effectiveness of reducing NOx emissions from 

0.080 lb/MMBtu to 0.050 lb/MMBtu. EPA calculated an incremental cost-effectiveness for the 0.050 

lb/MMBtu option of $583/ton, which it concluded made “it a control option that we would consider 

cost-effective.” (77 Fed. Reg. 42863, col. 1). However, EPA acknowledged that it had received 

information from SRP indicating that design and construction of the Unit 2 SCR was well under way, 

and SRP identified several significant costs that may be incurred if it were required to re-design the 

SCR to achieve the lower emission rate. Since these additional costs were not factored into EPA’s 

original cost-effectiveness analysis, EPA acknowledged that the incremental cost-effectiveness of 

requiring Coronado Unit 2 to meet an emission limit of 0.050 lb/MMBtu may in fact be greater than 

indicated by its analysis. EPA noted that it intended to request further documentation in order to 

determine the extent of these costs and how they would affect the cost-effectiveness of the SCR 

control system. 

In a letter to SRP from EPA Region IX dated July 27, 2012, EPA stated that before it could 

incorporate these considerations into a final BART analysis for Coronado Unit 2, further 

documentation was needed regarding both the technical feasibility and cost of meeting the lower limit. 

Information specifically requested by EPA in its July 27, 2012 letter included documentation of the 

design changes to the SCR that would be needed to meet a limit of 0.050 lb/MMBtu for NOx at Unit 2. 
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In response to EPA’s request for information, SRP authorized S&L to perform the following tasks: 

Task 1: Evaluate Coronado Unit 2 operating data to determine the feasibility of meeting a 

controlled NOx emission limit of 0.050 lb/MMBtu (30-day rolling average) given the 

current SCR control system design; and 

Task 2: Evaluate changes to the current SCR design to achieve a more stringent NOx 

emissions limit. 

To complete these tasks, S&L modeled expected NOx emissions from CGS Unit 2 by applying NOx 

removal efficiencies based on the current SCR design to historical Unit 2 operating data. NOx 

emissions were modeled for several operating scenarios, including full load operation, high-load 

cycling, low-load cycling, unit startups and shutdowns. Based on the results of the NOx emissions 

modeling, S&L reviewed the design changes that would be needed to achieve additional NOx emission 

reductions, taking into consideration that engineering and design of the Unit 2 SCR is complete. 

S&L’s evaluation focused on changes that could be incorporated into the existing SCR design without 

changing the physical size of the control system, affecting CGS’ planned maintenance cycle, or 

requiring re-design of the structural steel, foundations, and balance-of-plant (BOP) tie-ins. 

This report provides the results of S&L’s evaluation. 
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ANALYSIS 

Task 1: Evaluate Feasibility of Meeting a Controlled NOx Emission Limit of 0.050 lb/MMBtu 

S&L was asked to evaluate the feasibility of meeting a controlled NOx emission limit of 0.050 

lb/MMBtu (30-day rolling average) given the current design of the CGS Unit 2 SCR control system. 

The Unit 2 SCR control system, which has been engineered, designed, and is currently being 

fabricated for installation, was designed to achieve an enforceable permit limit of 0.080 lb/MMBtu 

(30-day rolling average) applicable at all times including periods of unit cycling, startup, and 

shutdown. 

In order to meet an enforceable NOx emission limit of 0.080 lb/MMBtu, the existing SCR control 

system for CGS Unit 2 is designed to achieve a target NOx emission rate of 0.040 lb/MMBtu at full 

load steady state conditions, at an average inlet NOx emission rate in the range of 0.32 lb/MMBtu and 

short-term inlet NOx rate of 0.39 lb/MMBtu. The ammonia (NH3) injection system was designed to 

provide NH3 based on the NOx removal rates described above. Catalyst volume was determined by 

the SCR vendor to achieve a full load steady state guarantee value NOx emission rate of 0.040 

lb/MMBtu with an NH3 slip of 2 parts per million (ppm) at 25,000 hours catalyst life. The full load 

guarantee value NOx emission rate provided by the SCR vendor does not include periods of startup, 

shutdown, or cycling. 

SCR control systems require a minimum flue gas temperature of approximately 600 o

F for effective 

NOx reduction. At temperatures below 600 o

F, including periods of unit startup, shutdown, cycling at 

low loads, and malfunction, flue gas temperatures may not be high enough for effective NOx control. 

Because SCR control systems do not provide effective NOx control at these operating conditions, the 

SCR must be designed to achieve a full load guarantee value NOx emission rate below the enforceable 

permit limit to allow for periods of startup, shutdown, and cycling. 

To evaluate the feasibility of achieving an enforceable NOx emission rate of 0.050 lb/MMBtu, S&L 

analyzed the most recent eighteen months of available CGS Unit 1 and 2 operating data. Existing 

operating data was evaluated to quantify the affect of unit cycling, startup, and shutdown on the 

controlled NOx emission rate over a 30-day period. To do this, S&L used existing NOx emissions 
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data and flue gas temperatures at the air preheater to calculate: (1) expected full load NOx emissions 

with the SCR; (2) expected NOx emissions with Unit 2 operating in a cycling mode ranging from a 

minimum load of 138 MW-gross output (MWg) up to full load on a daily basis; and (3) expected NOx 

emissions on a 30-day rolling average taking into consideration unit startups and shutdowns. 

Load profiles were generated for CGS Units 1 and 2 using operating data from January 2011 through 

July 2012. Load profile data, NOx emissions, and flue gas temperature data for CGS Unit 1 was 

provided by SRP, amassed from the unit’s data collection system. Load profile data and NOx 

emissions for CGS Unit 2 were generated using continuous emissions monitoring system (CEMS) data 

reported to the EPA’s Clean Air Markets Program Database, and correlated to flue gas temperature 

data available from the unit’s data collection system. Graphs showing the Unit 1 and Unit 2 load 

profiles are included in Attachments 1a and 1b, respectively. The load profile graphs in Attachments 

1a and 1b show periods of start-up and shutdown, as well as frequent cycling of the units. 

Load profiles developed for CGS Units 1 & 2 were used to predict NOx emissions after the installation 

of the SCR control system on Unit 2. Two NOx emission scenarios were evaluated. The first scenario 

included installation of the SCR only. The second scenario included both the SCR and a low-load flue 

gas temperature control system. 

The purpose of the low-load flue gas temperature control system would be to increase flue gas 

temperatures at the SCR inlet to approximately 600 °F during periods of low-load cycling, startup, and 

shutdown. A minimum SCR operating temperature is required to avoid the formation of ammonium 

salts, primarily ammonium sulfate/bisulfate, which is formed by the reaction of SO3 and unreacted 

NH3. Ammonium salt deposition can blind the catalyst surface, and result in a significant reduction in 

catalyst activity and NOx removal performance. Ammonium salt formation can only be avoided by 

operating the SCR system above the formation temperature or by halting the injection of NH3 when 

temperatures are below design levels. The guaranteed Unit 2 SCR low operating temperature is 599 

o

F. 

In the first scenario, the use of the SCR was limited to those data points where the measured air 

preheater temperature was greater than 599 °F, the inlet temperature needed for effective NOx control 

guaranteed by the SCR original equipment manufacturer (OEM). Operating data indicate that an air 
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preheater temperature of 599 °F corresponds to a steam turbine generator outlet of approximately 270 

MWg. NOx emissions associated with the SCR-only scenario were calculated for two load cycling 

profiles (described below). 

In the second scenario, the use of the SCR was again limited to those data points where the minimum 

required temperature was achieved. However, since this scenario included a low-load temperature 

control system, minimum inlet temperatures to the SCR could be achieved for loads down to 

approximately 138 MWg, assuming the unit had enough operating hours to provide flue gas heating. 

As with the first scenario, NOx emissions with the SCR plus low-load temperature control system 

scenario were calculated for two load cycling profiles (described below). 

Task 1: Load Cycling Profiles 

NOx emissions from CGS Unit 2 were modeled for two load cycling profiles. Cycling profiles 

used for the NOx evaluation are shown in Attachments 2, 3 and 4. 

The first cycling profile is based on load data from mid January 2012 to early March 2012. 

During the winter Unit 2 typically operates above 270 MWg and the unit cycles between 

approximately 60% and 100% of its full load. This load profile is referred to as the “high-load 

cycling” profile. A detailed load profile for this period is shown in Attachment 3. Continuous 

operation above 270 MWg would allow the unit to operate the SCR without use of a low-load 

temperature control system, as temperatures at the SCR inlet typically remain at or above 599 °F. 

NOx emissions during the high-load cycling profile were calculated based on the following 

assumptions: 

a. NOx emissions will be controlled to 0.050 lb/MMBtu when the unit is increasing in load 

due to the lag in the delivery of additional ammonia and adsorption on the catalyst. 

b. NOx emissions will be controlled to 0.040 lb/MMBtu when the unit is decreasing in load 

due to the residual ammonia on the catalyst surface. 

c. The SCR will provide no additional NOx control, beyond that provided by the low-NOx 

burners (i.e., 0.320 lb/MMBtu average), when the unit is operating below 270 MWg. 

The second cycling profile analyzed for Unit 2 occurred from mid March 2012 to the beginning of 

May 2012. Unit loads during this period of time ranged from approximately 138 MWg to full 
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load; therefore, this load profile is referred to as the “low-load cycling” profile. A detailed load 

profile for this period is shown in Attachment 4. During a low-load cycling period the unit will 

not consistently operate above 270 MWg, and economizer outlet temperatures will drop below the 

required 599 oF for effective NOx control. Without using a low-load temperature control system 

to increase flue gas temperature at the SCR inlet, ammonia feed to the SCR will be shut off 

whenever the unit drops below 270 MWg to prevent the formation of ammonium salts. NOx 

emissions during the low-load cycling profile were calculated based on the same assumptions used 

for the high-load profile. 

Task 1: Load Cycling Profiles - Results 

NOx emission rates developed from the high- and low-load cycling scenarios were used to model 

the 30-day rolling average NOx emissions rate for CGS Unit 2. In accordance with the monitoring 

and recordkeeping requirements in the CGS’ Title V Operating Permit (Permit No. 52639), the 30-

day rolling average was calculated by dividing the total NOx emitted (in pounds during the last 30 

unit operating days) by the total heat input (in MMBtu/hr during the last 30 unit operating days). 

Days where no heat input to the boiler was reported were excluded from the calculation (i.e., they 

were not considered operating days). Calculations were performed based on the reported load 

profile for Unit 2. In addition, calculations were performed based on the load profile for Unit 1, 

but using the modeled NOx emissions from Unit 2. 

Graphs showing the modeled 30-day rolling average NOx emissions are included in Attachments 

5a and 5b. Attachment 5a shows the 30-day rolling average NOx emissions using the Unit 1 load 

profile and the modeled Unit 2 NOx emission rates. Attachment 5b shows the 30-day rolling 

average NOx emissions using the Unit 2 load profile and the modeled Unit 2 NOx emission rates. 

It can be seen from the emission calculations summarized in Attachments 5a and 5b, that CGS 

Unit 2 would meet a controlled NOx emission rate of 0.080 lb/MMBtu (30-day rolling average) 

without installing a low-load temperature control system under practically all operating scenarios, 

including periods of startup and shutdown. The only period of time modeled NOx emissions 

exceed 0.080 lb/MMBtu (30-day rolling average) occur during short periods of time when the unit 

cycled extensively at loads below 270 MWg coupled with a unit shutdown/startup. SRP could 
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respond to these periods by increasing NH3 injection to the SCR control system for short periods 

of time, or by cycling the other CGS unit (Unit 1) instead. However, NH3 injection rates could not 

be increased for extended periods of time due to the increased potential for ammonium bisulfate 

formation, catalyst blinding, and air preheater plugging. 

Modeled NOx emissions shown in Attachments 5a and 5b also indicate that Unit 2 NOx emissions 

would exceed 0.050 lb/MMBtu (30-day rolling average) for extended periods of time without the 

low-load temperature control system. It is apparent that SRP would have to design, install, and 

operate a low-load flue gas temperature control system to meet any permit limit more stringent 

than the current limit of 0.080 lb/MMBtu. Even with the low-load temperature control system, 

modeled NOx emissions exceed 0.050 lb/MMBtu (30-day rolling average) during periods of lowload cycling (i.e., when the unit cycles below approximately 138 MWg) and during periods of 

frequent outages. This can be seen graphically in Attachment 5a for a 30-day period in mid-2011 

and in Attachment 5b for a 30-day period around April 2012. Comparing these periods with the 

load profiles in Attachments 1a and 1b, it can be seen that during these periods the unit was 

frequently cycling from full load down to loads as low as 100 MWg and that an outage was taken. 

Task 1: Startup Profiles 

Startup profiles were also modeled to determine how unit startups affect the 30-day rolling average 

NOx emissions rate. Number 2 fuel oil is used as the initial startup fuel for GGS Unit 2 to warm 

the boiler and turbine. Once the boiler and turbine are sufficiently warm, the first mill is brought 

on-line and coal is introduced to the boiler. Coal and fuel oil are co-fired, primarily for flame 

stability, as the unit is ramped up to approximately 150 MWg, at which point the unit will fire coal 

exclusively, and the unit is ramped up to full load. During unit startup, ammonia injection cannot 

occur until flue gas temperatures at the SCR inlet reach 599 o

F. The SCR would provide no 

additional NOx control prior to reaching sufficient flue gas temperature. 

NOx emissions during startup were modeled based on the Unit 2 startup profile shown in 

Attachment 6. Two startup periods were modeled: (1) starting with initial fuel oil firing and 

ending when the first mill is brought on-line and coal is introduced to the boiler; and (2) starting 

with initial coal firing and ending when the economizer outlet temperature reaches 599 o

F. 
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Based on the startup profile shown in Attachment 6 for a cold startup (defined as greater than 96 

hours off-line), fuel oil is fired exclusively for approximately 18 to 22 hours before coal is 

introduced to the boiler. This period of time will be shorter, in the range of 8 to 10 hours, for a 

warm unit restart (defined as less than 48 hours off-line). Startup continues for an additional 10 to 

12 hours following initial coal firing to reach 270 MWg output and an air heater outlet temperature 

of 599 oF. This period of time will be shorter for a warm restart. Total startup time, from initial 

oil firing to 270 MWg output (assuming no operating issues, unit trips, or restarts) ranges from 30 

to approximately 36 hours. 

NOx emissions were modeled for both startup periods based on the load (MWg), temperature (oF), 

and NOx emissions data (lb/MMBtu) shown in Attachment 6. Heat input-weighted average NOx 

emission rates were determined for each startup period by dividing total NOx emitted during the 

startup period (in pounds) by the total heat input (in MMBtu) over that time period. During the 

first period the unit had a heat input-weighted average NOx emission rate of 0.145 lb/MMBtu per 

hour. During the second period the unit had a heat input-weighted average NOx emission rate of 

0.289 lb/MMBtu per hour. These heat input-weighted average emission rates were used to model 

the affect of unit startups on the 30-day rolling average NOx emission rate. 

Task 1: Shutdown Profiles 

Shutdown profiles were also modeled to determine how unit shutdowns affect the 30-day rolling 

average NOx emissions rate. During unit shutdown ammonia injection would cease once flue gas 

temperatures at the SCR inlet drop below 599 o

F. CGS Unit 2 shutdown profiles were analyzed 

using 15-minute SRP supplied operating data. Unit 2 shutdown data, shown graphically in 

Attachment 7 (May 3 – May 5, 2012), were used to profile NOx emissions during a unit shutdown. 

Analysis of the shutdown data, including unit load (MWg), air heater inlet temperature (oF), and 

NOx emission rate (lb/MMBtu), reveals that the air heater inlet temperature stays above 599 oF 

from the point of unit turndown until the unit reaches a load approaching 138 MWg. Once the air 

heater inlet temperature is below 599 oF, the SCR will not provide effective NOx control. 

NOx emissions were modeled at 0.040 lb/MMBtu during initial turndown of the boiler (based on 

the assumptions listed above for the cycling profiles). From the period of time that the air heater 
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inlet temperature is below 599 oF (approximately 138 MWg) until the unit is no longer producing 

power (0 MW), NOx emissions averaged approximately 0.277 lb/MMBtu. This emission rate 

continues for approximately 2 to 2.5 hours as the unit turns down from 138 to 0 MW. 

It was also determined that there would be no significant difference in NOx emissions during a 

unit shutdown for the SCR plus low-load temperature control system scenario. Although the lowload temperature control system may allow the SCR to operate at somewhat lower loads during 

shutdown, there is a threshold below which NH3 injection to the SCR would have to cease. As 

determined in the low-load cycling profile analysis, flue gas temperatures at the SCR inlet will 

drop below 599 o

F at approximately 138 MWg even with the low-load temperature control system. 

Therefore, even with the low-load temperature control system, NOx emissions will average 

approximately 0.277 lb/MMBtu for the 2 to 2.5 hour period as the unit ramps down from 138 to 0 

MW. 

Task 1: Startup/Shutdown Profile Results 

To quantify the potential impact of unit startups and shutdowns on the 30-day rolling average NOx 

emission rate, S&L modeled NOx emissions over a 30-day period based on the following 

assumptions: 

a. NOx emissions were modeled using the calculated heat input-weighted average NOx 

emission rates for each startup period and using the startup durations shown in Attachment 

6. 

b. To account for all typical operating scenarios, for the remainder of the 30-day period S&L 

assumed Unit 2 would operate in a low-load cycling mode. 

A 30-day rolling average NOx emission rate was calculated assuming one, two, and three startups 

within a 30-day operating period. As expected, the number of starts in a given 30-operating day 

period had a significant affect on the calculated 30-day rolling average NOx emissions rate. 

Startup emission impacts were modeled for the SCR only scenario (i.e., no low-load temperature 

control system) and the SCR combined with a low-load temperature control system scenario. 

Results of the startup evaluations are summarized in Table 1. 
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Table 1 

30-Day Rolling Average Including Unit Startups* 

Modeled Scenario 1 Start Per 30 

Operating Days 

2 Starts Per 30 

Operating Days 

3 Starts Per 30 

Operating Days 

SCR with no low-load 

temperature control system 0.075 lb/MMBtu 0.083 lb/MMBtu 0.091 lb/MMBtu 

SCR with a low-load 

temperature control system 0.053 lb/MMBtu 0.063 lb/MMBtu 0.072 lb/MMBtu 

* NOx emissions for the remainder of the 30-day operating period were modeled based on the low-load cycling 

scenario. 30-day rolling average emission rates will vary somewhat depending on the time of day unit startup 

begins. 

Results summarized in Table 1 are based on the 34-hour startup profile shown in Attachment 6. It 

should be noted that more significant impacts to the 30-day rolling average NOx emission rate 

would occur for a longer startup, or if the boiler trips during startup requiring a second startup 

within a short period of time. Such a scenario would not be unusual for a large coal-fired boiler. 

For example, plant operating data from CGS Unit 1 from April 12-15, 2012 shows an extended 

startup period with two starts. For that specific startup, air heater gas inlet temperatures did not 

reach 599 o

F for approximately 94 hours after initial coal firing. S&L did not model impacts 

associated with longer startup times, however higher 30 day-rolling average NOx emissions would 

result from these longer startup times. 

Task 1: Summary of Results 

Based upon the analyses performed, CGS Unit 2 would be expected to meet its existing permit 

limit of 0.080 lb/MMBtu (30-day rolling average) under practically all operating scenarios, 

including periods of startup and shutdown. The only periods of time modeled NOx emissions 

exceed 0.080 lb/MMBtu (30-day rolling average) occur during short periods of time when the unit 

cycled extensively at loads below 270 MWg coupled with a unit shutdown/startup. SRP could 

respond to these periods by increasing NH3 injection to the SCR for short periods of time. Thus, 

including periods of startup and shutdown, CGS Unit 2 would be expected to comply with an 

emission limit of 0.080 lb/MMBtu (30-day rolling average) with the SCR and no low-load 

temperature control system. 
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A low-load temperature control system would be required to comply with a more stringent NOx 

emission limit. Even with a low-load temperature control system, modeled NOx emissions from 

CGS Unit 2 exceed 0.050 lb/MMBtu (30-day rolling average) when periods of low-load cycling 

and startup are taken into consideration. 

Task 2: Evaluate Changes to the Current SCR Design to Achieve a More Stringent NOx 

Emission Limit 

Task 2 included an evaluation of the design and operational changes that SRP would need to consider 

implementing to achieve a more stringent NOx emission limit. Based on the NOx emissions modeling 

completed in Task 1, SRP would need to modify the current design of the Unit 2 SCR control system 

to accept any enforceable permit limit below the current limit of 0.080 lb/MMBtu (30-day rolling 

average). 

As an initial change, SRP would have to design, install, and operate a low-load temperature control 

system to allow the SCR control system to operate at lower loads. In addition, SRP would have to 

obtain a guarantee from the SCR OEM for a full load steady state guarantee value of 0.030 lb/MMBtu 

in lieu of the current 0.040 lb/MMBtu guarantee. Based on S&L’s evaluation of historical CGS Unit 1 

& 2 operating data, the following design changes would have to be evaluated and implemented, if 

available, to obtain the more stringent full load NOx guarantee value: 

a. Add additional catalyst to the existing reactor box and increase the NH3 injection rate in 

an effort to achieve a full load guarantee value NOx emission rate of 0.030 lb/MMBtu. 

b. Maintain the catalyst life at 25,000 hours with 2 ppm NH3 slip at the end of the catalyst 

life to correspond with the unit’s planned outage schedule. 

c. Account for additional pressure drop through the catalyst. 

d. Install a DSI control system to address increased SO2 to SO3 conversion, and increased 

sulfuric acid mist and condensible particulate matter emissions. 

e. Evaluate the need to retrofit a fabric filter baghouse to ensure continued compliance with 

the unit’s PM emission limit. 

Task 2: Control System Modifications 

Without redesigning the entire SCR control system and BOP equipment, and without altering the 

unit’s planned maintenance cycle, the only options available to SRP to achieve lower NOx 
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emissions on CGS Unit 2 include the installation of a low-load temperature control system, adding 

additional catalyst to the existing SCR reactor box, and increasing the NH3 injection rate to 

provide additional NOx removal. This approach would maintain the current 25,000 hour catalyst 

design life and allow SRP to incorporate catalyst changes into its existing 3-year planned 

maintenance cycle. 

Increasing the catalyst volume will result in increased SO2 to SO3 conversion across the SCR. SO3

can react with water to form sulfuric acid mist (H2SO4) or with unreacted NH3 to form ammonium 

salts. Sulfuric acid mist and ammonium salts are classified as condensible particulates, and can 

increase total PM emissions from the unit. The facility’s existing Title V Operating Permit 

requires that SRP conduct stack testing after installation of the Unit 2 SCR to determine if H2SO4

emissions are consistently less than or equal to 0.006 lb/MMBtu. If stack test results demonstrate 

that Unit 2 H2SO4 emissions exceed 0.006 lb/MMBtu, SRP must prepare an H2SO4 minimization 

analysis that evaluates further options, including but not limited to reagent/sorbent injection, to 

reduce emissions to 0.005 lb/MMBtu or less, while maintaining PM emissions within 80% of 

unit’s 0.030 lb/MMBtu limit. 

Installation of the additional catalyst and the resulting increase in SO2 to SO3 conversion makes it 

significantly more likely that H2SO4 emissions from CGS Unit 2 will exceed 0.006 lb/MMBtu. 

Assuming H2SO4 emissions exceed 0.006 lb/MMBtu, SRP would be required to install a DSI 

control system to mitigate H2SO4 emission increases. The DSI control system would inject 

sorbent after the unit’s hot side electrostatic precipitators and air heater to capture the acid gas. 

To ensure continued compliance with the unit’s PM emission limit, particulates generated in the 

SCR and DSI control systems would have to be collected in the unit’s existing wet FGD control 

system. If particulate matter emissions exceed the applicable permit limits, SRP’s only option 

would be to install a fabric filter baghouse upstream of the unit’s wet FGD. Conceptual design 

layouts show that the installation of a fabric filter baghouse on CGS Unit 2 would be a 

complicated retrofit project and would require significant modifications to the existing unit. 

The need for DSI and fabric filter baghouse controls could only be determined after the SCR is 

installed and initial operating tests are performed. A detailed demonstration plan would be 
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required to determine H2SO4 emissions, demonstrate the effectiveness of the DSI control system, 

and determine whether a fabric filter baghouse would be required for PM control. 

Task 2: Control System Modifications - Capital Costs 

Capital costs associated with redesigning the SCR to achieve more aggressive NOx control include 

the cost of installing the low-load temperature control system, increased capital costs associated 

with the initial catalyst fill, and capital costs associated with SO3 and PM emission controls. The 

total increase in capital costs will range from a minimum of $8,350,000 (including the additional 

catalyst, low-load temperature control system, and DSI control system, but no fabric filter 

baghouse) to as much as $117,850,000 (including a fabric filter baghouse). Capital costs include 

the following: 

Additional Catalyst $350,000 to $1,600,000 

Low-Load Temperature Control System $2,000,000 to $3,000,000 

SO3 Control System $6,000,000 to $7,000,000 

Structural Modifications Not Required 

Fabric Filter Baghouse & ID Fans(1) $85,000,000 to $106,250,000 

(1) The new ID fans recently installed by SRP as part of the new FGD on CGS Unit 2 are unlikely 

to be sufficient to overcome the additional pressure drop associated with a new fabric filter 

baghouse. 

The wide range additional catalyst cost shown above depends on project timing. The lower cost 

($350,000) is associated with adding approximately 10% more catalyst to the existing reactor box 

during initial installation. This can be achieved by installing longer catalyst elements into the SCR 

reactor box, and can be implemented only if this change can be specified prior to commencing 

catalyst fabrication. However, once catalyst fabrication starts, the only option would be to add a 

partial fourth catalyst layer in the space currently reserved for a fourth catalyst layer as part of the 

initial fill. This option increases the initial capital cost to approximately $1,600,000, including 

installation costs. 

Similarly, a range of costs is shown for the low-load temperature control system, the SO3

mitigation system, and the fabric filter baghouse. Additional engineering and design would be 

required for all of these systems to better define the costs. 
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Task 2: Control System Modifications - Operating & Maintenance Costs 

O&M costs associated with the design and operating modifications described above include an 

incremental increase in the catalyst replacement cost to account for the additional catalyst, an 

incremental increase in the ammonia consumption rate based on the additional NOx removed, 

increased parasitic energy consumption associated with the increased pressure drop across the 

catalyst bed, sorbent consumed in the SO3 control system, increased parasitic energy consumption 

and bag/cage replacement costs associated with the fabric filter baghouse (if required). 

Total increased annual O&M costs will range from a minimum of $1,461,000/yr (without the 

fabric filter baghouse) to approximately $3,881,0000/yr (with the fabric filter baghouse). Annual 

O&M costs include the following: 

Incremental Catalyst Replacement Cost(1) $193,000 to $343,000 

Incremental Ammonia Cost(2) $28,000 

Incremental Pressure Drop Across SCR(3) $40,000 to $110,000 

DSI Control System Operating Costs(4) $1,200,000 

Fabric Filter Baghouse Operating Costs(5) $2,200,000 

(1) The annual catalyst replacement cost will be a function of the approach taken to increase the 

volume of catalyst. Incremental catalyst replacement costs are based on the increased catalyst 

volume and assuming 11 replacements over the initial 20-operating years of the control system. 

(2) Incremental ammonia costs reflect the increased ammonia consumption associated with additional 

NOx reduction, and is calculated based on 0.01 lb/MMBtu NOx removal @ $400/ton NH3. 

(3) Operating costs associated with increased pressure drop across the SCR depends on which catalyst 

option is implemented, and will range from 0.3” to approximately 0.8” w.c. across the catalyst. 

(4) DSI control system operating costs include sorbent costs for acid gas control. 

(5) Fabric Filter Baghouse operating costs include routine bag & cage replacement costs, auxiliary 

power costs, and fixed maintenance material and labor costs. 

Schedule Impacts 

The CGS Unit 2 SCR control system has been engineered and designed, and contracts have been 

awarded for control system fabrication. The current SCR control system design does not include a 

low-load temperature control system, an SO3 mitigation system, or a fabric filter baghouse. 

Implementation of any of these systems would require additional engineering, design, procurement, 

and fabrication phases that would be difficult to complete in advance of the planned installation date 
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for the Unit 2 SCR, with is scheduled to be completed during SRP’s next planned outage in Spring 

2014. Typical project durations to bring these major pieces of equipment on-line would be: 

 Low-Load Temperature Control System: 14 to 24 months 

 SO3 Mitigation System (DSI): 18 to 30 months 

 Fabric Filter Baghouse & ID Fans: 36 to 42 months 

A more detailed analysis of these control systems would need to be evaluated to determine their 

feasibility and to define an achievable implementation schedule. 

In addition, there are current significant scheduling constraints that could affect costs associated with 

re-designing the Unit 2 SCR. As noted above, once fabrication of the SCR catalyst system begins, 

design changes needed to increase the catalyst volume become much more expensive. At the time of 

this report, it is our understanding that the catalyst supplier has been issued a purchase order and is free 

to begin fabrication at any time. 
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August 24, 2012 

ATTACHMENTS 

Attachment Description 

1a Unit 1 Load Profile (1/11 – 7/12) 

1b Unit 2 Load Profile (1/11 – 6/12) 

2 Unit 2 Load Cycling 

3 Unit 2 High-Load Cycling Model 

(60% - 100% Gross Load Cycling) 

4 Unit 2 Low-Load Cycling Model 

(40% to 100% Gross Load Cycling) 

5a 30-Day Rolling Average Model 

(Dates from Unit 1 Load Profile) 

5b 30-Day Rolling Average Model 

(Dates from Unit 2 Load Profile) 

6 Unit 2 Startup Data from 5/1/3/2012 

7 Unit 2 Shutdown Data from 5/3 to 5/5/2012 
0

50

100150200250300350400450500

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012 7/10

Load (MWgross)

Attachment 1a ‐ Unit 1 Load Profile (1/11‐7/12)
0

50

100150200250300350400450500

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012 7/10

Load (MWgross)

Attachment 1b ‐ Unit 2 Load Profile (1/11‐6/12)
0

50

100150200250300350400450500

Load (MWgross)

Time

Attachment 2 ‐ Unit 2 Load Cycling

High Cycling Low Cy
0

50

100150200250300350400450500

1/12/12 1/17/12 1/22/12 1/27/12 2/1/12 2/6/12 2/11/12 2/16/12 2/21/12 2/26/12 3/2/12 3/7

Load (MWgross)

Date

Attachment 3 ‐ Unit 2 High Load Cycling Model

(60‐100% Gross Load Cycling)
0

50

100150200250300350400450500

3/12/12 3/17/12 3/22/12 3/27/12 4/1/12 4/6/12 4/11/12 4/16/12 4/21/12 4/26/12 5/1/12 

Load (MWgross)

Date

Attachment 4 ‐ Unit 2 Low Load Cycling Model

(40‐100% Gross Load Cycling)
0

0.020.040.060.08

0.1

0.12

11/18/2010 2/26/2011 6/6/2011 9/14/2011 12/23/2011 4/1/2012 7/10

NOx Emissions (lb/MMBtu)

Attachment 5a ‐ 30‐Day Rolling Average Model

(Dates from Unit 1 Load Profile)

SCR, NSCR, Ec
0

0.020.040.060.08

0.1

0.12

11/18/2010 0:00 2/26/2011 0:00 6/6/2011 0:00 9/14/2011 0:00 12/23/2011 0:00 4/1/2012 0:00 7/10/20

NOx Emissions (lb/MMBtu)

Attachment 5b ‐ 30‐Day Rolling Average Model

(Dates from Unit 2 Load Profile)

SCR, No Low Load Temperature CSCR, Low Load Temperature Cont
0

100200300400500600700800

18:00 0:00 6:00 12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00

Load (MWgross)

Temp (F)

Time (hrs)

Attachment 6 ‐ Unit 2 Start‐Up Data from 5/13/2012

NOx avg:

0.29

lb/MMBtu

NOx avg:

0.15

lb/MMBtu

Coal

Starts

Fuel Oil

Starts

Temperature

Reached
0

00000000

0

100200300400500600700800

5/3/12 19:12 5/4/12 0:00 5/4/12 4:48 5/4/12 9:36 5/4/12 14:24 5/4/12 19:12 5/5/12 0:00

Load (MWgross)

Temperature (F)

Attachment 7 ‐ Unit 2 Shutdown Data from 5/3‐5/5/12

SCR Operaton

Discontinued

Unit Shutdown

Complete