### www.AndoverTechnology.com 1 

### October 23 , 2012

To: Doug Grano

Fm: Jim Staudt

Re: Review of E stimated C ompliance Costs for Wyoming Electricity Generating Units ( EGUs )

Attachment: Microsoft Excel Workbook WY EGU BART_RP Costs_20121019.xlsx

On June 4, 2012 (77 FR 33022) , EPA proposed the Wyoming Regional Haze Federal implementation plan.

Below is Andover Technology Partners’ evaluation of the cost of nitrogen oxides NOx emission controls

for particular power pl ants in Wyoming subject to EPA’s proposed rulemaking . These plants and units

include:

• Dave Johnson, units 1

- 4

• Laramie River Station, units 1, 2, and 3

• Naughton units 1, 2 and 3

• Wyodak

Note that Dave Johnston Units 1

- 2 are not subject to Best Available Re trofit Technology (BART)

requirements, but the cost of compliance for these units has been evaluated here under reasonable

progress reguirements.

For each unit, estimates were made for the following technologies, where applicable:

• Combustion Controls, includ ing Low NOx Burners (LNBs) with Overfire Air (OFA)

• Selective Non

- Catalytic Reduction (SNCR)

• Selective Catalytic Reduction (SCR)

Estimates were based upon an initial average annual NOx level equal to 2001

- 2003 historical rates

(average of annual aver age for each of the three years ) when advanced combustion controls were not in

use at these units. Emission rates with combustion controls were estimated from more recent data: the

lower of 2011 annual emission rate or the average of 2012 Q1 and Q2, or

, w here there is no available

operatin g data with combustion controls, a projected emission rate. 2001

- 2003 historical data w ere

also used to estimate annual heat input and the associated capacity factor for each unit ; these estimates

are used in all calculations.

In estimating the cost of controls, the following were considered:

• IPM Cost models

• US EPA Air Pollution Control Cost Manual 1



### • Data provided by the facilities

• Other data that ha ve been published and are described in more detai l

1 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B

- 02

- 001

### www.AndoverTechnology.com 2 The BART guidelines recommend use of the EPA Air Pollution Control Cost Manual, and the

methodology use d here for estimating cost s is consistent with the recommendations in the manual,

such as inclusion of taxes, insurance and administrative costs, and the use of overnight cost 2 

### for capital

cost.

Combustion Controls

For combustion controls, if the capital and operating cost estimates by the users were avail able, they

were used. If not, IPM models were used to estimate capital and operating costs of combustion

controls

. 3 

### Percent reduction and tons of NOx removed w ere based upon actual emission rates after

control installation or projected emission rates if actual emission rates were not available. Fixed and

v ariable operating costs of combustion con trols were estimated from IPM algorithms.

SNCR

For SNCR

, capital cost is assumed to be $20/kW. According to the 2008 Institute of Clean Air

Companies’ SNCR White Paper, 4 

### “Typical SNCR capital costs for utility applications are $5

- $15/kW,

vendor scope, which corresponds to a maximum of $20 /kW if balance

- of

- plant capital requirements are

included.” This is also consistent with my personal experience, having worked with t he following

electric utilities and power plants on their SNCR installations as a consultant or as a past employee of

Research

- Cottrell and Fuel Tech

– suppliers of SNCR systems.

• Constellation Energy

– C P Crane units 1&2 and Wagner Unit 2 5



### • Conectiv

– Edge Moor unit 3 and Indian River 6



### • New England Power

– Salem Harbor Station 7



### • Montaup Electric

– Somerset Unit 8 8



### And, I have also published reports that describe the cost and application of technologies used for control

of NOx, including SNCR

. 9

, 10

2 “Overnight” costs means capital costs are expressed in constant dollars for the base year, excluding Allowance

for Funds Used During Construction (AFUDC)

3 Documentation for EPA Base Case ver 4.10 Chapter 5, Emission Control Technologies;

http://www.epa.gov/airmarkt/progsregs/epa

- ipm/BaseCasev410.html#documentation , pg 5

- 7

4 Institute of Clean Air Companies, “White Paper

– Selective Non

- Catalytic Reduction ( SNCR) for Controlling NOx Emissions”,

February 2008 , p 7.

5 Staudt, J, Hoover, B., Trautner, P., McCool, S., Frey, J., “Optimization of Constellation Energy’s SNCR System at Crane Units 1

and 2 Using Continuous Ammonia Measurement”, The MEGA Symposium, Baltimore, MD, August 31

- September 2,

2010

6 Staudt, J.E., Kehrer, K., Poczynek, J., Cote, R., Pierce, R., Afonso, R., Miles, D., and Sload, A., "Optimizing Selective Non

- Catalytic

Reduction Systems for Cost

- Effective Operation on Coal

- Fired Electric Util ity Boilers", presented at ICAC Forum '98,

Durham, NC, March 19

- 20, 1998.

7 Staudt, J.E., Casill, R.P., Tsai, T., and Arigiano, L., "Commercial Application of Urea SNCR for NOx RACT Compliance on a 112

MWe Electric Utility Pulverized Coal Boiler" presented at the 1995 EPRI/EPA Joint Symposium on Stationary

Combustion NOx Control, Kansas City, May 16

- 19, 1995

8 Ibid

9 Staudt. J. and M J Bradley & Associates, for the Northeast States for Coordinated Air Use M anagement, “Control Technologies

to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power Plants”, March 31, 2011

10 "Status Report on NOx: Control Technologies and Cost Effectiveness for Utility Boilers", report for Northeast States for

### www.AndoverTechnology.com 3 Therefore, $20/kW provides a reasonable estimate for the capital cost of SNCR. Furthermore, due to

the low capital cost of SNCR, the operating cost

– especially reagent cost

– is the much mo re important

component of cost.

SNCR reagent consumption and the level of NOx reduction are very dependent upon a number of

factors

– such a s initial NOx level and furnace temperature s

. It was not possible to evaluate all of the

relevant factors because detailed furnace characteristics were not available. Figure 1 is an example of

test data from an SNCR optimization program on a pulverized coal fired boiler that shows NOx reduction

and chemical utilization versus Normalized Stoichiometric Ratio (NSR

– a measure of chemical treatment

rate) . Chemical utilization equals p er cent reduction divided by NSR and is a measure of the efficiency of

reagent use. The data include data from optimized as well as unoptimized configurations , whi ch is why

some of the data points fall below the curves . The curves that would be developed for any given unit

will vary from one unit to another and, while having similar shapes as those in Figure 1, may have

somewhat different values. For the purpose of making an estimate of reagent consumption for the

Wyo ming pulverized coal units it was assumed that the chemical utilization was 25% and that NOx

reduction diminished with lower NOx concentrations

– 30% for NOx greater than 0.25 lb/MMBtu, 25%

for NOx between 0.20 and 0.25 lb/MMBtu, and 20% for NOx under 0.2 0 lb/MMBtu. This is expected to

provide a reasonable estimate of NOx reduction and reagent consumption.

Other elements of SNCR variable operating cost and fixed operating cost are estimated using IPM

algorithms.

Figure 1. NOx Reduction and Reagent

Util ization versus reagent

treatment rate in NSR for a

Pulverized Coal Fired Boiler

during an SNCR optimization

program 11

(data points plotted

below the curve s are at

unoptimized conditions)



### SCR

Selective Catalytic NOx Reduction (SCR)

capital cost is estimated using the IPM

algorithms with retrofit factors

adjusted on a unit by unit basis. The retrofit factor is a subjective factor used to account for the

estimated difficulty of the retrofit that is unique to the facility. Because site visits were not possible, the

retrofit factor was estimated from satellite images that provide some insight to the configuration of the

units and degree of congestion around the site and in the vicinity of where th e SCR would be installed.

These factors impact the ability to locate large cranes on the site

– that impact how the SCR is

Co ordinated Air Use Management and Mid Atlantic Regional Air Management Association, June 1998.

11 Staudt, J.E., Kehrer, K., Poczynek, J., Cote, R., Pierce, R., Afonso, R., Miles, D., and Sload, A., "Optimizing Selective Non

Catalytic Reduction Systems for C ost

- Effective Operation on Coal

- Fired Electric Utility Boilers", presented at ICAC

Forum '98, Durham, NC, March 19

- 20, 1998.

### www.AndoverTechnology.com 4 assembled (are large sections lifted into place or is the SCR “stick built”), how much ductwork is needed,

if the SCR must be built on to a large , elevated steel structure or can be built near the ground , and if

other equipment must be relocated to accommodate the space of the SCR. When using the IPM capital

cost model

, r etrofit difficulties associated with an SCR may result in capit al cost increases of 30 to 50%

over the base model. 12



### In addition, historical industry cost data w ere considered to determine if the costs were reasonable in

t he context of what has been reported at other facilities

. 10 , 13

, 14 

### Estimates were also compared against

estimates provided by the facility owners (both December 2007 and March 2008 estimates for Dave

Johnston, Naughton and Wyodak, and June 2008 for Laramie River ). For Dave Johnston, Naughton and

Wyodak units the estimated capital cost of SCR provided by the owners for the five units increased by

roughly 60% between these two dates , and I did not see an explanation for the increase in cost

.

Table 1

. Owner’s estimates of capital cost for SCR *

(s ee workbook: WY EGU BART_RP Costs_ 20121019 .xlsx) 15

Plant Dave Johnston Naughton Laramie

River Wyodak

Unit BW43 BW44 1 2 3 1

- 3 BW91

Capacity, MW 220 330 160 210 330 565 335

Dec 2007 $/kW SCR $306 $300 $318 $312 $279 $296

March /July 2008 $/kW SCR $510 $436 $531 $509 $415 $218 $474

4 month % increase 66% 46% 67% 63% 49% 60%

* Costs include owner’s cost and Allowance for Funds Used During Construction ( AFUDC )



### Figure 2 is taken from Cich anowicz, and shows the industry

- reported costs for SCRs at different time

periods, including 2008

- 2010. Note that, as shown on Figure 2, all costs have been normalized to a 2008

basis. In addition, t hese costs are on the same basis as those shown above (inclusive of owner’s costs,

AFUDC, etc.). As shown, the Wyoming owner’s estimates in Table 1 for December 2007 were in the

same range as the actuals reported by Cichanowicz for installations which occurred between 2008 and

2010 ($125/kW to $450/kW) , but the capital costs reported only four months later for Dave Johnston,

Naughton and Wyodak (all owned by Pacificorp) were near or well above the highest costs (in $/kW)

reported by Cichanowicz in the 2008

- 2010 period

. The dramatic increase in estimated cos t between

December 2007 and March 2008 for the Pacificorp units and the stark inconsistency of the March 2008

estimated costs with other industry data begs m ore explanation from the owners about their reported

costs

. The SCR cost estimate from Basin Elect ric for the Laramie River units was consistent with what

industry had reported.

12 Sargent & Lundy, “IPM Model

– Revisions to Cost and Performance for APC Technologies SCR Cost Development

Methodology FINAL”, Aug ust 2010, Project 12301

- 007, Perrin Quarles Associates, Inc . p 1.

13 Fox, Phyllis, “Revised BART Cost Effectiveness Analysis for Tail

- End Selective Catalytic Reduction at the Basin

Electric Power Cooperative Leland Olds Station Unit 2 Final Report”, RTI Pro ject Number

0209897.004.095 , March 2011

14 Cichanowicz, J. E., “CURRENT CAPITAL COST AND COST

- EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL

TECHNOLOGIES”, Prepared for Utility Air Regulatory Group, January 2010

15 This workbook is discussed in further detai l in the Cost Estimating section of this memo

### www.AndoverTechnology.com 5 Figure 2 also demonstrates two other points

–

• The scatter in cost shows that SCR capital cost is a strong function of site conditions as well as

capacity, and this is why a re trofit factor is important.

• SCR costs have increased significantly between 2000 and the 2008

- 2010 period.

Regarding the first point, the IPM documentation states that “Retrofit difficulties associated with an SCR

may result in capital cost increases of 30 to 50% over the base model. “ 16 

### So, retrofit factors up to 1.5

were used in my cost estimates.

Regarding the second point, this is supported by the increase in the Chemical Engineering Plant Cost

Index (CEPCI) between 2000 and 2007, as shown in Figure 3. However, between 2006 and 2012 the

annual CEPCI has remained in a range between about 500 and 600 (550±10%), and the monthly CEPCI

peaked in August 2008 at 619.3. The July 2012 CEPCI, recently published in the October 2012 issue of

Chemical Engineerin g , was reported to be 582.2 and is shown as the 2012 value on Figure 3. Therefore,

the rapid escalation of cost that was experienced after 2003 and peaked in August 2008 has slowed

down appreciably.

Figure 2

. Capital cost of SCRs (in $/kW) for four diffe rent time periods, reported by Cichanowicz 17

16 Appendix 5

- 2A (SCR) of the IPM Base Case v.4.10 documentation , p 1.

17 Cichanowicz, January 2010

### www.AndoverTechnology.com 6 Figure 3. Annual Chemical Engineering Plant Cost Index (CEPCI)

Chemical Engineering magazine



### A ssumptions

In estimating cost of control, it is assumed that a full complement of combustion controls are

implemented prior to installation of post

- combustion controls (SNCR and SCR). Emissions rates for the

2001

- 2003 period were used to estimate the emission rate p rior to installation of combustion controls.

The average reported emission rates for 2001

- 2003, 2011 and 2012 year

- to

- date are shown in Table 2

with Wyoming’s proposed BART limit

. 18 

### Except for Dave Johnston units 1 and 2, there has been some

significant N Ox reduction since 2003 at these facilities through implementation of combustion NOx

controls. The most recent NOx reductions occurred at Naughton plant in 2012

. For Naughton 1,

Separated Overfire Air was installed in June , which is why the reduction in NOx is not yet reflected in the

six months of data for 2012 . It is assumed that Naughton 1 will achieve the same NOx emissions rate as

Naughton 2 since they are both tangential furnaces, both have similar NOx emissions prior to the

installat ion of controls and, according to the Wyoming BART proposed limits, are projected to have

similar emission rates after the installation of controls. For Naughton 3, it is assumed that the annual

average emission rate with combustion controls will be 0.33 lb/MMBtu

– roughly 10% lower than the

expected 30

- day average with combustion controls in Wyoming’s proposed SIP.

Cost E stimating

The cost estimates summarized in the following sections of this memo are detailed in a Microsoft Excel

workbook WY_EGU_BART_RP _Costs_20121019.xlsx that is an attachment to this memo. The details of

the estimating methods are described in the workbook. Consistent with the EPA Control Cost Manual, 19

18 WY Regional Haze SIP, January 7, 2011, Attachment A

19 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B

- 02

- 001 , p 2

- 5

- 2

- 7 0% 10% 20% 30% 40% 50% 60%

300 350 400 450 500 550 6002000200120022003200420052006200720082009201020112012Percent change in CEPCI since 2000CEPCI

Year Chemical Engineering Plant

Cost Index (CEPCI)

CEPCI % growth from 2000

### www.AndoverTechnology.com 7 capital cost estimates do not include AFUDC or Owner’s Costs. With regard to capi tal cost escalation, as

demonstrated in Figure 3, the CEPCI has remained in a range of about 550 ± 50 since 2006. Since all of

the capital cost estimates and algorithms that are utilized in this effort were developed since 2006,

escalation has been modest , and was adjusted for in some cases.

Table 2. Reported emission rates and Wyoming proposed BART limits for affected EGUs

Facility Name Facility ID

(ORISPL) Unit ID Annual Heat

Input, MMBtu

2001

- 03 avg. Avg. NOx Rate (lb/MMBtu)

2001

-

2003 2011 2012

YTD Wyoming

Proposed

BART limit *

Dave Johnston 4158 BW41 9,618,309 0.4549 0.3864 0.3934 none

Dave Johnston 4158 BW42 9,810,184 0.4406 0.4273 0.4328 none

Dave Johnston 4158 BW43 19,209,226 0.5116 0.2261 0.2162 0.28

Dave Johnston 4158 BW44 27,687,905 0.3662 0.1413 0.2039 0.15

Laramie River 6204 1 46,814,433 0.2585 0.1843 0.1930 ** 0.23

Laramie River 6204 2 46,557,737 0.2703 0.1838 0.1901 0.21

Laramie River 6204 3 47,765,529 0.2669 0.2174 0.1930 0.21

Naughton 4162 1 13,787,157 0.5155 0.5892 0.5551 0.26

Naughton 4162 2 16,616,431 0.5221 0.5641 0.2108 0.26

Naughton 4162 3 24,856,366 0.3656 0.4333 0.3984 0.07

Wyodak 6101 BW91 35,204,108 0.2622 0.2062 0.1918 0.23

All historical emissions and heat input data developed from Air Markets Program Data

. For 2012 YTD for L aramie

River and W yodak nine months of data was available, for others only six months of data was available

* either 12 month or 30 day rolling average, depending upon facility

** April and May 2012 data was excluded for LR1 due to apparent shutdown and/or use of natural gas



### For combustion controls, capital and operating costs were based upon what was in the Wyoming

proposed SIP supporting attachments, when available. In the case of Dave Johnston 1 and 2, the IPM

cost estimating algorithms were used for combustion control capital and operating costs and the CEPCI

was used to escalate from 2007 dollars to 2010 dollars

.

For SNCR, the capital cost was assumed to be $20/kW

. Regent consumption was determined using a

chemical utilizati on factor of 0.25. After combustion controls, SNCR can typically achieve NOx

reductions of 20% to 30%. 20 

### NOx reduction with SNCR is known to be greater at higher NOx emission

rates than lower rates. 21 

### NOx reduction was estimated as 30% for initial NOx greater than 0.25

lb/MMBtu, 25% for NOx from 0.20 to 0.25 lb/MMBtu and 20% for NOx less than 0.20 lb/MMBtu.

For consumables, notably urea, there has been significant variability in cost , and current cost estimates

were used (delivered price of about $650/ ton)

. 22

, 23 

### Unfortunately, the cost of urea has increased

20 Institute of Clean Air Companies, February 2008 , p. 9

21 Hofmann, J., Sun, W., “Process for Nitrogen Oxides Reduction to Lowest Achievable Level”, US Patent 5,229,090,

July 20, 1993 , Figure 6

22 Email from Jennifer Zagorsky, Potash Corp. 10/15/2012

23 Email from Doug Kirk, Fuel Tech, 10/12/2012

### www.AndoverTechnology.com 8 significantly, as indicated in Figure 4, an index that is indicative of the price of urea paid to producers

(not including transport, etc.) . As shown, producer prices have roughly doubled in the pas t three years.

“Improvement” as used in the figure, means increasing prices for producers

.

Figure 4. Profercy World Nitrogen Index.

www.fertilizerworks.com/html/market/profercy.pdf

### www.AndoverTechnology.com 9 

### Dave Johns t on, U nits 1

- 4

An overhead view of Dave Johns t on plant is shown in Figure 5 . Dave Johnson 1 and 2 do not have NOx

controls. Units 3 and 4 are equipped with combustion NOx controls and no post

- combustion controls.

Units 1 and 2 are dry bottom wall fired units and combustion control retrofits on such units are

relatively routine. For units 1 and 2 EPA estimated emission rates are 0.20 lb/MMBtu (annual average)

in the proposal in the Federal Register, and this is reasonable for LNBs with OFA (about 55% NOx

reduction)

. For units 3 and 4

, Wyoming’s analysis estimated an emission rate of 0.28 lb/MMBtu and

0.15 lb/MMBtu (30

- day average) with LNB and OFA for units 3 and 4, respectively

. 24 

### Units 3 and 4 have

already in stalled combustion controls as reflected in 2011 annual average NOx emission rates of 0.23

lb/MMBtu and 0.14 lb/MMBtu, respectively

.

Retrofit costs

Retrofit costs for combustion controls and SNCR are expected to be consistent with other similar units.

Ret rofit costs for combustion controls are based upon company estimates for Units 3 and 4. However,

since the company did not provide costs for Units 1 and 2, IPM cost estimates were used. For SNCR a

presumed capital cost of $20/kW is assumed

. 25



### It was previously determined that post

- combustion NOx controls , including SCR, are feasible , but they

were not selected in Wyoming’s proposal as BART due to cost

. 24 

### Based upon the close proximity of the

boilers and associated equi pment (including, decommissioned chimneys) to one another , and the coal

pile , retrofit of an SCR on U nits 1

- 3 would likely entail a significantly higher than average retrofit cost

. There may be more space available near unit 4 for a retrofit of SCR, but this is unclear from the

photograph. For these reasons, the estimates of capital cost shown in Table 3 are a djusted for retrofit

difficulty using subjective factors that are inte grated into the IPM cost estimating algorithms and a

retrofit difficulty factor of 1.5 is assumed for all units

.

24 Wyoming Regional Haze SIP, Jan 7, 2011, Attachment A

25 Based upon input from technology suppliers it was determined that $20/kW is a reasonable and conservative estimate of

c apital cost, and therefore this is used in lieu of the estimates used for IPM that are relied on by Wyoming in their SIP

evaluation. See discussion on page 2 of this memo.

### www.AndoverTechnology.com 10 Figure 5

. Dave Johnston Power Plant

### www.AndoverTechnology.com 11 Table 3

. David Johnston Estimated Control Costs

DJ 1 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $93 $113 $439

Control Efficiency 56% 67% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 536 536 536

NOx Rate (lb/MMBtu) 0.45 0.45 0.45

NOx (TPY) 2188 2188 2188

Controlled Rate

NOx Rate (lb/hr) 236 176.82 58.94

NOx Rate (lb/MMBtu) 0.20 0.15 0.05

NOx (TPY) 962 721.37 240.46

Tons/Year Removed 1226 1466.31 1947.23

Total Cost/year $1,187,179 $2,338,102 $6,619,121

$/Ton $968 $1,595 $3,399

$/ton Incremental $4,786 $8,902



### DJ 2 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $93 $113 $439

Control Efficiency 55% 66% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 519 519 519

NOx Rate (lb/MMBtu) 0.44 0.44 0.44

NOx (TPY) 2161 2,161 2,161

Controlled Rate

NOx Rate (lb/hr) 236 177 59

NOx Rate (lb/MMBtu) 0.20 0.15 0.05

NOx (TPY) 981 736 245

Tons/Year Removed 1180 1,425 1,916

Total Cost/year $1,188,797 $2,356,537 $6,637,642

$/Ton $1,007 $1,653 $3,464

$/ton Incremental $4,761 $8,728

### www.AndoverTechnology.com 12 Table 3

. David Johnston Estimated Control Costs

DJ 3 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $73 $93 $378

Control Efficiency 58% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.51 0.51

NOx (TPY) 4913 4,913 4,913

Controlled Rate

NOx Rate (lb/hr) 528 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05

NOx (TPY) 2077 1,558 480

Tons/Year Removed 2837 3,356 4,433

Total Cost/year $1,699,807 $4,087,200 $11,708,335

$/Ton $599 $1,218 $2,641

$/ton Incremental $4,598 $7,074



### DJ 4 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $22 $42 $297

Control Efficiency 61% 69% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1325 1325 1325

NOx Rate (lb/MMBtu) 0.37 0.37 0.37

NOx (TPY) 5070 5,070 5,070

Controlled Rate

NOx Rate (lb/hr) 511 409 181

NOx Rate (lb/MMBtu) 0.14 0.11 0.05

NOx (TPY) 1956 1,565 692

Tons/Year Removed 3114 3,505 4,377

Total Cost/year $767,342 $3,000,528 $13,375,101

$/Ton $246 $856 $3,055

$/ton Incremental $5,708 $11,888

### www.AndoverTechnology.com 13 

### Laramie River Units 1

- 3

The Laramie River plant has three roughly 570 MW units. All are dry bottom wall fired boilers and

currently are equipped with LNBs and OFA and averaged under 0.20 lb/MMBtu in 2012 through

September

.

Retrofit Costs

For SNCR a presumed capital cost of $20/kW is assumed. SNCR does not require much space and

retrofit difficulty does not vary much for SNCR.

The plant is shown in Figures 6a and b. These figures show a much less constrained site than Dave

Johnston. As a result, ret rofit difficulty of installing S CR is expected to be average, except possibly for

unit 2 which is located between units 1 and 3. Access of a crane will be somewhat more challenging for

unit 2 and a n SCR retrofit difficulty of 1. 2 is assumed for estimating SCR capital cost

. In all cases the SCR

reactor is likely to be installed above the ESP ductwork.

The W yoming analysis indicated that NOx should be reduced to around 0.18±0.02 lb/MMBtu with LNB

and OFA and s uggested a 30

- day rolling average rate of 0.23 lb/MM Btu

. 26 

### Actual emission levels at the

plant for the first nine months of 2012 for all three units are about 0.19 lb/MMBtu, which is an

indication of what is expected on an annual average basis. Units 1 and 2 had even lower annual

a verage emission rates in 2011 at about 0.18 lb/MMBtu and Unit 3 was somewhat higher just under

0.22 lb/MMBtu, with the average of the three units combined at about 0.195 lb/MMBtu annual average

.

The Wyoming document also suggests that addition of SNCR wo uld reduce NOx to 0.12 lb/MMBtu

(assumedly on a 30

- day rolling average basis) . This is greater NOx reduction from SNCR than expected

and is inconsistent with other experience. Fuel Tech, the leading supplier of SNCR, was contacted and

confirmed that an emission reduction of about 20% is expected from SNCR at these NOx levels , which

suggests an annual emission r ate close to 0.15 lb/MMBtu with SNCR from an annual rate of about 0.19

lb/MMBtu without SNCR

. 27



### The cost analysis of Table 4 shows slightly different costs for the three Laramie River units, although

they are similar boilers. Th is is in part due to the units ha ving slightly different starting NOx levels, which

affect the costs. In addition, a ccording to NEEDS data, unit 1 has slightly lower capacity than units 2 and

3 (565 MW versus 570 MW). NEEDS also indicated slightly different heat rates for the units, which

i mpact capacity factors and tons of NOx emitted. Finally, a modestly higher SCR retrofit difficulty factor

is assumed for unit 2 because access will be poorer than for units 1 or 3.

26 DEPARTMENT OF ENVIRONMENTAL QUALITY, AIR QUALITY DIVISION, BART Application A nalys is, AP

- 6047, Laramie River

Station, May 28, 2009 , pages 7 and 8

27 Email from Fuel Tech, October 15, 2012

### www.AndoverTechnology.com 14 Figure 6 a

. Laramie River Units 1

- 3

Figure 6 b

. Laramie River Units 1

- 3

### www.AndoverTechnology.com 15 Table 4

. Laramie River Estimated Control Costs

LR 1 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $219

Control Efficiency 26% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1652 1652 1652

NOx Rate (lb/MMBtu) 0.26 0.26 0.26

NOx (TPY) 6051 6,051 6,051

Controlled Rate

NOx Rate (lb/hr) 1227 982 320

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4495 3,596 1,170

Tons/Year Removed 1556 2,455 4,880

Total Cost/year $2,268,806 $6,818,815 $19,075,563

$/Ton $1,458 $2,777 $3,909

$/ton Incremental $5,062 $5,054



### LR 2 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $247

Control Efficiency 29% 43% 82%

Uncontrolled Rate

NOx Rate (lb/hr) 1688 1688 1688

NOx Rate (lb/MMBtu) 0.27 0.27 0.27

NOx (TPY) 6293 6,293 6,293

Controlled Rate

NOx Rate (lb/hr) 1199 959 312

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4470 3,576 1,164

Tons/Year Removed 1823 2,717 5,129

Total Cost/year $2,268,806 $6,817,107 $20,941,828

$/Ton $1,244 $2,509 $4,083

$/ton Incremental $5,088 $5,856

### www.AndoverTechnology.com 16 Table 4

. Laramie River Estimated Control Costs

LR 3 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $223

Control Efficiency 28% 42% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1778 1778 1778

NOx Rate (lb/MMBtu) 0.27 0.27 0.27

NOx (TPY) 6375 6,375 6,375

Controlled Rate

NOx Rate (lb/hr) 1279 1023 333

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4586 3,669 1,194

Tons/Year Removed 1789 2,706 5,181

Total Cost/year $2,268,806 $6,890,841 $19,544,833

$/Ton $1,268 $2,546 $3,772

$/ton Incremental $5,039 $5,114

### www.AndoverTechnology.com 17 

### Naughton Units 1

- 3

The Naughton units 1, 2 and 3 are 160 MW, 210 MW and 330 MW, respectively. All are tangentially

fired and have recently installed combustion controls. The reported emissions levels shown in Table 2

do not yet fully reflect the anticipated NOx reductions from combustion controls

. It is assumed that

Naughton Units 1 and 2 will achieve similar rates with controls, about 0.21 lb/MMBtu annual average.

It is assumed that Naughton Unit 3 will achieve 0.33 lb/MMBtu annual average since that is 10% lower

than the 0.37 lb/MMBtu presumed 30 day average by Wyoming, thereby accounting for the longer

averaging period

.

Retrofit costs

Naughton U nits 1

- 3 a re shown in Figure 7

. Like the other plants, SNCR costs are assumed to be $20/kW.

If SCR were installed on units 1 and 2 it may be necessary to install a n SCR reactor above the ESP and on

the other side of the retired chimney from the boiler. In such a case, the ductwork fr om the economizer

to the SCR and from the SCR to the air preheater inlet would be longer than usual for a high dust SCR

and would need to go around the retired chimney s

. For unit 3 it is also unclear if there is enough space

to install the SCR reactor on the same side of the chimney as the boiler , which , like Units 1 and 2,

impacts the length of ductwork that would be needed

. There appears to be access for construction

equipment, such as a crane, in the area east of the plant (the upper part of the photo) . In estimating the

cost of the SCR, I assume that the retrofit difficulty is above average, and an assumed retrofit difficulty

factor of 1.3 is assumed. Results of cost calculations are shown in Table 5.

Figure 7

. Naughton U nits 1

- 3

–

### www.AndoverTechnology.com 18 Table 5

. Naughton Estimated Control Costs

N 1 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $55 $75 $330

Control Efficiency 59% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 895 895

NOx Rate (lb/MMBtu) 0.52 0.52 0.52

NOx (TPY) 3553 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05

NOx (TPY) 1453 1090 345

Tons/Year Removed 2100 2463 3209

Total Cost/year $932,466 $2,637,981 $7,747,105

$/Ton $444 $1,071 $2,414

$/ton Incremental $4,694 $6,854



### N 2 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $40 $60 $300

Control Efficiency 60% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 1174 1174

NOx Rate (lb/MMBtu) 0.52 0.52 0.52

NOx (TPY) 4337 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05

NOx (TPY) 1752 1314 415

Tons/Year Removed 2586 3024 3922

Total Cost/year $883,900 $2,967,010 $9,216,804

$/Ton $342 $981 $2,350

$/ton Incremental $4,757 $6,957

### www.AndoverTechnology.com 19 Table 5

. Naughton Estimated Control Costs

N 3 Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $3 $23 $247

Control Efficiency 10% 37% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1266 1266 1266

NOx Rate (lb/MMBtu) 0.37 0.37 0.37

NOx (TPY) 4544 4544 4544

Controlled Rate

NOx Rate (lb/hr) 800 173

NOx Rate (lb/MMBtu) 0.33 0.23 0.05

NOx (TPY) 4101 2871 621

Tons/Year Removed 442 1673 3922

Total Cost/year $106,393 $5,180,724 $13,691,175

$/Ton $240 $3,097 $3,491

$/ton Incremental $4,124 $3,783

### www.AndoverTechnology.com 20 

### Wyodak

Wyodak Power Plant is located on the Wyodak Energy Complex that includes the Wygen units 1

- 3 and

Neil Simpson units 1, 2. Wyodak is a 335 MW dry bottom wall

- fired unit equipped with low NOx burners

and overfire air

. In 2011 the annual average NOx emission was under 0.21 lb/MMBtu and the average

for the first nine months of 2012 was under 0.20 lb/MMBtu. Additional NOx controls would likely entail

SNCR or SCR.

Retrofit costs

As with the other plants, SNCR is assumed to cost $20/kW to install.

In the event SCR were installed at the site, the SCR reactor would likely be located above the existing

(but decommissioned) ESP shown between the boiler building and the chimney in Figure 8 . There is

ample room on the site for lay down of material. Location of a crane near the construction site appears

to be possible . Therefore, the difficulty of this retrofit is probably average to above average since it is

common to have some amount of relocation of equipment. A conservative estimate of retrofit difficulty

is 1.3.

Table 6 shows the results of cost calculations.

Figure 8

. Wyodak Power Plant

### www.AndoverTechnology.com 21 Table 6

. Wyodak Estimated Control Costs

Cost from 2003 emission levels

Comb ustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $36 $56 $302

Control Efficiency 27% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1060 1060 1060

NOx Rate (lb/MMBtu) 0.26 0.26 0.26

NOx (TPY) 4615 4,615 4,615

Controlled Rate

NOx Rate (lb/hr) 775 620 202

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 3376 2,701 880

Tons/Year Removed 1239 1,914 3,735

Total Cost/year $1,272,427 $4,491,994 $15,083,850

$/Ton $1,027 $2,347 $4,039

$/ton Incremental $4,769 $5,818