# Cost of NOx Controls on Wyoming EGUs

to:



# EC/R Incorporated

**501 Eastowne Drive, Suite 250**

**Chapel Hill, NC 27514**

October 2 8 , 2013

F

inal report



## Andover Technology Partners

112 Tucker Farm Road, North Andover, MA 01845

phone: (978) 683

- 9599; e

- mail : staudt@AndoverTechnology.com

# Andover Technology Partners

112 Tucker Farm Road, North Andover, MA 01845

# Contents

Sections Page

1. Background 1

2. NOx Control Cost Method ology 2

David Johnston 1

- 4 29

Jim Bridger 1

- 4 35

Laramie River 1

- 3 39

Naughton 1

- 3 45

Wyodak 52

### www.AndoverTechnology.com 1 

# Background

Andover Technology Partners (ATP) under contract to EC/R (ECR) provided cost estimates for

NOx contro ls at the following Wyoming Electric ity Generating Units.

• Dave Johnston units 1

- 4

• Jim Bridger units 1

- 4

• Naughton units 1

- 3

• Wyodek unit 1

• Laramie River units 1

- 3

Previous cost estimates are addressed in two memos and two spreadsheets provided to EC/R on

Feb ruary 7, 2013 :

• Review of Estimated Compliance Costs for Wyoming Electric Generating (EGUs)

— Revision of

Previous Memo, memo from Jim Staudt, Andover Technology Partners, to Doug Grano, EC/R,

Inc., February 7, 2013. (Staudt Memo) and associated workbook.

o Mic rosoft Excel Workbook WY EGU BART_RP Costs_20121019_revised.xlsx

 Which included estimates for all plants except Jim Bridger

• Review of Estimated BART Compliance Costs for Wyoming Electricity Generating Units (EGUs)

memo from Jim Staudt, Andover Technology P artners, to Doug Grano, EC/R, Inc., February 7,

2013 and associated workbook

o Microsoft Excel Workbook WY EGU BART_RP Costs_20130201.xlsx

 Which included estimates for Jim Bridger

EPA has since received comments from various stakeholders. After review of th e comments,

ATP has revised its cost estimates for NOx controls on these plants based upon the information in the

comments that ATP believes provided a valid reason to revise the cost estimates. ATP has provided

detailed responses to the comments offered by stakeholders in the Responses to Comments (R TCs) . In

this report ATP will address that information that has changed and how the costs have been affected.

ATP will highlight some of the key issues raised by commenters relating to cost, but will not exp lore

them in the level of detail found in the RTCs.

### www.AndoverTechnology.com 2 

# NOx Control Cost Methodology

In response to comments, cost estimates have been revised for the following Wyoming units.

• Dave Johnson, units 1

- 4

• Jim Bridger, units 1

- 4

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

• Naughton units 1, 2 and 3

• Wyodak unit 1

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

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

• Selective Non

- Catalytic Reduction (SNCR)

• Sele ctive Catalytic Reduction (SCR)

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

- 2003 historical

rates (average of annual average for each of the three years) when advanced combustion controls were

not in use at these units. Em ission rates with combustion controls were estimated from more recent

data for those units with combustion controls

. 2001

- 2003 historical data were also used to estimate

annual heat input and the associated capacity factor for each unit; these estimates are used in all

calculations. For each unit, SNCR and SCR costs were estimated in combination with applicable controls.

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

• IPM Cost models

• US EPA Air Pollution Control Cost Manual 1



### • Data provi ded by the facilities in their BART assessments

• Data provided in comments

, including in some cases budgetary price estimates from a control

technology consultant or vendor

• Other data that have been published and are described in more detail

The BART guide lines 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 sales and property taxes (but not impact on income taxes) , insur ance and

administrative costs, and the use of overnight cost 2 

### for capital cost. The overnight cost methodology

does not allow for inclusion of financing costs during construction (also called AFUDC) , such as used by

EPRI as well as in the Integrated Plann ing Model (IPM).

For each control method, changes from previous cost estimates are noted.

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

- 02

- 001

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

for Funds Used During Construction (AFUDC)

### www.AndoverTechnology.com 3 Combustion Controls

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

they were used. If not, IPM cost estimates were used to estimate capital and operating costs of

combustion controls (except that AFUDC is not included)

. 3 

### Percent reduction and tons of NOx removed

w ere based upon actual emission rates after control installation or projected emission rates if actual

em ission rates were not available

.

SNCR

For SNCR

, except where noted otherwise, capital cost is assumed to be $20/kW. This is a

simplifying assumption from the IPM algorithm that, as described below, generally yields more accurate

results

. 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 als o consistent with ATP ’ s

experience, having worked with the 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



### ATP has also published reports that describe the cost and application of technologies used for

control of NOx, including SNCR

. 9

, 10 

### ATP’s opinion is that the IPM algorithm for SNCR capital cost

assumes economies of scale that don’t really exist to a great extent in SNCR systems, which results in

over

- predicting of capital cost for small sy stems and under

- predicting capital cost for large systems.

Therefore, $20/kW provides a reasonable estimate for the capital cost of SNCR , unless there is

reason to believe that a more complex or costly SNCR system will be required . Furthermore, due to the

relatively low capital cost of SNCR, the operating cost

– especially reagent cost

– is the much mo re

3 Documentation for EPA Base Case ver 4.10 Chapter 5, Emission Co ntrol 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 Op eration on Coal

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

Durham, NC, March 19

- 20, 1998.

7 Ibid

8 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

9 Staudt. J. and M J Bradley & Associates, for the Northeast States for Coordinated Air Use Management, “Cont rol 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

Coordinated Air Us e Management and Mid Atlantic Regional Air Management Association, June 1998.

### www.AndoverTechnology.com 4 important component of cost. Therefore, for the purpose of a BART analysis

, this is a simplifying

assumption that has little i mpact on the cost

- effectiv eness calculation.

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

. Figure 1 is an example of test data from

an SNCR optimizati on program on a pulver ized 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 ha ving similar shapes as those in Figure 1, may have

somewhat different values. Except where furnace temperature data was provided to indicate a

different utilization rate, f or the purpose of making an estimate of reagent consumption for the

Wyoming pulveri zed 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 0.20 lb/MMBtu. This is expected to

provide a reasonable estimate of NOx

reduction and reagent consumption.

Figure 1. NOx Reduction and Reagent

Utilization 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)



### A utilization factor of 25% is

higher than the default utilization

factor of 15% in the IPM reagent cost calculation; however, 15% is overly conservative and would only

reflect utilizat ion rate at very high furnace temperatures

. For example , information from Fuel Tech, the

leading supplier of SNCR technology stated that at the unusually high furnace exit temperature of

2500 ° F, 25% reduction was possible with an NSR of 1.75 (utilization of 14.3%) while at a unit with an exit

temperature of 2334°F, 25% reduction was possible at an NSR of 1.1 (utilization equal to 22.7%). 12



### Assuming more typical furnace temperatures of 1800 to 2200°F utiliza tion should be well above 22.7%

for most boilers.

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 Cost

- Effective Op eration on Coal

- Fired Electric Utility Boilers", presented at ICAC

Forum '98, Durham, NC, March 19

- 20, 1998.

12 Email from Alexander Dainoff to Jim Staudt, June 27, 2012

### www.AndoverTechnology.com 5 Because the cost of SNCR is driven largely by the reagent consumption, selection of the correct

chemical utilization rate is very important. Chemical utilization equals Percent reduction divided by NSR.

Although the default utilization rate in the IPM al gorithm is 15%, as explained in more detail in EPA’s

responses to comments, these utilization rates are too low to be used in general ; however, if there is

temperature data indicating an unusually high furnace temperature (utilization drops off with incre ased

furnace temperature) lower utilization may result . For more typical furnace temperatures utilization

rates in the range of 25% are expected. Some commenters indicated that 12% chemical utilization , as

assumed by Sargent & Lundy in their cost estimat es , was a better estimate of utilization rate for Laramie

River Station. B ased upon the furnace temperature data provided by Basin Electric, ATP agrees

.

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

IPM algo rithms. A correction was made to the variable operating cost associated with water. This had a

negligible effect of the results of the cost estimates.

The cost of auxiliary power was changed from the previous estimate

. In the original analysis the

defau lt values for electricity in IPM were used, which reflects the ret ail market price for power. On the

other hand, the cost of power used for auxiliary loads should be equal to the cost to the owner of

generating the electricity rather than the retail price received in the market. ATP has reviewed FERC

Form 1 data for PacifiCorp 13 

### and has incorporated in the revised costs for each plant the stated cost of

electricity per net kWh. For Laramie River Station the costs in their July 2008 BART analysis 14 

### are us ed,

as these are also more consistent with PacifiCorp’s reported cost of generation than the values later

used by Basin Electric or by ATP in our original cost analysis, which we re more reflective of retail power

prices rather than the cost to generate.

S CR

Except for Laramie River units 1

- 3, Dave Johnston 3 and Naughton 1 and 2, 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 subjec tive 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 u nits and degree of

congestion around the site and in the vicinity of where the SCR would be installed. These factors impact

the ability to locate large cranes on the site

– that impact how the SCR is assembled (are large sections

lifted into place or is t he 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 capital cost increases of up to 50% over the base

13 FERC Financial Report, FERC Form No. 1: Annual Report of Mjor Electric Utilities, Lic ensees and Others and

Supplemental Form 3Q: Quarterly Financial Report, PacifiCorp, Year/Period of Report 2010/Q4., pgs 402.2, 403,

403.2, see line 35

14 Black & Veatch, “Basin Electric Power Cooperative Laramie River Station Refined BART Visibility Modelin g”, July

24, 2008 , pg 25 of 176

### www.AndoverTechnology.com 6 model. 15 

### In general, ATP tended to use conservative estimates of retrofit factor, with none lower than

1.0.

Satellite imagery provi des a unique, “bird’s eye” view of the site, and can be useful for

identifying the location of equipment relative to each other, access to and around the boilers for cranes

and other equipment , access to and from the site, interferences around the site per imeter, availability

of open areas for temporary storage of construction materials, etc. Therefore, because of its availability

and the information it yield s, satellite imagery is a very useful tool in major retrofits and is widely used

by air pollution c ontrol system original equipment manufacturers ( OEMs ) to evaluate a retrofit . Site

visits provide other information that may not be discernible from a satellite image , and are typically

performed in addition to rather than in lieu of use of satellite imag es. Information that is gained from a

site visit may be whether or not a major piece of equipment , like an air preheater, needs to be

rel ocated to make room for ductwork . None of the owners reported that relocation of the air preheater

or other major eq uipment was necessary. As a result, use of satellite imagery wa s considered sufficient

for the purpose of this estimate

.

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

, 16

, 17 

### Estimates were also

compared against estimates provided by the facility owners ( December 2007, March 2008 and August

2013 estimates for Dave Johnston and Naughton and, D ecember 2007 and March 2008 estimates for

Wyodak, and June 2008 and August 2013 estimates for Laramie River ). Without exception, owners

significantly increased their cost estimate from the original estimate. The owners did not provide an

explanation for the high increase in capital cost between their first and final estimates , although in some

cases the difference in time between estimates was only 4 months.

Table 1

. Owner’s estimates of capital cost for SCR *

(s ee workbook: WY EGU BART_RP Costs_ 2 013092 3 .xlsx) 18

P ant Dave Johnston Naughton Laramie River Wyodak

Unit BW43 BW44 1 2 3 1 2 3 BW91

Capacity, MW 220 330 160 210 330 565 570 570 335

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

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

August 2013 $504 $641 $486 $427 $449 $438

% increase in estimate 65 % 46% 102% 56% 49% 96% 108% 103% 60%

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

15 Sargent & Lundy, “IPM Model

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

Methodology FINAL”, August 2010, Project 12301

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

16 Fox, Phyllis, “Revised BA RT Cost Effectiveness Analysis for Tail

- End Selective Catalytic Reduction at the Basin

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

0209897.004.095 , March 2011

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

- EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL

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

18 This workbook is discussed in further detail in the Cost Estimating section of this report

### www.AndoverTechnology.com 7 Figure 2 is taken from Cichanowicz, and shows industry

- reported costs for SCRs at different time

peri ods, including 2008

- 2010. Although there was rapid cost escalation in the decade prior to 2008, that

has stopped. B etween 2006 and 2012 the annual Chemical Engineering Plant Cost Index ( CEPCI ) has

r emained in a range between about 500 and 600 (550±10%), and the monthly CEPCI reached a peak in

August 2008 at 619.3 and has since remained below that (June 2013 CEPCI was 564.9 )

. As a result,

2008

- 2010 costs are on the same basis as those shown above (in clusive o f owner’s costs, AFUDC, etc.).

Figure 2

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



### The PacifiCorp estimates in Table 1 for December 2007 and Basin El ectric in 2008 were in the

same range as the actuals reported by Cichanowicz, but the capital costs reported only four months

later for Dave Johnston, Naughton and Wyodak and more recently for Laramie River Station were near

or well above the highest cost s (in $/kW) reported by Cichanowicz. The most recent estimate for

Naughton unit 1 is over 40% greater than the highest historical cost reported by Cichanowicz! The

dramatic increase in estimated cost and the stark inconsistency of the more recent estimat ed costs with

other industry data begs more explanation from the owners about their reported costs. At the very

least, it demonstrates that these cost estimates are extremely conservative.

As noted, the more recent cost estimates provided by owners unive rsally are at the upper

extreme, or in some cases well beyond the upper extreme of recent costs experienced by the industry

for retrofit of SCR . As will be noted in this report , while there are varying levels of retrofit difficulty at

these sites, in most cases it was not possible to justify the high costs reported by the owners. In their

comments none of the owners reported the kind of issues that tend to dramatically increase retrofit

costs, such as the need for relocation of major pieces of equipment.

### www.AndoverTechnology.com 8 Changes to previous cost estimates were made, and these are largely due to the following

effects:

• Elevation

– Elevation does have an impact on the volume of gas treated and the resulting cross

section of the ductwork, the SCR reactor, the structure needed to support the ductwork and the

size of additional fan capacity. The elevation of the site is factored into the unit MW size

accordingly due to its effects on the flue gas volume. This had a significant impact on capital

cost.

• Reagent

– The facilities wi ll be using anhydrous ammonia rather than urea, As a result, the

variable operati ng cost was changed to accommodate ammonia rather than urea. This will not

make a signficant change to the reagent storage cost or to other costs. In fact, anhydrous

ammon ia storage systems tend to be less expensive than urea systems because they do not

require a urea to ammonia conversion system. So, the IPM cost model should provide a

conservative estimate of the reagent storage and handling system.

• As noted earlier in t his report, the auxiliary power cost was changed to equal the cost of

generation rather than the market price of power sold.

• In the cases of Laramie River units 1

- 3, Naughton 1 & 2 and Dave Johnston 3, ATP use d parts of

the owner’s estimated capital cost, but excluded other costs.

• For Dave Johnston 3 and Naughton units 1 and 2, alternatives were evaluated for plant lifetimes

under 20 years based upon comments received from PacifiCorp.

• SCR and LNB capital costs using the IPM were escalated from previous cost (2010) to 2013

dollars using the June 2013 CEPCI. SNCR costs were not escalated because the capital cost has

so little impact on SNCR cost and because using the CEPCI to escalate from 2008 (the year of the

ICAC White Paper) to 2013 would result in a drop in cost (CEPCI is lower in 2013 than 2008). The

costs for already insrtalled combustion controls were not escalated.

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 prior to installation of combustion controls.

The average reported emissi on rates for 2001

- 2003, 2011, 2012 and 2013 (quarters 1 & 2) are

shown in Table 2 with Wyoming’s proposed BART limit

. 19 

### Excep t for Dave Johnston units 1 and 2, there

has been some significant NOx reduction since 2003 at these facilities through implementati on of

combustion NOx controls.

Cost E stimating

The cost estimates are reflective of 2013 dollars, are summarized in the foll owing sections of

this report and are detailed in two Microsoft Excel workbooks attached to this report:

• WY_EGU BART RP costs_2013 10 2 8

19 WY Regional Haze SIP, January 7, 2011, Atta chment A

### www.AndoverTechnology.com 9 • WY_EGU BART RP_Jim Bridger Costs_2013 10 2 8

The first workbook includes cost estimates for all units except Jim Bridger and the second

includes cost estimates for Jim Bridger.

The details of the estimating methods are described in the workbook. Consistent with the EPA

Control Cost Manual, 20 

### capital cost estimates do not include AFUDC or Owner’s Costs (beyond the 10%

allowed fo r engineering and home office ).

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 2013

a vg

Q1, Q2 Wyoming

Proposed

BART limit

*

Dave Johnston 4158 BW41 9,618,309 0.4549 0.3864 

### 0.408 0.3844 none

Dave Johnston 4158 BW42 9,810,184 0.4406 0.4273 

### 0.4235 0.4146 none

Dave Johnston 4158 BW43 19,209,226 0.5116 0.2261 

### 0.2113 0.2273 0.28

Dave Johnst on 4158 BW44 27,687,905 0.3662 0.1413 

### 0.1543 0.1323 0.15

Jim Bridger 8066 BW71 42,980,000 0.3921 0.1929 

### 0.18 0.1853 0.26

Jim Bridger 8066 BW72 40,900,000 0.3705 0.1853 

### 0.1868 0.1933 0.26

Jim Bridger 8066 BW73 42,170,000 0.3725 0.1977 

### 0.1965 0.2027 0.26

Jim Bridger 8066 BW74 41,030,000 

### 0.3964 0.1981 0.1936 0.2124 0.26

Laramie River 6204 1 46,814,433 0.2585 0.1843 

### 0.1718 0.1660 0.23

Laramie River 6204 2 46,557,737 0.2703 0.1838 

### 0.1893 0.2097 0.21

Laramie River 6204 3 47,765,529 0.2669 0.2174 

### 0.1945 0.2 073 0.21

Naughton 4162 1 13,787,157 0.5155 0.5892 

### 0.3389 0.2176 0.26

Naughton 4162 2 16,616,431 0.5221 0.5641 

### 0.2157 0.2305 0.26

Naughton 4162 3 24,856,366 0.3656 0.4333 

### 0.3454 0.2861 0.07

Wyodak 6101 BW91 35,204,108 0.2622 0.2062 

### 0.1906 0.1937 0.23

A ll historical emissions and heat input data were developed from Air Markets Program Data

. * either 12 month or 30 day rolling a verage, depending upon facility



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

Wyoming pro posed 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.

F or SNCR, the capital cost was assumed to be $20/kW (except for LRS 1

- 3, as discussed later).

Except where furnace temperature information suggested otherwise, regent consumption was

determined using a chemical utilization factor of 0.25. After combustion controls, SNCR can typically

achieve NOx reductions of 20% to 30%. 21 

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

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

- 02

- 001 , p 2

- 5

- 2

- 7

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

### www.AndoverTechnology.com 10 NOx emission rates than lower rates. 22

, 23 

### 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, the following estimates were used:

• Urea

- delivered price of about $450/ton for a 50% by weight aqueous solution 24



### • Ammonia

- $785/ton

- this is based upon Basin El ectric Exhibits

• Power

– varies by site, based upon FERC 1 data or previous company data

SCR Retrofit Issues

An SCR retrofit is a capital intensive project that can require substantial modifications to the

plant. SCR retrofits typically require that:

• The S CR reactor be built elevated on structural steel outside, but adjacent to the boiler building

• Ductwork be routed from the boiler to the SCR inlet and back from the SCR exit to the air

preheater inlet

• Modification of existing boiler building to accommodate SCR ductwork

• SCR support steel will frequently impact equipment located below the SCR

• A fan is frequently added to overcome additional pressure drop from the SCR, which also

requires modification to auxiliary electrical system and review of ductwork for p ressure integrity

• Use of large cranes to lift large sections of the SCR ductwork into place, requiring space for such

cranes

• In many cases SCRs are buil t in middle units for boilers in a side by side arrang ement that limits

access to the middle units. Mid dle units, therefore, tend t o be more difficult to retrofit with

SCR.

• Often there are major pieces of equipment in the way, such as retired chimneys, that require

longer ductwork routing. Or, there may be other equipment that must be demolished to

provide access for construction equipment. In other cases equipment, such as air preheaters,

need to be relocated to allow sufficient space for ductwork to and from the SCR.

• Space for construction materials is needed.

The following section will provide brief exa mples of SCR retrofits to give an idea of the issues

that are commonly experienced in SCR retrofits as well as some of the differences that might be

experienced and how they might impact cost . In some cases the cost of the project was available, and is

pr ovided both in reported dollars as well as escalated to 2012 dollars using the CEPCI

. It is reasonable to

assume that these re ported costs are “all in” costs that include AFUDC since they are reported by the

utilities who typically include this cost

.

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

July 20, 1993, Figure 6

23 US EPA Control Cost Manual, Section 1.2.3 SNCR Performance Parameters

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

### www.AndoverTechnology.com 11 Fi gure 3 a

. Montour SCR 25



### As an example, F igure 3 a shows the SCR

that was built for the Montour Station (Figure 2b)

in 2001 at a cost of $215 million or $143/kW

($205 /kW escalated t o 201 3 dollars using the

CEPCI), which included new ID fans, dismantling

the old ESPs and erecting new ESPs for both units

, shown in Figure 3b

. 26 

### It is clear from the figure

that the SCR reactor is built on a support

structure and the ductwork must pass through

the boiler building. Since the SCR is commonly

built outside of the b oiler building, it is routine to

have to route ductwork through the boiler

building wall. Ductwork to the ESP and I D fa n is

also below the structure

.

Figure 3 b. Montour Plant

25 Glaser, R., Licata, A., Robinson, R., “THE SCR RETROFIT AT THE MONTOUR STEAM ELECTRIC STATI ON”

http://www.babcockpower.com/pdf/RPI

- TP

- 0169.pdf

26 http://pplweb.mediaroom.com/index.php?s=12270&item=16522 

### Montour SCRs New Montour ESP s

### www.AndoverTechnology.com 12 Figure 4 is a photo taken by ATP of the SCRs at TVA’s Widow’s Creek uni ts 7 and 8 (~470 MW

each) while on a tour of the plant

. The SCRs were completed in 2003 and 2004 at costs of $66 million

($140/kW and $ 196 /kW in 201 3 dollars) and $61 million ($130/kW and $ 16 7 /kW in 201 3 dollars) for

units 7 and 8, respectively. 27 

### It is clear that the ductwork must pass through the boiler wall and that

SCRs are directly above other equipment , including fans and ductwork

. A large support structure is built

to support both SCR reactors. The support structure in this case is built to go b eyond the equipment to

avoid interference w ith the equipment that is below

. Unit 8 does not have an ESP, while unit 7 does.

Figure 4

. SCRs at TVA Widows Creek 7 and 8

Progress Energy Carolina’s Asheville 1 (on the right side of Figure 5 ) was equipped with an SCR

that went into service in 2007 at a total project cost of $35.7 million ($197/kW or $ 212 /kW in 201 3

dollars). 28 

### The project required replacement of the air preheater as well as the ESP. 29

27 Attorney General of North Carolina v. Tennessee Valley Authority, Defendant’s Response to Plaintiff’s

Interrogatories, September 1, 2006

28 Annu al NC Clean Smokestacks Act Compliance Report, March 30, 2006 

### Widows Creek 7

and 8 SCRs

### www.AndoverTechnology.com 13 Figure 5

. Progress Energy’s Asheville Power Plant

At the time it was completed, Belews Creek was the world’s largest SCR system. The cost of the

SCR system was $ 450 million 30 

### , or roughly $202/kW in 2003 ($ 285 /kW in 201 3 dollars) . The Belews

Creek plant, shown in Figure s 6 a and b required installing two SCR reactors per unit on each of the

roughly 1100 MW boilers. This SCR retrofit included replacement of the air preheaters

– from horizontal

shaft to vertical shaft

– and also included replacement of both ID and FD fans

.

29 Cisek, Steve, “Case Histories: Asheville Power Station’s Retrofit First to Meet North Carolina’s Clean Smokestacks

Act”, Power Magazine , 9/1/2006

30 http://www.asheville.com/news/dukepoweremiss ion.html 

### Asheville 1 SCR

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

. Belews Creek Power Plant

Figure 6 b

. Belews Creek 31

31 Duke Energy’s photostream, http://www.flickr.com/photos/dukeenergy/tags/scr/ 

### B elews Creek SCRs

Belews Creek SCRs

### www.AndoverTechnology.com 15 Figure 7

. Brayton Point Power Plant, Somerset, MA

Even with very congested sites it is

possible to install SCRs. Middle unit

arrangements are also not an unusual challenge

. At the Brayton Point plant, shown in Figure 7

, which is especially challenging, because it is an

extremely congested site with four boilers side

by

- side on a small peninsula with very little space

to locate a crane, a derrick crane was installed on

top of unit 3’s boiler when buildi ng the unit 3

SCR. 32 

### The derrick crane (see Figures 8 a and b) made it possible to erect the unit 3 SCR without the

need for a very large crane or without the need to demolish other existing equipment to provide access.

A “rubber tire” crane (as opposed to the very heavy lift tractor

- tread cranes typically used for SCRs) that

did not take up much room was used to put the derrick crane in place. It was also necessary to put the

support steel through a building below the SCR.

32 

### http://www.cranestodaymagazine.com/features/the

- first

- tower

- builders/image/the

- first

- tower

builders

- 1.html Brayton Point Unit

3 SCR Location of derrick

crane during SCR

construction

### www.AndoverTechnology.com 16 

### Figure 8 a

. The Derrick Cr ane at Brayton Point 33



### Figure 8 b. Use of the Derrick Crane at Brayton Point 34

33 Used with permission: http://www.cranestodaymagazine.com /features/the

- first

- tower

- builders/image/the

- first

tower

- builders

- 1.html

34 Wright, B., Erickson, C., Phillipo, M.,”Keys to Success: SCR Installations at Dominions Brayton Point Units 1 and

3”, Electric Power, May 2008

### www.AndoverTechnology.com 17 T he Ghent 1 SCR is an example of where the SCR ductwork had to both penetrate the boiler

wall, underneath the coal conveyors and conveyor rooms while also being installed above other

equipment. Figure 9a shows a satellite image of Ghent 1 and Figure 9 b is a diagram of the configuration.

Figure 9 a . Ghent 1 and SCR



### Figure 9b

. Ghent 1 SCR reactor and ductwork 35



### As shown from these figures , it was

necessary at Ghent unit 1 to erect the SCR above the

ESP and other equipment and also route the

ductwork through the boiler wall an d underneath

the coal conveyors, resulting in unusually long

horizontal duct runs.

35 Saunders, E., Chelvan, T., Erickson, C., Jasinski, M., “Selective Catalytic Reduction System Performance at LG&E

Energy LLC’s Mill Creek and Ghent Generating Stations”, Presented at EPRI Workshop on Selective Catalytic

Reduction, October 19

- 20, 2004, Pittsburgh, Pennsylvania 

### Ghent Unit 1 SCR

Coal Conveyors

### www.AndoverTechnology.com 18 At the So uthern Company Plant Bowen SCRs shown in Figure 10

, the SCR support steel actually

goes through the inlet plenum to the ESP. Southern Company installed a dummy section into the ESP

where the support column passes through. It was also necessary to modify the existing boiler building

to accommodate the SC R ductwork. 36

, 37



### Figure 10

. Plant Bowen SCRs

DTE Monroe , shown in Figure 11, has four

nearly 800 MW units built side by side. SCR is installed

on three of the four units and DTE announced that they

would install SCR on the fourth unit at a cost o f $330

million, or roughly $412/kW. 38 

### In this case the SCR

reactors must be elevated well off of the ground and be

built above the existing ESP structure and ductwork.

Access is limited by the adjacent units, a coal conveyor

as well as buildings on the si te. Access to the site is very

limited because it is surrounded by water.

36 Southern Comp any, “SCR Operating Experience”, EPRI SCR Workshop, October 31, 2006

37 Healy, E., Wall, D., Paseur, K.,” Implementation of SCR at Southern Company”, EPRI SCR Workshop, April 18

- 21,

2000

38 PR Newswire , “ DTE Energy Environmental Project Will Create 900 Jobs ” 

### Bowen SCRs

### www.AndoverTechnology.com 19 Figure 11

. DTE Monroe

Side

- by

- side retrofits are not uncommon. It is even possible to retrofit nine units in a row, as

was performed at TVA’s Kingston power plant shown in Figure s 12a and b

. In this case it was also

necessary to relocate air preheaters and work within the limitations of the existing ductwork and retired

chimneys. Kingston is definitely an unusual case of a side

- by

- side retrofit, but it demonstrates what can

be done . Th e cost of these retrofits ranged from $ 136 /kW to $ 240 /kW (201 3 dollars). Monroe SCRs Location of Planned

SCR

### www.AndoverTechnology.com 20 Figure 12 a

. Kingston Power plant.



### Figure 12b . Kingston Power Plant SCR (photo by ATP while on site visit) Kingston units 1

- 9

SCRs

### www.AndoverTechnology.com 21 

### Situations where site visits are essential to iden tify interferences are when equipment

like air preheaters must be moved or replaced or spacing for ductwork is not available without

other substantial modifications. End units and single units typically have better access but can

be very difficult when eq uipment needs substantial modification, such as air preheater

relocation. TVA’s Colbert 5 is an end unit and the SCR could even be constructed with

supporting structure to the ground, but the interface with the boiler and air preheater

ductwork was very d ifficult. Figure 13 shows the Colbert SCR and the tight spacing between the

boiler house and the ESP. When adjusted for 2012 dollars, at $ 312 /kW (201 3 dollars) the

Colbert 5 SCR was the most costly SCR for TVA when measured in $/kW.

Bull Run, shown in Fi gure s 14a and b is a single unit that does appear to generally have

good access for construction of the SCR, however, it was necessary to relocate the air preheater

at Bull Run, which at $ 303 /kW (adjusted to 201 3 dollars) made it the second most expensive

TVA SCR when measured in terms of $/kW.

Figure 13

. Colber t Power Plant SCR

Colbert 5 SCR

### www.AndoverTechnology.com 22 

### Figure 14a

. Bull Run Power Plant SCR

Figure 14b

. Bull Run Power Plant SCR (photo by ATP while on plant tour) Bull Run SCR

Bu ll Run SCR

### www.AndoverTechnology.com 23 Paradise 1, 2 and 3, shown in Figure 15, are a good example of contrasts in difficulty. Paradise 1

and 2 do not have ESPs (PM is captured in the scrubber), and therefore had ample room to install the

SCR easily. The cost, escalated to 201 3 dollars was $ 102 /kW for unit 1 and $ 140 /kW for unit 2. As

expecte d for an inside unit, unit 2 was more expensive than unit 1 although the boilers and equipment

are quite similar. Unit 3, with an ESP

, entailed a more complex ret rofit than either units 1 or 2 , and cost

$ 1 79 /kW escalated to 201 3 dollars.

Figure 15 . Para dise Power Plant

TVA has a large fleet of SCRs. A summary of the cost for their SCRs are shown in Table 3

. As

shown, there is a wide range of costs because there is also a wide range of difficulties. In this case the

most expensive SCR cost over $ 300/kW (escalated to 201 3 dollars) because of the difficulty in making

the duct connections between the SCR, the boiler and the air preheater. The least expensive SCR had

the advantage of not having an ESP and a significant amount of open area between the boiler and

scrubber.

Therefore, there are a number of factors that need to be considered when determining the

difficulty of a retrofit, but a number of situations

– such as routing boiler ductwork through boiler

buildings, building the SCR on an above gro und structure while trying to minimize the impact to

equipment below, addition of more fan capacity, and retrofitting side

- by

- side units are very common

issues (although side

- by

- side situations like Kingston are rare). Other factors that may vary from one Paradise 1 & 2 SCRs Paradise 3 SCR

### www.AndoverTechnology.com 24 unit to another include the need to relocate large pieces of equipment, the access to the site, complex

duct arrangements, the access for construction equipment near the boiler, equipment that may

interfere with construction but is not going to be relocat ed (like a retired chimney), etc. These other

factors are most often what determine if a retrofit will be significantly more expensive than normal. All

of these factors were considered in developing retrofit difficulty factors.

Table 3

. SCR costs for TV A coal power plants

Plant Unit SCR cost In

service Capacity

(net MW) $/kW $/kW (201 3 )

Allen 1 $30,500,000 2003 245 $124 $175

2 $28,800,000 2002 245 $118 $168

3 $50,000,000 2002 245 $204 $291

Bull Run 1 $210,000,000 2004 881 $238 $303

Colbert 5 $102 ,000,000 2003 459 $222 $312

Cumberland 1 $165,000,000 2003 1232 $134 $188

2 $159,000,000 2004 1233 $129 $164

Kingston 1 $25,250,000 2004 134 $188 $240

2 $25,250,000 2004 134 $188 $240

3 $25,250,000 2004 134 $188 $240

4 $25,250,000 2004 134 $188 $ 240

5 $28,000,000 2005 175 $160 $193

6 $28,000,000 2005 175 $160 $193

7 $28,000,000 2004 175 $160 $203

8 $28,000,000 2004 175 $160 $203

9 $21,000,000 2006 175 $120 $136

Paradise 1 $44,000,000 2001 616 $71 $102

2 $59,000,000 2000 602 $98 $140

3 $124,500,000 2003 977 $127 $179

Widows

Creek 7 $65,900,000 2003 473 $139 $196

8 $61,000,000 2004 464 $131 $167

Average $155 $204

Median $160 $193

Minimum $71 $102

Maximum $238 $312

• SCR Cost and In service date from Defendant's Resp onse to Plaintiff's Interrogatory #8,

North Carolina v. TVA, Filed with US District Court, Asheville, NC, September 1, 2006.



### • Cost escalation to 201 3 dollars using the CEPCI. Using June 2013 CEPCI of 564.9 as

published in September 2013 Chemical Engineerin g magazine

### www.AndoverTechnology.com 25 SCR Cost Estimates from Basin Electric and PacifiCorp

PacifiCorp and Basin Electric provided SCR cost estimates for the following units:

• Dave Johnston 3

• Naughton units 1 and 2

• Laramie River 1

- 3

As demonstrated in Table 1, t he cost estimates pr ovided by these companies were at the

extreme end of what has been experienced historically, or in some cases well above historical costs. As

a result, the cost estimates are definitely very conservative and include substantial built

- in contingency



### .

In al l three cases some costs were accepted and others were not . The following are specific

costs that were not accepted for any of these cost estimates.

1. Process Contingency

Although the Control Cost Manual ( CCM ) shows a process contingency of 5% in Table 2 .5 in

Section 4.2 (page 2

- 44) , this is not necessary today for SCR on coal fired boilers firing the coals used in

Wyoming. According to the Department of Energy’s National Energy Technology Laboratory

, 39



### “Process contingency is intended to compensate for uncertainty in cost estimates caused by

performance uncertainties associated with the development status of a technology. Process

contingencies are applied to each plant section based on its current technology status.”

According to that document, for comm ercially available technologies process contingency could

range from 0

- 10%.

When the CCM was issued in January 2002, SCR was commercially available but was only

emerging in application on coal fired utility boilers in the United States, According to a stu dy by

Cichanowicz, 40 

### at the end of 2001, there were only about 13,000 MW of coal SCR capacity in the United

States, with nearly all installed in the prior two years, meaning that there was very limited long

- term

experience with SCR on US coals. SCR usage on coal fired boilers has since increased about ten times to

about 130,000 MW of coal capacity (over 40% of all coal capacity) and is therefore a very well proven

and well understood technology on a wide range of US coals. As a result, the process conting ency for

SCR on coal fired utility boilers should be much lower today than what it was when the CCM was issued

in January 2002

– 5%. For SCR applications on utility boilers burning Powder River Basin coals, which are

very well understood SCR applications, there should not be a need for process contingency.

2. Project Contingency of 15% is too high in light of the cost method used and very conservative

underlying assumptions.

39 US Department of Energy, National Energy Technology Laboratory, “Cost Estimating Methodology for NETL

Assessments of Power Plant Performance”, DOE/NETL

- 2011/1455, April 2011, pg 4.

40 From data in Cichanowicz, J., Muzio, L., Hein, M., “The First 100 GW of SCR in the U.S.,

- What Have We

Learned?”, 2006 Mega Symposium

### www.AndoverTechnology.com 26 Because the cost estimates developed for PacifiCorp and Basin Electric are already very

conservative and based upon detailed estimates of the labor and materials to build the SCR, a 15%

project contingency is excessive.

According to the CCM, Section 1.1 Chapter 1, page 1

- 4,

“The accuracy of the information in the Manual works at two distinct levels.

From a regulatory standpoint, the Manual estimating procedure rests on the notion of the

“study” (or rough order of magnitude

- ROM) estimate, nominally accurate to within ± 30%. This

type of estimate is well suited to estimating control system costs intended for use in regulatory

development because they do not require detailed site

- specific information necessary for

industry level analyses.”

The methods and cost elements of the CCM were adapted from the American Association of

Cost Engi neers, or AACE (CCM Section 1, Chapter 2, p 2

- 5). AACE 16R

- 90 41 

### states that, “Project

Contingency is included to cover the costs that would result if a detailed

- type costing was followed as in

a definitive

- type study.” According to NETL, 42 

### “AACE 16R

- 90 st ates that project contingency for a

“budget

- type” estimate (AACE Class 4 or 5) should be 15% to 30% of the sum of BEC, EPC fees and

process contingency.” AACE 18R

- 97 43 

### defines different classes of estimates, from 5 (least detailed) to 1

(most detailed). The methodology used in the CCM falls into a Class 4 or Class 5, while the methodology

used by PacifiCorp and Basin Electric in their comments, with hundreds of line items and thousands of

input parameters and use of cost estimates from vendors , is clearly a far more detailed estimate that

leaves out very little, if any, project scope that would fall into a Class 1 or 2.

For this reason, t he 15% project contingency factor in the CCM for SCR shown in Table 2.5 on

page 2

- 44 of Section 4.2 Chapter 2 is based upon use of the cost estimating method described in the

CCM to develop the Total Direct Capital Costs. It is not intended to apply to a detailed estimate that:

• Includes many cost line items that are not explicitly included in the estimating method

describ ed in the CCM to develop the Total Direct Capital Costs and meant to be included in

the 15% project contingency, and

• Already has substantial contingency built into it through conservative assumptions.

In fact, the CCM discusses the importance of not doub le

- counting contingency in multiple places

such as retrofit factor and contingency at page 2

- 30 of Chapter 2

- Cost Estimation: Concepts and

Methodology

“Due to the uncertain nature of many estimates, analysts may want to add an additional

contingency (i. e., uncertainty) factor to their estimate. However, the retrofit factor is a kind of

contingency factor and the cost analyst must be careful to not impose a double penalty on the

system for the same unfor e seen conditions. Retrofit factors should be reserve d for those items

directly related to the demolition, fabrication, and installation of the control system. A

contingency factor should be reserved (and applied to) only those items that could incur a

reasonable but unanticipated increase but are not direct ly related to the demolition, fabrication,

41 AACE Recommended Practice, AACE 16R

- 90; www. aace i.org/non/rps/ 18R

- 90 .pdf

42 US Department of Energy, National Energy Technology Laboratory, “Cost Estimating Methodology for NETL

Assessments of Power Plant Performance”, DOE/NETL

- 2011/1455, April 2011, pg 5.

43 AACE Recommended Practice, AACE 16R

- 87; www. aace i.org/non/rps/ 18R

- 97 .pdf

### www.AndoverTechnology.com 27 and installation of the system. For example, a hundred year flood may postpone delivery of

materials, but their arrival at the job site is not a problem unique to a retrofit situation.”

(emphasis added)

The CCM, therefore, explicitly anticipates that some analysts may, incorrectly, apply multiple

contingencies for the same areas of cost even when using the methods described in the CCM for

estimating Total Direct Capital Costs. The CCM is clear that such double

- co unting should be avoided.

Because the cost estimates developed for Basin Electric and PacifiCorp are already very

conservative and based upon detailed estimates of the labor and materials to build the SCR, rather than

study

- level (class 4 or 5) estimates, they have double

- counted both the costs that are intended by the

CCM to be included in the project contingency when using the CCM method, plus they have added

additional contingency in the form of conservative assumptions to address uncertainties in their

estimate. For this reason a 15% project contingency is excessive for their estimate s

. In light of the very

conservative estimates they already developed and the comprehensive nature of those estimates, no

additional project contingency was allowed.

3. G eneral Facilities

General Facilities are costs that are not directly associated with the process equipment, and

inclu de such things as access roads , safety equipment (such as eye

- wash stations), general lighting, etc.

On the other hand, ductwork, piping, structural steel to support process equipment and process

auxiliaries (such as air compressors or cooling water) do not fall into the category of General Facilities.

The cost estimate from Babcock & Wilcox (for PacifiCorp) and Sargent & Lundy (Basin Ele ctric)

included a number of items that would fall into the category of General Facilities, and in order to avoid

double

- counting, an additional line item for General Facilities will not be included

.

With regard to Laramie River Station, the itemized cost estimate in the Appendices to Exhibit 14

from Basin Electric includes items that are normally incorporated into the General Facilities cost, while

Sargent & Lundy took an additional provision for General Facilities (Exhibit 14 at page 31). The itemized

c ost estimate by Sargent & Lundy in the Appendices to Exhibit 14, however, includes the cost of many

items that would normally fall under the category of General Facilities. This includes the cost of roads

and a parking area ($930,226 at page 2 of SCR esti mate), eye wash stations (page 3), a pre

- engineered

building for the construction warehouse ($780,000 page 8), fire protection systems (page 16), gratings,

handrails, ladders (page 22). As a result, Sargent & Lundy double counts for General Facilities by having

these costs accounted for in the itemized direct capital cost as well as in its Indirect Capital costs.



### The cost estimate by Babcock & Wilcox for SCR on Dave Johnston unit 3 and Naughton units

1 and 2 includes items like potable water systems, fire protection, service water, other assorted

non

- process auxiliaries as well as roads, fences, etc. which would fall into the category of General

Facilities. Therefore, there is no need to add additional 5% for General Facilities.

### www.AndoverTechnology.com 28 4. AFUDC

AFUDC is not incl uded in the overnight cost methodology of the CCM and therefore was not

allowed.

5. Other items

There are a number of other items that were in the estimates provided by Basin Electric or

PacifiCorp that have not been included in the capital costs. An example of this is additional overtime

costs in Basin Electric’s estimate that appeared excessive in light of assumed labor rates that were

already high when compared to published labor rates for construction trades. Another was excessive

fees for the Contractor , amounting to 14%, that were reduced to a value of 10% that is consistent with

what is used in the IPM. Because these costs were not supported by the information provided by Basin

Electric , they were not allowed or were reduced

.

### www.AndoverTechnology.com 29 

### D ave Johns t on, U nits 1

- 4

An overhead view of Dave Johns t on plant is shown in Figure 1 6 . 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

reductio n)

. 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

. 44 

### Units 3 and 4 have

already installed combustion controls as reflected in 2011 ann ual average NOx emission rates of 0.23

lb/MMBtu and 0.14 lb/MMBtu, respectively

.

Figure 1 6

. Dave Johnston Power Plant

Retrofit costs

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

units. Retrofit costs for combustion controls are based upon company estimates for Units 3 and 4.

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

### www.AndoverTechnology.com 30 However, s ince 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. 45



### It was previously determ ined that post

- combustion NOx controls, including SCR, are feasible,

but they were not selected in Wyoming’s proposal as BART due to cost. 44 

### Based upon the close

proximity of the boilers and associated equipme nt to one another, decommissioned chimneys that will

limit access and ability to move a crane, the coal pile and coal conveyors that also limits access to the

area of the units where construction would occur, the office building that is adjacent to unit 1 and limits

access, and the unit 4 scrubber, retrofit of an SCR on Units 1

- 4 would likely entail a significantly higher

than average retrofit cost. Unit 4 probably has the best access of all of the units because there may be

some space between the boiler a nd the scrubber, but it is difficult to say for sure from the image and

therefore a conservatively high retrofit difficulty was used for unit 4 that is co nsistent with the other

units.

Based upon the aforementioned site issues the estimates of capital cos t shown in Tables 3a (20

year life) and 3b (9 years life for DJ3) are , in the case of DJ 1, 2, and 4, adjusted for retrofit difficulty

using subjective factors that are integrated into the IPM cost estimating algorithms and a retrofit

difficulty factor of 1.5 is assumed for all units. PacifiCorp provided an estimate of the cost of SCR for

DJ3, and ATP has accepted that with a number of exceptions. When adjusting for items that are

duplicative in cost (Project and Process Contingencies, General Facilities) , the estimate using the cost

provided by PacifCorp produces a very similar result as the cost that results from the IPM model.

I t is unclear why in the estimate developed by B&W that the horizontal ductwork to the SCR

reactor (shown in Figure s 17a and b ) is as long as it is. There are no apparent obstructions in the

drawings provided by Pacificorp or in the satellite photo that make such a long horizontal duct run

necessary . The length of this duct run locates the SCR reactor above the retired chimney, which makes

demolition of the chimney necessary. It appears that a shorter horizontal duct run and perhaps a

change in the width and depth of the SCR reactor would reduce the cost of ductwork and might also

make it possible to avoid demolition of the chi mney. These effects might reduce the cost from what is

estimated by Babcock & Wilcox.

Because combustion controls were placed in service around 2010, a life of 17 years is used for

the combustion controls and 9 years for post

- combustion controls in the sh orter life case. Costs are

shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combinatio n with SCR

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

capital 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 beginning on page 3 of this report.

### www.AndoverTechnology.com 31 Figure 17a. Drawing of SCR at Dave Johnston 3

– side view 46



### Figure 17b. Drawing of SCR at Dave Johnston 3

– top view 46

46 Babcoc k & Wilcox, Selective Catalytic Reduction Systems Naughton Units 1 and 2 and Dave Johnston Unit 3

Budgetary Cost Estimate, August 19, 2013

### www.AndoverTechnology.com 32 Table 3 a

. Dav e Johnston Estimated Control Costs

DJ 1 Cost of controls

Comb ustion Control

(CC) 

### SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $95 $20 $422 $115 $517

Control Efficiency 56% 25% 75% 67% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 536 236 236 536 536

NOx Rate (lb/MMBtu) 0.45 0.20 0.20 0.45 0.45

NOx (TPY) 2188 962 962 2188 2188

Controlled Rate

NOx Rate (lb/hr) 236 177 59 176.82 58.94

NOx Rate (lb/MMBtu) 0.20 0.15 0.05 0.15 0.05

NOx (TPY) 962 721 240 721.37 240.46

Tons/Year Removed 1226 240 721 1466.31 1947.23

Total Cost/year $1,214,000 $882,430 $5,594,374 $2,096,430 $6,808,374

$/Ton $990 $3,670 $7,755 $1,430 $3,496

$/ton Incremental $9,798 $3,670 $9,798



### DJ 2 Cost of controls

Comb ustion Control

(CC) 

### SNCR SCR CC and SNCR CC and SCR

Capi tal Cost, $/kW $115 $20 $422 $135 $537

Control Efficiency 55% 25% 75% 66% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 519 236 236 519 519

NOx Rate (lb/MMBtu) 0.44 0.20 0.20 0.44 0.44

NOx (TPY) 2161 981 981 2,161 2,161

Controlled Rate

NOx Rate (lb/hr) 236 177 59 177 59

NOx Rate (lb/MMBtu) 0.20 0.15 0.05 0.15 0.05

NOx (TPY) 981 736 245 736 245

Tons/Year Removed 1180 245 736 1,425 1,916

Total Cost/year $1,441,146 $893,877 $5,596,824 $2,335,022 $ 7,037,969

$/Ton $1,221 $3,645 $7,607 $1,638 $3,673

$/ton Incremental $9,588 $3,645 $9,588

### www.AndoverTechnology.com 33 Table 3 a

. Dav e Johnston Estimated Control Costs

DJ 3 Cost of controls

Combustion Control

(CC) 

### SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $73 $ 20 $368 $93 $440

Control Efficiency 58% 25% 77% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 528 528 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.22 0.22 0.51 0.51

NOx (TPY) 4913 2077 2077 4,913 4,913

Controlled Rate

NOx Rate (lb /hr) 528 396 122 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05 0.16 0.05

NOx (TPY) 2077 1558 480 1,558 480

Tons/Year Removed 2837 519 1597 3,356 4,433

Total Cost/year $1,699,807 $1,810,782 $9,980,337 $3,510,589 $11,680,144

$/Ton $599 $3,488 $6,251 $1,046 $2,635

$/ton Incremental $7,583 $3,488 $7,583



### DJ 4 Cost of controls

Comb ustion Control

(CC) 

### SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $22 $20 $338 $42 $360

Control Efficiency 61% 20% 65% 69% 86%

U ncontrolled Rate

NOx Rate (lb/hr) 1325 511 511 1325 1325

NOx Rate (lb/MMBtu) 0.37 0.14 0.14 0.37 0.37

NOx (TPY) 5070 1956 1956 5,070 5,070

Controlled Rate

NOx Rate (lb/hr) 511 409 181 409 181

NOx Rate (lb/MMBtu) 0.14 0.11 0.05 0.11 0.05

NOx (TPY) 1956 1565 692 1,565 692

Tons/Year Removed 3114 391 1264 3,505 4,377

Total Cost/year $767,342 $1,774,258 $13,391,557 $2,541,600 $14,158,899

$/Ton $246 $4,535 $10,595 $725 $3,235

$/ton Incremental $13,312 $4,535 $13,312

### www.AndoverTechnology.com 34 Table 3 b

. Dav e Johnston Estimated Control Costs for 9 year life for SNCR and SCR and a 17 year life

for combustion controls

DJ 3 Cost of controls

Comb ustion Control

(CC) (already installed) 

### SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $73 $20 $368 $93 $440

Control Efficiency 58% 25% 77% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 528 528 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.22 0.22 0.51 0.51

NOx (TPY) 4913 2077 2077 4,913 4,913

Controlled Rate

NOx Rate (lb/hr) 528 396 122 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05 0.16 0.05

NOx (TPY) 2077 1558 480 1,558 480

Tons/Year Removed 2837 519 1597 3,356 4,433

Total Cost/year $1,828,137 $2,070,793 $14,7 62,870 $3,898,930 $16,591,006

$/Ton $644 $3,988 $9,247 $1,162 $3,742

$/ton Incremental $11,781 $3,988 $11,781

### www.AndoverTechnology.com 35 

### Jim Bridger

, U nits 1

- 4

An overhead view of Jim Bridger plant is shown in Figure 1 8

. All four units are tangentially fired

and are cur rently equipped with combustion controls to reduce NOx emissions. Annual emission rates

with combustion controls are assumed to be the lesser of the 2011 or 2012 annual average emission

rate.

Retrofit costs

Retrofit costs for combustion controls are based upon company estimates. Retrofit costs for

SNCR are expected to be consistent with other similar units and a presumed capital cost of $20/kW is

assumed. 47



### It was previously determined that post

- combustion NOx controls, including SCR, are feasible,

but the y were not selected in Wyoming’s proposal as BART due to cost. 48 

### The estimates of SCR capital

cost made here are adjusted for retrofit difficulty using subjective factors that are integrated into the

IPM cost estimating algorithms. Based upon the satellit e photo, the SCR reactors would likely be

installed above the ESPs and ductwork routed to the boiler. The boilers do not appe ar to be unusually

constrained from the perspective of installing SCR ductwork; however, access for construction

equipment will be much more difficult to achieve for the two middle units

. The scrubbers and

associated piping will limit access somewhat. Unit 4 access will be limited somewhat by the coal

conveyor and because it’s scrubber takes up more room than the other scrubbers

. For this reason a

retrofit difficulty factor of 1.5 is assumed for the middle units and 1.25 for unit s 1 and 4

.

Table 4 shows the estimated costs of control for each of the Jim Bridger units. Costs are shown

for:

• Combustion Controls alone

• SNCR alone but a fter installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

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

estimate of capital 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 report

. 48 Wyoming Department of Environmental Quality on Jim Bridger Power Plant AP

- 60 40 BART Application Analysis,

May 28, 2009

### www.AndoverTechnology.com 36 Figure 1 8

. Jim Bridger Power Plant

### www.AndoverTechnology.com 37 Table 4

. Jim Bridger Estimat ed Control Costs

JB 1 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $278 $39 $297

Control Efficiency 54% 20% 72% 63% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2175 998 998 2175 2175

NO x Rate (lb/MMBtu) 0.39 0.18 0.18 0.39 0.39

NOx (TPY) 8426 3868 3868 8426 8426

Controlled Rate

NOx Rate (lb/hr) 998 799 277 798.61 277.29

NOx Rate (lb/MMBtu) 0.18 0.14 0.05 0.14 0.05

NOx (TPY) 3868 3094 1074 3094.39 1074.44

Tons/Year Removed 4558 774 2794 5332.02 7351.97

Total Cost/year $1,167,297 $3,162,755 $18,204,809 $4,330,052 $19,372,105

$/Ton $256 $4,088 $6,517 $812 $2,635

$/ton Incremental $7,447 $4,088 $7,447



### JB 2 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $330 $39 $350

Control Efficiency 50% 20% 73% 60% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2035 1018 1018 2035 2035

NOx Rate (lb/MMBtu) 0.37 0.19 0.19 0.37 0.37

NOx (TPY) 7577 3789 3789 7,577 7,577

Controlled Rate

NOx Rate (lb/hr) 1018 814 275 814 275

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3789 3031 1022 3,031 1,022

Tons/Year Removed 3787 758 2767 4,545 6,554

Total Cost/year $1,167,297 $3,123,887 $21,140,195 $4,291,184 $22,307,492

$/Ton $308 $4,122 $7,641 $944 $3,403

$/ton Incremental $8,968 $4,122 $8,968

### www.AndoverTechnology.com 38 Table 4

. Jim Bridger Estimated Control Costs

JB 3 Cost of controls

Comb ustion Co ntrol

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $333 $39 $353

Control Efficiency 47% 20% 75% 58% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2056 1085 1085 2056 2056

NOx Rate (lb/MMBtu) 0.37 0.20 0.20 0.37 0.37

NOx (TP Y) 7853 4143 4143 7,853 7,853

Controlled Rate

NOx Rate (lb/hr) 1085 868 276 868 276

NOx Rate (lb/MMBtu) 0.20 0.16 0.05 0.16 0.05

NOx (TPY) 4143 3314 1054 3,314 1,054

Tons/Year Removed 3710 829 3089 4,539 6,799

Total Cost/year $1,167,297 $3,291,479 $21,406,623 $4,458,776 $22,573,920

$/Ton $315 $3,972 $6,931 $982 $3,320

$/ton Incremental $8,015 $3,972 $8,015



### JB 4 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cos t, $/kW $19 $20 $280 $39 $299

Control Efficiency 51% 20% 74% 61% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2200 1074 1074 2200 2200

NOx Rate (lb/MMBtu) 0.40 0.19 0.19 0.40 0.40

NOx (TPY) 8133 3972 3972 8,133 8,133

Controlled Rate

NOx Rate (lb/hr) 1074 859 277 859 277

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3972 3178 1026 3,178 1,026

Tons/Year Removed 4161 794 2946 4,956 7,108

Total Cost/year $1,167,297 $3,205,160 $18,327,121 $4,372,457 $19,494,417

$/Ton $281 $4,035 $6,220 $882 $2,743

$/ton Incremental $7,027 $4,035 $7,027

### www.AndoverTechnology.com 39 

### 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 w ith LNBs and OFA and averaged under 0.20 lb/MMBtu in 2012

.

Retrofit Costs

Data provided by Basin Electric indicated a very high furnace exit temperature. As a result, it is

anticipated that a more costly injection system was likely and Basin Electric’s estimate of SNCR capital

cost was accepted. In addition, in light of the high temperature, a reagent utilization rate of 12% was

assumed, per information from Basin Electric.

The plant is shown in Figures 1 9 a an d 1 9 b. These figures show a less cons train ed site than Dave

Johnston, with good access to both units 1 and 3. The coal conveyor is clearly visible and will be an

obstruction for the unit 2 SCR. As a result, retrofit difficulty of installing SCR 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 when the IPM algorithms were used an 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.

Basin Electric’s estimated cost of constructing the SCRs was accepted, but without some items

such as additional overtime, project contingency, process contingency and general facilities. The

detailed cost e stimate by Sargent & Lundy for Basin Electric already included the costs that would fall

into those categories, and it would therefore be double counting to additionally include those costs.

Also, the assumed labour rates for construction labour were well in excess of published rates, suggesting

that allowances for overtime were already incorporated into the labour rates.

Information from Basin Electric (see Figures 20 a and b) demonstrates that SCR ductwork and

configuration are typical arrangements, witho ut the need for any unusually long ductwork routing or

relocation of major equipment. The modifications necessary to install the SCR are modifications that are

routinely necessary for SCR retrofits.

The W yoming analysis indicated that NOx should be reduce d to around 0.18±0.02 lb/MMBtu

with LNB and OFA and suggested a 30

- day rolling average rate of 0.23 lb/MM Btu

. 49 

### Recent emission

data is shown in Table 2 and confirm that these rates are possib l e

. Wyoming had previously suggested

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

. 50



### The cost analysis of Table 5 shows slightly differ ent 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

49 DEPARTMENT OF ENVIRONMENTAL QUALITY, AIR QUALITY DIVISION, BART Application A nalysis, AP

- 6047, Laramie River

Station, May 28, 2009 , pages 7 and 8

50 Email from Fuel Tech, October 15, 2012

### www.AndoverTechnology.com 40 levels, which affect the costs. In addition, a ccording to NEEDS data, unit 1 has slightly lower capaci ty

than units 2 and 3 (565 MW versus 570 MW). NEEDS also indicated slightly different heat rates for the

units, which impact capacity factors and tons of NOx emitted. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of com bustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

### www.AndoverTechnology.com 41 Figure 1 9 a

. Laramie River Units 1

- 3

Figure 1 9 b

. Laramie River Units 1

- 3

### www.AndoverTechnology.com 42 Figure 20 a L aramie River SCR

– Side View of SCR 51



### Figure 20 b

. Laramie River SCR

– top view 51

51 Appendices to Exhibit 14 of Basin Electric Comments

### www.AndoverTechnology.com 43 Table 5

. Laramie River Estimated Control Costs

LR 1 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC an d SCR

Capital Cost, $/kW $37 $30 $282 $67 $319

Control Efficiency 26% 20% 74% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1652 1227 1227 1652 1652

NOx Rate (lb/MMBtu) 0.26 0.19 0.19 0.26 0.26

NOx (TPY) 6051 4495 4495 6,051 6,051

Cont rolled Rate

NOx Rate (lb/hr) 1227 982 320 982 320

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4495 3596 1170 3,596 1,170

Tons/Year Removed 1556 899 3324 2,455 4,880

Total Cost/year $2,268,806 $6,286,091 $19,501,329 $8,554,896 $21,770,134

$/Ton $1,458 $6,993 $5,866 $3,485 $4,461

$/ton Incremental $5,449 $6,993 $5,449



### LR 2 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $37 $30 $294 $67 $331

Control Efficiency 29% 20% 74% 43% 82%

Uncontrolled Rate

NOx Rate (lb/hr) 1688 1199 1199 1688 1688

NOx Rate (lb/MMBtu) 0.27 0.19 0.19 0.27 0.27

NOx (TPY) 6293 4470 4470 6,293 6,293

Controlled Rate

NOx Rate (lb/hr) 1199 959 312 959 312

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4470 3576 1164 3,576 1,164

Tons/Year Removed 1823 894 3306 2,717 5,129

Total Cost/year $2,268,806 $6,262,825 $20,422,662 $8,531,631 $22,691,467

$/Ton $ 1,244 $7,006 $6,178 $3,140 $4,424

$/ton Incremental $5,871 $7,006 $5,871

### www.AndoverTechnology.com 44 Table 5

. Laramie River Estimated Control Costs

LR 3 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $37 $30 $294 $67 $331

Co ntrol Efficiency 28% 20% 74% 42% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1778 1279 1279 1778 1778

NOx Rate (lb/MMBtu) 0.27 0.19 0.19 0.27 0.27

NOx (TPY) 6375 4586 4586 6,375 6,375

Controlled Rate

NOx Rate (lb/hr) 1279 1023 3 33 1023 333

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4586 3669 1194 3,669 1,194

Tons/Year Removed 1789 917 3392 2,706 5,181

Total Cost/year $2,268,806 $6,375,033 $20,398,176 $8,643,839 $22,666,982

$/Ton $ 1,268 $6,951 $6,014 $3,194 $4,375

$/ton Incremental $5,667 $6,951 $5,667

### www.AndoverTechnology.com 45 

### 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

. I t 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 pres umed 30 day average by Wyoming, thereby accounting for the longer averaging period

.

Retrofit costs

Naughton U nits 1

- 3 a re shown in Figure 21

. Like most of the other plants, SNCR costs are

assumed to be $20/kW.

Babcock & Wilcox provided cost estimates for th e Naughton unit 1 & 2 SCRs. Babcock &

Wilcox’s estimate assumed that it would be necessary to demolish stacks that will be abandoned after a

planned scrubber installation and they also determined that additional fan capacity was not necessary.

Babcock & Wilcox also assumed a complex support structure would be needed, which adds cost.

Babcock and Wilcox also stated that units 1 and 2 are slightly offset which makes it impractical to build a

common support structure for the SCR reactors; however, as shown in Figures 22, 23, and 24, Babcock &

Wilcox has used a longer horizontal duct run on the unit 1 SCR which places the unit 1 and unit 2 SCR

reactors side

- by

- side so that a common support structure is likely to be possible, offering some potential

savings fr om what they have estimated. Alternatively, a shorter horizontal duct run on unit 1 may make

it possible to avoid demolition of the unit 1 chimney that will be abandoned. When using the IPM

algorithm a retrofit diffi culty factor of 1.3 is assumed. T his w as based upon the fact that it appeared to

be a less congested site than Dave Johnston, but there were potential challenges, such as the chimneys,

that could result in longer duct runs or additional demolition.

For unit 3 it is also unclear if there is eno ugh space to install the SCR reactor on the same side of

the chimney as the boiler , which

, means that demolition of that chimney may be needed

. There

appears to be access for construction equipment, such as a crane, in the area east of the plant (the

uppe r part of the photo) and to the north of unit 3

. In estimating the cost of the SCR for unit 3, retrofit

difficulty is above average because more lengthy duct runs or demolition of the chimney are likely

needed , and an assumed retrofit difficulty factor of 1.3 is assumed for unit 3

.

Results of cost calculations for a 20 year life are shown in Table 6 a and Table 6b for an 11 year

life for units 1 and 2

. Because combustion controls were placed in service around 2012, a life of 17

years is used for the combus tion controls and 11 years for post

- combustion controls in the shorter life

case. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion co ntrols in combination with SNCR

• Combustion controls in combination with SCR

### www.AndoverTechnology.com 46 Figure 21

. Naughton U nits 1

- 3

–

### www.AndoverTechnology.com 47 Figure 22. Naughton unit 1 SCR

– side view 52



### Figure 23 . Naughton unit 2 SCR side view 52

52 Babcock & Wilcox, Selective Catalytic Reduction Systems Naughton Units 1 and 2 and Dave Johnston Unit 3

Budgetary Cost Estimate, August 19, 2013

### www.AndoverTechnology.com 48 F igure 24. Naughton 1 (right) & 2 (left) SCRs, top view 53

53 Developed from Babcock & Wilcox, Selective Catalytic Reduction Systems Naught on Units 1 and 2 and Dave

Johnston Unit 3 Budgetary Cost Estimate, August 19, 2013

### www.AndoverTechnology.com 49 Table 6 a

. Naughton Estimated Control Costs

N 1 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $55 $20 $467 $75 $521

Control Efficiency 59% 25% 76% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 366 366 895 895

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 3553 1453 1453 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1453 1090 345 1090 345

Tons/Year Removed 2100 363 1109 2463 3209

Total Cost/year $932,466 $1,302,361 $9,042,150 $2,234,827 $9,974,616

$/Ton $444 $3,584 $8,155 $907 $3,109

$/ton Incre mental $10,384 $3,584 $10,384



### N 2 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $40 $20 $353 $60 $393

Control Efficiency 60% 25% 76% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 474 474 1174 1174

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 4337 1752 1752 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1752 1314 415 1314 415

Tons/Year Removed 2586 438 1336 3024 3922

Total Cost/year $883,900 $1,596,932 $9,178,850 $2,480,832 $10,062,750

$/Ton $342 $3,647 $6,869 $820 $2,566

$/ton Incremental $8,440 $3,647 $8,440

### www.AndoverTechnology.com 50 Table 6 a

. Naughton Estimated Contr ol Costs

N 3 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $3 $20 $322 $23 $325

Control Efficiency 10% 30% 85% 37% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1266 1142 1142 1266 1266

NOx Rate (lb/MMBtu) 0.37 0.33 0.33 0.37 0.37

NOx (TPY) 4544 4101 4101 4544 4544

Controlled Rate

NOx Rate (lb/hr) 800 173 800 173

NOx Rate (lb/MMBtu) 0.33 0.23 0.05 0.23 0.05

NOx (TPY) 4101 2871 621 2871 621

Tons/Year Removed 442 1230 3480 1673 3922

Total Cost/year $106,393 $3,745,984 $13,498,309 $3,852,377 $13,604,702

$/Ton $240 $3,045 $3,879 $2,303 $3,469

$/ton Incremental $4,335 $3,045 $4,335

### www.AndoverTechnology.com 51 Table 6 b

. Naughton Estimated Control Costs for 11 year life for SNCR and SCR and 17 year life for

combustion controls

N 1 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $55 $20 $353 $75 $407

Control Efficiency 59% 25% 76% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 366 366 895 895

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 3553 1453 1453 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1453 1090 345 1090 345

Tons/Year Removed 2100 363 1109 2463 3209

Total Cost/year $1,002,863 $1,427,046 $11,950,751 $2,429,910 $12,953,615

$/Ton $478 $3,927 $10,779 $986 $4,037

$/ton Incremental $14,118 $3,927 $14,118



### N 2 Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $40 $20 $334 $60 $374

Control Efficiency 60% 25% 76% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 474 474 1174 1174

NOx Rate (lb/MMBtu) 0. 52 0.21 0.21 0.52 0.52

NOx (TPY) 4337 1752 1752 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1752 1314 415 1314 415

Tons/Year Removed 2586 438 13 36 3024 3922

Total Cost/year $950,631 $1,760,581 $12,069,960 $2,711,212 $13,020,591

$/Ton $368 $4,020 $9,033 $897 $3,320

$/ton Incremental $11,476 $4,020 $11,476

### www.AndoverTechnology.com 52 

### 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 mo nths 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 b e located above the

existing (but decommissioned) ESP shown between the boiler building and the chimney in Figure 2 5

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

appears to be possible ; however , in every direction from the boiler there is a potential interference that

might complicate crane location relative to the lay

- down area . Therefore, the difficulty of this retrofit is

probably average to perhaps above average

. A conservative estimat e of retrofit difficulty of 1.3 is

assumed , although a closer examination of the site may show that a lower retrofit difficulty may be

possible.

Table 7 shows the results of cost calculations. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

### www.AndoverTechnology.com 53 Figure 2 5

. Wyodak Power Plant

### www.AndoverTechnology.com 54 Table 7

. Wyodak Estimated Contr ol Costs

Cost of controls

Comb ustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $36 $20 $321 $56 $357

Control Efficiency 27% 20% 74% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1060 775 775 1060 1060

NOx Rate (lb/M MBtu) 0.26 0.19 0.19 0.26 0.26

NOx (TPY) 4615 3376 3376 4,615 4,615

Controlled Rate

NOx Rate (lb/hr) 775 620 202 620 202

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3376 2701 880 2,701 880

Tons/Year Removed 1239 675 2496 1,914 3,735

Total Cost/year $1,272,427 $2,454,146 $13,801,075 $3,726,573 $15,073,502

$/Ton $1,027 $3,635 $5,530 $1,947 $4,036

$/ton Incremental $6,233 $3,635 $6,233