BILLINGS GENERATION, INC.
 

Suite 200
 

1087 West River Street
 

Boise, Idaho 83702
 

Telephone (208) 344-3570
 

Telecopier (208) 344-3984
 

February 24, 2011 

Vanessa Hinkle, 8P-AR 

U.S. Environmental Protection Agency 

Region 8 

1595 Wynkoop Street 

Denver, CO 80202-1129 

Dear Ms. Hinkle: 

The attached report IS In response to your letter requesting additional Reasonable 

Progress Information for the Yellowstone Energy Limited Partnership (YELP) facility 

located in Billings, Montana. Billings Generation, Inc. (BGI) has conducted an analysis 

of control options for the potentially affected units at the YELP facility and included the 

four factors included in 40 CFR §51.308(d)(1 )(i)(A): the costs of compliance, the time 

necessary for compliance, the energy and non-air quality impacts of compliance, and 

the remaining useful life of the potentially affected sources. 

Pursuant to Section 114(c) of the Clean Air Act, 42 U.S.C. §7414(c), and 40 C.F.R Part 

2, Subpart B, BGI is entitled to assert a business confidentiality claim covering all or part 

of the attached report. BGI hereby asserts that all financial information included in the 

attached report is confidential until 2029. This date was chosen due to contractual 

agreements which are discussed in the attached report. The emission rate information 

included in the attached report is already available to the public and is not declared 

confidential by BGI. 

Please contact me or Scott Siddoway at Rosebud Operating Services (208-344-3570) if 

ou n y her' ormation. 
STATEMENT OF CERTIFICATION
 

Title:
 

Date: /~ '! III
 
RESPONSE TO REQlTEST FOR ADDITIONAL
 

REASONABLE PROGRESS INFORMATION FOR
 

THE YELLOWSTONE ENERGY LIMITED
 

PARTNERSHIP FACILITY PURSUANT TO
 

SECTION 114(A) OF THE CLEAN AIR ACT (42
 

U.S.C SECTION 7414(A))
 

Preparedfor: 

Billings Generation, Inc.
 

Suite 200
 

1087 West River Street
 

Boise, ID 83702
 

Prepared by: 

~BISON
 ENGINEERING, INC. 

1400 11 th Avenue 

Helena, MT 59601 

406-442-5768 

www.bison-eng.com 
TABLE OF CONTENTS
 

1.0 INTRODUCTION 1-1 

1.1 Introduction 1-1 

1.2 Regulatory Summary 1-1 

1.3 Selection of Reasonable Progress 1-2 

2.0 COSTS OF COMPLIANCE 2-1 

2.1 Circulating Fluidized Bed Boiler Information 2-1 

2.2 Particulate Matter 2-1 

2.3 Sulfur Dioxide 2-2 

2.3.1 Control Technologies Considered 2-2 

2.3.2 Eliminating Technically Infeasible Options 2-4 

2.3.3 Technically Feasible Options 2-5 

2.3.4 Cost-Effectiveness 2-6 

2.4 Nitrogen Oxides 2-6 

2.4.1 Control Technologies Considered 2-7 

2.4.2 Eliminating Technically Infeasible Options 2-9 

2.4.3 Technically Feasible Options 2-9 

2.4.4 Cost-Effectiveness 2-9 

3.0 TIME NECESSARY FOR COMPLIANCE 3-1 

3.1 Time Necessary for Compliance 3-1 

3.1.1 Installation of S02 Controls 3-1 

3.1.2 Installation of NOx Controls 3-1 

4.0 ENERGY AND NON-AIR QUALITY IMPACTS OF COMPLIANCE 4-2 

4.1 Energy Impacts 4-2 

4.1.1 Energy Impacts: S02 Controls 4-2 

4.1.2 Energy Impacts: NOx Controls 4-2 

4.2 Non-Air Quality Impacts 4-2 

4.2.1 Non-Air Quality Impacts: S02 controls 4-2 

4.2.2 Non-Air Quality Impacts: SCR or SNCR. 4-3 

5.0 REMAINING USEFUL LIFE OF THE POTENTIALLY AFFECTED SOURCES 5-1 

6.0 VISIBILITY MODELING RESULTS 6-1 

6.1 Visibility Modeling Results 6-1 

7.0 SOX CONTROL ECONOMIC RESULTS AND IMPACTS TO ViSiBILiTy 7-3 

7.1 NOx Control Economic Results and Impacts to Visibility 7-4 

8.0 SUMMARy 8-1 

APPENDIX A -COSTS OF COMPLIANCE ANALySiS 8-1 

APPENDIX B - MODELING 2 

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1.0 INTRODUCTION
 

1.1 Introduction 

On November 15, 2010, Billings Generation, Inc (BGI) received a letter from EPA 

requesting an analysis of control options for the Billings facility (Yellowstone Energy 

Limited Partnership Facility, YELP). The letter was written plJrsuant to Section 114(a) of 

the Federal Clean Air Act. The letter notes that in 2006, the Montana Department of 

Environmental Quality (MDEQ) withdrew its development of a state implementation plan 

(SIP) for regional haze under the Regional Haze Rule (RHR).1 EPA stated in their 

November letter that in order to develop the technical and policy work to implement 

RHR, the agency requested information from BGI and other affected facilities in January 

of 2009. BGI complied with the 2009 information request and provided EPA Region 8 

with the requested information. After reviewing the information provided, the EPA has 

now requested BGI conduct further analysis on its two circulating fluidized bed boilers 

for the purposes of meeting the reasonable progress goals (RP) of the RHR. More 

specifically, EPA has requested "an analysis of control options." The November letter 

goes on to ask that the analysis "address the four factors included in 40 CFR 

§51.308(d)(1)(i)(A)." These factors are summarized as: 

(1) The costs of compliance, 

(2) The time necessary for compliance, 

(3) The energy and non-air quality impacts of compliance, and 

(4) The remaining useful life of the potentially affected sources. 

This report serves as BGI's response to the EPA's information request. The remainder 

of this document provides the requested analysis. 

1.2 Regulatory Summary 

Before analyzing EPA's request, it is instructive to review the nature and purpose of the 

visibility protection program in order to ascertain important criteria that will lead to the 

selection of specific Reasonable Progress requirements. 

We begin the summary by observing that the entire program of protecting visibility is 

found as 40 CFR 51, Subpart P (subsections 300 through 309). A review of Subpart P 

indicates the purpose and goals of the program. The overall purpose of the program is 

outlined as follows: 

"The primary purposes of this subpart are . ..to assure reasonable 

progress toward meeting the national goal ofpreventing any future, and 

remedying any existing, impairment of visibility in mandatory Class I 

Federal areas . ..." [40 CFR 51.300(a)]. 

1 The RHR is a reference to the visibility protection program outlined in 40 CFR 51.308. The entire 

visibility program, including RHR, is found in 40 CFR 51, Subpart P. 

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Yellowstone Energy Limited Partnership, Billings Plant Page 1-1
 
For convenience, the visibility program may then be thought of as the implementation of 

two sub-programs. One regards new source review (PSD, etc.) and the other addresses 

regional haze. Regional haze may further be broken down into the BART program and 

the Reasonable Progress program. The underlying reason for EPA's letter to BGI is to 

address the Reasonable Progress portion of visibility protection. 

In that regard, the RHR (§308(d)) outlines what it refers to as: "the core requirements" 

for the implementation of regional haze. More specifically, §308(d)(1) states: 

"For each mandatory Class I Federal area . .., the State must establish 

goals . .. that provide for reasonable progress towards achieving natural 

visibility conditions. The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days . .." [40 CFR 

51.308(d)(1 )]. 

The rules go on to provide states (EPA in this case) with what must be considered in 

developing reasonable progress. These details were outlined above and in the 

November 5 letter. 

1.3 Selection of Reasonable Progress 

EPA is tasked to establish Reasonable Progress in carrying out the visibility protection 

program. Section 1.2 outlines the purpose of the program along with some core 

elements. To that end, EPA has asked for "an analysis of control options" which will, we 

assume, be used in order to establish a set of specific control strategies that create 

"reasonable progress." 

The review of control options notwithstanding, it seems the visibility program is clear as 

to its intent. That is, the purpose of the program is to protect (remedy, prevent or 

otherwise) visibility in mandatory Class I areas. Based on the language contained in the 

rule, it is also quite clear that any activity (proposed or otherwise) that does not "improve 

visibility" is not, therefore, a candidate for those "reasonable progress" goals. 

As a result, we believe an analysis that only provides emission control options is not 

sufficient for inclusion into reasonable progress elements unless those emission 

controls improve visibility. It would be foolhardy to include an emission control scenario 

as part of a regional progress goal without an improvement in regional haze (i.e. a 

discernible change in deciviews). 

To that end, we have chosen to not only analyze various control options using the four 

factor test outlined in the November letter, we have also conducted a brief analysis of 

the impacts this facility has on the nearest mandatory Class I areas. This was 

accomplished to determine if any of the possible control options would fulfill the 

underlying need of the program which would "provide for an improvement in 

visibility. ,,2 

2 40 CFR 51.308(d)(1). 

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The visibility impact of YELP or any of the control options, via dispersion modeling, is 

presented in subsequent sections of this document. The reader is referred to those 

sections for details on the analysis method and the results of those investigations. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 1-3
 
2.0 COSTS OF COMPLIANCE
 

This section of the RHR Section 114 response will describe the costs of compliance to 

meet the reasonable progress goals and strategies of the RHR. The EPA has requested 

that BGI determine the costs of compliance for particulate matter (PM), nitrogen oxides 

(NOx), and sulfur dioxide (S02). Additional information related to the costs of 

compliance is provided in Section 6.0 Visibility Modeling Results. 

2.1 Circulating Fluidized Bed Boiler Information 

BGI operates two circulating fluidized bed boilers at the Yellowstone Energy Limited 

Partnership Facility (YELP). The boilers began operation in 1995 and combust 

petroleum coke and coker gas. Emissions from both boilers exit a single, 199 foot stack. 

More detailed information on the facility was provided in the March 13, 2009, Section 

114 response provided to EPA. 

2.2 Particulate Matter 

Particulate matter (PM) from YELP's two boilers is currently controlled by two 

baghouses. The baghouses are made by Amerex and were installed when YELP began 

operation in 1995. The baghouses achieve >99% control of particulate matter. 

YELP must control particulate emissions to 0.03 Ib/MMBtu per Title V Operating Permit 

OP2650-01. Compliance with this limit is demonstrated via annual emission testing 

using Method 19 and Method 5 as specified in 40 CFR 60, Subpart Da. Below is a 

summary of YELP's PM and PM10 emission testing results from 2008 through 2009: 

Table 2.2-1: 2008-2009 PM and PMlO Emission
 

Testing Results
 

Year PM (Ibs/MMbtu) PM10 (Ibs/MMbtu) 

2008 0.006 0.002 

2009 0.006 0.002 

A January 2011 review of the RACT/BACT/LAER Clearinghouse Database (RBLC) for 

Utility and Large Industrial-Size Boilers/Furnaces (more than 250 million Btu/hr) that fire 

coal shows controlled particulate emission rates from 0.0120 Ib/MMbtu to 0.1500 

Ib/MMbtlJ. YELP's particulate emission test results demonstrate that particulate is 

currently being controlled to a level that is 50% of the current BACT for PM (0.006 

Ibs/MMbtu vs. 0.0120 Ib/MMbtu). Based on experience, conducting a cost analysis for 

additional controls to a clearly superior existing control device would show that 

additional control would be prohibitively expensive with minimal improvement to visibility 

impacts. Therefore, we conclude that PM is being controlled to a level that satisfies the 

RP goals of the RHR and no further cost analysis is warranted. Please see the Visibility 

Modeling Results in Section 6.0 of this report which support this conclusion. 

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Yellowstone Energy Limited Partnership, Billings Plant Page 2-1
 
2.3 Sulfur Dioxide 

Several techniques can be used to reduce S02 emissions from fossil fuel combustion. 

S02 control options can be divided into pre-combustion strategies (e.g., combusting low 

sulfur fuels, fuel blending, coal cleaning, etc.), combustion techniques (e.g., types of 

boilers, turbines, etc.), and post-combustion controls (e.g., wet scrubbers, dry 

scrubbers, etc.). 

YELP currently controls S02 emissions using limestone injection. Limestone is injected 

with the petroleum coke prior to its combustion in the two circulating fluidized bed 

boilers. In the boilers, the limestone calcines to lime and reacts with S02 to form calcium 

sulfates and calcium sulfites. The calcium compounds are removed as particulate 

matter by the baghouses. Depending on the fuel fired in the boilers and the total heat 

input, YELP must control S02 from 70% to 92% reduction per OP2650-01. During 2008 

through 2009, YELP averaged 95% S02 reduction. The current limestone injection 

system is operating at or near its maximum capacity. The boiler feed rates are 

approximately 740 tons/day of petroleum coke and 415 tons/day of limestone. 

Increasing limestone injection beyond the current levels results in plugging of the 

injection lines, increased bed ash production which can reduce combustion efficiency, 

and increased particulate loading to the baghouses. Increasing limestone beyond its 

current level would require major upgrades to the limestone feeding system and the 

baghouses. Further, we would expect only modest increases in S02 removal efficiency 

with this scenario, compared to add-on S02 control systems which were further 

analyzed for this 114 response. 

2.3.1 Control Technologies Considered 

As YELP's fuel type (petroleum coke and coker gas), type of boiler (Circulating 

Fluidized Bed), and the limestone system are operating at current maximum capacity, 

this cost analysis will focus on post-combustion controls to further reduce sulfur dioxide 

emissions beyond the existing limestone injection control. The post-combustion controls 

that are initially technically feasible in this application are flue gas desulfurization (FGD) 

systems. FGD options for CFB boilers include: Wet Lime Scrubber, Wet Limestone 

Scrubber, Dual-Alkali Scrubber, Spray Dry Absorber, Dry Sorbent Injection, Circulating 

Dry Scrubber, and Hydrated Ash Reinjection. 

Wet Lime Scrubber 

The wet lime scrubbing process uses alkaline slurry made by adding lime (CaO) to 

water. The alkaline slurry is sprayed into the exhaust stream and reacts with the S02 in 

the flue gas. Insoluble calcium sulfite (CaS03) and calcium sulfate (CaS04) salts are 

formed in the chemical reaction that occurs in the scrubber. The salts are removed as a 

solid waste by-product. The waste by-product is mainly CaS03, which is difficult to 

dewater. Solid waste by-products from wet lime scrubbing are typically managed in 

dewatering ponds and landfills. A review of the RBLC database has found limited 

applications of this technology on CFBs firing petroleum coke. 

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Wet Limestone Scrubber 

Wet limestone scrubbers are very similar to wet lime scrubbers. However, the use of 

limestone (CaC03) instead of lime requires different feed preparation equipment and a 

higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically requires a larger 

absorbing unit. The limestone slurry process also requires a ball mill to crush the 

limestone feed. 

Wet lime/limestone scrubbers can achieve S02 control efficiencies of approximately 

95% or greater when used on boilers burning higher sulfur fuels, but may be less on 

lower sulfur fuels. The actual control efficiency of a wet lime/limestone FGD system 

depends on several factors, including the uncontrolled S02 concentration entering the 

scrubber. Similar to wet lime scrubbers, wet limestone scrubbers generate sludge that 

can create material handling and disposal issues. A review of the RBLC database has 

found limited applications of this technology on CFBs firing petroleum coke. 

Dual Alkali Wet Scrubber 

Dual-alkali scrubbers use a sodium-based alkali solution to remove S02 from the 

combustion exhaust gas. The process uses both sodium-based and calcium-based 

compounds. The sodium-based reagents absorb S02 from the exhaust gas, and the 

calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium sulfites 

and sulfates are precipitated and discarded as sludge, and the regenerated sodium 

solution is returned to the absorber loop. 

The dual-alkali process requires lower liquid-to-gas ratios than scrubbing with lime or 

limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units; 

however, additional regeneration and sludge processing equipment is necessary. 

A sodium-based scrubbing solution, typically consisting of a mixture of sodium 

hydroxide, sodium carbonate, and sodium sulfite, is an efficient S02 control reagent. 

However, the process generates sludge that can create material handling and disposal 

issues. The control efficiency is similar to the wet limellimestone scrubbers at 

approximately 95% or greater. Once again, control efficiencies are highly dependent 

upon the uncontrolled S02 concentration entering the scrubber. A review of the RBLC 

database has found limited applications of this technology on CFBs firing petroleum 

coke. 

Spray Dry Absorber 

The typical spray dry absorber (SDA) uses lime slurry and water injected into a tower to 

remove S02 from the combustion gases. The towers must be designed to provide 

adequate contact and residence time between the exhaust gas and the slurry in order to 

produce a relatively dry by-product. The process equipment associated with an SDA 

typically includes an alkaline storage tank, mixing and feed tanks, atomizer, spray 

chamber, particulate control device, and recycle system. The recycle system collects 

solid reaction products and recycles them back to the spray dryer feed system to reduce 

alkaline sorbent use. 

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SDAs are the commonly used dry scrubbing method in large industrial and utility boiler 

applications. SDAs have demonstrated the ability to achieve greater than 95% S02 

reduction. Once again, control efficiencies are highly dependent upon the uncontrolled 

S02 concentration entering the scrubber. 

Dry Sorbent Injection 

Dry sorbent injection involves the injection of powdered or hydrated sorbent (typically 

alkaline) directly into the flue gas exhaust stream. Dry sorbent injection systems are 

simple systems, and generally require a sorbent storage tank, feeding mechanism, 

transfer line and blower, and injection device. The dry sorbent is typically injected 

countercurrent to the gas flow through a venturi orifice. An expansion chamber is often 

located downstream of the injection point to increase residence time and contact 

efficiency. Particulates generated in the reaction are controlled in the system's 

particulate control device. 

S02 control efficiencies for dry sorbent injection systems are approximately 50%, but if 

the sorbent is hydrated lime, then 80% or greater removal can be achieved. These 

systems are commonly called lime spray dryers. Once again, control efficiencies are 

highly dependent upon the uncontrolled S02 concentration entering the scrubber. 

Circulating Dry Scrubber 

A third type of dry scrubbing system, the circulating dry scrubber (CDS), uses a 

circulating fluidized bed of dry hydrated lime reagent to remove S02. Flue gas passes 

through a venturi at the base of a vertical reactor tower and is humidified by a water 

mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime 

where S02 is removed. The dry by-product produced by this system is routed with the 

flue gas to the particulate removal system. 

Hydrated Ash Reinjection 

The hydrated ash reinjection process is a modified dry FGD process developed to 

increase utilization of unreacted lime (CaO) in the CFB ash and any free lime left from 

the furnace burning process. The hydrated ash reinjection process will further reduce 

the S02 concentration in the flue gas. The actual design of a hydrated ash reinjection 

system is vendor-specific. In a hydrated ash reinjection system, a pOition of the 

collected ash and lime is hydrated and re-introduced into a reaction vessel located 

ahead of the fabric filter inlet. In conventional boiler applications, additional lime may be 

added to the ash to increase the mixture's alkalinity. For CFB applications, sufficient 

residual CaO is available in the ash and additional lime is not required. 

2.3.2 Eliminating Technically Infeasible Options 

CDS systems result in high particulate loading to the unit's particulate control device. 

Because of the high particulate loading, the pressure drop across a fabric filter would be 

unacceptable; therefore, electrostatic precipitators (ESP) are generally used for 

particulate control. YELP has high efficiency fabric filters in place. Based on limited 

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Yellowstone Energy Limited Partnership, Billings Plant Page 2-4
 
technical data from non-comparable applications and engineering judgment, it has been 

determined that CDS is not technically feasible with a CFB boiler equipped with a fabric 

filter for particulate control. Therefore, the CDS will not be evaluated further. 

The YELP facility has a very limited area to install additional S02 controls and manage 

waste materials (see Figure 2.3-1). The wet FGD scrubber systems with the higher 

water requirements (Wet Lime Scrubber, Wet Limestone Scrubber, Dual Alkali Wet 

Scrubber) would require an on-site dewatering pond or landfill to dispose of scrubber 

sludge. Due to YELP's limited space requirements, its proximity to the Yellowstone 

River, and limited water availability for these controls, these technologies are 

considered technically infeasible and will not be evaluated further. 

Figure 2.3-1: YELP Property Boundary and Yellowstone River 

2.3.3 Technically Feasible Options 

Technologies requiring low amounts of water and installation space were evaluated. 

The three technically feasible control options for the YELP facility were determined to be 

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Yellowstone Energy Limited Partnership, Billings Plant Page 2-5
 
hydrated ash reinjection (HAR), spray dry absorber (SDA), and dry sorbent injection 

(DSI). 

The ability of the existing fabric filter baghouses at YELP to accommodate the additional 

particulate resulting from HAR, SDA or DSI is in question. Conversations with at least 

one vendor of these systems indicated that baghouse design must be matched with the 

add-on control systems and its resulting particulate loading. As a result, we have 

included a redesigned (new) fabric filter baghouse in the cost for each S02 control 

technology. 

2.3.4 Cost-Effectiveness 

The cost-effectiveness of the technically feasible S02 control technologies was 

estimated based on the methodologies developed by William M. Vatavuk in the book 

"Estimating Costs of Air Pollution Control" and the methodologies provided in EPA's 

Office of Air Quality Planning and Standards (OAQPS) Pollution Cost Control Manual, 

6th Edition. 

The average of YELP S02 emissions from the 2008 and 2009 emission inventories was 

used to estimate the cost-effectiveness of the technically feasible control options. The 

results of the analysis are presented in the Results section of this report. Detailed 

estimates and supporting information are provided in Appendix A - Costs of 

Compliance Analysis. 

2.4 Nitrogen Oxides 

Applicable NOx control technologies can be divided into two main categories: 

combustion controls, which limit NOx production, and post-combustion controls, which 

destroy NOx after formation. 

YELP currently controls NOx emissions using good combustion practices in the CFB 

boilers? Emissions are controlled through the boiler design and its lower operating 

temperatures, and a recirculation of fuel and ash particles through the combustion 

boiler. The lower operating temperature in a CFB boiler already reduces the formation 

of thermal NOx emissions in the range of 50% or more compared to other boiler 

designs. YELP must meet emission limits of 0.400 Ibs/MMBtu and 319.0 Ib/hr per 

OP2650-01. YELP demonstrates compliance with these limits using continuous 

emission monitors and EPA Method 717E. Table 2.4-1 summarizes the NOx emissions 

from annual emission tests from 2008 through 2009. 

3 CFB combustion technology design has inherently lower combustion temperatures than pulverized coal 

(PC) technology. The lower combustion temperature of a CFB boiler (1550 - 1650°F) typically leads to a 

lower formation of thermal NOx than a PC boiler, which has a relatively higher combustion temperature 

(2400 - 2700°F) and more thermal NOx. 

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Table 2.4-1: 2008-2009 NOx Emission Testing Results
 

Year NOx (Ibs/MMbtu) NOx (Ibs/hr) 

2008 0.201 199.8 

2009 0.201 112.8 

2.4.1 Control Technologies Considered 

As YELP is currently using boiler design to control NOx emiSSions, only postcombustion controls were considered for this analysis. The post-combustion controls 

that are initially technically feasible in this application are Low Excess Air (LEA), Flue 

Gas Recirculation (FGR), Overfire Air (OFA), Low NOx Burners (LNB), Selective 

Catalytic Reduction (SCR), and Selective Non-Catalytic Reduction. 

Low Excess Air (LEA) 

LEA operation involves lowering the amount of combustion air to the minimum level 

compatible with efficient and complete combustion. Limiting the amount of air fed to the 

furnace reduces the availability of oxygen for the formation of fuel NOx and lowers the 

peak flame temperature, which inhibits thermal NOx formation. 

Emissions reductions achieved by LEA are limited by the need to have sufficient oxygen 

present for flame stability and to ensure complete combustion. As excess air levels 

decrease, emissions of CO, hydrocarbons and unburned carbon increase, resulting in 

lower boiler efficiency. Other impediments to LEA operation are the possibility of 

increased corrosion and slagging in the upper boiler because of the reducing 

atmosphere created at low oxygen levels. 

This technology is typically utilized on Pulverized Coal (PC) units. This option cannot 

be utilized on CFB due to air needed to fluidize the bed. 

Flue Gas Recirculation (FGR) 

FGR is a flame-quenching technique that involves recirculating a portion of the flue gas 

from the economizers or the air heater outlet and returning it to the furnace through the 

burner or windbox. The primary effect of FGR is to reduce the peak flame temperature 

through absorption of the combustion heat by relatively cooler flue gas. FGR also 

serves to reduce the O2 concentration in the combustion zone. 

This technology is typically utilized on PC units. This option can not be utilized on CFB 

due to air needed to fluidize the bed. 

Overfire Air (OFA) 

OFA allows staged combustion by supplying less than the stoichiometric amount of air 

theoretically required for complete combustion through the burners. The remaining 

necessary combustion air is injected into the furnace through overfire air ports. Having 

an oxygen-deficient primary combustion zone in the furnace lowers the formation of fuel 

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NOx. In this atmosphere, most of the fuel nitrogen compounds are driven into the gas 

phase. Having combustion occur over a larger portion of the furnace lowers peak flame 

temperatures. Use of a cooler, less intense flame limits thermal NOx formation. 

Poorly controlled OFA may result in increased CO and hydrocarbon emissions, as well 

as unburned carbon in the fly ash. These products of incomplete combustion result 

from a decrease in boiler efficiency. OFA may also lead to reducing conditions in the 

lower furnace that in turn may lead to corrosion of the boiler. 

This technology is typically utilized on PC units. This option cannot be utilized on CFB 

due to air needed to fluidize the bed. 

Low NOx Burners (LNB) 

LNB integrate staged combustion into the burner creating a fuel-rich primary 

combustion zone. Fuel NOx formation is decreased by the reducing conditions in the 

primary combustion zone. Thermal NOx is limited due to the lower flame temperature 

caused by the lower oxygen concentration. The secondary combustion zone is a fuellean zone where combustion is completed. LNB may result in increased CO and 

hydrocarbon emissions, decreased boiler efficiency, and increased fuel costs. 

This technology is typically utilized on PC units. This option cannot be utilized on CFB 

because the combustion occurs within the fluidized bed. 

Selective Catalytic Reduction (SCR) 

SCR is a post-combustion gas treatment technique that uses a catalyst to reduce NO 

and N02 to molecular nitrogen, water, and oxygen. Ammonia (NH3) is commonly used 

as the reducing agent. 

Ammonia is vaporized and injected into the flue gas upstream of the catalyst bed, and 

combines with NOx at the catalyst surface to form an ammonium salt intermediate. The 

ammonium salt intermediate then decomposes to produce elemental nitrogen and 

water. The catalyst lowers the temperature required for the chemical reaction between 

NOx and ammonia. 

Technical factors that impact the effectiveness of this technology include the catalyst 

reactor design, operating temperature, type of fuel fired, sulfur content of the fuel, 

design of the ammonia injection system, and the potential for catalyst poisoning. 

SCR has been demonstrated to achieve high levels of NOx reduction in the range of 

80% to 90% control for a wide range of industrial combustion sources, including PC and 

stoker coal-fired boilers and natural gas-fired boilers and turbines. Typically, installation 

of the SCR is upstream of the particulate control device (e.g., baghouse). However, 

calcium oxide (from a dry scrubber) in the exhaust stream can cause the SCR catalyst 

to plug and foul, which would lead to an ineffective catalyst. 

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SCRs are classified as a low or high dust SCR. A low dust SCR is usually applied to 

natural gas combustion units or after a particulate control device. High dust SCR units 

can be installed on solid fuel combustion units before the particulate control device, but 

they have their limitations. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR involves the non-catalytic decomposition of NOx to nitrogen and water. An NOx 

reducing agent, typically ammonia or urea, is injected into the upper reaches of the 

furnace. Because a catalyst is not used to drive the reaction, temperatures of 1600 to 

21000 F are required. 

Typical NOx control efficiencies range from 40% - 60%. NOx removal efficiency varies 

for this technology, depending on inlet NOx concentrations, fluctuating flue gas 

temperatures, residence time, amount and type of nitrogenous reducing agent, mixing 

effectiveness, acceptable levels of ammonia slip, and presence of interfering chemical 

substances in the gas stream. 

2.4.2 Eliminating Technically Infeasible Options 

Because OFA, LEA, and FGR are used to reduce flame temperature and reduce the 

thermal NOx, these control options are technically ineffective on a CFB boiler that has 

inherently low combustion temperatures and relatively lower thermal NOx. Further, a 

CFB boiler does not use burners like a PC boiler, limiting the available combustion 

control options. The remaining post combustion NOx control options are considered 

technically feasible. 

2.4.3 Technically Feasible Options 

SCR and SNCR are technically feasible options for NOx control on the YELP boilers. 

2.4.4 Cost-Effectiveness 

BGI consulted with Bison Engineering, Inc., the Harris Group and Metso to estimate the 

cost-effectiveness of installing SCR or SNCR at the YELP facility. Metso and the Harris 

Group have extensive experience building CFBs with NOx controls. Their expertise was 

utilized to develop as close to a "real world" estimate of each control technology as 

possible. 

The cost-effectiveness of the technically feasible NOx control technologies was 

estimated using the total capital and operating costs estimates developed by Metso, the 

Harris Group, and by the Office of Air Quality Planning and Standards (OAQPS) 

Pollution Cost Control Manual, 6th Edition. 

The average of uncontrolled NOx emissions from the 2008 and 2009 emission 

inventories was used to estimate the cost-effectiveness of the technically feasible 

control options. The results of the analysis are presented in the Results section of this 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 2-9
 
report. Detailed estimates and supporting information are provided in Appendix A ­

Costs of Compliance Analysis. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 2-10
 
3.0 TIME NECESSARY FOR COMPLIANCE
 

3.1 Time Necessary for Compliance 

Based on the modeling results presented in Section 6 of this report, BGI considers 

YELP already in compliance with the RHR. This section of the report will discuss the 

estimated amount of time to install the S02 and NOx control technologies identified 

previously in this report. 

3.1.1 Installation of S02 Controls 

The addition of hydrated ash reinjection (HAR), spray dry absorber (SDA), and dry 

sorbent injection (DSI) would each take approximately the same amount of time. 

However, as stated previously, the addition of SOx controls would likely require 

complete replacement or major modifications to the existing baghouses. The installation 

of the new SOx controls and baghouses should be staggered to allow one boiler to 

remain in operation while the retrofits are applied to the other boiler. Bison estimates 

that the time necessary to complete the modifications to one boiler would be 

approximately four to six months. A boiler outage of approximately two to three months 

per boiler would be necessary to perform the installation of both control systems. The 

total time necessary to install the controls would be approximately one year. 

3.1.2 Installation of NOx Controls 

Due to the complexity of the existing infrastructure and severely limited space, the 

installation of SCR is estimated to take approximately 26 months. The installation of 

SNCR is less complex, and would take approximately 24-30 weeks. Please see the 

attached report included in Appendix A for more information. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 3-1
 
4.0 ENERGY AND NON-AIR QUALITY IMPACTS OF 

COMPLIANCE 

4.1 Energy Impacts 

4.1.1 Energy Impacts: 802 Controls 

FGD systems require electricity to operate. The dry FGD uses electricity primarily for 

the 10 fan, lime/limestone handling equipment and baghouse blowers. With a hydrated 

ash reinjection system, there is no recirculation pump, wet waste dewatering and 

reduced power consumption for the reagent (lime/limestone) handling system. 

Wet FGD systems have been estimated to consume 1% - 2.5% of the total electric 

generation of the plant. Wet FGD system power consumption is approximately 40% 

greater than that of the dry FGD system (0.6% to 1.9% of total electricity generation of 

the plant). 

Dry Sorbent Injection systems have been estimated to consume 0.1 % to 0.5% of the 

total plant generation. 

4.1.2 Energy Impacts: NOx Controls 

The energy impacts from an SNCR are minimal and an SNCR does not cause a loss of 

power output from the facility. On the other hand, SCR would cause a significant 

backpressure in the CFB boiler leading to lost boiler efficiency and, thus, a loss of 

power production. Along with the power loss, YELP would be subject to the additional 

cost of reheating the exhaust gas, which is an inefficient use of energy and would be 

expensive at today's price of natural gas. 

4.2 Non-Air Quality Impacts 

4.2.1 Non-Air Quality Impacts: 802 controls 

The addition of the S02 controls would result in increased ash production at the YELP 

facility. Boiler ash is currently either sent to a landfill or sold for beneficial use, such as 

oil well reclamation. Changes in ash properties due to increased calcium sulfates and 

calcium sulfites could result in the ash being no longer suitable to be sold for beneficial 

uses. The loss of this market would cost BGI approximately $2,300,000 year at the 

current ash value and production rates (approximately 170,000 tons of ash/year). The 

loss of this market would also result in BGI having to dispose of the ash at its current 

landfill, which is approximately 80 miles from the YELP plant. YELP currently pays a 

fixed fee of approximately $500,000 a year to manage this landfill. YELP incurs a fee of 

$3.56/ton on ash taken to the pit that is in excess of 140,000 tons/year. At its current 

production and ash disposal costs, this would result in an increased cost to BGI of 

approximately $96,000/year. The total cost from the loss of the beneficial use market 

and the increase in ash disposal costs would be a total of $2,400,000/year. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 4-2
 
4.2.2 Non-Air Quality Impacts: SCR or SNCR 

The addition of chemical reagents in SNCR and SCR controls would add equipment for 

its storage and use. The storage of on-site ammonia would pose a risk from potential 

releases to the environment. An additional concern is the loss of ammonia, or "slip" into 

the emissions stream from the facility; this "slip" contributes another pollutant to the 

environment, which has been implicated as a precursor to PM2.5 formation in the 

atmosphere. The additional costs of chemicals and catalysts have been included in the 

cost analysis. 

SCRs can contribute to fouling in backpass equipment due to ammonia bisulfate 

formation. Equipment fouling could reduce unit efficiency, increase flue gas velocities, 

and cause corrosion and erosion. 

On some installations, catalyst life is very short and SCRs have fouled in high dust 

environments. This had led to boiler downtime in some installations. The presence of 

vanadium in the fuel has led to reduced catalyst life on SCR units. A detailed 

assessment of catalyst life cost would require further analysis by a catalyst vendor. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 4-3
 
5.0 REMAINING USEFUL LIFE OF THE POTENTIALLY 

AFFECTED SOURCES 

YELP began operation in 1995. Estimates vary on the typical useful life of coal-fired 

boilers, but CFB manufacturers have stated that 40 years is a reasonable target. Based 

on a 40 year lifespan of the boilers, the remaining useful life of the boilers is 

approximately 24 years. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 5-1
 
6.0 VISIBILITY MODELING RESULTS
 

6.1 Visibility Modeling Results 

To assess impacts to visibility, YELP used recent emission data from 2008 through 

2009. The highest 24-hr emission rates not occurring during a startup, shutdown, or 

malfunction were used in the baseline emission modeling. Table 6.1-1 summarizes the 

emission rates used in the baseline visibility modeling analysis. 

Table 6.1-1: Modeled Emission Rates 

SOz NOx PM10 PMZ.5 

(Ibs/hr) (Ibs/hr) (Ibs/hr) (Ibs/hr) 

591 242 2.3 2.2 

Visibility impacts were determined for the following Federal Class I Areas: Yellowstone 

National Park, UL Bend Wilderness Area, North Absaroka Wilderness Area, and the 

Gates of the Mountains Wilderness Area. Table 6.1-2 summarizes the 98th percentile 

visibility impacts from YELP's highest 24-hr emissions on these Class I Areas. 

Table 6.1-2: Visibility Impacts Without Additional Control 

Class I Area Visibility Impact (~DV)

Yellowstone National Park 0.193 

UL Bend 0.376 

North Absaroka 0.294 

Gates of the Mountains 0.176 

The highest modeled impact was determined to be 0.376 deciviews at the UL Bend 

Wilderness. This is below the 0.5 deciview level that EPA has proposed as a level at 

which a source may contribute to a visibility impact and well below the 1.0 deciview 

level EPA employs as a level to indicate that a source causes a visibility impact.4 

The data in the table shows that BGI, by itself and as currently configured, has no 

perceptible change in visibility at any mandatory Class I area. It is reasonable to 

conclude that the addition of any emission controls will not change that conclusion. 

Since the purpose of the program is to improve regional haze and given BGI does not 

impact regional haze, no additional controls are warranted. The addition of controls 

4 See 40 CFR 51, Appendix Y and elsewhere. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 6-1
 
would not serve the program's purpose of creating "reasonable progress" toward the 

national goal, since no measurable progress would be created. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 6-2
 
7.0 SOX CONTROL ECONOMIC RESULTS AND IMPACTS TO 

VISIBILITY 

Table 7.0-1 summarizes the results of the potential addition of SOx controls and their 

emission reductions. 

Table 7.0-1: Cost-Effectiveness of SOx Controls 

Technology 

Capital 

Investment 

Annual 

Operating 

CostS 

Control 

Efficiency 

(%) 

Tons 

SOx 

Emitted 

after 

Control 

Tons 

SOx 

Reduced 

CostEffectiveness 

(S/ton) 

Hydrated Ash 

Re-Injection 

(HAR) 

$30,895,353 $7,471,601 50% 913 913 $8,183 

Spray Dry 

Absorber 

(SDA) 

$39,054,955 $9,605,960 80% 365 1461 $6,575 

Dry Sorbent 

Injection (DSI) 

$20,225,105 $5,548,697 50% 913 913 $6,077 

The visibility impacts of installing the most cost-effective of these controls, OSI, were 

determined by modeling the resultant 50% control of SOx emissions on the highest 24­

hr emission rate from 2008-2009. The highest 98th percentile impact to the most 

impacted Class I Area following control was compared to the highest 98th percentile 

impact from the baseline modeling. Table 7.0-2 summarizes what the effects to visibility 

would be if OSI was installed and the cost-effectiveness of this option in $/deciview. 

5 Annual Operating Cost includes maintenance, materials, electrical costs, loan interest, and other costs. 

Please see Appendix A for more details. The unlikelihood of securing loans for new pollution control 

equipment is discussed in the summary section of this report. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 7-3
 
Table 7.0-2: Cost-Effectiveness of DSI in $/Decaview 

Control 

Option 

Emission 

Rate (Ib/hr) 

Max 98m 

Percentile 

Prediction 

(~DV)

Class I 

Area 

Impacted 

Incremental 

Deciview 

Change 

Annual 

Operating 

Cost 

CostEffectiveness 

($/deciview) 

Base Case 591.2 0.376 UL Bend --­ --­ --­

With DSI 295.6 0.267 UL Bend 0.109 5,548,697 $50,905,477 

7.1 NOx Control Economic Results and Impacts to Visibility 

Table 7.1-1 summarizes the results of the potential addition of SCR and SNCR and their 

emission reductions. 

Table 7.1-1: Cost-Effectiveness of NOx Controls 

Technology 

Capital 

Investment 

Annual 

Operating 

Cost6 

Control 

Efficiency 

(%) 

Tons 

NOx 

Emitted 

after 

Control 

Tons 

NOx 

Reduced 

CostEffectiveness 

($/ton) 

SCR $28,000,000 $5,796,720 80% 79 317 $18,309 

SNCR $880,000 $589,938 50% 198 198 $2,981 

The visibility impacts of installing the most cost-effective of these controls, SNCR, were 

determined by modeling the resultant 50% control of NOx emissions on the highest 24­

hr emission rate from 2008-2009. The highest 98th percentile impact to the most 

impacted Class I Area following control was compared to the highest 98th percentile 

impact from the baseline modeling. Table 7.1-2 summarizes what the effects to visibility 

would be if DSI was installed and the cost-effectiveness of this option in $/deciview. 

6 Annual Operating Cost includes maintenance, materials, electrical costs, loan interest, and other costs. 

Please see Appendix A for more details. The unlikelihood of securing loans for new pollution control 

equipment is discussed in the summary section of this report. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 7-4
 
Table 7.1-2: Cost-Effectiveness of SNCR in $IDecaview 

Control 

Option 

Emission 

Rate 

(Ib/hr) 

Max 98m 

Percentile 

Prediction 

(~DV)

Class I 

Area 

Impacted 

Incremental 

Deciview 

Change 

Annual 

Operating 

Cost 

CostEffectiveness 

($/deciview) 

Base 

Case 

241.8 0.376 UL Bend --­ --­ --­

With 

SNCR 

120.9 0.301 UL Bend 0.075 $589,938 $7,865,840 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 7-5
 
8.0 SUMMARY
 

As requested by EPA, BGI has analyzed its two CFB boilers at the YELP facility for the 

purposes of meeting the Reasonable Progress Goals of the Regional Haze Rule. BGI 

retained Metso, the Harris Group, and Bison Engineering, Inc. to assist BGI in 

evaluating possible control alternatives at YELP. The analysis concluded that the 

current particulate matter controls (baghouses) achieve a superior level of particulate 

control and alternative particulate control options were not considered. The analysis 

identified two technically feasible controls for NOx (SCR and SNCR) and three 

technically feasible controls for S02 (HAR, SOA, and OSI). As the intent of the Regional 

Haze Rule is to protect visibility in Class I Areas, BGI also conducted visibility modeling 

to assess the predicted impacts from YELP's current facility emissions and from the 

potential emission reductions from the most economical add on controls (SNCR and 

OSI). The modeling analysis has shown that current emission rates result in impacts 

well below the 1.0 deciview level EPA employs as a level to indicate that a source 

causes a visibility impact and are also below the 0.5 deciview level that EPA has 

proposed as the level at which a source may contribute to a visibility impact. The add-on 

controls resulted in modeled predictions of a 0.075 deciview improvement from SNCR 

and a 0.109 deciview improvement from OSI. 

As part of the analysis, EPA requested that BGI analyze the costs of compliance.
 

The EPA's document "Guidance for Setting Reasonable Progress Goals under the
 

Regional Haze Program"? states:
 

"... the cost of compliance factor can be interpreted to encompass the cost of 

compliance for individual sources or source categories, and more broadly the 

implication of compliance to the health and vitality of industries within a state." 

The two technically feasible NOx control options identified in the Metso study would 

have major impacts on the facility and its ability to remain in operation. To put this 

discussion in context, YELP has a long-term fixed rate contract through 2028 with 

NorthWestern Energy to sell its electrical output. That contract determines the rates to 

be paid, and does not allow any pass-through of any costs, whether capital, operating, 

financing, or otherwise. Therefore, to the extent it can do so, the entire burden 

(including lost revenue, as well as all other impacts) of implementation of any required 

control method will be borne by the YELP facility. The YELP facility has struggled to 

maintain operation and has done so through borrowing and depreciation. The YELP 

facility has never paid any return on equity. The YELP facility provides many benefits to 

the state and community, including a key environmental benefit by scrubbing 

ExxonMobil refinery coker flue gas (previously emitted) through its boilers, reducing 

materially the S02 content of the Billings, Montana, airshed. 

7 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, U.S. 

Environmental Protection Agency Office of Air Quality Planning and Standards Air Quality: 

http://www.epa.gov/ttncaaa1/t1/memoranda/reasonable_progress_guid071307.pdf. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 8-1
 
As can be seen in this response and the attachments hereto, the two NOx control 

options (SCR and SNCR) bring with them capital costs and installation of $28,000,000 

and $880,000, and annual operating costs of $5,800,000 and $590,000, respectively. 

These operating costs would double or quadruple YELP's current budgeted costs for 

similar requirements. They also have the potential to cost the project on the order of 

$2,500,000 annually in lost revenue and incurred disposal costs for ash presently sold, 

and in the case of SCR include an extraordinary downtime of two to three months for 

implementation, resulting in a loss of revenue which is neither insured nor passed 

through to NorthWestern. 

The addition of SOx controls would have a similar impact to YELP's ability to remain in 

operation. Bison Engineering identified three technically feasible SOx controls, which 

are hydrated ash re-injection (capital investment $31,000,000 - annual operating cost 

$7,500,000), spray dry absorber (capital investment $39,000,000 - annual operating 

cost $9,600,000), and dry sorbent injection (capital investment $20,000,000 - annual 

operating cost $5,500,000), also bringing with them lost revenue and increased costs 

for ash disposal, and downtime of four to six months to modify YELP's boilers. 

YELP has no capacity for further borrowing to implement the costs of any of the 

alternatives (SOx or NOx), either for capital improvements or operations. Just the 

downtime alone for implementation of the SCR alternative or any of the SOx 

alternatives would cause YELP to be unable to meet ongoing operating cost obligations. 

YELP is financed, in part, by tax exempt bonds issued by the State of Montana. Should 

YELP be required to implement either alternative without a cost pass-through 

mechanism to the purchaser of its output, the outcome would be bankruptcy for YELP. 

The consequences to the community and state of such an event would be annual loss 

of about $18,000,000 in payroll, vendor payments, property taxes, etc., and default on 

about $220,000,000 in debt-related obligations, as well as the loss of the environmental 

benefits of scrubbing the ExxonMobil coker flue gas emissions. 

Billings Generation Inc. Regional Haze Rule Section 114 Response
 

Yellowstone Energy Limited Partnership, Billings Plant Page 8-2
 
APPENDIX A -COSTS OF COMPLIANCE ANALYSIS
 

Billings Generation Inc. Regional Haze Rule Section 114 Response 

Yellowstone Energy Limited Partnership, Billings Plant 
ECONOMIC EVALUATION OF NOx CONTROL 

Yellowstone Energy Limited Partnership 

Billings, Montana 

METSO REFERENCE No. 710068 

Feb 2011 

1)metso II' Expect results 
NOx Control Economic 2 (12) 

)metso Evaluation (YELP) 

Date of Report 

Feb 2011 Project # 710068 

Executive Summary 

Metso was contracted to provide an economic evaluation of NOx control for the two 

Circulating Fluidized Bed Boilers (CFB) at the Yellowstone Energy Limited Partnership 

(YELP) facility in Billings, Montana. This estimate was compiled using drawings ofthe 

plant that are in Metso's archives. The drawings do not show balance of plant piping, cable 

trays, small bore piping, and modifications that have been made to the facility following 

initial installation. There could be interferences and significant unknowns that would alter 

Metso's conclusions contained within this report. This is an order ofmagnitude estimate. 

Metso evaluated the use of Selective Catalytic Reduction (SCR) and Selective Noncatalytic 

Reduction (SNCR) technology to reduce NOx emissions at the YELP facility. A SNCR is 

capable of reducing NOx emissions by at least 50% while the SCR is capable of practical 

reductions of up to 80%, depending on space availability. 

The total cost for installing SCRs on both units ranges from $22,000,000 to $28,000,000 

whereas the total installed cost for SNCRs would be less than $1,000,000 for both units 

combined. Since the bulk of the SNCR system will be shared by two units, SCR 

technology will be between 22 and 32 times the cost for SNCR technology at the facility. 

The Operation and Maintenance (O&M) costs for the SCR are estimated to be 2.8 times the 

costs for O&M of the SNCR system. The increased cost for the potential 30% additional 

reduction in NOx emissions by the installation of an SCR system at this facility is 

significant. 

CFBs are typically inherently lower NOx generators than other boiler types. Petroleum 

coke fired CFBs emit fewer NOx emissions than those firing coal or other fuels. SNCRs 

are on many of the boilers that Metso has supplied within the United States. However, 

none of the Metso-supplied CFB boilers within the United States incorporate SCR 

technology. 

There are risks associated with using an SCR on a boiler utilizing petroleum coke as a fuel 

source. There is vanadium in petroleum coke. It is proven that vanadium poisons SCR 

catalysts. The catalyst life for this unit is likely to be short (likely months instead of years). 

This will likely reduce the availability of this unit and subject the facility to significant 

operating and maintenance costs. The catalyst life is difficult to quantify without a further 

extensive study by a catalyst supplier. It is unlikely or would be costly to obtain a lengthy 

catalyst life guarantee from a catalyst supplier for this application. 

Fouling ofpetcoke fired units occurs on superheater surfaces. The superheater is upstream 

of this SCR. The fouling will likely cause plugging and blinding of the SCR catalyst when 

it breaks loose from the superheater surfaces. This will increase maintenance costs at this 

facility and subject the unit to increased downtime. 

Metso would be hesitant to install an SCR on a petroleum coke fired boiler. 

Metso Power© 2011 
NOx Control Economic 3 (12) 

metso Evaluation (YELP) 

Date of Report 

Feb 201L Project # 710068 

TABLE OF CONTENTS 

OVERVIEW - 4 

AQUEOUS AMMONIA SySTEM 4 

SYSTEM DESCRIPTION: 4 

LOCATION AND INSTALLATION CONSIDERATIONS Of AMMONIA SYSTEM 4 

SELECTIVE NONCATALYTIC REDUCTION SYSTEM (SNCR) •••••••••••••••••••••••••••••••••••••••••••.•••••••••••••••••••••••••••••••••• 5 

SYSTEM DESCRIPTION: 5 

LOCATION AND INSTALLATION CONSIDERAnONS 5 

TIME fOR COMPLIANCE 5 

CAPITAL COSTS AND DOWNTIME 5 

OPERATING AND MAINTENANCE CONSlDERATIONS 6 

OTHER NON-ENVIRONMENTAL IMPACTS 6 

SELECTIVE CATALYTIC REDUCTION SYSTEM (SCR) 6 

SYSTEM DESCRIPTION: 6 

LOCATION AND INSTALLATION CONSIDERATIONS 7 

Upstream o/the economizer- 7 

Between economizer and baghouse - 7 

Possible Solution 8 

TIME fOR COMPLIANCE 8 

CAPITAL COSTS AND DOWNTIME 8 

OPERATING AND MAINTENANCE CONSiDERATIONS 9 

OTHER NON-ENVIRONMENTAL IMPACTS 10 

ATIACHMENT 1-SUMMARY ECONOMIC EVALUATION TABLE 11 

ATIACHMENT 2 - GENERAL ARRANGEMENT DRAWING ••••••••••••••••••••••••••••••••••••••••.••••••••••••••••••••••••••••••••••. 12 

Metso Power© 2011 
.~., ) metso NOx Control Economic 

Evaluation (YELP) 

4 (12) 

Date of Report 

Feb 201 1 Project # 710068 

Overview ­

There are two Circulating Fluidized Bed Boilers at the YELP facility_ Each boiler is 

rated for 300,000 Iblhr at 1300 psig and 955F main steam. The fuel is petroleum 

coke and coker gas. 

The purpose of this assessment is to provide estimated capital and O&M costs for 

NOx control solutions. 

•	 The average uncontrolled NOx for Yellowstone (YELP) is .15 Ib/MMBTU. 

The following solutions were evaluated 

•	 An SNCR system capable of 50% NOx reduction for controlled NOx rates 

of .075 Ib/MMBTU 

•	 An SCR system capable of 80+% reduction for controlled NOx rates of .03 

IbIMMBTU. 

Both solutions require a method for the storage and supply of ammonia to the 

process. An aqueous ammonia system was selected for the evaluation. 

Aqueous ammonia system 

SYSTEM DESCRIPTION: 

The ammonia system is similar for both the SNCR and the SCR. 

There are two boilers at this facility however a common ammonia system can be 

used to supply reagent to both units. It is less expensive and more practical to have 

one larger system than two small systems. 

The system consists ofa 14,000 gal ammonia tank with metering pumps, filters, 

tank level sensor and alarm, caged ladder for access to top of tank, and other various 

attachments. The tank can contain approximately 8.5 days of storage of 19.5% 

aqueous ammonia using the SNCR system while providing 50% reduction of NOx 

when both boilers are at full load. The larger tank will allow more flexibility in the 

filling cycle. The tank is sized to contain slightly more than 2 standard tank truck 

loads of aqueous ammonia. 

LOCATION AND INSTALLATION CONSIDERATIONS OF AMMONIA SYSTEM 

The tank and forwarding skid would be located on the ground, outside of the boiler 

house. A containment dike is installed around the tank to capture the fluid if a leak 

or rupture occurs. 

Metso Power© 2011 
NOx Control Economic 5 (12) 

) metso 

.' Evaluation (YELP) 

Date of Report 

Feb 20ll Project # 710068 

Selective noncatalytic reduction system (SNCR) 

SYSTEM DESCRIPTION: 

An SNCR system for a CFB consists of the aqueous ammonia system listed above, 

small bore piping from the metering skid to the boilers, and injection nozzles at the 

cyclone inlets for the boilers. 

There are two boilers at this facility. A single line will be routed from the 

forwarding system to the elevation of the cyclone inlet ducts of the two boilers. The 

line will branch into two lines at this elevation. Each branch line will have a control 

valve that will meter the required flow to the specific boiler. The line downstream 

of each control valve will branch again to feed two distribution or metering panels. 

A distribution panel will be located at each oftwo cyclone inlet ducts on each 

boiler. The metering skids will be used to bias ammonia flow to each ofthe four 

nozzles on each cyclone inlet duct. 

Steam or compressed air is used to atomize and distribute the ammonia into the 

cyclone inlet ducts. If the system is to be used intermittently, purge air would be 

installed to keep the nozzles clear of material when the system is not in use. 

LOCATION AND INSTALLATION CONSIDERATIONS 

The distribution panels and injection nozzles are located near the cyclone inlet 

ducts. The injection nozzles penetrate and mount to the cyclone inlet ducts. The 

nozzles are used to inject ammonia into the duct, while distributing the ammonia 

across as much as the duct as practical. This location provides an area of high 

velocity and narrow duct width to allow for good penetration and mixing of the 

ammonia with the flue gas. The ammonia is sprayed upstream of the cyclones on 

the CFB. The cyclones promote further mixing of the ammonia and the flue gas 

because of flue gas cyclonic action, direction change, and mixing. Higher reduction 

rates are achievable on CFBs than for BFBs, and other boiler types because of this 

optimum spray location and cyclonic mixing. While it may be possible to capture 

more NOx on a CFB, the standard guaranteed reduction rates are in the 50% range 

in order to limit slip to lO ppm. 

TIME FOR COMPLIANCE 

An SNCR system could be installed within 16-24 weeks. A maximum 2 week 

outage would be required to make tie-ins. 

CAPITAL COSTS AND DOWNTIME 

There are two boilers at YELP. A common ammonia system tank and delivery 

system will be utilized for both boilers. The ammonia tank and forwarding system 

is the bulk of the cost for supply and installation. The rest of the system consists of 

supply and installation of small bore piping, distribution skids, and injection 

Metso Power© 2011 
NOx Control Economic 6 (12) 

metso Evaluation (YELP) 

Date of Report 

Feb 2011 Project # 710068 

nozzles. The majority of the piping is installed for the SNCR for the first unit. The 

pipe for the second unit branches off at the upper elevation for distribution of 

ammonia to the second unit. There is a minimal incremental cost for the equipment 

and installation of SNCR technology for the second unit because of this. The 

incremental cost is limited to installation ofsome small bore piping, a control valve, 

two additional distribution panels, tubing, and nozzles into the cyclones. The 

installed estimate for the SNCR system is $880,000. This is the installed cost for 

SNCR technology for NOx control for both units. Control technologies are often 

evaluated based on $/kw basis. The gross electrical generation for each boiler is 

32.5 MW. The estimated cost for SNCR capital costs (supply and installation) is 

$14/kw. 

The tie- in can be made during the normal annual outage. The majority of the 

system can be installed with boilers on-line. The nozzles would be installed during 

the annual outage. 

OPERATING AND MAINTENANCE CONSIDERATIONS 

The O&M costs are estimated to be approximately $220,000 per unit. Most of this 

is the cost of the ammonia. Ammonia consumption is $203,000 per unit based on 

$196/delivered ton. Maintenance of the ammonia system and nozzles should 

average $10,000-15,000 for each unit. 

OTHER NON-ENVIRONMENTAL IMPACTS 

SNCRs are the primary method ofNOx control on the majority ofCFBs and no 

problems have been noted. Metso has not observed nor is aware of any increased 

fouling, decreased pressure part life, or other issues associated with the use of 

SNCRs. 

Selective catalytic reduction system (SCR) 

SYSTEM DESCRIPTION: 

An SCR is an array of catalyst installed in an existing duct or in a dedicated 

enclosure. Ammonia is injected upstream of the catalyst. The catalyst enhances the 

reaction rate between the ammonia and the NOx, thus high capture efficiencies can 

be attained. 

The temperature range for proper operation of an SCR is between 480F to 800F. 

The optimum operation of an SCR depends on straight, uniform, and optimum flue 

gas velocities across the catalyst grid. When optimum conditions exist, SCRs are 

often capable ofup to 90% reduction ofNOx in low dust flue gas streams. For 

practical retrofits, especially on smaller units, optimum conditions do not exist 

without significant capital modifications. 

Metso Power© 2011 
NOx Control Economic 7 (12) 

metso Evaluation (YELP) 

Date of Report 

Feb 2011 Project # 710068 

Installation of an SCR in a low dust flue gas streams is often not practical, 

especially on an existing boiler. The reason is that the low dust portion of a flue gas 

stream is located after a baghouse or a precipitator. The temperature of the flue gas 

stream is too low in these areas for proper operation of an SCR. Many of the CFBs 

in the United States have baghouses for particulate controL The nonnal maximum 

allowable temperature for a baghouse is 400F. This is still too low for the operation 

of an SCR. Therefore, on some installations, a regenerative SCR is installed. 

Regenerative SCRs are expensive to install and expensive to operate because an 

RSCR requires the use of burners to heat up the flue gas stream in order for the NOx 

capture to occur. This is often an efficiency decrease for the boiler, significant 

increase in operating cost, and often not a practical solution. For this reason, Metso 

did not evaluate the use of an RSCR. 

Metso evaluated the use of a high dust SCR for this installation based on the above 

information. 

A vaporizer in the ammonia delivery system is required for an SCR to inject the 

ammonia in gaseous form. 

LOCATION AND INSTALLATION CONSIDERATIONS 

The temperature range for proper operation of an SCR is between 480F to 800F. As 

can be seen from the general arrangements drawings there are two locations that 

could be utilized for the current configuration. Neither ofthese two locations have 

flue gas temperatures in the range listed above. One possible solution is presented. 

However, the solution will be costly to implement and is not an ideal location for an 

SCR. Metso believes that a maximum NOx reduction rate of 80% would be the 

recommended target for an SCR at this facility. CFO modeling and physical 

modeling, as well as a detailed assessment ofcatalyst life would need to be 

performed before any guarantees could be presented. An assumption of 80% NOx 

reduction was used as a basis for capital and O&M costs. 

The two available locations considered were: 

1. Upstream of economizer 

2. Between the economizer and the baghouse. 

Upstream of the economizer ­

The temperature upstream of the economizer is between 800-880F. This is too 

high for the proper operation ofan SCR. 

Between economizer and baghouse ­

The temperature downstream of the economizer is 350F, which is too low for 

effective operation of an SCR. 

Metso Power© 2011 
NOx Control Economic 8 (12) 

)metso Evaluation (YELP) 

Date ofReport 

Feb 2011 Project # 710068 

Possible Solution 

One possible option is to split the economizer since it is constructed in two 

assemblies with a jumper pipe between the two. The predicted temperature in 

this area is in the range of 550F. The lower bank ofthe economizer and the ash 

hopper could be lowered down approximately 25 ft. This would allow for the 

installation of2 levels of catalyst within the duct with a spray grid array above 

the catalysts. 

The practical limit for SCRs in high dust, in-duct installations, approaches 80%. 

To meet this level ofreduction for each of these units would require two layers 

of catalyst. While not completely investigated, it may be possible, but will be 

challenging to install two layers of catalyst in this location. Obtaining evenly 

distributed flue gas at optimum velocities in this area is the challenge. 

TIME FOR COMPLIANCE 

The nonnallead time for an SCR is 16-24 months, with an additional 2 months to 

make the necessary modifications and tie-ins. 

CAPITAL COSTS AND DOWNTIME 

The engineering and supply estimate for the SCR is $4,000,000-5,000,000 for each 

boiler. 

The area where modifications are required is quite congested. There is uncertainty 

in the installation estimate due to significant mechanical modifications required at 

the site. Rigging, ductwork modifications, and installation ofthe SCR will be a 

challenge. The Harris Group Inc. has estimated the installation costs to range 

between $6,100,000 and $9,100,000 for each SCR. 

The total installed estimated for an SCR solution for each unit is between 

$11,000,000 and $14,000,000. This equates to a range of$338/kw (gross electric) 

and $431/kw (gross electric) per unit. The estimated gross electrical generation is 

32.5 MW per boiler. The total installed cost for two SCRs, one for each unit, is 

between $22,000,000 and $28,000,000. There would be minimal savings realized 

from duplicate units, since the majority ofthe cost is equipment costs and 

installation costs. 

Significant mechanical modifications will be required. A 2-3 month outage would 

be required to make the necessary modifications and tie-ins. The cost of lost 

generation has not been estimated since Metso does not know the load profile and 

power sales rate structure. 

Metso Power© 2011 
v 

'~. NOx Control Economic 9 (12) , )metso Evaluation (YELP) 

Dale of Report 

Feb 2011 Project # 710068 

OPERATING AND MAINTENANCE CONSIDERATIONS 

(O&M costs are for each unit, there are two units at YELP - multiply by two for 

plant yearly costs) 

The O&M costs are expected to be approximately $620,000 per unit for the SCR 

when catalyst costs and installation are factored in. Catalyst Maintenance costs for 

the SCR are expected to annually average $430,000 for each unit. These estimates 

are based on typical catalyst life. The costs are likely low because ofthe higher 

potential for catalyst poisoning resulting from the presence of vanadium in the flue 

gas stream. Vanadium has been shown to poison catalysts. Catalyst poisoning 

would cause difficulty in maintaining compliance. Unit availability and revenues 

will likely decrease because of catalyst maintenance events. It is recommended that 

a detailed review oftube fouling and catalyst fouling potential be performed prior to 

selecting SCR technology as a method of NOx control on this unit. 

Maintenance ofthe SCR and catalyst will also be difficult due to limited working 

area. The performance and the reliability ofthe SCR could be compromised for 

various reasons including limited straight duct above the SCR. Ideally, an SCR 

should have additional space available for the future addition of another layer of 

catalyst. Because of limited available room, only two layers of catalyst can be 

installed. There is not enough room for the future addition of the third layer of 

catalyst. This additional expansion slot (third layer) would provide more 

performance flexibility as well as reduce the outage time for catalyst replacement. 

In most installations, new catalyst can be installed in the third row while the 

exhausted catalyst is being removed from one of the two in-service rows. In this 

installation, it is likely that one row of catalyst will have to be removed completely 

and then fresh catalyst will be installed in its place. This will cause more unit 

downtime, which translates into less availability and a decrease in revenue. 

Petroleum fired coke units often have fouling that occurs on superheater surfaces 

upstream of where this SCR is to be located. It has been shown on other petroleum 

coke fired units that the debris from fouled tubes have broken loose and plugged up 

airheater tubes downstream of the superheaters. It is likely that deposits on 

superheaters, which are known to exist at YELP will break loose and foul an SCR 

downstream of this superheater bundles. This could significantly increase the 

maintenance costs for the SCR. 

An SCR also introduces additional pressure drop in the system. A 4" pressure drop 

translates into $70,000 per year at $.06/kw. This is a per unit cost. 

The ammonia usage is less for an SCR than an SNCR. The predicted ammonia 

consumption will add $105,000 to the operating costs for each boiler. 

Metso Power© 2011 
NOx Control Economic LO (12)

metso Evaluation (YELP) 

Date of Report 

Feb 201 L Project # 710068 

OTHER NON..ENVIRONMENTAL IMPACTS 

SCRs can contribute to airheater fouling due to ammonia bisulfate formation. 

Airheater fouling could reduce unit efficiency, increase flue gas velocities in the 

airheater, cause corrosion, and erosion. 

On some installations, catalyst life is very short and SCRs have fouled in high dust 

environments. This had led to downtime on other units within the fleet in overseas 

installations. A detailed assessment of catalyst life cost would require further 

analysis by a catalyst vendor. The presence of vanadium in the fuel has led to 

reduced catalyst life on prior units. 

In summary, Metso does not believe that SCR technology would be the most 

practical solution for NOx reduction at this facility because of the many likely 

operating and maintenance issues presented above. SNCR technology is proven and 

is capable of at least 50% reduction ofNOx emissions. 

Metso Power© 201 L 
TABLE 1: Summary Table of Assessment of NOx Control Economic Evaluation 

Yellowstone Billings 

Cost of compliance 

Time necessary for compliance 

Energy and non-air quality environmental 

impacts of compliance 

Remaining useful life of affected source 

Eng and Supply 

Installation 

Total installed costs 

Other Capital Costs 10 fan upgrade 

IU&M(avg yeany) tor eacn Unit - sutltotal ot costs tlelOw 

Ammonia svs maint 

sootblower 

SCR catalyst 

Catalyst install 

SCR disposal 

additional pressure drop 

Ammonia cost (each unit) 

SUDDlv and install 

unit downtime, loss of 

revenue 

ash resale problems 

fouling 

$Iyr 

$Ivr 

$Ivr 

$Iyr 

$Iyr 

$Iyr 

$/yr 

$/yr 

capital and install for 

SNCR is for both units SCR Cost Range (each boiler) 

SNCR(50"k) SCR(-SO%) SCR(-SO%) 

$ 685,000 $ 5,500,000 $ 5,500,000 

$ 195,000 $ 5,500,000 $ 8,500,000 

$ 880,000 $ 11,000,000 $ 14,000,000 

SNGR cost aDove SCR Costs are for each of the two units 

for both units 

combined 

All costs below are per unit 

may need to upgrade 10 fan (estimate include in 

above) 

$ 217,719 $ 619,910 

$ 15,000 $ 10,000 

$ 5,000 

$ 223,650 

$ 189,000 

$ 20,000 

$ 61,323 

$ 202,119 $ 104,931 

24-30wks 26 months 

2 week outage lost revenue for 2 month outage 

none observed unknown 

not expected airheater fouling 

24 24 

SCR Installation order of magnitude estimates by Harris Group Inc. 
.. ... • 

"' .... " .... .: • "'.. II 

I

•

i

4 • 

• 

I Ii II 

iiiII s o.IL I '" Eo 

(1)0 = 1-(0 I

I I 

.f 

U 

II " ••-!. !II 

• u • c 
Harris Group Inc. 

February 21, 2011 

Mr. Scott Siddoway 

Rosebud Operating Services, Inc. 

1087 W. River Street, Suite 200 

Boise, ID 83702 

Via E-mail: scott.siddoway@rosi-boise.com 

Reference: Montana Power Plants 

Review of Economic Evaluation of NOs Control at YELP and CELP 

Harris Group Inc. Project No. 65353 

Dear Scott, 

Harris Group Inc. (HGI) has reviewed two reports prepared by Metso titled "Economic Evaluation of 

NOx Control; Colstrip Energy Limited Partnership" and "Economic Evaluation of NOx Control; 

Yellowstone Energy Limited Partnership" per your request. The reports are based on a general 

review of the two most common technologies for NOx control in power boilers: Selective NonCatalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR) with a brief presentation on 

how to implement each technology in each boiler. The reports present rough order of magnitude 

equipment costs, installation costs, and operating and maintenance costs for each technology. 

The total installed cost for SNCR ($880,000) is in the expected range compared to similar 

installations that we are familiar with. Operating costs are by far the greatest expense with the cost of 

the reagent being about 93% of annual operating cost. Metso's estimate of annual operating cost 

appears to be in the right range. However, the reagent cost is directly affected by the cost ofnatural 

gas and will have a tendency to fluctuate quickly when natural gas prices change. The application of 

SNCR on circulating fluid bed boilers (CFB) is wide spread today as an effective technology for NOx 

control; however, the technology is limited to about 50% removal. 

The installed costs for SCR appear to be on the low side considering the degree of difficulty 

associated with the installation on the boilers at these two facilities. The space inside the boiler 

buildings around the economizers is very limited and working space outside the building at YELP is 

extremely limited. This makes the engineering design and installation for a retrofit project 

considerably more difficult than a new installation of the same size and removal efficiency. Based on 

the equipment cost provided by Metso, HGI's rough order ofmagnitude installed cost for SCR at 

YELP is between $11,000,000 and $14,000,000 per boiler. The installed cost at CELP is slightly less 

at $10,500,000 to $13,000,000. This cost range includes upgrading or replacing the existing ID fans 

and supporting equipment as it is mostly likely required to overcome the increased flue gas pressure 

drop through the SCR catalyst. The largest part of the operating cost for SCR is the catalyst 

replacement cost and because there is limited experience with these fuels and CFBs retrofitted with 

SCR these costs could be considerable more than indicated in the reports due to fouling and plugging 

of the catalyst. 

; i!· ;,1 
Mr. Scott Siddoway 

Rosebud Opemting Services, Inc. 

Re: Montana Power Plants - Review of Economic Evaluation ofNOx Control at YELP and CELP 

February 21, 2011 

Page 2 

There is not an extensive list of circulating fluid bed boilers that have been retrofitted with 

SCR technology in North America. Because of this fact coupled with the unique fuel burned 

at each of the plants, installation of SCR is not recommended. If forced to install the 

technology, an extensive research effort is recommended including test burning the fuels 

with a test catalyst to help determine effectiveness, fouling and plugging potential, and 

catalyst life expectancy. 

If you have any questions and need additional information please call me at 303 223-6726. 

Sincerely, 

HARRIS GROUP INC. 

Steven D. McCormick 

Project Manager 

SDM:smk 

cc:	 R. D. Wankner 

Project File 

65353\docs\Siddoway-ROSI_022111.docx 
YELP 

Nox Control Cost Summary 

NOx Control Option % Control 

Total Capital 

Investment 

Total Annual 

Cost 

Annual 

Emission 

Reduction 

(tpy) 

Annual 

Emissions 

(tpy) 

CFB with Selective 

Catalytic Reduction 60% $28,000,000 $5,796,720 317 79 

CFB with Selective NonCatalytic Reduction 50% $880,000 $589,938 198 198 

Average Annual 

After Control Cost Effectiveness 

($lton) 

$ 18,309.29 

$ 2,981.37 
YELP Nox Control Cost Analysis 

SCR Cost Effectiveness Estimation Based on Contractor Estimates 

Based on contractor estimates developad by MetBo. Inc, sod HarTis Group, toe. see attached report. 

Tala! Capita! Inyestmenl 

Metso estimele (1wO units) 

Direct Annual CQSts (two yoKs) 

Ammonia System Mall11f1nBOce = 

Soot Blower Maintenance ; 

Addilional Pressure Drop = 

ACRC; 

Indirect AnO! la' emus 

CRF; if (1 - (1 • i)~)

i= 

n= 

CRF'TCI 

IDAC = 

Tolal Annual Costs 

TAC = 

Tons of Nox uncontrolled' 

Tons NOll emitted/yesr 

NOx (Ibslllr): 

Tons of NQX controlled' 

fJ NOJ( = 

NO. (Ibslhr): 

Tons NOll emittedlyesf 

Tons NOll feducedlyaar 

528,000,000 

520,000 

510,000 

5134,646 

52og.874 Iyr 

1447.300 Iyr 

1378,000 /yr
 

$40.000 Iyr
 

51.239.820/yr
 

10% 

10 

0.163 

14,556.900 /yr 

15.796.720 

39~.7~ ""'S 90 IbsIhr 

Conlrador Eslimale 

Reagent coosumption cost 

SCR catalyst• ...., boM,s 

Cotalysl notal. ...., boMrs 

SCR disposal. ...., boMrs 

Di"ect annual costs 

Capilal recovery lador 

Ind.ect annual 0051s 

Total annual cost 

Average of 2008 and 2009 Nox IOns from annum emission ioventoty 

80% Control efficiency 

18.07 IbsIhr 

79.2 ""'S 316.60 Ions 

Cost Effectiveness "/tool 

Cosl~Effectiveness=Annual CosVTons $ 18,309.29 Removed 
--

--

YELP Nox Control Cost Analysis 

SNCR Cost Effectiveness Estimation B"""d on Contr~ EstlmalB 

o•• 526.0 MM8tuItIi -....... ..,8IIe


IlfJiO:t" •.•""'*"'­ SHCR_""'*"' ..........
 O,151b1W8u 

CFPu,MT •.02 

NO.,,. '" .... _,""",01­ NO!<'""'" ;I _/-.oIllHCR __..__ 

CF~' 1.• 

CoIt BLC '" a.Of! fJkWh Cool 01_ I' 10% 1rII«eII'8IIe,~

SAT II 1 b MWnan6lI 8nd 2 b UN8 

CFroT.4l '" Cf"""",'CFICJl 

•.02 

N6R::t {Z"NOK,. +O.7/n"""INO'I(,. 

300 

POIIWK'" D.47·NQKPi "NSR"O,/9..5 

1Ul91cw 

Tote!! Capita! 'nyea1mtnl 

$880,000 

QjIJld ADm'" CgN, ''W9 un!IA\ 

$30,000 

ARC == ......,.'" PWR" (0.47'0. "NOQI ~f9,5

23.4 WI 

PC '" PWR • CF lVTAl. .. 8760 • COSTEUC 

"1.300 

DAC '" AMC.ARC.PC • AWe 

.....1,.'" Indirect Annual Costs (two YAts) 

CRF"I/(f-(t.I)") ,. "'" 10,0 

CRF • 0,183 

~C .. eRF' TCI _......-. "43,200 Iyr 

Tola! AnnuMl Cosl! TAe:;l PAC + IPAC 

TAe = $589,938 

Tooo gf Ne, lKIgxMrpI!od" 

90_ 394.7fJ tor. A""". ot 2008 A'Id 2009 Noll fDnI from ..... smIM10n lIwenb'y 

'IND!t = OO%""'*"'_ 

A5.'SlbI/IY

T0fI6Noxe~ar """0-" "7.9 kJrII 

TOfIlJNoKreduestVytJBr 197.'''' 

Cgtt Enoot!YftM!I ,$/too, I CoeI:-errect/wlnee.l'" Annu81 CaeVTcnl Rol!Imo\r«I $ 2.981.37

_2002 ""iIIIN»1

EPA PPII&.Itm eo. e..e.-al ........,flIn, EAIon 

&don A,1. QwIpW t 

ap.-.­

.....

AIWII.MII£m....,~ ­_012000_2009"""_

.....-

IWetence " Figtln 1,8 
YELP 

SOx Cost Summary 

Mnual Annua/ 

EmIHlOll Eml..101lll 

Total Capital Total Annual RBduc:tlOll AItIIr Control Average Mnua/ Cost 

SO. Control Option 0/0 Control Invntment Coe! /toYl /toYI Effectiveness /$Iton) 

CFB with Hydrated Ash Reinjection 

and BoohoullEls 50% $30,885,353 $7,.471,601 913 913 $8,183 

CFB with Spray Dry Absorbers and 

Baahouses 60% $39,054,955 $9,605,960 1,461 365 $8,575 

CFB with DSI and Baohouses 50% $20225105 $5546697 913 913 $6 on 
YELP 

S02 Cost Analysis 

Cost for Hydrated Ash Reinjection 

Estlm_ using OAQPS uample 100 Add Gaollem""'" 

Based on methodology desai>ed in 

EPA Pollution Cost Cmlrol Manual. 6Ih Edlioo 

January 2002 

Section 5.2, Chapter 1 Wet Scrubbers fa< Acid Gas Removal 

Cootbm Factor Coot CostMem Coot 

DIRECT COSTS 

Purchased _ipment OOSIS
 

Number 01 hydllll&d ash Sys1&ms required:
 

Plent mW, pel'-..(Gross)
 

Cost per system + aUJOliary equipment (Bison Estimate)·: 

Total FOA + a"-ry equiIlm&nt 

lns1J'UmBntabOn 

Sales_ 

Freight Putt_ _ ......... COS4 PEC
 8=uaA 

onet installation costs 

Foundations&supporls 0.128 

Handling & erection 0.408 

E_I 0.01 8 

Piping 0.308 

Insullllionlorduclwort< 0.018 

Pain1>'lg 0.01 8 

0Ir0cthts_COSI Oa58 

Retrofit FaClOC 1.3 

DlnlcIIns_liDn COS I b:/uding ReIJ'01ll Foetor: 

Sita preparaton As required, estimate 

Buildings As required. Estimate. 

Tot.l 0Ir0ct Cost. DC 1.30 8 + SP+ 81dg. 

INPIRECT COSTS On",!ltiqn) 

Engineering 0.108 

Construction .,d field expenses 0.108 

Coolractorfees 0.108 

Stan-up om 8 

pertormence !&St om 8 

Contingencies 0.03 8 

TOIoIlndhcl C004 IC 0.35 B
 

ToW _ICool 01Requ/Ad Elaghous. (s..bev/l- ceIQ):
 

TOTAL CAPITAL ..VESTMENT (Tel). DC +IC 2.208 + SP + Bldg.
 

Notes: 

A 

0.10A 

O.03A 

O.OSA 

DIRECT ANNUAL COSTS 

2 

32.5 

53.465.657 Operating Labor
 

S6.933,333 Operator
 

S693,333 Supervisor
 

5208,00000 

$346,657 Operating Materials 

$8,181.333 

Maintenance 

Lebor 

S9al,760 Material 

53.2n,533 

5a1.a13 Ulimes 

S2.454,400 Power Consumption (% of 1.DD'll. Bison El1lm.te
 

5a1,a13 EIectJic<ty 5,694,000 (kWhIyr)
 

5a1,a13 flale: 50.06 $/kWh
 

$6.954,133
 

INDIIlECT ANNUAl. COSTS !C
 

$8.040.373
 

Ovemead 60% of sum of operating labor and materials and 

$25,000 maintenance \abor and materials. 

$50,000 Administrative Cherges 2% of TCI 

Property Texes 1% of Tel 

517.29"707 Insutllnca 1% of TCI 

Capital Recovery Fector (Annualized Capital Cost. 10 y'" el 10%) 

TOTAL ANNUAL COST (tIAR) 

$61a,133 TOTAL ANNUAL COST FROM BAGHOUSl!(S}, 

sa1a,133 TOTAL ANNUAL COST FROM BAGHOUSI!(S) AND !tAR: 

sa1a,133 

5al,a'3 

5al,a13 

5245,440 

$2.863.487 

$20.180.173 

a: Capital cost scaled based on estimate from a vendor of SSM for a 15 MW planl 

0.5 hrslsl1ift 30.00 $/hr 

t5% of operator 

U1Uizes Recycktd Urne In Ash 

0.5 hrslshift 30.00 $/hr 

, 00% of maint. labor 

Uncontrolled Emissions (tonstyr): 

Control Efficiency: 

Controned Emissions (tonslyr):
 

Tons Removed (tonslyr~
 

ICoot.areetivon... (SIton): 

516.200 

$2,430 

51a,2OO 

51a,200 

$341,640 

$3O,61a 

S403,203 

$201,602 

5201,602 

$3,280,975 

$4,5'0.870 

$2.160.831 

$7.4T1.801 

1826.11 

50.00% 

913.1 

913.1 

sa.163 I 
YELP 

502 e-AnalJsis e_Costs tor Spny Dry_... ....... OAQPS 0_ Gee Rem"".. 

Based an methOdOJCgy desoJbed in 

EPA PoauIXJo Cost ComroI Manual. 6ttl Editicn 

Jonuary2l102 

Sedian 5.2, Chapter 1 Wet Scrubbers for Acid Gas Removal 

Cost hem 1'_ Cost Cost ..... C_ 

DRkfkOJfS DIRECT ANNUAl...COSlS. 

Purtnas&d oosls 

Numberd 

__ SDA $)$ferns required' .... _(Groosl 2 

32.5 

SDA Cost perkW:­ 150 

Cost PI' $ys:lem + llUXiial"yequipment: 

ToI8I + BUXNry equipment 

In:stnm8fMtion F_ Sales .....

A 

Q,10A 

0-03 A 

$4,875,000 

$9.7SO,OOO 

$975,000 

$292,500.00 

Operatng l..aboT 

Clpefa"" 

$upeNisor 

0.5 hrslstrifl 

15%of~ator

30.00 S"'u 516.200 

$2,430 

O.D5A S481,5OO Operating M&l&rials 

~~cosr.P£C a-U8A $11,505,000 

DinK:l'~COIIt5 _a........ 

-.dOng a_ 0-'2B 0.40 B 

$1.38J.600 

$4,502.000 

SOll. to be controued (tonS) 

Ratio of sorbant to SOx: 

Lime n9Quired: 

6me cost ($/ton~

1826.11 

1.• Scuce: !Vr PoIhJ.ion Engv'Ieering Manual, 2nd Edfiion, .p26S 

2238.08 """.Iy.... $100 estimate 

Bet1ricaI 0,01 B S115,050 Ii". cost ($lyear): $223.,807,61 

PilJirll 030 B $3.45',500 

_""_ 

_ 001 B 001 B $1'5,050 $115,050 Maintenance 

Lobor O.S"'_ 3O-I)0"r 516.200 

DncflMlallatloncosf 0.858 sa.m,25O MatWiat 100% fA maint tabor $16.200 

RIItMfa FBClOr: 1,3 

Dftcr_'-IncIudbtgR_"""ror, $12,?13,025 Uri/lies 

Po>N8r Consumption (% of EhtC1riclal GeneratIOn): 1,75% Median at values, Source: htfpjlwrMv.,.lcomobotec.c:omItechnolOgyfdt'y.sorbent-t~onhtml 

SitB preperat:ion As ~uired, ltstimate $25,000 Electricity 9.964.S00 (llWWy<) 

&ildngs A' l'l'Quired. Eslimate S50.ooo Rete: $0.06 SlkWh 5597,670 

T_ DIroct l»s\ DC '.30 B + SP + Bldg. $20,293,025 INDIRECT ANIIIJAL COSTS, IC 

INOIRECT COSTS llns!!!ll!ionl Ov"",oad 60% of sum d operating labor &ncI materials and $30,6'8 

~ng 0,10 B $1.150.500 maintenance IIbOr and materiels. 

Con6truction and field expmses 0,10 B 5"'SO,500 Administrative ChlfV8s 2'J(,oHCI $566.396 

~18es

Start""!'

-­ 0.10 B 

0,01 B 

5','SO,5OO 

$115,050 

Property Tax•• 

Ill$Ul'8nce 

1%. of TCI 

1% of TCI 

$283.'98 

$2Il3,198 

0-01 B 511S,05O Capitlil Recovery Factor (Annualized C.pital Cost, 10 yta at 10%) $4,60U'3 

Contingenties __ C08~1C 0.03 B 

0-35 B 5345,1 SO ko2i;nG 

TOTAL ANNUAL COST (SOA): 

TOTAL ANNUAL COST FJlOll BAClHOUSE<S): 

M,MS.03O 

$2,Il1O,131 

TOTAL CAPfTAllNVESTIIENT (TCI)- DC "Ie 2.20 B + SP + Bldg. $2I,319,TU TOTAL ANIIIJAL COST FROIIBAGHOUUlS) AND lIAR: p,-._ 

Note,: Uncontrolktd EmisSC'li (toosIyt) 1826..11 

• Lowe.t Capital Co.t In $lJl,W from EPA Ai PoUution Control Filet Sheet for FGO. Dry Systems <200 MW:	 Control Effioiency: 80.00% 

rttp:llwNN,&pa.govftlnlealeldit1mdg,pdf	 Cont"".. Emias>ons (tonSlyr): 36S2 

Tons Removed (tonsl)') 1,_.9 

ICosl-Elfo<;tt...... ($/ton): $Un] 
YELP 

S02 Cost Analysis 

CDsts trw Dry Sol1lent Injection _ using OAQPS uample for Add Gu R...ovaI 

Based CIl l1l8IIIod<logy desai>o<l in 

EPA Coso Cor4roI Manual, 6Ih Edi"'" 

January 2002 

-.5.2, Chllpla< 1 Wei Scrubbers fer Acid Gas RerrowBI 

Cootltam Foetor Cost Cost'em Cost 

\)IRECT __COSTS """",tCOSlS DIRECT ANNUAL COSTS

Number of hy<lrlOed ash systems requir8d: 2 

-..mil. per boier (Gross) 32.5 

Cost per system + auxiliary equ~na'l't· 51,625.000 Opemting Labor 

TOIBI FDA + auxiliary equipnenl A $3,250,000 Operator 0.5 hrsIst>ft 30.00 $Ihr 516,200 

hslrumenfalion 0.10A 5325.000 Supervisor '5% of operator $2,430 

SaIoslaxas 0.03 A 597.500,00 

Freight __ O,OSA $'62.500 Oporoling_erials ipmenrcost PEe 8: 1,1SA 53,835,0ll0 

SOx to be controled (ms) 1826.11 

Roi<> ofsor-' to SOx: 3 Source Air PcltJtiCIl Engineering _ 2nd Edlion. p264 

Ft>undlllions & supports 0,128 5460.200 Lime required: 4795,88 tonsIyear 

HardOIg & enlCtion 0,40 8 $1.534.000 Hmo cost ($ItCIl): $100 estimem 

El8l:tricaI 0,01 8 $38.350 lime cost ($!yeor): 547S1.587.74 

P¢ing 0,30 8 51.150.500 _ fer ductwor1< 0.01 8 $38,350 

llinttt _ CDSIs 

Meintenance 

Poi'lting 0.01 8 $38.350 labor 0.5 hrsIshift 30,00 $Ihr $16,200 

_ins_lIoncosr 0.858 53,259.750 Material 100% of mainl.lobor $16,200 

Ratmfil Facta 1.3 _1no_tion_In<:I......,,_m_: $4,237,675 Utili.. 

Po_ Consufl'C)lion (% of 0.30% Median of ........, Source: hltp:./www._.comIlochndogyldry-sOlt>enMljection.HImI 

SlIe p<eparBIlCll As reqUirad, astimota $25,000 Electricity 1.706,200 (kWNyr) 

BuIdOlgs As I8QUnd. Estimata, $50,000 Rate: $0.06 SA<Wh 5102,492 

rom/DIrKICoat, DC 1.30 8 +SP + Bldg, $8,147,675 INDIRECT ANNUAL COSTS IC 

INDIRECT COSTS l!nJt!I!l!I!onl Ovelhoad 60% d sum of operating tabor and malfrillts and S30.618 

EngWleering 0,108 $383.500 maintenance leba' and materiMl. CCI1tnI__ Coosbuc1lCll and lald axpen... 0.108 5383.500 AcllTinistrlllUve Charges	 2% orTCI 518!l.799 

0,108 $383.500 property Taxes I'll, ofTCI $94.899 

SIBrt"'P 0.018 $38.350 Insurance 1% ofTCI $94,899 

ParJon'nWlce lesl 0,0' B $38.350 CopRa' Rocovory Faclor (Annualized CoplIaI Cosl. 10 yrs 0110%) $1,544,442 

Ccntingantias 0.03B 5115.050 TOTAL ANNIJAL COST (tISl); 51.",­ rolOl .._r COst IC 0,358 51,342,250	 TOTAL ANNUAL COST FROM BAGHOUSE($)' a,lIlilI,131 

TOT,IiI.. CN'lTALINIIUTIofENT (TCQ. DC olC 2,20 8 + SP + Bldg. $8._,1125	 TOTAL ANNIJAL COST FROM DII AND 8AGHOUSltl$): 5S,S48.5lI7 

Uncontroled Emissions (1DnsIyr); ,~" Noles Con1roI Efficiency: 50.00% 

•	 Dry Sorbanl Injection Systems clIn cost -$40 • COntrolled Emssions (tonslyr): 9'3' 

$50IkW:hrtp:flwww.nalcomobot8C.comlt8chnolOgy/dry·sorbent....jection.tl~ Tons Removed (tonstyr): 9131 

!Coat-EflKtIva"""* ($/tonl:	 .077 I 
YELP 

Replacement of Baghouses for SOx Controls 

Reference: OAQPS Control Cost Manual Fifth Edition, Chapter 5 (December 1998) 

By these calculations from Chapter 5 of Manual 

Stack Flowrate a 233,542 ACFM 

Stack Flowrate a 116,771 dscfm 

Operating Hours 8,760 hrslyr 

Pressure Drop: 

Baghouse (mean from Section 5.2.2): 7.5 in. of H2O 

Baahouse Electricitv Costs: 0.00181lQ)(delta P)(hours oar year) 

Power (kWh/yr)= 2,777,215 kWhlyr 

Cost per kWh­ $0.060 Bison Estimate 

Cost of Electricity:.. $166,633 

Compressed Air Costs: 

low needed (2 scfm/1 ,000 acfm) 2 

cost (per 1,000 scfm) 0.36 

cost per min $0.17 

cost per hour $10.01 

cost per year $87,673.95 

,",ost of Bags (based on vendor estimate for 

similar project) Cost 

Fiberglass Bags $200,000 

Notes: 

a 2009 Stack Test Data 

Chemical Engineering Plant Cost Index (1998 & 2010) 

Annualavg 

Annual avg (proposed) 

CEPCI98 = 

CEPCI10 = 

389.5 

556.4 
YELP 

Replacement of Baghouse for SOx Controls 

Total Capital Costs for Fabric Filler Baghouse with Fiberglass Bags 

_"""", OAQPS Control Cos._ FI1\h Edlloo. Chapter 5 (Oe~ 19951 and associeted 

COST,AIR spreadsheet 

S 

S 

$8,751, 

C<>stC_ 

;ed Equipment Cosls 

BaghousesNeeded 

Capital Cost per scIm:' 

SCFM: 

Cost per Bag,ouse (estimate): 

Total Equipment Costs 

lns1JlJtn<nlation 

Equipment Tax: 

Freioht 

_ Equipment Cost 

1ns1slla_ COOls 

f<lI.ndation and Suppor1s 

HllfldIing end Erection 

Eleclrical 

Piping

lnsuIation forDu_ 

Painting 

Dir8cllnslallation Costs 

RetrofilFaclor: 

:_tion Costs Induding Rerofil Fador 

ita Preplntion 

atihas and Buildings 

T_ DIrect Costa 

IlilJi!lIIl 

Engineering 

Cons1Juction and Field Expenses 

Conlr8c1or Fees 

Stan-up
 

Performance Test
 

Continoencies
 

Tobll_ct Costa 

'otal Cll>ibllln..stment 

Notes: 

Equation COS 

Sum=A
 

0.1A
 

O.mA 

0.05A
 

Sum=B
 

0.048 

0.58 

0.088
 

0.01B
 

0.078 

0.048 

0.74B 

1.3 

1.748. Re1Tofil 

0.18 

0.28 

0.18 

0.018 

0.D18 

0.038 

0.458 

2.198 

Total Annual Costs
 

Reference: OAOPS Control Cost Manual Fifth Edition. Chapter 5 (December 1998)
 

Cost Comoonenl 

Direct Annual Costs 

Operating Labor
 

Operator
 

Supervisor
 

OpeIBting Melerials 

Maintenance 

Labor 

Materials 

Replacement 8ags 

Utilities 

Electricity 

Compl1lssed p.;r 

TOIaIDC 

Indlrec:t Annual ColdS 

Owlheed 

Administrative Charges 

Property Tax 

Insurance 

Caoilal Recov"'" lirom TCI soreedsheel\ 

Enuation COST 

2 hrlshift x 3 shifts/day x 365 days/yf x $3O.oo/hr $65.700 

15% 01 operator $9,~

I hrtshifl x 3 shifts/day x 365 deys/yf x $3O.00"'r $32. $32:: I 00% of Mainl8llance Labor 

(Futu", worth at 3 years end 10%=0.4021"cosl 01 bags) S160,84ll 

0.000181(0, aclm)(dP. in. H20)(hrtyr)"$40.0CVMWhlyr) S222,1n 

2 ,clmll .oooecfm(0)(SO.2511,OOOsclm)(6Omin"'r)(hrs/yf) $t75,34ll 

se!l9.UCI 

60% of sum 01 Operating Labor end Operating Materiels $84,753 

2% ofTolai Cepi1B1 Investment $214,~

1% ofTotai Cepi1Bllnvestment $107,35.1 

1% of Total Cepiiallnvestment $107,35.1 

al 10% for 10 veers (0.16275 x Total Cepilallnvestmenl) $1.7'47,151 

TotsllC $2,261,311 

obll Annual Cost S Sum of Total DC and TotailC 

• Median Value lrom Air Poilution Control Technology 

Factsheet, Fabric Filters: 

hUp:/Iwww.epa.govlttnlcatcldirllff-pulse.pdf 

12.960.931 
APPENDIX B - MODELING
 

Billings Generation Inc. Regional Haze Rule Section 114 Response 

Yellowstone Energy Limited Partnership, Billings Plant 
Appendix B
 

Dispersion Modeling Report
 

Visibility Impacts:
 

Mandatory Class I Areas
 
1.0 INTRODUCTION
 

This appendix provides a summary of the dispersion modeling conducted in support of 

EPA's November 5, 2010, letter (received by BGI on November 15, 2010). Since 

~ispersion modeling was not specifically required in response to the request, this 

appendix is only a brief summary of the model used and various options. More details of 

model options along with all modeling input and output files are available upon request. 

For purposes of brevity, only summary information is provided. 

The November letter from EPA asked BGI to "Please submit an analysis of control 

options" for the BGI facility located near Billings, Montana. The request relates to EPA's 

effort to "address requirements under the RHR for reasonable progress (RP) goals and 

strategies (see 40 CFR 51.308(d)(I) and 51.308(d)(3))." I 

Although the request did not specifically seek or address BGI's visibility impacts on any 

nearby mandatory Class I areas, we believe that such an analysis is required in order to I . , 

meet the underlying requirements of the RHR program. I 

I 

~e note that the entire program of protecting visibility is found at 40 CFR 51, Subpart P 

~subsections 300 through 309). A review of Subpart P indicates the purpose and goals 

bf the program. To begin, the overall purpose of the program is outlined as follows: 

"The primary purposes of this subpart are .. .to assure reasonable 

progress toward meeting the national goal of preventing any future, and 

remedying any existing, impairment of visibility in mandatory Class I 

Federal areas . ..." [40 CFR 51.300(a)]. 

Insofar as regional haze is concerned (the underlying requirement that triggered the 

EPA request), the following is noted when describing the "core requirements,,1 for an 

'implementation plan for regional haze. 

"For each mandatory Class I Federal area .' .., the State must establish 

goals . .. that provide for reasonable progress towards achieving natural 

visibility conditions. The reasonable progress goals must provide for 

an improvement in visibility for the most impaired days . .. " [40 CFR 

51.308(d)(1 )]. 

The rules go on to provide states (EPA in this case) with what must be considered in 

developing reasonable progress. These details were outlined in the November 5 letter. 

The review of control options notwithstanding, it seems the visibility program is clear as 

to its intent. That is, the purpose of the program is to protect (remedy, prevent or 

jOtherwise) visibility in mandatory Class I areas. Based on the language above, it is also 

1 40 CFR 51.308(d). 

-

Appendix B BGI11/15/2010 Section114 Request
 

Visibility Modeling Report Page B-1
 
quite clear that any activity (proposed or otherwise) that does not "improve visibility" is 

not, therefore, a candidate for those "reasonable progress" plans. 

As a result, we believe an analysis that only provides emission control options is not 

sufficient for inclusion into reasonable progress elements unless those emission 

controls improve visibility. It would be at odds with the program to include an emission 

control scenario that did not improve visibility (i.e., a discernible change in deciviews). 

To that end, we have chosen to conduct a brief analysis of the impacts this facility has 

on the nearest mandatory Class I areas. In order to conduct the analysis we have 

chosen, as a matter of convenience and consistency, to follow the general elements of 

the BART dispersion modeling effort. The modeling effort used by BART, including thiiS 

submittal, is found in 40 CFR 51, Appendix Y. 

Appendix B BGI11/15/2010 Section114 Request Visibility Modeling Report Page B-2· 

i 
2.0 MODEL SELECTION
 

For this analysis, and as generally required by EPA for visibility impacts, we used the 

CALPUFF dispersion model system. This is the same system that was applied for the 

~ART analyses carried out under 40 CFR 51.308(e). BART is, itself, an element of the 

~egional haze program and an element in the overall protection of visibility found in 40 

CFR 51, Subpart P. 

CALPUFF is a non-steady-state Lagrangian dispersion model that simulates pollutant 

~eleases as a continuous series of "puffs." It is supported by two primary sub-programs, 

PALMET and CALPOST. CALMET is used in refined analyses to create threepimensional wind fields based on multiple sources of geophysical and meteorological 

data. The output of the CALPUFF model consists of binary data files with information on 

pollutant concentrations, wet and dry flux rates, and visibility parameters. CALPOST 

processes these data based on specified input parameters, and reports calculated 

impact values. 

The CALPUFF analyses utilized for this project are noted below and were obtained from 

the CALPUFF developer, Atmospheric Studies Group (ASG)at: 

http://www.src.com/calpuff/calpuff1.htm. 

Geophysical Data Processors 

• TERREL (Version 3.311, Level 030709) 

• CTGCOMP 

• CTGPROC (Version 2.42, Level 030709) 

• MAKEGEO (Version 2.22, Level 030709) 

Meteorological Preprocessors 

• SMERGE (Version 5.31a, Level 040706) 

• PXTRACT 

• PMERGE (Version 5.31, Level 030528) 

• READ62 (Version 5.52, Level 040716) 

Main Models 

• CALMET (Version 6.211, Level 060414) 

• CALPUFF (Version 6.112, Level 060412) 

Postprocessors 

• CALPOST (Version 6.131, Level 060410) 

• PRTMET 

• CALSUM 

• POSTUTIL 

.~---_...-~

Appendix 8 8GI 11/15/2010 Section114 Request 

Visibility Modeling Report Page 8-3 
The version and level identifiers for the major modules used for this project are 

identified above. Electronic executable files for the primary modules and the primary 

electronic input and output files associated with this analysis are available upon request. 

Appendix B BGI 11/15/2010 Section114 Request 

VIsibility Modeling Report Page B-4 
3.0 CALMET
 

CALMET, the meteorological preprocessor for CALPUFF, was used to compile and 

process land use data, terrain data, and meteorological data for use in the CALPUFF 

model. The CALMET output files define gridded fields of wind speed, wind direction, 

mixing heights, stabilities, micrometeorological parameters, and precipitation - all 

parameters required for input to the CALPUFF dispersion model. The following sections 

provide a brief description of each of these data sets. The CALMET input files are 

provided on the portable hard drives that accompany this dispersion modeling report. 

3.1 Land Use Data 

CALMET uses specific land use data developed by the U.S. Geological Survey (USGS) 

[available for download from the USGS Earth Resources Observation and S~ience

(EROS) web site]. The data files used by this project are 1:250,000-scale files. Each 

land use cell, typically 200 meters square, is assigned a land use code. 

! 

13.2 Terrain Data I 

CALMET uses USGS 1:250k Digital Elevation Models (DEMs) to determine the terrain 

:elevation in the model domain. The terrain data are preprocessed into a data set 

!recognizable by CALMET and used to help create the CALMET output file. I 

! 

I

r.3 Meteorological Data 

IeALMET output files representing meteorological data for the 2001, 2002, and 2003 

talendar years were prepared for this analysis. The input surface and upper air 

meteorological data and the Mesoscale Model version 5 (MM5) data (processed with 

the CALMM5 processor) are those data sets used for the Montana Best Available 

Retrofit Technology (BART) modeling conducted by EPA. 

3.3.1 Mesoscale Model Data 

The MM5 meteorological data for the 2001, 2002, and 2003 calendar years were 

obtained from the Western Regional Air Partnership (WRAP) web site at 

http://pah.cert.ucr.edu/agm/308/bart.shtml. These data are generated by the CALMM5 

processor from MM5 mesoscale meteorological model output files. The CALMM5 data 

have a spatial resolution of 36 kilometers. The mesoscale models are limited-area, 

nonhydrostatic or hydrostatic, terrain-following sigma-coordinate models designed to 

.simulate or predict mesoscale and regional-scale atmospheric circulation. The data are 

lused as a basis for generating an "initial guess field" of multilayer meteorological 

Iparameters in CALMET. 

i 

Appendix B BGI11/15/2010 Section114 Request
 

Visibility Modelin,g Report Page 8-5
 
3.3.2 Surface Data 

Hourly surface meteorological data for 2001, 2002, and 2003 also were obtained from 

the WRAP internet site. This data set includes data from 39 locations for 2001 and 36 

locations for 2002 and 2003. The WRAP data are in the SMERGE format and are ready 

for input into CALMET Version 6. The data have been manually converted for use with 

CALMET Version 5.8 (involving only minor changes to the header records in the data 

files). 

Surface data from the following locations were used in the CALMET analysis: 

• Badger Peak, MT (2001 only) 

• Billings, MT 

• Bismarck, I\JD 

• Boise, ID 

• Bozeman, MT 

• Butte, MT 

• Casper, WY 

• Coeur d'Alene, ID 

• Cut Bank, IVIT 

• Dickinson, ND 

• Dillon, MT 

• Estevan, SK 

• Havre, MT 

• Kalispell, MT	 J 

f

• Garfield Peak, MT (2001 only) 

• Glacier National Park, MT 

• Glasgow, MT 

• Great Falls, MT 

• Helena, MT 

• Havre, MT 

• Lander, WY 

• Lewistown, MT 

• Livingston, MT 

• Medicine Hat, AB 

• Miles City, MT 

• Minot, ND 

• Missoula, MT 

• Morningstar, MT (2001 only) 

• Peabody Coal, MT 

• Pocatello, ID 

• Rapid City, SD 

• Rexburg, ID 

•	 Riverton, WY 

•	 Salmon,ID 

•	 Sheridan, WY 

•	 Spokane, WA 

•	 Spring Creek Coal, MT 

•	 Theodore Roosevelt National 

Park, ND 

•	 Williston, ND 

•	 Yellowstone National Park, WY 

---------	 ----._._--­ Appendix B BGI 11/15/2010 Sectlon114 Request 

Visibility Modeling Report Page 6-6 
3.3.3 Upper Air Data 

, 

IUpper air rawinsonde data collected at seven National Weather Service (NWS) stations 

iwere obtained from the rawinsonde data repository maintained by the National Oceanic 

land Atmospheric Administration (NOAA) at http://esrl.noaa.qov/raobs/. The data were 

Iprovided in the standard FSL data format for use in the CALMET system. The seven 

INWS upper air rawinsonde locations used for this project are: 

• Bismarck, ND 

• Boise,ID 

• Glasgow, MT 

• Great Falls, MT 

• Rapid City, SD 

• Riverton, WY 

• Spokane, WA 

3.3.4 Precipitation Data 

'Hourly precipitation data in the National Climatic Data Center (NCDC) TD-3240 format 

iwere obtained from the data set developed by MDEQ for their BART modeling analysis 

!effort. All precipitation stations located within the CALMET modeling domain were 

:extracted from the data set and used in the CALMET analysis. A total of 286 stations 

iwere selected for each of the three modeled years. A complete list of precipitation 

istations is included in the CALMET input files. 

:3.4 CALM ET Technical Options 

IThe CAL MET meteorological processor was executed using the technical options 

irecommended in the EPA/IWAQM guidance, the EPA Model Clearinghouse 

imemorandum of May 15, 2009, and the EPA-Federal Land Managers (FLM) Model 

IClearinghouse clarification memorandum of August 31,2009. A table of the values used 

:is available upon request. 

Appendix 6 6GI11/15/2010 Section114 Request
 

Visibility Modeling Report Page 6-7
 
4.0 CALPUFF
 

4.1 CALPUFF Technical Options 

CALPUFF applies mathematical algorithms to calculate pollutant concentrations at 

specified receptor locations. CALPUFF's output files contain concentration values for 

every receptor and every hour modeled. These output files must be processed through 

CALPOST to evaluate model results against regulatory limits or guideline thresholds. 

CALPUFF requires inputs of CALMET data files, source characteristics and emission 

rates, and receptor grids to model impacts. 

For purposes of brevity, a complete list of the technical options chosen for this modeling 

exercise is not presented. As noted earlier, the same options used for the BART 

analyses were used here as well. A copy of the technical options along with all other 

input and output files are available on request. . 

4.2 Receptors 

The receptors chosen for this modeling were those of the nearby mandatory Class I 

areas. The mandatory Class I areas chosen were: 

• Gates of the Mountain Wilderness 

• UL Bend Wildlife Wilderness Area 

• North Absaroka Wilderness 

• Yellowstone National Park 

These four areas represent the closest areas to the facility and also display a relativelv 

wide range in direction from the plant. I 

The specific receptors used for the runs are the same as those generated by the federal 

land managers and used in the prior BART analyses. The exact receptor locations are 

not presented here to keep this report brief. Copies of the receptors are available upon 

request. 

4.3 ModeJed Sources and Emission Rates 

The modeled source for this analysis was the BGI facility in Billings, Montana. There is 

only one stack associated with the facility and that was the only point-source emission. 

Appendix B BGI 11/15/2010 Section114 Request
 

Visibility Modeling Report Page B-8
 
The emission rate for this analysis was based on the same general procedure defined in 

,the BART analysis. That is, the highest 24-hour emission rate was chosen over three 

years (2007 through 2009).2 In some cases, additional modeling was done using lower 

emission rates that were based on control option analyses contained in this report so 

that an estimate could be made of the impact a specific option could have on the 

nearest mandatory Class I areas. 3 

The baseline emission rates4 used in the model are shown in the table below. 

Table B-1: Modeled Emission Rates 

502 NOx 

(Ibs/hr) (Ibs/hr) 

591 242 

., PM10 

(Ibs/hr) 

2.3 

PM2.5 

(Ibs/hr) 

2.2 

2 The BART analysis (40 CFR 51, Appendix Y) used emission years from early 2000. It was decided to 

use the three most recent years of data as a better representation of impacts. It is noted, however, that 

the emission rates from early 2000 through present emissions would not be expected to change in any 

meaningful way. In addition, to the extent that it is quantifiable, 24-hour periods that include emissions 

from startup, shutdown or malfunction were excluded in the emission rate determination in accordance 

,with BART guidance. J For reference, the nearest mandatory Class I area was about 120 kilometers from the plant. 

, Baseline means the emission rate (as discussed in footnote 2 above) and does not include the effect of 

the control options discussed elsewhere in this document. 

Appendix B BGI11/15/2010 Section114 Request
 

Visibility Modeling Report Page B-9
 

i 
5.0 CALPOST CLASS I VISIBILITY ASSESSMENT
 

Visibility impacts (expressed in terms of percentage change in 24-hour average 

background extinction relative to natural background visibility) were calculated using 

the CALPUFF modeling system and data. The analysis was conducted using 

concentration files produced by CALPUFF and CALSUM. The visibility assessment is 

based solely on the BGI facility. 

The methods recommended in the BART program were followed in the visibility. 

analyses. CALPOST Version 6.131, Level 060410 was used in these analyses. The 

technical options employed in the CALPOST analyses are not presented here for the· 

sake of brevity. It is noted, however, that some visibility options are specific to the 

mandatory Class I area being evaluated. Those area-specific data were applied as 

appropriate. 

Appendix B BGI 11/15/2010 Section114 Request 

Visibility Modeling Report Page B-10 

I 
6.0 RESULTS
 

6.1 Visibility Analysis 

The methodology for the visibility analysis portion of this project is the same as the 

methods used for the BART program discussed elsewhere in this appendix. The 

analysis is conducted by calculating concentrations of particulate, sulfate, nitrate and 

other compounds in the atmosphere from the modeled facility in question. The 

foncentration of those compounds in the atmosphere is used to estimate changes to 

visibility that could occur. 

Impacts to natural background visibility, expressed in terms of percentage change in 

24-hour average background extinction (~Bex) were calculated by CALPOST 

processor (an integral part of the CALPUFF modeling system). The BART guidelines 

also reference 40 CFR §51.301 (a) in asserting that determinations must be made on 

a "... case-by-case basis taking into account the geographic extent, intensity, duration, 

frequency and time of visibility impairments ...." In accordance with 40 CFR 51, 

Appendix Y, the 24-hour average 98th percentile impact results are summarized in 

the following table. 

To serve as a baseline, the table below shows the results of the CALPUFF modeling 

results. The data uses the baseline emission rates (2008-2009) and assumes no 

additional controls as discussed in the main document. The emission rate is shown in 

Section 4.3 above. 

Table B-2: Visibility Impacts: Baseline Case 

Visibility 

Class I Area (I\DV) 

Yellowstone National Park 0.193 

UL Bend 0.376 

North Absaroka 0.294 

Gates of the Mountains o176 

The results of this analysis are revealing. The deciview values themselves represent 

the change in visibility (L\DV) that could occur as a result of the facility as currently 

configured. The values in the table are all below 0.5 dv. EPA has used this 'threshold" 

value for some time as a measure of a non-measurable or nil impact. The modeling 

analysis has shown that current emission rates result in impacts well below the 1.0 

deciview level EPA employs as a level to indicate that a source causes a visibility 

impact and are also below the 0.5 deciview level that EPA has proposed as the level 

at which a source may contribute to a visibility impact. According to general guidance, 

Appendix B BGI11/15/2010 Section114 Request
 

Visibility Modeling Report Page B-11
 
if a facility's impact, by itself, is less than 0.5 dv, then the facility's impact is 

considered de minimis. 

Since the impact predicted from this facility, without the consideration of additional 

controls, is de minimis, then clearly the addition of additional controls adds nothing to . 

the analysis. As a result, no additional controls constitute "reasonable progress" since 

the addition of controls does not create any "progress" toward the national goal. 

As a matter of interest, it was decided to provide an estimate of the improvement to 

visibility, regardless how small, that would be expected to occur, based on the model, 

as a result of reducing emissions beyond their current baseline level. Since a 

particular strategy is not up for discussion, it was decided to execute the model using 

a 50% reduction of S02 from Dry Sorbent Injection and a 50% reduction of NOx from 

Selective Non-Catalytic Reduction. The 50% figure is a reduction from the baseline 

values used in the model above. 

Additional model runs were considered for a reduction in particulates. However, this 

was rejected for two reasons. First, the plant is already well controlled for particulates. 

Second, there are no reasonably available additional controls that could be added to 

improve, in any measurable way, particulate emissions. 

The results of the modeling are shown in the tables below. 

Table B-3: Visibility Impacts: SO% Reduction SOz 

Visibility (i\DV) 1----_._- ----,----~--'--'--__,_-----------.

Reduction "Improvement" Class I Area Baseline 502 to Visibility 

Yellowstone National Park 0.193 0.135 0.058 -- ._ .. ­ --.- -------t-------------j---------+-----------­

UL Bend 0376 0.267 0.109 

If--------------.. ~--+---------11

0 O80 North Absaroka ---- -- . 0_.2_9_4 .... i--

°.. 214----_- f-- _.__ [ 

0 125 IGa~t~e_s.Of~~~~,~~~~t.-~a,:_n~s~~~~~o~.~17~6~~~.L,.,., ~_~J.......~~~_~~0=52__~_~
 

Appendix B BGI11/15/2010 Secllon114 Request 

Visibility Modeling Report Page B-12 
I 

Table B-4: Visibility Impacts: 50(Yo Reduction NOx 

Class I Area Baseline 

Visibility (t.DV) 

Reduction 

NOx 

"Improvement" 

to Visibility 

The results of additional controls (S02 or NOx) to the currently configured facility 

show no improvement to regional haze. In fact, the "improvement" is about 1/5 of the 

the de minimis or nil value. Since these controls do not result in any perceivable 

improvement to regional haze, clearly the addition of such equipment could not be 

ponsidered "reasonable" progress. 

Appendix B BGI 11/15/2010 Section114 Request
 

Visibility Modeling Report Page 8-13