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 1595Wynkoop 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 ofthe potentially affected sources. Pursuant to Section 114(c) ofthe 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 TOREQlTEST FORADDITIONAL REASONABLE PROGRESSINFORMATIONFOR THE YELLOWSTONEENERGYLIMITED PARTNERSHIPFACILITYPURSUANT TO SECTION 114(A) OFTHE CLEANAIRACT (42 U.S.C SECTION7414(A))

Prepared for: 

### Billings Generation,Inc. Suite 200 1087WestRiver Street Boise,ID 83702

Preparedby:

# ~BISON ENGINEERING, INC. 1400 11th 

### Avenue Helena, MT59601 406-442-5768 www.bison-eng.com

## TABLE OFCONTENTS 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 Necessaryfor Compliance 3-1 3.1.1 Installation of S02 Controls 3-1 3.1.2 Installation of NOx Controls 3-1 4.0 ENERGYAND 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 POTENTIALLYAFFECTED SOURCES 5-1 6.0 VISIBILITY MODELING RESULTS 6-1 6.1 Visibility Modeling Results 6-1 7.0 SOX CONTROL ECONOMIC RESULTS AND IMPACTSTO ViSiBILiTy 7-3 7.1 NOx Control Economic Results and Impacts to Visibility 7-4 8.0 SUMMARy 8-1 APPENDIXA -COSTS OF COMPLIANCE ANALySiS 8-1 APPENDIX B - MODELING 2

Yellowstone Energy Limited Partnership Regional Haze Rule Section 114 Response Billings Generation Inc. Page ii

## 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 ofcompliance, (2) The time necessary for compliance, (3) The energy and non-air quality impacts ofcompliance, and (4) The remaining useful life ofthe potentially affected sources. This report serves as BGI's response to the EPA's information request. The remainder ofthis document provides the requested analysis. 

### 1.2 Regulatory Summary Before analyzing EPA's request, it is instructive to review the nature and purpose ofthe 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 ofthe program. The overall purpose ofthe program is outlined as follows: "The primarypurposes 

### ofthis subpartare
. .. to assure reasonable progress towardmeeting the nationalgoal

### ofpreventing anyfuture, and remedying anyexisting, impairment

### ofvisibilityin mandatory Class I Federalareas
. ... " 

### [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. Billings Generation Inc. Regional Haze Rule Section 114 Response 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 ofvisibility 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: "Foreach mandatory Class I Federalarea
. .. , the State mustestablish goals

. .. thatprovide forreasonable progress towards achieving natural visibilityconditions. 

### The reasonable progress goals mustprovide for 

### an improvementin visibilityforthe mostimpaired 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 ofReasonable 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 

### ofcontrol 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). Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 1-2

### 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 ofthose investigations.

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 1-3

## 2.0 COSTS OFCOMPLIANCE This section of the RHR Section 114 response will describe the costs of compliance to meet the reasonable progress goals and strategies ofthe 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 CirculatingFluidized Bed BoilerInformation 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 ParticulateMatter 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 ofYELP's PM and PM10 emission testing results from 2008 through 2009: 

### Table2.2-1: 2008-2009PMand PMlO 

### Emission TestingResults 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 ofthis report which support this conclusion.

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-1

### 2.3 SulfurDioxide 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 

### ControlTechnologies 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. WetLimeScrubber 

### 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 ofthis technology on CFBs firing petroleum coke.
Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-2Wet 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 ofthis technology on CFBs firing petroleum coke. DualAlkali 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. SprayDryAbsorber 

### 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 orderto 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. Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-3

### 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. DrySorbentInjection 

### 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. CirculatingDryScrubber 

### 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. HydratedAshReinjection 

### 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 ofthe 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 EliminatingTechnicallyInfeasible Options CDS systems result in high particulate loading to the unit's particulate control device. Because ofthe 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 Billings Generation Inc. Regional Haze Rule Section 114 Response 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.



### Figure2.3-1: YELPPropertyBoundaryand Yellowstone River 2.3.3 TechnicallyFeasible Options Technologies requiring low amounts of water and installation space were evaluated. The three technically feasible control options forthe YELP facility were determined to be

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-5

### hydrated ash reinjection (HAR), spray dry absorber (SDA), and dry sorbent injection (DSI). The ability ofthe 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 ofthese 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 ofYELP 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. Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-6

## Table2.4-1: 2008-2009 NOx Emission TestingResults Year NOx (Ibs/MMbtu) NOx (Ibs/hr) 2008 0.201 199.8 2009 0.201 112.8 

### 2.4.1 ControlTechnologies 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. 

### LowExcessAir (LEA) LEA operation involves lowering the amount of combustion air to the minimum level compatible with efficient and complete combustion. Limiting the amount ofair fed to the furnace reduces the availability of oxygen for the formation of fuel NOx and lowers the peak flame temperature, which inhibits thermal NOxformation. 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 ofthe 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. 

### OverfireAir (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 offuel
Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-7

### NOx. In this atmosphere, most of the fuel nitrogen compounds are driven into the gas phase. Having combustion occur over a larger portion ofthe furnace lowers peak flame temperatures. Use ofa 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 lowerfurnace that in turn may lead to corrosion ofthe boiler. This technology is typically utilized on PC units. This option cannot be utilized on CFB due to air needed to fluidize the bed. 

### LowNO xBurners (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 CatalyticReduction (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 ofthe 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.

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 2-8

### 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. 

### SelectiveNon-CatalyticReduction (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 EliminatingTechnicallyInfeasible 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.

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## 3.0 TIME NECESSARYFORCOMPLIANCE 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 ofS02 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 ofNOx 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.

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## 4.0 ENERGYAND NON-AIR QUALITYIMPACTS OF COMPLIANCE 4.1 EnergyImpacts 4.1.1 EnergyImpacts: 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 ofthe 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 EnergyImpacts: 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 QualityImpacts 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 atotal 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 QualityImpacts: SCRorSNCR 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 REMAININGUSEFULLIFE OFTHE 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 VISIBILITYMODELINGRESULTS 6.1 Visibility ModelingResults 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 PM 10 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 IAreas. 

### Table 6.1-2: Visibility ImpactsWithoutAdditional Control
Class I Area Visibility Impact**(~DV)** Yellowstone National Park 0.193
UL Bend 0.376
North Absaroka 0.294
Gates ofthe 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 CONTROLECONOMIC RESULTSAND IMPACTSTO VISIBILITY Table 7.0-1 summarizes the results ofthe potential addition of SOx controls and their emission reductions. 

### Table7.0-1: Cost-Effectiveness ofSOx 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 ofthis 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 ofthis report. Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 7-3

### Table7.0-2: Cost-Effectiveness ofDSI 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 ControlEconomic Results and Impactsto Visibility Table 7.1-1 summarizes the results ofthe potential addition of SCR and SNCR and their emission reductions. 

### Table7.1-1: Cost-Effectiveness ofNOx 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 ofthis report. Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 7-4

### Table7.1-2: Cost-Effectiveness ofSNCRin $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 ofthe 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 atwhich 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 improvementfrom OSI. As part ofthe analysis, EPA requested that BGI analyze the costs ofcompliance. 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 ofthe 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 offour 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 ofthe environmental benefits ofscrubbing the ExxonMobil cokerflue gas emissions.

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant Page 8-2

## APPENDIXA-COSTS OFCOMPLIANCEANALYSIS

Billings Generation Inc. Regional Haze Rule Section 114 Response Yellowstone Energy Limited Partnership, Billings Plant

## ECONOMIC EVALUATION OF NOxCONTROL 

# Yellowstone Energy Limited Partnership Billings, Montana METSO REFERENCE No. 

# 710068 Feb 2011 

# 1)metso

II' Expect results2 (12) 

## NOx Control Economic 

## )metso Evaluation (YELP)
Date ofReport Feb 2011 Project

### #710068



### Executive Summary Metso was contracted to provide an economic evaluation ofNOx control for the two Circulating Fluidized Bed Boilers (CFB) at the Yellowstone Energy Limited Partnership (YELP)facility in Billings, Montana. This estimatewas compiledusing drawings ofthe plantthat are inMetso's archives. The drawings do not showbalance ofplantpiping, cable trays, small borepiping, and modificationsthathavebeenmadeto the facility following initial installation. There couldbe interferences and significantunknowns that would alter Metso's conclusions contained within this report. This is an order ofmagnitude estimate. Metso evaluated the use ofSelective Catalytic Reduction (SCR) and SelectiveNoncatalytic Reduction (SNCR) technologyto reduce NOx emissions atthe YELP facility. A SNCRis capable ofreducing NOx emissionsbyat least 50% while the SCRis capable ofpractical reductions ofup to 80%, dependingon space availability. The total cost for installing SCRsonboth units ranges from $22,000,000 to $28,000,000 whereas the total installed cost for SNCRs would be less than $1,000,000 forbothunits combined. Since the bulk ofthe SNCRsystem will be shared bytwo units, SCR technology will be between22 and 32 times the cost for SNCRtechnology at the facility. The Operation and Maintenance (O&M) costs for the SCRare estimated tobe 2.8 times the costs for O&M ofthe SNCRsystem. The increased cost for the potential 30% additional reduction in NOxemissionsbythe installation ofan SCRsystem at this facility is significant. CFBs are typically inherently lowerNOx generators than otherboilertypes. Petroleum coke fired CFBs emit fewer NOxemissions than those firing coal orother fuels. SNCRs are onmany ofthe boilersthat Metso has supplied withinthe United States. However, none ofthe Metso-supplied CFB boilers within the United States incorporate SCR technology. There are risks associated with using an SCRon aboilerutilizingpetroleum coke as a fuel source. There is vanadium in petroleumcoke. 

### Itis proventhat vanadium poisons SCR catalysts. The catalyst life for this unit is likelyto be short (likely months instead ofyears). This will likelyreduce the availability ofthisunit and subjectthe facility to significant operatingand maintenance costs. The catalyst life is difficult to quantify without a further extensive studybya catalyst supplier. 

### Itis unlikely or would be costlyto obtain a lengthy catalyst life guarantee from a catalyst supplier for this application. Foulingofpetcoke fired units occurs on superheater surfaces. The superheateris upstream ofthis SCR. The fouling will likely cause plugging andblinding ofthe SCRcatalyst when it breaks loose from the superheater surfaces. This will increase maintenance costs atthis facility and subject the unit to increased downtime. Metso wouldbehesitant to install an SCR on a petroleumcoke fired boiler.

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## NOx Control Economic 

## metso Evaluation (YELP)
Date ofReport Feb 201L Project #710068



### TABLE OFCONTENTS

OVERVIEW
- 4 AQUEOUS AMMONIASySTEM 4 SYSTEM DESCRIPTION: 4 LOCATION AND INSTALLATION CONSIDERATIONS OfAMMONIA 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 economizerandbaghouse
- 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 EVALUATIONTABLE 11 ATIACHMENT2 - GENERAL ARRANGEMENT DRAWING ••••••••••••••••••••••••••••••••••••••••.••••••••••••••••••••••••••••••••••. 12

Metso Power© 2011**.~.**, 

## ) metso NOx Control Economic Evaluation (YELP) 4 (12)

Date ofReport Feb 201 1 Project

### #710068


## Overview­ There are two Circulating FluidizedBed Boilers at the YELP facility_ Eachboileris rated for 300,000 Iblhr at 1300psig and 955F mainsteam. The fuel is petroleum coke and coker gas. The purpose ofthis assessmentis 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 SNCRsystem capable of50% NOx reduction for controlled NOxrates of.075 Ib/MMBTU • An SCRsystemcapable of80+%reduction for controlledNOx rates of.03 IbIMMBTU. Bothsolutions require a method for the storage and supply ofammoniato the process. 

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

## Aqueous ammonia system SYSTEM DESCRIPTION: The ammonia system is similarforboth the SNCRand the SCR. There are two boilers at this facility howevera commonammonia systemcanbe usedto supplyreagent to bothunits. Itisless expensive and more practical to have one larger systemthan two small systems. The system consists ofa 14,000 gal ammoniatank with meteringpumps, filters, tank level sensor and alarm, caged ladder for access to top oftank, and othervarious attachments. The tank can contain approximately 8.5 days ofstorage of 19.5% aqueous ammoniausing the SNCR system while providing50%reduction ofNOx when both boilers are at full load. The largertank will allow more flexibility in the filling cycle. The tank is sized to contain slightly more than 2 standard tanktruck loads ofaqueous ammonia.
LOCATION AND INSTALLATION CONSIDERATIONS OF AMMONIA SYSTEM Thetank and forwarding skid would be located onthe ground, outside ofthe boiler house. A containmentdike is installed around the tank to capturethe fluid ifa leak orrupture occurs.

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## NOx Control Economic ) metso .' 

## Evaluation (YELP)
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### #710068 

## Selective noncatalytic reduction system (SNCR) SYSTEM DESCRIPTION: An SNCRsystem for a CFB consists ofthe aqueous ammonia systemlisted above, small bore pipingfrom the metering skidto theboilers, and injectionnozzles at the cyclone inlets for theboilers. There are two boilers at this facility. A single line will berouted from the forwarding system to the elevationofthe cyclone inlet ducts ofthe two boilers. The line willbranchinto two lines at this elevation. Eachbranch line will have a control valve that will meterthe required flow to the specific boiler. The line downstream ofeach controlvalve will branch againto feed two distribution or meteringpanels. A distributionpanel will be located at eachoftwo cyclone inlet ducts on each boiler. The metering skids will beused to bias ammonia flow to eachofthe four nozzles on each cyclone inlet duct. Steamorcompressedair is used to atomize and distribute the ammonia into the cyclone inlet ducts. Ifthe system is tobeused intermittently, purge air would be installed to keep the nozzles clearofmaterial whenthe system is not in use. LOCATION AND INSTALLATION CONSIDERATIONS Thedistributionpanels and injection nozzles are located near the cyclone inlet ducts. The injectionnozzlespenetrate and mountto thecyclone inletducts. The nozzles are used to inject ammonia into the duct, while distributingthe ammonia across as much as the duct as practical. This locationprovides an areaofhigh velocity and narrow duct width to allow for goodpenetration and mixingofthe ammoniawiththe flue gas. The ammonia is sprayed upstream ofthe cycloneson the CFB. Thecyclones promote further mixing ofthe ammonia and the flue gas because offlue gas cyclonic action, direction change, and mixing. Higherreduction rates are achievable on CFBsthan for BFBs, andotherboilertypesbecause ofthis optimum spraylocation andcyclonic mixing. While it maybepossibleto capture more NOxona CFB, the standard guaranteed reduction rates are in the 50%range in orderto limit slip to lO ppm. TIME FOR COMPLIANCE An SNCRsystemcould be installed within 16-24 weeks. A maximum 2 week outage would berequired to make tie-ins. CAPITAL COSTS AND DOWNTIME There are twoboilers at YELP. A commonammonia systemtank and delivery systemwill beutilized for bothboilers. The ammoniatank and forwarding system is the bulk ofthe costfor supplyand installation. The rest ofthe systemconsists of supply and installation ofsmall borepiping, distribution skids, and injection

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## NOx Control Economic metso 

## Evaluation (YELP)
Date ofReport Feb 2011 Project 

### #710068

nozzles. The majorityofthe pipingis installed for the SNCRfor the first unit. The pipe for the second unit branches offat the upper elevation for distribution of ammoniato the second unit. There is a minimal incremental cost for the equipment and installation ofSNCRtechnology for the second unit because ofthis. The incremental costis limited to installation ofsome smallborepiping, a control valve, two additional distributionpanels, tubing, and nozzles into the cyclones. The installed estimate for the SNCRsystem is $880,000. This is the installed costfor SNCRtechnology for NOx control for bothunits. Controltechnologies are often evaluatedbased on$/kwbasis. The gross electricalgenerationfor eachboileris 32.5 MW. Theestimated cost for SNCRcapital costs (supply and installation) is $14/kw. The tie- in canbemade duringthe normal annual outage. Themajority ofthe systemcanbe installed withboilers on-line. Thenozzles wouldbe installedduring the annual outage. OPERATING AND MAINTENANCE CONSIDERATIONS The O&M costs are estimatedto be approximately $220,000perunit. Most ofthis is the cost ofthe ammonia. Ammoniaconsumptionis $203,000perunitbased on $196/deliveredton. Maintenance ofthe ammonia system and nozzles should average $10,000-15,000 for eachunit. OTHER NON-ENVIRONMENTAL IMPACTS SNCRs are the primarymethod ofNOx control on the majorityofCFBsand no problems have been noted. Metso has not observed nor is aware ofany increased fouling, decreased pressurepart life, orotherissues associated withthe use of SNCRs. 

## Selective catalytic reduction system (SCR) SYSTEM DESCRIPTION: An SCRis an array ofcatalyst installed in an existing ductorin a dedicated enclosure. Ammoniais injectedupstream ofthe catalyst. The catalyst enhances the reaction rate between the ammonia and the NOx, thus high captureefficiencies can be attained. The temperaturerange for properoperation ofan SCRis between480F to 800F. The optimumoperationofan SCRdepends on straight, uniform, and optimumflue 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, especiallyon smaller units, optimumconditions do not exist without significant capitalmodifications.

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## NOx Control Economic 

## metso Evaluation (YELP)
Date ofReport Feb 2011 Project

### # 710068

Installation ofan SCRin a low dust flue gas streams is oftennot practical, especiallyonan existingboiler. The reason isthatthe low dustportion ofa flue gas stream is located after abaghouseoraprecipitator. Thetemperature ofthe flue gas stream is too low in these areas for proper operation ofan SCR. Manyofthe CFBs in the United States have baghouses for particulatecontroL Thenonnal maximum allowable temperature for abaghouse is400F. This is still too lowfor the operation ofan SCR. Therefore, onsome installations, a regenerative SCRis installed. Regenerative SCRs are expensiveto install and expensiveto operatebecause an RSCRrequires the use ofburners to heat up the flue gas stream in orderfor the NOx captureto occur. This is oftenan efficiencydecrease for the boiler, significant increase in operatingcost, and oftennot apractical solution. Forthis reason, Metso did not evaluate the use ofan RSCR. Metso evaluated the use ofa high dust SCRfor this installationbasedonthe above information. A vaporizer in the ammonia delivery system is required for an SCRto injectthe ammonia in gaseous form. LOCATION AND INSTALLATION CONSIDERATIONS The temperature range for properoperation ofan SCRis between480F to 800F. As canbe seen from the general arrangements drawings there are two locations that couldbe utilized for the currentconfiguration. Neitherofthese two locations have flue gas temperatures in the range listed above. One possible solution is presented. However, the solution will be costlyto implement and is not an ideal location for an SCR. Metso believes that a maximum NOx reductionrate of80% wouldbe the recommended target for an SCRatthis facility. CFO modelingand physical modeling, as well as a detailed assessment ofcatalyst life would need to be performedbefore anyguarantees could 

### be presented. An assumption of80%NOx reduction wasused as abasis for capital and O&Mcosts. The two available locations considered were: 1. Upstream ofeconomizer 2. Betweenthe economizer andthe baghouse. 

### Upstream ofthe economizer­ Thetemperature upstream ofthe economizeris between 800-880F. This is too high for theproper operation ofan SCR. 

### Between economizerand 

### baghouse­ The temperature downstream ofthe economizer is 350F, which is too low for effective operation ofan SCR.

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## NOx Control Economic 

## )metso Evaluation (YELP)
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### Possible Solution Onepossibleoption is to splittheeconomizer since it is constructed in two assemblies with ajumperpipe betweenthe two. Thepredictedtemperature in this area is in the range of550F. The lowerbank ofthe economizer and the ash hopper couldbe lowereddownapproximately 25 ft. This would allow for the installationof2 levels ofcatalystwithinthe duct with a spraygrid array above the catalysts. Thepractical limit for SCRs in high dust, in-duct installations, approaches 80%. To meetthis level ofreduction for eachoftheseunits would require two layers ofcatalyst. While not completely investigated, it maybepossible, butwill be challengingto install two layers ofcatalystin this location. Obtaining evenly distributed flue gas at optimumvelocities in this area is thechallenge. TIME FOR COMPLIANCE The nonnalleadtime for an SCRis 16-24 months, with anadditional 2 monthsto make the necessary modifications andtie-ins. CAPITAL COSTS AND DOWNTIME The engineering and supplyestimatefor the SCRis $4,000,000-5,000,000 for each boiler. The area where modifications are required is quite congested. There is uncertainty in the installation estimatedue to significantmechanical modifications required at the site. Rigging, ductworkmodifications, and installation ofthe SCRwill be a challenge. The Harris Group Inc. has estimatedthe installationcosts to range between $6,100,000 and $9,100,000 for each SCR. The total installed estimated for an SCRsolutionfor eachunit is between $11,000,000 and $14,000,000. This equates to a range of$338/kw (gross electric) and $431/kw (gross electric) perunit. Theestimated gross electrical generation is 32.5 MWperboiler. Thetotal installed cost for two SCRs, one for eachunit, is between $22,000,000 and $28,000,000. There wouldbe minimal savings realized from duplicate units, since the majorityofthe cost is equipmentcosts and installationcosts. Significant mechanical modifications willberequired. A 2-3 monthoutagewould berequired to make the necessary modifications and tie-ins. Thecostoflost generation has notbeen estimated since Metso does not know the loadprofile and power sales rate structure.

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## NOx Control Economic


## , )metso Evaluation (YELP)
Dale ofReport Feb 2011 Project#710068

OPERATING AND MAINTENANCE CONSIDERATIONS (O&Mcosts are for eachunit, there are two units at YELP

- multiply bytwo for plant yearlycosts) The O&M costs areexpectedto be approximately $620,000 perunit for the SCR whencatalystcosts and installation are factored in. CatalystMaintenance costsfor the SCRare expectedto annually average $430,000 for eachunit. Theseestimates are based ontypical catalyst life. Thecosts are likely lowbecause ofthe higher potential for catalyst poisoning resulting from the presenceofvanadiuminthe flue gas stream. Vanadiumhas been shownto poisoncatalysts. Catalystpoisoning wouldcause difficultyin maintainingcompliance. Unit availability andrevenues will likelydecreasebecauseofcatalyst maintenance events. It is recommended that a detailedreview oftube fouling andcatalystfouling potentialbeperformedpriorto selectingSCRtechnology as a method ofNOxcontrol onthis unit. Maintenanceofthe SCRand catalyst will alsobe difficult dueto limitedworking area. Theperformanceandthereliability ofthe SCRcouldbe compromisedfor various reasons including limited straight duct above the SCR. Ideally, anSCR shouldhave additional space available for the future addition ofanother layer of catalyst. Because oflimited available room, only two layers ofcatalystcan be installed. There is notenoughroom for the future addition ofthe third layer of catalyst. This additional expansion slot (third layer) wouldprovidemore performance flexibility as well as reduce the outage time for catalyst replacement. In most installations, new catalystcanbe installed inthe thirdrow whilethe exhausted catalyst is being removed from one ofthe two in-servicerows. In this installation, it is likelythat onerow ofcatalystwill have tobe removed completely andthen fresh catalystwillbe installed in its place. This will cause moreunit downtime, which translates into less availability and a decrease in revenue. Petroleum fired cokeunits oftenhave fouling that occurs on superheater surfaces upstream ofwherethis SCRis tobe located. It hasbeen shownonotherpetroleum coke fired units thatthe debris from fouled tubes have brokenloose andpluggedup airheatertubes downstream ofthe superheaters. It is likelythatdeposits on superheaters, which are knownto exist at YELP willbreak loose and foul an SCR downstream ofthis superheaterbundles. This could significantly increasethe maintenance costs for the SCR. 

### An SCR also introduces additional pressure drop inthe system. A 4"pressure drop translates into $70,000 peryear at $.06/kw. This is a perunit cost. The ammoniausage is less for an SCRthan an SNCR. Thepredicted ammonia consumption will add $105,000to the operating costs for eachboiler.

Metso Power© 2011LO (12) 

## NOx Control Economic metso 

## Evaluation (YELP)
Date ofReport Feb 201 L Project # 710068

OTHER NON..ENVIRONMENTAL IMPACTS SCRs can contribute to airheaterfouling due to ammoniabisulfate formation. Airheater fouling could reduce unitefficiency, increase flue gas velocities in the airheater, cause corrosion, and erosion. Onsome installations, catalyst life is very short and SCRshave fouled in high dust environments. This had led to downtime onother units within the fleet in overseas installations. A detailed assessment ofcatalystlife costwould require further analysisbya catalyst vendor. Thepresence ofvanadiumin the fuel has led to reduced catalyst life onpriorunits. In summary, Metso does notbelieve that SCRtechnology wouldbe the most practical solution for NOxreduction atthis facility because ofthe many likely operatingand maintenance issues presented above. SNCRtechnology is proven and is capable ofat least 50%reduction ofNOx emissions.

Metso Power© 201 LTABLE 1: SummaryTable ofAssessment of NOx Control Economic Evaluation Yellowstone Billings

Cost ofcompliance

Time necessaryfor compliance Energy and non-airquality environmental impacts of compliance

Remaining useful life ofaffected source Eng and Supply Installation Total installed costs

OtherCapital Costs 10 fan upgrade IU&M(avg yeany) toreacn Unit
- sutltotal otcosts tlelOw Ammonia svs maint sootblower SCR catalyst Catalyst install SCR disposal additional pressure drop Ammonia cost (each unit) SUDDlv and install unitdowntime, loss of revenue ash resale problems fouling $Iyr $Ivr $Ivr $Iyr $Iyr $Iyr $/yr $/yr capital and installfor SCR Cost Range (each boiler) SNCR is for both units 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 SNGRcostaDove SCR Costs are foreach ofthe two units forboth units combined Allcosts belowareperunit 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

2week outage lost revenue for2 month outage none observed unknown not expected airheaterfouling
24 24

SCR Installation orderofmagnitude estimates by Harris Group Inc.

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### Harris Group Inc.

February 21, 2011

Mr. Scott Siddoway Rosebud Operating Services, Inc. 1087 W. River Street, Suite 200 Boise, ID 83702
ViaE-mail: scott.siddoway@rosi-boise.com Reference: MontanaPowerPlants Review ofEconomicEvaluation ofNOs ControlatYELPand CELP HarrisGroupInc. ProjectNo. 65353 DearScott, Harris Group Inc. (HGI) has reviewed tworeports preparedby Metso titled "EconomicEvaluation of NOxControl; ColstripEnergy LimitedPartnership" and "EconomicEvaluationofNOxControl; Yellowstone EnergyLimitedPartnership"per yourrequest. The reports are based on a general review ofthe twomost common technologies forNOx control in powerboilers: SelectiveNonCatalyticReduction (SNCR) and SelectiveCatalytic Reduction (SCR) with a briefpresentation on how to implement each technology in each boiler. The reportspresentrough orderofmagnitude equipmentcosts, installation costs, and operating and maintenance costs for each technology. The total installed cost for SNCR ($880,000) is in the expectedrange compared to similar installations thatwe are familiar with. Operating costs are by far the greatest expensewith the costof the reagentbeing about93%ofannual operatingcost. Metso'sestimate ofannual operating cost appears to be inthe right range. However, the reagentcost is directly affected by the cost ofnatural gas and will have a tendency to fluctuate quickly when natural gaspriceschange. The application of SNCRoncirculating fluid bedboilers (CFB) is wide spreadtoday as an effective technology for NOx control; however, the technology is limited to about 50%removal. The installed costs for SCRappearto be on the low side considering the degree ofdifficulty associatedwith the installation on theboilers atthese two facilities. The space inside the boiler buildings around the economizers is very limitedand working space outside thebuilding atYELP is extremely limited. This makes the engineering design and installation for a retrofitproject considerablymore difficultthan a new installation ofthe same size andremoval efficiency. Basedon the equipmentcostprovidedby Metso, HGI'srough orderofmagnitude installed cost for SCRat YELP is between $11,000,000 and $14,000,000perboiler. The installed cost at CELP is slightly less at $10,500,000 to $13,000,000. This cost range includes upgradingorreplacing the existingID fans and supporting equipmentas it is mostly likely required to overcome the increased flue gaspressure drop through the SCR catalyst. The largestpartofthe operating costfor SCR is the catalyst replacementcost and because there is limited experience with these fuels and CFBs retrofitted with SCRthese costs couldbe considerable more than indicated in the reports due to fouling and plugging ofthe catalyst.

; i!· ;,1Mr. Scott Siddoway Rosebud Opemting Services, Inc. Re: MontanaPowerPlants

- Review ofEconomic Evaluation ofNOxControl at YELP and CELP February 21, 2011 Page 2

There is not an extensive list ofcirculating fluid bedboilers that have beenretrofitted with SCRtechnology in NorthAmerica. Becauseofthis fact coupled with the unique fuel burned at eachofthe plants, installation ofSCRis notrecommended. Ifforced to install the technology, anextensive research effortis recommended includingtest burningthe fuels with atest catalystto help determine effectiveness, fouling andpluggingpotential, and catalyst life expectancy. Ifyou have any questions and need additional informationplease call me at 303 223-6726. Sincerely, HARRIS GROUPINC.

StevenD. McCormick ProjectManager SDM:smk

cc: R. D. Wankner ProjectFile

65353\docs\Siddoway-ROSI

_022111.docxYELP 

### Nox Control CostSummary

NOx Control Option % Control Total Capital Investment TotalAnnual 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 $589,938 198 198 Average Annual AfterControl Cost Effectiveness ($lton) $ 18,309.29
$ 2,981.37YELP 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 NOllemitted/yesr NOx (Ibslllr): Tonsof NQX controlled' fJ NOJ( = NO. (Ibslhr): Tons NOllemittedlyesf Tons NOllfeducedlyaar 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 SCRcatalyst•....,boM,s Cotalyslnotal

....., boMrs SCRdisposal

. ...., boMrs Di"ect annual costs

Capilal recoverylador

Ind.ect annual 0051s

Total annual cost

Average of2008 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"""don**Contr~** EstlmalB

o•• 526.0 MM8tuItIi 

# -

....... .. ,8IIe IlfJiO:t" 

### •.•""'*"'­ SHCR_""'*"'

.......... O,151b1W8u CFPu,MT •.02 NO.,,. '" ....NO!<'""'" 

# _,""",01­

;I _/-.oIllHCR

__ .. __**CF~'** 1.• Cool

# 01_
CoItBLC '" a.Of! fJkWh 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,.'"

IndirectAnnual Costs (twoYAts) 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 gfNe, lKIgxMrpI!od" 90_ 394.7fJ tor. A""".ot2008 A'Id 2009 NollfDnI from

.....smIM10n lIwenb'y

'IND!t = OO%""'*"'_ A5.'SlbI/IY 

## """0-"**T0fI6Noxe~ar** "7.9 kJrII TOfIlJNoKreduestVytJBr 197.''''

CgttEnoot!YftM!I,$/too,

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

# I ""iIIIN»1 

# _2002 EPA PPII&.Itmeo.e..e.-al

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## .....

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IWetence " Figtln 1,8YELP SOx

### C ost

### Summary
Mnual Annua/ EmIHlOll Eml

..101lll Total Capital TotalAnnual RBduc:tlOll AItIIrControl AverageMnua/Cost SO.Control Option 0/0Control 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 $6onYELP S02 CostAnalysis CostforHydratedAshReinjection Estlm_ usingOAQPS uample100 AddGaollem""'" Based on methodologydesai>ed in EPA Pollution CostCmlrolManual. 6Ih Edlioo January 2002 Section 5.2, Chapter 1 WetScrubbersfa< Acid Gas Removal

Cootbm Factor Coot CostMem Coot DIRECTCOSTS

Purchased _ipment OOSIS Number01 hydllll&d ash Sys1&msrequired: Plent mW, pel' -.. (Gross) Cost persystem + aUJOliary equipment (Bison Estimate)·: Total FOA +a"-ryequiIlm&nt lns1J'UmBntabOn Sales_ Freight

Putt

_ _ .........COS4 PEC 8=uaA
onetinstallationcosts 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_liDnCOSIb:/udingReIJ'01llFoetor: Sita preparaton As required, estimate Buildings As required. Estimate. Tot.l0Ir0ctCost. DC 1.30 8 + SP+ 81dg. INPIRECT COSTSOn",!ltiqn) Engineering 0.108 Construction .,dfield expenses 0.108 Coolractorfees 0.108 Stan-up om 8
pertormence !&St om 8 Contingencies 0.03 8

TOIoIlndhclC004 IC 0.35B ToW_I Cool01Requ/AdElaghous. (s

.. bev/l- ceIQ): TOTALCAPITAL

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

Notes: A 0.10A O.03A O.OSA DIRECTANNUAL 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 INDIIlECTANNUAl. COSTS !C $8.040.373 Ovemead 60% ofsum ofoperating labor and materialsand $25,000 maintenance\abor and materials. $50,000 Administrative Cherges 2% ofTCI PropertyTexes 1% ofTel 517.29"707 Insutllnca 1% ofTCI Capital Recovery Fector (Annualized Capital Cost. 10 y'"el 10%) TOTALANNUAL COST (tIAR) $61a,133 TOTALANNUAL COST FROM BAGHOUSl!(S}, sa1a,133 TOTALANNUAL 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 ofSSM for a 15 MW planl 0.5 hrslsl1ift 30.00 $/hr t5% ofoperator 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 IYELP 502e- AnalJsis CoststorSpny Dry_

... 

# e_....... OAQPS 0_ GeeRem""

.. Based an methOdOJCgydesoJbedin EPAPoauIXJo CostComroI Manual. 6ttl Editicn Jonuary2l102 Sedian 5.2, Chapter1 WetScrubbersforAcid Gas Removal
Costhem 1'_ Cost Cost

..... C_ DRkfkOJfS DIRECT ANNUAl...COSlS.

Purtnas&d oosls NumberdSDA $)$ferns required'

__.... _(Groosl 2 32.5 SDACostperkW:­ 150 CostPI' $ys:lem + llUXiial"yequipment: ToI8I + BUXNry equipment In:stnm8fMtion Sales

..... 

# F_ A Q,10A 0-03A $4,875,000 $9.7SO,OOO

$975,000 $292,500.00 Operatngl..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........
-.dOnga_ 0-'2B 0.40B $1.38J.600 $4,502.000 SOll. to be controued (tonS) Ratio ofsorbantto SOx: Lime n9Quired: 6me cost**($/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 030B $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 (% ofEhtC1riclal GeneratIOn): 1,75% Median atvalues, Source:**htfpjlwrMv.,.lcomobotec.c:omItechnolOgyfdt'y.sorbent-t~on** html 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_DIroctl»s\DC '.30 B + SP + Bldg. $20,293,025 INDIRECT ANIIIJAL COSTS, IC INOIRECT COSTS llns!!!ll!ionl Ov"",oad 60% of sumd operatinglabor&ncI materials and $30,6'8**~ng** 0,10 B $1.150.500 maintenance IIbOrand materiels. Con6truction andfield 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, 10yta at 10%) $4,60U'3 Contingenties

__**C08~1C** 0.03B 0-35B 5345,1SO ko2i;nG TOTAL ANNUAL COST (SOA): TOTAL ANNUAL COST FJlOllBAClHOUSE<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.tIn $lJl,W from EPAAi PoUution Control Filet SheetforFGO. 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 S02CostAnalysis CDststrw DrySol1lentInjection

_ using OAQPSuampleforAdd Gu R

...ovaI BasedCIl l1l8IIIod<logydesai>o<l in EPA Coso Cor4roI Manual, 6Ih Edi"'" January2002

-. 5.2, Chllpla< 1Wei Scrubbersfer Acid GasRerrowBI Cootltam Foetor Cost Cost'em Cost \)IRECTCOSTS DIRECT ANNUAL COSTS

__"""",tCOSlS Number ofhy<lrlOed ash systemsrequir8d: 2
-.. mil.perboier(Gross) 32.5 Costpersystem+ 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% ofoperator $2,430 SaIoslaxas 0.03A 597.500,00 Freight O,OSA $'62.500 Oporoling_erials

__ipmenrcost PEe 8: 1,1SA 53,835,0ll0 SOxto 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 0,408 $1.534.000 Hmo cost ($ItCIl): $100 estimem El8l:tricaI 0,01 8 $38.350 limecost($!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 SlIep<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 INDIRECTCOSTS l!nJt!I!l!I!onl Ovelhoad 60% d sum ofoperatingtabor andmalfrilltsand S30.618 EngWleering 0,108 $383.500 maintenanceleba' and materiMl. CCI1tnI

__ Coosbuc1lCll and lald axpen
... 0.108 5383.500 AcllTinistrlllUve Charges 2% orTCI 518!l.799 0,108 $383.500 propertyTaxes I'll, ofTCI $94.899 SIBrt"'P 0.018 $38.350 Insurance 1% ofTCI $94,899 ParJon'nWlcelesl 0,0' B $38.350 CopRa' Rocovory Faclor (Annualized CoplIaI Cosl. 10 yrs0110%) $1,544,442 Ccntingantias 0.03B 5115.050 TOTAL ANNIJAL COST (tISl); 51.",­

rolOl

..

# _rCOst 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 5of 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 vendorestimatefor 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 = 389.5 556.4YELP Replacement ofBaghousefor SOx Controls

Total CapitalCostsforFabric FillerBaghouse with Fiberglass Bags _"""",OAQPS Control

# Cos._ FI1\h Edlloo. Chapter5**(Oe~** 19951 and associeted COST,AIR spreadsheet

S S

$8,751, C<>stC_

;ed EquipmentCosls BaghousesNeeded Capital CostperscIm:' SCFM: Costper Bag,ouse (estimate): Total EquipmentCosts lns1JlJtn<nlation EquipmentTax: Freioht

_ EquipmentCost 1ns1slla_COOls f<lI.ndation andSuppor1s HllfldIing end Erection Eleclrical Piping lnsuIationfor

# Du_
Painting Dir8cllnslallation Costs RetrofilFaclor: : _tion Costs Induding Rerofil Fador

ita Preplntion atihasand Buildings T_DIrect Costa IlilJi!lIIl Engineering Cons1Juction and Field Expenses Conlr8c1or Fees Stan-up Performance Test Continoencies Tobll_ctCosta '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 TotalAnnualCosts
Reference: OAOPS Control Cost Manual Fifth Edition. Chapter 5 (December 1998)

Cost Comoonenl DirectAnnual 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 hrlshiftx 3 shifts/dayx 365 days/yf x $3O.oo/hr $65.700 15%01 operator**$9,~**

I hrtshiflx 3 shifts/day x 365 deys/yfx $3O.00"'r 

## $32:: $32. I00% of Mainl8llance Labor (Futu", worth at 3 years end 10%=0.4021"cosl01 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% ofTotal Cepiiallnvestment $107,35.1 al 10%for 10veers (0.16275 x Total Cepilallnvestmenl) $1.7'47,151 TotsllC $2,261,311
obll Annual Cost S Sum ofTotal 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 ModelingReport Visibility Impacts: MandatoryClass 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 ofthe 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 ofpreventing 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-1quite 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 ofthe 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 8-3The 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 8-53.3.2 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 6-63.3.3 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 CALMET Technical Options IThe CALMET 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 ofAugust 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 ofthe 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-8The 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 ., PM 10 (Ibs/hr)

2.3 PM 2.5 (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 VISIBILITYASSESSMENT 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 BG I 11/15/2010 Section 114 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 

### o 176
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-11if 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 ofthe 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 O 80 North Absaroka
---- -- . 0_.2_9_4

.... i-- 

# °

..214----_- f-- _.__ [ 0 125 

# I**Ga~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-12I 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