Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 1 Reasonable Progress (RP) Four-Factor Analysis of Control Options For Platte River Power Authority – Rawhide Energy Station

I. Source Description

Owner/Operator: Platte River Power Authority Source Type: Electric Util ity Steam Generating Unit SCC (EGU): 1010026 Boiler Type: Pulverized Coal Dry-Bottom Tangentially-Fired

The Platte River Power Authority (PRPA) Rawhide Energy Station is located in Larimer County approximately 10 miles north of the town of Wellington, Colorado. The Rawhide Energy Station consists of one coal fired steam driven electric generating unit (Unit 101), with a rated electric generating capacity of 305 MW (gross), and was placed into service in 1984. The boiler is equipped with a fabric filter (baghouse) system fo r controlling particulat e matter (PM) emissions, and a lime spray dry absorber controls sulfur dioxide (SO 2 ). The boiler is equipped with low nitrogen oxide (NO x ) concentric firing system (LNCFS) burners with separated overfire air (SOFA) configuration for minimization of NO x emissions, installed in 2005.

The Rawhide Station also has five natural-gas fi red combustion turbines, designed to operate in a simple cycle mode, four rated at a heat i nput of 831.1 MMBtu/hour (approximately 82 MW) and one rated at a heat input of 1,400 MMBtu/hour (about 150 MW). Each turbine is equipped with integral dry low NO x combustion systems and inlet air f og cooling systems and startup and shutdown duration average NO x and CO emission limits determined to be Best Available Control Technology (BACT) 1 since each turbine is subject to Pr evention of Significant Deterioration (PSD) provisions. These turbines were placed in to service starting in May 2002, with the last turbine (150 MW) started up in June 2008. The primary use of these uni ts is to meet Platte River’s energy reliability and peak load requirements. The turbines operate on limited, intermittent, and unpredictable schedules as peak loading units. Additionally, the facility includes a number of fugitive dust sources. PRPA has prepared a R easonable Progress (RP) analysis as well as supplemental information which can be found in “PRPA RP Submittals”.

For this analysis, the Division also relied on th e existing Title V permit, historical information regarding the Rawhide facility, a nd information about similar faci lities to determine RP for PM 10 and SO 2 (available in the TSD). EPA’s BART guidelines recommend that states utilize a five step process for determining BART for EGU sources above 750 MW. Although this five step process is not required for making Reasonable Progress (RP) determinations, the Division has elected to largely follow it in RP. This is for ease of refe rence, and because the statutory factors that must considered in making BART and RP de terminations are largely the same.

For the purposes of evaluating RP, the Division has elected to set de minimis thresholds for any emission unit at a subject-to-RP source with actual baseline emissions of SO 2 , NO x , or PM 10 equal

1 Colorado Air Pollution Control Division, 2004. Colorado Operating Permit 03OPLR261: Rawhide Energy Station. Section II: Condition 1.7, pages 10 – 13.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 2 to or exceeding the federal Prev ention of Significant De terioration (PSD) signi ficance levels. The Division has established de minimis thresholds for SO 2 , NO x and PM 10 to focus the technical emission control analysis on signifi cant emission sources where poten tial controls could provide a meaningful improvement in visibility if emission controls are determined to be cost effective.

The de minimis levels are applicable to individual emi ssion units at a stationary source. The Division defines “emissions unit” as “any part or activity of a stati onary source that emits or has the potential to emit any air polluta nt regulated under the state or Federal Acts. This term is not meant to alter or affect the definition of the term “unit” for purposes of Title IV (acid deposition control) of the federal act, or of the term “source” for purposes of the Air Pollutant Emission Notice requirements of Regulation Nu mber 3, Part A, Section II.B.3. 2 .” These de minimis levels are as follows:

• NO x – 40 tons per year

• SO 2 – 40 tons per year

• PM 10 – 15 tons per year

Emissions Unit P301 serves as a detailed example of evaluating one “unit” in Table 1. As the PM10 emissions from emissions unit P301 are below the de minimis level of 15 tons per year, it is exempted from any further analysis under RP.

Table 1: Unit Detail Example for de minimis Threshold

Unit P301 Breakdown 2006 – 2008 Average PM 10 Emissions (Baseline Actual Emissions) Solid Wastes Silo Rotary Unloader Discharge 0.41 Solid Wastes Hauling to Landfill 1.64 Solid Wastes Haul Truck Unloading 0.02 Active/Exposed Landfill Area 0.21 Waste Landfilling/Reclamation 0.39 Bottom Ash Excavation and Loading 0.02 Solid Wastes Silo Filling 0.00 Solids Vacuum Conveying System and Silo Filling 0.17 Fly Ash and Solid Waste Silo Dry Unloading and Haul Truck Loading 0.02 Unit P301 Baseline PM 10 Emissions 3.01 << 15 (PSD threshold)

Rawhide Unit 101 is considered by the Division to be eligible for the purposes of Reasonable Progress, being an industrial boiler with the pote ntial to emit 40 tons or more of haze forming pollution (NO x , SO 2 , PM 10 ) at a facility with a Q/d impact greater than 20. PRPA submitted a “Rawhide NOx Reduction Study” on January 22, 2009 as well as additional relevant information on May 5 and 6, 2010. Table 2 depicts tech nical information for Rawhide Unit 101.

2 Colorado Department of Public Health and Environm ent. Air Quality Control Commission Common Provisions Regulation 5 CCR 1001-2. Amended December 17, 2009. Effective January 30, 2010. Page 19.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 3 Table 2: Rawhide Unit 101 RP-eligible Emission Controls and Reduction (%) Rawhide Unit 101 Placed in Service 1984 Boiler Rating, MMBtu/Hr for coal 3,000 Electrical Power Rating, Gross Megawatts 305

Description Combustion Engineering tangentially fired, dry bottom steam generator/boiler firing pulverized coal.

Air Pollution Control Equipment Fabric Filter (baghouse) for PM/PM 10 control Spray Dryer Removal System for SO 2 control

Special Features Low NO x Concentric Firing System (LNCFS) with separated overfire air (SOFA) installed in 2005

Emissions Reduction (%) 1 NO x – 49.6% SO 2 – 83.1% PM/PM 10 – 99.2/96.7%

1 Emissions Reduction estimated by comparing uncontrolled AP-42 factor to actual average emission factor for PM/PM 10 . For SO 2 estimates, CAMD data (average of 2006 – 2008) was used to calculate reduction %. The NO x reduction is based on actual data from pre-2005 actual emissions. See “Rawhide APCD Technical Analysis” for further details. Not based on actual testing.

For the boiler, the Voluntary Emissions Reduction Agreement (VERA) permit limit for NO x is 0.180 lbs/MMBtu on an annual average effective July 15, 2006. The Acid Rain permit limit for NO x is currently 0.40 lbs/MMBtu on an annua l average and the PSD /NSPS limit is 0.50 lbs/MMBtu on a 30-day rolling average.

In October of 2005, PRPA installed a low NO x Concentric Firing System (LNCFS) with separated overfire air (SOFA) on Unit 101 that resulted in an approximate 50% reduction of NO x emissions (from pre-2005 actual emissions) in accordance with the Voluntary Emissions Reduction Agreement entered into with the State of Colorado in 2002 3

. Rawhide Unit 101 was initially installed in 1984 with a baghouse for particulate emission (PM/PM 10 ) control, with contro l efficiency exceeding 99.9%. Th is system was BACT at the time of initial startup and is still considered BACT currently.

The “Spray Dryer Removal System” for Unit 101 wa s considered a new control technology at the time of installation in 1984 and started up at the same time as Rawhide Unit 101. This system originally reduced SO 2 emissions by approximately 80% and 0.13 lbs/MMBtu (30-day rolling average) (from AP-42 emission cal culations) according to Federal PSD emission standards at that time (0.2 lbs/MMBtu annually). In 2003, PRPA en tered into a Voluntary Emissions Reduction Agreement with the State of Colorado to reduce SO 2 emissions to 0.09 lbs/MMBtu (annual

3 Colorado Air Pollution Control Division, 1992. Exhibit A: Division Evaluation of Nitrogen Oxides Emission Limitation and Regulatory Assurance Periods.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 4 average) by upgrading the lime spray dryer system 4 . This upgraded system resulted in an approximate 30% emission rate reduction of SO 2 emissions from pre-VERA emission rates.

II. Source Emissions

Table 3 summarizes the NO x , SO 2 , and PM 10 actual emissions averaged over the 2006 – 2008 baseline timeframe from EPA’s CAMD Database for the facility. Table 4 summarizes each unit at the facility and applicable NO x , SO 2 , and PM 10 actual emissions averaged over the 2006 – 2008 timeframe with data from Colorado’s APEN’s submitted by the facility and as applicable, EPA’s CAMD Database (primarily for th e Unit 101 boiler and the turbines).

Table 3. Summary of 2006 - 2008 Aver aged Emissions - PRPA Rawhide Facility NO x (tons/year) SO 2 (tons/year) PM 10 (tons/year) 1,885 914 125

Table 4. Summary of 2006 - 2008 Averaged Emissions by Unit - PRPA Rawhide Facility

Unit Pollutant 2006 2007 2008 2006 - 2008 average*

Unit 101 Boiler SO 2 (tons) 943 928 869 913 SO 2 (lb/ MMBtu) 0.078 0.081 0.078 0.081 NO x (tons) 1,990 1,863 1,745 1,866 NO x (lb/ MMBtu) 0.163 0.162 0.173 0.166 PM 10 (tons) 109 113 101 108 PM 10 (lb/ MMBtu) 0.018 0.017 0.018 0.018 Turbine Unit A (82 MW) SO 2 (tons) 0.10 0.12 0.12 0.11 NO x (tons) 1.17 5.45 0.75 2.46 PM 10 (tons) 0.20 1.12 0.13 0.48 Turbine Unit B (82 MW) SO 2 (tons) 0.09 0.06 0.11 0.09 NO x (tons) 3.87 3.17 5.07 4.04 PM 10 (tons) 0.77 0.58 0.99 0.78 Turbine Unit C (82 MW) SO 2 (tons) 0.04 0.09 0.03 0.05 NO x (tons) 2.03 4.45 1.65 2.71 PM 10 (tons) 0.33 0.80 0.30 0.48 Turbine Unit D (82 MW) SO 2 (tons) 0.05 0.10 0.03 0.06 NO x (tons) 2.53 4.95 1.50 2.99 PM 10 (tons) 0.45 0.85 0.26 0.52 Turbine Unit F (150 MW)** SO 2 (tons) 0.38 0.38 NO x (tons) 20.45 20.45 PM 10 (tons) 3.75 3.75 P201 Train Unloading Facility PM 10 (tons) 0.60 0.01 0.01 0.20 P201 Active Coal Pile Reclaim PM 10 (tons) 0.03 0.02 0.00 0.02 P201 Coal Silo Filling and

Conveyor Belt Transfer PM 10 (tons) 0.30 0.00 0.00 0.10 P201 Coal Silo Discharge to Conveyor Belt PM 10 (tons) 0.28 0.00 0.00 0.10 P201 Coal Crushing and PM 10 (tons) 0.33 0.02 0.02 0.12

4 Colorado Air Pollution Control Division, 1992. Exhibit B: Division Evaluation of Sulfur Dioxides Emission Limitation and Regulatory Assurance Periods.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 5 Conveying P201 Coal Conveyor Belt Transfer PM 10 (tons) 0.30 0.00 0.00 0.10 P201 In-Plant Silo Filling

Conveyor Belt Transfer PM 10 (tons) 0.30 0.00 0.00 0.10 P201 Coal Pile Stockout PM 10 (tons) 1.18 0.01 0.02 0.40 P201 Active Coal Storage Area PM 10 (tons) 0.93 1.91 1.96 1.60
P201 Active Coal Pile Storage Area PM 10 (tons) 0.95 2.56 2.56 2.02 P201 Coal Crusher Stockout PM 10 (tons) 0 0 0 0.00 P201 Coal Conveying PM 10 (tons) 1.81 1.23 1.09 1.38 P301 Solid Wastes Silo Rotary Unloader Discharge PM 10 (tons) 0.70 0.28 0.25 0.41 P301 Solid Wastes Hauling to Landfill PM 10 (tons) 1.82 1.67 1.44 1.64 P301 Solid Wastes Haul Truck Unloading PM 10 (tons) 0.04 0.02 0.01 0.02 P301 Active/Exposed Landfill Area PM 10 (tons) 0.19 0.24 0.19 0.21 P301 Waste Landfilling/Reclamation PM 10 (tons) 0.13 0.57 0.46 0.39 P301 Bottom Ash Excavation and Loading PM 10 (tons) 0.03 0.02 0.02 0.02 P301 Solid Wastes Silo Filling PM 10 (tons) 0.02 0.20 0.17 0.13 P301 Solids Vacuum Conveying System and Silo Filling PM 10 (tons) 0.17 0.18 0.16 0.17 P301 Fly Ash and Solid Waste Silo Dry Unloading and Haul Truck Loading PM 10 (tons) 0.02 0.02 0.01 0.02 P401 Scrubber Lime Storage Silo Filling PM 10 (tons) 0 0.01 0.01 0.00 P401 Recycle Ash Storage Silo Filling PM 10 (tons) 0.11 0.89 0.81 0.60 P501 Unpaved Site Roadways and Parking Lots PM 10 (tons) 3.14 3.92 4.23 3.76 P501 PRS Soda Ash Storage Silo Filling PM 10 (tons) 0 0 0 0.00 *The above emissions are for the most recent thr ee years (2006 – 2008). These emissions are an annual average. 30-day rolling averages for th e Unit 101 Boiler are estimated to be 5-15% higher than the annual average emission rate (i.e. the maximum 30-day NO x rolling average is likely about 0.190 lbs/MMBtu). **Note that Unit F did not start up until June of 2008; th erefore it was not operated in 2006 or 2007 and for only half of 2008.

Units italicized in Table 3 are less than de minimis thresholds and will not be evaluated further for the purposes of reasonable progress.

Each of the five turbines at Rawhide Stati on was installed with an advanced dry low-NO x combustion system that controls NO x emissions to less than 9 ppm @ 15% O 2 as well as a gas turbine inlet air fog cooling system designed fo r optimal power augmenta tion during hot weather operations. . Each turbine is subject to BACT under the PSD provisions. The turbines are alsoColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 6 required to use pipeline quality natural gas as de fined by the Acid Rain Provisions 40 CFR Part 72. The Title V permit enforces a compliance SO 2 emission factor of 0.0006 lb/MMBtu for each turbine. These combustion turbines are further evaluated within the source category “Combustion Turbines” in Section 8. 2.3 of the Regional Haze SIP.

III. Units Evaluated for Control

As documented by PRPA, Rawhide Unit 101 fires low sulfur, high heating value Power River Basin sub-bituminous coal. The specifications for the coal are liste d below in Table 5.

Table 5: Coal Specifi cations (2006 - 2008 Averaged APEN data) Specifications Emission Unit Fuel Heating Value (Btu/lb) Sulfur (% by weight) Ash (% by weight)

Rawhide Unit 101 8,853 0.24 5.42

Table 4 lists the units at Rawhide that the Divi sion examined for control to meet reasonable progress requirements. Controlled and uncontrolled emission factor s and APEN data were used to evaluate the control effectiveness of the current emission controls. Uncontrolled emission factors are outlined in Table 6.

Table 6: Uncontrolled emission factors for Rawhide Unit 101

Emission Unit Pollutant Fuel Coal (sub-bituminous) (lb/ton)

Rawhide Unit 101 5 NO x 7.2 SO 2 35 x %S = 8.5* PM/PM 10 PM – 54.2** PM 10 – 12.5 *%S = % of sulfur present in coal su pply. For example, 35 x 0.24 = 8.5 **%A = % of ash present in coal supp ly. For example, 10 x 5.42 = 54.2

IV. Reasonable Progress Evaluation of Unit 101

a. Sulfur Dioxide Step 1: Identify All Available Technologies

PRPA identified one SO 2 control option: Fuel Switching – Natural Gas or Colorado Coal The Division requested that PRPA evaluate the option below, and received relevant information for this request on May 5, 2010: Dry FGD upgrades As discussed in EPA’s BART Guidelines 6 , electric generating units (EGUs) with existing controls achieving removal efficiencies of grea ter than 50 percent are not required to remove these controls and replace them with new controls.

5 EPA AP-42, Fifth Edition, Volume I, Chapte r 1, Section 1.1, Tables 1.1-3 and 1.1-4. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdf

6 EPA, 2005. Federal Register, 40 CFR Part 51. Regional haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule. Pgs. 39133.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 7 However, upgrades need to be considered for the scrubber if technica lly feasible. These upgrades include: -Use of performance additives -Use of more reactive sorbent -Increase the pulveriza tion level of sorbent -Engineering redesign of atomizer or slurry injection system

Step 2: Eliminate Technically Infeasible Options

Fuel Switching – Natural Gas or Colorado Coal: The Division and PRPA both assert that the Unit 101 boiler at Rawhide could convert fuels from coal to natural gas with boiler modifications and natural gas pipeline construction. Convers ion from coal to natural gas would reduce SO 2 emissions by about 906 tons per year, or a pproximately 99% (using 2006 - 2008 CAMD data average) 7 . SO 2 emissions from coal combustion are affected by the chemical and physical properties of the feed coal. Feed coal characte ristics significantly affect the design and operation of combustion controls, such as the existing LNB+SOFA system. With the dry FGD – lime spray dryer system in place, Unit 101 currently achieves an emission rate of 0.07 lb/MMBtu (annual average).

PRPA notes that Unit 101 is designed to burn PRB coal and the boiler is additionally optimized through a technologically complex pr ocess to burn this coal at ve ry tightly controlled rate. PRPA has indicated that it is in feasible as well as economically impractical to change coal supplies. The sulfur content of the Rawhid e Unit 101 PRB coal supply is between 0.8 – 1.4 lb/MMBtu with most of the supply containi ng less than 1.2 lbs/MMBtu (based on northern Wyoming PRB coal mine reports). The average sulfur content in the coal is 0.29%. PRPA obtains coal for Rawhide Unit 101 from the Antelope Mine in Converse County, Wyoming, which has one of the lowest sulfur content of any mine in the county. PRPA additionally pays a premium to ensure higher Btu/lo wer sulfur coal. A review by the Colorado Geological Survey found that on average, Wyoming coal had similar sulfur content to Colorado coal 8 . Virtually all Colorado coal contains less than 1 percent sulfur and most of it co ntains less than half of that amount (0.5% or less) 9 . Therefore, the sulfur content of the Antelope Mine coal is similar, if not lower, than Colorado coal.

The Division has determined that fuel switchi ng to natural gas is te chnically feasible for Rawhide Unit 101. However, fuel switching to Colorado coal will not further reduce SO 2 emissions from Unit 101 and will not be considered further in this analysis.

Dry Flue Gas Desulfurization (FGD) Upgrades: Dry FGD systems are commonly known as spray dry absorbers (SDA), and currently make up about 12% of FGD systems at U.S. power

7 Colorado Air Pollution Control Division Technical Anal ysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 2010. See Appendix D of the SIP for detailed calculations.

8 Colorado Geological Survey: RockTalk. Vo lume One, Number Three. July 1998. http://geosurvey.state.co.us/pubs/rocktalk/rtv1n3.pdf

9 Colorado Geological Survey: RockTalk. Vo lume One, Number Three. July 1998. http://geosurvey.state.co.us/pubs/rocktalk/rtv1n3.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 8 plants 10 . SDA systems are typically utilized at smalle r units that burn lower-sulfur in the western U.S., where water resources are limited. A SDA system captures SO 2 by using a slaked lime containing slurry that is sprayed into the flue gas and reacts with the SO 2 to form calcium sulfate, and then is subsequently dried by the heat of the flue gas, and collected in a particulate control device.

Rawhide Unit 101 was installed in 1984 with a “Spray Dryer Removal System” in connection with the aforementioned baghouse for control of th e resultant SDA materials. At the time, the system was a new control technology for SO 2 removal from the gaseous emission stream of a utility boiler. PRPA has since upgraded this system (in 2002) and currently achieves greater than 80% SO 2 removal, with an actual annual average of 0.07 lb/MMBtu and a permit limit of 0.09 lb/MMBtu on an annual average basis, 0.13 lb/MMBtu on a 30-day average, and 0.19 lbs/MMBtu on a 3-hour rolling average. This sy stem exceeds EPA’s presumptive limits stated in 40 CFR part 51 Appendix Y of 0.15 lb/MMBtu 11 . Lime spray dryers have been determined to be Best Available Control Tec hnology (BACT) for new Electric Generating Unit (EGU) sources proposed in the West according to EPA’s RBL C (RACT/BACT/LAER Clearinghouse) database. The RBLC database lists recent BACT determ inations ranging from 0.06 – 0.167 lb/MMBtu, with an average of 0.11 lb/MMBtu on a 30-day ro lling average. Refer to Appendix D for more details regarding recent RBLC BACT determinations. Additionally, an EPA Report regarding the control of SO 2 emissions found that lime spray dryi ng processes have a range of design efficiencies from 70 – 96% and a median desi gn efficiency of 90%; however, application conditions may differ (e .g. coal sulfur percent) 12

.

PRPA submitted a SO 2 upgrade analysis to the Division on May 6, 2010 upon request regarding potential upgrades for the dry FGD scrubber sy stem. PRPA asserts that operating the SO2 scrubber at the 0.09 lbs/MMBtu VERA limit pushe s many of the scrubber’s material handling and slurry preparation sub-systems to the limits of their design capacity. As part of the VERA scrubber improvements, the recy cle ash pressure feeders were upgraded and the recycle ash conveying line was replaced with larger diamet er piping to increase th e recycle ash conveying capacity between the solids waste silo and recy cle ash storage bin/sil o. Moving beyond current levels of scrubber operation would require addi tional equipment upgrades and would reduce the existing redundancy in some critic al scrubber sub-systems. Specifi cally, the recycl e ash blowers, bin vent filter on recycle ash s ilo, feed slurry preparation pumps , and feed slurry tanks are all operating at maximum thr oughput levels or at the margin and would need to be replaced with larger capacity equipment. While there is usua lly available redundancy within the lime slaking sub-system, a lower SO 2 limit would diminish this available ca pacity and likely also require an upgrade to ensure adequate margin.

PRPA notes that the SO 2 scrubber has three atomizer reaction compartments that provide critical operating flexibility. The scrubber generally operates with all th ree compartments in-service,

10 Electric Power Research Institute: A Review of Literature Related to the Use of Spray Dryer Absorber Material – Production, Characterization, Utili zation Applications, Barriers, and Recommendations, Technical Report, September 2007. University of North Dakota: Energy & Environmental Research Center – Coal Ash Resources Research Consortium. 15 North 23 rd Street, Stop 9018. Grand Forks, ND, 58202. Pg. v.

11 Colorado Operating Permit 96OPLR142 pg. 5 – SO 2 30-day rolling average limit is 0.13 lb/MMBtu.

12 EPA, 2000. “Controlling SO 2 Emissions: A Review of Technologies.” Prepared by Ravi K. Srivastava for Office of Research and Development, Washington, D.C. 20460. Pg. 33.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 9 which provides maximum reaction/residence time, eases SO 2 removal equipment demands, and minimize pressure drop. Though not a desirable op erating mode, the scru bber is currently capable of operating at full load with only two atomizer compartm ents in-service. In addition to the improved scrubber performance, the curren t atomizer compartment redundancy provides critical atomizer operational and maintenance flexibility, ensuring environmental compliance, and providing for high SO 2 scrubber and unit availab ility. Achieving a lower SO 2 limit may compromise atomizer compartment redundancy, which will significantly diminish scrubber operational and maintenance flexibility. This loss of redundancy and flexib ility will li kely result in increase malfunctions and could also affect unit availability if load reduc tion is triggered.

Even with the potential scrubbe r equipment upgrades, additional SO 2 reductions will still present unacceptable operational challenges. SO 2 scrubbing is limited by scrubber outlet temperatures which must remain above the fluegas dew poi nt with an adequate margin to prevent condensation and catastrophic damage to the baghouse. Over-spraying below minimum SDA outlet temperatures also results in higher moisture ash in the baghouse that is difficult to convey from the collection hoppers.

Given existing spray-down temper ature constraints, reducing SO 2 emissions below 0.09 lbs/MMBtu requires additional lime to increase feed slurry reactivity. At higher SO 2 removal rates, the lime/SO 2 stoichiometry increases and more unr eacted lime is carried-over with the flyash and scrubber waste to the baghouse. The higher lime content in the flyash and scrubber waste affects the fluidity of th e material making it harder to pneumatically convey out of and between the baghouse hoppers, solid waste silo, and recycle ash storage bin/silo. Hopper bridging and conveying piping pl uggage are significant operational and maintenance issues impacting SO 2 scrubber reliability. Lowering the SO 2 emissions below the VERA limit will increase the potential for sc rubber and baghouse malfunctions.

PRPA examined BART-guideline dry scrubbing poten tial upgrades, with the following results:

-Use of performance additives : Performance additives are typically used with dry-sorbent injection systems, not semi-dry SDA scrubbers that spray slurry pr oducts. PRPA and the Division are not aware of SO 2 scrubber performance additives a pplicable to the Unit 101 SDA system. Therefore, this upgrade is not tech nically feasible for th e dry scrubbing system.

-Use of more reactive sorbent : Lime quality is critical to achieving the VERA emission limit. PRPA utilizes premium lime at higher cost to ensu re compliance with the VERA limit. The lime contract requires >92% reactiv ity (available calcium oxide) lime to ensure adequate scrubber performance. Therefore, this upgrade is not technical ly feasible for the dry scrubbing system.

-Increase the pulverization level of sorbent : The fineness of sorbents used in dry-sorbent injection systems is a consideration and may im prove performance for these types of scrubbers. Again, the Unit 101 SO 2 scrubber is a semi-dry SDA type scrubbe r that utilizes feed slurry that is primarily recycle-ash slurry with added lime sl urry. PRPA recently completed SDA lime slaking sub-system improvements are designed to improve the reactivity of the slaked lime-milk slurry. Therefore, this upgrade is not technically feasible for the dry scrubbing system.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 10 -Engineering redesign of atomizer or slurry injection system : The Unit 101 SDA scrubber utilizes atomizers for slurry injection. The sc rubber utilizes three reactor compartments, each with a single atomizer. PRPA maintains a spar e atomizer to ensure high scrubber availability. The atomizers utilize the most current wheel-n ozzle design. Therefore, this upgrade is not technically feasible for the dry scrubbing system.

The Division concludes that upgrades are not technically f easible for the Unit 101 Boiler.

Fuel switching to Colorado coal will not provi de further SO 2 emission reductions. Rawhide Unit 101 has a SDA system for which the State has determined that no upgrades are feasible. Therefore, the Division has conducted a four-fac tor analysis for reasonable progress for fuel switching to natura l gas regarding SO 2 reductions.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Fuel Switching – Natural Gas: Conversion from coal to natural gas would reduce SO 2 emissions by almost 100% from the boiler us ing EPA’s AP-42 emission factors 13 and concurs with PRPA’s submittal.

Table 7 summarizes each available technology options and technical feasibility for SO 2 control on Rawhide Unit 101.

Table 7: Rawhide Unit 101 SO2 Techno logy Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no) Wet FGD 52-98%, median 90% 14 Y – not evaluated Dry FGD 70 – 90% Y - installed DSI (Trona) 60-65% Y – not evaluated, will not provide further SO2 control Fuel switching – different coal type None Y – will not provide further SO2 control

Use of performance additives None N

Use of more reactive sorbent None N

Increase the pulveriza tion level of sorbent None N

Engineering redesign of atomizer or slurry injection system None N

Fuel switching – natural gas 99% (EPA AP-42) Y

Step 4: Evaluate Factors and Present Determination

13 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.4, Table 1.4-2. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdf

14 Srivastava, R.K. Controlling SO2 Emissions: A Review of Technologies. U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-00/093 (NTIS PB2001-101224), 2000.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 11 Factor 1: Cost of Compliance

In 2008, Platte River performed a Unit 101 Na tural Gas Conversion Study. The primary objective of the study was to determine required un it modifications and asso ciated capital costs to co-fire the unit up to 100% using natural gas. The direct capital cost of converting to 100% natural gas was estimated to be about $50 million by PRPA 15 . This results in an initial control cost, using EPA’s Cost Control Manual 16 to estimate annual operating costs, of about $262,000 per ton of SO 2 removed annually 17 . Changing to natural gas would dramatically raise fuel costs given that natural gas prices are approximately nine (9) times the cost of PRB coal and are subject to significant cost variability, wh ich was not taken into account in the 2008 study 18

. To determine annualized costs of switching to natu ral gas, the annual electricity cost differentials between coal and natural gas were analyzed. PRPA notes that when using natural gas, fuel use will increase 17% annually due to anticipate d efficiency drops, increased heat input requirements, and drop in generation. The a nnual electricity cost of coal is $25.5 million compared to natural gas at about $240 million when using 2008 commercial natural gas prices reported by the U.S. Energy Information Administration 19 . Therefore, this results in a significant annualized cost increase of $233 million. Refer to Appendix D for details.

Table 8 and Table 9 illustrate the resultant emissi ons and costs of switching fuel to natural gas, based on the difference between costs of coal and natural gas in 2008 and AP-42 emission factors. 20

Table 8: Unit 101 Control Resultant SO 2 Emissions Alternative Control Efficiency (%)* Resultant Emissions** (tons/year) (lb/MMBtu) Baseline

--- 913 0.08 Fuel Switching - NG 99% 7.7 0.0006 * Control efficiency calculated by the Division based on PRPA submittal of projected natural gas NO x lb/MMBtu estimate. ** Division calculated from average base line years (2006 – 2008). This is an annual average.

Table 9: Unit 101 SO 2 Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($)* Cost Effectiveness ($/ton)* Incremental Cost ($/ton)

Baseline 0 $0 $0 n/a

15 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NO x Emissions Control Cost and Technical Feasibility Information Request – Additional Details and Explanation.” Contained in Appendix D.

16 EPA, 2002. EPA Air Pollution Control Cost Manual, Sixth Edition. Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, 27711.

17 Colorado Air Pollution Control Division Technical Anal ysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 2010. See Appendix D for detailed calculations.

18 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NO x Emissions Control Cost and Technical Feasibility Information Request – Additional Details and Explanation.” Contained in Appendix D.

19 U.S. Energy Information Administration, 2010. http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm

20 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.4, Table 1.4-2. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 12 Fuel Switching - NG 906 $237,424,331 $262,169 $262,169

* Division estimate based on PRPA submittal estimating direct capital cost at $50,000,000, current delivered coal costs at ~$20/ton, EPA Cost Control Manual, and EPA AP-42 emission factors for natural gas.

Platte River noted that the Divi sion natural gas cost analysis do es not account for replacement power for the lost generation. The Rawhide Natural Gas Conversion Study performed by B&V estimated that a 100% fuel switch would result in a loss of approximately 30 MW, in addition to the increased heat rate which was considered.

Platte River asserts that replacement power cost and associated emissions would depend on the specific source. Replacement with coal-fired sources would run in the $20 - $25/MWh range ($5.3 - $6.6 million/year), while natural gas-fi red sources would run in the $60 - $125/MWh range ($15.8 – 32.8 million/year). Unaccounted NO x emissions from the replacement power sources would likely be around 1.5 lbs/MWh (197 tons/year) for well combustion controlled coal-fired sources, and 0.36 lbs/MWh (47 tons /year) for natural gas- fired sources. The replacement power prices reflect current conditio ns and will need to be escalated over the 20- year 4-factor ev aluation period. SO 2 emissions would likely be in the 0.7 lbs/MWh (92 tons/year) for well controlled coal -fired sources and 0.007 lbs/MWH (1 ton/year) for natural gasfired sources. Table 7 below summar izes these costs and emissions.

Table 10: Unaccounted for Replacement Po wer Cost & Emissions Estimates (30 MW) Power Source Lower Cost ($/MWh) Lower Cost ($ million/year) Higher Cost ($/MWh) Higher Cost ($ million/year)

Coal $20 $5.26 $25 $6.57 Natural

Gas $60 $15.77 $125 $32.85

Power Source NO x (lbs/MWh) NO x (ton/year) SO 2 (lb/MWh) SO 2 (ton/year) Coal 1.5 197 0.7 92 Natural

Gas 0.36 47 0.007 1

Factor 2: Time Necessary for Compliance Based on other Colorado facility submittals 21 , the Division anticipates that, taking into account the time necessary for completing design, permitt ing, procurement, pipeline installation, and system startup and shutdown, after SIP approval it would take PRPA approximately 2 – 3 years to convert the boiler from coal to natural gas. This timeframe may vary somewhat due to regional demand for natural gas and to schedule the necessary major maintenance outage with other regionally a ffected utilities.

21 Prepared for Black Hills Colorado Electric by CH2M Hill, December 2009. “Black Hills Clark Station NOx Reduction Feasibility Study.” Pgs. 3-13 and 3-14.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 13 Factor 3: Energy and Non-Air Quality Impacts The Division has determined that there are not any negative energy or non-air quality related impacts related to fuel switching to natural gas fo r the Unit 101 boiler. Thus, this factor does not influence the selection of controls.

Factor 4: Remaining Useful Life PRPA asserts that since Rawhide Unit 101 is one of the newest units in Colorado, it will remain in service for the 20-year amortization period. Thus, this fact or does not influence the selection of controls.

Factor 5 (optional): Evaluate Visibility Results CALPUFF modeling was used to determine the proj ected visibility improve ment associated with various control technologies. The modeling guid eline requires that modeled baseline emission rate is the 24-hour peak emission rate. The mode ling guideline also requires that, at a minimum, the presumptive emission rate scenario be modele d. Table 11 shows the number of days pre- and post-control. Error! Reference source not found. depicts the visibility results (98 th percentile impact and improvements) as well as cost e ffectiveness in $/deciview and the calculation methodology utilized by the Division.

Table 11: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area

SO 2 Control Scenario Unit(s) SO2 Emission

Rate (lb/MMBtu) Class I Area Affected 3-year totals 3-year totals

PreControl Days >0.5 dv PostControl Days >0.5 dv ∆ days PreControl Days >1.0 dv PostControl Days >1.0 dv ∆ days

Max 24- hr SO 2

rates 101 0.11

RMNP 20 --- --- 6 --- ---

dry FGD 101 0.09 n/a dry FGD 101 0.07 20 19 1 6 4 2

Fuel Switching

- NG 101 0.001 n/a

Table 12: Visibility Results - SO2 Control Scenarios SO2 Control Scenario Unit(s) SO2 Emission Rate Output (@ 98 th Percentile

Impact) 98 th Percentile

Impact Improvement 98 th Percentile Improvement from Maximum (lb/MMBtu) (deciviews) (deciviews) (%)

Max 24-hr SO 2 rates 101 0.11 0.871

dry FGD 101 0.09* 0.87 0.01 1% dry FGD 101 0.07 0.84 0.03 3%

Fuel Switching - NG 101 0.001 0.00 0.87 100%Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 14 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “PRPA Modeling Summary” for more details.

Determination The Division evaluated emission limit tighteni ng based on current operations through the fourfactor analysis. PRPA’s average 30-day rolli ng emission rate during the baseline period (2006 – 2008) was 0.09 lb/MMBtu. The maximum 30-day ro lling emission rate during this period was 0.13 lb/MMBtu. Please refer to “Rawhide Cost Analysis” for more detail. The Division and PRPA agree that Rawhide can meet an emi ssion limit of 0.11 lb/MMB tu (30-day rolling average).

Based upon its consideration of the five factors su mmarized herein, the state has determined that SO2 RP is the following SO2 emission rate: Rawhide Unit 1: 0.11 lb/MMBtu (30-day rolling average)

The state has determined that these emissions rates are achievable with out additional capital investment. Upgrades to the existing SO2 c ontrol system were evaluated, and the state determines that meaningful upgrades to the syst em are not available. Lower SO2 limits would not result in significant visibili ty improvement (less than 0.02 de lta deciview) and would likely result in frequent non-compliance ev ents and, thus, are not reasonable.

b. Filterable Particulate Matter (PM 10

)

PRPA Unit 101 is currently equipped with two twel ve-compartment fabric filter baghouses to control PM/PM 10 emissions from the boiler. Baghouses, or fabric filters, operate on the same principle as a vacuum cleaner. Ai r carrying dust particles is for ced through a cloth bag. As the air passes through the fabric, the dust accumulates on the cloth, providing a cleaner air stream. The dust is periodically remove d from the cloth by shaking or by reversing the air flow. The layer of dust, known as dust cake, trapped on the su rface of the fabric results in high efficiency rates for particles ranging in size from submicron to several hundred micron in diameter. Additionally, fabric filters are th e best PM control for western co als, due to the higher electrical resistivity.

PRPA states that the baghouses are able to control PM/PM 10 emissions to 0.03 lb/MMBtu and further notes that that the baghous es meet a 99.9+% control efficien cy. The source was tested on November 18, 2009 and ran at 0.0023 lb/MMBtu, 92% lower than the permit limit (Method 5 – filterable portion). This boiler is subject to 40 CFR Part 60, Subpart Da, which requires 99% reduction (for facilities commencing constructi on after September 18, 1978) of the potential combustion concentration when burning solid fuel. A Division review of the PM/PM 10 emission limits in the current Title V permit revealed that these limits are for filterable PM/PM 10 emissions only.

A Division review of EPA’s RBLC revealed recent BACT PM/PM 10 determinations range from 0.010 – 0.10 lbs/MMBtu, which are dependent on a number of factors, including PSD netting, EGU type and age, coal type, and adjacent contro ls (i.e. wet and dry FGD systems). The current limit of 0.03 lb/MMBtu is well within the ra nge of recent BACT determinations.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 15 The State has determined that the existing Unit 101 regulatory emissions limits of 0.03 lb/MMBtu (PM/PM10) represents the most stringent control opti on. The state assumes that the emission limit can be achieved through the operation of the existing fabric filter baghouses. The unit is exceeding a PM control e fficiency of 95%, and the cont rol technology and emission limit is RP for PM/PM 10

. Thus, as described in EPA’s BART Guid elines, a full four-factor analysis for PM/PM 10 is not needed for Rawhide Unit 101.

c. Nitrogen Oxides (NO x )

Step 1: Identify All Available Technologies PRPA identified eight NO x control options: Fuel Switching – Natural Gas Selective non-catalyt ic reduction (SCNR) Selective catalytic reduction (SCR) Separated overfire Air (SOFA) Low NO x Burners (LNB) LNB + SOFA ECC – Enhanced Combustion Control

The Division also identified and examin ed the following additional control options: Electro-Catalytic Oxidation (ECO)® Rich Reagent Injection (RRI) Coal reburn +SNCR

Rotating overfire air (ROFA) was not consider ed in this analysis because ROFA® technology has been reported as achieving NO x emission reductions from 45 to 65 % based on fuel load 22

. While ROFA is considered superior to SOFA alone, ROFA alone is not superior to LNB+OFA and cannot achieve the greater than 70% NO x reduction already bei ng achieved at Unit 101. Since ROFA® technology would not be expected to provide better emissi ons performance than the LNB+OFA baseline for this unit, ROFA® technology is not c onsidered further in this analysis.

Step 2: Eliminate Technically Infeasible Options

Fuel Switching – Natural Gas: The Unit 101 boiler at Rawhide c ould convert fuels from coal to natural gas with boiler modifications. NO x emissions from coal combustion are affected by the chemical and physical properties of the feed coal. Feed coal characteristics significantly affect the design and operation of combustion controls, such as the existing LNB+SOFA system. With the LNB+SOFA system in place, Unit 101 curren tly achieves an emission rate of 0.17 lb/MMBtu (annual average).

PRPA notes that Unit 101 is designed to burn PRB coal and the boiler is additionally optimized through a technologically complex pr ocess to burn this coal at ve ry tightly controlled rate. PRPA has indicated that it is infeasible and ec onomically impractical to change coal supplies. With fuel switching to natural gas, NO x emissions were projected to drop from the current 0.17

22 Nalco-Mobotec, ROFA Technology, 1992-2009, http://www.nalcomobotec.com/technology/rofa-technology.htmlColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 16 lbs/MMBtu to a rate of 0.1 lbs/MMBtu 23 . However, this reduction would be diminished by the accompanying loss in boiler efficiency, increased boiler heat input requirement, and significant loss of generation resulting fr om natural gas firing.

The Division has determined that fuel switchi ng to natural gas is te chnically feasible for Rawhide Unit 101.

LNB/ROFA®/SOFA/LNB+SOFA: The boiler is already equippe d with a tangentially-fired LNB+SOFA system that was installed in 2005. This system achieves an approximate 50% NO x reduction (based on actual emissions).

SNCR: Selective non-catalytic reduction is ge nerally utilized to achieve modest NO x reductions on smaller units. With SNCR, an amine-based reag ent such as ammonia or urea is injected into the furnace within a temperature range of 1,600°F to 2,100°F, where it reduces NO x to nitrogen and water. Reagent utilizat ion, a measure of the efficiency with which the reagent reduces NO x , can have a significant impact on economics, with higher levels of NO x reduction generally resulting in lower reagent ut ilization and higher operating cost. The optimum temperature window for Rawhide Unit 101 will most likely occur somewhere at the top of the furnace and in the backpass of the boiler if SNCR is applied. SCNR is considered a technically feasible alternative for Unit 101.

SCR: SCR systems are the most widely used post-combustion NO x control technology. In retrofit SCR systems, vaporized ammonia (NH 3 ) injected into the flue gas stream acts as a reducing agent, achieving NO x emission reductions as low as 0.07 lb/MMBtu when passed over an appropriate amount of catalyst as demonstrat ed by recent determinations found in the EPA’s RBLC database. The NO x and ammonia reagent form nitrog en and water vapor. The reaction mechanisms are very efficient with a reagen t stoichiometry of approximately 1.0 (on a NO x reduction basis) with very low ammonia slip.

The SCR reaction occurs within the temperature range of 550°F to 850°F where the extremes are highly dependent on the fuel quality. There ar e three different types of SCR arrangements – high-dust, low-dust, and tail-end. The pre-dominant arrangement applied in the United States has been high-dust. In most circumstances, a high-dust SCR system is the most economical arrangement alternative and would likely be the arrangeme nt for Unit 101 if applicable. For high- and low-dust arrangements, the catalyst, becau se of its location dire ctly downstream of the boiler and upstream of the air heater, can impact the boiler through its ef fect on the air heater. The magnitude of this effect is dependent on th e power plant configurat ion, air quali ty control components, type of fuel, and overall emission c ontrol requirements. For retrofit applications, adequate space between the economizer outlet and th e air heater inlet to allow boiler outlet and air heater return duct is a prereq uisite for the installation of a hi gh-dust system and is the case at the Rawhide Station. Therefore, high-dust SCR is a technically feasible alternative for Rawhide Unit 101.

23 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NO x Emissions Control Cost and Technical Feasibility Information Request – Additional Details and Explanation.” Contained in Appendix D.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 17 ECC: The enhanced combustion co ntrol system option for Rawhide Unit 101, submitted by PRPA, consists of a neural-net based com bustion optimization subsystem (software and hardware) and companion real-time boiler combustion constituents and temperature measurement system. These system component s are interfaced with the boiler’s standard coordinated combustion control system (CCS). The ECC system continuously measures and monitors the dynamic boiler combustion const ituents, temperatures and other process parameters. The ECC system then commands the CCS to manipulate variables such as combustion air damper positions, burner tilts, coal feeder speeds, and other process parameters to optimize fuel combustion and boile r efficiency, while controlling NO x and CO emissions within targeted ranges. Optimizing the ECC requires periodic combustion testing and CCS tuning. ECC is a technically feasib le option for Rawhide Unit 101.

ECO®: The Powerspan ECO® system is installed downstream of a coal-f ired power plants’ existing baghouse. The ECO® Reactor then oxidi zes pollutants, which are removed downstream in an absorber vessel during cooling and saturati on of the flue gas. This technology has not been demonstrated on a full-si ze pulverized coal-fired boiler 24 and thus, is considered technically infeasible.

RRI: Rich reagent injection is the process of adding NO x reducing agents in a staged lower furnace to reduce the formation of NO x , accomplished by injecting urea into the fuel-rich region of a furnace, where the reducing conditions in the lower furnace make RRI ideal for NO x reductions. The combustion process is then complete d with the use of overfir e air. Rich reagent injection was developed for cyclone boilers 25 and has not been demonstrated for other types of units. Therefore, RRI is considered technically infeasible for Unit 101.

Coal Reburn + SNCR: Several research and development effo rts in the United States evaluated using a combination of technologies to reduce NO x emissions, including combining coal reburn and SNCR. A novel injection pro cedure into the fuel -rich, post-combustion zone with staged, fuel-rich primary combustion and SN CR injection was found to reduce NO x emissions by 93% or well below 0.1 lb/MMBtu 26 . However, this procedure has not been performed on a full-size pulverized coal-fired boiler yet and thus, is considered technically infeasible.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Fuel Switching – Natural Gas: The Unit 101 boiler at Rawhide c ould convert fuels from coal to natural gas with boiler modifica tions. Conversion from coal to natural gas would reduce NO x emissions by about 545 tons per year, or a pproximately 29% (using 2006 - 2008 CAMD data average) 27

.

24 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.power span.com/ECO_overview.aspx

25 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.php

26 Coal Tech. Corp, 2002. “Tests on Combined Stag ed Combustion, SNCR & Reburning for NOx Control and Combined NOx/SO2 Control on an Industrial & Utility Boilers.” http://www.netl.doe.gov/publications/proceedin gs/04/NOx/summary/h11.50zauderer-summary.pdf

27 Colorado Air Pollution Control Division Technical Anal ysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 2010. See Appendix D for detailed calculations.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 18 SNCR: Other Colorado facilities have noted a variet y of control ranges for SNCR. The Division used a variety of information, including a sim ilar Colorado facility es timates, EPA’s SNCR Air Pollution Control Fact Sheet and a recent AWMA study 28 to conservatively approximate that Rawhide Unit 101 can achieve up to 30% control wh en SNCR is applied. PRPA asserts that NO x reductions of up to 60% have been achieve d, although 20-40% is more realistic for most applications. However, if ammonia slip is controlled closer to 2 ppm then achievable NO x reduction efficiencies will be closer to 20 percent.

SCR: PRPA approximates that SCR can achieve an approximate 64% NO x reduction from the current low 0.17 lb/MMBtu baseline emission rate. PRPA asserts that while a lower controlled NO x emission values have been demonstrated by S CR system applications in new coal units, for PRPA, a retrofit SCR, the 0.07 lb/MMBtu controlled NO x value is more expected. This control efficiency is slightly lower than EPA’s AP- 42 emission factor discus sion, which estimates SCR as achieving 75 – 85% NO x emission reductions and also with a recent AWMA study citing SCR as achieving 80 – 90% reduction from an assu med baseline emission rate of 0.5 lb/MMBtu. 29,30 However, in the Division’s experience and nation al CAMD emissions data (2009) reflect that an emission limit of no lower than 0.07 lb/MMBtu is realistically achievable for a retrofit SCR.

Table 13 summarizes each available tec hnology and technical feasibility for NO x control.

Table 13: Rawhide Unit 101 NOx Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Low NO x Burners (LNB) 10-30% Y – installed LNB + OFA 25-45% Y – installed Air Staging – overfire air (OFA) 5-40% Y – installed

Rotating overfire air (ROFA) 45-65% Y – will not increase current NO x reductions SCNR 20 – 40% Y SCR – HTSCR Up to 90% Y-high-dust arrangement SCR – LTSCR SCR – RSCR Fuel switching – Natural gas 20-70% Y Electro-Catalytic Oxidation (ECO)® n/a N

Rich Reagent Injection (RRI) n/a N Coal reburn+SNCR n/a N ECC 15-25% Y

28 Srivastava et. al, 2005. Nitrogen Oxides Emission Contro l Options for Coal-Fired Electric Utility Boilers. Journal of Air & Waste Management Association 55:1367 – 1388.

29 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.1, Table 1.1-2. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdf

30 Srivastava et. al, 2005. Nitrogen Oxides Emission Contro l Options for Coal-Fired Electric Utility Boilers. Journal of Air & Waste Management Association 55:1367 – 1388.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 19 Step 4: Evaluate Factors and Present Determination

Factor 1: Cost of Compliance SNCR: A typical breakdown of annual for industria l boilers will be 15 – 35% for capital recovery and 65 – 85% for operating expense. 31 The PRPA-estimated SNCR costs for operating expenses is 44% for Unit 1. Since SNCR is an operating expense-driven techno logy, its cost varies directly with NO x reduction requirements and reagent usag e. The cost effectiveness for SNCR on Unit 1 is $3,168 per ton NO x reduced. Recent NESCAUM studi es estimate SNCR retrofits achieving NO x emission rates of 0.30 – 0.40 lb/MMBtu and emission reductions of 30 – 50% as costing $630 - $1,300 per ton of NO x reduced, depending on initia l capital costs and capacity factor. 32,33 EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NO x reduced. 34

Platte River relies on Black and Veatch’s (B&V) expertise and cost estimates on major projects. Platte River contracted with B& V to perform a detailed study to provide capital costs for NOx emissions reduction alternatives for the Rawhide Unit 101. The Rawhide NOx Reduction Study, January 2009 noted that the SNCR costs were based on actual B&V engineering, procurement, and contracting projects. Rawhide specifi c SNCR project cost c onsiderations were:

•

• Rawhide’s geographic location, economies of scale and small size of Rawhide Unit 101

• Three levels of automatic injection lan ces with retract system to accommodate SNCR reaction temperature and boiler turndown requirements.

• Computer flow/temperature modeling to establish optimum ammonia injection locations and flow patterns,

• Boiler waterwall modifications for injector lances and steam piping modifications for performance optimization,

• Electrical Motor Control Center switch gear upgrades and modifications to support urea system and a mmonia delivery system,

• Reagent storage tank,

• Digital Control System (DCS) computer system hardware and control logic upgrades,

• Fluegas temperature and NOx and ammoni a continuous emission monitoring, data acquisition, alarming and reporting system,

• Interest costs during construction, and

• Use of a more expensive urea reagent syst em rather than anhydrous ammonia due to safety and transport concerns.

31 ICAC, 2000. Institute of Clean Air Companies, Inc. “White Paper: Selective Non-Catalytic Reduction (SNCR) for Controlling NO x Emissions.” Washington, D.C. 2000.

32 Neuffer, Bill – ESD/OAQPS, 2003. “NO x Controls for Existing Utility Boilers.” http://www.epa.gov/ttn/nsr/gen/u3-26.pdf

33 Amar, Praveen, 2000. “Status Report on NOx Contro ls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines: Technologies & Cost Effectiveness.” Northeast States for Coordinated Air Use Management, 129 Portland Street, Boston, MA 02114.

34 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 20 Platte River notes that the SNCR cost effectiv eness ($/ton removed) remains comparatively high due to Rawhide’s low baseline NO x emission rates for the above reasons.

There is a wide range of cost effectiveness fo r SNCR due to different boiler configurations and site-specific conditions, even with a given industry. Cost effectiveness is impacted primarily by uncontrolled NO x level, required emission reductions, un it size and thermal efficiency, economic life of the unit, and degree of retrofit difficulty. 35 Although PRPA’s estimat es are greater than these ranges, the reasons above lead the Division to the conclusion that PRPA’s cost estimates for SNCR are reasonable.

SCR: SCR reagent materials, such as urea and/or ammonia, primarily use a limited resource, natural gas. Therefore, future costs for these ma terials may fluctuate widely. These costs are not included in the overa ll $/ton projections.

EPA’s regulations recommend using the EPA’s Of fice of Air Quality Planning and Standards’ Air Pollution Cost Control Manual (Sixth Ed ition, January 2002) for estimating costs of compliance. This Manual provides guidance a nd methodologies for developing accurate and consistent estimates of cost for air pollution c ontrol devices. The costs that may be estimated include capital costs, operati on and maintenance (O&M) expenses , and other annual costs.

In reviewing PRPA’s estimate, the Division found that the ratio of annua l costs to the total capital costs for all control technologies projec ted by PRPA to be slightly lower than those projected by other faciliti es that were amortized over the same 20 year time frame. For example, the annualized costs for SCR for Unit 101 are 10.5% of the total capital investment. The EPA found that other facilities in Arizona, New Me xico, and Oregon presented annual costs that ranged from 12 – 15% of total capital investments 36 . Therefore, the Division concurs that PRPA’s estimate is consistent with annua l costs estimated by other facilities.

Platte River relies on Black and Veatch’s (B&V) expertise and cost estimates on major projects. Platte River contracted with B& V to perform a detailed study to provide capital costs for NOx emissions reduction alternatives for the Rawhide Unit 101. The Rawhide NOx Reduction Study, January 2009 noted that the SCR costs were based on actual B&V engineering, procurement, and contracting projects. Rawhide specifi c SCR project cost considerations were:

• Vertical oriented high-dust SCR reactor configuration,

• Construction crane access constraints due to north-side coal conveyor and ACI silo, and south-side underground 84 inch circulating water line,

• Preliminary design and layout analyses in cluding foundations, stru ctural columns, cantilevered support steel, and main trusses support structures,

• Modification to existing structures in cluding demolition of ductwork between the economizer and the air heater inlet,

• Rawhide’s geographic location, economies of scale and small size of Rawhide Unit 101,

35 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf

36 Environmental Protection Agency, 2009. 40 CFR Part 49 : Assessment of Anticipated Visibility Improvements at Surrounding Class I Areas and Cost Effectiveness of Best Available Retrofit Technology for Four Corners Power Plant and Navajo Generating Station: Advance Notice of Proposed Rulemaking. Pg. 44318.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 21 • Induced draft (ID) fan higher hp moto r replacement and retrofit issues,

• Auxiliary power and switch gear upgrades and modifications to support two new ID fan motors,

• Digital Control System (DCS) computer system hardware and control logic upgrades including new electri cal and controls building lo cated adjacent to SCR,

• NOx and ammonia continuous emission monitoring, data acquisition, alarming and reporting system,

• Three layer (two catalyst and one initial spare) re actor sizing for maximizing catalyst utilization,

• Reactor design to accommodate both ceramic honeycomb and plate type catalyst products to insure future procurement flexibility,

• Rerouted underground utilities (bottom-ash sluice trench and drain piping) due to SCR foundation requirements,

• Added superstructure costs due to fully enclosed plant, including boiler and air heater areas for cold-weather concerns requiring roof and wall penetrations and modifications,

• Higher structural costs due to high wind loading ,

• High gas temperature design issues (>800° F economizer gas temperature results in higher grade catalyst a nd steel issues), and

• Use of a more expensive urea reagent syst em rather than anhydrous ammonia due to safety and transport concerns,

• Interest costs during construction, and

• Lost generation revenue costs during outage.

Platte River notes that the SCR cost effectiv eness ($/ton removed) remains comparatively high due to Rawhide’s low baseline NO x emission rates for the above r easons. The Division asserts that $/KW is not an appropriate metric when a de tailed cost estimate has be developed. $/KW is rough estimate of controls for back of the enve lope discussions and should not serve as cost estimate in light of more refined estimates. Therefore, the Division did not adjust PRPA’s estimates for capital costs.

Fuel Switching – Natural Gas : In 2008, Platte River performed a Unit 101 Natural Gas Conversion Study. The primary objective of the study was to determine required unit modifications and associated capita l costs to co-fire the unit up to 100% using natural gas. The direct capital cost of converting to 100% natural gas was estimated to be about $50 million. Conversion from coal to natural gas would reduce NO x emissions by about 545 tons per year (using 2006 - 2008 CAMD data average). This resu lts in an initial cont rol cost, using EPA’s Cost Control Manual to estimate annual ope rating costs, of about $436,000 per ton of NO x removed annually 37 . Changing to natural gas would drama tically raise fuel costs given that natural gas prices are approximately nine (9) tim es the cost of PRB coal and are subject to significant cost variability. Ta bles 9 and 10 illustrate the re sultant emissions and costs of switching fuel to natural gas, based on the difference between costs of coal and natural gas in 2008 and AP-42 emission factors. The annual cost to control was determined using a capital

37 Colorado Air Pollution Control Division Technical Anal ysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 2010. See Appendix D SIP for detailed calculations.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 22 recovery factor based on an approximate 8% intere st rate. Refer to “Rawhide Cost Analysis” for more details.

To determine annualized costs of switching to natu ral gas, the annual electricity cost differentials between coal and natural gas were analyzed. PRPA notes that when using natural gas, fuel use will increase 17% annually due to anticipate d efficiency drops, increased heat input requirements, and drop in generation. The a nnual electricity cost of coal is $25.5 million compared to natural gas at about $240 million when using 2008 commercial natural gas prices reported by the U.S. Energy Information Administration 38 . Therefore, this results in a significant annualized cost increase of $233 million. Refer to Appendix D for details.

ECC : PRPA worked with three different vendors on an enhanced combustion control pilot system. The cost estimates provided are from this pilot project. The annualized cost of approximately $288,500 is much lower than SNCR, which achieves about the same amount of control. This is little availabl e cost information regarding this type of boiler modification. Since the costs are comparable or lower than other pre-combustion technologies , the Division concurs that PRPA’s cost estimate is reasonable.

Table 14 and Table 15 de pict controlled NO x emissions and control cost comparisons.

Table 14: Unit 101 Control Resultant NO x Emissions Alternative Control Efficiency (%) Resultant Emissions

Annual Emissions (tons/year) Annual Average (lb/MMBtu) 30-day Rolling Average (lb/MMBtu)

Baseline

--- 1,866 0.166

ECC 24.0 1,418 0.126 0.145 SNCR 27 1,362 0.121 0.140 Fuel Switching - NG 29.2** 1,321 0.118 0.135 SCR 63.5 681 0.061 0.070 * Control efficiency calculated by the Division based on PRPA submittal of projected natural gas NO x lb/MMBtu estimate. ** Control efficiency provided in PRPA’s analysis based on 0.17 lb/MMBtu NO x input, equivalent to 2006 – 2008 baseline conditions. Refer to “Rawhide Cost Analysis” for more information.

Table 15: Unit 101 NO x Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

38 U.S. Energy Information Administration, 2010. http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htmColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 23 ECC 448 $ 288,450 $644 $644

SNCR 504 $1,596,000 $3,168 $23,357 Fuel Switching - NG 545 $237,424,331 $435,681 $5,735,260

SCR 1,185 $12,103,000 $10,214 ($352,073)

Factor 2: Time Necessary for Compliance Based on other Colorado facility submittals 39 , the Division anticipates that the time necessary for completing design, permitting, procurement, pipe line installation, and system startup and shutdown, after SIP approval, it would take PR PA approximately 2 – 3 years to convert the boiler from coal to natural gas. This timefra me may vary somewhat due to regional demand for natural gas and to schedule the necessary ma jor maintenance outage with other regionally affected utilities.

PRPA anticipates that the time necessary for completing design, permitting, procurement, control equipment installation, and system startup a nd shakedown, after SIP approval, would be approximately 2-3 years for SNCR and 3-4 years for SCR. These timeframes may also vary somewhat to schedule the necessary major mainte nance outage with other regionally affected utilities. The ECC option timeframe is much shor ter due to the fact that PRPA has already been working with independent vendors on this system. Therefore, this system could be functional within 6 months of SIP approval.

Factor 3: Energy and Non-Air Quality Impacts SCR retrofit impacts the existing flue gas fan systems, due to the additional pressure drop associated with the catalyst, which is typically a 6- to 8-inch water gage increase for the high temperature applications, and potentially somewhat lower for the low temperature alternatives. In addition, any flue gas reheat requirements for the low temperature applications may require significant energy input to heat the flue gas. SCR and SNCR reagent injection system have minimal power requirements.

Post-combustion add-on contro l technologies like SCR and SNCR do increase power needs, in the range of 100 – 300 kilowatts (kW) depending on the boiler size, to operate pretreatment and injection equipment, drive the pumps and fans necessary to supply reagents, overcome additional pressure drops caused by the control equipment, a nd provide steam in some cases. In particular, SCR systems require additional auxiliary power or power from the existing flue gas fan systems to overcome the pressure loss across the catalys t, to supply dilution air for mixing with the ammonia, and to pump ammonia into the vapori zer. 100 – 300 kW is less than 0.5% of the power generated by the Unit 101 boiler annually, or enough energy to power about 10 homes for a year. These energy requirements are minimal.

Installing SNCR or SCR increases levels of ammonia, and may create a ‘blue plume’, if ammonia rates are not adequately controlled. Other environmental fa ctors include ammonia storage and transportation, particularly for a nhydrous ammonia. Anhydrous ammonia is clear in

39 Prepared for Black Hills Colorado Electric by CH2M Hill, December 2009. “Black Hills Clark Station NOx Reduction Feasibility Study.” Pgs. 3-13 and 3-14.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 24 the liquid state and boils at a temperature of - 28°F. With its low boiling point, liquid anhydrous ammonia must be stored under pr essure at ambient temperatures to remain a liquid. With anhydrous ammonia, an invisible vapor or gas is formed as the liquid evaporates during depressurization. Accidental atmospheric release of a nhydrous ammonia vapor can be hazardous; therefore, stringent requirements for sa fety are enforced, and obtaining the permits to allow the storage of large quantities of anhydr ous ammonia may prove difficult in densely populated areas. PRPA has indicated to the Division that they would prefer to use urea instead if applicable to ensure personnel and surrounding community safety, and based the capital and operating costs of a SCR system on a urea reagen t versus an ammonia reagent. Refer to Appendix D for more information.

Factor 4: Remaining Useful Life PRPA asserts that since Rawhide Unit 101 is one of the newest units in Colorado, it will remain in service for the 20-year amortization period. Thus, this factor doesn’t influence the selection of controls.

Factor 5 (optional): Evaluate Visibility Results CALPUFF modeling was used to determine the proj ected visibility improve ment associated with various control technologies. The modeling guid eline requires that modeled baseline emission rate is the 24-hour peak emission rate. The mode ling guideline also requires that, at a minimum, the presumptive emission rate scenario be modele d. Table 16 shows the nu mber of days pre- and post-control. Table 17 depict s the visibility results (98 th percentile impact and improvements) as well as cost effectiveness in $/deciview and the calcula tion methodology utilized by the Division.

The state performed modeling using the maximu m 24-hour rate during the baseline period, and compared resultant annual average control estimate s. In the state’s experience and other state BART proposals, 30-day NOx rolling average emi ssion rates are expected to be approximately 5-15% higher than the annual average emissi on rate. The state projected a 30-day rolling average emission rate increased by 15% for a ll NOx emission rates to determine control efficiencies and annual reductions.

Table 16: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area

NOx Control Scenario Boiler NOx Emission Rate (lb/MMBtu)* Class I Area Affected 3-year totals 3-year totals

PreControl

Days >0.5 dv PostControl

Days >0.5 dv ∆ days PreControl

Days >1.0 dv PostControl

Days >1.0 dv ∆ days

Max 24-hr NOx rate 101 0.302

Rocky Mountain National

Park 20 --- --- 6 --- ---

ECC 101 0.126 20 6 14 6 1 5

SNCR 101 0.121* n/a
Fuel Switching

- NG 101 0.118* n/a

SCR 101 0.061 20 1 19 6 0 6Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 25 Table 17: Visibility Result s - NOx Control Scenarios

NOx Control Scenario Boiler NOx Emission Rate (lb/MMBtu)* Output (@ 98 th Percentile

Impact) 98 th Percentile Impact Improvement 98 th Percentile Improvement from Maximum Cost Effectiveness

(dv) ( ∆ dv) (%) ($/dv)

Max 24-hr NOx rate 101 0.302 0.87 --- --- ---

ECC 101 0.126 0.42 0.45 52% $642,428 SNCR 101 0.121* 0.41 0.46 53% $3,469,565

Fuel Switching - NG 101 0.118* 0.41 0.47 54% $509,494,272

SCR 101 0.061 0.28 0.59 68% $20,548,387 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “PRPA Modeling Summary” for more details.

Determination Based upon its consideration of the five factors su mmarized herein, the State has determined that NOx RP for Rawhide Unit 101 is the following NOx emission rate:

Rawhide Unit 1: 0.145 lb/MMBtu (30-day rolling average)

The state assumes that the RP emission limits ca n be achieved through the operation of enhanced combustion control. The dollars per ton c ontrol cost, coupled with notable visibility improvements, leads the state to this determination. Alt hough SCR achieves better emission reductions, the expense of SCR was determined to be excessive and above the guidance cost criteria discussed in section 8.4 above. SNCR would achieve similar emissions reductions to enhanced combustion controls and would afford a minimal additional visibility benefit (0.01 delta deciview), but at a signifi cantly higher dollar per ton control cost compared to the selected enhanced combustion controls, so SNCR was not determined to be reasonable by the state.