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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 1 Reasonable Progress Analysis of Control Options For Tri-State Generation & Transmission Asso ciation, Inc. – Craig Station Unit 3

I. Source Description

Owner/Operator: Tri-State Generati on & Transmission A ssociation, Inc. Source Type: Electric Util ity Steam Generating Unit SCC (EGU): 10100202 Boiler Type: Three Dry-Bottom Pulveriz ed Coal-Fired Boilers, two opposedwall-fired (Units 1 and 2) a nd one front-fired (Unit 3)

The Tri-State Generation & Transmission Asso ciation, Inc. (Tri-Sta te) Craig Station is located in Moffat County approximately 2.5 miles southwest of the town of Craig, Colorado. This facility is a coal-fired power plant with a total ne t electric generating capacity of 1264 MW, consisting of thr ee units. Units 1 a nd 2, rated at 4,318 mmBtu/hour each (net 428 MW), were placed in service in 1980, and 1979, respectively. Unit 3, rated at 4,600 MMBtu/hour (net 408 MW) was placed in service in 1984.

Units 1 & 2 : Construction of Units 1 and 2 began in 1974; Unit 1 began operation in 1980 and Unit 2 began operation in 1979. These units are equipped with fabric filter (baghouse) systems for controlling particulat e matter (PM) emissions, and wet limestone Fuel Gas Desulfurization (FGD) systems for the control of sulfur dioxide (SO 2 ) emissions. The boilers are equipped with ultra-low nitrogen oxide (NO x ) dual register burners with overfire air for minimization of NO x emissions. The FGD and ultra low NO x burner systems were required to be inst alled and fully operational by December 31, 2004 as a result of a consent decree with th e Sierra Club (signed January 10, 2001).

Unit 3 : Construction of Unit 3 began in 1981 an d the unit commenced operation in 1984. This unit is equipped with a baghouse system for controlling PM emissions, a dry lime system for control of SO 2 and low-NO x burners with overfire air.

All three units can use natura l gas, propane, or fuel oil for start-up, shutdown, and for flame stabilization. All three units are subject to the requirements of Title IV, the Acid Rain Program, and were approved for Early Election for NO x limits, effective January 1, 1997. Associated activities include two cooling towers, coal handling systems, ash handling systems, limestone handling sy stem, and the staging/landfilling area.

For this analysis, the Division also relied on the existing Constructi on permit, historical information regarding Craig Station, and inform ation about similar fac ilities to determine RP for NO x , SO 2 , and PM 10 . EPA’s BART guidelines reco mmend 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 reference, and because the statutory factors that must considered in making BART and RP determinations are largely the same. Units 1 and 2 are consider ed BART-eligible, being industrial boilersColorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 2 with the potential to emit 250 tons or more of haze forming pollution (NO x , SO 2 , PM 10 ), and commenced operation in the 15-year pe riod prior to August 7, 1977. Therefore, these two boilers have been evaluated fo r BART, which the Division has determined meets the requirements of RP at this time.

The Division has elected to set a de minimis threshold for actual baseline emissions for evaluating reasonable progress uni ts at each facility equal to the federal Prevention of Significant Deterioration levels. The Divi sion defines “unit” as an Air Pollutant Emission Notice (APEN) subject source, or a stationary sour ce, defined as “any building, structure, facility, equipment, or installati on, or any combination thereof belonging to the same industrial grouping that emit or may em it any air pollutant s ubject to regulation under the Federal Act that is located on one or more conti guous or adjacent properties and that is owned or operated by the same person or by persons under common control 1
.” These levels are as follows:

• NO x – 40 tons per year

• SO 2 – 40 tons per year

• PM 10 – 15 tons per year

Boiler 3 is considered by the Division to be eligible for the purposes of Reasonable Progress, being an industrial boiler with the potential 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. TriState Generation and Transmission Association (Tri-State) provided information relevant to RP to the Division on December 3 1, 2009, May 14, 2010, June 4, 2010 and July 30, 2010. Error! Reference source not found. depicts technical information for Unit 3 at Craig Station.

Table 1: Craig Unit 3 Technical Information

Unit 3

Placed in Service 1984
Gross Boiler Rating, MMBtu/Hr for coal 4,600

Electrical Power Rating, Net Megawatts 408

Description Babcock & Wilcox coal, dry bottom boiler - Natural gas, propane, or fuel oil used at startup and shutdown, and for flame stabilization

Air Pollution Control Equipment PM/PM 10 – Pulse Jet Fabric Filter Baghouse (1984 – upgraded between 2007 and 2009)

NO x – Low NO x Burners with Over-Fire Air (upgraded between 2007 and 2009)

SO 2 – Dry Limestone FGD (1984 – upgraded between 2007 and 2009) Existing turbine generator replaced with larger unit completed in May 2009.
Emissions Reduction (%)* NO x – 19.0%/38.8%* SO 2 – 80.9%

1 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 3 PM – 99.8%

PM 10 – 99.6% *Emissions Reduction estimated by comparing pre-control upgrade 2006-2008 CAMD data to AP-42 emission factor data. The first NO x number compares the additional redu ction achieved by the ultra-low NO x burners vs. the original low-NO x burners and the second NO x number compares uncontrolled AP-42 factor to actual average emission factor (June 2009 – June 2010). For PM/PM 10 ., uncontrolled AP-42 factor were compared to actual average emission factors (2006 – 2008). See “Craig APCD Technical Analysis” for further details. Not based on actual testing.

II. Source Emissions

Table 2 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 3 summarizes each unit at the f acility 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 the Unit 101 boiler and the turbines).

Table 2. Summary of 2006 - 2008 Averaged Emissions – Craig Station NO x (tons/year) SO 2 (tons/year) PM 10 (tons/year) 16,942 3,769 363

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit – Craig Station

Unit Pollutant 2006 2007 2008 2006 - 2008 average*

Unit 1 SO 2 (tons) 865.1 1053.0 990.5 969.5 SO 2 (lb/ MMBtu) 0.06 0.06 0.06 0.06 NO x (tons) 4665.7 5817.3 5056.9 5180.0 NO x (lb/ MMBtu) 0.34 0.32 0.30 0.32 PM (tons) 92.9 107.3 101.1 100.4 PM (lb/ MMBtu) 0.007 0.006 0.006 0.006

Unit 2 SO 2 (tons) 999.6 797.1 1149.1 981.9 SO 2 (lb/ MMBtu) 0.05 0.05 0.06 0.06 NO x (tons) 5548.7 4965.7 5566.4 5360.3 NO x (lb/ MMBtu) 0.30 0.32 0.30 0.31 PM (tons) 90.7 81.9 87.5 86.7 PM (lb/ MMBtu) 0.005 0.005 0.005 0.005

Unit 3 SO 2 (tons) 1721.3 1948.5 1782.6 1817.5 SO 2 (lb/ MMBtu) 0.10 0.11 0.11 0.10 NO x (tons) 6592.1 6670.1 5943.9 6402.0 NO x (lb/ MMBtu) 0.38 0.36 0.35 0.37 PM (tons) 70.4 71.8 67.7 70.0 PM (lb/ MMBtu) 0.004 0.004 0.004 0.004

Auxiliary Boiler (130 MMBtu/hr) Fuel Oil Boiler SO 2 (tons) 0 0 0 0 SO 2 (lb/ MMBtu) 0 0 0 0 NO x (tons) 0 0 0 0Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 4 Unit Pollutant 2006 2007 2008 2006 - 2008 average* NO x (lb/ MMBtu) 0 0 0 0 PM (tons) 0 0 0 0 PM (lb/ MMBtu) 0 0 0 0 F101a – Coal Hauling – Units 1 & 2 PM (tons) 8.15 8.15 11.39 9.23 F101b – Coal Unloading to Grizzly – Units 1 & 2 PM (tons) 0.04 0.04 0.05 0.04 F101c – Coal Surge Pile PM (tons) 0.05 0.05 0.05 0.05 S101d – Primary Coal Crushing – Units 1 & 2 PM (tons) 0.18 0.18 0.23 0.20 S101e – Secondary Coal Crushing Bldg – Units 1 & 2 PM (tons) 0.46 0.46 0.56 0.49 S101f – Common Coal

Transfer Bldg Belt A PM (tons) 0.001 0.001 0.0013 0.0011 S101g – Common Coal

Transfer Bldg Belt B PM (tons) 0.001 0.001 0.0013 0.0011 S101h – Coal Stackout Building – Units 1 & 2 PM (tons) 0.002 0.002 0.0025 0.0022 S101i - Coal Stackout – Units 1 & 2 PM (tons) 0.051 0.051 0.063 0.055 F101 j -Coal Storage Piles – Units 1 & 2 PM (tons) 0.63 0.63 0.63 0.63 S101k – Coal Reclaim A – Units 1 & 2 PM (tons) 0.0018 0.0018 0.0019 0.0018 S101l – Coal Reclaim B – Units 1 & 2 PM (tons) 0.0018 0.0018 0.0019 0.0018 S101m – coal Tripper Deck & Silos – Units 1 & 2 PM (tons) 0.0036 0.0036 0.0038 0.0037 S101n – Common Coal Drive House PM (tons) 0.0036 0.0036 0.0038 0.0037 S203a – Fly Ash Storage

Silo A – Units 1 & 2 PM (tons) 0.0047 0.0047 0.002 0.0038 S203b – Fly Ash Storage

Silo B – Units 1 & 2 PM (tons) 0.0047 0.0047 0.002 0.0038 F203c – Fly Ash Truck Loading – Units 1 & 2 PM (tons) 0.0079 0.0079 0.0034 0.0064 P204 – Ash Hauling & Storage – Unit 3 PM (tons) 62.2 62.2 62.2 62.2 P201 – Limestone Hauling PM (tons) 14.7 14.7 17.5 15.6 F102a – Coal Train Unloading – Unit 3 PM (tons) 0.0607 0.0607 0.0676 0.063 S102b/c – Coal Conveyor Portal Building – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 S102d – Secondary Coal Crushing (2 crushers0 – Unit 3 PM (tons) 0.68 0.68 0.76 0.71 S102e – Coal Stackout Building – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 F102f – Coal Stackout – Unit 3 PM (tons) 0.076 0.076 0.085 0.078Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 5 Unit Pollutant 2006 2007 2008 2006 - 2008 average* F102g – Coal Storage Pile – Unit 3 PM (tons) 0.24 0.24 0.24 0.24 S102h – Coal Reclaim System – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 S102k – Common Coal Transfer Building Extension PM (tons) 0.003 0.003 0.0034 0.0031

S102n – Common Coal Drive House PM (tons) 0.003 0.003 0.0034 0.0031 S102i – Coal Tripper Deck and Silos – Unit 3 PM (tons) 0.0018 0.0018 0.0018 0.0018 S102j – Loadout Coal to Railcars – Unit 3 PM (tons) 0 0 0 0 F205a – Ash Hauling to “Landfill” (Outage Waste to Trapper) PM (tons) 0.114 0.114 0.114 0.114 F205b – Ash and Wet Waste

Hauling to/from Decant Basin PM (tons) 0.676 0.676 0.676 0.676 F205c – Ash Unloading at “Landfill” (Outage Waste) & Ash Unloading at Decant Basin PM (tons) 0.0024 0.0024 0.0024 0.0024 F205d – Wet Waste Unloading at Decant Basin PM (tons) 0 0 0 0

F202a – Lime Hauling (trucks) PM (tons) 0 0 0 0 S202b – Lime Unloading – Unit 3 PM (tons) 0.0011 0.0011 0.0012 0.0011 S202c – Lime Conveying & Silo – Unit 3 PM (tons) 0.0011 0.0011 0.0012 0.0011 S202d – Lime Day Bin PM (tons) 0.0011 0.0011 0.0012 0.0011 S401/2 – Cooling Towers – Units 1 & 2 PM (tons) 10.3 10.3 10.3 10.3 Auxiliary Boiler PM (tons) 0 0 0 0 S403 - Cooling Tower – Unit 3 PM (tons) 5.8 5.2 5.2 5.4 *The above emissions are for the most recent thr ee years (2006 – 2008). These emissions are an annual average. 30-day NO x rolling averages for the boilers are estima ted to be 5-15% higher than the annual average emission rate.

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

Tri-State estimated that a realistic depiction of anticipated annual emissions for Unit 3, or “Baseline” Emissions”, to be conservative, was the average of 30-day averages from 2009, or 0.33 lb/MMBtu for NO x . Tri-State noted that this baseline reflects the recent PSD permit limit of 6,752 tons associated w ith a 2009 turbine upgrade. This baseline reflects the low-NO x burners and overfire air installe d at Craig 3 in 2009. The Division notes that the 2006 – 2008 baseline period used for other RP and BART sources is not reasonable for Craig Unit 3 due to the recent upg rades. The Division also used the recent PSD permit limit of 6,752 tons for NO x and 2,125 tons for SO 2 to determine a baseline.Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 6 The notable difference is that the Division used the average capacity factor (based on heat input) from 2006 – 2008 to determine the base line emissions, resulting in 0.28 lb/MMBtu for NO x and 0.09 lb/MMBtu for SO 2 . Craig Unit 3 ran at an average of 86.4% capacity (based on heat input) from 2006 – 2008, thus th is factor is assumed to be a reasonable baseline for this planning period. The highe st 24-hour peak emi ssion rate during this timeframe was used for modeling visibility results. The Divi sion verified these emissions using Colorado’s Air Pollutant Emission No tices and EPA’s CAMD database. These emissions are summarized in Table 4.

Table 4: Tri-State Craig Unit 3 Baseline Emissions

Pollutant Unit 3 Annual Emissions* (tpy) Average Emissions (lb/MMBtu) NO x 5,693 0.283 SO 2 1,792 0.089 PM 10 148** 0.007** *The Division calculated annual (tpy and lb/MMBtu) NO x and SO 2 emissions using 2006 – 2008 capacity factor and current PSD permit limits. **The PM 10 emissions and emissions factor are from August 2009 stack test data; PM 10 current construction permit annual emission limit is 403 tons/year and 0.012 lb/MMBtu.

III. Units Evaluated for Control

Tri-State notes that the Crai g boilers burn Colorado coal th at primarily comes from the Trapper mine, supplemented by ColoWyo co al, which are both high-ranking subbituminous coal. Limited amounts of coal from the Twentymile mine, ranked as bituminous, are also burned. All of these mi nes are located in northwestern Colorado. The Trapper contract expires in 2014. Futu re nearby coal supplie s could come from sources such as Trapper, Colo Wyo, or Twentymile. Accordingl y, the trend of future coal supplies is such that in the context of NO x -forming characteristics, Craig 3 will continue to burn “bituminous-like” coal, plus, it is lik ely that additional quantities of bituminous coals will be burned at Craig 3 in the future. Similar to PSCo, Tri-State notes that these coals are ranked as sub-bituminous, but are clos er in characteristics to bituminous coal in many of the parameters influencing NO x formation. The specifications for these coals are listed below in Table 6. Note that with th e exception of moisture content, the coal characteristics are reasonably close for the two coals. The actual APEN coal specifications (2006 – 2008) ar e listed 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)

Craig Unit 3 10,224 0.39 6.47

Table 6: Craig Station Coal Specifications (2008) Coal Mine/Region Colowyo Trapper Twentymile Coal Rank Classification Sub-bituminous, Class A Sub-bituminous, Class A Bituminous H 2 O (Moisture %) 17.42 16.7 9.62 Ash (%) 5.71 6.5 11.93 Sulfur (%) 0.37 0.44 0.52 Nitrogen (%) 1.35 ~1.5 1.57Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 7 Heating Value (HHV Btu/lb) 10,392 9,800 11,084

Uncontrolled emission factors are outlined in Table 7. The factors are based on firing bituminous coal as well as the highest ash and sulfur content fr om the two coals for conservative estimates.

Table 7: Uncontrolled emission factors for Craig BART-eligible sources 2 Pollutant (lb/ton)* Emission Unit NO x SO 2 PM (filterable) PM 10 (filterable) Unit 3 12 14.7 64.7 14.9 *SO 2 and PM/PM 10 factors are determined by th e applicable AP-42 equation, where %S and %A are the % of sulfur and ash present in the coal supply, respectively, averaged from APEN data (2006 – 2008). Please refer to “Craig APCD Technical Analysis” for more details.

IV. Reasonable Progress Evaluation of Unit 3

A. Sulfur Dioxide (SO 2 )

Step 1: Identify All Available Technologies

The Division requested that Tri-State evalua te the option below, and received relevant information for this request on June 4, 2010: Dry FGD upgrades As discussed in EPA’s BART Guidelines 3 , 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 . However, upgrades need to be considered for the scrubber if technically feasible. These upgrades include: -Use of performance additives -Use of more reactive sorbent -Increase the pulverizati on level of sorbent -Engineering redesign of atomizer or slurry injection system

The current PSD permit SO 2 limits are depicted in Table 8.

Table 8: Craig Unit 3 SO 2 PSD Permit Limits SO 2 limits (lb/MMBtu) Reduction (%) Required 30-day rolling Annual Emission Limit (tons/year) Calendar day average Unit 3 0.20* 80 2,125 *May be exceeded once during any calendar month.

2 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

3 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 8 Step 2: Eliminate Technically Infeasible Options

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 plants 4 . 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 slaked lime slurry that is sprayed into the flue gas, subseque ntly dried by the heat of the flue gas, and then collected in a particul ate control device.

Craig Unit 3 was installed in 1984 with a “Spray Dryer Removal System” in connection with the aforementioned baghouse for control of the 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. Tri-State has since upgraded this syst em (between 2007 and 2009) and currently achieves greater than 80% SO 2 removal, with an actua l annual average of approximately 0.09 lb/MMBtu. This system exceeds EPA’s presumptive limits stated in 40 CFR part 51 Appendix Y of 0.15 lb/MMBtu 5 . Lime spray dryers have been determin ed to be Best Available Control Technology (BACT) for new Electric Genera ting Unit (EGU) sources proposed in the West according to EPA’s RBLC (RACT/BACT/LAER Clearinghouse) da tabase. The RBLC da tabase lists recent BACT determinations ranging from 0.06 – 0.167 lb /MMBtu, with an average of 0.11 lb/MMBtu on a 30-day rolling average. Refer to “Divis ion RBLC Analysis” for more details regarding recent RBLC BACT determinations. Additionally, an EPA Report regarding the control of SO 2 emissions found that lime spray drying processe s have a median design efficiency of 90% 6

. The BART Guidelines note potentia l upgrades for dry scrubbing systems 7 . These upgrades include: -Use of performance additives -Use of more reactive sorbent -Increase the pulverization level of sorbent -Engineering redesign of atomizer or slurry injection system

Tri-State examined BART-guideline dry scr ubbing potential 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. Tri-State and the Division are not aware of SO 2 scrubber performance additives applicable or commercially available for the Unit 3 SDA system.

4 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.

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

6 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.

7 EPA, 2005. Federal Register, 40 CFR Part 51. Regional haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule. Pgs. 39171.Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 9 -Use of more reactive sorbent/Increase the pulverization level of sorbent : The purchase and installation of two new vertical ball m ill slakers improved the ability to supply high quality slaked (hydrated) lime

. A higher quality slaked lime slurry means a more reactive sorbent. Typically, slakers are not designed for particle size reduction as part of the slaking process. However, the new vertical ball mill slakers are particularly suited for slaking lime that is a mixture of commercial peblle lime and lime fines. Fines are generated at the Craig facility in the pneumatic lime hand ling system. Therefore, the Division concurs that Tri-State cannot use a more reactive sorbent or increase the pulverization leve l of sorbent.

-Engineering redesign of atomizer or slurry injection system : Both the slaked lime slurry and recycled ash slurry preparation and de livery systems were redesigned to improve overall performance and reliability. The improved system allows for slurry pressure control at both the individual reactor level a nd for each slurry injection header level on each reactor. Tri-State notes that consistent control of slurry parameters (pressure, flow, composition) promotes consistent and reliab le SO2 removal performance. The Division concurs that with the recent redesign of the slurry injecti on system and expansion to two trains of recycled ash slurry preparation, no further redesigns are possible at this time.

Therefore, Tri-State and the Divi sion concur that th ere are not any techni cally feasible upgrade options for Craig Station Unit 3. However, the Division has evaluated the option of tightening the SO 2 emission limit for Craig Unit 3.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

The control effectiveness of tightening the 30-day rolling emission limit on Craig Unit 3 has been evaluated by the Division. The Division an alyzed the period after Tri-State upgraded the turbine (post-control: June 2009 – June 2010) against baseline emissions (2006 – 2008) to determine the maximum and average 30-day roll ing emission rates, shown in Table 9, to determine potential control effectiveness, if any. Additionally, the Division evaluated the baseline heat input, capacity factor, and hours of operation pre-upgrade (2006 – 2008) and postupgrade (June 2009 – June 2010) to evaluate whet her the data was consistent with baseline information, and whether there was enough informati on to determine if a tighter emission limit is warranted, in Table 10. This information allows the Division to set a more relevant emission limit for Craig Unit 3 using re presentative actual emissions.

Table 9: Craig Unit 3 30-day rolling emission rates (baseline 2006 - 2008) Unit and Timeline Maximum 30-day rolling emission rate (lb/MMBtu) Average 30-day rolling emission rate postcontrol (lb/MMBtu) Craig Unit 3 – post control (June 2009 – June 2010) 0.1350 0.1081

Craig Unit 3 – precontrol (2006 – 2008) 0.1412 0.1088Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 10 Table 10: Craig Unit 3 30-day rolling emission rates (baseline 2006 - 2008)

Unit and Timeline Capacity Factor (Heat Input %) Hours of Operation (% of total possible operating hours) Craig Unit 3 – June – D ecember 2009 98.1% 95.5%

Craig Unit 3 – January – June 2010 89.7% 96.1% Craig Unit 3 – June 2009 – June 2010 Average 93.9% 95.8% Craig Unit 3 – pre-control (2006 – 2008) 86.4% 96.3%

The Division notes that there are not significant differences be tween the maximum or average 30-day rolling emissions before and after the tu rbine and control upgrades. Similarly, the capacity factor and hours of operation do not ch ange discernibly. Therefore, the Division concludes that post-upgrade operations may be used in determining a tighter SO 2 emission limit in this reasonable progress.

Table 11 summarizes each available technology options and technical feasibility for SO 2 control on Craig Unit 3.

Table 11: Craig Unit 3 SO2 Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no) Wet FGD 52-98%, median 90% 8 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 pulverization level of sorbent None N

Engineering redesign of atomizer or slurry injection system None N

8 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 11 Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance A more stringent emission limit is not anticipated to result in any increased costs. Thus, this factor does not influence th e selection of controls.

Factor 2: Time Necessary for Compliance A more stringent emission limit is not anticipated to result in any system upgrades or changes and can be implemented as soon as the SIP is ap proved. Thus, this factor does not influence the selection of controls.

Factor 3: Energy and Non-Air Quality Impacts There is not any negative energy or non-air quality im pacts related to a more stringent emission limit. Thus, this factor does not influence the selection of controls.

Factor 4: Remaining Useful Life Tri-State asserts that there are no near-term limitations on the useful of this boiler, so it can be assumed that they will remain in service for th e 20-year amortization period. Thus, this factor does not influence the selection of controls.

Step 5 (optional): Evaluate Visibility Results

CALPUFF modeling was used to determine the proj ected visibility improve ment associated with emission limit tightening. The modeling guideline requires that modeled baseline emission rate is the 24-hour peak emission rate. The modeling guideline also requires that, at a minimum, the presumptive emission rate scenario be modele d. Table 12 shows the number of days pre- and post-control. Table 13 depict s the visibility results (98 th percentile impact and improvements). Cost effectiveness in $/deciview was not determ ined since there will minimal, if any, costs associated with emission limit tightening.

Table 12: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area

SO2 Control Scenario Boiler(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- hour SO2

rates 3 0.326 Mt. Zirkel Wilderness 239 --- --- 173 --- ---

Dry FGD 3 0.150 239 233 6 173 170 3 Dry FGD 3 0.070 239 230 9 173 168 5Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 12 Table 13: Visibility Results – SO 2 Control Options

SO2 Control

Scenario Boiler(s) SO2 Emission Rate (lb/MMBtu) Output (@ 98 th Percentile Impact)* 98 th Percentile Impact Improvement 98 th Percentile Improvement from Maximum

(dv) ( ∆ dv) (%)

Max 24-hour

SO2 rates 3 0.326 5.20 --- ---

Dry FGD 3 0.150 4.94 0.26 5% Dry FGD 3 0.070 4.82 0.38 7%

Step 6: Select RP Control Therefore, there are no technically feasible upgrade options for Crai g Station Unit 3. However, the state evaluated the option of tightening the emission limit for Craig Unit 3 and determined that a more stringen t 30-day rolling SO 2 limit of 0.15 lbs/MMBtu repres ents an appropriate and reasonable level of emissions control for this dry FGD control technology. Upon review of 2009 emissions data from EPA’s Clean Air Markets Di vision website, the state has determined that this emissions rate is achievable wi thout additional capita l investment.

Based upon its consideration of the five factors su mmarized herein, the state has determined that SO2 RP is dry FGD controls at the following SO2 emission rates: Craig Unit 3: 0.15 lb/MMBtu (30-day rolling average)

An SO2 limit lower than 0.15 lbs/MMBtu would not result in signi ficant visibility improvement (less than 0.2 delta deciview ) and would likely result in fre quent non-compliance events and, thus, is not reasonable.

B. Filterable Particulate Matter (PM 10 )

Craig Unit 3 is equipped with pulse jet fabric filter (PJFF) baghouses to control PM/PM 10 emissions. Baghouses, or fabric fi lters, operate on the same principl e as a vacuum cleaner. Air carrying dust particles is forced through a cloth bag. As th e air passes through the fabric, the dust accumulates on the cloth, providing a cleaner ai r stream. The dust is periodically removed from the cloth by shaking or by reversing the ai r flow. The layer of dust, known as dust cake, trapped on the surface of the fabric results in high efficiency rates for particles ranging in size from submicron to several hundred microns in diam eter. Additionally, fabric filters are the best PM control for western coals, due to the higher electrical resistivity.

Table 14 shows the most recent stack test data (2009). Real-time data demonstrates that these baghouses are meeting >95% control. The cu rrent Colorado construction permit limit is 0.013 lb/MMBtu for filterable PM emissions and 0.012 lb/MMBtu for filterable PM 10 emissions and also limits total PM and PM 10 (filterable and condensable) emissions to 0.022 and 0.020 lb/MMBtu respectively (Condition 4). The most r ecent stack test data is used to determineColorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 13 compliance with the permit limit, which at a mi nimum, occurs every five years, and more frequently depending on the results.

Table 14: Craig Unit 3 Stack Test Results (August 2009) Pollutant Unit 3 (lb/MMBtu) Total PM 0.013 Filterable PM 0.0091 Condensable PM 0.0035 Total PM 10 0.007 Filterable PM 10 0.0035 Condensable PM 10 0.0035 PM Control efficiency 99.5% PM 10 Control efficiency 98.8%

A Division review of EPA’s RBLC revealed recent BACT PM/PM 10 determinations ranging from 0.010 – 0.1 lbs/MMBtu, which are dependent on a number of factors, including PSD netting, EGU type and age, coal type, and adjacent controls (i.e. wet and dry FGD systems). The above stack test results are well below the range of recent BACT determinations. Refer to “Division RBLC Analysis” for more deta ils regarding BACT determinations.

The State has determined that the existing Unit 3 fabric filter baghouse and regulatory emissions limit of 0.013 (filterable PM) and 0.0 12 lb/MMBtu (PM10) represents the most stringent control option. The unit is exceeding a PM control effi ciency of 95%, and the control technology and emission limit is RP for PM/PM 10

.

C. Nitrogen Oxide (NO x )

Step 1: Identify All Available Technologies Tri-State identified five options for NO x control: New/modified Low NO x Burners (LNBs) with Overfire Ai r (OFA) system (next generation) Advanced OFA system or Rotating overfire Air (ROFA) Neural network system combustion controls Selective Non-Catalytic Reduction (SNCR) Selective Catalytic Reduction (SCR)

The Division also identified and examined th e following additional control options for these units: Electro-Catalytic Oxidation (ECO)® Rich Reagent Injection (RRI) Coal reburn +SNCR

Step 2: Eliminate Techni cally Infeasible Options LNBs with OFA Upgrades: TriState contracted with ACT to modify the existing Craig 3 burners and upgrade the OFA system. ACT determined that burners and OF A system could be upgraded. However, ACT has not modified ultra low-NO x Babcock & Wilcox 4Z burners such as those in use at Craig Unit 3. In addition AC T stated that a complete plant inspection, data review, baseline testing, and computational fl uid dynamics (CFD) modeling would be required for them to guarantee performa nce predictions. An amended proposal was submitted by ACTColorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 14 upon receipt of updated coal analyses that more closely represent the qu ality of coal being burned at Craig 1&2. In their am ended proposal, ACT again reiterat ed that “to give a guaranteed NO x reduction, a lot more information is required .” LNBs modifications with OFA upgrades appear to be technically feasible for Craig Unit 3.

Advanced OFA system – rotati ng overfire air system (ROFA): ROFA® injects air into the furnace first to break up the fireball and then to create a cyclonic gas flow to improve combustion. ROFA® differs from OFA in that ROFA® utilizes a booster fan to increase the velocity of air to promote mixing and to increase the retention time in the furnace. To date, ROFA® has only been installed as a retrofit te chnology on units firing eastern bituminous coals.

TriState contacted Motobec, the manufacturer of ROFA® technology, to de termine if ROFA is feasible for Craig Unit 3. Mobotec could not give TriState a definitive guarantee for reductions due to the variability in the quality of coals.

Based on data published by the manufacturer , ROFA® technology has been reported as achieving NO x emission reductions from 45 to 65 % based on fuel load 9 . While ROFA is considered superior to OFA/SO FA alone, ROFA alone is not s uperior to LNB+OFA and is not expected to increase emissions reductions for Cr aig Units 1 and 2. The Division asserts that ROFA® technology would not be expected to pr ovide better emissions performance than the LNB+OFA baseline for these un its, ROFA® technology is not considered further in this analysis.

Neural network system combustion controls: TriState received a neur al network proposal from NeuCo in April 2006. The proposal offers to e nhance the existing Craig 3 control system by providing combustion optimization technology. For a given set of objectives, a neural network directs the unit’s distributive control system (D CS) or other control systems to optimize the boiler performance.

Based on review of the Craig 3 current operations , NeuCo stated that Craig 1&2 appear to be good candidates for the optimization system. Key aspects to neural network success are the training support provided by the supplier, as well as achieving buy-in from plant operators. TriState states that it is impor tant to note that the condition of the unit(s) and the manner in which the unit(s) is operated prior to the installation of the combustion optimization system also play an important role in determining potential NO x reductions. Neural network system combustion controls appear to be te chnically feasible for Craig Unit 3.

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. NO x reductions of up to 60% have been ach ieved, although 20-40% is more realistic for most applications. Reagent utilization, a measure of the effi ciency with which the reagent reduces NO x , can have a significant impact on ec onomics, with higher levels of NO x reduction generally resulting in lower reagent utilization a nd higher operating cost. SCNR is considered a technically feasible alternativ e for Craig Unit 3. Tri-State con ducted a site-specific SNCR study

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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 15 in October and November 2010. The Division r eceived a summary of results on November 23, 2010 and the raw data on December 8, 2010.

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.

While a lower controlled NO x emission values have been demonstrated by SCR system applications in new coal units, for Craig, a re trofit SCR system, the 0.07 lb/MMBtu controlled NO x value is more expected, al though Tri-State asserts that the unit cannot achieve below 0.08 lb/MMBtu. See “Tri-State BART Submittals” for more details. The SCR reaction occurs within the temperature range of 550°F to 850°F where th e extremes are highly dependent on the fuel quality. SCR is a technically feasible alternative for Craig Unit 3.

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 10 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 11 and has not been demonstrated for other types of units. Therefore, RRI is considered t echnically infeasible for Units 1 and 2.

LNB/SOFA/LNB+SOFA: Craig Unit 3 is equipped with low-NO x burners with over-fire air (LNB+OFA) as part of a construction permit modification. Table 1 illustrates that this system achieves about 39% NO x reductions (based on actual emissions) on Unit 3.

Coal Reburn + SNCR: Several research and development ef forts 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 12 . However, this procedure has not been performed on a full-size pulverized coal-fired boiler yet and thus, is considered technically infeasible.

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

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

12 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.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 16 Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Tri-State provided the Division an nual average control estimates. In the Division’s experience and other state BART proposals, 13 30-day NO x rolling average emission rates are expected to be approximately 5-15% higher than the annual aver age emission rate. The Division projected a 30-day rolling average emission ra te increased by 15% for Crai g Unit 3 to determine control efficiencies and annual reductions.

LNBs with OFA Upgrades: TriState noted in the original BART submittal (July 31, 2006) that ACT proposed that a modified LNB with upgr aded OFA system could achieve 10 – 15% NO x reduction above current levels. Tri-State subm itted additional information regarding combustion control refinement, which the Division assume s is upgrades of the existing ULNBs, on December 8, 2010. These control refinements consist mostly of more precise control of fuel and air for combustion. This study conducted by Black & Veatch (B&V) notes that these refinements could achieve approximately 0- 2 % c ontrol. B&V explains that the reduction in control efficiency is due to the difference betw een “design criteria” versus permit limit. The Division notes that the Craig un its already have ultra-low NO x burners (ULNBs) installed, and as there is very little to no information on impr ovements to ULNBs, the Division accepts the amended B&V study for combustion control refinements from December 8, 2010.

Neural network system combustion controls: TriState noted in the original BART submittal (July 31, 2006) that NeuCo provided a neur al network proposal projecting that an optimization system could achieve 5 – 15% NO x reductions. Tri-State submitted additional information regarding neural network (NN) system combustion co ntrols on December 8, 2010. This study, conducted by Black & Veatch (B&V), notes that the NN eq uipment will be minimal, consisting of a few computer servers that will inte rface with existing systems in the same location(s). NN system combustion controls could achieve approximately 0 – 5% control. B&V explains that the reduction in control efficiency is due to the difference between “design criteria” versus permit limit. The Division notes that although limited in formation is available regarding NN systems, this information is very specific to individual units and is still consid ered emerging by industry standards. Therefore, the Division accepts th e amended B&V study control efficiency for NN system controls submitted on December 8, 2010.

SNCR: Tri-State stated in the May 14, 2010 submitta l that based on the boiler configuration, TriState could expect a continuous NO x reduction performance with SNCR technology in the range of 10 – 15%. This is based on Tri-State’s exte nsive research into the application of SNCR technology at Craig Station. The vast major ity of the research was focused on system performance and impacts on plant performance. Tri-State staff conducted a visit to First Energy’s Eastlake and Sammis power plants in Ohio; this visit was specifically design to evaluate boiler designs due to the similarity in boiler/burner configurations similar to the Craig Station boilers. These estimates are lower than EPA’s SNCR Air Pollution Control Technology Fact Sheet, which estimates SNCR between 30 – 50% control. Other Colorado facilities estimated SNCR as achieving between 17 – 40% NO x control. Control effectiveness has been historically noted to be lower for wall fired boilers similar to the Craig boilers; therefore the Divisions considers 15% to be a reas onable control effectiveness for SNCR.

13 State of North Dakota BART Determination for Le land Olds Station Units 1 and 2. Page 16.Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 17 SCR: Tri-State stated in the May 14, 2010 submittal th e expected emission rate for Craig Unit 3 when applying SCR are 0.08 lb/MMBtu. Tri-State did not specify if this estimate was a 30-day rolling averages, although, as stated in th e December 31, 2009 submittal, the baselines are averages of 30-day averages. The Division note s that several other Co lorado facilities have noted SCR expectations of 0.070 lb/MMBtu 14 or even lower. Additionally, a recent AWMA study found similar-sized EGUs achieve NO x reduction efficiencies greater than 85% with emission rates between 0.04 and 0.07 lb/ MMBtu (during the ozone season). 15 EPA’s AP-42 emission factor tables estima te SCR as achieving 75 – 85% NO x emission reductions. Table 15 depicts a comparison of SCR control efficiencies. The Division adjusted Tri-State’s estimate to 0.07 lb/MMBtu based on the reasoning above.

Table 15: SCR Control Efficiency Comparison Unit Baseline (lb/MMBtu) Control Efficiency (%) Resultant Emissions (lb/MMBtu) Tri-State Estimate Division Estimate Tri-State Estimate (annual average) Division Estimate (annual average) Craig Unit 3 0.283 71.8 75.2 0.080 0.070

Table 16 summarizes each available tec hnology and technical feasibility for NO x control.

Table 16: Craig Unit 3 NOx Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

LNB + OFA 25-45% Y – installed Air Staging – overfire air (OFA) 5-40% Y – installed

Ultra-Low NO x Burner (ULNB) Upgrade/Refinements 0 – 2% (TriState) Y

Neural network system 0 – 5% (TriState) Y

SNCR 10 – 40% Y Rotating overfire air (ROFA) 45 – 65% N SCR 75 – 90% Y Electro-Catalytic Oxidation (ECO)® n/a N

Rich Reagent Injection (RRI) n/a N Coal reburn+SNCR n/a N

14 Public Service Company of Colorado (April 20, 2010), Colorado Energy Nations Company (November 12, 2009), Colorado Springs Utilities (February 20, 2009), and Platte River Power Authority (January 22, 2009) all note that their individual EGUs can achieve 0.070 lb/MMBtu or even lower on a 30-day rolling average basis.

15 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 18 Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

Low NO x burner upgrades: Tri-State submitted additional information regarding combustion control refinement, which the Division assume s is upgrades of the existing ULNBs, on December 8, 2010. Through a literature review, the Division could not find any examples or support for upgrades on ultra-low NO x burners with overfire air. Ultra-low NO x burners are fairly new within the industry, so additional upgr ades have not yet been researched. The first commercial application for these bu rners was documented in May 2000. 16 Tri-State estimates that the initial cost of com bustion control refinement at about $2,200,000 with an annualized 20- year cost of $122,000. The Division notes that the Craig units alre ady have ultra-low NO x burners (ULNBs) installed, and as there is ve ry little to no information on improvements to ULNBs, the Division accepts the amended B&V study for combustion control refinement cost estimates from December 8, 2010.

Neural network system: TriState did not provide a quantitative evaluation of the application of a neural network system to the Division. There ar e three other facilities in Colorado alone using neural network systems from the same provider that TriState contacted. 17 It is unknown why TriState will provide further analysis of this syst em. Costs for these syst ems are very specific to individual units, so the Divisi on cannot estimate costs for th is option. Tri-State submitted additional information regarding neural networ k (NN) system combustion controls on December 8, 2010. Tri-State estimates that th e initial cost of neural networ k systems (per unit) at about $800,000 with an annualized 20-year cost of $280,000. The Division notes that although limited information is available regarding NN systems, this information is very specific to individual units and is still considered emerging by industry standards. Therefore, the Division accepts the amended B&V study cost estimates for NN system controls submitted on December 8, 2010.

SNCR: A typical breakdown of annualiz ed costs for SNCR on industr ial boilers will be 15 – 25% for capital recovery and 65 – 85% for operating expenses. 18 The Tri-State-estimated SNCR costs for operating expenses are 70% for Craig Unit 3. Since SNCR is an operating expense-driven technology, its cost varies directly with NO x reduction requirements and reagent usage. There is a wide range of cost effectiveness for SNCR due to different boiler configurations and sitespecific 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. 19

16 Bryk and Kleisley, 2000. “First Commercial Application of DRB-4ZTM Ultra-Low NOx Coal-Fired Burner.” Presented to POWER-GEN International 2000. November 14-16, 2000. Orlando, Florida.

17 NeuCo White Papers and Case Studies. http://www.neuco.net/library/ case-studies/default.cfm and Platte River Power Authority January 22, 2009 submittal: “Rawhide Unit 101 NOx Emission Control Cost and Technical Feasibility Information.”

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

19 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 19 The cost effectiveness for SNCR on Unit 3 (at 15% control efficiency) is approximately $4,887 per ton. Recent NESCAUM studies estimate SNCR re trofits on wall fired boilers (comparable to Unit 3) achieving 0.50 – 0.65 lb/MMBtu and emissi on reductions of 30 – 50% as costing $590 - $1,100 per ton of NO x reduced, depending on initial capit al costs and capacity factor. 20,21 It should be noted that Tri-State is estimating resultant emission rates lower than 0.30 lb/MMBtu for both boilers, therefore costs will be higher. EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NO x reduced. 22 On a linear scale, based on the NESCAUM estimates and assuming an achieved rate of 0.23 lb/MMBtu, the costs should be approximately $2,500 per ton. Tri-State and the Division’s revise d estimates are above this range; the Division inquired about the reagent and auxiliary power costs; Tri-State responded on July 30, 2010 adjusted the auxiliary power a nd lost generation costs for all of the Craig Units for both SNCR and SCR. Tri-State also provide d further information regarding the cost of potential reagent options. The costs for these two items remain hi gher than other Colorado facility estimates; however, Tri-State has provided adequate info rmation detailing the reasoning for power and reagent costs. The Division and Tri-State still do not completely concur on other cost items, including an annual 3% escalation rate for capital material, capita l labor, capital indirect, and operation and maintenance. Additionally, similar Co lorado facility cost estimates fall within the EPA SNCR Fact Sheet range. The Division will use Tri-State’s capital and operation/maintenance costs for this analysis in the absence of additional information at this time.

SCR: Recent NESCAUM studies estimate SCR retr ofits on wall fired boilers achieving NO x emission rates of 0.15 – 0.25 lb/MMBtu and emission reductions of 75 – 85% as costing $1,700 - $3,200 per ton of NO x reduced, depending on initial capit al costs and capacity factor. 23,24 25,26 It should be noted that Tri-State is estimating resultant emission rates lower than 0.15 lb/MMBtu for both boilers, therefore costs will be higher. Tri-State’s estimates ar e above this range; on a linear scale (achieving 0.07 lb/ MMBtu); the costs should be ap proximately $7,000 per ton. The Division’s revised cost estimates are close to this estimate; therefore, th e Division concludes that these cost estimates are reasonable.

Table 17 and Table 18 de pict controlled NO x emissions and control cost comparisons.

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

21 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.

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

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

24 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.

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

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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 20 Table 17: Craig Unit 3 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

--- 5,693 0.283 Combustion control refinements 2 5,579 0.277 0.32

Neural network system 5 5,408 0.268 0.31

SNCR 15 4,839 0.240 0.28

SCR 75 1,412 0.070 0.08

Table 18: Craig Unit 3 NO x Cost Comparisons Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

--- Combustion control refinements 114 $122,000 $1,071 $1,071

Neural network system 285 $280,000 $984 $925

SNCR 854 $4,173,000 $4,887 $4,887

SCR 4,281 $239,762,387 $6,952 $7,466

Factor 2: Time Necessary for Compliance Based on other Colorado facility submittals, 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 Tri-St ate approximately 3 - 5 years to implement any of the above control options. This timeframe may vary somewhat due to regional demand for natural gas and to schedule the necessary ma jor maintenance outage with other regionally affected utilities.

Factor 3: Energy and Non-Air Quality Impacts LNB Upgrades/Neural network system(s): There are no known non-air quality impacts associated with upgrades on low-NO x burner systems or neural network systems. Energy impacts are not significant. Thus, this factor doe s not influence the select ion of this control.

SNCR/ SCR: 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 poten tially somewhat lower for the low temperature alternatives. In addition, any fl ue gas reheat requirements for the low temperature applications may require significant energy inpu t to heat the flue gas.Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 21 Post-combustion add-on control technologies such as SNCR do incr ease power needs to operate pretreatment and injection equi pment, drive the pumps and fans necessary to supply reagents, overcome additional pressure drops caused by the control equipment, and provide steam in some cases. In particular, SCR systems require additi onal auxiliary power or power from the existing flue gas fan systems to overcome the pressure lo ss across the catalyst, to supply dilution air for mixing with the ammonia, and to pu mp ammonia into the vaporizer.

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 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.

Factor 4: Remaining Useful Life Tri-State asserts that there are no near-term limitations on the useful of this boiler, so it can be assumed that they will remain in service for th e 20-year amortization period. Thus, this factor does not influence the selection of controls.

Step 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 19 shows the number of days pre- and post-control. Table 20 depicts 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 estima tes. 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 19: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area

NOx Control Scenario Boiler(s) 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- hour 2nd 3 0.365 Mt. Zirkel Wilderness 239 --- --- 173 --- ---Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 22 half 2009 NOx rate

2009 New

LNBs 3 0.283 239 234 5 173 170 3

SNCR 3 0.240 239 233 6 173 166 7

SCR 3 0.070 239 224 15 173 149 24

Table 20: Visibility Results – NO x Control Options

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

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

(dv) ( ∆ dv) (%)

Max 24-hour 2nd half 2009 NOx

rate 3 0.365 5.20 --- ---

2009 New LNBs 3 0.283 4.99 0.21 4%

SNCR 3 0.240 4.88 0.32 6%

SCR 3 0.070 4.41 0.79 15%

Step 6: Select RP Control

Based upon its consideration of the five factors su mmarized herein, the state has determined that NOx RP for Craig Unit 3 is SNCR contro l at the following NOx emission rates: Craig Unit 3: 0.28 lb/MMBtu (30-day rolling average)

For SNCR at Unit 3, the cost per t on of emissions removed, coupled with the estimated visibility improvements gained, falls with guidance cost criteria discussed in section 8.4 above.

• Unit 3: $4,887 per ton NOx removed; 0.32 deciview of improvement

The dollars per ton control cost, coupled with notable visibility improvements, leads the state to this determination. To the extent practicable, an y technological applicati on Tri-State utilizes to achieve this RP emission limit shall be installed, maintained, and operated in a manner consistent with good air pollution control pr actice for minimizing emissions. Although SCR achieves better emission reductions, the expense of SCR was dete rmined to be excessive and above the guidance cost criteria discussed in section 8.4 of the Regional Haze State Implementation Plan.

V. Reasonable Progress Evaluation of Ash Ha uling & Storage (P204) and Limestone Hauling (P201)

Both of these fugitive dust sources are permitted within Colorado Operating Permit 96OPMF155.Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 23 Ash hauling (P204) is controlled with tw o methods to minimize fugitive emissions:

• Ash deposited in trucks for transport to disposal areas shall be sufficiently moist (Condition 8.2).

• The scrubber sludge/ash haul road servings Units 1, 2, and 3 shall be treated with magnesium chloride or equivalent as a dust suppressant. The magnesium chloride shall be applied according to manufacture r’s specifications. The frequency of application shall be according to manuf acturer’s recommendations (Condition 8.3).

Limestone hauling (P201) activities are contro lled several ways to minimize fugitive emissions:

• Opacity limitations of 20% except under certain operational conditions (U.S. EPA Reference Method 9) (C onditions 6.2, 11.2, and 11.3)

• Unloading facilities are vent ed to a baghouse (Condition 6.3)

• All process equipment shall be maintained a nd operated so as to minimize leakage of air contaminants to the atmosphere prior to their in the pollution control system (Condition 6.4)

These existing controls and corresponding emi ssion limits in Section II, Conditions 6 and 8 of Operating Permit 96OPMF155 represent the most stringent level of control available for these fugitive dust sources.

Therefore, the Division proposes that RP for these sources is no additional control and the current emission limit for the above units is RP.

VI. Reasonable Progress Evaluation of Units 1 & 2

Units 1 and 2 have been evaluated under Best Available Retrofit Technology (BART) provisions. BART for Units 1 and 2 can be found in Chapter 6 of the Regional Haze State Implementation Plan. The Division dete rmines that BART represents the most stringent available NO x , SO 2 , and PM/PM 10 control technologies and represents reasonable progress. Therefore, a full 4-fact or analysis is not needed to evaluate reasonable progress for NO x , SO 2 , or PM/PM 10 for Units 1 and 2 at Craig Station.