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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 1 Best Available Retrofit Technology (BART) Analysis of Control Options For Tri-State Generation & Transmission Associ ation, Inc. – Craig Station Units 1 & 2

I. Source Description

Owner/Operator: Tri-State Generati on & Transmission A ssociation, Inc. Source Type: Electric Util ity Steam Generating Unit SCC (EGU): 10100222 Boiler Type: Dry-Bottom Pulverized Coal -Fired Boilers, two opposed-wall-fired (Units 1 and 2)

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.

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 system, a nd the staging/landfilling area. Unit 3 is not subject to BART.

Error! Reference source not found. below lists the units at Tri-State Craig Station that the Division examined for control to meet BART-eligible requirements. Controlled and uncontrolled emission factors and CAMD data were used to evaluate the control effectiveness of the current emission controls. Table 1: Craig Boilers Technical Information
Unit 1 Unit 2

Placed in Service 1980 1979
Gross Boiler 4,417 4,417Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 2 Rating, MMBtu/Hr for coal

Electrical Power Rating, Net Megawatts 428 428

Description Babcock & Wilcox Pulverized Coal Opposed-Wall Dry Bottom, firing coal with natural gas, propane or No. 2 fuel oil used for startup, shutdown and/or flame stabilization. Babcock & Wilcox Pulverized Coal OpposedWall Dry Bottom, firing coal with natural gas,

propane or No. 2 fuel oil used for startup, shutdown and/or flame stabilization.

Air Pollution Control Equipment PM/PM 10 – Pulse Jet Fabric Filter Baghouse
NO x – Ultra-low NO x Burners with Over-Fire Air
SO 2 – Wet Limestone FGD All updated control equipment commenced full operations in 2004. PM/PM 10 – Pulse Jet Fabric Filter Baghouse
NO x – Ultra-low NO x Burners with Over-Fire Air
SO 2 – Wet Limestone FGD All updated control equipment commenced full operations in 2004.

Emissions Reduction (%)* NO x – 23.8% /53.9% SO 2 – 77.6%
PM – 99.6%

PM 10 – 99.4% NO x – 29.5%/54.7% SO 2 – 79.5%
PM – 99.9%

PM 10 – 99.5% *Emissions Reduction estimated by comparing pre-control 2001 – 2002 CAMD data to controlled 2006 – 2008 data. The first NO x number compares the additional reduction achieved by the ultra-low NO x burners vs. the original lowNO x burners and the second NO x number compares uncontrolled AP-42 fact or to actual average emission factor (2006 – 2008). 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.

Only Units 1 and 2 are BART-eligible, being fossil-fuel steam electric plants of more than 250 MMBtu/hr heat input with the pot ential to emit 250 tons or more of haze forming pollution (NO x , SO 2 , PM 10 ), and commenced operation in the 15-year period prior to August 7, 1977. These boilers also cause or contribute to visibility impairment at a federal Class I area at or above a 0.5 deci view change. Tri-State submitted a BART Analysis to the Division on July 31, 2006 w ith revisions, updates, and/or comments submitted on October 25, 2007, December 31, 2009, May 14, 2010, June 4, 2010, July 30, 2010, November 23, 2010, and December 8, 2010. The submittals are included as “TriState BART Submittals”.

II. Source Emissions

Tri-State estimated that a realistic depicti on of anticipated annual emissions for Units 1 and 2, or “Baseline” Emissions”, to be cons ervative, was the average of two previous (2004, 2005) of emissions data in the July 31, 2006 analysis. Several years have passed since the original BART submittal, in which the Division has updated modeling and technical analyses. Therefore, the Divisi on used years 2006 – 2008 (annual averages and 30-day rolling) for baseline emissions for reduction and cost calcu lations. The highest 24-hour peak emission rate during this timef rame was used for modeling visibility results. The Division verified these emissi ons using Colorado’s Air Pollutant Emission Notices and EPA’s CAMD database. These emissions are summarized in Table 2.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 3 Table 2: Tri-State Craig Units 1 and 2 Baseline Emissions

Pollutant Unit 1 Unit 2 Annual Emissions* (tpy) Average Emissions** (lb/MMBtu) Annual Emissions* (tpy) Average Emissions** (lb/MMBtu) NO x 5,190 0.278 5,372 0.271 SO 2 970 0.052 982 0.050 PM 10 80 0.006*** 40 0.005*** *Using daily CEMs data from 2006 – 2008 calendar years (CAMD data). **The Division calculated average emission rate (lb/MMBtu) from the 2006 - 2008 calendar years (CAMD data) based on average daily reported data for each unit for NO x and SO 2 emissions. ***The PM 10 emission factor is determined from the most recent Title V permit compliance stack tests (January 2004).

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 1&2 will continue to burn “bituminous-l ike” coal, plus, it is likely that additional quantities of bituminous coals will be burned at Craig 1&2 in the future. Similar to PSCo, Tri-State notes that these coals are ranked as sub-bitu minous, but are closer in characteristics to bituminous coal in many of the parameters influencing NO x formation. The specifications for these coals are listed below in Table 3. Note that with the exception of moisture content, the coal characteristics are reasonably close for the two coals.

Table 3: 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 1.57 Heating Value (HHV Btu/lb) 10,392 9,800 11,084

Uncontrolled emission factors are outlined in Table 4. 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 4: Uncontrolled emission factors for Craig BART-eligible sources 1 Pollutant (lb/ton)* Emission Unit NO x SO 2 PM (filterable) PM 10 (filterable) Unit 1 12 16.9 73.9 17.0

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 4 Unit 2 12 16.1 71.1 16.4 *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. BART Evaluation of Units 1 and 2

A. Sulfur Dioxide (SO 2 )

Step 1: Identify All Available Technologies

Wet FGD Upgrades – As discussed in EPA’s BART Guidelines 2 , electric generating units (EGUs) with existing controls achieving removal e fficiencies of greater than 50 percent are not required to remove these controls and replace th em with new controls. The Division interprets this to include fuel switching to natural gas, which would require significant boiler modifications, including removing the wet FGD.

However, based on Appendix Y [70 FR 39171], th e following dry scrubber upgrades should be considered for Craig Units 1 and 2 if tec hnically feasible. Th ese upgrades include: -Elimination of bypass reheat -Installation of liqui d distribution rings -Installation of perforated trays -Use of organic acid additives -Improve or upgrade scrubber auxiliary equipment -Redesign spray header or nozzle configuration

The current Operating Permit limits are depicted in Table 5.

Table 5: Craig Units 1 & 2 SO 2 Operating Permit Limits SO 2 limits (lb/MMBtu) Reduction (%) Required 90-day rolling 3-hr rolling 30-day rolling 90-day rolling Units 1 & 2 1.2 0.160 0.130 90

The current Operating Permit also requires that 100% of the flue gas in the FGD be treated (Conditions 1.3.3 and 2.3.3) and that the Craig Unit 1 and 2 FGDs be designed to meet at least a 97.3% removal rate (Conditions 1.3.4 and 2.3.4).

Step 2: Eliminate Techni cally Infeasible Options

FGD: Flue gas desulfurization removes SO 2 from flue gases by a variety of methods. The most common dry FGD system is a lime spray dry absorber uses that slaked lime slurry sprayed into the flue gas, which is subsequently dried by the heat of the flue gas, and then collected in a particulate control device. Generally, FGD control systems need to be located in close proximity

2 EPA, 2005. Federal Register, 40 CFR Part 51. Regi onal Haze Regulations and Guid elines for Best Available Retrofit Technology (BART) Determinations: Final Rule. Pgs. 39133.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 5 to the boiler exhaust gas stream to prevent condensation (e.g. coo ling of the exhaust gases) that result in acidic precipitation in the duct which results in corrosion issues.

Wet FGD: Wet FGD control systems must be locat ed after the baghouse because the moist plume resulting from the wet scrubber system would create baghouse plugging issues if the control is placed ahead of the baghouse. Each abso rber tower requires a similar “foot print” area, along with additional space for support equipment access, slurry preparation, mixing, associated tanks, dewatering and a chimney. Colorado Ute El ectric Association, which owned Craig before TriState, installed wet limestone FGD systems, on Craig Units 1 and 2 when the units began operations in 1980 and 1979, respectively. TriState upgraded these FGD systems in the 2003 – 2004 timeframe. This system exceeds EPA’s presumptive limits stated in 40 CFR Part 51 Appendix Y of 0.15 lb/MMBtu.

At the Division’s request, TriState submitted a SO 2 upgrade analysis to the Division on June 4, 2010 regarding potential upgrades for the wet FGD systems at Craig Station Units 1 and 2.

TriState examined potential upgrades to the Craig wet FGD systems, with the following results:

-Elimination of bypass reheat : The FGD system bypass was rede signed to eliminate bypass of the FGD system except for boiler safety situat ions. After the Yampa Environmental Project (YEP) Upgrades (2003 – 2004), 100 percent of th e flue gas now passes through the scrubber with no reheat and no bypassing.

-Installation of liquid distribution rings: Liquid distribution rings were not installed during the YEP; however, TriState determined that instal lation of perforated trays, described below, accomplished the same objective.

-Installation of perforated trays: Upgrades during the YEP included installation of a perforated plate tray in each scrubber module. The trays improve the absorption of SO 2 by increasing the contact between the flue gas and the limestone slurry. The trays also function like Slurry Distribution Rings by redirecting slurry from running down the absorber wall back to the flue gas flow stream.

-Use of organic acid additives: Organic acid additives such as Dibasic Acid (DBA) can be used to improve SO 2 removal efficiency by increasing scr ubbing liquor alkalinity. This option was considered for Craig Units 1 and 2 during YEP; however, it was not selected for the following

reasons: 1. DBA has not been tested at the very low inlet SO 2 concentrations seen at Craig Units 1 and 2. 2. DBA could cause changes in su lfite oxidation with impacts on SO 2 removal and solids settling and dewatering characteristics. 3. Installation of the perforated plate tray a ccomplished the same objective of increased SO 2 removal.

-Improve or upgrade scrubber auxiliary equipment: YEP included installation of the following upgrades on limestone processing and scrubber modules on Craig 1 and 2:Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 6 1. Two vertical ball mills were installed fo r additional limestone processing capability for increased SO 2 removal. The two grinding circuit trains were redesigned to position the existing horizontal ball mills and the vertical ball mills in series to accommodate the increased quantity of limestone required for increased re moval rates. The two mills in series also were designed to maintain the fine particle size (95% < 325 mesh or 44 microns ) required for high SO 2 removal
rates. 2. Forced oxidation within the SO 2 removal system was thought necessary to accommodate increased removal rates and maintain the dewatering characteristics of the limestone slurry. Operation, performance, and maintenance of th e gypsum dewatering equipment are more reliable with consistent sl urry oxidation. 3. A ventilation system was installed for each reaction tank. 4. A new mist eliminator wash system was in stalled due to the increased gas flow through the absorbers since flue gas bypass was eliminated, which increased demand on the mist eliminator system. A complete redesign and replacement of the mist eliminator system including new pads and wash system improved the reliability of the individual modules by minimizing down time for washing deposits out of the pads. 5. TriState installed new module outlet isolati on damper blades. The new blades, made of a corrosion-resistant nickel al loy, allow for safer entry in to the non-operating module for maintenance activities. 6. Various dewatering upgrades were completed. Dewatering the gypsum slurry waste is done to minimize the water content in waste solids pr ior to placements of the solids in reclamation areas at the Trapper Mine. The gypsum solids ar e mixed or layered with ash and used for fill during mine reclamation at Trapper Mine. The installed system was designed for the increased capacity required for increased SO 2 removal. New hydrocyclones and vacuum drums were installed as well as a new conveyor and stack out system for solid waste disposal. 7. Instrumentation and controls were modifi ed to support all of the new equipment.

-Redesign spray header or nozzle configuration: The slurry spray dist ribution was modified during YEP. The modified slurry spray distribution system improved slurry spray characteristics and was designed to minimize pluggage in the piping.

Therefore, TriState and the Divi sion concur that there are not any technically feasible upgrade options for Craig Station Units 1 and 2. Howe ver, the Division has evaluated the option of tightening the SO 2 emission limit for Craig Units 1 and 2.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

The control effectiveness of ti ghtening the 30-day rolling emissi on limits on Craig Units 1 and 2 have been evaluated by the Division. The Di vision analyzed the base line period (2006 – 2008) to determine the maximum and average 30-day rolling emission rates, shown in Table 6, to determine potential control effectiveness, if any. This information allows the Division to set a more relevant emission limit for Craig Units 1 and 2 using representa tive actual emissions.

Table 6: Craig Units 1 & 2 30-day rollin g emission rates (baseline 2006 - 2008) Unit Maximum 30-day rolling emission rate (lb/MMBtu) Average 30-day rolling emission rate (lb/MMBtu) Craig Unit 0.081 0.052Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 7 1 Craig Unit 2 0.093 0.079

Step 4: Evaluate Impacts and Document Results

Since there are not any remaining control technologies available for Craig Station Units 1 and 2, there are not any impacts to eval uate or results to document.

Step 5: 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, thepresumptive emission rate scenario be modeled. Table 7 shows the number of days pre- and postcontrol. Table 8 depicts the visibility results (98 th percentile impact and improvements). Cost effectiveness in $/deciview was not determined si nce there will minimal, if any, costs associated with emission limit tightening.

Per the April 2010 modeling protocol 3 , to isolate the effects of a given unit for controls on a given pollutant, the Division has judiciously cons tructed each emissions scenario to isolate the impact of a given BART control on a given unit. For example, to determine the effect of a SO 2 BART control technology on a given unit, em ission rates for the ot her pollutants (NO x and PM/PM 10 ) and other BART-eligible units are held constant at pre- control levels. For BART sources with more than one BART unit, modeli ng the units individually would ignore important atmospheric chemical reactions that occur when units operate simultaneously. The combination scenario assumed both boilers with NO x emissions at 0.07 lb/MMBtu (SCR control) and SO 2 emissions at 0.10 lb/MMBtu (wet FGD).

In situations where the BART-eligible units at a given BART-eligible source operate simultaneously, the sulfate and nitrate estimates from the modeling system will be more realistic, in general, if all BART units and all pollutants at a BART-eligible source are modeled together. The combined unit approach has the added bene fit of allowing Colorado to estimate the net degree of visibility improvement from the simu ltaneous operation of BART controls on multiple units for multiple pollutants at a given BART-eligible source.

Table 7: 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 1 0.166 Mt. Zirkel Wilderness 207 --- --- 123 --- --- 2 0.161

3 Colorado Air Pollution Control Division, Technical Se rvices Program, 2010. “Supplemental BART Analysis CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.”Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 8 Wet FGD 1 0.150 207 206 1 123 123 0

2 0.150 207 207 0 123 123 0

Wet FGD 1 0.120 207 204 3 123 123 0

2 0.120 207 204 3 123 123 0

Wet FGD 1 0.110* n/a

2 0.110* n/a

Wet FGD 1 0.100 207 203 4 123 123 0

2 0.100 207 203 4 123 123 0

Wet FGD 1 0.070 207 202 5 123 122 1

2 0.070 207 203 4 123 122 1

Combo 1 0.100 207 57 150 123 12 111 2 0.100 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “Craig BART Modeling Summary” for more details.

Table 8: 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 1 0.166 3.73 --- --- 2 0.161

Wet FGD 1 0.150 3.72 0.01 0%

2 0.150 3.72 0.01 0%

Wet FGD 1 0.120 3.70 0.02 1%

2 0.120 3.71 0.02 1%

Wet FGD 1 0.110* 3.70 0.03 1%

2 0.110* 3.70 0.03 1%

Wet FGD 1 0.100 3.69 0.03 1%

2 0.100 3.70 0.03 1%

Wet FGD 1 0.070 3.68 0.05 1%

2 0.070 3.68 0.05 1%

Combo 1 0.070 1.17 2.56 69% 2 0.070 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “Craig BART Modeling Summary” for more details.

Step 6: Select BART ControlColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 9 There are no technically feasible upgrade options for Craig Stati on Units 1 and 2. However, the state evaluated the option of tightening the emi ssion limit for Craig Units 1 and 2 and determined that a more stringen t 30-day rolling SO 2 limit of 0.11 lbs/MMBtu represents an appropriate level of emissions control for this wet FGD cont rol technology. The tighter emission limits are achievable without additional capital investment. An SO 2 limit lower than 0.11 lbs/MMBtu would likely require additional capital expendi ture and is not reasonable for the small incremental visibility im provement of 0.02 deciview.

B. Filterable Particulate Matter (PM 10 )

Craig Units 1 and 2 are each equipped with pulse jet fabric filter (PJ FF) baghouses to control PM/PM 10 emissions. Baghouses, or fabric filters, ope rate on the same principle as a vacuum cleaner. Air carrying dust partic les is forced 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 removed from the cloth by shaking or by reversing the air 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 diameter. Additionally, fabric filters are the best PM control for western coals, due to the higher electrical resistivity.

Table 9 shows the most recent stack test data (2 004). Real-time data de monstrates that these baghouses are meeting >95% control. The Title V permit limit is 0.03 lb/MMBtu (Condition 1.1.3). The most recent stack test data is used to determine compliance with the permit limit, which at a minimum, occurs every five years, and more frequently depending on the results.

Table 9: Craig Units 1 and 2 Stack Test Results (2004)

Pollutant Unit 1 (lb/MMBtu) Unit 2 (lb/MMBtu) Filterable PM 10 0.006 0.005 PM 10 Control efficiency 99.23% 99.35%

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 details regard ing BACT determinations. Both boilers must meet the PM emission standard of 0.03 lb/MMBtu in accordance with the Long-Term Strategy Review and Revision of Colorado’s SIP for Class I Visibility Protection Part I: Craig Station Units 1 and 2 Requirements (4/19/01), as approved by EPA at 66 FR 35374 (07/05/01).

The Division has determined that the existing Unit 1 and 2 pulse jet fabric filter baghouses and the emission limit of 0.03 lb/MMBtu (PM/PM 10 ) represents the most st ringent control option. The units are exceeding a PM control effici ency of 95%, and the control technology and emission limits are BART for PM/PM 10.

C. Nitrogen Oxide (NO x )

Step 1: Identify All Available TechnologiesColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 10 TriState 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

Craig Units 1 and 2 currently have ultra-low NO x burners with over-fire air (ULNBs+OFA) installed (2004) for NO x control purposes.

Step 2: Eliminate Techni cally Infeasible Options LNBs with OFA Upgrades: TriState contracted with ACT to modify the existing Craig 1&2 burners and upgrade the OFA system. ACT determ ined that burners and OFA system could be upgraded. However, ACT has not modified ultra low-NO x Babcock & Wilcox 4Z burners such as those in use at Craig Units 1 and 2. In addition ACT stated that a complete plant inspection, data review, baseline testing, and computa tional fluid dynamics (CFD) modeling would be required for them to guarantee performance predictions. An amended proposal was submitted by ACT upon receipt of updated coal analyses that more closely represent the quality 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 feas ible for Craig Units 1 and 2.

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 Units 1 and 2. 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 4 . 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.

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 11 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 1&2 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 1&2 current operati ons, NeuCo stated that Cr aig 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 techni cally feasible for Craig Units 1 and 2.

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. This 20-40% range in cludes units operating with LNB/combustion modifications. Reagent utilizati on, 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 uti lization and higher operating co st. SCNR is considered a technically feasible alternativ e for Craig Units 1 and 2. Tri- State conducted a site-specific SNCR study in October and November 2010. The Division received 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, two retrofit SCR system s, the 0.07 lb/MMBtu controlled NO x value is more expected, although TriSta te asserts that the units cannot achieve below 0.08 lb/MMBtu. See “TriSt ate BART Submittals” for more details. The SCR reaction occurs within the temperature range of 550°F to 850°F where the extremes are highly dependent on the fuel quality. SCR is a technically f easible alternative for Craig Units 1 and 2.

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 12 been demonstrated on a full-si ze pulverized coal-fired boiler 5 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 6 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 Units 1 and 2 are already equipped with ultra-low NO x burners with over-fire air (ULNB+OFA) as part of a consent decree. Requirements for these control systems were adopted into revisions to Colora do’s Visibility SIP, specified in a document entitled “Long-Term Strategy Review and Revisi on of Colorado’s State Implementation Plan for Class I Visibility Protection Pa rt I: Craig Station Units 1 an d 2 Requirements,” dated April 19, 2001. Table 1 illustrates that these systems achieve 39.7% and 41.1% NO x reductions (based on actual emissions) on Units 1 and 2, respectively.

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 7 . 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

TriState provided the Division annual average cont rol estimates. In the Division’s experience and other state BART proposals, 8 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 Units 1 and 2 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

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

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

7 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
8 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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 13 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: TriState 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 TriState’s extensive 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. Tr iState 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 simila r 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. Tri-State conducted a site-specific SNCR study in October and November 2010. The Division received a summary of results on November 23, 2010 and the raw data on December 8, 2010. The results of this study varied significantly depending on what coal type was utilized a nd were applicable for Craig Unit 1. Control effectiveness has been historically noted to be lower for wall fired boilers similar to the Craig boilers; therefore the Divisions considers approximately 15% to be a reasonable control effectiveness for SNCR.

SCR: TriState stated in the May 14, 2010 submittal the expected emission rates for Craig Units 1 and 2 when applying SCR are 0.08 lb/MMBtu. TriSta te did not specify if this estimate was a 30- day rolling averages, although, as stated in the 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 9 or even lower. Additionally, a recent AWMA study found similar-sized EGUs achieve NO x reduction efficiencies great er than 85% with emission

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 14 rates between 0.04 and 0.07 lb/MMBtu (during the ozone season). 10 EPA’s AP-42 emission factor tables estimate SCR as achieving 75 – 85% NO x emission reductions. However, an appropriate margin of error must be applied when evaluating SCR. The design goal emission rate may be lower than the permitted limit to ensure that unnecessary non-compliance periods do not become an issue, The Division may evaluate tighter emission limits in future RH planning periods if SCR is determined to be BART for e ither Craig Unit 1 or 2. At this time, the Division accepts Tri-State’s estimates of 0.08 lb/MMBtu on a 30-day rolling average. Table 10 depicts a comparison of SCR control efficiencies. The Division adjusted TriS tate’s estimate to 0.07 lb/MMBtu based on the reasoning above.

Table 10: SCR Control Efficiency Comparison Unit Baseline (lb/MMBtu) Control Efficiency (%) Resultant Emissions (lb/MMBtu) TriState Estimate Division Estimate TriState Estimate (annual average) Division Estimate (annual average) Craig Unit 1 0.278 71.4 74.9 0.080 0.070

Craig Unit 2 0.271 70.5 74.0 0.080 0.070

Table 11 summarizes each available tec hnology and technical feasibility for NO x control.

Table 11: Craig Units 1 and 2 NOx Techno logy Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Low NO x Burners/Ultra-low NO x burners (LNB/ULNB) 10-30% Y – installed

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 ~15% 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

Step 4: Evaluate Impacts and Document Results

Cost of Compliance

10 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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 15 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. 11 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. 12 It is unknown why TriState will provide further analysis of this syst em. Costs for these systems 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. 13 The TriState-estimated SNCR costs for operating expenses are 67% for Craig Units 1 and 2 (individually). 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 co st effectiveness for SNCR due to different boiler configurations and site-specific conditions, even with a given i ndustry. Cost effectiveness is impacted primarily by uncontrolled NO x level, required emission reductions, unit size and thermal efficiency, economic life of th e unit, and degree of retrofit difficulty. 14

The cost effectiveness for SNCR on Units 1 and 2 (at 15% control efficiency) is approximately $4,877 and $4,712 per ton, respectively. Recent NESC AUM studies estimat e SNCR retrofits on wall fired boilers (similar to Units 1 and 2) achieving 0.50 – 0.65 lb/MMBtu and emission reductions of 30 – 50% as costing $590 - $1,100 per ton of NO x reduced, depending on initial

11 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.

12 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.”

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

14 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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 16 capital costs and capacity factor. 15,16 It should be noted that TriState 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 cos ting from $400 - $2,500 per ton of NO x reduced. 17 On a linear scale, based on the NESCAUM estimates and assuming an achieved rate of 0.23 lb/MMBtu, the costs should be approximatel y $2,500 per ton. TriState and the Division’s revised estimates are above this range; the Divi sion has inquired about th e reagent and auxiliary power costs, but has not received feedback from TriState. The costs for these two items are higher than other Colorado facility estimates. Additionally, similar Colorado facility cost estimates fall within the EPA SNCR Fact Sheet range. The Division acce pts TriState’s capital and operation/maintenance costs for this analysis..

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. 18,19 20,21 It should be noted that TriState is estimating resu ltant emission rates lower than 0.15 lb/MMBtu for both boilers, therefore cost s will be higher. TriState’s estimates are above this range; on a linear scale (achieving 0.07 lb/MMBtu); the costs should be appr oximately $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 12, Table 13, Table 14, and Ta ble 15 depict controlled NO x emissions and control cost comparisons. Table 12: Craig Unit 1 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 --- 5,190 0.278 Combustion control refinements 2 5,087 0.273 0.31

Neural network system 5 4,931 0.264 0.30

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

16 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.

17 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf
18 Neuffer, Bill – ESD/OAQPS, 2003. “NO x Controls for Existing Utility Boilers.” http://www.epa.gov/ttn/nsr/gen/u3-26.pdf

19 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.

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 17 SNCR 15 4,412 0.236 0.27

SCR 74.9 1,305 0.070 0.08

Table 13: Craig Unit 2 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

--- 5,372 0.271
Combustion control refinements 2 5,264 0.265 0.31

Neural network system 5 0.257 0.30

SNCR 15 4,566 0.230 0.27

SCR 74 1,397 0.070 0.07

Table 14: Craig Unit 1 NO x Cost Comparisons Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0 ---
Combustion control refinements 104 $122,000 $1,175 $1,175

Neural network system 260 $280,000 $1,079 $1,015

SNCR 779 $3,797,000 $4,877 $6,776

SCR 3,893 $25,036,709 $6,432 $6,708

Table 15: Craig Unit 2NO x Cost Comparisons Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0 ---

Combustion control refinements 107 $122,000 $1,136 $1,136

Neural network system 269 $280,000 $1,043 $980

SNCR 806 $3,797,000 $4,712 $4,712

SCR 3,975 $25,036,709 $6,299 $6,702

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

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 18 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.

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.

Remaining Useful Life TriState asserts that there are no near-term limitati ons on the useful of these boilers, 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: 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 number of days pre- and post-control. Table 17 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.

Per the April 2010 modeling protocol 22 , to isolate the effects of a given unit for controls on a given pollutant, the Division has judiciously cons tructed each emissions scenario to isolate the impact of a given BART control on a given unit. For example, to determine the effect of a SO 2 BART control technology on a given unit, emi ssion rates for the other pollutants and other BART-eligible units are held constant at pre-cont rol levels. For BART s ources with more than

22 Colorado Air Pollution Control Division, Technical Se rvices Program, 2010. “Supplemental BART Analysis CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.”Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 19 one BART unit, modeling the units individually would ignore important atmospheric chemical reactions that occur when units operate simulta neously. The combination scenario assumed both boilers with NO x emissions at 0.07 lb/MMBtu (SCR control) and SO 2 emissions at 0.10 lb/MMBtu (wet FGD control).

In situations where the BART-eligible units at a given BART-eligible source operate simultaneously, the sulfate and nitrate estimates from the modeling system will be more realistic, in general, if all BART units and all pollutants at a BART-eligible source are modeled together. The combined unit approach has the added bene fit of allowing Colorado to estimate the net degree of visibility improvement from the simu ltaneous operation of BART controls on multiple units for multiple pollutants at a given BART-eligible source.

Table 16: 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 1 0.352

Mt. Zirkel Wilderness 207 --- --- 123 --- --- 2 0.345

SNCR 1 0.236 207 192 15 123 123 0 2 0.230 207 194 13 123 123 0 SCR 1 0.07 207 165 42 123 123 0 2 0.07 207 166 41 123 123 0

Combo 1 0.07

207 57 150 123 12 111 2 0.07

Table 17: 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 Cost Effectiveness

(dv) ( ∆ dv) (%) ($/dv)

Max 24-

hour 1 0.352 3.73 --- --- ---

2 0.345

SNCR 1 0.236 3.42 0.31 8% $12,327,922 2 0.230 3.42 0.31 8% $12,327,922 SCR 1 0.07 2.72 1.01 27% $24,887,384 2 0.07 2.75 0.98 26% $25,652,365

Combo 1 0.07

1.17 2.56 69%

$19,537,034 2 0.07

Step 6: Select BART ControlColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 20 While potential modifications to the ULNB burners and a neural network system were also found to be technically feasible, these options did not provide the same level of reductions as SNCR or SCR, which are included within the ultimate BART Alternative determination for Units 1 and 2. Therefore, these options were not further considered in the technical analysis.

Based upon its consideration of the five factors su mmarized herein, the state has determined that NOx BART is SNCR controls at the following NOx emission rates: Craig Unit 1: 0.27 lb/MMBtu (30-day rolling average) Craig Unit 2: 0.27 lb/MMBtu (30-day rolling average) For SNCR at Units 1 and 2, the cost per ton of emissions removed, coupled with the estimated visibility improveme nts gained, falls within the guidance criteria presented in Chapter 6 of the Regi onal Haze State Implementation Plan.

• Unit 1: $4,877 per ton NOx removed; 0.31 deciview of improvement

• Unit 2: $4,712 per ton NOx removed; 0.31 deciview of improvement The dollars per ton control costs, coupled with no table visibility improvements, leads the state to this determination. To the extent practicable, an y technological applicati on Tri-State utilizes to achieve these BART emission limits shall be in stalled, maintained, and operated in a manner consistent with good air pollution control practic es for minimizing emissions. Although emission limits associated with SCR achieve better emissions reductions, the cost-effectiveness of SCR for this BART determination was determined to be excessive and above the cost guidance criteria presented above. The state reached this conclusion after consid ering the associated visibility improvement information and after co nsidering the SCR cost information in the SIP materials and provided during the pre-hearing and hearing process by the company, parties to the hearing, and the FLMs.

Per Section 308(e)(2) of EPA ’ s Regional Haze Rule, as an a lternative to BART (or “BART alternative”) it was proposed and the state agreed to a more stringent NO x emissions control plan for these BART units that consists of emission li mits assumed to be associated with the operation of SNCR for Unit 1 and the opera tion of SCR for Unit 2. These NO x emission rates are as follows: Craig Unit 1: 0.28 lb/MMBtu ( 30-day rolling average) Craig Unit 2: 0.08 lb/MMBtu ( 30-day rolling average)

Unit 1 ’ s 0.28 lb/MMBtu NO x emission rate equates to a 14% control and a NO x reduction of 727 tons per year, which is slightly less than the 15% control and a NO x reduction of 779 tons per year associated with the 0.27 lb/MMB tu BART emission rate determination. Unit 2 ’ s 0.08 lb/MMBtu NOx emission rate equates to a 74% control and a NO x reduction of 3,975 tons per year, which is much greater than the 15% control and a NO x reduction of 806 tons per year associated with the 0.27 lb/MMB tu BART emission rate determination. The total NO x emission reduction resulting from the BART determination is 1,585 tons per year (779 + 806 = 1,585 tons per year). The total NO x emission reduction resulting from the BART Alternative is 4,702 tons per year (727 + 3,975 = 4,702 tons per year). Given the far greater emission reduction achieved by the BART Alternative when compared to the BART determinations for the individual units, the stat e determines, in accordance with the federal Regional Haze regulations, that the BART Altern ative emission rates are appropriate for CraigColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) An alysis – TriState Craig Station Page 21 Units 1 and 2 as providing greater reasonable progress than the appl ication of BART as set forth in the federal BART Alternative regulation.

The state also evaluated the NO x emission reduction associated with both units (Craig 1 & 2) in contrast to the existing NO x rates, presumptive BART NO x rate, source-by-source determination, and the final RH determination to determine the total NO x reduction benefit. In the below table, the existing NO x emissions from both units is 10,562 tons/year which is much lower than the existing presumptive BART emissions of 14,849 tons/year. The source-by-source BART determination resulted in NO x emissions of 8,978 tons/year which is well above the 5,860 tons/year in NOx emissions calculated to result fr om application of the BART Alternative. These tons/year calculations provide an emissions ba sed comparison to demonstrate that the Craig BART Alternative provides greater reasonable progress than, and is superior to, source by source BART for these units. The table below is illustra tive for demonstration purposes only. The tons per year projections provide an emission based comparison and are not enforceable requirements.