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

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 1 Best Available Retrofit Technology (BART) Analysis of Control Options For Colorado Energy Nations, Golden, Colorado

I. Source Description

Owner/Operator: Colorado Energy Nations Company (CENC) (formerly Trigen Colorado Energy Corporation) Source Type: Steam Generating Unit Boiler Type(s): Boiler 4 – Pulverized Coal Dry-Bottom Tangentially-Fired (SCC: 10200222 for coal) Boiler 5 – Pulverized Coal Dry-Bottom Tangentially-Fired (SCC: 10200222 for coal)

The CENC facility is loca ted in Jefferson County on 10 th Street in the town of Golden, Colorado. Figure 1 below provides an aerial perspective of the CE NC site. The two large buildings are separated by Clear Creek to the south and US Highway 58 borders the northern side of the CENC site. The large building to the north of CENC and south of Highway 58 is the Coors Brewery.

Figure 1: CENC facility Aerial Perspective

The CENC facility consists of five (5) boile rs and the associated equipment for coal and ash handling. The boilers provide steam fo r one (1) 20 MW generator, two (2) 10 MW generators, and for industrial use. The boile rs are rated at 228 MMB tu/hr (Boilers 1 and 2), 225 MMBtu/hr (Boiler 3), 360 MMBtu/hr (Boiler 4) and 650 MMBtu/hr (Boiler 5). Boilers 1 and 2 normally operated in hot sta ndby mode or when one of the coal boilers (Boilers 3, 4, or 5) is down. Boile rs 3, 4, and 5 are controlled for PM/PM 10 by separateColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 2 fabric filter baghouses, which were installed at the time of construction for each boiler. The boilers were installed as follows:

• Boiler 1 – 1962

• Boiler 2 – 1962

• Boiler 3 – 1962 – updated to coal in 1981

• Boiler 4 – 1974 – last modification in 1975

• Boiler 5 – 1979 – reached full capacity in 1980

No coal processing is performed on-site. Th e coal is received ready for feed to the boilers. Boilers 4 and 5 are equipped with pulve rizers that process th e coal directly into the fire zone. The ash and flyash from the bo ilers may be sold or transported off-site for disposal. Therefore, all fugitive dust sources at the facility are related to coal conveying or ash handling. There is also one Detroit Di esel engine (<100 HP) at the facility for maintenance of equipment and/or backup opera tion of air compressors that was installed prior to 1970. This engine is tested weekl y. The Coors Brewery currently contracts for the purchase of the total elec tricity and steam output.

Boilers 4 and 5 are considered BART-eligible, being industria l boilers 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 period prior to A ugust 7, 1977. Initial ai r dispersion modeling performed by the Division demonstrated that the CENC facility contributes to visibility impairment (a 98 th percentile impact equal to or gr eater than 0.5 deciviews) and is therefore subject to BART. Trigen (now CENC) submitted a BART Analysis to the Division on July 31, 2006. CENC also pr ovided information in “NOx Technical Feasibility and Emission Control Costs fo r Colorado Energy Nations, Golden, Colorado” Submittal provided on November 16, 2009 as well as additional information upon the Division’s request on February 8, 2010 a nd May 7, 2010. These documents are all provided as “CENC BART Submittals”. Tabl e 1 depicts technical information for each BART-subject boiler at the CENC facility.

Table 1: CENC Facility BART-eligible Emission Controls and Reduction (%) Unit B004 Unit B005 Placed in Service 1975 1979 Boiler Rating, MMBtu/Hr for coal 360 650

Electrical Power Rating, Gross Megawatts 35 65

Description Combustion Engineering Model CE-VU40 360 MMBtu/hr (coal), tangential fired, firing coal, natural gas, #2 fuel oil, ethanol, on-site generated on-spec used oil and sludge from WWTP Combustion Engineering Model CE-VU40 650 MMBtu/hr (coal), tangential fired, firing coal, natural gas, #2 fuel oil, ethanol, on-site generated on-spec used oil and sludge from WWTP Air Pollution Control Equipment Wheelabrator-Frye Model 264 fabric filter baghouse with 8 compartments Carter Day fabric filter baghouse with 12 modules

Monitoring Equipment COM CEMs for SO 2 , NO x , CO 2 , and stack gas COM CEMs for SO 2 , NO x , CO 2 , and stack gasColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 3 Emissions Reduction (%) NO x – None SO 2 – None PM/PM 10 – 99+% NO x – None SO 2 – None PM/PM 10 – 99+%

II. Source Emissions

CENC estimated that a realisti c depiction of anticipated a nnual emissions for Boilers 4 and 5, or “Baseline Emissions”, to be cons ervative, was the maximum historical (2000 – 2005) 12-month (rolling) emissions experienced in the July 31, 2006 analysis. CENC also provided 2-year annual averag e emissions for comparison purposes.

Several years have passed since the original BART submittal, in which the Division has updated modeling and technical analyses. Therefore, the Division used years 2006 – 2008 (annual averages and 30-day rolling) for ba seline emissions for reduction and cost calculations. The highest 24-hour peak emissi on rate during this timeframe was used for modeling visibility results. The baseline emissions are used as the basis for estimating annual emission reductions for the various control technologies evaluated and determining the annualized costs to achieve those reductions. . The Division verified these emissions using Colorado’s Air Pollutant Emission Notices and EPA’s CAMD database as applicable. These emi ssions are summarized in Table 2.

Table 2: CENC Boilers 4 and 5 Baseline Emissions

Pollutant Boiler 4 Boiler 5 Annual Emissions* (tpy) 30-day rolling

average emissions** (lb/MMBtu) Annual Emissions* (tpy) 30-day rolling

average emissions** (lb/MMBtu) NO x 600 0.50 691 0.34 SO 2 781 0.64 1,406 0.71 PM 10 11 0.003*** 18 0.01*** *Using most recent three cal endar years (CEMs data). **The Division calculated 30-day rolling average rate (lb/MMBtu) from the most recent three calendar years (CEMs data) based on maximum daily reported data for each unit for NO x and SO 2 emissions. Days with zero emissions/heat input were not included in these averages. ***The PM 10 emission rate is determined from calculating the maximum heat input and annual operating hours.

Boiler 4 is mainly fired on coal and can be fire d on natural gas. Fuel oil may be used as a backup fuel, but has not been used in recent y ears. Boiler 5 is fired on coal, with backup oil firing. Either boiler also may fire etha nol or sludge from the Coors Brewery. Both units are subject to Colorado Regulation 6 Part A and NSPS 40 CFR Subpart D.

III. Units Evaluated for Control

As documented by CENC, these boilers fire low sulfur, high heating value bituminous coal from western Colorado. The specificati ons for the coal are listed in Table 3.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 4 Table 3: Coal Specifications (2006 – 2008 Averaged APEN data) Specifications Emission Unit Fuel Heating Value (Btu/lb) Sulfur (% by weight) Ash (% by weight)

B004 11,703 0.42 9.14 B005 11,833 0.42 9.17

Table 1 lists the units at the CE NC facility that the Division examined for control to meet BART-eligible requirements. Controlled a nd uncontrolled emission factors and CEMs data were used to evaluate the control effectiveness of the current emission controls. Uncontrolled emission factors are outlined in Table 4. The factors are based on firing bituminous coal.

Table 4: Uncontrolled emission factors for CENC BART-eligible sources

Emission

Unit Pollutant Fuel Natural Gas (lb/MMscf) Coal (bituminous) (lb/ton) #2 Fuel Oil (lb/Mgallons)

Boiler 4 &

Boiler 5 NO x 280 8.4 24 SO 2 0.6 35 x %S = 14.7* 157 x %S = 67.5* PM/PM 10 7.6 PM – 10 x %A = 91.4** PM 10 – 2.3 x %A = 21.0** PM – 2 PM 10 – 1 *%S = % of sulfur present in coal supp ly. For example, 35 x 0.42 = 14.7 **%A = % of ash present in coal supp ly. For example, 10 x 9.14 = 91.4

IV. BART Evaluation of Boiler 4 and Boiler 5

A. Sulfur Dioxide (SO 2 )

Step 1: Identify All Available Technologies

CENC identified four SO 2 control options: Flue gas desulfurization (FGD): Lime spray dry absorber (SDA or dry FGD) Dry sorbent injection – Trona (DSI) SO 2 emission management

The Division also identified and examined additional control options for these units: Lime or limestone-based (wet FGD) Emission limit tightening (no control)

Step 2: Eliminate Techni cally Infeasible Options

FGD: Flue gas desulfurization removes SO 2 from flue gases by a variety of methods. Wet scrubbing uses a slurry of alkaline sorbent, either limestone or lime, to scrub the gases. 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 proximityColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company 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.

Dry FGD: Dry FGD systems are commonly known as sp ray dry absorbers (SDA) or lime spray dryers (LSD), and currently make up about 12% of FGD systems at U.S. power plants 1 . SDA systems are typically utilized at smaller units th at burn lower-sulfur coal in the western U.S., where water resources are limited. Additionally, Controlling SO 2 Emissions: A Review of Technologies 2 evaluates various SO 2 control technologies and show s that for low-sulfur coal applications, LSDs can meet comparab le emission rates to wet systems.

A SDA system must be located before the boiler flue gases enter the ba ghouse. Each reactor vessel requires a “foot print” area comprisi ng about 2,000 to 4,000 square feet (depending on volume of flue gas treated) along with additi onal space for support equipment access, slurry preparation, mixing and associated tanks.

The plant is bounded to the north by US Highway 58 and Coors Brewery buildings, to the west by 12 th street and a small parking, to the east by Coors rail yard lots, and the south by Clear Creek and the Coors Brewery. Tr ain tracks also bound the facility to the north and east. Figure 1 illustrates these boundaries. Figure 2, depictin g a detailed view of the boilers, respective baghouses, and available spaces for FGD systems, indicates that availa ble physical space is severely constrained at the CENC facility, due to locations as we ll as pollution control retrofits for particulate matter. The entire site is ve ry congested, with limited access and limited room for major retrofits of new capital equipment. CENC asserts that in order to allow sufficient residence time for evaporation and reaction with SO 2 , the design gas residence time in a SDA is approximately 10 seconds. For Boilers 4 and 5, a SDA vessel for each boiler, not including other associated equipment, would be approximately 35 feet in diameter by 60 feet high. In addition, in order to provide high reagent utilization, the unreacted lime mixed with ash form the baghouse must be recycled. This would increase solids loading in ea ch baghouse by a factor of 3 and require extra baghouse capacity and a complete reconstruction of the ash handling system. Subsequently, CENC determined that it is not te chnically feasible to install dry FGD systems on either Boilers 4 or 5 (B004/B005).

In 2007, the Division conducted an on -site visit to determine the te chnical feasibility of potential SO 2 controls on Units 4 and 5. The Division noted:

1 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. 2 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

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 6 • CENC determined dry FGD controls are not technically feasible as discussed above, therefore control effectiveness and impacts are not evaluated in this analysis. After the site visit, the Division concurred with this conclusion.

• Traditional wet FGD controls ar e possible considering that th ere is adequate space near the baghouse to allow for the in stallation of controls, but are eliminated based on other considerations within the five factors (i.e. energy and non-air quality impacts). Refer to the energy and non-air quality impact section for the Division review regarding wet FGD controls for Boilers 4 and 5.

Figure 2: Aerial Zoom of CENC Facility

DSI: Dry sorbent injection involves th e injection of typically a sodi um based reagent, either the mineral trona (sodium sesquicarbonate) or refine d sodium bicarbonate, into the flue gas. The injected reagent reacts with the SO 2 present in the flue gas to create sodium sulfate, which is then collected in the particulate contro l device, in the case of CENC. CENC asserts that the flue gas temperatures present upstream of the boiler airh eaters are in the appropriate range to allow for DSI application. A very importa nt factor in DSI application is the ability for the boiler’s particulate control device to accommodate the ad ded particulate loading of the DSI reagent in addition to the flyash loading. CENC’s prelimin ary review indicates that even with the added loading of DSI reagent, the CENC baghouses w ould be operating within the design specification for particulate loading, but the ash collection sy stem(s) would require modifications. The flue gas is not cooled nor saturated wi th water, so reheating of desulf urized flue gas is not required. No gas-sorbent contacting vessel is required to be installed. DSI requires less capital equipment, less physical space, and less medication to exis ting ductwork compared to a SDA system.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 7 However, reagent costs are much higher and depending upon the absorbent and amount of sorbent injected, control efficiency is lower when compared to a SDA system. Lime, soda ash, and Trona (sodium sesquicarbonate) are possible. Lime is the least reactive reagent resulting in low efficiencies even at high injection rates. Tron a is a very reactive reagen t that can be used to achieve a range of efficiencies depending on the amount of sorben t injected, and would likely be the chosen reagent.

Due to variability of boiler c onfigurations, coal composition, NO x to SO 2 ratios, and other factors, it is difficult to arrive at a precise estimate of the maximum SO 2 removal rate that is achievable while minimizing the brown plume cond ition. However, based on literature review, CENC estimated the maximum SO 2 removal rate that can be achieved while minimizing the creation of the brown plum e condition to be 65% SO 2 removal. In practical application, a higher SO 2 removal rate may be possible, while it is also possible that a lower SO 2 removal rate may be necessary to limit the brown pl ume formation. This determination would require actual SO 2 removal real-time testing. CENC consulted with PPC Industries to determ ine the feasibility and emission reduction potential associated with in stalling DSI-Trona contro ls. Therefore, DSITrona is technically feasible for the CENC facility Boilers 4 and 5.

SO 2 Emissions Management: CENC is subjected to variations in as-received coal sulfur content. Figure 3 provided by CENC shows that there ar e clearly historical (2000 – 2005) short-term peaks in SO 2 emissions that can be attributed to infre quent deliveries of high- sulfur coal. CENC has no capability or additional storage space on site to store coal or to blend with other lower sulfur coals in order to manage SO 2 emissions to lower levels, and has not had a regulatory need to do so. Once delivered, the facility has no ch oice but to use the coal delivered before a subsequent lower sulfur shipment can be obtained and burned.

Figure 3: Boilers 4 and 5 SO 2 lb/hour daily average (2000 - 2005)Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 8 Using alternative approaches to operations ma nagement, CENC proposes a new, enforceable permit limit to reduce peak lb/hr SO 2 emissions. CENC can employ a variety of options to reduce emissions: dispatch natural gas-fired cap acity, reduce total system load, and/or reduce coal firing rate to maintain a new peak SO 2 limits. Since these two boilers already have CEMs and stack flow monitors installed, the CEMs could be used to demonstrate continuous compliance. CENC proposes reducing peak leve ls with limits at 280 lb /hr for Boiler 4 and 500 lb/hour for Boiler 5 on a 24-hour aver age basis. This option is tec hnically feasible for Boilers 4 and 5.

Emission limit tightening : The Division and CENC conducted tech nical analyses of sulfur % and heat content in historical coal supp lies to determine whether the current SO 2 emission limit could be more stringent based on actual emissions ( 2006 – 2008) from the units. This option is technically feasible for Boilers 4 and 5.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

CENC provided the Division annual average control estimates. In the Division’s experience, 30- day SO 2 rolling average emission rates are expected to be approximately 5% higher than the annual average emission rate. The Division projec ted a 30-day rolling average emission rate increased by 5% for CENC Boilers 4 and 5 to determine control efficiencies and annual reductions.

The Division has reviewed the data supplied by CENC as well as ot her control techniques applied to pulverized coal boile rs. A Division review of the EPA’s RBLC revealed recent BACT SO 2 determinations range from 0.06 – 0.167 lbs/ MMBtu. The Division narrowed down this range depending on the averaging time, permit type, facility size, and fuel type. This narrowed range is 0.095 – 0.161 lbs/MMBtu, with an average of 0.119 lbs/MMBtu rounded to 0.12 lbs/MMBtu. While determinations made by other st ates do not dictate the emissions rate choice made by the Division, they do provide information on the range to validate the emissions rate chosen by the Division. Refer to “Division RBL C Analysis” for more details. The Division notes that for CENC, any RBLC determ inations apply for DSI only, since SO 2 emissions management is unit-specific.

DSI: CENC asserts that the maximum SO 2 removal rate that can be achieved to be 65% SO 2 removal due to the small size of the boilers, and non-ideal gas/solids residence time. The Division adjusted this removal rate to 60%, based on other Colorado submittals 3 and to be conservative since this tec hnology is relatively novel.

SO 2 Emissions Management : Table 5 summarizes current Title V permit limits and projected emission reductions using CENC’s proposed limits.

3 Colorado Springs Utilities, 2010. “RE: Question Regardin g the Application of Dry Sorbent Injection to Martin Drake Power Plant Unit 5.” Submitted to the Colorado Air Pollution Control Division on May 10, 2010.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 9 Table 5: CENC Boiler 4 an d 5 Current vs. Proposed SO 2 Permit Limits and Emissions Reduction Unit Current Title V SO 2 permit limits Actual Emissions (2000 – 2005) Actual Emissions (2006 – 2008) CENC proposed SO 2 limits

Boiler 4 1892.0 tons/year (approx. 432 lb/hour) 911.8 tons/year (approx. 208 lb/hour) 780.6 tons/year (approx. 178 lb/hour) 280 lb/hour (CEM 24-hr rolling avg.) Coal – 1.2 lb/MMBtu (CEM 3-hr rolling avg.) Fuel Oil – 0.8 lb/MMBtu (CEM 3-hr rolling avg.) Boiler 5 3,416.0 tons/year (approx. 780 lb/hour) 1,954.7 tons/year (approx. 446 lb/hour) 1,406.0 tons/year (approx. 321 lb/hour) 500 lb/hour (CEM 24-hr rolling avg.) Coal – 1.2 lb/MMBtu (CEM 3-hr rolling avg.) Fuel Oil – 0.8 lb/MMBtu (CEM 3-hr rolling avg.) Combined limit 4,888.0 tons/year (approx. 1,116 lb/hour) (PM 10 SIP Agreement) 2,866.5 tons/year (approx. 655 lb/hour) 780 lb/hour (CEM 24-hr rolling avg.)

*Refer to pages A-31, A-34, and A-35 of CENC BART Submittal (July 31, 2006) for detailed SO 2 emission documentation.

Emission limit tightening: Since emission limit tightening is ba sed on actual data, there will be minimal, if any, reductions from baseline period (2006 – 2008) SO 2 emissions. The Division found that the maximum 30-day rolling emission rate was 0.80 lb/MMBtu for Boiler 4 and 0.9 lb/MMBtu for Boiler 5. However, for these sma ll industrial boilers with very limited coal storage capacity, the Division and CENC agree that reviewing sulfur % a nd heat content is a better basis for determining an appropriate SO 2 emission limit. CENC submitted supplemental information on October 26 and November 10, 2010 to support this methodology. Refer to Table 6 for more details.

Table 6: Coal Supply Analysis for SO2 Emission Limit 2006 – 2008 Minimum (Btu/lb) 9.997 Maximum (% Sulfur) (30-day period) 0.52 Theoretical lb/MMBtu Boiler 4 Sulfur to SO 2 conversion averages at 99%* 1.03 (rounded to 1.0) Boiler 5 Sulfur to SO 2 conversion averages at 100%* 1.04 (rounded to 1.0) *CEMs data vs. theoretical

Based on the boiler sulfur to SO 2 conversions, the appropriate em ission limit based on actual fuel supply data for the baseline period is 1.0 lb/MMBtu (30-day rolling average). This option serves as assurance that CENC will be able to both co ntinually comply with an appropriate emission limit while simultaneously eliminating future potential emission increases.

Table 7summarizes each available tec hnology and technical feasibility for SO 2 control.

Table 7: CENC Boilers 4 and 5 SO 2 Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 10 Wet FGD 52-98%, median 90% 4 Y

Dry FGD (SDA) 70-90% (CENC) Y DSI (Trona) ~60% Y SO 2 Emissions Management 30% Y Emission Limit Tightening Minimal Y

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance Wet FGD : The significant cost issue associated with securing sufficient water supplies (a costly and scarce resource in the Front Range) to support a wet FGD control system along with the cost of disposing the sludge byproduct at an approved landfill since on-site storage is not an option. There are other costs and environmental impacts that the Division also considers undesirable with respect to wet scrubbers. For example, the off-site disposal of sludge entails considerable costs, both in terms of direct disposal costs, and indirect costs such as transportation and associated emissions. Refer to the energy and non-air quality impact section for the Division review regarding wet FGD controls for Boilers 4 and 5.

DSI: PCC Industries provided the cost to CENC for the basic equipment required for Trona injection. DSI requires less capital equipment, less physical space, and less medication to existing ductwork compared to a SDA system. However, reagent costs are much higher and depending upon the absorbent and am ount of sorbent injected, contro l efficiency is lower when compared to a SDA system. Additional costs for equipment redundancy, modifications to the facility’s ash handling system, and increased tr ansformer capacity were estimated by CENC based on the need to maintain continuous complia nce with a short-term emission rate (30-day rolling) and past experience with retrofits at ot her CENC facilities. CENC derived total installed costs from the purchased equipment cost using USEPA factors (EPA’s Co st Control Manual). Operating costs were based on estimated Trona requirements of 2.8 lb Trona per lb of SO 2 collected for 65 percent control. The theoretical minimum requireme nt is 2.4 lb Trona per lb of SO 2 collected. Detailed capital and annual cost data are presented in “CENC APCD Technical Analysis”.

The Division compared CENC’s costs for DSI to other Colorado facilities similar in size that analyzed DSI, shown inTable 8.

Table 8: DSI Cost Comparisons Facility & Unit Size (MW) Annualized Costs ($/year) Cost Effectiveness ($/ton) Ratio ($/kW) Colorado Energy Nations – Boiler 4 35 $1,766,000 $3,774 $50.46

Colorado Springs Utilities – Drake Unit 5 51 $1,746,172 $2,293 $34.33

4 U.S. EPA, 2000. “Controlling SO 2 Emissions: A Review of Technologies.” Prepared by Ravi K. Srivastava for the U.S. Environmental Protection Agency, Office of Re search and Development. Office of Research and Development. Washington, D.C. 20460.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 11 Colorado Energy Nations – Boiler 5 65 $2,094,000 $2,485 $32.22

Colorado Springs Utilities – Drake Unit 6 85 $2,910,287 $1,741 $34.24

The Division considers CENC’s DSI costs to be within a reasonable cost range that is comparable to other Colorado facility submittals. 5 CENC Boiler 4 is more expensive compared to other units because of the small size of the boi ler and the increased difficulty of the retrofit. Therefore, the Division did not adju st CENC’s DSI cost estimates.

SO 2 Emissions Management: CENC notes that the costs for implementing a SO 2 Emission Management Plan are based on essentially zero ca pital cost with increment variable operating costs based on the replacement of a portion of coal boiler capacity with natural gas as needed to reduce historical 24-hour SO 2 peaks. The emission level projected for this alternative was derived from the analysis of historical emi ssion level variability de tailed in Figure 3.

The Division verified CENC’s calculated costs for SO 2 Emission Management based on SO 2 hourly CEMs data (06/29/2000 through 01/04/2006), the amount of curtailment that will be required, and average natural gas costs ($10/MMBt u). In reviewing CENC’s DSI estimate, the Division found that the ratio of annual costs to the total capita l costs for the control technology option projected by CENC to be higher than th ose projected by other fa cilities that were amortized over the same 20 year time frame. Th e annualized costs for DS I are about 35% of the total capital investment. The EPA found that other facilities in Arizona, New Mexico, and Oregon presented annual costs th at ranged from 12 – 15% of total capital investments 6

. However, CENC is a much smaller facility th an the facilities in Arizona, New Mexico, and Oregon, which can significantly increase costs. CENC also clearly followed the Cost Control Manual methodology for estimating operation and main tenance costs. Ther efore, the Division did not adjust CENC’s cost estimates.

Emission limit tightening: There are no costs associated w ith this option. This option is considered equivalent to the “baseline” row in the tables below, and is not considered as a separate cost option.

Table 9, Table 10,Table 11, and Ta ble 12 depict controlled SO 2 emissions and control cost comparisons.

Table 9: Boiler 4 Control Resultant SO 2 Emissions Alternative Control Efficiency (%) Resultant Emissions

Annual Emissions (tons/year) Annual Average (lb/MMBtu) 30-day Rolling Average (lb/MMBtu) Baseline --- 780 0.64 0.74

5 ENSR, 2006. BART Analysis for the TriGen Colorado Energy Corporation Facility in Golden, Colorado. Prepared for Trigen. Document No: 10279-017-700.

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

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 12 SO 2 Emissions Management 0.13 767 0.64 0.74

DSI - Trona 60 312 0.26 0.30

Table 10: Boiler 5 Control Resultant SO 2 Emissions Alternative Control Efficiency (%) Resultant Emissions

Annual Emissions (tons/year) Annual Average (lb/MMBtu) 30-day Rolling Average (lb/MMBtu) Baseline --- 1,406 0.71 0.82

SO 2 Emissions Management 0.06 1,448 0.71 0.82

DSI - Trona 60 562 0.29 0.33

Table 11: Boiler 4 SO 2 Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($)* Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0 ---

SO 2 Emissions Management 1.0 $44,299 $43,690 $43,089

DSI - Trona 468 $1,766,000 $3,744 -$85

Table 12: Boiler 5 SO 2 Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0 ---

SO 2 Emissions Management 0.8 $65,882 $78,095 $92,572

DSI - Trona 844 $2,094,000 $2,482 -$90

Energy and Non-Air Quality Impacts Traditional Wet FGD: Based upon its experience, and as disc ussed in detail below, the Division has determined that wet scrubbing has several ne gative energy and non-air quality environmental impacts, including massive water usage. This is a significant issue in Co lorado, where water is a costly, precious and scarce resource. In the ar id West, securing sufficient water supplies to support a wet FGD control system is a difficult unde rtaking that precludes other beneficial uses for such water. In Colorado, water law is based u pon the doctrine of prior a ppropriation or “first in time - first in right,” and the priority date is established by the date the water was first put to a beneficial use. Thus, depending upon whether an d when a power plant first secured a water appropriation and whether such appropriation is adequate to supply the demand, there may be insufficient water appropriations available in some areas of the state, pa rticularly in the Front Range, to accommodate the added demands of wet FGD controls. At a minimum, the water demands of wet FGDs will compete for what is already a scarce resource needed for Colorado’sColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 13 domestic, agricultural and indus trial demands. Wet scrubbers c onsume approximately 23% more water than LSD scrubbers, depending on boiler size. 7

There are other environmental im pacts that the Division also c onsiders undesirable with respect to wet scrubbers. On-site storage of wet ash is an increasing regulatory concern, as evidenced by the recent Tennessee Valley Authority spill. In addition, the steam plum e resulting from a wet FGD control system in such a confined creek bed will produce a noticeable cloud that will hang over a densely populated area (City of Golden). Th e Division has received complaints regarding the more visible plumes associated with wet scru bbing; a potential irony in light of the visibility issues at the heart of the BART program. The Division largely focused its BART SO 2 control technology consideration on commercially av ailable once-through dry FGD controls, specifically, “lime spray dryers” (LSD), that have an established record of reliable performance on boilers burning low-sulfur coal. Generally, we t FGD controls can achieve a higher level of SO 2 control on a percent capture ba sis that exceeds the capabilities of LSDs but, as noted above, there are a number of non-air quality and other envi ronmental impacts including increased water usage, sludge disposal and wet plume issu es that often overshadow any incremental improvement in SO 2 emission reductions. Recent PSD applications in Colorado have demonstrated lime spray dryer systems to be BACT.

The Division finds that the non-ai r quality environmental impacts ou tweigh the visibility benefits from this technology. Therefore, the Stat e has eliminated this option as BART.

SO 2 Emissions Management: The Division has determined that there are not any negative energy or non-air quality related imp acts related to the proposed SO 2 emission management scenario.

DSI: CENC documents additional collateral impacts of applying DSI include enhanced removal of halogenated acid gases, and reduced mercur y capture in the baghouse. DSI ahead of the baghouse would contaminate the flyash with sodi um sulfate, rendering the ash unsalable as a replacement for concrete and render it landfill material only. Currently, there is moderate removal of acid gases in the baghouse due to the alkaline nature of the flyash.

The dry sorbent injection system does result in an ash by-product. This by-product does not require additional treatment before being deposit ed in a landfill. However, a study conducted by the Department of Energy found arseni c and methylene chloride in the ash, 8 which could become a problem if more stringent regula tions are imposed in the future. However, it is not known yet if these levels are considered haza rdous or if the levels vary depe nding on the ash; therefore, this issue requires future research. Otherwise, the DSI does not have any negative energy or non-air quality related impacts. Thus, this factor (r egarding DSI) does not influence the selection of controls.

7 2008. “Revised BART Analysis for Unit 1 & 2 Gerald Gentleman Station Sutherland, Nebraska: Nebraska Public Power District.” Prepared by: HDF 701 Xenia Avenue South, Suite 600 Minneapolis, MN 55416 With control technology costs provided by: Sargent & Lundy.

8 Department of Energy, 2001. LIFAC Sorbent Inj ection Desulfurization Demonstration Project: A DOE Assessment. U.S. Department of Energy: National En ergy Technology Laboratory. P.O. Box 880, 3610 Collins Ferry Road Morgantown, WV 26507-0880. http://www.netl.doe.gov/technol ogies/coalpower/cctc/resources/pdfs/lifac/LIFAC_PPA.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 14 Emission Limit Tightening : There are no known non-air quality or energy impacts associated with emission limit tightening. Thus, this factor does not influence the sel ection of this option.

Remaining Useful Life CENC 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 13 shows the number of days pre- and post-control. Table 14 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 9 , 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 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 (DSI control) at 0.258 lb/MMBtu for Boiler 4 and 0.286 lb/MMBtu for Boiler 5.

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

SO 2 Control Scenario Unit(s) SO 2 Emission Rate (lb/MMBtu) Class I Area Affected 3-year totals 3-year totals

PreControl

Days >0.5 dv PostControl

Days >0.5 dv ∆ days PreControl

Days >1.0 dv PostControl

Days >1.0 dv ∆ days

Max 24- hr 4 0.90 Rocky Mountain 33 --- --- 10 --- --- 5 0.98

9 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) Analys is – Colorado Energy Nations Company Page 15 DSI 4 0.258 National Park 33 29 4 10 7 3

5 0.286 33 28 5 10 7 3

Combo 4&5 0.361 0.392 33 3 30 10 0 10

Table 14: Visibility Results – SO 2 Control Options

Scenario Boiler(s) SO 2 Emission Rate (lb/MMBtu) Output (@ 98 th Percentile Impact) 98 th Percentile Impact Improvement 98 th Percentile Improvement from Maximum Cost Effectiveness

(dv) ( ∆ dv) (%) ($/dv)

Max 24- hr 4 0.90 1.07 --- --- --- 5 0.98

DSI 4 0.258 0.99 0.08 8% $21,802,469 5 0.286 0.94 0.13 12% $16,752,000

Combo 4 5 0.361 0.392 0.28 0.79 74% $18,393,225

Step 6: Select BART Control Based upon its consideration of the five factors su mmarized herein, the state has determined that SO 2 BART is the following SO 2 emission rates:

CENC Boiler 4: 1.0 lb/MMB tu (30-day rolling average) CENC Boiler 5: 1.0 lb/MMB tu (30-day rolling average)

The state assumes that the BART emission lim its can be achieved wit hout additional control technology. Although dry sorbent in jection does achieve better emissions reductions, the added expense of DSI controls were determined to not be reasonable coupled w ith the low visibility improvement afforded.

B. Filterable Particulate Matter (PM 10 )

CENC Boilers 4 and 5 are each equipped with fabric filter 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.

Colorado Operating Permit 96OPJE143 Conditions 3.5 and 4.4 require Boilers 4 and 5 to each meet a PM/PM 10 emission limit of 0.1 lb/MMBtu. A dditionally, Condition 18.1 mandates thatColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 16 each baghouse be equipped with an operating pressure drop measuring device and outlines the Continuous Opacity Mo nitor requirements.

Table 15 shows the most recent stack test data (August 23, 2007 for Boiler 4 and October 10, 2007 for Boiler 5). It is important to note that the most recent st ack test, which at a minimum, occurs every five years in accordance with Colorado Operating Permit 96OPJE143 Condition 18.2, and more frequently depending on the resu lts, demonstrates that these baghouses are meeting >95% control.

Table 15: CENC 2007 Stack Test Results Pollutant Boiler 4 (lb/MMBtu) Boiler 5 (lb/MMBtu) Filterable PM 10 0.013 0.012 PM 10 Control efficiency 98.4% 98.3%

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. The current st ack test results above are well below the range of recent BACT determ inations. While determinations made by other states do not dictate the emissions rate choice made by the Division, they do provide information on the range to validate the emissions rate c hosen by the Division. Refer to “Division RBLC Analysis” for more details rega rding BACT determinations.

These boilers are subject to National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutiona l Boilers and Process He aters, more commonly known as the Boiler MACT, which was proposed on June 4, 2010. 10 As currently proposed, the boilers will be subject to a PM lim it of 0.02 lb/MMBtu (monthly average). 11

Other commercial EGUs must meet a PM limit of 0.03 lb/MMBtu, so the Division evaluated the possibility of tightening the existing PM limit of 0.07 lb/MMBtu on CENC units 4 and 5 based on the idea that there may not be any cost associ ated with a tighter limit. However, compliance with the PM limit is demonstrat ed through periodic performance tests, where compliance is unknown until the test results are evaluated. Conse quently, a tighter emissi on limit has the effect of increasing the likelihood of non-compliance w ithout any possibility of remedy until after the test is complete. This dilemma is further complicated by the presumption that any noncompliance is assumed backward in-time until the last performance test indicating compliance. Thus a tighter PM limit has the effect of forcing sources into more freque nt performance testing to ensure that any unanticipated non-compliance is of shorter duration and thus less costly for any associated enforcement ac tions. Consequently, a tighter emission limit does have an associated increase in costs to the source.

Furthermore, the Division conducted sensitivit y analysis of the CALP UFF model for several sources that indicated that tight ening of PM emissions by 0.07 lb/ MMBtu resulted in negligible

10 EPA, 2009. 40 CFR Part 63 [EPA HQ-OAR-2002-058; FRL-RIN 2060-AG69]. National Emission Standards for Hazardous Air Pollutants for Major Sources : Industrial, Commercial, and Institutio nal Boilers and Process Heaters.

11 EPA, 2009. 40 CFR Part 63 [EPA HQ-OAR-2002-058; FRL-RIN 2060-AG69]. National Emission Standards for Hazardous Air Pollutants for Major Sources : Industrial, Commercial, and Institutio nal Boilers and Process Heaters. Pg. 34 – Table 1 – Existing Coal Stoker.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 17 (less than a tenth to several hundr edths of a delta dv) visibility improvement. Since a tighter PM emission limit does increase costs and does not resu lt in any appreciable visibility improvement, the Division concludes a PM emission limitati on of 0.07 lb/MMBtu is appropriate level of control that satisfies BART.

The Division has determined that an emission limit of 0.07 lb/MMBtu (PM/PM 10 ) represents the most stringent control option. The units are exce eding a PM control efficiency of 95%, and the control technology and emission limits are BART for PM/PM 10 . The state assumes that the BART emission limit can be achieved through th e operation of the exis ting fabric filter baghouses. Thus, as described in EPA’s BART Guidelines, a full five -factor analysis for PM/PM 10 is not needed for CENC Boilers 4 and 5.

C. Nitrogen Oxide (NO x )

Step 1: Identify All Available Technologies CENC identified four NO x control options: Selective catalytic reduction (SCR) Selective non-catalyt ic reduction (SNCR) Combustion modifications/low-NO x burners (LNB) Low-NO x burners + Separated Overfire Air (LNB+SOFA)

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

Step 2: Eliminate Techni cally Infeasible Options

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. 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.

CENC estimated that the retrofit SCR systems on Boilers 4 and 5 could achieve 0.06 lb/MMBtu. The SCR reaction occurs within the temperature range of 600°F to 750°F where the extremes are highly dependent on the fuel quality. There ar e three different types of SCR arrangements – high-dust, low-dust, and tail-end. The pre-dominant arrangement applied in the United States has been high-dust. In most circumstances, a high-dust SCR system is the most economical arrangement alternative and would likely be the arrangement for Un its 4 and 5 if applicable. For high- and low-dust arrangements, the catalyst, becau se of its location dire ctly downstream of the boiler and upstream of the air heater, can impact the boiler through its ef fect on the air heater. The magnitude of this effect is dependent on th e power plant configurat ion, air quali ty control components, type of fuel, and overall emission c ontrol requirements. For retrofit applications,Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 18 adequate space between the economizer outlet and th e air heater inlet to allow boiler outlet and air heater return duct is a prereq uisite for the installation of a hi gh-dust system and is the case for the CENC boilers. Therefore, high-dust SCR is a technically feasible alternative for CENC Boilers 4 and 5.

SNCR/SNCR+LNB/SOFA: Selective non-catalytic reduction is generally utilized to achieve modest NO x reductions on smaller units. With SNCR, an amine-based reagent 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 achieved, although 20-40% is more realistic for most applications. Reagent utilization, a meas ure 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 reag ent utilization and higher operating cost. SCNR is considered a technically feasible alternative for CENC Boilers 4 and 5.

LNB/LNB+SOFA: Low NO x burners are designed to control fuel and air mixing at each burner in order to create large and more branched flames. Peak flame temperature is thereby reduced, and results in less NO x formation. The improved flame structure also reduces the amount of oxygen available in the hottest part of the flam e thus improving burner efficiency. Combustion, reduction and burnout are achieved in thr ee stages within a conventional low NO x burner. In the initial stage, combustion occurs in a fuel rich, oxygen deficient zone where the NO x are formed. A reducing atmosphere follows where hydrocarbons are formed which react with the already formed NO x . In the third stage internal air staging completes the combustion but may result in additional NO x formation. This however can be minimized by completing the combustion in an air lean environment. Installing LNB with separated OFA may increas e carbon monoxide (CO) emissions. LNB/LNB+SOFA are a technically f easible alternative for CENC Boilers 4 and 5.

Low NO x burners can be combined with other primar y measures such as overfire air (OFA) or for even greater NO x emission reductions, separated overfir e air (SOFA). The SOFA system diverts secondary air from the main windbox and inje cts it into the furnace above the main firing zone. This staged combustion process is one of the first principles of aggressive NO x reductions. LNB+SOFA is a technically feasible alternative for CENC Boilers 4 and 5.

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 12 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 13 and has not been demonstrated for other types of units. Therefore, RRI is considered techni cally infeasible for CENC Boilers 4 and 5.

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

13 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.phpColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 19 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 14 . 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

CENC provided the Division annual average control estimates. In the Division’s experience and other state BART proposals, 15 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 CENC Boilers 4 and 5 to determine control efficiencies and annual reductions.

LNB/LNB+SOFA: CENC estimated that low-NO x burners (Alstom’s Low NO x Concentric Firing System (LNCFS) System) are capable of reducing NO x emissions by approximately 10 – 12%, which results in annual emission rates of 0.45 and 0.30 lb/MMBtu for Boilers 4 and 5, respectively. A similar Colorado facility w ith installed LNB achieve s approximately 0.35 – 0.38 lb/MMBtu and estimates an addi tional 20% reduction if OFA is installed to achieve 0.28 – 0.30 lb/MMBtu. These same burners with Separate d Overfire Air were estimated to reduce NO x emissions by 19 – 35%, resulting in an annualized estimated 0.32 and 0.28 lb/MMBtu for Boilers 4 and 5 respectively.

EPA’s AP-42 emission factor tables estimate low-NO x burners controlling 35 – 55% and LNB with OFA controlling 40 – 60% of NO x emissions. 16 A recent AWMA study noted that LNB with close-coupled OFA firing bituminous coal in tangentially fired boilers achieved, on average, 35% NO x reduction. 17 However, due to the size and configuration (e.g. furnace dimensions) of the CENC boilers, the Division conc urs that the estimated control e fficiency rates are reasonable.

SNCR/SNCR+LNB/SOFA: CENC noted in the original BA RT submittal (July 2006) that SNCR achieves 30 – 50% control, which is consis tent with EPA’s SNCR Air Pollution Control Technology Fact Sheet and the Di vision’s experience. However, when CENC calculated SNCR control efficiency in the November 2009 submitta l, it was assumed that LNB+SOFA would be installed beforehand. CENC estimated that SNCR would reduce NO x emissions 40% with LNB+SOFA installed, for resultant emission rates of 0.19 lb/MMBtu and 0.17 lb/MMBtu for Boilers 4 and 5, respectively. This equates to 62 – 67% reducti on depending on the boiler, which

14 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

15 State of North Dakota BART Determination for Le land Olds Station Units 1 and 2. Page 16.

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

17 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) Analys is – Colorado Energy Nations Company Page 20 is consistent with EPA’s AP-42 emission factor tables (50 – 80%). 18 Therefore, the Division concurs with CENC’s control efficien cy estimates for LNB+SOFA+SNCR.

The Division conducted a separate analysis re garding stand-alone SN CR installation (without LNB+SOFA installation) for comparison purposes . The Division did not use CENC’s original estimate of 40% reduction for SNCR . Instead, the Division estimat ed control efficiency based on a variety of information, incl uding similar Colora do facility estimates, EPA’s SNCR Air Pollution Control Fact Sheet and a recent AWMA study 19 to conservatively approximate that the CENC boilers can achieve 30% control when SNCR is applied.

SCR: CENC, via their vendor, estimates that each bo iler will be able to achieve a 0.06 lb/MMBtu emission rate on a 30-day rolling average. CENC estimated control efficiencies on the assumption that LNB+SOFA will already be insta lled. However, this will not change the overall SCR resultant emission rate.

The Division adjusted this emission rate to be 0.07 lb/MMBtu to be consistent with other Colorado facility submittals and li terature review. This adjusted rate equates to 86% control for Boiler 4 and 80% control for Boiler 5. These contro l efficiencies are consistent with EPA’s AP42 emission factor tables, which es timate SCR as achieving 75 – 85% NO x emission reductions and also with a recent AWMA study citing SCR as achieving 80 – 90% reduction. 20,21 Table 16 summarizes each available tec hnology and technical feasibility for NO x control.

Table 16: CENC Boilers 4 and 5 NO x Technology Options an d Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Low NO x Burners (LNB) 35 – 55% Y LNB + OFA 40 – 60% Y Overfire air (OFA) 10 – 25% (alone) Y Selective non-catalytic reduction (SNCR) ~30 - 50% Y

SNCR+LNB+SOFA ~50 – 80% Y Selective catalytic reduction (SCR) ~75 – 90% Y ECO® n/a N RRI n/a N Coal reburn +SNCR n/a N

Step 4: Evaluate Impacts and Document Results

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

19 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.

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

21 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) Analys is – Colorado Energy Nations Company Page 21 Cost of Compliance

LNB/LNB+SOFA: CENC contracted Alstom Power to determine total installed costs for lowNO x burners and separated overfire air. Factors from EPA’s Cost Control Manual were used to develop the total annual cost es timate. EPA’s regulations recommend using the EPA’s Office of Air Quality Planning and Standards’ Air Pollutio n Cost Control Manual (Sixth Edition, January 2002) for estimating costs of compliance. This Manual provides guidance and methodologies for developing accurate and consistent estimates of co st for air pollution control devices. The costs that may be estimated include capital costs, operation and maintenance (O&M) expenses, and other annual costs.

In reviewing CENC’s estimates, the Division found that the ratio of annu al costs to the total capital costs for LNB/LNB+SOFA pr ojected by CENC to be sligh tly higher than those projected by other facilities that were am ortized over the same 20 year time frame. For example, the annualized costs for LNB for Boilers 4 and 5 are 16.1% and 15.5%, respec tively, of the total capital investment. The EPA found that other facilities in Arizona, New Mexico, and Oregon presented annual costs that ranged from 12 – 15% of total capital investments 22 . However, the Division and CENC note that the boilers are much smaller than those examined by the EPA. Therefore, the Division concurs with CENC’s co st estimates for LNBs. Further, the Division compared recent NESCAUM studies estimating LN B+SOFA for tangentially-fired boilers as between $420 - $1,600 per ton NO x reduced. 23 Both the original and revised CENC cost effectiveness estimates are within the NESCAUM ranges, providing further verification that cost estimates are reasonable. The NESCAUM study did not provide cost estimate ranges for LNB on tangentially-fired boilers.

SNCR/SNCR+LNB+SOFA: The difficulty of SNCR retrofit on smaller boilers significantly increases, with the primary concern being that there is adequate wall space within the boiler for installation of injectors. Moveme nt and/or removal of existing watertubes and asbestos from the boiler housing may be required, as in the case of the CENC boilers.

A typical breakdown of annual for in dustrial boilers will be 15 – 35% for capital recovery and 65 – 85% for operating expense. 24 The CENC-estimated SNCR costs for operating expenses are 81% and 86% for Boiler 4 and Boiler 5, respec tively. Since SNCR is an operating expensedriven technology, its cost varies directly with NO x reduction requirements and reagent usage. There is a wide range of cost effectiveness fo r SNCR due to different boiler configurations and site-specific conditions, even with a given industry. Cost effectiveness is impacted primarily by uncontrolled NO x level, required emission reductions, un it size and thermal efficiency, economic life of the unit, and degree of retrofit difficulty. 25

22 Environmental Protection Agency, 2009. 40 CFR Part 49 : Assessment of Anticipated Visibility Improvements at Surrounding Class I Areas and Cost Effectiveness of Best Available Retrofit Technology for Four Corners Power Plant and Navajo Generating Station: Advance Notice of Proposed Rulemaking. Pg. 44318.

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

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

25 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) Analys is – Colorado Energy Nations Company Page 22 The cost effectiveness for SNCR on Boile rs 4 and 5 is about $2,900 and $3,350 per ton, respectively. Recent NESCAUM studies estimate SNCR retrofits on tangentially fired boilers achieving NO x emission rates of 0.30 – 0.40 lb/MMBtu and emission reductions of 30 – 50% as costing $630 - $1,300 per ton of NO x reduced, depending on initia l capital costs and capacity factor. 26,27 EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NO x reduced. 28 Although CENC’s estimates are greater th an these ranges, the small size of the boilers as well as the difficulty of the retrofit leads the Division to the conclusion that CENC’s cost estimates for SNCR are reasonable.

SCR: CENC contracted Lutz, Daily, & Brain (LDB) to develop a cap ital cost estimate. On both boilers, it was determined that the economizers must be moved becau se there is very little space between the air heater ou tlet and the current economizer configur ation, adding to the capital cost.

Recent NESCAUM studies estimate SCR retrofit s on tangentially fired boilers achieving NO x emission rates of 0.10 – 0.15 lb/MMBtu and emission reductions of 75 – 85% as costing $2,600 - $5,000 per ton of NO x reduced, depending on initial capit al costs and capacity factor. 29,30 CENC’s cost estimates are higher than this range, but the small size of the boilers as well as the difficulty of the retrofit leads the Division to th e conclusion that CENC’s cost estimates for SCR are reasonable.

Table 17, Table 18, Table 19, and Ta ble 20 depict controlled NO x emissions and control cost comparisons.

Table 17: CENC Boiler 4 Control Resultant NO x Emissions Alternative Control Efficiency (%) Resultant Emissions

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

Baseline

--- 599 0.50 179

LNB 10 539 0.45 0.515 161 185

SNCR 30 420 0.35 0.400 125 144

LNB+SOFA 35 390 0.32 0.372 116 134

SNCR+LNB+SOFA 61 231 0.192 0.221 69 79

SCR 86 84 0.070 0.080 25 29

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

27 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.

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

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

30 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) Analys is – Colorado Energy Nations Company Page 23 Table 18: CENC Boiler 5 Control Resultant NO x Emissions Alternative Control Efficiency (%) Resultant Emissions

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

Baseline

--- 691 0.34 165

LNB 7 643 0.32 0.368 153 176

LNB+SOFA 18.5 563 0.28 0.322 134 155

SNCR 30 484 0.24 0.277 115 133

SNCR+LNB+SOFA 51 337 0.17 0.193 80 93

SCR 79.6 141 0.07 0.081 34 39

Table 19: CENC Boiler 4 NO x Cost Comparisons Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

LNB 59.9 $193,433 $3,227 $54

SNCR 179.8 $694,046 $3,860 $5

LNB+SOFA 209.8 $678,305 $3,234 -$21

SNCR+LNB+SOFA 368.0 $1,372,351 $3,729 $3

SCR 515.4 $4,201,038 $8,150 $30

Table 20: CENC Boiler 5 NO x Cost Comparisons Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

LNB 48.4 $249,858 $5,166 $107 LNB+SOFA 127.3 $815,829 $6,383 $15

SNCR 207.3 $923,996 $4,458 ($24)

SNCR+LNB+SOFA 353.7 $1,739,825.3 $4,918 $3

SCR 550.0 $6,469,610 $11,764 $35

Energy and Non-Air Quality Impacts LNB/LNB+SOFA: Installing LNB with separated OFA ma y increase unburned carbon in the ash, commonly referred to as loss on ignition (LOI). Otherwise, there are no known non-air qualityColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 24 impacts associated with low-NO x burners and separated overfire air systems. Energy impacts are not significant. Thus, this factor does not influence the selecti on of this control.

SNCR/SNCR+LNB+SOFA/SCR: SCR retrofit impacts the existing flue gas fan systems, due to the additional pressure drop associated with the cat alyst, which is typically a 6- to 8-inch water gage increase for the high temperature applicat ions, and potentially somewhat lower for the low temperature alternatives. In a ddition, any flue gas reheat requir ements for the low temperature applications may require significan t energy input to heat the flue gas. SCR reagent injection systems have minimal power requirements.

Post-combustion add-on control t echnologies such as SNCR do increa se power needs, in the case of the CENC boilers, 90 kW per hour, or enough energy to power about 9 homes for a year, to operate pretreatment and injection equipment, drive the pumps and fans necessary to supply reagents, overcome additional pr essure drops caused by the c ontrol equipment, and provide steam in some cases.

SCR systems require additional auxiliary power or power from the existing flue gas fan systems to overcome the pressure loss across the catalys t, to supply dilution air for mixing with the ammonia, and to pump ammonia into the vapori zer. For CENC Boilers 4 and 5, the estimated pressure drop across the catalyst is 7 to 8 inch es water column and the total energy consumption is approximately 1,000 kW per hour, or enough ener gy to power about 100 homes for a year.

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. CENC has indicated to the Division that they would prefer to use urea instead if applicable to ensure personnel and surrounding community safety, and based the capital and operating costs of a SCR system on a urea reagent versus an ammonia reagent. Refer to “CENC BART Submittals” for more information.

Remaining Useful Life CENC 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 21 shows the number of days pre- andColorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 25 post-control. Table 22 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 31 , 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 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 0.258 lb/MMBtu for Boiler 4 and 0.286 lb/MMBtu for Boiler 5.

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 21: 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-hr 4 0.67

Rocky Mountain National

Park 33 --- --- 10 --- --- 5 0.66

LNB 4 0.45* n/a

5 0.30* n/a

SNCR 4 0.35* n/a

5 0.24* n/a

LNB+SOFA 4 0.32 33 27 6 10 7 3

NOx Modeled Rate 5 0.28 33 25 8 10 6 4

LNB+SOFA 5 0.24* n/a

LNB+SOFA+SNCR 4 0.19 33 27 6 10 7 3

5 0.17 33 19 14 10 6 4 SCR @ 0.07 lb/MMBtu 4 0.07 33 25 8 10 6 4
SCR @ 0.07 lb/MMBtu 5 0.07 33 19 14 10 6 4

31 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) Analys is – Colorado Energy Nations Company Page 26 Combo 4 0.07 33 3 30 10 0 10 5 0.07 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “CENC BART Modeling Summary” for more details.

Table 22: 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-hr 4 0.67 1.07 --- --- --- 5 0.66

LNB 4 0.45* 1.02 0.05 5% $3,868,660 5 0.30* 0.89 0.17 16% $1,435,965

SNCR 4 0.35* 0.99 0.07 7% $9,507,477 5 0.24* 0.86 0.21 20% $4,358,471 LNB+SOFA 4 0.32 0.99 0.08 7% $8,478,816

NOx Modeled Rate 5 0.28 0.88 0.18 17% n/a LNB+SOFA 5 0.24* 0.86 0.21 20% $3,848,252

LNB+SOFA+SNCR 4 0.19 0.96 0.11 10% $12,475,919 5 0.17 0.82 0.25 23% $7,101,328 SCR @ 0.07 lb/MMBtu 4 0.07 0.89 0.18 17% $23,734,677
SCR @ 0.07 lb/MMBtu 5 0.07 0.75 0.31 29% $20,669,680

Combo 4 0.07 0.28 0.79 74% $18,393,225 5 0.07 * Denotes that output was interpolated by the Division and is not an actual modeled output. See “CENC BART Modeling Summary” for more details.

Step 6: Select BART Control The Division and CENC worked together to de termine a “flexible” BART option for Boilers 4 and 5. CENC initially proposed this option in its’ prehearing statement on September 15, 2010. This option incorporates both an individual lim it (lb/MMBtu) for each boiler or a combined average (lbs/hr) for both boilers for a 30-day rolling average period. CENC submitted supplemental information regarding a “fle xible” BART plan on October 19, 2010 to the Division, citing the preamble to the BART regulati ons to ‘consider allowing sources to ‘average’ emissions across any set of BART -eligible emission units within a fencline, so long as the emission reductions from each pollutant being co ntrolled for BART would be equal to those reductions that would be obtained by simply cont rolling each of the BART-eligible source.” This determination adheres to the language in the BART preamble.Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analys is – Colorado Energy Nations Company Page 27 Based upon its consideration of the five factors su mmarized herein, the state has determined that NOx BART for Boiler 4 is the following NOx emission rates: CENC Boiler 4: 0.37 lb/MMBtu (30-day rolling average)

or 0.26 lb/MMBtu Boiler 4 and Boiler 5 combined average (30-day rolling average)

The state assumes that the BART emission lim its can be achieved thr ough the installation and operation of low NOx burners with separated ove r-fire air. Although the other alternatives achieve better emissions reductions, achieving lower limits through different controls was determined to not be reasonable based on the high cost/effectiveness ratios coupled with the low visibility improvement afforded.

Based upon its consideration of the five factors su mmarized herein, the state has determined that NO x BART for Boiler 5 is the fo llowing NOx emission rates: CENC Boiler 5: 0.19 lb/MMBtu (30-day rolling average)

or 0.26 lb/MMBtu Boiler 4 and Boiler 5 combined average (30-day rolling average)

The state assumes that the BART emission lim its can be achieved thr ough the installation and operation of low NOx burners with separated over- fire air and selective non-catalytic reduction.

For the emission limits above, the cost per ton of emissions removed, coupled with the estimated visibility improvements gained, falls within the guidance criteria discussed in section 6.4.3 of the Regional Haze State Implementation Plan.

• Boiler 5: $4,918 per ton NOx remove d; 0.26 deciview of improvement

The dollars per ton control cost, coupled with notable visibility improvements, leads the state to this determination. Though SCR achieves bette r emissions reductions, achieving lower limits through SCR was determined to not fall into th e guidance cost and visibility improvement criteria discussed in section 6.4.3 of th e Regional Haze State Implementation Plan.