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

Regional Haze Reasonable Progress Analysis - Nixon Page 1 Reasonable Progress (RP) Four-Factor Analysis of Control Options For Colorado Springs Utilities – Ray D. Nixon Power Plant

I. Source Description

Owner/Operator: Colorado Springs Utilities Source Types: Electric Util ity Steam Generating Unit SCC (EGU): 10100222 Boiler Type: Pulverized Coal, Dry-Bottom, Front-Fired, firing coal and natural

gas

The Nixon facility is located at 14020 Ra y Nixon Road in Fountain, Colorado. This facility consists of one (1) steam driven turbine/generator unit, auxiliary boiler, the associated equipment needed for generating el ectricity, and two natural gas fired simple cycle combustion turbines driving electricit y generators. The boiler fires low sulfur western coal as the primary fuel and can curr ently use No. 2 distillate oil or natural gas for an ignition fuel. The ignition fuels ar e used for startup of the boiler, flame stabilization, and the coal pulverizer startup. The facili ty also includes the various processes necessary to handle the coal, flyash and bottom ash. The coal and flyash handling systems are provided with baghouses for air pollution emission control at appropriate point sources.

For this analysis, the Division also relied on the existing Title V permit, historical information regarding the Nixon power plant, a nd information about similar facilities to determine RP for NO x , SO 2 , and PM 10 . EPA’s BART guideline s recommend that states utilize a five step process for determin ing BART for EGU sources above 750 MW. Although this five step process is not re quired for making Reasonable Progress (RP) determinations, the Division has elected to largely follow it in RP. This is for ease of reference, and because the statutory factors that must considered in making BART and RP determinations are largely the same.

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

.” These levels are as follows:

• NO x – 40 tons per year

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

Regional Haze Reasonable Progress Analysis - Nixon Page 2 • SO 2 – 40 tons per year

• PM 10 – 15 tons per year

Nixon Power Plant is considered a single source with six (6) ot her facilities, depicted in Table 1.

Table 1: Facilities Co-Located or Considered to be a Single Source with Nixon Power Plant

Emission Sources Colorado Construction/Operating Permit # Permit Holder

Coal Screen 98PO149 Western Resources 2 Anaerobic Digestors, 4 Biogas Boilers and 2 Flares 96OPEP152 CSU – Clear Spring Ranch Solids & Handling 2 Natural Gas Turbines 99EP0851 Front Range Power Company, LLC 1 Coal-fired Boiler, 2 Natural Gas Turbines, Cooling Tower, Ash Handling, Coal Handling, Auxiliary Boiler 95OPEP106 CSU – Nixon Power Plant

Wastewater Treatment and 3 Internal Combustion Engines 95EP1097 CSU – Las Vegas Street Municipal Treatment Plant

Custom Anaerobic Wastewater Treatment System 03EP0158 CSU – Northern Water Reclamation Facility

The two natural-gas fired combustion turbines at Front Range Power Plant (FRPP) are above the Prevention of Significant De terioration signifi cance level for NO x . The other single source facilities emit NO x , SO 2 , and/or PM 10 below the Prevention of Significant Deterioration signifi cance levels.

The Front Range Power Plant (FRPP) is located at 6615 Generation Drive, Fountain, Colorado. The facility produces electrica l power using two na tural gas combustion turbines, with two Heat Recovery Steam Ge nerators (HRSG), and duct burners. These two combustion turbines are evaluated w ithin the source category “Combustion Turbines” in Section 8.2.3 of the Regional Haze SIP.

Nixon Unit 1 is considered by the Division to be eligible for the purposes of Reasonable Progress, being an industrial boiler with the potential to emit 40 tons or more of haze forming pollution (NO x , SO 2 , PM 10 ) at a facility with a Q/d impact greater than 20. CSU provided information in “NOx and SO2 Reduction Cost and Technology Updates for Colorado Springs Utilities Drake and Nixon Pl ants” Submittal provided on February 20, 2009 and additional relevant information on February 21, March 21, May 10, and June 2, 2010. Table 2 depicts technical information for Nixon Unit 1.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 3 Table 2: Nixon/FRPP RP-eligible Emission Controls and Reduction (%) Nixon Unit 1 Placed in Service April 1980 Boiler Rating, MMBtu/Hr for coal 2,049 Electrical Power Rating, Gross Megawatts 227

Description Babcock and Wilcox Pulverized Coal Front Fired Dry Bottom, firing coal. The coal burner ignitors fire No. 2 fuel or spec oil & NG

Air Pollution Control Equipment Western Precipitation Thermoflex Fabric Filter (baghouse)
Special Features Low NOx burners placed in service in 1989

Emissions Reduction (%) NO x – 37% SO 2 – None PM/PM 10 – 99.9/99.7%

Regulations that apply to the boiler are as follows: For Nixon Unit 1:

• NSPS Subpart D regulates particulate matter emissions to 0.1 lb/MMBtu.

• NSPS Subpart D regulates NO X emissions to 0.7 lb/MMBtu.

• The Title V Operating Permit limits annual NO X emissions to 2853.3 tons per

year.

• 40 CFR, Part 76-Acid Rain Nitroge n Oxides Emission Reduction Program regulates NO X emissions to 0.50 lb/MMBtu of heat input on an annual average basis.

• NSPS Subpart D regulates SO 2 emissions to 1.2 lb/MMBtu.

II. Source Emissions

Table 3 summarizes each unit at the facility and applicable NO x , SO 2 , and PM actual emissions averaged over the 2006 – 2008 timef rame with data from EPA’s CAMD database, Colorado’s Air Pollutant Emissi on Notices submitted by the facility, and Colorado inspection reports as applicable. Table 4 summarizes the NO x , SO 2 , and PM actual emissions averaged over the 2006 – 2008 timeframe (baseline) for each RPeligible unit.

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit - Nixon Facility

Unit Pollutant 2006 2007 2008 2006 - 2008 average* Boiler #1 SO 2 (tons) 3877.6 4043.1 4442.3 4121.0 SO 2 (lb/MMBtu) 0.46 0.52 0.53 0.50 NO x (tons) 2390.1 2137.0 2542.9 2356.7 NO x (lb/MMBtu) 0.26 0.26 0.26 0.26Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 4 PM 10 (tons) 89.24 82.29 88.78 86.8 PM 10 (lb/MMBtu) 0.011 0.011 0.011 0.011 Auxiliary Boiler SO 2 (tons) 0 0 0 0.0 SO 2 (lb/MMBtu) 0.00 0.00 0.00 0.00 NO x (tons) 0.02 0.02 0.05 0.0 NO x (lb/MMBtu) 1.50 1.50 1.52 1.51 PM 10 (tons) 0 0 0 0.0 PM 10 (lb/MMBtu) 0.000 0.000 0.000 0.000 Nixon Combustion Turbine 1 SO 2 (tons) 0.01 0.01 0.01 0.0 SO 2 (lb/MMBtu) 0.00 0.00 0.00 0.00 NO x (tons) 0.81 0.61 0.76 0.7 NO x (lb/MMBtu) 0.04 0.04 0.04 0.04 PM 10 (tons) 0.23 0.19 0.25 0.2 PM 10 (lb/MMBtu) 0.011 0.012 0.012 0.012 Nixon Combustion Turbine 2 SO 2 (tons) 0.01 0.02 0.01 0.0 SO 2 (lb/MMBtu) 0.00 0.00 0.00 0.00 NO x (tons) 0.97 1.67 0.85 1.2 NO x (lb/MMBtu) 0.04 0.05 0.05 0.05 PM 10 (tons) 0.27 0.36 0.23 0.3 PM 10 (lb/MMBtu) 0.012 0.012 0.014 0.012 Coal Reclaim Conveyor (003) PM 10 (tons) 25.97 25.97 21.85 24.60 Ash Handling/Disposal (006) PM 10 (tons) 1.41 1.41 1.41 1.41 Coal Handling (008) PM 10 (tons) 23.2 23.2 1.47 15.96 Ash Haul Roads &

Disposal (009) PM 10 (tons) 1.85 1.85 1.87 1.86 Unit #1 Cooling Tower PM 10 (tons) 0.8 0.8 0.75 0.78 Four Digester Gas Boilers SO 2 (tons) 10.15 9.03 9.03 9.40 NO x (tons) 4.95 3.84 3.84 4.21 PM 10 (tons) 0.50 0.35 0.35 0.40 2 Digester Gas Flares SO 2 (tons) 11.0 11.19 11.19 11.13 NO x (tons) 2.61 2.65 2.65 2.64 PM 10 (tons) 0.54 0.40 0.40 0.45 Sludge Injection &

Unpaved Roads PM 10 (tons) 8.90 8.90 8.90 8.90 *The above emissions are for the most recent thr ee years (2006 – 2008). These emissions are an annual average. 30-day rolling averages are estimated to be 5-15% higher than the annual av erage emission rate (i.e. the 30-day NO x rolling average is likely about 0.58 lbs/MMBtu for Boiler 1).

Units italicized in Table 2 are less than de minimis thresholds and will not be evaluated further for the purposes of reasonable progress.

Table 4. Nixon Unit 1 Baseline Emissions

Pollutant Nixon Unit 1 Annual Emissions* (tpy) Annual Emissions** (lb/MMBtu) NO x 2,357 0.258 SO 2 4,121 0.453 PM 10 87 0.002*** *Using daily CEMs data from 2006 – 2008 calendar years (CAMD data).Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 5 **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 and for PM 10 emissions for the turbines. ***The PM 10 emission rate is determined from the Title V permit compliance stack test. These values are as follows: Nixon Unit 1 – 0.0021 lb/MMBtu (4/15/2008)

III. Units Evaluated for Control

As documented by CSU, Nixon Unit 1 fires lo w sulfur, high heating value Power River Basin sub-bituminous coal. The specifications for the coal are liste d below in Table 5.

Table 5: Coal Specifi cations (2006 - 2007 Averaged APEN data) Specifications Emission Unit Fuel Heating Value (Btu/lb) Sulfur (% by weight) Ash (% by weight)

Nixon Unit 1 8,752 0.22 4.99

Table 1 lists the units at Nixon that the Division examined fo r control to meet reasonable progress requirements. Controlled and uncont rolled emission factors and APEN data were used to evaluate the control effec tiveness of the current emission controls. Uncontrolled emission factors are outlined in Table 6.

Table 6: Uncontrolled emissio n factors for Nixon Unit 1

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

Nixon Unit 1 2 NO x 7.2 SO 2 35 x %S = 7.7* PM/PM 10 PM – 49.90** PM 10 – 11.48 *%S = % of sulfur present in coal su pply. For example, 35 x 0.22 = 7.7 **%A = % of ash present in coal supp ly. For example, 10 x 4.99 = 49.90

IV. Reasonable Progress Evaluation of Nixon Unit 1

a. Sulfur Dioxide Step 1: Identify All Available Technologies CSU identified one SO 2 control option: Flue gas desulfurization (FGD): Lime spray dry absorber (SDA or dry FGD)

The Division identified two additional SO 2 control options: Flue gas desulfurization (FGD): Lime or limestone-based (wet FGD) Dry sorbent injection – Trona (DSI)

2 EPA AP-42, Fifth Edition, Volume I, Chapte r 1, Section 1.1, Tables 1.1-3 and 1.1-4. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 6 Step 2: Eliminate Technically Infeasible Options

FGD: Flue gas desulfurization removes SO 2 from flue gases by a variety of methods. Wet scrubbing uses a slurry of alkaline sorben t, 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 c ontrol device. Generally, FGD control systems need to be located in close proximity to the boiler exhaust gas stream to prevent condensation (e.g. cooling of the exhaust gases) that result in acidi c precipitation in the duct which results in corrosion issues.

Wet FGD: Wet FGD control systems must be located after the baghouse because the moist plume resulting from the wet scr ubber system would cr eate baghouse plugging issues if the control is placed ahead of the baghouse. Each absorber tower requires a similar “foot print” area, along with additiona l space for support equipment access, slurry preparation, mixing, associated ta nks, dewatering and a chimney.

Dry FGD: Dry FGD systems are commonly known as spray dry absorbers (SDA) or lime spray dryers (LSD), and currently make up about 12% of FGD systems at U.S. power plants 3 . SDA systems are typically utilized at sm aller units that burn lower-sulfur coal in the western U.S., where water resources are limited. Additionally, Controlling SO 2 Emissions: A Review of Technologies 4 evaluates various SO 2 control technologies and shows that for low-sulfur coal applications, LSDs can meet comparable emission rates to wet systems.

CSU’s 2009 submittal states that a dry FGD (SDA ) system is technically feasible. The Division concurs with this conclusion.

The Division notes that traditional wet FGD controls are possible at Nixon Unit 1 considering that there is adequate space near the baghouse to allow fo r the installation of controls, but are eliminated ba sed on other considerations wi thin 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 regard ing wet FGD controls at Nixon Unit 1.

It is worth noting that CSU is currently testing a new, innovative non-traditional wet scrubber control system at anothe r facility that appears to be as effective, if not more effective, at controlling SO 2 emissions with much less pressure drop (less parasitic load from increased fan demands) and requires a mu ch smaller operational foot print area in comparison to traditional wet scrubbing.. Th e pilot-scale wet scrubber control system,

3 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. 4 Srivastava, R.K. Controlling SO2 Emissions: A Review of Technologies. U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-00/093 (NTIS PB2001-101224), 2000.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 7 called the NeuStream-S FGD process, is presently being tested on a 20 MW flue gas stream. CSU anticipates scaling the non-trad itional wet scrubber control to full scale pending successful outcome of the current te sting. This new wet scrubber technology uses a unique contacting vessel th at makes it different from tr aditional wet scrubbers. It affords a higher liquid to gas contact ratio and so uses much less water / has lower pressure drop. It also uses a dual alkali sy stem that is somewhat unique when compared to most traditional wet scrubbers. In comp arison to traditional wet and LSD scrubbers, this new technology will have smaller water and energy requirements. There are several non-air quality aspects of the NeuStream-S process that comp are favorably to traditional scrubbers, described in Step 4.

Although the technology being tested by CSU do es not technically me et the definition of “available” as set forth in the BART (Regiona l Haze) rules, the Division is willing to allow CSU the opportunity to prove the technology and if successful, the opportunity to install the NeuStream-S FGD scrubber at Nixon Unit 1 if desired and applicable. This process will be required to meet the emissi on limits established for the LSD technology established in this RP determination. Rega rdless of the technology utilized, Nixon has to meet the LSD-based RP limits within 5 years of EPA approval of the Regional Haze SIP. CSU will test the NeuStream system at th is facility until December 2011, and at that time, determine the control technology that wi ll be used to comply with the specified SO 2 RP limit for Nixon Unit 1.

DSI: Dry sorbent injection involve s the injection of typically a sodium based reagent, either the mineral trona (sodium sesquicarbonat e) or refined 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 part iculate control device as in the case of the Drake boilers. CSU asserts that the flue gas temperatures present downstream of the airheater are in the appropriate range to al low for DSI application. A very important factor in DSI application is the ability for the boiler’s particulate control device to accommodate the added particulate loading of the DSI reagent in addition to the flyash loading. CSU’s preliminary review indicates that even with the added loading of DSI reagent, the Drake baghouses would be ope rating within the design specification for particulate loading. The flue gas is not cooled nor saturated with wa ter, so reheating of desulfurized flue gas is not required. No gas-sorbent contac ting vessel is required to be installed. 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 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 reag ent resulting in low efficiencies even at high injection rates. Tr ona is a very reactive reagent 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.

One major challenge of DSI systems is the possibility of converting the NO x present in the flue gas from NO which is colorless to NO 2 which has a reddish-brown color. This conversion of NO to NO 2 can create a brown plume from the stack which could createColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 8 opacity compliance issues. Du e 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 condition. However, based on literature review, CSU estimated the maximum SO 2 removal rate that can be achieved while minimizing the creation of the brown plume condition to be 60% SO 2 removal at another facility. 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 plume fo rmation. This determination would require actual SO 2 removal real-time testing. Therefore, since CSU notes that DSI is technically feasible for a similar facility, the Division assumes this same technology is also then technically feasible for Nixon Unit 1.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

CSU provided the Division annual average co ntrol estimates. In the Division’s experience, 30-day SO 2 rolling average emission rates ar e expected to be approximately 5% higher than the annual average emissi on rate. The Division projected a 30-day rolling average emission rate increased by 5% for Unit 1 to determine control efficiencies and annual reductions.

The Division has reviewed the data supplied by CSU as well as other control techniques applied to pulverized coal boilers. A Di vision 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 aver aging 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 states 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 RBLC Analysis” for more details.

Dry FGD (LSD): Controlling SO 2 Emissions: A Review of Technologies 5 indicates that the median control efficiency for dry FGD pro cesses, such as LSD, is 90%. Typically dry FGD technology is applied to units that fire coal with a sulfur content below 1.0% to 1.5%. However, when concentrations of pollutant s are low, as is the case with low-sulfur western coal, the achievable c ontrol efficiency will drop. Due to the very low sulfur content of the coal burned at the Nixon Power Plant, typically <0.5% as detailed in Table 5, a 90% removal rate is at the upper end of what may reasonably be expected in practice. Therefore, dry FGD is evaluated at tw o control efficienci es level – 78% (0.010 lb/MMBtu annual average) and 82.3% (0.08 lb /MMBtu annual average) for comparison

purposes.

DSI: Based on literature review, CSU estimated the maximum SO 2 removal rate that can be achieved to be 60% SO 2 removal. The Division concurs that this control efficiency is reasonable for retrofit on these units.

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

Regional Haze Reasonable Progress Analysis - Nixon Page 9 Table 7 summarizes each available tec hnology and technical feasibility for SO 2 control.

Table 7: Nixon Unit 1 SO 2 Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Wet FGD 95% Y Dry FGD (LSD) 75 – 85% Y DSI 60% (CSU) Y

Step 4: Evaluate Factors and Present Determination

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. Th ere are other costs and envi ronmental impacts that the Division also considers undesirable with respect to wet scrubbers.

LSD/DSI: CSU submitted cost estimates for a LSD system on Unit 1 on February 20, 2009. CSU provided cost estimates for the DSI system evaluated on another similar Colorado unit (CSU Drake Unit 5) on May 10, 2010.

CSU states that the direct energy cost of the LSD systems due to additional auxiliary loads on the plant, as well as increased headloss through th e scrubber, is the primary energy impact. These loads reduce the net out put of each unit; theref ore, both the lost energy production, as well as the reduced cap acity, must be replaced. CSU estimates energy costs for replacement capacity and differential cost between existing MW-h of output and a replacement MW-h in Table 8. Th is is the incremental cost of a unit of replacement energy, and does not double count th e direct energy cost already included in the operating cost. The reduced unit output will consequently re duce unit efficiency, thereby increasing emissions of CO 2 when measured on a per MW-h basis. These estimates are for another facility, Drake Units 6 and 7, but are assumed to be directly applicable to Nixon Unit 1 as well.

Table 8: LSD Energy Replacement Costs Unit Replacement capacity cost ($/kW-yr) Differential energy cost ($/MW-h) Drake 6/7 44 35

This information, including de tailed capital and annual cost data, are provided as “CSU Drake BART Submittals” and “CSU Nixon RP Submittals”. CSU originally generated costs using EPRI’s FGD Cost model for Drake. 6 This model uses specific unit data to

6 EPA’s BART Guidelines recommend that the OAQPS Contro l Cost Manual be used to develop cost estimates, where possible. Unfortunately, the Cont rol Cost Manual does not contain a s ection for SO2 removal equipment as ofColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 10 calculate the cost of controlling emissions, and is considered to be accurate within ± 30%. When preparing cost estimates for Nixon, co st estimates were developed using the IECCOST program.

The application of LSD or DSI would remove n early all of the haloge ns in the flue gas, thus improving the acid gas removal of the ba ghouse. However, it is anticipated that LSD or DSI would also lower the inherent mercury removal in the baghouses. Recent mercury tests at the Drake Plant have shown that the amount of merc ury leaving the stack is approximately 60 – 90% less than what would have been expected based on coal analysis. It is believed that the halogens pr esent in the flue gas are oxidizing the mercury, which is subsequently removed in the baghous e. The application of LSD or DSI would remove the halogens in the flue gas, which ma y lead to reduced mercury control. Due to this possibility, the provision of adding mercur y control via activated carbon injection as part of a LSD or DSI system has been in cluded in the estimated cost of LSD/DSI application.

The Division compared CSU’s updated cost in formation to the study that EPA conducted in developing presumptive BART limits, 7 shown in Table 9.

Table 9: CSU-Drake SO 2 LSD Control Cost Comparison Unit Capacity (MW) EPA’s Calculated Cost Effectiveness for MW Group ($/ton SO 2 Removed) CSU Refined Cost Estimate ($/ton SO 2 Removed (Control System)) Cost Differential

Drake Unit 6

– 85 MW $2,399 $2,579 - $2,981 + 8% – 24%

Drake Unit 7

– 142 MW $1,796 $2,140 - $2,694 + 19% - 50%

Nixon Unit 1

– 225 MW $1,282 $3,744 - $3,950 + 192% - 208%

EPA’s study was published in 2005 whereas CSU sent the Division updated cost analyses for LSD systems on Unit 1 us ing various cost updates from the 2008 timeframe. Nixon has reflected the costs of retrofitting a f acility that is moderately congested with limited room and access for major retrofits of new capital equipment in the retrofit multiplier that is applied to the cost of new equipment. The Division does not necessarily concur with these esti mates, but will accept them for purposes of this RP analysis.

CSU only submitted DSI cost information fo r another facility, Drake Unit 5. The Division scaled this cost information for Units 1 in Table 10. Please see “Drake APCD Technical Analysis” a nd “Nixon APCD Technical Anal ysis” for more details.

the date of this report. The Fifth edition (EPA 453/B-96-001 ) of the Control Cost Manual is referenced in the BART guideline; however, the Sixth edition (EPA 452/B-02-001, 7-22-2002) is now available.

7 EPA, 2005. Technical Support Document for the Best Available Retrofit Technology (BART) Notice of Final Rulemaking: Setting BART SO 2 Limits for Electric Generating Units: Cont rol Technology and Cost-Effectiveness.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 11 For dry FGD, CSU estimated a removal rate of 80% based on 2008 average data and a resulting emission rate at the BART presumptive limits of 0.10 lb/MMBtu. The Division adjusted this removal rate using the baseline SO 2 emissions from Table 4 (lb/MMBtu and tons/year) for each unit and using a realistic removal rate of 78 - 82%that meets the BART presumptive limit for Nixon Unit 1. This range allows the Division to determine the most reasonabl e RP limit for this control option, if applicable. The Division scaled costs lin early for the LSD systems for higher control efficiencies as applicable. See “Nixon APCD Technical Analysis” for more details.

Table 10 illustrates resultant SO 2 emissions for each technically feasible control option. Table 11 shows the SO 2 control cost comparisons for each unit based on the detailed cost analyses. The Division used baseline emissions from Table 4. The Division analyzed both annual and 30-day ro lling average limits. The Department’s experience with power plants suggests that the maximu m 30-day rolling average SO 2 emission rate is approximately 5% higher than the annual average emission rate.

Table 10: Nixon Unit 1 Control Resultant SO 2 Emissions

Alternative Control Efficiency (%) Resultant Emissions

Unit 1

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

Baseline

--- 4,121 0.453

DSI 60 1,649 0.181 0.190 Dry FGD (LSD) @ 78% control 78 907 0.100 0.105

Dry FGD (LSD) @ 82.3% control 82.3 729 0.080 0.084

Table 11: Nixon Unit 1 SO 2 Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

--- DSI 2,473 $4,938,692 $1,997 $1,997 Dry FGD (LSD) @ 78% control 3,215 $12,036,604 $3,744 $9,568

Dry FGD (LSD) @ 82.3% control 3,392 $13,399,590 $3,950 $7,691

Factor 2: Time Necessary for ComplianceColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 12 Based on other Colorado facility submittals 8 , the Division anticipates that the time necessary for completing design, permitting, procurement, pipeline installation, and system startup and shutdown, after SIP appr oval, it would take CSU approximately 3 – 5 years to implement any of the above cont rol options. This timeframe may vary somewhat due to regional demand for natura l gas and to schedule the necessary major maintenance outage with other re gionally affected utilities.

Factor 3: Energy and Non-Air Quality Impacts Traditional Wet FGD: Based upon its experience, and as discussed in detail below, the Division has determined that wet scrubbi ng has several negative energy and non-air quality environmental impacts, including massive water usage. This is a significant issue in Colorado, where water is a costly, precious and scarce resource. In the arid West, securing sufficient water supplies to support a wet FGD control system is a difficult undertaking that precludes other beneficial uses for such water. In Colorado, water law is based upon the doctrine of prior appropriation or “first in time - first in right,” and the priority date is established by the date the wa ter was first put to a beneficial use. Thus, depending upon whether and when a power plan t first secured a wa ter appropriation and whether such appropriation is adequate to supply the demand, there may be insufficient water appropriations available in some areas of the state, particular ly 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’s domestic, agricultu ral and industrial demands.

There are other environmental impacts that the Division also cons iders undesirable with respect to wet scrubbers. Potential on-site st orage of wet ash is an increasing regulatory concern, as evidenced by the recent Tennessee Valley Authority spill. In addition, the steam plume resulting from a wet FGD control system in such a confined river valley will produce a noticeable cloud that will hang over a densely populated area (City of Colorado Springs). The Division has received compla ints regarding the more visible plumes associated with wet scrubbing; a potential irony in light of the visibility issues at the heart of the Regional Haze program. The Division largely focused its RP 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, wet FGD controls can achieve a higher level of SO 2 control on a percent capture basis that exceeds the capabilities of LSDs but, as noted above, there are a number of non-air quality and other environmental impacts including increased wa ter usage, sludge dis posal and wet plume issues that often overshadow any incremental improvement in SO 2 emission reductions. Recent PSD applications in Colorado have demo nstrated lime spray dryer systems to be BACT.

The Division finds the negative environmental impacts of a traditional wet FGD control system far outweigh minimal incremental SO 2 emission reduction benefits (tons of SO 2 reduced annually) and visibility improvement (deciview improvement at nearest Class I

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

Regional Haze Reasonable Progress Analysis - Nixon Page 13 area) when compared to LSD or the pilot NeuStream-S FGD scrubber when applied to the Nixon Unit 1 boiler.

Semi-dry FGD (LSD): CSU notes that there are a number of non-air quality environmental impacts with regard to lime sp ray dryer systems. Application of a dry scrubber will tend to remove halogens from the flue gas (primarily chlorine) that are important to the removal of mercury from th e flue gas. Several sources of speciated mercury stack test data, including EPA’s own ICR stack test data, show that an unscrubbed plant with a baghouse burning wester n coal will remove more mercury from the flue gas when compared to a similar plan t with a scrubber. There will be a greater volume of material being landfilled. A LSD scrubber consumes a tremendous amount of water, as detailed in Table 12. Wet scrubbe rs consume approximately 23% more water than LSD scrubbers, depending on boiler size. 9

Table 12: LSD Water Requirements Unit Water required for LSD (gpm) Water required for LSD (Mg/year) Drake 6 68 35.7 Drake 7 100 53.0 Nixon 1 (scaled) ~160 ~84.0

Although these non-air quality/e nergy impacts have been identified, th e State has determined that these impacts are not significant or unusual enough to warrant elimination of this control option.

DSI: CSU documents additional collateral impacts of applying DSI include enhanced removal of halogenated acid gases, and redu ced mercury capture in the baghouse. DSI ahead of the baghouse would contaminate the fl yash with sodium sulfate, rendering the ash unsalable as a replacement for concrete and render it landfill material only. Application of DSI would be effective in further enhanci ng the removal of halogenated acid gases in the baghouse. Currently, there is moderate removal of acid gases in the baghouse due to the alkaline na ture 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 deposited in a landfill. However, a study conducted by the Department of Energy found ar senic and methylene chloride in the ash at some plants, 10 which could become a problem if more stringent regulations are imposed in the future. However, it is not known yet if these levels are considered hazardous or if the levels vary depending on th e ash; therefore, this issue requires future research. Otherwise, the DSI does not ha ve any negative energy or non-air quality

9 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.

10 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

Regional Haze Reasonable Progress Analysis - Nixon Page 14 related impacts. Thus, this factor (regard ing DSI) does not influence the selection of controls.

Factor 4: Remaining Useful Life CSU asserts that the remaining useful life of Nixon Unit 1 in excess of 20 years, which is the maximum amortization period allowed in the RP analysis. Thus, this factor does not influence the selection of controls.

Factor 5 (optional): Evaluate Visibility Results CALPUFF modeling was used to determine the projected visibility improvement associated with various control technologi es. The modeling guideline requires that modeled baseline emission rate is the 24- hour peak emission rate. The modeling guideline also requires that, at a minimum, the presumptive emission rate scenario be modeled. Table 13 shows the number of days pr e- and post-control. Table 14 depicts the visibility results (98 th percentile impact and improvement s) as well as cost effectiveness in $/deciview and the calculation methodology utilized by the Division.

The state performed modeling using the ma ximum 24-hour rate during the baseline period, and compared resultant annual aver age control estimates. In the state’s experience, 30-day SO2 rolling average emissi on rates are expected to be approximately 5% higher than the annual average emission ra te. The state projected a 30-day rolling average emission rate increased by 5% for a ll SO2 emission rates to determine control efficiencies and annual reductions.

Table 13: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area SO2 Control Scenario Unit(s) Class I Area Affected 3-year totals 3-year totals

Pre-Control Days >0.5 dv PostControl Days >0.5 dv ∆ days Pre-Control Days >1.0 dv PostControl Days >1.0 dv ∆ days

Max 24-hr SO 2 rates 1

RMNP 17 --- --- 6 --- ---

DSI @ 0.18 lb/MMBtu 1 17 6 11 6 1 5 LSD @ 0.10

lb/MMBtu 1 17 6 11 6 1 5 LSD @ 0.08

lb/MMBtu 1 17 6 11 6 1 5

Table 14: Visibility Result s – SO2 Control Scenarios SO2 Control

Scenario Unit(s) Output (@ 98 t h Percentile Impact)* 98 th Percentile Impact Improvement 98 th Percentile Improvement from Maximum Cost Effectiveness

(deciviews) (deciviews) (%) ($/deciview)

Max 24-hr SO 2 rates 1 0.914 ---

DSI @ 0.18 lb/MMBtu 1 0.48 0.44 48% $11,249,869Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 15

LSD @ 0.10

lb/MMBtu 1 0.46* 0.46 50% $26,454,076

LSD @ 0.070

lb/MMBtu 1 0.42 0.50 55% $28,307,522

* Denotes that output was interpolated by the Division and is not an actual modeled output. See “Nixon Modeling Summary” for more details.

Determination Based upon its consideration of the five factors summarized herein, the state has determined that SO2 RP the following SO2 emission rate:

Nixon Unit 1: 0.11 lb/MMBtu (30-day rolling average)

The state assumes that the emission limit can be achieved with semi-dry FGD (LSD). A lower emissions rate for Unit 1 was deemed to not be reasonable as increased control costs to achieve such an emissions rate do not provide appreciable improvements in visibility (0.04 delta deci view). Also, stringent re trofit emission limits below 0.10 lb/MMBtu have not been demonstrated in Co lorado, and the state determines that a lower emission limit is not reasonable in this planning period.

The LSD control for Unit 1 provides 78% SO 2 emission reduction at a modest cost per ton of emissions removed and result in a meaningful contribution to visibility improvement.

• Unit 1: $3,744 per ton SO 2 removed; 0.46 deciview of improvement

An alternate control technology that achieve s the emissions limits of 0.11 lb/MMBtu, 30- day rolling average, may also be employed.

b. Filterable Particulate Matter (PM) & Particulate Matter (PM 10

)

Nixon Unit 1 is equipped with a reverse-air fabric filter baghouse to control PM/PM 10 emissions. Baghouses, or fabric filters, ope rate on the same principle as a vacuum cleaner. Air carrying dust pa rticles is forced through a cl oth 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 reversi ng 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 si ze from submicron to several hundred microns in diameter. Additionally, fabric filters are the best PM cont rol for western coals, due to the higher electrical resistivity.

Colorado Operating Permit 95OPEP106 Cond ition 1.5.5 requires Unit 1 to conduct performance testing for PM 10 annually. While the emission limit in Condition 1.5.1 is set at 0.1 lb/MMBtu, the annual perf ormance test must be used as an emission factor in determining emissions.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 16 Table 15 shows the most recent stack test data (April 14, 2008). It is important to note that the most recent stack test, which at a minimum, occurs every five years, and more frequently depending on the results, demonstr ates that these baghouses are meeting >95% control.

Table 15: Nixon Unit 1 2008 Stack Test Results Pollutant Unit 1 (lb/MMBtu) Filterable PM 10 0.0021 PM 10 Control efficiency 99.5%

A Division review of EPA’s RBLC revealed recent BACT PM/PM 10 determinations ranging from 0.010 – 0.1 lbs/MMBtu, which ar e 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 current stack test results above are well below the range of recent BACT determinations. Refer to “D ivision RBLC Analysis” for more details regarding BACT determinations.

The state determines that the existing Unit 1 regulatory emissions limit of 0.03 lb/MMBtu (PM/PM 10 ) represents the most stringent control op tions. The unit is ex ceeding a PM control efficiency of 95%, and the control technol ogy and emission limits are RP for PM/PM 10 . The state assumes that the emission limit can be achieved through the ope ration of the existing fabric filter baghouse. Thus, as described in EPA’s BART Guidelines, a full four-factor analysis for PM/PM 10 is not needed for Nixon Unit 1.

c. Nitrogen Oxides (NO x ) Step 1: Identify All Available Technologies CSU identified four NO x control options: Overfire air (OFA) Ultra-low NO x burners (ULNBs) Selective Catalytic Reduction (SCR) Ultra-low NO x burners and SCR (ULNBs + SCR)

The Division also identified and examin ed the following additional control options for these units: Electro-Catalytic Oxidation (ECO)® Rich Reagent Injection (RRI) Ultra-low NO x burners and Over-fire air (ULNBs+OFA) Selective Non-Catalytic Reduction (SNCR) Coal reburn +SNCR

Rotating overfire air (ROFA) was not cons idered in this analysis because ROFA® technology has been reported as achieving NO x emission reductions from 45 to 65 % based on fuel load 11 . While ROFA is considered superior to SOFA alone, ROFA alone is not superior to LNB+OFA and cannot achieve th e predicted 70% or greater NO x reduction for Unit 1. Since ROFA® technology would not be expected to

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

Regional Haze Reasonable Progress Analysis - Nixon Page 17 provide better emissions performance than the LNB+OFA baseline for this unit, ROFA® technology is not considered further in this analysis.

Step 2: Eliminate Technically Infeasible Options

OFA: Air staging or two-stage combustion, is generally described as the introduction of overfire air into the boiler or furnace. Staging the air in the burner (internal air staging) is generally one of the design features of low NO x burners, such as those already present on Unit 1. Furnace overf ire air (OFA) technology requires the introduction of combustion air to be sepa rated into primary and secondary flow sections to achieve complete burnout and to encourage the formation of N 2 rather than NO x . Primary air (70-90%) is mixed with the fuel producing a relatively low temperature; oxygen deficient, fuel-rich zone and therefore moderate amounts of fuel NO x are formed 12 . The secondary (10-30%) of the combustion air is injected above the combustion zone through a special wi nd-box with air introducing ports and/or nozzles, mounted above the burners. Combusti on is completed at this increased flame volume. Hence, the relatively low-temper ature secondary-stage limits the production of thermal NO x . The location of the injection ports and mixing of overfire air are critical to maintain efficient combustion. Re trofitting overfire air on an existing boiler involves waterwall tube modifi cations to create the ports for the secondary air nozzles and the addition of ducts, dampers and the wind-box. OFA is a technically feasible option for Unit 1.

ULNBs: Unit 1 has low NO x burners installed, shown in Table 2. These LNBs can be replaced with ULNBs. Burner designs have improved in recent years to improve flame stability and combustion control schemes for increased NO x emission reductions with these ultra-low NO x burners. ULNBs are a technically feasible option for Unit 1.

ULNBs+OFA: Since ULNBs and OFA are each technically feasible options and would be installed separately for Unit 1, it stands to reason that ULNBs+OFA is a technically feasible options for Unit 1.

SCR : SCR systems are the most widely used post-combustion NO x control technology. In retrofit SCR syst ems, 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 demonstrated by recent determinations found in the EPA’s RBLC database. The NO x and ammonia reagent form nitrogen and water vapor. Th e reaction mechanisms are very efficient with a reagent stoichiometry of approximately 1.0 (on a NO x reduction basis) with very low ammonia slip.

12 IEA Clean Coal Centre: Clean Coal Technologies – Air Stating for NO x control (overfire air and two-stage combustion), 2010. http://www.iea-coal.o rg/site/ieacoal_old/clean-coal-techno logies-pages/air-staging-for-noxcontrol-overfire-air-ofa-or-two-stage-combustion ?Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 18 While lower controlled NO x emission values have been demonstrated by SCR system applications in new coal units, for CS U Nixon, a retrofit SCR, the 0.07 lb/MMBtu controlled NO x value is more expected. 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 are three different t ypes of SCR arrangements – high-dust, lowdust, and tail-end. The pre-dominant arrang ement applied in the United States has been high-dust. In most circumstances, a high-dust SCR system is the most economical arrangement alternat ive and would likely be th e arrangement for Unit 1 if applicable. For high- and low-dust arrangement s, the catalyst, because of its location directly downstream of the boiler and upstream of the air heater, can impact the boiler through its effect on the air heater. The magn itude of this effect is dependent on the power plant configuration, air quality control components, type of fuel, and overall emission control requirements. For retrofit applications, adequate space between the economizer outlet and the air h eater inlet to allow boiler out let and air heater return duct is a prerequisite for the installation of a high-dust system and is the case at the Drake Plant. Therefore, high-dust SCR is a technically feasible alternative for Nixon Unit 1.

ULNBs/SCR layered: A layered approach of instal ling ULNBs pre-combustion and SCR post-combustion is techni cally feasible for Nixon Unit 1.This scenario considers that less NO x would enter the SCR system and reduce aqueous ammonia storage, handling, and injection. CSU considered this scenario to determine if this option would be more economically and tec hnically feasible for Nixon Unit 1.

ECO®: The Powerspan ECO® system is insta lled downstream of a coal-fired power plants’ existing baghouse. The ECO® React or then oxidizes pollutants, which are removed downstream in an absorber vessel during cooling and sa turation of the flue gas. This technology has not been demons trated on a full-size pulverized coal-fired boiler 13 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 pro cess is then completed with the use of overfire air. Rich reagent injection was developed for cyclone boilers 14 and has not been demonstrated for other types of units. Therefore, RRI is considered technically infeasible for Nixon Unit 1.

SNCR: Selective non-catalytic reduction is gene rally 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 with in 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 measure of the efficien cy with which the reagent reduces NO x , can have

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

14 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

Regional Haze Reasonable Progress Analysis - Nixon Page 19 a significant impact on economics, with higher levels of NO x reduction generally resulting in lower reagent utilizat ion and higher operating cost.

It should be noted that sel ective non-catalytic reduction (SNCR) was not considered in CSU’s RP analysis because CSU asserts that SNCR achieves full-load NO x removal in the same range as ULNB at a higher levelized cost ($/ton NO x removed), and therefore should be ruled ou t due to a “least-cost envelo pe” analysis as detailed in the BART rule, and therefore should be ruled out for RP as well. The higher cost is primarily due to much higher operating costs, with most of the operating costs being for the reagent. Additionally, the chemical reaction required for SNCR to work is temperature sensitive. The CSU Drake bo ilers often operate below full load, when the temperature is no longer conducive to optimal NO x removal, resulting in NO x removal declines. The weighted average NO x removal over an annual load range can be less than ULNB depending on the portion of time the units operate at partial load. Therefore, SNCR was eliminated from cons ideration by CSU because of higher costs and efficiency losses at partial loads. However, the Division considers SNCR a technically feasible alternative for Ni xon Unit 1. Similar Colorado facilities evaluated SNCR as an option and it is recognized nationally as a NO x control option for EGUs, so the Division included SN CR in the full four-factor analysis.

Coal Reburn + SNCR: Several research and developmen t efforts in the United States evaluated using a combination of technologies to reduce NO x emissions, including combining coal reburn and SNCR. A novel injection procedure into the fuel-rich, post-combustion zone with staged, fuel-r ich primary combustion and SNCR injection was found to reduce NO x emissions by 93% or well below 0.1 lb/MMBtu 15

. However, this procedure has not been perf ormed on a full-size pulverized coal-fired boiler yet and thus, is consid ered technically infeasible.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

CSU provided the Division annual average co ntrol estimates. In the Division’s experience and other state BART proposals, 16 30-day NO x rolling average emission rates are expected to be approximately 5-15% higher than the annual average emission rate. The Division projected a 30-day rolling average emission rate increased by 15% for Nixon Unit 1 to dete rmine control efficiencies and annual reductions.

OFA: CSU estimated that overfire air, in conjunction with the existing low-NO x burners, is capable of reducing NO x emissions approximately an additional 25% from existing conditions in the original BA RT submittal (August 1, 2006). EPA’s AP-42 emission factor tables estimate low-NO x burners controlling 35 – 55% and LNB with

15 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

16 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

Regional Haze Reasonable Progress Analysis - Nixon Page 20 OFA controlling 40 – 60% of NO x emissions. 17 The low NO x burners currently achieve about 10% control. However, in a more recent AWMA study, it is noted that OFA achieves an additional 10 – 25% control with the installed low NO x burners. 18 Therefore, the Division concur s with CSU’s additional 25% NO x control estimate.

ULNBs : CSU asserts that additional NO x reductions of 20% are possible with implementation of some or all of the modifi cations that will be needed to retrofit ULNBs at Nixon Unit 1. These additional NO x reductions could be achieved while meeting acceptable CO levels. The ULNBs are estimated to control approximately 75% of uncontrolled NO x emissions, which is consistent with a U.S. Department of Energy Study which estimated NO x emissions reductions between 75 – 85%. 19 Therefore, the Division concurs with CSU NO x reduction estimates for ULNBs.

ULNBs+OFA : The Division used information fr om CSU regarding ULNBs and OFA control efficiencies as described above. ULNBs alone can achieve 20% control; OFA alone can achieve 25% control. When dete rmining the appropriate control efficiency regarding the combination of ULNBs and OF A, the most important consideration to note is that Nixon burns only Power River Basin (PRB) coal which is low in nitrogen content initially, so the margin to reduce NO x is lower than other facilities (i.e. Drake). The Division and CSU concur that a realistic control efficiency assumption is 30% for Nixon Unit 1.

SNCR: Other Colorado facilities have noted a variety of control ranges for SNCR. The Division used a variety of informa tion, including a similar Colorado facility estimates, EPA’s SNCR Air Pollution C ontrol Fact Sheet and a recent AWMA study 20 to conservatively approximate that Nixon Unit 1 can ac hieve 30% control when SNCR is applied.

SCR: CSU approximates that SCR can achieve an approximate 80% NO x reduction using 2008 baseline emissions (or 0.05 lb/ MMBtu), determined by URS WD using a survey of a large collection of photographs , and experience in developing retrofit factors for many types of units and confi gurations at numerous facilities. The Division adjusted the control efficiency percent reduction to reflect the 2006 – 2008 baseline emissions and adjusted the resu ltant SCR percent re moval to 73% (or 0.07 lb/MMBtu), which the Division considers mo re realistic and consistent with otherColorado facility submittals. This control efficiency is slightly lower than EPA’s AP42 emission factor discussion, which es timates SCR as achieving 75 – 85% NO x emission reductions and also with a r ecent AWMA study citing SCR as achieving 80

17 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

18 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.

19 U.S. Department of Energy, 2004. Office of Fossil Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/publications /factsheets/project/Proj294.pdf

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

Regional Haze Reasonable Progress Analysis - Nixon Page 21 – 90% reduction. 21,22 However, in the Division’s experience a emission limit of no lower than 0.07 lb/MMBtu is realisti cally achievable for a retrofit SCR.

ULNBs/SCR layered approach: CSU evaluated a layered approach of installing ULNBs upstream of the combustion process to reduce NO x entering the boiler and thus reducing subsequent SCR reduction requirements. This approach will achieve the same NO x emission reductions as SCR alone and is deemed to be appropriate by the Division.

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

Table 16: Nixon Unit 1 7 NO x Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Low NO x Burners (LNB) ~10% Y – installed LNB + OFA 60 – 81% Y (partially installed) Overfire air (OFA) 10 – 25% (alone) Y Ultra-low NO x burners (ULNBs) 20% Y ULNBs+OFA 30% Y Selective non-catalytic reduction (SNCR) 20 – 40% Y

Selective catalytic reduction (SCR) 70 – 90% Y ULNB/SCR layered approach 70 – 90% Y ECO® n/a N RRI n/a N Coal reburn +SNCR n/a N

Step 4: Evaluate Factors and Present Determination

Factor 1: Cost of Compliance OFA: Washington Group International Inc. estim ated the cost of overfire air during the course of a pollution control study fo r the Drake and Nixon boilers in 2004. The cost estimates were generated using EPRI’s IECCOst model. This model uses specific unit data to calculate the cost of controlling emissions and is typically considered to be accurate within ±30%. Ov erfire air will not require large pieces of new equipment, but instead the costs consis t primarily of labor and materials related to modifying the boiler waterwall tubes to allow for new air injection ports and the necessary ductwork, dampers, and instrument ation and control to supply the air from the existing secondary air duct. In a technical support document issued by the Northeast States for Coordinated Air Use Management (NESCAUM) entitled “NO x

21 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

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

Regional Haze Reasonable Progress Analysis - Nixon Page 22 Controls for Existing Utility Boilers,” 23 OFA alone ranges from $410 - $1,100 per ton NO x reduced annually for units estimating 15 – 30% NO x control, which is within the range of Nixon’s estimated OFA NO x reductions (25%). The estimates in Table 17 and Table 18 are within this range. Ther efore, the Division concurs with the OFA cost estimates.

ULNBs : CSU’s cost estimate includes the bur ners, oil or gas lighter systems and controls at burner front, automatic air regi ster adjustment and control drives, flame scanners and controls, all wind box controls including cont rol drawings, all control and burner logic drawings. The estimates do not include burner wind box extensions or stove pipe, ducts installed on top of existing wind boxes, furnace water wall openings, structural steel support for ULNBs beyond suppl emental support steel, cost for engineering, supply and construction of wind box extensions, physical modeling, math modeling, or wind box baffling, pulverizer upgrades, burner pi ping or classifiers for improved coal fineness and required size distribution. CSU notes that some or all of the items must be determined by boiler modeling and pulverizer testing. If all of these are needed, the capital costs could in crease by 40 – 70% compared to the base scope listed in Table 18. Th e Division considers CSU’s estimated costs more than reasonable, with ULNBs at about $1,200/ton which is comparable or lower than LNB costs presented in recent NESCAUM papers. 24, 25

ULNB+OFA : The Division based cost estimates for this control option assuming that OFA and ULNBs will be installed separately ; therefore, the cost for this layering option is a summation of individual annualized costs for OFA and ULNBs for each unit. The Division checked this a ssumption with CSU on November 8, 2010.

SNCR: A typical breakdown of annual for industrial boilers will be 15 – 35% for capital recovery and 65 – 85% for operating expense. 26 A similar Colorado facility estimated operating expenses at approximately 81 – 86%. 27 Since SNCR is an operating expense-driven technology, its cost varies directly with NO x reduction requirements and reagent usage. There is a wide range of cost effectiveness for SNCR due to different boiler configurations and site-specific conditions, even with a given industry. Cost effectiveness is impacted primarily by uncontrolled NO x level, required emission reductions, unit size and thermal efficiency, economic life of the unit, and degree of retrofit difficulty. 28

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

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

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

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

27 CENC, 2009. “NOx Technical Feasibility and Emission Control Costs for Colorado Energy Nations, Golden, Colorado.” Prepar ed by AECOM.

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

Regional Haze Reasonable Progress Analysis - Nixon Page 23 The Division used information from a similar facility submittal to determine approximate SNCR costs scaled for the Nixon boiler since CSU did not have SNCR information. 29 The Division consulted with CSU on this decision to ensure that these boilers are roughly equivalent to the Nixon boiler in scope and retrofit difficulty.

The resultant cost effectiveness for SNCR on Units 1 is approximately $4,500 per ton. Recent NESCAUM studies estimate SNCR retrofits on ta ngentially 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 initial capital costs and capacity factor. 30,31 EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NO x reduced. 32 Although the resulting cost estimates for the Nixon boiler greater than these ranges, the smaller size of the boiler as well as the difficulty of the retrofit leads the Division to the conclusion that the estimated cost estimates for SNCR are reasonable.

SCR: CSU estimated the cost for the SCR system(s) using the IECCOST program. This estimate includes the cost of a ne w ID booster fan, since CSU/URS noted that the current ID fan does not have suffici ent capacity to accommodate the additional pressure drop of the SCR retrofit. Recent NESCAUM studies estimate SCR retrofits achieving NO x emission rates of 0.05 – 0.15 lb/MMBtu and emission reductions of 65 – 85% as costing $2,600 - $7,400 per ton of NO x reduced, depending on initial capital costs and capacity factor. 33,34 The SCR system estimates for the CSU Nixon boiler is approximately $6,400, which is within the NESCAUM estimates. The Division concurs that CSU cost estimates for SCR controls are reasonable.

ULNBs/SCR layered approach: CSU chose to examine the ULNB/SCR layered approach because the cost of the SCR would be reduced somewhat in this scenario. The reduced costs would be noted in the re actor housing, amount of catalyst required, and the aqueous ammonia storage, handling, a nd injection. Therefor e, this option was examined to determine the significance of the potential cost differential. The Division concurs that this is an appropr iate option and may po ssibly reduce costs.

Table 17 illustrates resultant NO x emissions for each technically feasible control option. Table 18 shows the NO x control costs for each uni t based on detailed cost analyses. The Division estimated resultant NO x using annual average reductions for

29 CENC, 2009. “NOx Technical Feasibility and Emission Control Costs for Colorado Energy Nations, Golden, Colorado.” Prepared by AECOM.

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

31 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.

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

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

34 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

Regional Haze Reasonable Progress Analysis - Nixon Page 24 tons of NO x reduced per year. The Division’s experience with power plants suggest that the maximum 30-day rolling average NO x emission rate is 5- 15% higher than the annual average emission rate.

Table 17: Unit 1 Control Resultant NOx Emissions Alternative Control Efficiency (%) Resultant Emissions

Unit 1

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

Baseline

--- 2,357 0.258

Ultra-low NOx burners (ULNBs) 20 1,885 0.206 0.24

Overfire air (OFA) 25 1,768 0.194 0.22 ULNBs+OFA 30 1,650 0.181 0.21 Selective Non-Catalytic Reduction (SNCR) 30 1,650 0.181 0.21

ULNB+SCR 73 636 0.070 0.080 Selective Catalytic Reduction (SCR) 73 636 0.070 0.080

Table 18: Unit 1 NOx Cost Comparison Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

Ultra-low NOx burners (ULNBs) 471 $567,000 $1,203 $1,203

Overfire air (OFA) 589 $403,000 $684 ($1,392)

ULNBs+OFA 707 $907,000 $1,372 $4,812 Selective Non-Catalytic Reduction (SNCR) 707 $3,226,877 $4,564 ---

ULNB+SCR 1,720.4 $11,007,000 $6,398 $7,677 Selective Catalytic Reduction (SCR) 1,720 $11,010,000 $6,400

---

Factor 2: Time Necessary for Compliance Based on other Colorado facility submittals 35 , the Division anticipates that the time necessary for completing design, permitting, procurement, pipe line installation, and system startup and

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

Regional Haze Reasonable Progress Analysis - Nixon Page 25 shutdown, after SIP approval, it would take CS U be approximately 2-3 years for SNCR and 3-4 years for SCR. This timeframe may vary some what due to regional demand for natural gas and to schedule the necessary major maintenance outag e with other regionally affected utilities.

Factor 3: Energy and Non-Air Quality Impacts OFA: Overfire air does not have an y significant energy or non-air qu ality related impacts. Thus, this factor does not influence the selection of this control.

ULNBs: The additional energy required to further pulverize coal is relatively small and is accounted for in CSU’s February 2009 submittal. Therefore, ULNBs do not have any significant energy or non-air quality related impacts. Thus, this factor does not influence the selection of this control.

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

Post-combustion add-on contro l technologies like SNCR do increase power needs, in the range of 100 – 300 kilowatts (kW) depending on the boiler size, to operate pretr eatment and injection equipment, drive the pumps and fans necessary to supply reagents, overcome additional pressure drops caused by the control equipment, and prov ide steam in some cases. 100 – 300 kW is less than 1.0% of the power generated by the Dr ake Unit 7 boiler annually, or enough energy to power about 10 homes for a year. Thes e energy requirements are minimal.

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 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. CSU has indicated to the Division that they would prefer to use aqueous ammonia instead if applicable to ensure pers onnel and surrounding community safety, and based the capital and operating costs of a SCR system on a aqueous ammonia reagent versus an ammonia reagent.

Factor 4: Remaining Useful LifeColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 26 CSU asserts that the remaining useful life of Nixon 1 is in ex cess of 20 years, which is the maximum amortization period allowed in the RP an alysis. Thus, this factor does not influence the selection of controls.

Factor 5 (optional): Evaluate Visibility Results CALPUFF modeling was used to determine the proj ected visibility improve ment associated with various control technologies. The modeling guid eline requires that modeled baseline emission rate is the 24-hour peak emission rate. The mode ling guideline also requires that, at a minimum, the presumptive emission rate scenario be modele d. Table 19 shows the number of days pre- and post-control. Table 20depicts the visibility results (98 th percentile impact and improvements) as well as cost effectiveness in $/deciview and the calcula tion methodology utilized by the Division.

The state performed modeling using the maximu m 24-hour rate during the baseline period, and compared resultant annual average control estimate s. In the state’s experience and other state BART proposals, 30-day NOx rolling average emi ssion rates are expected to be approximately 5-15% higher than the annual average emissi on rate. The state projected a 30-day rolling average emission rate increased by 15% for a ll NOx emission rates to determine control efficiencies and annual reductions. Table 19: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area NOx Control Scenario Unit(s) Class I Area Affected 3-year totals 3-year totalsPreControl Days >0.5 dv PostControl Days >0.5 dv ∆ days PreControl Days >1.0 dv PostControl Days >1.0 dv ∆ days

Max 24-hour

NOx rates 1

RMNP 17 --- --- 6 --- ---

ULNBs @ 0.21 lb/MMBtu 1 17 15 2 6 4 2 OFA @ 0.19

lb/MMBtu 1 17 15 2 6 4 2 ULNBs+OFA @ 0.18 lb/MMBtu 1 17 15 2 6 4 2 SNCR @ 0.18

lb/MMBtu 1 17 15 2 6 4 2 SCR @ 0.07 lb/MMBtu 1 17 12 5 6 3 3

Table 20: Visibility Result s - NOx Control Scenarios NOx Control

Scenario Unit(s) Output (@ 98 t h Percentile Impact)* 98 th Percentile Impact Improvement 98 th Percentile Improvement from Maximum Cost Effectiveness

(deciviews) (deciviews) (%) ($/deciview)

Max 24-hour NOx

rates 1 0.91 --- --- ---

ULNBs @ 0.21 lb/MMBtu 1 0.77 0.15 16% $3,831,081

OFA @ 0.19

lb/MMBtu 1 0.76* 0.15 17% $2,616,883Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 27

ULNBs+OFA @ 0.18 lb/MMBtu 1 0.75* 0.16 18% $6,024,845

SNCR @ 0.18

lb/MMBtu 1 0.75* 0.16 18% $20,042,714

SCR @ 0.07 lb/MMBtu 1 0.68 0.24 26% $46,639,831

* Denotes that output was interpolated by the Division and is not an actual modeled output. See “Nixon Modeling Summary” for more details.

Determination Based upon its consideration of the five factors su mmarized herein, the state has determined that NOx RP for Nixon Unit 1 the following NOx emission rate: Nixon Unit 1: 0.21 lb/MMBtu (30-day rolling average)

The state assumes that the emission limit can be achieved with ultra-low NOx burners with over fire air control. The Division notes that ul tra-low NOx burners with over-fire air is the appropriate RP determination for Nixon Unit 1 due to the low cost effectiveness. SNCR would achieve similar emissions reductions at an adde d expense. Therefore, SNCR was determined to not be reasonable considering the lo w visibility improvement afforded.

V. RP Evaluation for Fugitive Dust Sources: Coal Reclaim Conve yor (003) and Coal Handling (008)

Both of these fugitive dust sources are permitted within Colorado Operating Permit 95OPEP106.

Coal handling is comprised of five (6) part s – reclaim tunnel bagfilte r vent, coal crusher building bagfilter vent, coal gallery bagfilter ve nts, and coal train off-loading-conveyingstockpiling. It should be noted that while these two sources are reported individually in Colorado’s emission inventory, in the Operat ing Permit, these sources are combined together since coal handling is treated as one point. Colorado Regulation No.1.II.A.1 limits opacity from these sources to 20%. Th is source is also subject to NSPS Subpart Y, New Source Performance Standards for Coal Preparation Plants. Additionally, the following measures to control fugitive dust via a fugitive particulate emissions control plan (Condition 3.4):

• A wet dust suppression system shall be used for railroad car unloading.

• Above ground conveyors to and from the tr ansfer building must be covered.

• Loadout to storage must by telescoping chute.

• Emissions from coal storage piles shall be effectively controlled by application of chemical binders and by watering, if need be.

These existing controls and corresponding em ission limits in Section II, Condition 3 of Operating Permit 95OPEP106 represent the most stringent level of control available for these fugitive dust sources.

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