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

Regional Haze Reasonable Progress Analysis - Nucla Page 1 Reasonable Progress (RP) Four-Factor Analysis of Control Options

For
Tri-State Generation & Transmission Association, Inc. – Nucla Station

I. Source Description

Owner/Operator: Tri-State Generati on & Transmission A ssociation, Inc. Source Type: Electric Util ity Steam Generating Unit SCC (EGU): 10100218 Boiler Type: Atmospheric Circulating Fluidized Bed

The Tri-State Generation Transmission & Asso ciation, Inc. (Tri-State) Nucla Station is located in Montrose County approximately 3 miles southeast of the town of Nucla,
Colorado. The Nucla Station consists of one co al fired steam driven electric generating unit (Unit 4), with a rated electric generating capacity of 110 MW (gross), which was placed into service in 1987. The boiler is equi pped with a fabric filter (baghouse) system for controlling particulate matter (PM) em issions, and limestone injection into the fluidized bed for the removal of sulfur dioxide (SO 2 ). The boiler is designed for the
reduction of NO

x formation and a small Selective Non-Catalytic Reduction (SNCR) system using anhydrous ammonia injection is used for NO

x trim to ensure compliance
with annual NO

x limits. Additionally, the facility includes a number of fugitive dust

sources.

For this analysis, the Division also relied on the existing Title V permit, historical information regarding the Nucla facility, a nd information about similar facilities to
determine RP for PM and SO 2 . EPA’s BART guidelines r ecommend that states utilize a five step process for determining BART for EGU sources above 750 MW. Although this five step process is not required for making Reasonable Progress (RP) determinations, the Division has elected to largely follow it in RP. This is for ease of reference, and because the statutory factors that must be 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

.”

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 - Nucla Page 2 These de minimis levels are as follows:

• NO

x – 40 tons per year

• SO 2 – 40 tons per year

• PM 10 – 15 tons per year

The Nucla facility originally consisted of thr ee coal fired stoker boi lers that were shut down and replaced with an atmospheric circulat ing fluidized bed (CFB) boiler (Unit #4). Unit #4 was placed in service in June, 1987. CFBs without post-combustion controls are
able to achieve emission rates of NO

x and SO 2 that are lower than Pulverized Coal (PC)

fired boilers due to the nature of their desi gn (lower combustion temp eratures result in
less NO

x formation, while intimate mixing of a sorb ent within the fluidized bed results in
enhanced SO 2 removal). SO 2 emissions from CFBs without post-combustion controls are typically lower than similarly sized PC-fired boilers equipped with Flue Gas Desulfurization (FGD) systems. 2 The original constructi on of Unit #4 included four baghouses for the control of PM 10 emissions, limestone injection to the combustion
chamber for SO 2 removal, and inherent minimization of NO

x emissions due to boiler design.

In 2006, Tri-State permitted and installed a small-scale SNCR system that injects anhydrous ammonia to provide additional NO

x reduction. Tri-State does not operate the SNCR system frequently; it is used on occasions when NO

x emissions approach 0.4 lb/MMBtu (operation above this level at high unit capacity fact ors results in levels that approach the annual NO

x limit of 1,987.9 tons per year on a 12-month rolling basis). The system was designed with a 2,000 gallon tank an d a flow rate during operation of around 10 gallons per hour. 3

Nucla Unit 4 is considered by the Division to be eligible for the purposes of Reasonable Progress, being an industrial boiler with the potential to emit 40 tons or more of haze forming pollution (NO

x , SO 2 , PM 10 ) at a facility with a Q/d impact greater than 20. TriState Generation and Transmission Association (Tri-State) provided information relevant
to RP to the Division on Decembe r 31, 2009, May 14, 2010, and July 30, 2010. Error!
Reference source not found. depicts technical information for Unit 4 at Nucla Station.

Table 1: Nucla Unit 4 Technical Information

Unit 4

Placed in Service 1987

Gross Boiler Rating, MMBtu/Hr for coal 1,112

Electrical Power Rating, Net Megawatts 110

Description Pyropower Circulating Fluidized Bed, Coal Fired Boiler

Air Pollution Control Equipment PM/PM 10 –Fabric Filter Baghouses (1987)

2 Babcock & Wilcox Company, 2000. “Why Build a Circulating Fluidized Bed Boiler to Generate Steam and
Electric Power” Presented to PO WER-GEN Asia 2000. Page 2.

3 Tri-State, May 14, 2010. “RE: Response to the Division’s January 25, 2010 Letter Regarding NO

x Emissions Control Costs.” Page 6.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 3 NO

x – Voluntary SNCR (2006)

SO 2 – Limestone Injection (1987)

Emissions Reduction (%) NOx – NA 4

SO 2 – 77.4%

PM/PM 10 – 98% - 99.9+% 5

II. Source Emissions

Table 2 summarizes the NO

x and SO 2 actual emissions averaged over the 2006 – 2008 timeframe from EPA’s CAMD Database for the facility. Table 3 summarizes each unit at the facility and applicable NO

x , SO 2 , and PM 10 actual emissions averaged over the 2006 –
2008 timeframe with data from Colorado’s Air Pollutant Emission Notices (APENs) submitted by the facility (based on amount and heat content and amount of coal combusted, also as reported on the APENs).

Table 2. Summary of 2006 - 2008 Averaged Emissions – Tri-State Nucla Station
NO

x (tons/year) SO 2 (tons/year) PM 10 (tons/year) 1,760 1,335 40

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit – Tri-State Nucla Station

Unit Pollutant 2006 2007 2008 2006 - 2008 average*

Unit 4 Boiler SO 2 (tons) 1509.4 1230.4 1265.7 1335.2

SO 2 (lb/MMBtu) 0.34 0.30 0.30 0.31

NO

x (tons) 1716.0 1598.0 1711.4 1675.1

NO

x (lb/MMBtu) 0.39 0.38 0.40 0.39

PM 10 (tons) 41.6 39.4 40.24 40.4

PM 10 (lb/ MMBtu) 0.009 0.009 0.009 0.009 Coal Handling & Processing PM 10 (tons) 2.09 2.15 2.15 2.13 Ash Handling & Processing PM 10 (tons) 8.91 10.62 10.62 10.05 P401 Cooling Tower PM 10 (tons) 37.5 23.7 0.34 20.5 P402 Cooling Tower PM 10 (tons) 9.8 9.8 9.8 9.8 Limestone Preparation PM 10 (tons) 1.29 1.29 1.29 1.29

*The above emissions are for the most recent thr ee years (2006 – 2008). These emissions are an annual

average.

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

Note also that Tri-State in stalled improved drift eliminat ors on the P401 Cooling Tower in 2007. The Operating Permit 6 for the facility incl udes a limit of 0.55 tons PM 10 per

4 NO

x emission reductions from the existing SNCR system ha ve not been characterized because the system is operated only infrequently – total reported emissions are therefore assumed to be uncontrolled.

5 The low range is calculated assuming uncontrolled emissions based on AP-42 factors. The high range is stated in the U.S. Department of Energy: Project F act Sheet – Nucla CFB Demonstration Project. http://www.netl.doe.gov/technologies /coalpower/cctc/cctdp/project_briefs/nucla/documents/nucla.pdf . Page 5.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 4 year effective beginning October 1, 2007 (act ual emissions for 2008 we re reported to be 0.34 tons per year); therefore this unit will also not be consider ed further in this analysis.

The Title V permit includes the following limits for the Unit 4 Boiler:

• NO

x : 0.50 lbs/MMBtu on a rolling 30-day av erage (PSD limit), 0.5 lb/MMBtu on a rolling 30-day average (NSPS Subpar t Da) and 1987.9 tons per year on a rolling 12-month total

• SO 2 : 1.2 lb/MMBtu on a rolling 30-da y average (NSPS Subpart Da), 1.2 lb/MMBtu on a 3-hr average (Colora do Regulation No. 1), 0.4 lb/MMBtu on a 30-day average (Colorado Regulation No. 6) and 1598.9 tons per year on a rolling 12-month total; 70% reduction at less th an 0.6 lb/MMBtu (30-day rolling average)

• PM 10 : 131 tons per year on a rolling 12-month total

• PM: 0.03 lb/MMBtu (PSD limit), 0.03 lb/MMBtu (NSPS Subpart Da) 0.1 lb/MMBtu (Colorado Regulation No. 1) and 135.9 tons per year on a rolling 12-

month total

III. Units Evaluated for Control

The Nucla boiler burns Colorado bituminous coal. Nucla Station is a mine-mouth facility; therefore the Division assumes that this facility burns New Horizon Coal, since that facility is the closest coal mine identif iable in Division records. The actual APEN coal specifications (2006 – 2008) are liste d below in Table 4. Uncontrolled emission
factors are outlined in Table 5.

Table 4: Coal Specifi cations (2006 - 2008 Averaged APEN data) Specifications Emission Unit Fuel Heating Value (Btu/lb) Sulfur (% by weight) Ash (% by weight)

Nucla Unit 4 10,545 0.83 19.95

Table 5: Uncontrolled emission factors for Nucla RP-eligible sources 7

Pollutant

Emission Unit NO

x SO 2 PM (filterable) PM 10 (filterable) Unit 4 (lb/ton) 5.0 25.8 17.0 12.4 Unit 4 (lb/MMBtu) 0.24 1.22 0.81 0.59

6 Colorado Air Pollution Control Division, September 25, 2007. Colorado Operating Permit 96OPMO168: Nucla Station. Section II: Condition 8.2, Page 38.

7 PM and PM 10 emission factors are from AP-42, Fifth Edition, Volu me I, Chapter 1, Section 1.1, Tables 1.1-3 and

1.1-4. http://www.epa.gov/ttn/chief/a p42/ch01/final/c01s01.pdf (for spreader stokers with multiple cyclones and reinjection). Uncontrolled SO 2 emission factors are based on the AP-42, Fi fth Edition, Volume I, Chapter 1, Section 1.1 emission factor for underfeed stoker boilers (Table 1.1-3). Uncontrolled NO

x emission factors are based on
actual emissions from 2006 – 2008.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 5 IV. Reasonable Progress Evaluation of Unit 4

a. Sulfur Dioxide Step 1: Identify All Available Technologies

The Division identified all of the availa ble CFB control technologies listed below. Fuel Switching – Natural Gas or Alternate Coal Source Fuel Washing Limestone Injection Process Upgrades Post-Combustion Controls: Dry Scrubbing (Spray Dry Absorber, Circulating Dry Scrubber, Hydrated Ash Reinjec tion and Dry Sorbent Injection) Post-Combustion Controls: Wet Scrubbing

As discussed in EPA’s BART Guidelines 8 , electric generating units (EGUs) with existing controls achieving removal efficiencies of greater than 50 percen t are not required to remove these controls and repl ace them with new controls. However, upgrades need to be considered for the existing limestone in jection process if technically feasible.

The current PSD permit SO 2 limits are depicted in Table 6.

Table 6: Nucla Unit 4 SO 2 PSD Permit Limits
SO 2 limits (lb/MMBtu) Rolling 12-month

Emission Limit (tons/year) 3-hour avg. (Colo. Reg. No. 1) Rolling 30-day avg. (NSPS Subpart Da) 30-day avg. (Colo. Reg. No. 6)

Unit 4 1.2 1.2 0.4 1,599

Step 2: Eliminate Technically Infeasible Options

Fuel Switching – Natural Gas or Alternative Coal Sources: CFB boilers are designed to create a circulating bed of so lid fuels; the nature and locations of the solids and air injection points as well as the combustion zone itself are inherently different fromtraditional PC and natural gas-fired boilers. The recent conversion from a natural gasfired boiler to a CFB-boiler at the Lamar Light and Power facility in Lamar, Colorado required the construction of an entirely new a nd separate unit. Ther efore, the Division determines that the conversion to natural ga s is technically infeasible for Nucla’s CFB

boiler.

Nucla Unit #4 is currently burni ng coal from the New Horiz on Mine located five miles south of the plant, with an average sulfur cont ent of 0.83%. The f acility is located approximately 4.5 miles southeast of Nucla, Colorado and does not have rail service.
There are no other coal mines located 100 miles of the facility. Because the current coal source is already lower than 1% sulfur and no other sources within a reasonable distance

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

Regional Haze Reasonable Progress Analysis - Nucla Page 6 of the facility have been identified, fuel switching to other coal types will not be

considered further in this analysis.

Fuel Washing: Fuel washing has been used historic ally to reduce the sulfur content of some high sulfur coals prior to combus tion. There are no identified fuel-washing processes for low sulfur coal.

Existing Process Upgrades and Post-Combustion Controls : In the absence of any specific feasibility or cost information related to SO 2 controls for the Nucla Station, the Division relied on control evaluations performe d for other CFB boilers, with a focus on CFB boilers in the western part of the count ry. Coal supplies for CFB boilers in the eastern part of the country are significantly different from west ern coals in terms of sulfur and heat content; therefore the Division believe s that the specifics of control devices for eastern CFB boilers may not be wholly appli cable to Nucla Unit 4. The majority of recent BACT determinations identify limestone injection, with or without additional postcombustion controls as the chosen SO 2 control device. Refer to “Division RBLC Analysis” for more details. The Division reviewed two of the most recent BACT analysis reports in detail : the lignite-fired Spiritwood Station in North Dakota 9 and the
waste coal-fired Bonanza Station in Utah 10 . The Spiritwood Station was intended to fire beneficiated lignite but is designed with the capability for firing dried lignite and subbituminous coal as well, and the BACT anal ysis specifically iden tified the findings to be applicable to subbituminous coal. The es timated control efficiencies and costs from these reports were used as a basis to evaluate potential SO 2 emission control options at

Nucla.

Limestone Injection Process Upgrades : The average reduction in SO 2 emissions due to limestone injection into the CFB boiler for the baseline period is estimated to be 77.4% as shown in Table 1, above. The unit participat ed in a U.S. Department of Energy Clean Coal Technology Demonstration Program (CCTDP) from 1988 – 1991 in order to examine the energy and environmental impacts from the unit, which was the first utilityscale atmospheric CFB boiler at the time. The project demonstrated a 70% SO 2 removal rate at a calcium to sulfur ratio (Ca/S) of 1.5 and a 95% removal rate at a calcium to
sulfur ratio of 4.0 11 . The demonstration project test ed a range of western bituminous coals, including Salt Creek (0.5% sulfur), Peabody (0.7% sulfur) and Dorchester (1.5% Sulfur), with the Salt Creek coal serving as the baseline coal (used in 62 of the 72 tests). Limestone injection process upgrades are feasible for Nucla Unit 4.

Post-Combustion Controls – Dry Scrubbing: Additional treatment of the boiler exhaust gases can potentially be accomplished with several dry scrubbing techniques.

9 Barr, July 2007. “Application for a Permit to Construct a Combined Heat and Power (C HP) Plant.” Prepared for Great River Energy – Spiritwood Station, Spiritwood, ND.

10 EPA, August 30, 2007. “Deseret Power Electric Coop erative, Bonanza Power Plant, Waste Coal Fired Unit: Prevention of Significant Deterioration Permit to Constr uct – Final Statement of Basis for Permit No. PSD-00-

0002.01.00. ”

11 U.S. Department of Energy: Project Fact Sheet – Nucla CFB Demonstration Project. http://www.netl.doe.gov/technologies /coalpower/cctc/cctdp/project_briefs/nucla/documents/nucla.pdfColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 7 Spray Dryer Absorption (SDA) is the most commonly used follow-on controls for CFB boilers with limestone inject ion. SDAs currently make up about 12% of Flue Gas Desulfurization (FGD) systems at U.S. power plants 12 . SDA systems are typically
utilized at smaller units that burn lower-s ulfur coal in the western U.S., where water resources are limited. A SDA system captures SO 2 by using slaked lime slurry that is sprayed into the flue gas, subsequently dried by the heat of the flue gas, and the collected in a particulate control device. A SDA syst em is technically feasible for Nucla Unit 4.

Circulating Dry Scr ubber (CDS) Systems use a circulating fluidized bed of dry hydrated lime in a separate reactor tower. The flue gas must first be humidified with a water mist. EPA noted in the Bonanza BACT analysis th at CDS systems have limited application on large PC-fired boilers or CFB boilers, and can result in particulate loading rates that are high enough to create unacceptable pressure drops across fabric filters and therefore require electrostatic precipit ators for particulate control. 13 The potential need to replace the existing baghouse (99.9% particulate contro l) with an electrost atic precipitator renders a CDS system inappropriate as an option for the Nucla station.

Hydrated Ash Reinjection (HAR) increases utilization of uncreated calcium oxide in the CFB boiler ash by collecting, hydrating and re-i ntroducing a portion of the unit’s ash in a separate vessel prior to the baghouse. HAR is technically feasible for Nucla Unit 4.

Dry Sorbent Injection (DSI) systems require injection of pow dered absorbent directly into the flue gas stream. EPA identified this opt ion as impractical for use in a CFB boiler burning low sulfur coals due to an expected SO 2 reduction of less than 50%. 14 DSI is a technically feasible option for Nucla.

Post-Combustion Controls – Wet Scrubbing: Wet Flue Gas Desulfurization (FGD) systems were identified as potentially feasib le for CFB boilers in both the Bonanza and Spiritwood BACT analyses. The process involves an alkaline slurry (lime or limestone) scrubbing liquid in an absorber tower. The process produces a wet byproduct that requires dewatering. Wet scrubbing is a tech nically feasible option for Nucla Unit 4.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Limestone Injection Process Upgrades: The Spiritwood BACT analysis states that the control efficiency from the limestone in jection process is expected to be 75% 15 (further reductions occur in a Spray Dry Absorber). EPA acknowledges in the Bonanza BACT analysis report that a contro l efficiency of 80 – 85% should be expected for the limestone injection process alone 16 . The Division believes that an expectation of 95% reduction for the Nucla station from the limestone inje ction process, although it may have been

12 Recommendations, Technical Report, September 2007. University of North Dakota: Energy & Environment
Research Center – Coal Ash Resources Research Consortium. 15 North 23 rd Street, Stop 9018. Grand Forks, ND, 58202. Pg V.

13 Ibid., Page 92.

14 EPA, Deseret Power Electric Cooperative...Page 93.

15 Barr, Appendix E, Page 50

16 EPA, Deseret Power Electric Cooperative...Page 99.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 8 demonstrated during the CCTDP test project, is not appropr iate as a long term operation scenario. The fluidized bed is currently optimized carefully to balance efficiency, operational and emission characteristics. Incr easing the Ca/S to 4.0 in order to achieve
95% SO 2 reduction is expected to cause signifi cant operational issu es; the Division has not found any evidence of current CFB boilers in operation with Ca/S ratios near 4.0. Higher limestone injections will also result in an increase in NO

x emissions, although the quantitative relationship is not well understood. 17 For these reasons, the Division
believes that an increase in SO 2 control efficiency to 85% by increasing limestone injection is a feasible opti on. This correlates to an approximate 39.4% decrease in comparison to current SO 2 emissions.

Spray Dry Absorber: Based on experience with other Colorado EGUs, the Division
believes that a realistic achievable control e fficiency for a SDA at Nucla is approximately 87%, or an approximate 0.04 lb/MMBtu (30-day rolling average). This is approximately
97% from uncontrolled SO 2 emissions. A review of the EPA’s RBLC database showed
two retrofit Western facilities from about 0.04 – 0.05 lb/MMBtu (30-day rolling average)
with SDAs as the SO 2 control option. Please refer to the document “RBLC for CFBs – July 2010” for more information.

Limestone Injection Improvements + Spray Dry Absorber: Limestone injection improvements (85%) combined with a spray dry absorber (90%) could achieve up to approximately 94% control from current SO 2 emissions, or 98.4% from uncontrolled SO 2 emissions.

Hydrated Ash Reinjection: EPA references vendor information showing that hydrated ash reinjection could reduce the post-combustion SO 2 emissions by about 80%. 18 This
results in about 95% redu ction from uncontrolled SO 2 emissions.

Hydrated Ash Reinjection + Limestone Injection Improvements: It may be possible to combine HAR (80% reduction) with improveme nts to the limestone injection system (85% reduction). This results in a potential 87.9% decrease from current SO 2 emissions
or 96.9% reduction from uncontrolled SO 2 emissions.

Post-Combustion Controls – Wet Scrubbing: EPA noted a potential SO 2 removal efficiency of 94% for the post-combus tion gas in the Bonanza BACT analysis 19

. Combined with the current limestone injec tion system, the overall potential control efficiency is 98.4% from uncontrolled SO 2 emissions.

Table 7 summarizes each available technol ogy option and technical feasibility for SO 2 control
for Nucla Unit 4.

17 Ibid., Page 100.

18 Barr, Appendix E, Page 93.

19 Ibid., Page 94.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 9 Table 7: Nucla Unit 4 SO2 Technology Options and Technical Feasibility Technology Emission Reduction Potential (%) Technically Feasible? (Y = yes, N = no) Fuel switching – Natural gas or alternate coal

source Natural gas: 99%

Alternate coal: minimal Natural gas – N Alternate coal – Y – will not provide

further SO2 control Fuel washing Minimal N Limestone Injection Process Upgrades ~85% overall control efficiency
~40% increase from current control efficiency Y

Dry Scrubbing (SDA) ~97% overall control efficiency
~87% increase from current control efficiency Y

Limestone Injection Improvements + SDA ~98% overall control efficiency
~94% increase from current control efficiency Y

Circulating Dry Scrubber Unknown N Hydrated Ash Reinjection (HAR) ~95% overall control efficiency
~80% increase from current control efficiency Y

HAR + Limestone Injection Improvments ~97% overall control efficiency
~88% increase from current control efficiency Y

Dry Sorbent Injection (DSI) <50% overall control efficiency Y – will not provide further SO2

control Wet Scrubbing ~98% overall control efficiency
~94% increase from current control efficiency Y

Step 4: Evaluate Factors and Present Determination

Factor 1: Cost of Compliance

Costs for SO 2 control options were evaluated based on analyses for similar systems proposed at other western CFB boiler units (S piritwood and Bonanza). Refer to “Nucla APCD Cost Analysis” for more details. Depending on the control option, the Division also relied on additional submittals regardi ng Nucla feasibility and costs submitted on

Limestone Injection Process Upgrades: The Division relied on the U.S. Department of Energy Clean Coal Technology Demonstrati on Program (CCTDP) study to determine control efficiency for limestone injection upg rades. The Spiritwood BACT analysis used
the cost of limestone in 2006 to determine limestone injection costs. The Division adjusted this cost using the Consumer Price Index (CPI), increasing limestone cost fromColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 10 $80 per ton to $87 per ton. The Division al so calculated the additional amount of limestone (in tons per year) that will be needed to achieve an 85% control efficiency (or 40% increase from current control efficiency). These calculations result in an annualized cost of $914,920 per year. Refer to “Nucla APCD Cost Analysis” for more details.

Dry Scrubbing (Spray Dry Absorber)/ Limest one Injection Process Upgrades + SDA: The Division again relied on the Spiritwood BACT Analysis to determine the cost of a spray dry absorber (SDA) system. The a nnualized cost (2006) for the Spiritwood CFB was $2,644,412. The Division used the CPI to adjust this cost to $2,814,108 and then scaled this cost up by the ratio of potential tons SO 2 removed at the Nucla CFB compared to tons removed at the Spiritwood CFB, and th en added in a retrofit factor of 50% to consider the difficulty of the retrofit at Nucla as compared to a new CFB (Spiritwood).

This results in an annualized cost of $4,304,807. For limestone injection improvements combined with a SDA system, the Divi sion combined annualized costs from both

controls to result in an annualized cost of $5,219,097. Refe r to “Nucla APCD Cost Analysis” for more details.

Wet Scrubbing: Although Wet FGD systems pr ovide higher levels of SO 2 removal over dry scrubbers, their incremental cost is likel y the reason that they are not identified as BACT controls on any CFB boilers. The increm ental cost of using a wet scrubber versus the spray dry absorber is identified as $12,902/ton in the Spiritwood BACT analysis 20

, and $10,540 per ton in the Bonanza BACT analysis. 21 A wet scrubber at the Nucla Station should be expected to have even higher costs than these examples due to the retrofit factor. Therefore, a Wet FGD opti on will not be considered further in this analysis.

HAR/HAR+Limestone Injection Improvements: Study-level information for potential HAR systems at Nucla or any other EGU in the western part of the country were not available for use in evaluating costs. Ther efore, the Division does not consider this option to commercially available at this time, and HAR will not be considered further in this analysis. However, HAR is technically feasible and will be considered in future analyses if more inform ation becomes available.

Table 8 illustrates resultant SO 2 emissions for each technically feasible control option.
Table 9 shows the SO 2 control cost comparisons for each unit based on the detailed cost analyses. The Division used baseline emi ssions from Table 3. The Division analyzed both annual and 30-day rolling average limits. The Department’s experience with power plants suggests that the maximum 30-day rolling average SO 2 emission rate is approximately 5% higher than the annual average emission rate.

Table 8: Nucla Unit 4 Control Resultant SO 2 Emissions

Alternative Control Resultant Emissions

20 Barr, Appendix E, Page 95.

21 EPA, Deseret Power Electric Cooperative...Page 95.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 11 Efficiency (%) Unit 4

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

Baseline

--- 1,335 0.299 0.314
Limestone Injection Improvements (LII) 39.4 809 0.182 0.191

Hydrated Ash Reinjection (HAR) 80.0 267 0.060 0.063

Spray Dry Absorber (SDA) 87.0 174 0.039 0.041

HAR + LII 87.9 162 0.036 0.038

LII+SDA 93.9 81 0.018 0.019

Wet Scrubbing 94.0 80 0.018 0.019

Table 9: Nucla Unit 4 SO 2 Cost Comparison
Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

LII 526 $2,188,595 $4,161 $4,161

HAR 1,068 Not determined

HAR+LII 1,173 Not determined

SDA 1,162 $7,604,627 $6,547 $8,520

LII+SDA 1,254 $9,793,222 $7,808 $23,619

Wet Scrubbing 1,255 Not determined

Factor 2: Time Necessary for Compliance It is assumed that the Limestone Inj ection Improvements will not require any construction or capital improvements since th e Unit has already been demonstrated at the higher Ca/S ratios during the CCTDP test project.

Based on other Colorado facility submittals, the Division anticipates that the time necessary for completing design, permitting, procurement, pipeline installation, and system startup and shutdown, after SI P approval, it would take Tri-State approximately 3 – 5 years to implement the SDA or LII+SDA control options. This timeframe may vary somewhat due to regional demand for natural gas and to schedule the necessary major maintenance outage with other re gionally affected

utilities.

Factor 3: Energy and Non-Air Quality ImpactsColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 12 There are no identified energy or non-air quality impacts associated with improvements to the Limestone Injection System. Thus, this factor does not

influence the selection of this control.

Wet Scrubbing: 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 bene ficial 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 establishe d by the date the water was first put to a beneficial use. Thus, depending upon whethe r and when a power plant first secured a water appropriation and whether such a ppropriation is adequate to supply the demand, there may be insufficient water appropr iations available in some areas of the state, particularly 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, agricultural and

industrial demands.

There are other environmental impacts that the Division also considers undesirable with respect to wet scrubbers. Potential on- site storage of wet ash is an increasing regulatory concern, as evidenced by the recen t Tennessee Valley Authority spill. The Division has received complaints regarding the more visible plumes associated with wet scrubbing; a potential irony in light of th e visibility issues at the heart of the Regional Haze program. The Divisi on largely focused its RP SO 2 control technology consideration on commercially available onc e-through dry FGD controls, specifically, “lime spray dryers” (LSD), that have an established record of reliable performance on boilers burning low-sulfur coal. Generall y, 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 water usage, sl udge disposal and wet plume issues that often overshadow any incremental improvement in SO 2 emission reductions. Recent PSD applications in Colorado have demons trated 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 im provement (deciview improvement at nearest Class I area) when compared to a SDA system when applied to the Nucla Unit
4 CFB boiler.

Spray dry absorber (SDA): Other Colorado facility have noted that there are a number of non-air quality environmental impacts with regard to lime spray 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 the flueColorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 13 gas. Several sources of speciated mercur y stack test data, including EPA’s own ICR stack test data, show that an unscrubbed plant with a baghouse burning western coal will remove more mercury from the flue gas when compared to a similar plant with a scrubber. There will be a greater vo lume of material being landfilled. A LSD
scrubber consumes a tremendous amount of water. Wet scrubbers consume approximately 23% more water than LSD scrubbers, depending on boiler size. 22

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: Other Colorado facility have documented additional collateral impacts of applying DSI include enhanced removal of halogenated acid gases, and reduced mercury capture in the baghouse. DSI ahead of the baghouse would contaminate the flyash with sodium sulfate, rendering the ash unsalable as a replacement for concrete and render it landfill material only. Applicat ion of DSI would be effective in further enhancing the removal of halogenated acid ga ses in the baghouse. Currently, there is moderate removal of acid ga ses in the baghouse due to th e alkaline nature of the flyash.

The dry sorbent injection system does result in an ash by-product. This by-product does not require additional treat ment before being deposited in a landfill. However, a study conducted by the Department of Ener gy found arsenic and methylene chloride in the ash at some plants, 23 which could become a problem if more stringent regulations are imposed in the future. Howeve r, it is not known yet if these levels are

considered hazardous or if the levels vary depending on the ash; therefore, this issue requires future research. Otherwise, th e DSI does not have any negative energy or non-air quality related impacts. Thus, this factor (regarding DSI) does not influence

the selection of controls

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

Factor 5 (optional): Evaluate Visibility Results Due to time and domain constraints, proj ected visibility improvements were not modeled by the state for this an alysis. Nucla already has a system in place to inject

limestone into the boiler as required by current state and federal air permits. This system achieves an approximate 70% SO2 emi ssions reduction capture efficiency at a

22 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.

23 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 - Nucla Page 14 permitted emission rate of 0.4 lbs/MMBtu lim it. Increased SO2 capture efficiency (85%) with the existing limestone injection as an effective system upgrade, by use of more limestone (termed “limestone inj ection improvements”) was evaluated and

determined to not be feasible under cert ain operating conditions. The system cannot be ‘run harder’ with more limestone to achieve a more stringent SO2 emission limit; the system would have to be reconstructe d or redesigned with attendant issues, or possibly require a new or different SO2 syst em, to meet an 85% capture efficiency.

Step 6: Select RP Determination

Based upon its consideration of the five factors summarized herein, the state has determined that the existing permitted SO 2 emission rate for Unit 4 satisfies RP: Nucla Unit 4: 0.4 lb/MMBtu (30-day rolling average)

The state assumes that the emission limit can be achieved through the operation of the existing limestone injection system.

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

)

Nucla Unit 4 is currently equipped with a four baghouse system to control PM/PM 10 emissions from the boiler. Baghouses, or fabric filters, operate on the same principle as a vacuum cleaner. Air carrying dust par ticles is forced through a cloth bag. As the air passes through the fabric, the dust accu mulates on the cloth, providing a cleaner air stream. The dust is periodically removed from the cloth by shaking or by reversing the air flow. The layer of dust, known as dust cake, trapped on the surface of the fabric results in high efficiency rates for particles ranging in size from submicron to several hundred micron in diameter. Additionally, fabric filters are the best PM control for western coals, du e to the higher electrical resistivity.

The baghouses performed over the 2006 – 2008 baseline period with PM and PM 10 emissions of 0.013 lb/MMBtu and 0.009 lb/MMBtu, respectively. During the CCTDP test project, the unit demonstrat ed particulate emissions ranging between 0.0072 to 0.0125 lb/MMBtu, corresponding to a removal efficiency of 99.9% 24 . This boiler is subject to 40 CFR Part 60, Subpart Da, which requires 99% reduction (for facilities commencing cons truction after September 18, 1978) of the potential combustion concentration when burning solid fuel. A Division review of the

PM/PM 10 emission limits in the current Title V permit revealed that these limits are
for filterable PM/PM 10 emissions only.

Table 10 shows the most recent verified stack test data (2002). Another stack test was conducted in August 2010, but is not ye t available for rele ase due to ongoing analysis by the Division and Tri-State. Real-time data demonstrates that these

24 U.S. Department of Energy, Page 5.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 15 baghouses are meeting >95% control. Th e Operating Permit (96OPMO168) limit is
0.03 lb/MMBtu for PM/PM 10 emissions (Conditions 1.1.1, 1.1.2). The most recent

stack test data is used to determine co mpliance with the permit limit, which at a minimum, occurs every five years, and more frequently depending on the results.

Table 10: Nucla Unit 4 Stack Test Results (August 2002) Pollutant Unit 4 (lb/MMBtu)

Filterable PM 10 0.014

PM 10 Control efficiency 98.3%

A Division review of EPA’s RBLC revealed recent BACT PM/PM 10 determinations range from 0.010 – 0.10 lbs/MMBtu, which are dependent on a number of factors, including PSD netting, EGU type and age, co al type, and adjacent controls (i.e. wet and dry FGD systems). The current limit of 0.03 lb/MMBtu is in the range of recent BACT determinations. Please refer to “Division RBLC Analysis” for more details
about recent BACT determinations.

The State has determined that the ex isting regulatory emissions limit of 0.03 lb/MMBtu represents the most stringent control option. The unit is exceeding a PM control efficiency of 95%, and the contro l technology and emission limit is RP for

PM/PM 10 . The state assumes that the emi ssion limit can be achieved through the operation of the existing fabric filter baghouse. Therefore, a full 4-factor analysis is
not needed to evaluate PM/PM 10 for the Unit 4 boiler.

c. Nitrogen Oxides (NO
x ) Step 1: Identify All Available Technologies

Fuel Switching – Natural Gas or Alternate Coal Source Selective Non-Catalytic Re duction (SNCR) system upgrades Selective Catalytic Reduction (SCR) with flue gas reheat

Step 2: Eliminate Technically Infeasible Options

Tri-State provided an analysis of the requirements and costs associated with increasing the size of the existing SNCR system to allow for more frequent operation, and the Division has relied on this information (with some exceptions) in order to evaluate a full-time SNCR option. Due to la ck of any specific feasibility or cost
information related to SCR controls at Nucla Station, the Division relied on recent control evaluations performed for other CFB bo ilers in the western part of the country (the Spiritwood and Bonanza evaluations, noted in Section III.a above). Every BACT
determination listed in the RACT/BAC T/LAER Clearinghouse for CFB Boilers specifies SNCR; no SCR determinations or inst allations have been identified. This is likely due to the significantly high incremen tal costs of SCR systems, as discussed
below.

As described above for SO 2 controls, fuel switching to na tural gas or an alternative coal source is not considered technically feasible.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 16 SNCR: Selective non-catalytic re duction is generally utiliz ed 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 a significant impact on economics, with higher levels of NO

x reduction generally resulting in lower reagent ut ilization and higher operating cost. SNCR is considered a technically feasible alte rnative is Nucla Unit 4.

SCR: SCR systems are the most widely used post-combustion NO

x control technology for PC-fired boilers. SCR cont rol involves injecti ng ammonia into the flue gas stream in the presence of a catal yst, and requires a temperature range of 500°F – 800°F. SCR systems are not consider ed feasible for CFB boilers because the particles present in the boiler exhaust act as catalyst poisons. However, the recent BACT analyses for the Spiritwood and Bonanza Units have considered the application of SCR technology following th e particulate control device on CFB
boilers in order to achieve 90% NO

x reduction. Since baghous e exhaust temperatures are too low to satisfy SCR requirements, re heating of the flue gas is required. NO

x control efficiencies of 90% are expected. The Division considers SCR a technically
feasible alternative for Nucl a Unit 4. Please see the cost section for more details regarding SCR.

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

SNCR: The current SNCR system associated with Unit 4 is a small system using anhydrous ammonia injection for NO

x trim during period when emissions approach 0.4 lb/MMBtu (the permit limit is 0.5 lb/MMBtu). NO

x trim is required to ensure that the facility is able to meet the 1,987.9 t on per year permit limit on a rolling 12-month
total. Tri-State notes that the unit is not in service the majority of the time. The system was designed with a 2,000 gallon ta nk and a flow rate during operation of around 10 gallons per hour, allowing only 8 da ys of continuous service. Tri-State
also notes that there is such a wide vari ability in the effectiveness of SNCR for controlling NO

x emissions that only 10% contro l should be assumed, but provided no data to support this value. Note that 10% control over a baseline of 0.39 lb/MMBtu is
0.35 lb/MMBtu.

On August 17, 2006, Tri-State performed a stack test in order to ensure that ammonia slip emissions resulting from the newly in stalled SNCR system would not result in a significant emission increase (for PM 10 ) and trigger PSD review for the project. The test was completed at maximum and mini mum boiler loads, and maximum ammonia injection rate (15.4 – 15.5 gallons per hour) 25 . The test runs occurred during the following timeframes:

25 Colorado Department of Public Health & Environment, November 2, 2006. “Stack Testing Report, Nucla
Station”Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 17 Low Load (80.4 MW) High Load (109.2 MW)

Run 1: 7:28 – 8:28 Run 1: 13:51 – 14:51
Run 2: 9:14 – 10:14 Run 2: 15:25 – 16:25

Run 3: 10:44 – 11:44 Run 3: 16:52 – 17:52

The NO

x CEMS data from CAMD for August 17, 2006 in Figure 1 shows an hourly

NO

x rate during the low load test of 0.22 lb /MMBtu (correspondi ng to 43.6% control over the baseline), and an hourly NO

x rate during the high load test of 0.35 lb/MMBtu (corresponding to 10.3% control).

Figure 1: NOx CEMs Data (August 17, 2006) for Nucla Unit 4

0 0.1 0.2 0.3 0.4 0.5 0.6

0 5 10 15 20 25 l b / M M B t u

Hour 

### NOx Emissions on 8/17/2006 (CAMD)

CEMS Data

Low Load Test

High Load Test

The low load rate of control is more in line with estimates for the SNCR systems in the Spiritwood and Bonanza BACT analyses (58% 26 and 47% 27 , respectively).

The Division conducted an analysis to de termine the typical load for Nucla Unit 4 using baseline data (2006 – 2008). From 2006 – 2008, Nucla ran at 97.6% load. This high load data indicates that 10.3% contro l is more reasonable. However, the
Division and Tri-State both note that the existing small scale SNCR system is not designed for full-scale operation and would last about 8 days in continuous service and has never operated for an extended peri od of time. Tri-Stat e further notes that given the design purpose of the existing syst em for injection to trim emissions as

26 Barr, Appendix E, Page 56.

27 EPA, Deseret Power Electric Cooperative...Page 49.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 18 needed, the system is not engineered to achieve a specific percent reduction. The
Division concludes that ther e is a significant amount of uncertainty surrounding the application of SNCR on CFB boilers due to lack of information at this time.

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

x control.

Table 11: Nucla Unit 4 NO

x Technology Options and Technical Feasibility Technology Emission

Reduction Potential (%) Technically Feasible? (Y = yes, N = no)

Fuel switching – Natural gas or alternate coal source Natural gas: 20 –
70%

Alternate coal:

minimal Natural gas – N

Alternate coal – Y – will not provide further

NOx control

Low NO

x Burners (LNB) ~10% N – CFB boiler Overfire air (OFA) 10 – 25% (alone) N – CFB boiler Selective non-catalytic reduction (SNCR) 20 – 40% Y – small scale system already installed Selective catalytic reduction (SCR) 70 – 90% Y

Step 4: Evaluate Factors and Present Determination

Tri-State provided the Division annual averag e control estimates. In the Division’s experience and other state BART proposals, 28 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 Nucla Unit 4 to de termine control efficiencies and annual

reductions.

Factor 1: Cost of Compliance

SCR: Although SCR systems provide signi ficantly higher levels of NO

x removal over SNCR systems, their incremental cost is like ly the reason that they are not identified as BACT controls on any CFB boilers. Th e incremental cost of using SCR versus
SNCR on a CFB Boiler is identified as $25,315/ton in the Spiritwood BACT analysis 29 , and $40,297 per ton in the Bonanza BACT analysis 30 . A SCR system at
the Nucla Station should be expected to have even higher costs than these examples

due to a retrofit factor and small size. Ther efore, the Division considers that costs for SCR will be excessive. Additionally, site-specific costs for SCR on Nucla are not
available at this time.

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

29 Barr, Appendix E, Page 57.

30 EPA, Deseret Power Electric Cooperative...Page 51.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 19 SNCR: The cost associated with installation of an upgraded SNCR system is shown
below. Costs are based on values submitted by Tri-State on May 14, 2010. 31 Refer to “Nucla APCD Cost Analysis” for more de tails. The Division used two discrete control efficiencies to demonstrate the signi ficant uncertainty of the application of
SNCR and the variation in resultant cost effectiveness.

Table 12 and Table 13 de pict controlled NO

x emissions and control cost comparisons.

Table 12: Nucla Unit 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)

Baseline

--- 1,675 0.387

SNCR 10.3 1,503 0.347 0.399

SNCR 43.6 945 0.218 0.251

Table 13: Nucla Unit 4 NO

x Cost Comparisons
Alternative Emissions Reduction (tpy) Annualized Cost ($) Cost Effectiveness ($/ton) Incremental Cost ($/ton)

Baseline 0 $0 $0

---

SNCR 173 $2,238,592 $12,974 $12,974

SNCR 730 $2,238,592 $3,065

---

Factor 2: Time Necessary for Compliance Tri-State states that the SNCR project coul d be implemented in a two to three year time frame, but also notes that 32 : “Projects of this size entailing a significant outage lasting eight weeks or more must be integrated into the long term sc hedule in order to coordinate with the management of the grid and for power replacement commitments. The date on which EPA SIP approval occurs is necessa rily the starting point for any schedule including significant investments for e ngineering and design, procurement of equipment and contract commitments. In addition, the schedule would have to be integrated into the electr ic supply planning process.”

Tri-State has also described significant constructability challenges and balance-ofplant changes that will likely affect th e timeframe for reconstruction of the SNCR project 33 . Nucla station is located approximately 70 miles from the nearest interstate highway. The facility does not have rail service and is located 40 miles from the
nearest commercial air terminal. Below freezing temperatures are expected seven

31 Tri-State, Page 3.

32 Ibid., Page 24.

33 Ibid., Page 10.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 20 months of the year, which affects soil ex cavation, structure fou ndations and concrete placement.

Based on other Colorado facility submittals, the Division anticipates that the time necessary for completing design, permitting, procurement, pipeline installation, and system startup and shutdown, after SI P approval, it would take Tri-State approximately 3 - 5 years to implement a ny of the above control options. This timeframe may vary somewhat due to regional demand for natural gas and to schedule the necessary major maintenance outage with other re gionally affected

utilities.

Factor 3: Energy and Non-Air Quality Impacts

Post-combustion add-on control technologi es like SNCR do increase power needs, in the range of 100 – 300 kilowatts (kW) de pending on the boiler size, to operate pretreatment and injection equipment, driv e the pumps and fans necessary to supply reagents, overcome additiona l pressure drops caused by the control equipment, and provide steam in some cases. The cost a ssociated with increased power needs was

addressed in the cost effec tiveness study provided by Tri-Stat e and is reflected in the
costs shown in the tables above.

Installing SNCR increases levels of ammoni a, and may create a ‘blue plume’, if ammonia rates are not adequately controll ed. Other environmental factors include ammonia storage and transportation, partic ularly for anhydrous ammonia. Anhydrous ammonia is clear in the liquid state and boils at a temperatur e of -28°F. With its low boiling point, liquid anhydrous ammonia must be stored under pressure at ambient temperatures to remain a liquid. With a nhydrous ammonia, an i nvisible vapor or gas is formed as the liquid evaporates during depressurization. Accidental atmospheric release of anhydrous ammonia vapor can be hazardous; Tri-State has indicated that the larger quantity of on-s ite anhydrous ammonia storage required by the scale-up of the SNCR system will require the review and approval of new Risk Management Plans and Process Safety Management Plans. The larger tank ma y also trigger other state and local ordinances and requirements.

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

Factor 5 (optional): Evaluate Visibility Results Due to time and domain constraints, proj ected visibility improvements were not modeled by the state for this analysis. Nucla has a limited, small-scale SNCR system for emissions trimming purposes already installed.Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 21 Step 6: Select RP Determination

Based upon its consideration of the five factors summarized herein, the State has determined that NOx RP for Nucla Unit 4 is the following NOx emission rate: Nucla Unit 4: 0.5 lb/MMBtu (30-day rolling average)

Additional Analyses of SO2 and NOx Controls for Nucla As state-only requirements of this Reasona ble Progress determination, the Commission requires, and Tri-State agrees, that Tri-State conduct a comprehensive four factor analysis of all SO2 control options for Nucla using si te-specific studies and cost information and provide to the state a draft analysis by July 1, 2012. A protocol for the four-factor analysis and studies will be approved by the Division in advance. The analysis will include enhancements or upgrades to the existing limestone injection system for increased SO2 reduction performance, and other relevant technologies such as lime spray dryers and flue gas desulfuri zation. A final analysis that addresses the state’s comments shall be submitted to the state by January 1, 2013. By January 1, 2013, Tri-State shall also conduct appropriate cost analyses, study and testing, as approved by the Division, to inform what performance would be achieved by a full-scale SNCR system at Nucla to determine potential circulating fluidized bed (CFB) boiler-specific NOx control efficiencies. By January 1, 2013, Tri-St ate shall conduct CA LPUFF modeling in compliance with the Division’s approved BART-modeling protocol to determine potential visibility impacts the different SO2 and NOx control scenarios for Nucla. Finally, Tri-State shall propose to the state any preferred SO2 and NOx emission control strategies for Nucla by January 1, 2013.