## BART DETERMINATION

SUPPORT DOCUMENT FOR

TRANSALTA CENTRALIA GENERATION LLC POWER PLANT CENTRALIA, WASHINGTON

Prepared by

Washington State Department of Ecology Air Quality Program

August 2009 Revised April 2010

Revised Novem ber 2011Tabl e of Contents

Executive Summary

Section 1.0 Introduction

1.1 The BART Analysis Process

1.2 Basic Description of the TransAlta Centralia Generation LLC Power Plant

1.3 B ART Eligible Units and Pollutant at TransAlta Centralia Generation LLC Power

Plant

1.4 Visibility Impact of B ART Eligible Units at TransAlta Centralia Power Plant 1.5 Relationship to 1997 RACT Analysis and D etermination

Section 2.0 Summary of TransAlta Centralia P ower Plant ’s BART Analysis

2.1 NOx Controls E valuated

2.2 TransAlta ’ s Proposed B ART

Section 3.0 Visibility Impacts and Degree of Improvement

Section 4.0 Ecology’s B ART Determination

4.1 NOx Control

4.2 Ecology’s Determination of the NOx Emission Controls That Constitute BART

Appendix A Coal Quality Appendix B Nitrogen Oxides Controls Evaluated in the 1997 Reasonably Available Control Technology Process Appendix C References Appendix D Modeling Result Information from June 2008 and January 2008 Best Available Retrofit Technology Modeling reports Appendix E Coal

- Fired Electric Generating Unit BART Determinations in Western U .S. Appendix F TransAlta Centralia Power Plant Site Plans and Pro files Appendix G Centralia BART Control Technology Analysis, Response to Questions Appendix H Additional Centralia Power Plant BART Modeling Simulations

– Com parison of Flex Fuel and Flex Fuel plus SNCR Appendix I Establishing SNCR NOx Emission Limitation

## Executive Summary

The Best Available Retrofit Technology (BART) program is part of the larger effort under the Clean

Air Act Amendments of 1977 to eliminate human- caused visibility impairment in all mandatory Class I areas. Sources that are required to comply with the BART requirements are those sources

that :

1. Fall within 26 specified industrial source categories;

2. Commenced operation or completed permitting between August 7, 1962 and August 7, 1977;

3. Have the potential to emit more than 250 tons per yea r of one or more visibility impairing compounds;

4. Cause or contribute to visibility impairment within at least one mandatory Class I area.

TransAlta Centralia Generation LLC Power Plant (TransAlta) operates a two -unit, pulverized coalfired plant near Centralia , Washington. Each unit of the plant is rated at 702.5 MW net output when using coal fro m the Centralia coal field . Current o utput capacity reported by TransAlta is 670

MW/unit as a result of using coals from the Powder River Basin (PRB)

. Opera tion of a coal- fired power plant results in the emissions of P articulate M atter (PM), S ulfur D ioxide ( SO 2 ) and Nitrogen

O xides ( NOx ). All of these pollutants are visibility impairing.

Pulverized coal plants such as the TransAlta facility are one of the 26 listed source categories. The

units at the plant began commercial operation in 1971 and 1972. The units have the potential to emit more than 250 tons per year of SO 2 , NOx , and PM. As part of an approval of the Washington State Visibility S tate Implementation Plan (SIP) in 2002, Environmental Protection Agency ( EPA ) Region 10 determined that particulate and SO 2 controls installed as part of a 1997 Reasonably Available Control Technology (RACT) determination 1 issued by the Southwest Clean Air Agen cy (SWCAA) 2
met the requirements for BART and constituted BART for those pollutants. EPA specifically did not adopt the NOx controls in the RACT order as BART

.

Modeling of visibility impairment was done following the Oregon/Idaho/Washington/EPA- Region 10 BART modeling protocol. 3 Modeled visibility impacts of baseline emissions show impacts on the

8 th highest day in any year (the 98 th percentile value) of greater than 0.5 D eciviews (dv) at the

twelve Class 1 areas within 300 km of the plant. The highes t impact was 5.55 dv at Mt. Rainier National Park. Modeling showed that NOx and SO 2 emissions from the power plant are responsible

for the facility’s visibility impact.

TransAlta prepared a BART technical analysis following Washington State’s BART Guidance. 4

Future operation of t he TransAlta facility is specifically addressed in Chapter 180, Laws of 2011 (a lso known as E2SSB 5769). Un der this law , the Governor is to enter a Memorandum of Agreement whereby the plant owners will bring the two coal -fired units into compliance with the greenhouse gas

1 SWAPCA Order No. 97

- 2057R1 issued December 26, 1998.

2 Previously known as the Southwest Air Pollution Control Authority (SWAPCA).

3 Modeling protocol available at http://www.deq.state.or.us/aq/haze/docs/bartprotocol.pdf

. 4 “Best Available Retrofit Technology Determinations Under the Federal Regional Haze Rule,” Washington State Department of Ecology, June 12, 2007.(GHG) emission performance standard in RCW 80.80.040. 5 The law also requires the plant owner to install and operate selective noncatalytic reduction (SNCR) for NOx by January 1, 2013. The

schedule in the law f or bringing the coal units into compliance with th e GHG emission performance standard directs that one unit is to comply by Dec ember 31, 2020, and the other is to comply by

December 31, 2025. Based on testimony at the legislature and in the press, i t is expec ted that the units will comply with the GHG emission standard by being decommissioned. The law also states that the requirement to meet the GHG emission performance standard do es not apply in the event the Washington State Department of Ecology (Ecology) determines as a requirement of state or federal law or regulation that the selective catalytic reduction (SCR) technology must be installed on either

coal -fired unit.

In accordance with this law and its effects on potential NOx emission controls , Ecology has revised

its determination of BART. We now find that BART for NOx emissions is the current combustion controls, the Flex Fuels Project , the use of a sub -bituminous coal from the PRB or other coal that will

achieve similar emission rates and the installation and use of SNCR . In addition to the 20 percent
reduction in NOx emissions by use of the Flex Fuels Project , SN CR will further reduce NOx

emissions.

The exact amount of NOx reduction attributable to SNCR at this plant is un known. However , all analyses of the effects of the use of SNCR are based on an assumption of an additional 25 percent reduction. The SNCR system is required to be installed and operating by January 1, 2013. Ecology

has established an interim emission limitation of 0.21 lb/MMBtu that will be in effect after start

- up of the SNCR system until the BART Order is revised in 2015. During calendar years 2013 and 2014, TransAlta will be required to optimize the SNCR system to maximize the NOx reduction while maintaining an acceptable ammonia emission rate.

The use of low sulfur PRB coal also reduces SO 2 emission by about 60 percent from the same period

. The NOx reduction anticipated from the revised BART controls selected by Ecology will result in a visibility improvement from the baseline impacts at Mt. Rainier National Park of approximately 1.99 dv, with improvements of 0.67 to 1.65 dv at other affected Class I areas

. We estimate that the visibility improvement from meeting the interim emission limitation will be approximately 1 dv at

Mt. Rainier National Park

. Looking to the future, the 2020 decommissioning of one coal unit will further de crease the visibility imp ac ts and the final 2025 decommissioning of the other un it will eliminate all visibility impacts from the combustion of coal at this facility. Ecology considers the future decommissioning of the

coal units to be reasonable progress elements of the Regional Haze State Implementation Plan.

5 RCW 80.80.040(3)(c)(i) A coal

- fired baseload e lectric generation facility in Washington that emitted more than one million tons of greenhouse gases in any calendar year prior to 2008 must comply with the lower of the following greenhouse gas emissions performance standard such that one generating boiler is in compliance by December 31, 2020, and any other generating boiler is in compliance by December 31, 2025: (A) One thousand one hundred pounds of greenhouse gases per megawatt

- hour; or (B) The average available greenhouse gas emissions output as dete rmined under RCW 80.80.050. (ii) This subsection (3)(c) does not apply to a coal

- fired baseload electric generating facility in the event the department determines as a requirement of state or federal law or regulation that selective catalytic reduction te chnology must be installed on any of its boilers.

### 1.0 I NTRODUCTION

This document is to support Ecology’s determination of the BART for the TransAlta coal

- fired power plant located near Centralia , Washington.

The TransAlta plant is a coal -fired power plant rated to produce a net of 702.5 MW per unit. The plant has two tangentially fired pulverized coal units currently using P RB sub-bituminous coals for

fuel.

In a letter dated October 16, 1995, the National Park Service (NPS) notified Ecology c ertified that there was uniform haze visibility impairment at Mt. Rainier National Park. The NPS expressed their

belief that some or all of the haze was attributable to emissions from the Centralia coal

- fired power plant.

In 1998 , the S WCAA issued a RACT , Order No. 97-2057 R1 , for compliance with the requirements of Chapter 70.94.153 Revised Code of Washington. This order established emission reductions for

SO 2 and NOx emissions from the coal-fired boilers at the plant. The emission limitations in the

Order w ere the results of a negotiation process involving SWCAA, the plant’s ownership group,

NPS , U.S. Forest Service , Ecology, and EPA Region 10.

On June 11, 2003, EPA Region 10 approved Ecology ’s Visibility State Implementation Plan (Visibility SIP ) submitted on November 9, 1999. 6 Ecology included the RACT emission reductions for Centralia as evidence of further progress in meeting the national visibility goals, but not as BART since no determination of attribution had been made as was required by the visibility rules in place in

1997. The Federal Register notice app roving this 1999 submittal notes that while the NPS had certified visibility impairment at Mt

. Rainier National Park

, “The State of Washington has not determined that this visibility impairment is reasonably attributable to the Centralia Power Plant (CPP) .”

The EPA approval of Ecology’s 1999 V isibility SIP submittal includ ed a determination by EPA that

the SO 2 and PM limits and controls required by the 1997 RACT O rder issued by SWCAA met the requirements of BART. EPA’s determination that SO 2 and PM emissions were BART level of control were based on an analysis performed by Region 10 staff and an example analysis in the Technical Support Document issued by SW CAA

.

In the F ederal R egister n otice, EPA specifically did not include the NOx emission limit in the RACT

Order as BART stating “ while the NOx emission limitation may have represented BART when the emission limits in the RACT Order were negotiated, recent technology advancements have be en made. EPA cannot say that the emission limitations in the SWAPCA 7 RACT Order for NOx represent BART.”

6 68 Federal Register 34821, June 11, 2003.

7 At the time, SWCAA was known as the Southwest Air Pollution Control Agency (SWAPCA).As a result of the June 11, 2003, approval of the Washington State Visibility SIP, the TransAlta plant is subject to BART under the Regional Haze (RH) program only for its NOx emissions

. 8



### 1.1 The BART Analysis Pro cess

TransAlta and Ecology used EPA’s BART guid ance contained in Appendix Y to 40 CFR Part 51 , as annotated by Ecology, to determine BART. The BART determination for coal -fired power plants greater than 7 50 MW of total output must follow the process in BART guid ance

. The BART analysis protocol reflects utilization of a five

- step analysis to determine BART. The five steps are:

1. Identify all available retrofit control technologies.

2. Eliminate technically infeasible control technologies.

3. Evaluate the control effectiveness of remaining control technologies.

4. Evaluate impacts and document the results

5. Evaluate visibility impacts.

The BART guidance limits the types of control technologies that need to be evaluated in the BART

process to available control t echnologies . Available control technologies are those which have been applied in practice in the industry. The state can consider additional control techniques beyond those

that are “ available ,” but is not required to do so. This limitation to available control technologies contrasts to the Best Available Control Technology ( BACT ) process where innovative technologies and techniques that have been applied to similar flue gases must be considered.

In accordance with the EPA BART guidance, Ecology weigh s all five factors in its BART

determination s. To be selected as BART, a control has to be availab le , technical ly feasible, cost
effective , provide a visibility benefit, and have minimal potential for adverse non- air quality impacts. Normally , the potent ial visibility improvement from a particular control technology is only one of the factors weighed for determ inin g whether a control constitute s BART. However, if two available and feasible controls are essentially equivalent in cost effectiveness and non- air quality impacts, visibility improvement becomes the deciding factor in the determination of BART.



### 1. 2 Basic Description of the TransAlta Centralia Generation LLC Power Plant

The TransAlta plant is a two -unit, pulverized coal boiler based power plant that currently uses PRB

coal. The boilers were initially commissioned in 1971 and 1972. Each unit is currently rated at 702.5 MW (net) output capacity when using coal from the Centralia coal field . The units are physically

identical

, tangen tially fired, wet bottom units designed by Combustion Engineering.

TransAlta also operates two other generating resources that are part of the Centralia P ower P lant complex. Operating under the name of Centralia Gas is a group of four combined cycle co mbustion turbines producing 248 MW. The combustion turbines were built in 2002 and were subject to

Prevention of S ignificant D eterioration ( PSD ) permitting requirements. They are currently operated as peaking units. The combined cycle turbines are electrically and physically separate from the coal

8 Mahbubul Islam, EPA Region 10, “Best Available Retrofit Technology Applicability for the TransAlta Centralia Power Plant,” letter, addressed to Robert Elliott, SWCAA, and Phyllis Baas, Ecology, September 18, 2007.unit s. There is also a one MW hydropower facility located at TransAlta’s Skookumchuck River Dam

and Reservoir.

In addition to the above electricity generating units, the plant includes numerous other units, including an oil-fired auxiliary boiler used for cold starting of the coal- fired boilers and steam turbines. The auxiliary boiler is a 170 MMBtu/hr, oil- fired unit permitted to operate on #2 distillate oil (with less than 0.5 percent sulfur by weight) for a maximum of 600,000 gallons per year. The SO 2 emissions from fuel oil combustion in this unit are included in the coal boiler SO 2 emission

limitation. The potential to emit of NOx from this unit is 7.2 ton/year and SO 2 of 77 ton/y ear.

SO 2 control on the two coal

- fired boilers is provided by a wet limestone, forced oxidation wet scrubber system . This system removes over 95 percent of SO 2 in the flue gas from the boilers. The

SO 2 controls were installed in the 1999–2002 time period.

Particulate control is provided by two electrostatic precipitators in series followed by the wet scrubber system. The first electrostatic precipitators were part of the original construction of the plant. The second precipitators date from the late 1970s.

Current NOx control is provided by combustion modifications incorporating Alstom concentric firing, low NOx burners with close coupled and separated over- fire air

. 9 These combustion modifications are collectively known as Low NOx Combustion, Level 3 ( LNC3 ).” The controls were installed in the 2000–2002 time period in response to the RACT Order. The combustion controls were designed and optimized to suit Centralia M ine coal.

For a variety of reasons, TransAlta stop ped active m ining at the Centralia C oal Mine and now purchases all coal from P RB coal fields. To accommodate the change, the company has modified the rail car unloading system to handle up to 10 coal unit trains per week. Additional modifications are focused on the boilers. The boilers have been modified to reduce temperatures in the flue gas to accommodate the higher Btu coal now being combusted. Additional changes include the

reinstallation of specific soot blowers and installation of new soot blowing equipment ( steam lances) necessary to accommodate the different ash characteristics of the P RB coals. Improved fire suppression equipment has been installed to accommodate the increased potential of P RB coals to catch fire spontaneously.

The use of PRB coals has resulted in the derating of the output capacity of the facility. TransAlta reports on their corporate internet pages that the Centralia facility is rated at 1340 MW or 670 MW per unit.

Prior to 2010, TransAlta anticipated operating the plant until at lea st 2030. They acknowledge that to operate beyond 2025 will require significant plant upgrades to assure safe and reliable operation into

the future.

On May 21, 2009, the Governor of Washington State issued Executive Order 09-05, Washington’s Leadership o n Climate Change. This Executive Order contained provisions that affected the

9 This set of combustion controls are the basis of the presumptive BART limit s of 0.15 lb NOx/MMBtu in Section 4.E of

EPA’s BART Guideline

.re maining useful lifetime of the coal units at the plant. This Executive Order has now been superseded by amendments to Chapter 80.80 RCW contained in Chapter 180 , Laws of 2011 . These amendments require the coal units at the plant to come into compliance with the GHG emission performance standard established in RCW 80.80.040. One unit is required to be in compliance by December 31, 2020, while the other is required to comply by December 31, 2025. The amendments also provide that if Eco logy determines that state or federal law or regulations require the installation

of SCR on the coal units, that the requirement to comply with the GHG emission standard will not apply.

The powe r plant is subject to the federal Clean Air Act's Title V permitting program. The plant operations are covered by Air Operating Permit No. SW98-8-R3, issued September 2009 by

SWCAA.

Ecology received a BART analysis fr om TransAlta in February 2008, which was revised and

resubmitted in July 2008 and supplemented in December 2008 and March 2010. The original BART

determination was issued June 2010.

The R evised BART Order is based on the above materials supplemented by ad ditional BART decision information and material submitted by letter from Bob Nelson, Plant Manager , to Alan Newman of Ecology on August 8, 2011. This letter respond ed to a preliminary draft of the R evised

BART Order and a Revised BART Determination Support Document that was developed for review and comment by the company, environmental group representatives, and EPA Region 10.



### 1.3 BART Eligible U nits and Pollutant at TransAlta Centralia Power Plant

The TransAlta facility located near Centralia , Washington, includes a number of different operations and units. Emissions from the plant are primarily generated and emitted by the two coal -fired boilers of the main power plant. The oil- fired auxiliary boiler is operated infrequently and is permitted to

use a limi ted number of gallons of diesel fuel oil each year. The auxiliary boiler is used during cold

start -up of the coal boilers to heat the boiler water to prevent thermal shock and failure of cold boiler tubes and for preheating of the steam turbines. Emissio ns from th e auxiliary boiler were not

evaluated for BART.

As noted above, NOx is the only pollutant addressed in this BART analysis. As required by the BART guidance and modeling protocol, the maximum day emission rate in the calendar 2003 to 2005 period was determined

. The hourly NOx emissions on the day with maximum emissions during the baseline period (2003–2005 ) were 2 ,474 lb/hr (0.302 lb/ MMBtu ) for Unit 1 and 2,510 lb/hr (0.306

lb/ MMBtu ) for Unit 2.

### 1.4 Visibility Impact of BART Eligible Units at TransAlta Centralia Power

Plant

Class I area v isibility impairment and improvement modeling was performed by TransAlta using the BART modeling protocol developed by Oregon , Idaho, Washington, and EPA Region 10. 10 This protocol uses three years of metrolog ical information to evaluate visibility impacts. As directed in the protocol, TransAlta used the highest 24-hour emission rates for NOx

, SO 2 , and PM/PM 10 that

occurred in the 3- year period to model its impacts on Class I areas. The modeled SO 2 and PM/

Coarse Particle Matter ( PM 10 ) emission rates complied with their respective emission limits. The modeling indicates that the emissions from this plant cause visibility impairment on the 8 th highest day in any one year and the 22nd highest day as all manda tory federal Class I areas within 300 km of the power plant. 11 For more information on visibility impacts of this facility, see Section 3 below.



### 1.5 Relationship to 1997 R ACT Analysis and Determination

As noted previously, in 1997 the SWCAA finalized a determ ination of RACT for the Centralia Power Plant. As part of the technical analysis that led to the determination of RACT for NOx emissions from this plant, 37 different emission control alternatives were evaluated (see Appendix B for the list) . The analysis documents produced by the plant’s owners reviewed many alternative techniques potentially applicable to the facility. The list of controls reviewed ranged from proven methods of combustion control to methods that had only been proven to work in the laboratory. The alternate technologies evaluated at that time included methods such as natural gas reburn, SNCR, SCR, and several options which could control NOx and SO 2 with the same control system

.

As discussed in the company’s analysis and the SWCAA support document , these technologies were

not selected as RACT for NOx emissions in favor of the installation of the package of combustion modifications that are now recognized as LNC3.

Since the 1997 RACT d etermination , Ecology has tracked development and installations of NOx control technologies. Based on the large list of emission controls that had been reviewed to support

the RACT determination

, the relatively slow development of some techniques, and disappearance of

some other technique s, Ecology allowed TransAlta to use the evaluation fr o m the 1997 RACT determination to narrow the list of potential control technologies appropriate for this BART review.

The BART analysis by TransAlta focused on those controls that are available an d have been implemented on coal-fired boilers of the general size of the plant. For more details on the control options evaluated for the RACT analysis, please refer to the RACT report by PacifiCorp for the Centralia Power Plant and the SWCAA Technical Support Document supporting the RACT

determination.

10 A copy of the modeling protocol is available at http://www.deq.state.or.us/aq/haze/docs/bartprotocol.pdf

. 11 A source causes visibility impairment if its modeled visibility impact is above 1 dv, and contributes to visibility impairment if its modeled visibility impact is above 0.5 dv.

### 2.0 SUMMARY OF TRANSALTA CENTRALIA POWER PLANT’S BART

ANALYSIS

The TransAlta’s BART technology analysis was based on the 5-step process defined in BART guidance and listed in Section 1.1 of this report. This section is an overview of TransAlta’s BART analysis and supplemental material provided by the plant’s owner.



### 2.1 NOx Controls Evaluated

The plant already has installed combustion controls to reduce NOx emissions from thermal NOx

. The controls currently installed are considered the base case from which the effects of other controls

are evaluated.

Table 2 -1 Nitrogen Oxides Controls Evaluated
Control Technology Control Efficiency Technically Feasible?

Low N O x burners with close coupled and separated over

- fire air (LNC3) -- Yes, already installed under

RACT

Flex Fuels Project

— Existing LNC3 combustion controls plus change in fuel to

PRB coal and boiler modifications to

accommodate use of PRB

- type coals Yes, LNC3 already installed, Unit

2 Flex Fuel modifications completed and both units are operating in compliance with the original BART Order signed June
18, 2010

SCR Up to 95%

reduction Yes

SNCR 20 %

- 40 % reduction Yes

ROFA/RotaMix Unknown No

Neural net controls Up to 15% Yes

Low NOx Combustion, Level 3

As noted above, the combustion controls known as Low Nitrogen Oxides Combustion, Level 3, ( LNC3 ) are currently installed on each of the coal

- fired boilers at the plant. These controls have demonstrated an ability to meet the current NOx emission limit of 0.30 lb NOx /MMBtu using

Centralia M ine coal and PRB coal s.

The Centralia Power Plant ’s implementation of the LNC3 technology was included in EPA’s control effectiveness evaluations leading to its determination of the presumptive BART limit s of 0.15 lb

NOx /MMBtu in Section 4.E of EPA’s BART Guideline. In 2004 in connection with its adoption of the final BART Guidelines, EPA found that of the 17 boilers in the U.S. with the boiler design of the Centralia Power Plant’s (tangential -fired) that burn sub-bituminous coal, two of the units with LNC3 installed prior to 1997 did not meet the presumptive BART limit. Seven of the units with pre-1997 design d id meet the presumptive limit. Of the remaining eight units with LNC3 technology installed in 1997 or after, the two Centralia boilers were the only two that did not meet the presumptive limit (EPA

- HQ

- OAQ -2002-076-0446(1) TSD).Subs equent to the public comment period on the proposed BART determination, TransAlta was requested to supply additional information on the installation of LNC3 at this facility. This additional detail is contained in a March 31, 2010, report from CH2M HILL to Mr. Richard Griffit h (Appendix G).

The LNC3 system installed met its original design intent of a one- third reduction in NOx from the

boiler.

Subsequent to the initial burner installation, the company reports no additional analyses or boiler tuning operations beyond what is done in the normal course of operating the boilers.

Flex Fuels Project

TransAlta has proposed its Flex Fuels Project as an addition to the currently installed LNC3

combustion controls for consideration as BART emission control. The Flex Fuels Project is a series of actions being undertaken by the company to accommodate the exclusive use of sub-bituminous coals with ash, nitrogen and sulfur contents similar to P RB sub-bituminous coals. Combustion modeling of the boilers performed by Black & Ve atch using EPRI’s Vista model using a representative PRB coal has indicated that the proposed changes will result in a reduction of t he hourly and annual emission rate for NOx

.

TransAlta decided to rely on PRB coal after suspending mining operations fo r Centralia sub

bituminous coal at the end of 2006. PRB coals have a number of characteristics that differ significantly from the Centralia coal the plant was designed to use. I mportant characteristics that affect the boilers’ operation are the net heat content, the quantity of ash, and the abundance of sodium. Appendix A contains tables showing the important characteristics of typical PRB coals and

the Centralia coal.

The most important differences between the coals is the heat content British Thermal Units Per

Pound (Btu/lb) , lower fuel nitrogen, lower sulfur content , the moisture content, and the concentration

of sodium. Centralia coal is very low in sodium, higher in fuel nitrogen and sulfur content, and much higher in water content than the PRB c oals. The difference in sodium content changes the ash that deposits on the boiler tubes from light and fluffy (Centralia) to glassy and sticky (PRB).

The boiler tube slagging and fouling characteristics of PRB coal increase the heat rates of the boilers compared with Centralia Mine coal. The Flex Fuels Project incorporates physical changes to the pressure parts in each boiler’s convective pass that improve heat transf er

by reducing the boiler’s susceptibility to ash deposition

. The major individual pressure part changes include: (a) reheater

r eplacement to maximize soot blower cleaning effectiveness on the tube assembly surface areas

, and (b) additional low temperatu re superheater and economizer heat transfer surface area to result in higher boiler efficiency and a lower flue gas exit temperature

. Other significant changes associated with this project are reinstallation of some of the original soot blowers and installation of new ‘soot blowing’ equipment specifically designed to remove the now sticky and glassy soot from the boiler

tubes. These changes allow for more efficient heat transfer within the boiler. Additional discussion of this project’s effects and the c ombustion thermodynamic modeling performed to estimate the emissions decrease from the project can be found in the BART Analysis Supplement by TransAltadat ed Dec ember 2008 and the TransAlta Centralia Boiler Emissions Modeling Study by Black & Veatch, date d Sept ember 2007.

No changes to the fuel delivery equipment (other than adding fire suppression equipment), burners, combustion air system, or steam turbine are being made. The Flex Fuels Project allow s the boilers to burn PRB coal more efficiently, but does not increase the boilers’ potential steam generating capacity.

The lower nitrogen content of the PRB coals combined with the lower total quantity of fuel required to produce the same heat input rate to the boilers after the project has been completed on both units.

The reduction in total fuel combusted will reduce the emissions of NOx by approximately 20 percent from the rates during 2003–2005 period. The emission rates during that baseline period averaged

0.304 lb NOx /MMBtu and at the completion of the Flex Fuels Project are expected to be below 0.24

lb/MMBtu.

Annual average NOx emissions from December 1, 2003 through November 31, 2005 were 15,695 tons. Based on the proposed BART rate of 0.24 lb/ MMBtu , the BART limit would reduce emissions by 3 ,139 tons/year to 12,556 tons/year.

The estimated capital to implement Flex Fuels on both units is $101,808,663, based on the actual costs to implement the Flex Fuels Project on Unit 2 and the expected costs of installation on Unit 1.

The annualized cost o f the Flex Fuels Project is $11,184,197. Based on the estimated NOx reductions of 3,139 tons/ year , the cost effectiveness of the Flex Fuels Project is $3,563/ton of NOx

reduced . S ince the Flex Fuels Project also reduces SO 2 emissions by an estimated 1 ,287 tons/year,

TransAlta has calculated that the overall cost effectiveness of the Flex Fuels Project as $2,526/ton of

NOx plus SO 2 reduced

. 12

Neural N et Controls

Neural net controls for boilers are a relatively new technique. It is based on using a number of different boiler operational information and using that information to continuously optimize the combustion efficiency of the boiler. While numerous vendors will provide this technology,

Trans Alta received detailed information from NeuCo, Inc. (NeuCo)

. NeuCo offers several neural net optimization products. Two of their products, CombustionOpt and SootOpt, provide the potential for

NOx reduction at some facilities. Both CombustionOpt and SootOpt are control- system

- based products. CombustionOpt provides for optimized control of fuel and air to reduce NOx and improve fuel efficiency. SootOpt improves boiler soot blowing by proportioning heat transfer and reducing “hot spots” resulting from ine ffective cleaning. NeuCo stated that these products can be used on most boiler control systems and can be effective even in conjunction with other NOx reduction technologies.

NeuCo predicts that generally CombustionOpt can reduce NOx by 15 percent, and SootOpt can provide an additional 5 to 10 percent. Expected NOx reductions are very unit

- specific, and actual results may vary greatly. Previously received budgetary prices for CombustionOpt and SootOpt were

12 Because the Flex Fuels Project is not being implemented for the primary purpose of emissions reduction, these cost

effectiven ess values are not directly comparable to those for installation of a control technology.$150,000 and $175,000, r espectively, with an additional $200,000 cost for a process link to the unit control system.

Because NeuCo does not guarantee NOx reduction, the estimated emission reduction levels provided

are not considered as reliable projections. In light of the uncertain and unquantifiabl e emission reductions, T ransAlta considers a neural net s ystem as a potential supplementary or polishing technology, but not as a n applicable NOx technology for this BART analysis. Because of the potential NOx reductions and cost effectiveness, TransAlta is continuing to investigat e use of this technique at this plant.

Selective Nonc atalytic R eduction

SNCR i s generally used to achieve modest NOx reductions. It is often chosen to augment combustion controls on older coal-fired boiler units, which are generally smaller units (units with heat input less than 3,000 MMBtu/hr) and industrial boilers. With SNCR, an ammonia or urea

solution is injected into a location in the furnace that provides a temperature range of 1,600 degrees Fahrenheit (°F) to 2,100°F and provides a minimum detention time for the reaction to occur. Within this temperature range

, the ammonia or urea reduces NOx to nitrogen and water. NOx reductions of up to 60 percent have been achieved, although 20 to 40 percent is more realistic fo r most applications.

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NOx , can range from 20 to 60 percent, depending on the amount of reduction to be achieved , unit size, operating conditions, and allowable ammon ia slip. If the temperature in the boiler at the location of the ammonia injection is too high or too much ammonia is injected, the ammonia or urea is oxidized

to NOx

. With low reagent utilization, low temperatures, or inadequate mixing, ammonia slip occ urs, allowing unreacted ammonia to create problems downstream.

There are a number of potential adverse impact s due to ammonia slip. U nreacted ammonia can contaminate the fly ash collected in the ESPs that is sold for making concrete. If the ammonia

con centration in the fly ash is high enough, it will render the fly ash odorous and unsaleable

. 13 If the fly ash is unsaleable to make concrete, it would require disposal in a landfill or could be sold to a cement plant as a raw material to make cement. If used to make cement, the heating of the fly ash in a cement kiln will release any mercury that may be contained in the fly ash.

Two additional issues with ammonia slip are that ammonia is listed as a toxic air pollutant by Ecology, and its discharge from the stack may result in additional impact s. The unreacted ammonia

may also react with sulfur oxides to generate ammonium sulfate or bisulfate to foul economizer, air preheater, and other duct surfaces . At facilities where there is no wet scrubber system included,

excess ammonia may also create a visible stack plume. Since the TransAlta plant has a wet scrubber, no additional plume visibility would be anticipated.

13 Fly ash is reported to lose its desirability as a concrete admixture if the ammonia content is high enough that detectable

levels of ammonia will be volatilized fro m the fly ash when it is mixed into the wet concrete. Ammonium on or in the fly ash is converted to ammonia when the pH of the mixture rises. At a pH of 12, essentially all the ammonium is converted to ammonia in solution. Based on Ecology’s review of t he available literature, it is unlikely that a properly controlled SNCR system will cause any adverse impacts to fly ash sales due to ammonia slip.The control effectiveness of SNCR is a function of many variables, including the uncontroll ed emissions concentrations, physical conditions, and operational conditions. A study by Harmon 14
(1998) indicates that a large coal fired, tangentially fired unit equipped with a low NOx SNCR has the potential to reduce NOx emissions by only 20 to 25 percent with an ammonia slip of less than 10 ppm. The EPA Office of Air Quality Planning and Standards’ EPA Air Pollution Control Cost

Manual (EPA, 2002) states, “SNCR systems applied to large combustion units (greater than 3,000 MMBtu/hr) typically have lower NOx reduction efficiencies (less than 40 percent), due to mixing

limitations.” The Centralia P ower P lant units have heat input rates of much greater than 3,000 MMBtu/hr (abo ve 7,000 MMBtu/hr 15 ). After considering the above factors and a reasonable compliance factor, TransAlta selected a control effectiveness of 25 percent for its evaluation

.

T ransAlta’s cost analysis uses a urea

- based SNCR system providing a nominal 25 percent reduction

in NOx levels with a 5 ppm ammonia slip. A 5 ppm ammonia slip is the maximum recommended taking into account the flue gas sulfur levels to avoid problems with ammonium sulfate and bisulfate fouling of the air heater. To achieve the proposed reduction, multiple n ozzle lances are proposed to handle load changes from 50 to 100 percent.

Retrofit costs to incorporate SNCR at this facility are included in the cost estimate. These retrofit costs are higher than for other similarly sized facilities d ue to an extremely tight boiler outlet configuration, limited available space for new equipment , probable modifications to boiler tubes to accommodate the urea injection lances, construction access difficulties to install SNCR injection equipment, and location of urea storage and solution preparation equipment.

TransAlta has estimated that use of SNCR on their units would consume about 700 kW-h of electricity per unit, or a total of 1.4 MW-h for both units.

The anticipated 25 percent reduction in emissions from the installation of SNCR would result in an emissions limitation of 0.225 lb/MMBtu and an emission reduction of 3,923 tons /year. TransAlta has estimated that the estimates of capital cost including the retrofit costs, adding S NCR to both units at the plant would cost $33.2 million with a cost effectiveness of $2,258/ton NOx reduced.

Subsequent to the public comment period on the proposed BART determination, TransAlta was requested to supply additional information on the use and cost of SN CR at this facility. T he company had its contractor supply additional information related to the basis of its SN CR cost estimates. This additional detail is contained in a March 31, 2010, report from CH2M HILL to Mr. Richard Griffith (Appendix G) . The additional detail indicates the cost estimating approach utilized by CH2M HILL on this BART analysis.

The March 31, 2010, report indicates that the SNCR cost estimates in the June 2008 BART analysis were “budgetary estimates” supplemented by vendor quote of costs and NOx removal efficiency from

Fuel Tech.

Selective Catalytic Reduction

14 Harmon, A., et al

, 1998

, Evaluation of SNCR Performance on Large

- Scale Coal

- Fired Boilers

, Institute of Clean Air Companies (ICAC) Forum on Cutting NO
x Emissions, Durham, NC, March 1998

. 15 2008 Acid Rain Program report lists the heat input rate at 8500 MMBtu/hr/boiler.SCR works on the same chemical principle as SNCR, but SCR uses a catalyst to promote the

chemical reaction. Ammonia or urea is injected into the flue gas stream, where it reduces NOx to nitrogen and water. Unlike the high temperatures required for SNCR, the SCR reaction takes place

on the surface of a vanadium/titanium- based catalyst at a temperature range between 580°F and

850°F. Due to the catalyst, the SCR process is more efficient than SNCR result ing in lower NOx and

ammonia emissions. Typically , an SCR system can provide between 70 and 95 percent reduction in

NOx emissions.

On coal -fired power plants, the most common type of SCR installation is kno wn as the hot-side highdust configuration, where the catalyst is located downstream from the boiler economizer and upstream of the air heater and particulate control equipment. In this location, the SCR is exposed to the full concentration of fly ash in the flue gas that is leaving the boiler. An alternate location for an SCR system is downstream of the air heater or the particulate control device. In many cases, this location is compatible with use of a low temperature SCR catalyst or is within the low end of the temperature range of a conventional catalyst. Because the temperature of the flue gas leaving the air

heaters and the Electrostatic Precipitators ( ESPs ) is too cool for the low temperature versions of SCR catalyst to operate, t he high-dust configuration is assumed for TransAlta

.

In a new boiler installation or a retrofit installation where the existing boiler has minimal emission controls installed, the flue gases flow downward through the catalyst to aid in dust removal. In a retrofit situation, the SCR catalyst is often located in the existing gas duct, which may be expanded in the area of the catalyst to reduce flue gas flow velocity and increase flue gas residence time to maximize removal efficiency and minimize ammoni a usage

. As an alternate location, the catalyst

bed in a retrofit situation may be installed in a “loop” of ducting. This loop may be horizontal or vertical in orientation, depending on how the flow in the duct that is intercepted is routed and

available space to locate the catalyst bed.

A new installation type SCR costing was used as the basis for analysis at the Centralia Power Plant

because of the limited space to install an SCR catalyst in the existing flue duct and the ability to design for a 90-plus percent reduction catalyst bed

. The short distance between the boiler air heater and the entrance to the first ESP does not provide the room required for a catalyst bed with

reasonable temperatures or velocities to be inserted in the existing flue gas duct. 16 The ducts from

each boiler to the ESP have a relatively high velocity, such that the amount of catalyst that could fit into the unmodified duct would have minimal effectiveness due to the short residence time through the catalyst bed.

As a result of electing to use a design capable of 90 -plus percent NOx reduction, an adjustment was

used for SCR cost estimates due to the Centralia Power Plant ’s extremely tight boiler outlet ductwork configuration as shown in Figures 3-3, 3-4, and 3-5 of the June 2008 Revised BART Analysis and March 2010 supplement. As can be seen in the figures, installation of a full- scale SCR system requires reconfiguration of the flue ducts from the boilers, structural modifications of the first ESP s (or installation of a ll new structural support to hold the weight of the catalyst beds and ductwork) to accommodate the weight of the SCR catalyst and duct work, and realignment of the duct work from

16 See Figures ES

- 1, 3.2, 3

- 4, and 3.5 of the BART Analysis for Centralia Power Plant, revi sed July 2008 and supplemented March 2010.th e economizers to the air preheaters

. The restricted site layout , support structure needs , intricate duct routing, limited construction space, and complexity of erection increases the capital cost.

E ach boiler at the Centralia Power Plant has two exhaust gas ducts to aid in splitting the flow to the

ESPs. As a result

, each boiler would require two smaller

, separate catalyst vessels instead of a single large catalyst vessel. The capital cost of installing dual catalyst vessels for each unit is slightly greater than a single catalyst vessel for units of similar size.

As in the c ase for SNCR, a potential adverse impact due to unreacted ammonia from the SCR system is that it may render fly ash unsaleable. At facilities where there is no wet scrubber system included, excess ammonia could also create a visible stack plume. Again, TransAlta has a wet scrubber, so a visible stack plume from ammonia is not likely.

As stated in TransAlta’s BART analysis, a SCR retrofit increase s the electricity consumed by the existing flue gas fan system to overcome the additional pressure drop associated with the new catalyst, typically a 6

- to 8- inch water gage increase

. 17 The increase in pressure drop r esults in marginally higher operating costs. Since the BART analysis uses a planning level cost analysis, there

has not been a more detailed engineering study of all components that may be affected by adding the SCR system

.

TransAlta evaluated twp options to use SCR at the plant. One option included SCR on only one unit to achieve the Presumptive BART emission limit of 0.15 lb NOx /MMBtu , both units averaged together. The other option included SCR on both units.

The emissions reduction for installation of SCR (at a 95 percent removal rate) on one unit would be 4,364 tons/year. The capital cost for including SCR on only one unit was estimated to be $290.1

million with a cost effectiveness of $8,205/ton NOx reduced.

The emissions reduction for installation of SCR (at a 95 percent removal rate) on both units would be 7,855 tons/year. The capital cost for including SCR on both units would be double that for one unit with a cost effectiveness of $9,091/ton NOx reduced.

Subsequent to the public comment period on the proposed BART determination, TransAlta was requested to supply additional information on the use and cost of SCR at this facility

.

In addition to the more readily readable drawings (Appendix F), the company had its contractor supply additional information related to the basis of its SCR cost estimates. This additional detail is

contained in a March 3 1, 2010

, report from CH2M HILL to Mr. Richard Griffith (Appendix G). The additional detail indicates the cost estimating approach utilized by CH2M HILL on this BART analysis. The approach described involved a company re evaluation of historical informatio n updated with current equipment, material , and constructions costs, including cost estimates based on preliminary engineering sketches. The March 31 submittal indicates that a basic capital cost for a SCR system of $200/kW was used as the basis for the c ost estimate. This basic cost was then scaled by CH2M HILL ’s engineering judgment of the costs and complexity to install a SCR system on these boilers. As part of this additional analysis, the predicted TransAlta costs were compared to costs for

17 Associated with providing a gas velocity through the catalyst beds below 20 ft/sec.ot her coal -fired power plants in the western U.S. (in Attachment 1 of the March 31, 2010 report). The cost analyses compared were performed by CH2M HILL and four other consulting firms. M any have been determined to be BART by the various states . The cost for SC R at the Boardman OR plant is listed as $382/kW versus $413/kW at Centralia. Both costs can be considered to be essentially equivalent since both are well within the +/ -30% cost estimating range of the EPA Control Cost

Manual and CH2M HILL ’s +50%/ -2 0% estimate range of each other’s cost analyses

.

The March 31, 2010, report also contains an improved description of how CH2M HILL envisioned the proposed SCR system to be installed and operated. Their proposal would have the SCR system installed in a “hot, dirty” location taking hot flue gas from the economizer and returning it to before the air preheater. The “hot , dirty” location in the flow path assures the catalyst bed would be at proper operating temperatures. The catalyst beds would be located above the first ESPs to avoid structural supports in the current access way under the divergent ducting between the air preheater

and the ESP inlets. Structural s upports would block plant operations and maintenance staff access to equipment and the ESPs. Loca ting the catalyst above the ESP would also provide the duct length to provide for lower velocities through the catalyst bed. The structural needs to support the weight of the ductwork and the catalyst beds were evaluated qualitatively.

In response to Ecology’s questions resulting from public comment, TransAlta had CH2M HILL

evaluate two other locations where SCR catalyst could be installed (Appendix G).

One location evaluated an installation between the ESPs and the wet Flue Gas Desulfurization ( FGD )

s ystem. The analysis indicates the anticipated difficulties due to changes in flue gas volume and

velocit y resulting from reheating the flue gas to 700°F and adding aqueous ammonia reagent. The potential adverse impacts of flue gas reheating (even through a regenerative system) on operation of

the wet scrubber s w ere not evaluated

.

The other location is in the ESP inlet ducting after the air preheater

. The air preheater outlet is

300°F , well below the normal range for SCR catalysts. To increase the temperature of the gas exiting the air preheater would require changes to the plant thermodynamics (by reducing the temperature of combustion air) and would impact the overall plant heat rate and efficiency . I n this location, CH2M

HILL has estimated that the c atalyst bed could be no more than 17 f ee t deep without requiring significant modifications to the ductwork from the economizer to the air heater. CH2M HILL presents information that in this location, one layer of catalyst would provide a five percent decrease

in NOx with a five inch water gauge pressure drop. A 2- layer system would increase removal to 12

percent at a pressure drop of 15 inches water gauge

. The effects of an increased back pressure on the boilers or the ability of the induced fans to accommodate this much increase in pressure drop was outside of the scope of CH2M HILL ’s contract.

Rotating O ver

- fire A ir and Rotamix

Mobotec markets R otating O ver

- fire A ir ( ROFA ) as an improved second-generation over- fire air distribution system. In their system , the combustion gases in the boiler are set in rotation with asymmetrically placed air nozzles. According to Mobotec installation information, the ROFA technology alone has not bee n installed on any tangentially fired coal unit greater than 175 MW.The Mobotec Rotamix technology is a modification of the SNCR process. The ammonia or urea solution is added using lances in conjunction with the ROFA air nozzles to improve both the

chemical distribution and lengthen the residence time for the reactio ns to occur. According to the Mobotec installation list, the largest tangentially fired coal unit using the Mobotec ROFA/Rotamix

combination is 175 MW. The Rotamix SNCR system is anticipated to provide NOx reductions similar to conventional SNCR systems

. 18

Based upon the BART guidance, Mobotec ROFA and Rotamix technologies are ‘available’ because they have been installed and operated successfully on tangentially fired pulverized coal boilers.

TransAlta believes that while the ROFA and Rotamix technology are ‘available’ control technolog ies as described in the BART guideline, the use of either ROFA as a replacement or addition to the

current over

- fire air injection system or installation of the Rotamix process are not technically

feasible technologies due to unknown difficulties with installation on their boilers. Due to perceived

risks of scale -up to their unit size, TransAlta believes that these technologies are not applicable to their facility.



### 2.2 TransAlta’s Propo sed BART

T he existing LNC3 co mbustion controls (low NOx burners, close coupled and separated over- fire air) currently installed at the plant and the Flex Fuels Project meeting an emission limitation of 0.24 lb

NOx /MMBtu , 30- day average, were propose d as B ART for their facility.

Subsequent to TransAlta’s BART analysis submittals, which proposed the Flex Fuels Project as BART, TransAlta, the Governor’s office, environmental organizations, and state legislators negotiated a different set of emission control requirements.

The end result of the negotiation and agreement was enactment of amendments to Chapter 80.80, Revised Code of Washington, which requires the coal units at the plant to implement SNCR control by January 1, 2013, and to meet the state GHG emission performance standard in 2020 and 2025. All parties of the negotiation anticipate compliance will be through decommissioning of the existing coal

fired units at the Centralia Power Plant.



### 3. 0 V ISIBILITY I MPACTS AND D EGREE OF I MPROVEMENT

TransAlta modeled the visibility impairment for the baseline years per the modeling protocol and the potential improvement f rom the control scenarios that they evaluated as potential BART controls for their facility . In modeling the emissions, they followed the BART modeling guidance prepared for use by sources in Washington, Oregon, and Idaho. In accordance with the EPA BART guidance, this modeling protocol utilizes the CALPUFF modeling system and the ‘old’ Interagency Monitoring of Protected Visual Environments ( IMPROVE ) equation to convert modeled concentrations to visual impairment. This approach is consistent with most of the states included in the Western Regional Air Partnership for modeling individual source visibility impairment. The ‘old’ IMPROVE equation is

used because it is included within the CALPUFF modeling system and is part of the EPA accepted

18 The Mobotec combustion air injection techniques were not evaluated as part of the RACT process. Their development

occurred after the RACT determination had been made.ver sion of the model per 40 CFR Part 51, Appendix W. A new equation is available, but is not

included within the version of the CALPUFF modeling system sp ecified in the modeling protocol.

The results of the TransAlta modeling are shown in Table 3 -1 for all Class I areas within 300 km of the plant plus the Columbia River Gorge National Scenic Area. T able 3-1 shows the maximum day impairment due to TransA lta , the highest of the three 98 th percentile days of each year modeled, and

the 98 th percentile day of all three years modeled. Also shown is the modeled visibility impairment resulting from the control scenarios modeled by TransAlta

. The modeled dv impacts for the baseline

condition and the three control scenarios for the 98 th percentile day (22 nd day over the 3- year period)

are included in T able 3-1. 19

The emission rates modeled were de rived from operating records for each boiler and reflect the highest 24- hour emission rate within the three years that were modeled. The proposed emission rates

were applied to this maximum 24 -hour operating rate and those rates were then used for modeling the visibility impairment/improvement that could be achieve d through the use of the proposed controls.

The modeled emission rates are shown in T able 3-1.

The modeled visibility impairment indicates that the plant causes visibility impairment at all Class I areas within 300 km of the plant. The tables include m odeled visibility levels for three alternative control scenarios, including the highest level of control considered by TransAlta to be available for the plant, SCR applied to both boilers.

Ecology modelers have reviewed the modeling performed by TransAl ta and have found that the modeling complies with the Modeling Protocol and produces a reasonable result.

The modeled emission reductions from the control options modeled by the company result in

substantial reduction in the visibility impairment caused by the Centralia Power Plant in all Class I areas modeled and in the Columbia River Gorge NSA. For example, Table 3 -1 20 shows that a t the

three most heavily impacted Class I areas, Olympic National Park, Mt. Rainier National Pa rk, and the

Goat Rock s Wilderness, TransAlta ’s proposed BART controls would provide 1.13 to 1.45 dv reduction in visibility impairment in each of these areas. All Class I areas within 300 km of the plant are modeled to have visibility improvements of at least 0.2 dv from the NOx emission reduction from

use of SNCR or Flex Fuels . Combined with the effe c ts of the reduction in SO 2 from implementation proposed BART controls, the minimum visibility improvement is 0.67 dv.

The initial modeling for the control scenarios in the table evaluated only the NOx reduction impacts.

Effects of SO 2 reductions, which would occur as a result of implementing the Flex Fuels Project

,

were not initially evaluated by TransAlta

.

The actual SO 2 emission rates from usage of PRB coals are anticipated to result in an additional reduction of about 1, 287 tons/y ea r from the baseline emission rates . Subsequent to the public

19 See the BART Determination Modeling Analysis, TransAlta Centralia Generation Power Plant by Geomatrix Consultants, Inc, June 2008, for additional information on the modeling results for the other control scenari os evaluated. This report is part of the July 2008 BART analysis report.

20 Revised from the prior version of this document with the modeling results in the March 2010 modeling. This additional modeling was performed in response to public comments on the proposed BART determination.com ment period, Ecology requested and TransAlta remodeled the Flex Fuels Project emissions to

include th e effect of the SO 2 reduction from use of the PRB coals. The results of this remodeling are portrayed in Table 3-1. Control Scenario 3 was not included in the table as presented during the public comment period but was available in TransAlta’s July 2008 BART Analysis Revision.

In their review of the initial modeling results, TransAlta’s modeling consultant evaluated the modeling results to see if there were any patterns to the modeled impacts, such as season of the year, primary pollutant, or grouping of Class I area. Their revie w indicated that groups of Class I areas exhibited similar patterns . They found that the 12 Class I areas fell into four groups, which coincide with both their physical locations and the modeled visibility effects. For their evaluation, see pages 8 and 9 of the June 2008 BART modeling report.

The important points to consider are that for the “East” group (Mt. Rainier N ational P ark and Goat Rocks and Mt. Adams Wildernesses) most impacts occurred in the summer due to SO 2 emission s. The expected high impacts due to NOx do not occur because the weather patterns transport the plant’s plume to other areas in the winter seasons. The impacts on Olympic National Park , (the sole member of the “Northwest” group) occur during wintertime stagnation episodes. While not mentioned in the report, this impact would be dominated by nitrates. For the “South” group (Mt. Hood, Mt. Jefferson, and T hree Sisters Wildernesses) there are summertime impacts, but the highest potential visibility changes occur in the winter during wintertime stagnation episodes. Again, the wintertime events are dominated by nitrates. A t the remaining four Class I areas ( the “Northeast ” group), there was no obvious seasonality or trends. The figures in Appendix D graphically depict this

information for some of the Class I areas.

Overall, t he visibility impacts from the plant ’s emissions on Class I areas are dominated by nitrates. The tables in Appendix D 21 depict the chemical species contributions to visibility impairment for the baseline case, the Scenario 2 Flex Fuels case and the Scenario 1 SNCR case as predicted by

C AL PUFF. Again, consistent though not identical with the evaluation by TransAlta’s modeling consultant, at most nearby Class I areas, the visibility impairment on the 98th percen tile worst days is primarily caused by the nitrate resulting from the plant’s emissions. These worst days primarily occur in the September through June time period. Conversely, at the more distant Class I areas, the visibility impairment is more variable, but the 98th percen tile days usually occur in the June through September period and are dominated by sulfates. For more details , please refer to the modeling reports supplied by TransAlta.

As noted above, TransAlta was requested to remodel the emissions from the project as a result of public comment on the proposal. They remodeled two scenarios using the same modeling protocol as used in the initial modeling. The two scenarios were the Flex Fuels and the Flex Fuels plus SNCR control options. The emission rates are consistent between the scenarios, with only the NOx rate changing to r eflect the anticipated 25 percent reduction in NOx from the application of SNCR to the

emissions from the Flex Fuels Project . The modeling results are contained in a report attached to a March 26, 2010, e-mail from Ken Richmond of Environ to Alan Newman and Clint Bowman of Ecology (Appendix H).

21 From Geomatrix BART Modeling Reports, June 2008 and January 2008.Th e visibility impacts depicted in Table 3 -1 have been updated to reflect the results of the revised modeling. The maximum 24 -hour emission rate for SO 2 in the revised Control Scenario 2 and new

Control Scenario 3 is based on the ratio of the average sulfur content of Jacobs Ranch PRB coal to the average of the Centralia Mine coal used in the 2003–2005 time period . The maximum 24-hour

NOx emission rate u sed in the Flex Fuels only control scenario is as modeled previously. The NOx rate for Flex Fuels plus SNCR is a 25 percent reduction from the Flex Fuels only rate.

Ecology did not request that TransAlta remodel their SCR control scenarios reflecting the use of low sulfur PRB type coals. The modeling results assume that TransAlta would return to using Centralia

coal as a primary fuel for the boilers. Based on the modeling performed on Flex Fuels and Flex Fuels plus SNCR, there would be additional visibility improvements were PRB coal continued to be used by the facility and SCR added.Tabl e 3

- 1 Three

- Year Delta Deciview Ranking Summary

Class I Area Visibility Criterion Baseline
Emissions Control
Scenario 1:
SNCR Control
Scenario

2 : Flex

Fuel Control
Scenario 3 :

Flex Fuel plus SNCR Control
Scenario 4 :

SCR on both units Alpine Lakes

Wilderness Max 98% value (8th high) in any year 4.871 4.393 3.564 2.949 3.057

3

- yrs Combined 98% value (22nd high) 4.346 3.844 2.994 2.598 2.531

Glacier Peak

Wilderness Max 98% value (8th high) in any year 3.615 3.209 2.403 2.049 2.036

3

- yrs Combined 98% value (22nd high) 2.622 2.294 1.905 1.532 1.562

Goat Rocks

Wilderness Max 98% value (8th high) in any year 4.993 4.398 3.676 3.069 3.137

3

- yrs Combined 98% value (22nd high) 4.286 3.708 3.108 2.637 2.385

Mt. Adams
Wilderness Max 98% value (8th high) in any year 3.628 3.118 2.646 2.194 1.984

3

- yrs Combined 98% value (22nd high) 3.628 3.152 2.591 2.147 1.934

Mt. Hood

Wilderness Max 98% value (8th high) in any year 3.471 3.051 2.346 1.978 2.082

3

- yrs Combined 98% value (22nd high) 2.830 2.388 1.997 1.665 1.543

Mt. Jefferson

Wilderness Max 98% value (8th high) in any year 2.079 1.784 1. 399 1.150 1.159

3

- yrs Combined 98% value (22nd high) 1.888 1.596 1.267 1.053 1.061

Mt. Rainier

National Park Max 98% value (8th high) in any year 5.447 4.774 4. 318 3.606 3.359

3

- yrs Combined 98% value (22nd high) 5.489 4.743 4.225 3.501 3.275
Mt. Washington
Wilderness Max 98% value (8th high) in any year 2.027 1.756 1. 323 1.106 1.170

3

- yrs Combined 98% value (22nd high) 1.414 1.248 0.872 0.737 0.855

North Cascades

National Park Max 98% value (8th high) in any year 2.821 2.496 1.852 1.570 1.658

3

- yrs Combined 98% value (22nd high) 2.212 1.887 1.486 1.228 1.183
Olympic National

Park Max 98% value (8th high) in any year 4.645 4.040 3.192 2.695 2.506

3

- yrs Combined 98% value (22nd high) 4.024 3.456 2.991 2.486 2.339
Pasayten
Wilderness Max 98% value (8th high) in any year 1.954 1.701 1. 287 1.075 1.160

3

- yrs Combined 98% value (22nd high) 1.482 1.318 0.999 0.822 0.864

Three Sisters

Wilderness Max 98% value (8th high) in any year 2.172 1.910 1. 333 1.139 1.172

3

- yrs Combined 98% value (22nd high) 1.538 1.328 0.993 0.819 0.902

Class II area modeled per the Modeling Protocol

Columbia River Gorge National
Scenic Area Max 98% value (8th high) in any year 2.545 2.193 1.748 1.446 1.347

3

- yrs Combined 98% value (22nd high) 2.353 1.942 1.657 1.378 1.182

Modeled Rates (lb/hr) Both units added together

NOx

-- > 4,984 3,738 3

, 936 2,952 1148

SO 2 -- > 4,522 4,522 1,854 1,854 4,522

The 8 th day in any year or the 22 nd day over the 3 year period, are the 98 th percentile days.

### 4.0 ECOLOGY’S BART DETERMINATION

Ecology has reviewed the information submitted by TransAlta

. The following discussions present

our rationale for our determination.



### 4.1 NOx Control

The BART analysis reports and supplemental material provided by TransAlta indicate that the Flex

Fuels Project and SNCR are the only feasible controls for use at the Centralia P ower P lant. We concur with their opinion on controls. This concurrence is based on o ur evaluations of their

submittals plus Ecology research on potential controls.



### 4.1.1 Control opti ons determined not to be feasible

Three available control technologies were evaluated and determined not to be feasible NOx controls

for use at the Centralia Power Plant . In addition, one available control option, natural gas reburning,

had been evaluated for the 1997 RACT determination , but w as not reevaluated by TransAlta in their BART analysis . Ecology has determined that none of these control technologies are feasible controls

of NOx at the Centralia Power Plant

.

Rotating Over

- fire Air/RotaMix

TransAlta did evaluate the installation of the Mobotec ROFA technology. Both Ecology and TransAlta found that this air injection technique has been neither tested nor demonstrated in tangentially fired coal boilers of this size. Similarly, the Mobotec RotaMix technique for SNCR has not been tested or demonstrated on boilers of this size. For both Mobotec technologies, the largest tangentially fired unit reported to have the equipment is 565 MW. 22

, 23 This rating is below that of

TransAlta’s units , which are rated at 700 MW each.

Emissions information on the recent installation is not published. The technology remains untested or demonstrated on units the size of the TransAlta facility. With the current lack of information on the control efficiency on the 565 MW plant, there are questions about the capabilities of scaling the technology up to Centralia size. Under BART, facilities are not expected to assume large risk or expense for installing a new technology or technique on an untried s ize or type of facility

. 24 As a result, Ecology concurs with TransAlta that these techniques are not yet technically feasible for use on this facility.

Neural Nets

22 As of 2009, The NALCO/Mobotec reports the largest tangentially fired pulverized coal unit using ROFA or Rotamix was 565MW, Minnesota Power’s Boswell Unit #4. The next two largest units listed by the company are a 424 MW wall

fired unit and a 577 MW opposed fired unit achieving a 55% reduction to 0.25 lb NOx/MMBtu on bituminous coal. Jay Crilley (Nalco), telephone conversation, June 24, 2009.

23 In spite of the limited application of the Mobotec ROFA technology, EPA did evaluate in its analysis of control techniques when evaluating the presumptive BART limitations. Go to the EPA’s Regional Haze Rule Docket for EPA

HQ

- OAR

- 2002

- 0076

- 0446(1) TSD.xls

. 24 40 CFR P art 51, Appendix Y

, S ection IV. D.Thi s technique is an available control technology. However, Ecology agrees with TransAlta that the use of this technique at the Centralia Power Plant is not guaranteed to reduce emissions. TransAlta is likely to continue to evaluate the appropriateness of installation and us e of a neural net combustion optimization process at the facility and may at a future date choose to include it for polishing and

fine -tuning operations beyond what can be achieved by their human operators.

Natural Gas Reburning

Natural gas reburning has the potential to reduce NOx emissions. Natural gas reburning is a technique where natural gas is injected into the boiler above the last over

- fire air ports and additional

over- fire air ports are added above the natural gas injection level. The natural gas has the effect of reducing part of the nitrogen oxides to nitrogen gas, carbon dioxide, and water. The technique has an

estimated control effectiveness of 40 to 50 percent

.

Ecology has looked briefly at the use of natural gas reburning to reduce NOx from these boilers. A review of the EPA RACT/BACT/LAER Clearinghou se database does not include any listings of this technique being used on a ny coal

- fired boiler of any size. The lack of any entries showing use of this technology for coal- fired boilers of any size or type leads us to question whether this control technique is truly available. A review of NOx contro l literature from the late 1990 s indicates there was a lot of interest and evaluations of various methods to implement reburning, including the use of pulverized coal as the fuel. W hile there was much experimentation, it appears that low NOx burner/combustion controls were the dominant technology being implemented at that time.

A 2005 r eview of NOx control techniques available for coal fired boilers listed 26 plants that have

instal led or tested reburning 25 . Of these 26 plants, only 4 were indicated as still using reburning

when the review was written. The report’s authors express the belief that the reason the control is not used on the plants where it is installed is simple economics; it is costly to operate the reburn process. The 4 largest units listed in the review article, bracket TransAlta in size, but none of them were operating their reburning equipment. The few NOx emission limitations listed for reburning have higher emission rates than the control level achievable by Flex Fuels or SNCR

. Based on the limited published information on installation of reburning on units the size of Centralia , we question the ability of the technology to achieve a level of control comparable to Flex Fuels or SNCR

.

Natural gas reburning was not cost effective (compared to the installation of LNC3 combustion controls) in 1997. The cost of natural gas is the primary cost of using this technology. Natural gas

cost s in Washington State have in creased significantly since 1997 , while natural gas pipeline capacity serving the part of Washington west of the Cascade Mountains has not expanded significantly.

SWCAA determined in 1997 that this control technique was not cost effective. Ecology is of the opinion that reburning is still not cost effective for implementation at the plant.

25 See Reference 5 for details.

### 4.1.2 Evaluation of con trols determined to be feasible

Low NOx Combustion, Level 3 /Flex Fuels

As described in Section 2, the Flex Fuels Project is to allow the boilers at this plant to utilize PRB

coals and accommodate its potential increased fire hazard . These modifications are relatively simple

and well known in the coal combustion industry. Compared to the Centralia M in e coal, PRB coal contains less nitrogen and has higher energy content. These two factors work together to reduce the

NOx emissions from the boilers.

The estimated capital cost to TransAlta to implement the Flex Fuels Project is $101,808,663. The

annualized cost of the Flex Fuels Project is $11,184,197. Based on the estimated NOx reduction of 3,139 tons/y ea r, the cost effectiveness of the Flex Fuels Project is $3,563/ton of NOx reduced. Since the Flex Fuels Project also reduces SO 2 emissions by an esti mated 1,287 tons/year, the cost effectiveness of the Flex Fuels Project is $2,526/ton of NOx plus SO 2 reduced.

Selective Catalytic Reduction

For new coal-fired power plants, SCR is the BACT control technology of choice to reduce NOx emissions. In some cases, the use of SCR is being considered to be the technology to be implemented for BART. TransAlta has presented a number of technical difficulties to implementing

SCR at the Centralia Power Plant . The primary difficulty identified is a lack of space for easy installation of the catalyst beds and ducts, leading to very high estimated construction costs that far surpass ranges of acceptable cost effectiveness.

In response to public comment on the clarity of the plan and profile drawings supplied, Ecology acquired additional layout drawings from TransAlta with dimensions and elevations more readily discernable to reviewers (Appendix F). The drawings indicate that the location proposed for installation of a SCR system is on top of the first ESP bank. This is at an elevation of approximately 80 feet in the air, above the precipitator. This is also the elevation of the air preheaters. The horizontal distance between the outlet of the air preheater and the ESP is 55 feet. As indicated in the drawings, in this 55 ft distance, the flue gas currently has to turn 90 degrees and spread it out across

the full width of the ESP inlet.

TransAlta also supplied an explanation of the anticipated flow routing for the proposed SCR

installation. As described in CH2M HILL ’s March 31, 2010, report to TransAlta (Appendix G), they envision a “hot, dirty” SCR installation. In other words, the flu gas would be intercepted on leaving the boiler economizer (located before/above the preheater), routed through the SCR unit, and returned to the air preheater inlet.

A “hot, dirty” installation provides flue gas within the normal operating range of a S CR catalyst, but a high concentration of particulate matter. Installing a SCR c atalyst after the air preheater or after the ESPs would require reheating the fl ue gas to SCR operating temperatures.

The March 2010 report identified additional engineering analyses that would be required to improve the construction cost estimate. These additional analyses include a fluid dynamics evaluation forea ch possible location, an evaluation of new structures needed to support ductwork and catalyst beds,

considerati on of maintenance access to the ESPs and other equipment in that area of the plant, and a construction difficulty evaluation. All of these additional analyses were outside the scope of work for

CH2M HILL ’s March 2010 report.

At Ecology’s request, TransAl ta had CH2M HILL evaluate two alternate SCR locations: in the diverging duct between the air preheater and the ESP and between the ESP and the wet FGD system.

CH2M HILL acquired vendor information about the removal efficiency and head loss of a one and

two layers of catalyst that could be installed within the duct between the air preheater and the ESP. Due to velocity and the limited depth of catalyst bed possible in this location, SCR removal seems to

be limited to five percent for a single layer syste m and 12 percent for a 2

- layer system. As a result of the low removal rates that would be provided by a catalyst system in this location, CH2M HILL did not evaluate the construction costs of this location. In Ecology’s view, there are significant questio ns if these ducts could support the added weight of the catalyst without additional structural support, or if the company could work around the loss of vehicle access for maintenance purposes to the equipment located on the ground under and around the air preheaters and ESPs.

The other location evaluated was in the ductwork between the ESPs and the wet FGD system. As indicated by the drawings in Appendix F, the ductwork is of different lengths and, what is not clearly obvious from the drawings, they have different cross -sectional dimensions. CH2M HILL provided a qualitative analysis of what would be involved in installation of an SCR system between the ESPs and the wet FGD system (Appendix G). Ecology accepts their qualitative analysis as demonstrating the difficulties in retrofitting an SCR system in this location.

Subsequent to the finalization of the original BART order, EPA Region 9 received BART submittals for the Navajo Generating Station and the Four C orners Power Plant. Region 9 has proposed BA RT

fo r the Four Corners plant and is continuing to evaluate additional submittals for the Navajo station. Separately, EPA Region 6 rejected New Mexico’s BART determination and is issuing its final BART determination for the San Juan Generating station.

NPS provided Ecology a copy of a presentation made by the Navajo Generating Station plant owners to EPA and the FLMs. This presentation give s the result of a detailed construction evaluation and a design level construction cost estimate to install SCR at the Navajo Power plant. The units at the Navajo plant are approximately the same capacity as Centralia and the construction difficulties due to layout and previously installed emission controls present a similarly difficult construction project

with three existing boilers with their existing particulate controls, SO 2 scrubbers and stacks placed adjacent to each other with little space between them. The tight construction configuration result s in SCR catalyst beds being installed above and to the sides of existing ESPs and FGD control systems, with the exact configuration depending on which unit is being looked at. Due to the more detailed design and construction evaluation developed by the owners of the Navajo plant, their estimated costs

of construction are significantly lower than the Navajo plant owners originally proposed and lower than the estimates produced for Centralia. As part of the Four Corners Power Plant BART evaluation, EPA developed construction cost

estimates for the installation of SCR . The EPA construction cost estimate for the Four Corners

Power Plant units 4 and 5 is similar to the Navajo Generating Station estimate.For the initial BART evaluation, Ecology concurred with TransAlta that the construction costs to

overcome the technic al difficulties of retrofitting an SCR system on its boilers, given its current configuration and installed emission controls, rendered this technology economically infeasible for implementation. As demonstrated in the next paragraphs, Ecology still agree s that installation of the technology is not cost effective as a NOx control at the Centralia Power Plant.

We have reevaluated the cost effectiveness of SCR at the Centralia Power Plant to include the limited remaining lifetime of the units. For purposes of this evaluation , we assume the design/build process

would start about November 2012 and take four years to complete 26 ( resulting in start ing operation in 2016). Using this 2016 starting date, one unit (Unit A) would operate with SCR for only four years (calendar years 2017 through calendar year 2020) and the other (Unit B) would operate for nine

years. 27 Using the revised cost estimate provided by TransAlta in the March 2010 submittal, the cost effectiveness for SCR on Unit A would be $14,800/ton NOx reduced and Unit B would be $8,400/ton

NOx reduced.

Ecology also has used the cost estimate prepared by Sargent and Lundy for the Navajo Generating

Station to estimate alternative cost effectiveness for the Centralia Power Plant. Based on the site description for the Navajo plant compared to the Centralia site, Ecology scaled the construction cost based on the gross MW output for a coal unit at each plant. For Unit A, Ecology used the cost estimate for Unit 2 at the Navajo station and for Unit B; Ecology used the Unit 3 cost estimate for the Navajo station . The estimate Ecology derived based on the Navajo estimate results in a cost

effectiveness of $12,000/ton NOx reduced over the 4

- year operating lifetime of the SCR installation on the Unit A and $6,400/ton NOx reduced over the 9- year operating lifetime of the SCR installation

on the Unit B

.

These costs are both above cost effectiveness levels for NOx that Ecology has determined to represent Best Available Control Technology to any source type in recent years. For comparison, EPA Region 9 has proposed S CR as BART for NOx on Units 4 and 5 at the Four Corners Power Plant. Since EPA rejected the owner’s cost calculation, EPA developed a revised cost effectiveness estimate for Unit 4 of $2,622 and for Unit 5 of $2,908/ton NOx reduced

. 28 Similarly

, EPA disag reed

with the BART determination of the s tate of New Mexico for the San Juan Generating Station and proposed SCR as BART with the cost effectiveness for the four units at that plant ranging from $1,579 to $1,920/ton NOx reduced. EPA has not yet proposed BART for the Navajo station.

26 For illustration, a constructability analysis and proposed construction schedule for the Navajo Generating station indicates a construction time of 55 months (4.5 years) to install SCR and baghouses on two of the three units at the plant. This time period includes initial engineering design and equipment procurement for all three units ahead of the start of on

site construction. Construction at the Navajo site is difficult and the proposal includes significant demolition prior to installation of a construction crane between two of the three existing units to assist in construction. Centralia would not require this same degree of demolition or so sophisticated of a crane system.

EPA’s fina l BART determination for the San Juan Generating Station is allowing five years for the design and construction of the required SCR system.

27 “Unit A” and “Unit B” are used here to designate the two coal units for this cost discussion. TransAlta has not yet identified to Ecology which unit (BW21 or BW22) would be the first to be decommissioned.

28 Ibid., Table 15.Ba sed on this additional information, analyses performed, and especially considering the limited remaining operating li ves of the units, Ecology finds that SCR is not economically feasible to implement.

Selective Non c atalytic Reduction

SNCR has been commonly selected for BACT determinations on new and modified coal-fired power plants where SCR cannot be used

, as a method to meet NOx reductions required to comply with the Clean Air Interstate Rule ( CAIR ) program , and for seasonal NOx control requirements. SNCR has been required to meet BART at a few facilities, although the most common BART determination s publically available from states to date is low NOx burner technology similar to that already installed

at the Centralia Power Plant with SNCR or SCR added later as further progress emission reductions

. We evaluated a 25 percent reduction from the use of SNCR, a level supported in the emission control literature reviewed. When this reduction is applied to the baseline emission rate of 0.304 lb

NOx /MMBtu , the resulting emission limit becomes 0.23 lb NOx / MMBtu. This is marginally better

than the limit of 0.24 lb NOx /MMBtu limit proposed for the Flex Fuels Project

.

As can be seen in June 2008 Modeling Report, visibility improvement resulting from the NOx

reductions from SNCR or Flex Fuels (Control Scenario SNCR and Control Scenario Flex Fuels) provide essentially equal reduction in visibility impacts at all Class I areas within 300 km of the plan t. In addition , the use of low sulfur sub-bituminous coals can also reduce SO 2 emissions from the plant by up to 1,300 ton/year. 29 The March 2010 modeling, which includes the effects of the reduced

SO 2 emissions from use of the Flex Fuels Project

, indicate s that Flex Fuels provides significantly better visibility improvement than SNCR alone.

As can be seen by looking at Table 3 -1, t he visibility improvement modeled from the NOx reduction

aspects of the Flex Fuels Project (Control Scenario 2) ran ges from 1.13 to 1.45 dv at the three most heavily impacted Class I areas. This visibility improvement at the most heavily impacted Class I areas is significantly greater than that provided by the use of SNCR alone (Control Scenario 1). At the most impacted Class I area, the improvement in visibility from adding SNCR to Flex F uels provides an additional 0.7 dv of improvement, while at the least impacted Class I areas the visibility improvement is about 0.2 dv.

Ammonia slip from the use of an SNCR system is inevitable. TransAlta assumed a 5 ppm slip in its

BART analyses for calculating ammonia costs

. An SNCR system of the type contemplated for installation on these boilers normally results in an ammonia slip of 5–10 ppm 30 , though a review of the EPA RACT/BACT/LAER Clearinghouse data indicates SNCR systems on coal

- fired units with ammonia slip emission limit s as high as 41 ppm. As noted in Section 2’s discussion of SNCR, there are a number of potential adverse impacts that can result from ammonia slip

. The higher the ammonia slip, the higher chance that one of the potential adverse impacts could occur.

29 The effects of the SO 2 reduc tion was modeled and included in the January 2008 BART report. However, the NOx and

SO 2 rates modeled for that report are not identical to those used in the June 2008 report or the December update. The March 2010 remodeling includes the SO 2 reduction fro m Flex Fuels at the final anticipated reduction rather than the previous differing rates. Ecology is relying on the March 2010 analysis as the most accurate and consistent version for comparison purposes.

30 For comparison, actual monthly average SO 2 emiss ions from this plant are currently under 20 ppm.Am monia can be a visibility impairing air pollutant and is a precursor to the formation of secondary

Fine Particles ( PM 2.5 ). The presence of ammonia in the plant’s exhaust will tend to increase the total quantity of ammonia available for the formation of ammonium nitrate and sulfate in the plume and ultimately in the concentration of PM 2.5 at downwind locations. This secondary PM 2.5 is comprised

of am monium aerosols. These ammonium aerosols have been included in the dispersion modeling of the effects on Class I areas. The modeling assumes an unlimited supply of ammonia in the atmosphere available to react with NO 2 and SO 2 to produce ammonium compounds.

Flex Fuels P lus Selective Non c atalytic Reduction

Ecology has also evaluated the impacts of utilizing the Flex Fuels Project and adding SNCR to

further reduce NOx emissions. Assuming a 25 percent reduction in NOx to occur from adding SNCR

to Flex Fuels , the resulting emission limit would be 0.1 8 lb NOx /MMBtu. The capital costs to add SNCR to Flex Fuels would increase by about one- third above Flex Fuels Project costs to an estimated $135 million. The annual costs would increase by $6.2 million to about $17.3 million/year. The cost effectiveness of Flex Fuels plus SNCR is $2,162 /ton NOx for a net reduction of 8,022 tons NOx per

year. The annual cost increase is mostly to cover the cost of ammonia or urea , and to remove

ammonium sulfate and bisulfi te from boiler tubes and duct work downstream from the ammonia injection point.

T he Centralia Power P lant has already installed the LNC3 technology and the Flex Fuels Project , the cost of adding SNCR now is an incremental cost . The capital cost to add SNCR to F lex F uels is the same as SNCR alone since the same equipment needs to be installed. The incremental cost of adding SNCR to both units at the facility is estimated to be $2,145/ton to remove an additional 2,890 tons 31

NOx over Flex Fuels alone.

The combination of Flex Fuels and SNCR would increase the level of visibility improvement at the

three most heavily impacted Class I areas due to NOx reductions by 1.99 dv on the 98 th percentile day, with improvement of 0.67 to 1.45 dv at other Class I areas modeled

.

Under the interim NOx emission limitation, visibility would also improve . We estimate that the improvement would be approximately midway between the projected improvements for Control Scenarios 2 and 3 in Table 3-1. At Mt. Rainier NP, this would be an improvement of approximately 0.35 dv from the Flex Fuels impacts, and at the Three Sister s Wilderness approximately 0. 1 dv additional improvement from the Flex Fuels impacts.

Subsequent to the passage of the amendments to Chapter 80.80 RCW, TransAlta issued a Request for Proposal and received responses fro m vendor s for installation of a SNCR system. The TransAlta requested proposals from six SNCR system suppliers and received responses from two of them. None of the responses indicated an anticipated NOx reduction rate expected. TransAlta working with one SNCR system vendor to determine what emissi on reduction may actually be possible form the use of SNCR at this plant. The vendor is unwilling to set any guaranteed minimum level of removal until it has performed a through computational fluid dynamics (CFD) analysis of the boilers. The CFD modeling is unable to start until there are more detailed temperature and flow measurements

31 Based on 78% capacity factor, which is below the company target rate of over 84 percent.with in the boilers to calibrate the models. As of the first week of August 2011, th ese measurements have not occurred. As a result of an oversupply of hydro and wind powe r within the BPA system, the two coal units had not been fired since the middle part of March 2011. Plant restart occurred in late August and the necessary measurements for the CFD modeling occurred shortly after the units resumed normal operation. As of early August 2011, TransAlta anticipated CFD modeling will be completed during October 2011. At that time, the vendor ’s anticipated minimum NOx removal will

be known.

However, TransAlta and the vendor have identified several issues that may limit the am ount of reduction possible while holding ammonia slip to a reasonable level. The items that cause concern are the location of the beginning of the SNCR reaction temperature zone , the presence of falling slag removed by the soot blowers from the superheater tubing, the anticipated short residence time at the SNCR reaction temperatures, and some concerns about inconsistent mixing provided by the separated

over- fire air system (SOFA) . T he actual residence time at proper SNCR reaction temperatures is the only issue that is unique to the TransAlta boilers. All other issues have been addressed at other

facilities. As presented by the company, based on temperature measurements inside the boiler, of the temperatures at bottom of the superheater pendants is high er than occurred when burning Centralia

coal. This results in the beginning of the SNCR reaction zone being within the superheater zone. As a result, there is concern that inadequate reaction time is available.

As explained by the company, the Central ia mine coal produced a slag on the boiler waterwall tubes that was a gray/dark color that aided heat absorption by the water in the waterwall tubes. This kept the temperature at the super heater lower than is now occurring. The burning characteristics of the Centralia mine coal also resulted in a boiler firebox configuration that is different than many eastern US boilers that have been designed for or converted to PRB coal combustion. The different furnace geometry affects the temperature at the superheater also.

The PRB coal now used by the plant produces a white slag on the waterwall tubes that impedes the heat transfer to the water in the waterwall tubes, resulting in higher temperatures at the superheater. The Flex Fuels Project did install additio nal boiler tubes to capture this excess heat, but the new tubes do not affect the combustion gas temperature at the superheater.

The SNCR system vendor anticipates 3 levels of reagent injection to be installed in the boilers. These injection lances would be located within the elevation range of the superheater pendants. This location exposes the injection lances to slag falling off the superheater pendants and other boiler tubing located above the firebox leading to a recurring maintenance issue . This b oiler tubing in this

area has relatively constant soot blowing to remove the soot (slag) from the boiler tubes. Chunks of slag fall off the pendants and currently damage soot blowing lances (these lances are retractable to enable slag removal all along th eir length).

There is also a concern about competing combustion reactions as a result of the expected inconsistent mixing of secondary combustion air from the SOFA system in the firebox. Th e effect of poor mixing and competing reactions should be minimized by the location of the reagent injection lances

based on the CFD modeling.Ba sed on the information from their vendors, a review of other BART decisions in the w estern U .S. where SNCR was selected as BART, TransAlta has proposed a modest additional reduction from

Flex Fuels attributable to SNCR. TransAlta has proposed a starting NOx limit of 0.22 lb/MMBtu as a reasonable expectation.

Remaining useful life of the plant

T here was an issue of the remaining useful life of the Centralia Power Plant

. TransAlta ’s investor

information about its facilities has indicated that continued operation of the Plant beyond 2030 will require a substantial capital investment 32 with decisions to be made by 2025

. This projected lifetime is longer than the BART guidance would consider as a limiting factor for making a BART technology decision on economic grounds.

However

, since TransAlta made that statement in 2007, other circumstances that affect the remaining lifetime of this plant in its current configuration have occurred . On May 21, 2009, the Governor of Washington issued Executive Order 09-05, Washington’s Leadership on Climate Change. Th is Order would have ultimately resulted in the shutdown of the coal units at the plant by 2025.

Governor’s E xecutive Orde r 09-05 has now been superseded by amendments to Chapter 80.80, Revised Code of Washington. 33 Under the amendments to this law, the Governor is directed to sign a Memorandum of Agreement by January 1, 2012, whereby the plant owners will:

• I nstall selective noncatalytic reduction for nitrogen oxides by January 1, 2013.

• B ring the two coal

- fired units into compliance with the GHG emission performance standard in RCW 80.80.040, 34 one unit by December 31, 2020, and the other unit by December 31,

2025.

• Incorporate other specific requirements in the law into the Memorandum of Agreement.

As noted in public testimony to the legislature and the press during development and passage of these amendments, the plant owners, the legislators sponsoring the bill, the Washington environmental community, and the Governor’s Office have all publically stated that compliance with the GHG emission performance standard will be through decommissioning of the coal- fired units at the plant.

The law also states that in the event Ecology determines as a requirement of state or federal law or regulation that the selective catalytic reduction technology m ust be installed on either coal-fired unit, the requirement to meet the GHG emission performance standard does not apply. Thi s would then imply that the coal units would continue to operate indefinitely.

The current GHG emission rate for the P lant is about 2,300 lb total GHGs /MW -hour (MWh) of electricity produced for sale. The emission performance standard in the RCW 80.80.040 (1) is currently 1,100 lb total GHGs /MWh of electricity produced. Meeting that performance standard

32 TransAlta Investor Day 2007, presentations published as PDF file on Nov. 17, 2007, Slide 38 of 101.

33 Enacted in Chapter 180, Laws of 2011.woul d require a GHG reduction in excess of 50 percent , on the order of 6– 7 million tons of CO 2 per

year. The law (Chapter 80.80, RCW) also requires an evaluation of the GHG emission capabilities of natural gas fired combined cycle power plants every five years and a revision to this limitation based on that evaluation be established by rule. The revised emission performance standard is based on the capability of new combined cycle natural gas combustion turbines offered for sale and purchase in

the U .S. Based on current offerings by the combined cycle combustion turbine industry, the first of the revised standards (due in 2012) is anticipated to be 850–920 lb/MWh.

The effect of the ‘ decommissioning process’ is to limit the economic lifetime of the units . Using a starting point of June 2011, the maximum remaining useful life of the units is reduced to 8 and 13

years.

4.2 Ecology’s Determination of BART

Ecology has determined BART for the Centralia Power Plant to be the Flex Fuels Project plus SNCR

and the u se of a sub -bituminous PRB coal or other coal that will achieve similar emission rates

. This determination is based on the information synopsized above, information submitted by TransAlta, and additional materials collected by Ecology

.

Considerations in our decision include:

• T he Flex Fuels Project provides a 20 percent reduction from the 2003–2005 average emissions rate. The use of SNCR

, as required by state law

, will further reduce emissions by

a t least an additional 10 - 25 percent

.

• The Flex Fuels emission reductions are not exclusively NOx , but include SO 2 reductions from ability to us e PRB type coals

.

• The NOx emissions reduction from the use of Flex Fuels and SNCR will result in reduced visibility impairment at all Class I areas within 300 km of the plant.

• Additional NOx reductions from adding SNCR will start by January 1, 2013, less than 11⁄2

years from June 2011. January 2013 is also approximately 13 months from the time the revised BART order is anticipated to be issued and submitted to EPA.

• In order to meet the requirement of state law, TransAlta will be making significant financial and plant viability analyses of how best to comply with the GHG emission performance standard requirements of the law to be included in the Memorandum of Agreement.

• The law provides that if Ecology determine s that state or federal law or regulation requires the

use of SCR to control NOx emissions from the plant, then the requirement to comply with the

GHG emission performance standard (shut down the coal units) does not apply and the plant can operate beyond 2025.

The emission limitation and coal quality limitation reflecting Ecology’s determination of BART for

NOx from the Centralia Power Plant is provided in Table 4-1 below. A coal meeting the nitrogen and

sulfur content of the Jacobs Ranch Upper Wyodak coal depicted in Appendix A, Table A-2 is considered to be a PRB coal or equivalent coal. Additional discussion on the basis for selecting the

initial NOx emission limitation is contained in Appendix I.Ta ble 4 -1 Ecology’s Determination o f t he Emission Controls That Constitute B ART

BART Control Technology Emission Limitation

Flex Fuels Project plus SNCR 0.21 lb NOx /MMBtu, 30 operating day rolling

average , both units averaged together

Fuel Quality Requirements Coal used shall be a sub -bituminous coal from the

Powder River Basin or other coal that will achieve

similar emission rates

SNCR optimization Optimize SNCR operation for lowest NOx reduction while minimizing ammonia slip . Revise the NOx emission limitation to reflect that optimization.

## Appendix A —Coal QualityTa ble A-1 Summary of Key Centralia M ine and Powder River Basin Coal Characteristics

TransAlta Centralia Mine Coal Powder River Basin Coal

Low Sulfur (<1.2%) High Sulfur (>1.2%)

Mean Max From Mean Max Mean Max

Btu/lb 7,681 8,113 7,930 8,121 8,414 8,800 Jacobs Ranch Upper Wyodak

Sulfur (%) 0.69 0.84 1.89 2.14 0.40 0.88 Jacobs Ranch Upper Wyodak Ash (%) 15.44 16.44 14.43 16.46 6.21 13.04 Special K Fuel

Carbon (%) 44.95 47.37 45.63 46.45 49.11 51.26 Jacobs Ranch Upper Wyodak Nitrogen (%) 0.76 0.80 0.71 0.75 0.67 0.8 Jacobs Ranch Upper Wyodak

C oal characteristics on an "as received" basis.

Table A -2 Powder River Basin Coal Characteristics, from B est A vailable R etrofit Technology Analysis for the Centralia Power Plant, July 2008

Coal Sources and Characteristics

Coal Quality Data

Units Bucksk

in Caballo

8500 Cordero Rojo Jacobs Ranch Upper Wyodak Rawhid

e Special

K Fuel Belle Ayr Eagle

Butte

Proximate Analysis (As

- Received Basis)

Higher Heating

Value Btu/lb 8400.00 8500.00 8456.00 8800.00 8300.00 7907.00 8500.00 8400.0

0

Moisture % 29.95 29.90 29.61 26.45 30.50 25.74 30.50 30.50

Volatile Matter % 30.25 31.40 30.71 32.50 30.40 28.76 30.40 31.92

Fixed Carbon % 34.65 33.80 34.22 34.35 34.20 32.46 34.20 32.93

Ash % 5.15 4.90 5.46 6.70 4.90 13.04 4.90 4.65

Fixed Carbon to

Volatile Matter (Fuel) Ratio 1.15 1.08 1.11 1.06 1.13 1.13 1.12 1.03

Ultimate Analysis (As

- Received Basis)

Carbon % 49.00 49.91 49.16 51.26 48.58 45.82 50.01 49.17

Hydrogen % 3.24 3.56 3.43 3.89 3.34 3.07 3.43 3.42

Nitrogen % 0.63 0.71 0.71 0.80 0.63 0.56 0.67 0.67

Sulfur % 0.35 0.36 0.32 0.88 0.37 0.28 0.26 0.38

Ash % 5.15 4.90 5.46 6.70 4.90 13.04 4.90 4.65

Moisture % 29.95 29.90 29.61 26.45 30.50 25.74 30.50 30.50

Chlorine % 0.00 0.00 0.00 0.01 0.01 0.00 0.01 0.01

Oxygen % 11.68 10.66 11.31 10.01 11.68 11.49 11.12 11.20

Note: Special K Fuel is blend of Spring Creek and Kaolin coals

## Appendix B —Nitrogen Oxides Controls Evaluated in the 1997 Reasonable Available Control Technology ProcessTa ble B -1 N itrogen Ox ides Controls Evaluated in the 1997 Reasonable Available Control Technology Process

Screening Criteria used in 1997 Review Technically

Feasible Increase

other

Emissions Safety? Reduce

Product Marketability Cost Competitive compared to

LNB? Mets or

Exceeds

CDM

Emission

Level Comments

Boiler

Modifications

1 Boiler Tuning Yes No

2 Low Excess Air Yes No Already Optimized

3 Burners

- out

- of

Service (BOOS) Constrained by mill capacity

4 Fuel & Air Tip Replacement Yes Meets New tip developments may provide capability

to meet LNB

levels of NOx

5 Close Coupled

Over

- fire Air (CCOFA) Increased

UBC potential Yes Meets

6 Separated Over

fire Air (SOFA) Increased

UBC potential Yes Meets

7 ABB Advanced

TFS

- 2000 System (2 levels of SOFA) Furnace height/spacing

at Centralia

reduces applicability Increased

UBC potential Yes Meets Limited

commercial

demonstration of this technology, furnace specific

8 CCOFA plus

SOFA May

necessitate

pressure part
modifications Increased

UBC potential Yes Exceeds

9 Selective Noncatalytic

Reduction (SNCR) Not

demonstrated

on Centralia

sized unit Ammonia slip Ammonia Ammonia

contamination

of fly ash resulting in

lost sales No Exceeds High reagent

cost/limited

reduction capability

10 SNCR plus Air

heater SCR (Hybrid) Only one

pa rtial unit

coal

- fired utility

demonstration

; no demonstration

s on Centralia

sized unit Ammonia slip Ammonia Ammonia

contamination

of fly ash resulting in

lost sales No Exceeds High reagent &

O&M cost

11 Selective Catalytic Reduction (SCR) Ammonia slip Ammonia Ammonia

contamination

of fly ash resulting in

lost sales No Exceeds Extremely high capital and O&M

cost

12 Natural Gas co

firing Reduced ash

sales No Meets # 14 is a better

variation on this option

13 Natural Gas

Conversion No ash to sell No Meets Very High Fuel

cost

14 Natural gas Reburn (1 st Not

demonstrated Reduced ash

sales No Meets High variable cost of operationScreening Criteria used in 1997 Review Technically

Feasible Increase

other

Emissions Safety? Reduce

Product Marketability Cost Competitive compared to

LNB? Mets or

Exceeds

CDM

Emission

Level Comments

Generation) on Centralia

sized unit

15 Natural Gas Reburn (2 nd

Generation) No

Commercial Application Reduced ash

sales No Meets Natural Gas Expensive

Combined SO 2 /

NOx Controls

16 UOP/PETC

Fluidized Bed Copper Oxide Pilot level or

limited use No Exceeds

17 Rockwell Moving

- Bed Copper Oxide

Process Pilot level or

limited use No Exceeds

18 NOXSO Process Pilot level or

limited use No Exceeds

19 Mitsui/BF

Activated Process Pilot level or

limited use No Exceeds

20 Sumitomo/EPDC

Activated Char

Process Pilot level or

limited use No Exceeds

21 Sanitech

Nelsorbent SOx

NOx Control

Process Pilot level or

limited use No Exceeds

22 NFT Slurry with

NOXOUT

Process Pilot level or

limited use No Exceeds

23 Ebara E

- Beam

Process Pilot level or

limited use No Exceeds

24 Karlsruhe

Electron Streaming

Treatment Pilot level or

limited use No Exceeds

25 ENEL Pulse

Energization

Process Pilot level or

limited use No Exceeds

26 California (Berkeley) Ferrous Cysteine

Process Pilot level or

limited use No Exceeds

27 Haldor Topsoe

WSA

- SOX

Process Pilot level or

limited use No Exceeds

28 Degussa

DESONOX

Process Pilot level or

limited use No Exceeds

29 B&W SOx/

NOx /ROx/Box (SNRB) Process Pilot level or

limited use No Exceeds

30 Parsons Flue Gas Cleanup Process Pilot level or

limited use No Exceeds

31 Lehigh University Low

Temperature Pilot level or

limited use No ExceedsScreening Criteria used in 1997 Review Technically

Feasible Increase

other

Emissions Safety? Reduce

Product Marketability Cost Competitive compared to

LNB? Mets or

Exceeds

CDM

Emission

Level Comments

SCR Process

32 IGR/Hellpump

Solid

- State

Electrochemical

Cell Pilot level or

limited use No Exceeds

33 Argonne High

Temperature Spray Drying

Studies Pilot level or

limited use No Exceeds

34 PETC Mixed Alkali Spray Dryer Studies Pilot level or

limited use No Exceeds

35 Battelle ZnO Spray Dryer

Process Pilot level or

limited use No Exceeds

36 Cooper Process Pilot level or

limited use No Exceeds

37 ISCA Process Pilot level or

limited use No Exceeds

Controls Evaluated in D etail as part of 1997 RACT Evaluation

1997 Anticipated NOx Emission Emission Reduction Technology Rate (lb/ MMBtu ) Boiler Tuning 0.40 to 0.44 Fuel and Air Tip Replacement 0.40 to 0.44

LNB & Close Coupled Over

- fire Air (CCOFA) 0.38 to 0.42 LNB & Separated Over

- fire Air (SOFA) 0.30 to 0.34 Selective Noncatalytic Reduction (SNCR) 0.29 to 0.33 LNB with CCOFA plus SOFA 0.26 to 0.30 Hybrid (SNCR plus air heater SCR) 0.24 to 0.28 Gas Reburning 0.20 to 0.25 Selective Catalytic Reduction (SCR) 0.10 to 0.15

## Appendix C —References1. C H2M HILL

, BART ANALYSIS FOR CENTRALIA POWER PLANT at Centralia Washington, January, 2008, Revised July 2008 , Supplemented Dec ember 2008 and March

2010

2. TransAlta Centralia Boiler Emissions Modeling Study by Black & Veatch, dated September . 2007, Attachment to September 10, 2007 Air Permit Applicability Analysis for TransAlta Centralia Generation, LLC., Fuel Conversion Project.

3. Raytheon Engineers and Constructors, Inc. and Easter Research Group, Inc., COAL UTILITY ENVIRONMENTAL COST (CUECost) WORKBOOK USERS MANUAL and Excel Spreadsheet, Version 1.0, 1998, Provided by EPA.

4. Air and Waste Management Association, Editors, Anthony Buonicore and Wayne Davis,

AIR POLLUTION ENGINEERING MANUAL , Von Nostrand Reinhold, 1992

5. Srivastava, Ravi K., Hall, Robert E., et al, Nitrogen Oxides Emission Control Options for

Coal- Fired Electric Utility Boilers , Journal of the Air & Waste Management Association, Sept. 2005

6. Comparato, J. R., NOx Control Technologies: Focus SNCR , Presented at Western Coal Council, Burning PRB Coal Seminar , Presentation TPP -550

7. Cardone, Carol, Kim, Ann, & Schroeder, K arl, Release of Ammonia from SCR/SNCR Fly

Ashes , 2005, http://www.flyash.info/2005/68car.pdf

.

8. EPRI project summary, Evaluation of an SNCR Trim System on a 720 MW Tangential Design Coal- Fired Utility Boiler , May 2003, EPRI report 1008029

9. Southwest Air Pollution Control Agency, 1997 Technical s upport Document for RACT

Order No. 97 -2057

10. Harmon, A., et al, Evaluation of SNCR Performance on Large- Scale Coal

- fired Boilers

., Institute of Clean Air Companies Forum on Cutting NOx emissions, March 1998

11. US EPA, Air Pollution Control Cost manual, 6 th Ed ition , January, 2002, EPA/452/B-02-

001

12. New Mexico Dept. of Environment, Discussion of Nalco-Mobotec ROFA and Rotamix, evaluation for application at San Juan Generating Station, March 29, 2008,http://www.nmenv.state.nm.us/aqb/reghaz/documents/03292008DiscussionofNalcoMobotecROFAandRotamixRev080329.pdf

13. SNCR Committee

, White Paper: Selective Non

- Catalytic Reduction (SNCR) for Controlling NOx Emissions ., Institute of Clean Air Companies, February 2008

14. TransAlta Investor Meeting presentations, September, 2007, 2007 Investor Day Presentations (produced Nov. 2007)15. L etter to Lewis Dendy, North Dakota Department of Health, from Debr a Nelson, Great River Energy, February 9, 2010, including attachments, concerning Fly Ash usage and properties

related to ammonia

BART Analyses from other states, such as:

16. Black and Veatch, Public Service Company of New Mexico, San Juan Generating

Statio n Best Available Retrofit Technology Analysis , June, 2007

17. CH2M HILL

, BART Analysis for Jim Bridger Unit 1 {also Units 2 – 4}, January 2007

18. Black & Veatch, Portland General Electric Boardman Plant Best Available Retrofit Technology (BART) Analysis , November, 2007

19. Northern States Power Co. d/b/a Xcel Energy – Sherburne County Generating Plant Units 1 and 2 Best Available Retrofit Technology Analysis , October, 2006

20. Pinnacle West, Arizona Public Services, Four Corners Power Plant , BART Analysis Conclusions, January, 2008

21. BART analyses by Region 9 for the 4 Corners Power Plants as included in federal rule

docket EPA-R009- OAR -2010-0683 supporting Federal Implementation Plan proposal published in the Federal Register February 25, 2011

22. Salt River Project and S argent & Lundy, Presentation to EPA Region 10 and Federal Land Managers for the Navajo Generating Station, July 20, 2010.

## Appendix D

— Modeling ResultsMod eling Result Information

Table D -1 is c opied f rom the June 2008 BART Modeling Report , Table D -2 is from the Dec. 2008 Flex Fuels Addendum, and Table D-3 is from the January 2008 report.

Tabled D -1, D-2, and D-3 show the percent contribution to visibility impairment on the days listed, the specific day, and the modeled visibility on those days. The days shown are the 98 th percentile for each year and the three years modeled. Since the same metrological information is used for each different emission scenario, the only thing that changes is the emission rate and percentage of total visibility attribu table to each chemical species. This information is from the referenced report. The modeling addendum received in March 2010 did not extract this

information from the model results.

Table D -1 June 2008 R eportTa ble D -2 December 2008 Flex Fuels AddendumTa ble D -3 January 2008 ReportFi gures D -1 through D-5 graphically depict the seasonality of visibility impacts from the TransAlta facility. Five different Class I areas are depicted in order to indicate how the seasonality of impacts chan ges somewhat based on season of the year.

Figure D -1Fi gure D -2

Figure D -3Fi gure D -3Fi gure D -4Fi gure D -5

## Appendix E

— Coal -Fired Electric Generating Unit BART

Determinations in Western U .S.Tab le of Coal

- Fired Electric Generating Unit BART Determinations in Western U .S.

All information presented is contained in Regional Haze State Implementation Plans available for public review or that have been submitted to EPA for approval, as of August 2011.

Tab le E -1

State Unit NOx Technology lb/MMBtu, 30
day avg

. Comments

EPA Region 6,

New Mexico San Juan Generating Station

SCR 0.05, 30 day
rolling average,

each unit

EPA Region 8,

Montana Colstrip No final Decisions
publicly available

EPA Region 9,
Navajo

Reservation Navajo

SCR No final Decision
publicly available

Four Corners

SCR 0.11 plant wide
rolling 30 day

average Unit specific limits ranging from 0.11

to 0.21 Proposed Decision

, see Federal Register , Vol. 76, No. 38, Friday, February 25, 2011

Arkansas Entergy Arkansas, Inc. White
Bluff, Units 1 and 2 0.28 on

bituminous coal

0.15 on sub

bituminous coal Controls not given.

Limits in State Regulation 19.1505

SWEPCO Flint Creek Power

Plant Unit 1 0.23 Controls not given.

Limits in State Regulation 19.1506

California No Coal fired Units subject to

BART

Colorado Martin Drake Units 5

- 7 Install over

- fire air

systems 0.39 Also limited to 0.35 lb/MMBtu, annual

Average CENC (Trigen) Unit 4 Limited by rule to

combustion
controls, LNC3 115 lb/hr

CENC (Trigen) Unit 5 Limited by rule to

combustion
controls, LNC3 182 lb/hr

Craig Unit 1 Limited by rule to

combustion
controls, LNC3 0.39 Also limited to 0.30 lb/MMBtu, annual

Average
Craig Unit 2 Limited by rule to

combustion
controls, LNC3 0.39 Also limited to 0.30 lb/MMBtu, annual

Average
Public Service of Colorado,

Comanche Units 1 and 2 Low NOx Burners 0.2 Also limited to 0.15 lb/MMBtu annual
average both units

combinedState Unit NOx Technology lb/MMBtu, 30
day avg

. Comments

Public Service of Colorado,

Cherokee Unit 4 Modify existing

Low NOx burner

and over fire air

or install new

burners 0.28

Public Service of Colorado,
Hayden Unit 1 Modify existing

Low NOx burner

and over fire air

or install new

burners 0.39

Public Service of Colorado,
Hayden Unit 2 Modify existing

Low NOx burner

and over fire air

or install new

burners 0. 28

Public Service of Colorado,

Pawnee Unit 1 Modify existing

Low NOx burner

and over fire air

or install new

burners 0.23

Public Service of Colorado,

Valemont Unit 5 Modify existing

Low NOx burner

and over fire air

or install new

burners 0.28

Idaho No coal fired units

Kansas La Cynge Generating Station,

Unit 1 and 2 SCR on Unit 1,

Controls as

needed on Unit 2 0.13, both units
averaged
together
Jeffrey Energy Center, Units

1 and 2 Low NOx Burners 0.15

Minnesota MN Power, Taconite Harbor

Boiler No. 3 ROFA/Rotamix
(Mobotec) 0.13

MN Power, Boswell Boiler

No. 3 LNB + OFA, SCR 0.07

Rochester Public Utilities,
Silver Lake, Unit #3 boiler No additional

controls No Limit

Rochester Public Utilities,
Silver Lake, Unit #4 boiler ROFA/Rotamix
(existing controls) 0.25

Xcel Energy, Sherco, Boiler 1 LNB

+SOFA+Combusti
on Optimization 0.15

Xcel Energy, Sherco, Boiler 2 Combustion
optimization 0.15

Xcel Energy, Allen S. King

Boiler 1 SCR (existing
controls) 0.1

Northshore Mining, Silver
Bay, Boiler 1 LNB + OFA 0.41State Unit NOx Technology lb/MMBtu, 30
day avg

. Comments

Northshore Mining, Silver
Bay, Boiler 2 LNB + OFA 0.4

Iowa Used CAIR for BART

Louisiana Used CAIR for BART

Nebraska Gerald Gentleman, Units 1

and 2 Existing LNC3 on

Unit 2 New LNC3

on Unit 1 0.23, both units
averaged
together
Nebraska City Station, Unit 1 LNC3 0.23

Nevada No Coal Fired BART units

New Mexico San Juan Generating Station No final Decision
publicly available

North Dakota Olds Unit 1 SNCR plus over

fire air 0.19

(All Lignite units) Olds Unit 2 SNCR plus over

fire air 0.35

Coal Creek Units 1and 2 Additional over

fire air plus LNB 0.19

Stanton Unit 1 LNC3 plus SNCR for a 1/3

reduction 0.29 a 1/3 reduction

Milton Young Station Unit 1 Advanced over

fire air plus SNCR

for a 58%

reduction 0.36

Milton Young Station Unit 2 Advanced over

fire air plus SNCR

for a 58%

reduction 0.35

Oregon Boardman LNC3 0. 2 3 between
July1, 2011 and

Dec. 31, 2020. Note Plant Closure by

Dec. 31, 2020.

Oklahoma OG&E Muskogee Generating

Station Units 4 and 5 0.15

OG&E Sooner Generating

Station Units 1 and 2 0.15

AEP/PSO Northeastern

Power Station Units 3 and 4 0.15

Texas No Coal Fired BART units
Subject to BART

Utah Hunter Power Plant, Units 1

and 2 LNC3 0.26 Replacing LNC1 burners

and add 2 levels of

over

- fire air under
minor NSR program.State Unit NOx Technology lb/MMBtu, 30
day avg

. Comments

Huntington Power Plants,

Units 1 and 2 LNC3 0.26 Replacing LNC1 burners

and add 2 levels of

over

- fire air under
minor NSR program.

Wyoming Naughton Unit 1 LNC3 0.26 Wyoming Long term

strategy for this unit
requires SCR @ 0.07 lb/MMBtu by 2018.

Naughton Unit 2 LNC3 0.26

Naughton Unit 3 LNC3 plus SCR 0.07
Jim Bridger Units 1

- 4 LNC3 0.26

Dave Johnston Unit 3 LNC3 0.26

Dave Johnston Unit 4 LNC3 0.15
Wyodak Unit 1 LNC3 0.23

Basin Electric Units 1

- 3 LNC3 0.23

## Appendix F —TransAlta Centralia Power Plant Site Plan s and

ProfilesThe se four drawings are large, and intended to be reproduced at 11 ” x 17” or larger scale for readability. The drawings are available from Ecology and are located o n the Ecology w ebsite.

Drawing 1 is an overall site plan of the power plant including the plant office, wet scrubbers storm water lagoons, maintenance buildings, etc. It does not include the coal pile

area. Drawing 2 is a site plan of the boiler building, ESPs, and wet scrubber area of the plant. Drawing 3 is an elevation d rawing looking from the south at the overall steam turbine/ boiler building, ESPs and old stacks. Drawing 4 is an elevation drawing showing subset elevation indicated in Drawing 3 showing the plant boiler outlet area, and the ESPS.

## Appendix G —Centralia BA RT Control Technology Analysis, Response to Questions

## Appendix H —Additional Centralia Power Plant BART Modeling

Simulations– Comparison of Flex Fuel and Flex Fuel plus SNCRFrom: Ken Richmond [krichmond@Environcorp.com]

Sent: Friday, March 26, 2010 2:00 PM

To: Newman, Alan (ECY); Bowman, Clint (ECY)

Cc: RickLGrif@aol.com; Gary_MacPherson@TransAlta.com;
Lori_Schmitt@transalta.com; richard_debolt@transalta.com Subject: Additional Centralia Power Plant BART simulations

Attachment s: flex

- vs

- flexwsncr.pdf

Al & Clint

I’ve attached the results from the additional BART simulations that you requested for the Centralia Power Plant. The results supplement the

earlier BART simulations with 2 new cases.

Revised Flex Fuels: (PM10 242 lb/h r, NOx 3936 lb/hr & SO2 1854 lb/hr) The

Flex Fuels SO2 emissions are based on the ratio of sulfur content of
Jacobs Ranch (PRB) coal to Centralia Mine coal (41%) times the 2003

- 2005

maximum 24

- hr baseline rate of 4522 lb/hr.

Flex Fuels with SNCR: (PM10 242 lb/hr, NOx 2952 lb/hr & SO2 1854 lb/hr)

NOx emissions are reduced by 25% to 0.18 lb/MMBtu from the Flex Fuel

factor of 0.24 lb/MMBtu.

In all respects the simulations were performed in the same manner as the original BART analysis. The results are summar ized in the attached Tables that augment the tables from the original BART modeling analysis. How many copies of the modeling files do you want? As before the modeling files will contain spreadsheets with the extinction budgets for the top 8 days
each year and top 22 days in three years for each Class I area of

interest.

Regards,

Ken Richmond Sr. Air Quality Scientist ENVIRON International Corp.
19020 33rd Avenue W, Suite 310
Lynnwood, WA 98036

Phone: 425.412.1800

Direct: 425.412.1809

Fax: 425.672.1840

This message contains information that may be confidential, privileged or otherwise protected by law from disclosure. It is intended for the exclusive use of the Addressee(s). Unless you are the addressee or authorized agent of the addressee, you may not review, copy, distribute or disclose to anyone the message or any information contained within. If you have received this message in error, please contact the sender by electronic reply to email@environcorp.com and immediately delete all copies of the messa ge.

## Appendix I—Establishing SNCR NOx Emis sion Limitation for

Revised OrderThe 2011 amendments to RCW 80.80 require the Centralia Power Plant to install and operate SNCR by January 1, 2013. This SNCR technology is in addition to the emission reduction resulting from implementation of the Flex Fuels Project

.

A number of consid erations are discussed below related to determining the most appropriate averaging period and initial NOx emission limitation for SNCR. Included is a discussion of the results expected from the SNCR optimization study.

What is the removal rate that can be expected by SNCR ?

The literature contains a reasonable amount of information compiled for existing coal- fired utility boilers. The various sources all indicate that minimum expected removal rates of 20

percent with maximum removal for boilers above 500 MW of 35 percent . For boilers above 500 MW, the most commonly reported removal rates are 25 to 35 percent . The following paragraphs are synopsis of three representative reviews.

A 2003 EPRI report synopsis 35 reported on an evaluation of a single level SNCR Trim system on a 720 MW tangential boiler. The single level system was operated over a load range from 40 to 100 percent of the boiler maximum continuous rating. NOx reductions as measured at the

economiz er exit showed the highest levels of NOx reduction occurred in the furnace nearest the injectors. The system provided NOx reductions of 20 to 25 percent while the boiler operated at rates of 300–710 MW with an ammonia slip of 6–9 ppm.

A 2008 report on SN CR by the Institute of Clean Air Companies supports SNCR on Centralia sized units producing 20 to 30 percent NOx reductions with ammonia slip as low as 5 ppm. The report notes that this level of NOx removal is anticipated for any installation, with the ma in criteria being able to adequately distribute the reagent within the reaction zone. The report indicates for various sizes of coal-fired utility boiler applications, the range of reduction is 20 to 90 percent and the most commonly reported reduction is 25 percent

.

A 2005 report in the Journal of the Air and Waste Management Association 36 evaluated NOx controls systems in operation in the U.S. Table 3 of this report indicates that for larger coal-f ired units, SNCR reduction of NOx can be anticipated in the range of 25 to 35 percent for units over 200 MW. The data indicates smaller units can achieve higher removal rates. The units reviewed for this report had higher pre control emissions than Centralia, so the reported reductions may be

more illustrati ve of the capability of SNCR in general rather than specifically applicable to

TransAlta’s Centralia units. The article does not include information on ammonia slip.

Based on SNCR vendor reluctance 37 to provide a proposal to TransAlta, there is a reasonable doubt about the ability to achieve the 20 to 25 percent NOx reduction that is normally anticipated

35 Evaluation of an SNCR Trim System on a 720 MW Tangential Design Coal

- fired Utility Boiler, May 2003, Document #E214967, by R. Himes on EPRI Report #1008029, April 2003.

36 Nitrogen Oxides Emission Control Options f or Coal

- Fired Electric Utility Boilers, Ravi K. Srivastava

, Robert E.

Hall et al

, Journal of the Air & Waste Management Association, Volume 55

, September 2005

. 37 TransAlta has noted that they sent out six requests for proposal and received two responses, e ach with two variations in return. Anecdotally, the system supplier with the greatest familiarity with the plant (Black and Veatch) did not submit a proposal.thr ough the use of SNCR. Two SNCR system vendors supplied four proposals for SNCR systems. The vendors did not propose an ability to meet a specific NOx emission rate or removal percentage. The system vendors indicated that some small NOx removal would occur, but until they had completed modeling of the boilers, they would not be able to provide any guarantee of performance. Using the information suppli ed by the two vendors, TransAlta has proposed an initial NOx emission limit based on the use of SNCR of 0.22 lb/MMBtu (about a nine percent additional reduction). The rationale for this proposal is contained in the August 8, 2011, letter from Bob Nelson of TransAlta to Alan Newman of Ecology. In short, the company identifies operational and mixing issues resulting from the location of ammonia/urea injection lances within the superheater pendants, the end of the active combustion zone in the firebox at the bottom of the superheater pendants, 38 and damage to injection lances from falling slag removed from the superheater tubes. Other normal operational problems are identified such as the formation of ammonium bisulfate and ammonium sulfate deposits in the ai r preheaters and

economizer.

As part of the design for the SNCR system, TransAlta’s system vendor will be performing computational fluid dynamics modeling of the boilers. This modeling will determine a number of aspects of the SNCR system design, such as optimum location s for the injection system, the reaction time in the SNCR reaction temperature zone, and the anticipated nitrogen oxides emission rate and ammonia slip. Due to the lack of operation of the TransAlta coal boilers between mid February and mid August of 2011, the vendor was unable to acquire the temperature and flow rate information necessary to complete the modeling exercise. The earliest this information is expected to be available is the end of October 2011.

The rationale presented to Ec ology by TransAlta is very boiler specific. It is compelling information, but based on the literature on operation of SNCR in existing boilers, does not present many unexpected issue s. The most unexpected issue is the higher temperatures at the super hea ter pendants when burning the PRB coal producing a smaller than anticipated size for

the SNCR reaction zone.

Based on literature reviewed, a reasonable minimum reduction rate to expect from the application of SNCR at this facility would be 25 percent as proposed by TransAlta in their BART analysis reports and as modeled by TransAlta to estimate the degree of visibility improvement that could be achieved. However, based on the recent information provided by

TransAlta 39 and the prospective SNCR system vendors, a lower minimum expected reduction

rate on the order of 10 percent may be more reasonable as the basis for setting the initial NOx

reduction rate.

Potential basis for emission limit

The proposed limitation is based on a 30-day rolling average, both units averaged together. This scenario tends to smooth out the hourly/daily variability in the NOx emissions from the boilers, especially when start

- up emissions are included in the emission limitation

. Thirty

- day rolling

38 The combustion zone ended well below the superheater pendants when using Centralia coal. The Centralia coal have a different volatility than the PRB coals, leading to the larger combustion zone.

39 Letter and attachments from Bob Nelson, Plant Manager, to Alan Newman, August 8, 2011.aver ages are used by other states for other coal -fired power plants and by EPA in its coal- fired

boiler rules.

Two approaches were used to evaluate the appropriate basis for setting the emission rate to apply the percent reduction from use of SNCR. One approach was to look at the a vailable emissions data; the other was to utilize the basis used to set the current BART emission limitation.

Actual emissions rate based limitation

Rolling 30- day average emissions from the TransAlta plant were evaluated. These averages

were based on the daily average values of NOx lb/MMBtu values for 2010 reported for the Acid Rain Program. The Acid Rain Program uses a different missing data substitution process for periods of start-up and extended monitor outages that result in higher values being i nserted for missing data than the data substitution process in the BART Order. The data substitution process in the BART Order better reflects operating realities of the system than the process used in the Acid Rain Program. 40 As a result, the use of this Acid Rain Program information is for illustrative purposes only and does not indicate compliance or noncompliance. This review is in

an Ecology

- generated spreadsheet titled CentraliaAnnualSummary2003-2010.xlsx.

As a result of the A cid R ain P rogram mis sing data substitution, there were several 30- day periods where 30-day averages were above the current and proposed BART emission limitation. Upon inspection, these periods are almost entirely based on 30-day periods when only one boiler was in operation, when daily values were dominated by start -up of a boiler, or when Acid Rain Program substituted data was reported. There were no exceedances of the emission limitation contained in the current BART Order when the process contained in the BART Order was u sed for missing data substitution.

Prior to using the missing data process in the BART Order, all 30-day periods with emission averages above 0.24 lb/MMBtu (the NOx limit in the current BART Order) were dominated by the Acid Rain Program’s substitute data , especially when one unit was in start -up mode.

The current limitation is based on a 30-day rolling average, both units averaged together. This

scenario tends to smooth out the hourly/daily variability in the NOx emissions from the boilers.

A 30 -day rolling average is used by other states for other coal-fired power plants and by EPA in

its coal

- fired boiler rules.

During the last three months of 2010, operation of the plant was consistent and continuous. During that 3-month period, the NOx emissions averaged 0.227 lb/MMBtu. A proposed NO 2 emission limitation based on this 3-month period and a 25 percent reduction from SNCR would

be 0.170 lb/MMBtu. A 10 percent reduction would result in limits of 0.204 lb/MMBtu.

Emission limit reduction basis

40 The data substitution process in the Acid Rain Program is desig ned to estimate the maximum theoretical emissions during periods of time such as unit start

- up and shutdown (when certified CEMs are not available for use), extended monitoring equipment outages, rather emissions that are more akin the unit actually operat es.The current Flex Fuels emission limitation is based on a 20 percent reduction from the RACT emission limitation of 0.30 lb/MMBtu. The RACT limit value was conservatively set at 0.30 lb/MMBtu to include a reasonable compliance margin. The current BART Ord er limit for Flex Fuels uses the RACT emission limit then applies the 20 percent reduction attributable to Flex Fuels (resulting in the current BART limit of 0.24 lb/MMBtu) continues to incorporate a reasonable compliance margin. Applying a further reduction resulting from the use of SNCR would result in a NOx limitation of 0.180 lb/MMBtu (25 percent reduction) or 0.21 lb/MMBtu (12 percent reduction).

Operating day versus calendar day

We are proposing to use the concept of operating day rather than calendar day. The use of an operating day means that any day where neither coal unit is in operation (zero emissions) is not used to evaluate compliance with an emission limitation.

Operating day is used in many EPA regulations for combustion units. 41 An op erating day has been defined as any day in which fuel is fired for any amount of time in either coal unit or a day where fuel is fired for more than a specified minimum amount of time (such as 4 or 8 hours).

Recent revisions to EPA’s New Source Performanc e Standards for boilers have defined an operating day as any calendar day when fuel is fired at least one hour during the day. One rationale given by EPA to use the ‘any number of hours’ definition of operating day was specifically to include start -up and shutdown emissions in the 30 operating day rolling average

emission limitation.

The same operating day concept is also used in some BART determinations that have been reviewed for this revision of the BART Order. Of most importance to this discussion is EPA Region 6’s use of a rolling 30 operating day average in its BART determination for the San Juan Generating station and proposed by Region 8 for coal-fired power plants in North Dakota. Alternately, EPA Region 9 has proposed to use a 30 calendar day a verage for the Four Corners

Power Plant.

The Centralia Power Plant has a history of not operating for 2– 6 weeks each year due to the availability of lower cost hydropower in the market. Operating records for the past several years indicate several time p eriods during each year where only one unit may be operat ing continuously while the other unit operates for a few days at a time then be shut down or operate at minimum firing rate.

Another reason for considering the operating day concept is that Ecology and EPA are now requiring emissions during start-up and shutdown to be addressed specifically in permits and orders such as this. In the recent revisions to 40 CFR Part 60, Subpart DA, EPA retained the minimum hours of operation definition for operating d ay specifically for use in the preexisting NSPS requirements while using a definition of operating day that includes any hours where fuel

is fired for us e in the revised NSPS standard.

41 In the EPA rules, both types of operating day have been used, though the most recent EPA rules have defined an operating day as any day when fuel is fired, regardless of the duration of fuel firing.Ra ther than going through the process of establishing emission limitat ions covering start

- up and shutdown, Ecology is choosing to follow EPA’s lead on more recent emission standards of addressing start -up and shutdown emissions by establishing longer averaging period emission standards. The use of a 30 operating day averaging period that includes all days with fuel combustion in either coal unit addresses start-up and shutdown.

Alternate form of the emission limitation

Ecology could change from the current emission standard expressed in terms of lb/MMBtu fired to an output based limitation such as lb of NOx per gross or net MWh produced. This approach would make the BART result more difficult to compare to other facilities. However, this form of emission limitation may be very appropriate for a new power plant or an existing plant undergoing significant renovation to assure maximum net efficiency in generating electricity.

Th e approach of using lb/MWh has not been analyzed in detail, though based on information from some combined and simple cycle combustion turbines, it may not be adequate to address periods of low load and unit start-up and shutdown.

An annual NOx emission limit in terms of tons per calendar year, like the current SO 2 limit for the plant, could be established for the plant. One difficulty in this approach is the number of variables involved in setting the number. The current boilers have been modified and changed fuel from Centralia coal to PRB coal, all of which affect the plant heat input rate, NOx emissions from the boilers, and gross output rates . A result of these changes are that a number of values must be estimated or assumed such as the current design firing rate, controlled emission rate, plant capacity factor, and annual operating hours.

Rationale for establishing the initial NOx emission limitation

Based on the above information, plus additional considerations explained below, Ecology proposes to establish an initial NOx emission limitation that will be achievable by the facility, low enough that use of the SNCR system on both units will be required to comply with the limitation, but not be so low as to result in an extensive SIP limit relaxation analysis by Ecology and EPA if the actual emissions from the power plant are unable to achieve the limitation.

The emission limitation selecte d is in the form of pounds of pollutant per million Btu heat input, 30 operating day average. This is selected primarily for comparative purposes to other coal- fired power plants across the country, which commonly have emission limits in this form. This is also the unit of measure used in the federal New Source Performance Standard for utility boilers, and is the unit the plant is required to report its NOx emissions to EPA under the Acid Rain Program requirements. The use of a 30- day rolling average will also meet EPA guidance on setting emission limits that are enforceable in practice.

For the numerical value of the NOx limit, several pieces of information were considered. One is that during periods of sustained operation, where neither unit is shut down or started up,

emissions data indicate it is possible for the plant to demonstrate compliance with the Company’s proposed 0.22 lb/MMBtu limitation without operating the SNCR system.As noted above there is a state law that affects the operation of this facility, Chapter 180, laws of 2011 amending RCW 80.80.040. The specific requirement in RCW 80.80.040(3) says:

(c)(i) A coal-fired baseload electric generation facility in Washington that emitted more than one million tons of greenhouse gases in any calendar year prior to 2008 must comply with the lower of the following greenhouse gas emissions performance standard such that one generating boiler is in compliance by December 31, 2020, and any other generating boiler is in compliance by December 31, 2025:
(A) One thousand one hundred pounds of greenhouse
gases per megawatt-hour; or (B) The average available greenhouse gas emissions output as determined under RCW 80.80.050.(ii) This subsection (3)(c) does not apply to a coalfired baseload electric generating facility in the event the department determines as a requirement of state or federal law or regulation that selective catalytic reduction technology must be installed on any of its

boilers.

Ecology interprets subsection (3)(c)(ii) to mean that if the plant is required to install SCR to comply, that the requirement to meet the GHG emission performance standard goes aw ay for both units. Such a requirement to install SCR can derive from a revised New Source Performance Standard , a requirement to comply with an emission limitation unachievable by SNCR in the BART order (as a requirement under state regulations), or afte r the BART order is included in the SIP (becoming a requirement of federal regulation too). It is in the interests of the state to see the coal units at the plant decommissioned. If the BART limitation is set at a level that SNCR cannot achieve, and woul d require the installation of SCR, then it is Ecology’s opinion that the decommissioning requirement in state law goes away.

In comments to Ecology on a preliminary draft of the Revised BART Order, TransAlta suggested an initial emission limitation of 0 .22 lb/MMBtu (a <9% reduction from the current emission limitation of 0.24 lb/MMBtu) . As noted previous ly , our review of the Acid Rain Program data indicates that the units at the plant could achieve this proposed emission limitation without the operation of the required SNCR system during extended periods of consistent operation.

In recent years, the Acid Rain Program report for the facility indicates plant operation has changed to lower capacity factors accompanied by more unit start -up and shutdown occurrences. During unit shutdown and start-up, emissions are higher on a pound/MMBtu basis than during consistent operation. For example, during 2011, the plant stopped producing electricity in February, and did not resume operations until August due primarily to two factors: an excess of hydropower from the Bonneville Power Adminis tration system, and the large increase in electric generation from wind turbines, which receives preferential treatment by power purchasers. During 2010, the data also shows numerous unit shutdowns, periods of one unit operation andper iods of no operation. Historically, the plant has not operated in the late spring/early summer for periods of 2–4 weeks due to the availability of lower cost hydropower. 42

As a result of the increased number of unit start- ups with their relatively higher emission s, the potential for extended operation to comply with the company’s proposed initial NOx emission limitation without operating the SNCR system, and Ecology’s desire that the plant be required to utilize the system to comply while not triggering a requirement to in stall SCR, we propose to establish an initial NOx emission limitation a slightly lower emission limitation than proposal by the company.

Projected Visibility Improvement as a result of implementing SNCR and ceasing to burn coal at the TransAlta Centralia plant

The following table depicts the projected visibility impacts at 3 future years resulting from the emissions reductions and coal unit decommissioning. SNCR is to be installed and operational in 2013. It will then have a period of optimization to achieve the maximum NOx reduction; this will be achieved in 2015. By law, one unit must be decommissioned by the end of 2020 and the other coal unit by the end of 2025. These shutdowns are portrayed as starting in 2021 and 2026 respectively.

The visibil ity improvement analysis assumes that the result of the SNCR optimization study will result in at least a 25% reduction in NOx emissions from the rates required for the Flex Fuels project (as reflected in the original BART Order). This reduction is projected to occur in 2015

Based on this analysis, by 2015 when the results of the SNCR optimization study are required to be implemented, we anticipate the visibility improvement from SNCR will be at least 0.7 dv at all Class I areas within 300 km of the plant. By 2021 when the first unit will be decommissioned the visibility improvement is expected to be even more dramatic, leading to no impact by 2026

when the second unit has been decommissioned. Th e following table indicates the visibility impacts and em ission r ates expected in the future.

Visibility Impacts from TransAlta Centralia Power Plant

Class I Area Visibility Criterion Baseline (2002)

Emissions 2015 Flex

F uels and

SNCR 2021, one unit

decommissioned 2026, both units

decommissioned Alpine Lakes

Wilderness Max 98% value (8th high) in any year 4.871 2.949 1.475 0

3

- yrs Combined 98% value (22nd high) 4.346 2.598 1.299 0

Glacier Peak

Wilderness Max 98% value (8th high) in any year 3.615 2.049 1.025 0

3

- yrs Combined 98% value (22nd high) 2.622 1.532 0.766 0

Goat Rocks

Wilderness Max 98% value (8th high) in any year 4.993 3.069 1.535 0

42 As a result of this known period of time when hyd ropower is available, the plant has routinely scheduled major maintenance for the late spring time period.Visibility Impacts from TransAlta Centralia Power Plant

Class I Area Visibility Criterion Baseline (2002)

Emissions 2015 Flex

F uels and

SNCR 2021, one unit

decommissioned 2026, both units

decommissioned

3

- yrs Combined 98% value (22nd high) 4.286 2.637 1.319 0

Mt. Adams

Wilderness Max 98% value (8th high) in any year 3.628 2.194 1.097 0

3

- yrs Combined 98% value (22nd high) 3.628 2.147 1.074 0

Mt. Hood

Wilderness Max 98% value (8th high) in any year 3.471 1.978 0.989 0

3

- yrs Combined 98% value (22nd high) 2.83 1.665 0.833 0

Mt. Jefferson

Wilderness Max 98% value (8th high) in any year 2.079 1.15 0.575 0

3

- yrs Combined 98% value (22nd high) 1.888 1.053 0.527 0

Mt. Rainier

National Park Max 98% value (8th high) in any year 5.447 3.606 1.803 0

3

- yrs Combined 98% value (22nd high) 5.489 3.501 1.751 0

Mt. Washington

Wilderness Max 98% value (8th high) in any year 2.027 1.106 0.553 0

3

- yrs Combined 98% value (22nd high) 1.414 0.737 0.369 0

North Cascades

National Park Max 98% value (8th high) in any year 2.821 1.57 0.785 0

3

- yrs Combined 98% value (22nd high) 2.212 1.228 0.614 0

Olympic

National Park Max 98% value (8th high) in any year 4.645 2.695 1.348 0

3

- yrs Combined 98% value (22nd high) 4.024 2.486 1.243 0

Pasayten

Wilderness Max 98% value (8th high) in any year 1.954 1.075 0.538 0

3

- yrs Combined 98% value (22nd high) 1.482 0.822 0.411 0

Three Sisters

Wilderness Max 98% value (8th high) in any year 2.172 1.139 0.570 0

3

- yrs Combined 98% value (22nd high) 1.538 0.819 0.410 0

Columbia River Gorge National

Scenic Area Max 98% value (8th high) in any year 2.545 1.446 0.723 0

3

- yrs Combined 98% value (22nd high) 2.353 1.378 0.689 0

Modeled

Emission Rates (lb/hr) Both units added together

NOx

-- > 4,984 2,952 1476 0

SO 2 -- > 4,522 1,854 927 0

It is anticipated that there will at least 700 MW of replacement power generation located at the TransAlta site. This replacement power is anticipated to be provided by a new natural gas fired combined cycle combustion turbine facility that will have to r eceive a Prevention of Significant Deterioration permit.

Proposed BART e mission limitation

Based on the above analysis, Ecology proposes to establish an emission limitation of 0.21 lb/MMBtu, 30 operating day rolling average as the initial NOx emission limitation. Theemis sion limitation will be revised in the future to reflect optimization of the installed SNCR

system

. 43 An operating day is any calendar day when a boiler was fired. A more precise estimate of the nitrogen oxides emission reduction ach ievable with the SNCR system could be made based on the upcoming computational fluid dynamics analysis of the boilers. However, the state law requires the installation of SNCR and the revision of the BART Order for this plant be completed prior before Dec ember 31, 2011, prior to the completion of that analysis.

EPA has adopted the definition of operating day and 30 operating day averaging period for a number of its regulations and at least one BART determination established by Regions 6 and 9.

The NSPS r ules and BART determination intend covering unit start-up and shutdown emissions within the 30 operating day averaging period. Ecology agrees with EPA that a 30 operating day period is suitably long to moderate the effects of unit start -ups and low load operation.

Based on the above review, Ecology proposes that the NOx emission limits for the R evised

BART O rder to be:

• Starting on date of order issuance, 0.24 lb/MMBtu, 30 operating day rolling average, both units averaged together.

• Starting on the 31 st operating day after January 1, 2013, 0.21 lb/MMBtu/hr 30 operating day rolling average, both units averaged together, 30-day rolling average.

• A NOx reduction optimization program will be required. The initial NOx limitation

based on the use of SNCR will be revised to reflect the NOx reduction rate derived from the required NOx reduction optimization program.

The monitoring and emission calculation process in the Revised BART Order is based on the BART Federal Implementation Plans issued by EPA for c oal fired power plants in North Dakota

and New Mexico. Similar to EPA and other states in BART determinations , we do not propose to include tons of NOx per year, operating rate, or operating time limit in the BART Order.

NOx Reduction Optimization P rogram

The goal of the SNCR optimization program is to determine the lowest NOx emissions that may be achievable and the lowest NOx emission rate that is paired with the lowest ammonia emission

rate. The revised emission rate to be inserted in the R evise d BART Order will be based on lowest NOx rate achievable with a minimum ammonia slip rate. The target of the optimization is not to determine how little ammonia injection is required to achieve the initial NOx emission limitation, but to determine the low est NOx and ammonia rates achievable and that do not result in contamination of fly ash or gypsum 44 produced by the FGD system that would render these byproducts unsalable.

43 This revision will be submitted to EPA as a revision to the SIP emission limitations for this plant.

44 The use of fly ash to make concrete reduce s the quantity of greenhouse gases and other air pollutants produced to make concrete by reducing the quantity of cement required. The use of gypsum to make wallboard for the local area reduces the pressure to mine natural gypsum in Mexico (the alternate gypsum source for the purchaser of theTh e goal of the optimization process is to identify three operating points of the SNCR system:

• The lowest NOx emission rate that will meet an amm onia slip of less than 5 45 ppmdv.

• The lowest NOx emission rate that will meet an ammonia slip of up to 20 ppmdv.

• The lowest NOx emission rate that coincides with the lowest ammonia slip.

• The ability to achieve a NOx emission rate no higher than 0.180 ppmdv, 30 operating day rolling average, each unit individually.

To facilitate a true optimization of the SNCR system, the revised Order will allow a higher ammonia slip during part of the optimization period. This higher slip is necessary to allow excess ammonia to be injected to determine how much NOx emissions can be reduced.

The Revised BART Order will then be revised again to incorporate the results of the optimization study. Based on t he results of the study, the NOx limit will be revised to a lower limit. The ammonia slip limit may also be revised to a higher or lower limit, depending on the findings of the optimization study. Ecology intends to then submit the revision as an amendment to the Regional Haze portion of the Washington State Implementation Plan.

TransAlta gypsum) or import wallboard from other countries. If these byproducts cannot be beneficially used the environmental and direct costs are more than simply the cost to TransAlta to landfill the materials.

45 Change per request of Company during public comment. The 5 ppm value here and the 10 ppm limit in the Order are both 30 day averages.August 8, 2011

Mr. Alan Newman Washington Department of Ecology Air Quality Program

P.O. Box 47600

300 Desmond Drive Lacey, WA 98504-7600

Re: TransAlta Centralia Generation LL C’s Comments on Proposed Revisions to

BART Order to Address SNCR

Dear Mr. Newman:

TransAlta Centralia Generation LLC (“TransAlta” ) has reviewed the Department of Ecology’s proposed revisions to the Implementation Orde r that was issued in June of 2010 (“BART Order”) and we would like to provide the fo llowing comments. The issues of concern are

described in this letter and s uggested changes to address these concerns are made in attached

red-line version of the draft BART Order.

Nitrogen Oxides Limit (Condition 1.1.1) The draft Order proposes a nitrogen oxides (“ NOx”) emission limit of 0.18 lb/MMBtu based on a presumed reduction factor of 25% of the Flex Fuels Project emission rate. However, for the following reasons, the 25% fact or does not necessarily apply a nd is unlikely to be achieved in practice.

As background, the CH2M Hill “BART Analysis for Centralia Power Plant,” p.3-6 (rev. July 2008) cites a study by Harmon (1998) concluding that tangentially fired boilers are able to achieve a 20 to 25 percent reduc tion with the application of SNCR. Based on the study and other information, CH2M Hill’s 2008 BART Analysis applied the high end of the range, 25 percent, to the baseline emission rate of 0.30 lb/ MMBtu to derive an estimated emission rate of 0.228 or 0.23 lb/MMBtu for the purpose of modeli ng visibility benefits from SNCR. (See Case 3 SNCR estimated emissions of 0.228 in 2008 BART Analysis).Page 2

8/8/2011

Ecology’s BART Determination Support Docume nt (rev. April 2010) concurred that the 25 percent reduction factor was a reasonable assumption. Tran sAlta’s May 2008 response to Ecology’s comments on the January 2008 BART Analysis report reiterated the Harmon findings and implicitly acknowledged that the high end of the range from adding SNCR to existing LNC3 and Flex Fuels is 25%:

“The control effectiveness of SNCR is a function of many vari ables including the uncontrolled emissions concentrations, physical conditions, and operational conditions. The greatest control effectiven ess is generally achieved with high uncontrolled NOx concentrations, on new units that have been specifically designed for SNCR, and at a specific load ... In addition, a study by Harmon indicates that a large coal fired tangentially fired unit equipped with a low NOx SNCR has the potential to reduce NOx emissions by only 20- 25 percent with an ammonia slip of less than 10 ppm....”

The conclusion that 25 percent reduction is highe st likely reduction is supported by PGE’s “Alternative BART Analysis fo r the Boardman Power Plant,” p. 3-4 (Aug. 27, 2010) concludes

that SNCR achieves “emissions reduc tion levels of 15 to 25 percent fo r retrofit applications.” At Ecology’s request, in March 2010 TransAlta m odeled the visibility benefits from adding SNCR to Flex Fuels. Based on the previous 25 percent reduction fact or from the 2008 BART Analysis report, the 2010 visibility modeli ng assumed an emission rate of 0.18 lb/MMBtu based on the Flex Fuel Project rate of 0.24 lb/MMB tu. It is important to note that the 25 percent assumption was not based on an engine ering study or a vendor estimate. The emission reduction was not intended to be relied upon as a potential enforceable limit but only as an approximation of the visibility benefits.

TransAlta did not begin to develop SNCR emission rates for use as an enforceable BART limit until the passage of SB 5769 earlier this year. In recent months Tran sAlta selected and is currently working with a SNCR system vendor to determine what NOx reduction efficiency and emission rates will be achievable with the pr oposed SNCR systems when they are installed

on the TransAlta units. A com putational fluid dynamics (CFD) model of each of the two Centralia furnaces must be generated as the first step in designing the optimal emissions reduction systems. This modeling and design must be completed before a construction contract for the systems can be issued a nd a warranty for the projected NOx reduction efficiency is obtained from the vendor.

The creation and verification of CFD models a llow the vendor’s technical experts to predict temperature distribution, gas fl ow paths and concentration and distribution of constituents including O2, CO, NOx, and unburned carbon within the boilers. The model is used to select the size, location and design of the SNCR system components and capabilities. The first step in the CFD modeling process is to generate a m odel based on the Plant’s engineering drawings for each boiler. The next step is to develop a baseline simulation at low & high boiler loads on each Centralia unit. This requires gathering ope rational data on temperature distribution, gas flow paths and concentration and distribution of constituents includ ing O2, CO, NOx, and unburned carbon during operation of the units at different produc tion levels. Since both unitsPage 3

8/8/2011

were off-line from early March through late July, the testing to gather the required data is currently scheduled for August 2011.

The data gathered in August will be used to calibrate the CFD models developed for each unit and estimate potential NOx reductions achievabl e over the anticipated operating range of the

units. The information obtained from the CFD modeling will allow the selected vendor to finalize the design of the SNCR system equipm ent and warranty the design NOx removal efficiency of the SNCR systems in October 2011.

Prior to completion of the CFD modeling and ba sed on current information, the limit that can

be achieved with reasonable assurance would be 0.22 lb/MMBtu, which is already a reduction of more than 25% from the pre-BART baseline em ission levels. The study by Srivastava et al, Table 3, cited in the draft Determination S upport Document lists 20 plants with SNCR that had emission rates ranging from 0.274 to 0.755, significantly higher th an the 0.22 lb/MMBtu rate that TransAlta is proposing for Centra lia. Although the removal rates may be higher,

TransAlta understands that SNCR has diminishi ng efficiency at lower levels of baseline emissions, such as the Flex Fuel Proj ect rates of the Centralia Plant.

An emission rate of 0.22 lb/MMBtu is substantia lly lower than the median emission rate of 0.27 for all the SNCR systems proposed as BART in the Western United States (see attached table). The attached table and the Departme nt’s own draft BART Determination Support Document show that no coal-fired plant in the Western United States has been determined to be capable of achieving a BART emission rate less than 0.19 lb /MMBtu with SNCR technology and LNC3 combusti on controls combined.

Based on the foregoing information and Tran sAlta’s operating expe rience with LNC3 technology, an emission rate of 0.22 lb/MMBtu should be achievable w ith the addition of SNCR technology to the current LNC3 technology and an ammonia slip of less than 5 ppm. This would result in a greater than 25 per cent reduction from the pre-BART emissions. Operating experience will determine whether an additional emission reduction to a level of 0.20 lb/MMBtu (a 33% reduction from 0.30 and 17% reduction from 0.24) is achievable with optimization of an SNCR system. However, as explained in the CH2M Hill BART Analysis, the reduction achievable depends upon many factors, including higher amm onia slip than the proposed limit. Achieving the Department’s pro posed emission rate of 0.18 is considered very unlikely (see attached discussion). A discussi on of the unique factors that influence NOx the

installation of SNCR for NOx reducti on in the TransAlta units is att ached in the letter from the Centralia Plant engineer.

In conclusion, it is necessary to complete the study required by Section 5 of the order to

determine the lowest level that SNCR can reas onably achieve before a limit lower than 0.22 lb/MMBtu is set. TransAlta proposes that, at the conclusion of the st udy required by Section 5, a lower emission limit (as low as 0.20 lb/MMBtu) will be requested if it is shown to be achievable by the result of the st udy. If the plant is able to optimize the systems to reach 0.20 lb/MMBtu, this level would be among the lowe st achieved by any plant in the Western U.S. utilizing SNCR with LNC3 technology.Page 4

8/8/2011

Ammonia Emissions Limit Compliance with the ammonia emissions limit must be determined on the same 30-day rolling average time frame as the NOx limit. Without th e flexibility to adjust ammonia addition rates as needed to operate the SNCR system optima lly, we cannot assure that we can achieve compliance with the 0.22 lb/MMBtu NOx limit.

Ammonia Emissions Monitoring We have not been able to find any CEMS for a mmonia that will provide the required accuracy and repeatability on our plants when controlle d by SNCR. A recent review of the technology confirms this ( http://www.ladco.org/about/gener al/Emissions_Meeting/Greaves_032510.pdf ). NDIR/FTIR ammonia analyzers ha ve proven to be unreliable a nd inaccurate for measuring ammonia slip in the 5 ppm range. UV ammonia an alyzers have also proven to be inaccurate for measuring ammonia slip in the desired range. TDLAS in-situ analyzers cannot be used on the saturated stack following the SO 2 scrubber.

The Differential NOx/NH3 Converter Method descri bed on slide 8 of the presentation is the only technology that might be effective; however this type of system only works accurately when NOx emissions are at very low levels. For our process with SN CR the full scale of the analyzers must be set at levels approximately 200 ppm. The allowable 2.5% daily drift on an analyzer with a full scale of 200 ppm is 5 ppm. Since two analy zers are used to determine the ammonia concentration, the allo wable drift of the two analyzers could compound the potential error to 10 ppm which is double the proposed lim it for ammonia and would be unable to pass the proposed certification requirements. Based u pon this review, it has been determined that

monitors for ammonia that can be certified as CEMS are not availabl e for our units.

While we intend to install some type of pro cess monitoring equipment on the SNCR system to provide necessary ammonia data for optimizi ng the SNCR operation, as we described above, the current technology cannot meet requirement for use as a CEMS. We therefore propose removing the ammonia monitoring requirements fr om the Order and replacing them with an annual compliance test. Once we determine the be st system to monitor ammonia levels for the ammonia optimization study and where it can be installed to provide the most useful information (with assistance from the SNCR system supplier), we will include that information in the study plan required by condition 5.2.

Greenhouse Gas Emissions Including SB 5769’s greenhouse gas (GHG) emissi on limitations is inap propriate. The GHG requirements are unrelated to the BART Order and the requirements of the Regional Haze SIP. SB 5769 provides that these requirements will be incorporated in an enforceable agreement

between TransAlta and the State. There is no implication in the stat ute that the GHG limits should be incorporated in a BART determinatio n. To the extent necessary to support the

timelines used for the cost be nefit calculations in the BART determination Support Document,

State law establishes the enforceabilit y of those timelines for EPA.Page 5 

# Trans t\ lta 8/8 / 2011

TransAlta believes that completely removing this section is appropriate; however, we have proposed alternative language if the Department cannot rely on State law to establish the enforceability of the timelines. The proposed language utilizes the language " cease burning

coal" similar to the EPA approved Oregon BART language

.

Operating Days and Startup / Shutdown (Section 8

. 3)

Removal of the 360 MW minimum operating rate references in the BART Order has essentially eliminated the startup/shutdown allowance from the existing Order. There must be

an allowance for partial operating days or staJ1ups and shutdowns in the Order because the

limits are based upon operation of the SNCR systems. These systems cannot operate under

startup and shutdown conditions. EPA concurs that BART determinations may take into

account higher emissions

- during startup and shutdown. (Letter from EPA Region 8 to South

Dakota Department of Environment and Natural Resources, Sept. 13,2010, p. 2

, attached). If Ecology does not concur with the 360 MW minimum operating rate approach, then one
alternative would be that an operating day with less than 8 hours of operation would have to be

eliminated from the 30-day average since it will represent either startup or shutdown

conditions. We propose that section 8.3 reflect that only days with 8 or more hours of firing

coal would be averaged into the 30-day average. This is similar to the 8-hour startup

allowance in our Title V permit condition M9 and we believe would exclude a portion of

emissions that occur only during the beginning of a startup or ending of a shutdown from the 30-day average.

BART Determination Support Document (Section 4.2 and Appendix 1)

We request that Ecology leave the BART determination as LNC3 and Flex Fuels. The

installation of SNCR could be based on the technology needed to meet the State's Visibility

Reasonable Progress goals. This approach would avoid the need to issue a new BART Order

but would still accomplish the goal of setting a lower enforceable limit to improve visibility

.

Please contact Brian Brazil or Rick Griffith if you have any questions regarding these

comments.

Sincerely

,

# 5f'~

Bob Nelson
Director, Centralia Operations

TransAlta Centralia GenerationLLC

cc: Clint Lamoreaux, Southwest Clean Air Agency

Rick Griffith

### SNCR BART/RFP Determinations fo r Western Coal Plant Sources

Emission Unit Assumed
NOx Control Type NOx Emission

Limit Assumed
SO 2 Control Type SO 2 Emission

Limit Reasonable Progress NOx
Controls
Alaska ( http://www.dec.state.ak.us/air/ anpms/rh/rhdoc/Section III.K.6.pdf ) GVEA Healy
Unit 1 existing LNB with OFA,
SNCR required to be

added 0.20 lb/MMBtu existing dry

sorbent injection system 0.30 lb/MMBtu Will be

evaluated if

not shut down by 2024

Colorado ( http://www.cdphe.state.co. us/ap/regionalhaze.html )
CENC

Unit 5 new LNB with SOFA, and
SNCR 0.19 lb/MMBtu

Or
0.26 lb/MMBtu Average for Units 4 & 5 (30- day rolling) None 1.0 lb/MMBtu (30-day rolling) no

TSG&T Craig

Unit 1 new SNCR System 0.28 lb/MMBtu (30-day rolling) Wet

Limestone

scrubber 0.11 lb/MMBtu (30-day rolling) BART is 0.27

, 0.28 allowed
with SCR on

Unit 2

TSG&T Craig

Unit 2 (SNCR is BART) new SCR System

for RP 0.08 lb/MMBtu (30-day rolling) Wet

Limestone

scrubber 0.11 lb/MMBtu (30-day rolling) BART is 0.27, 0.08 required
for reasonable progress goal
Nevada ( http://deq.state.wy.us/aqd/308 SIP/ 309(g) SIP 1-7-11 Clean Final.pdf )

NVE Reid

Gardner
Units 1 & 2 ROFA with

Rotamix 0.20 lb/MMBtu (12-month rolling) existing wet

soda ash
FGD 0.15 lb/MMBtu (24-hr) no

NVE Reid

Gardner
Unit 3 ROFA with

Rotamix 0.28 lb/MMBtu (12-month rolling) existing wet

soda ash
FGD 0.15 lb/MMBtu (24-hr) no

North Dakota ( http://www.ndhealth.gov/AQ/RegionalHaze/Regional Haze Link Documents/Main SIP Sections 1-12.pdf )
BEPC

Leland Olds
Unit 1 new LNB with
SOFA and
SNCR 0.19 lb/MMBtu (30-day rolling) new Wet

Limestone

scrubber 0.15 lb/MMBtu (30-day rolling) no

BEPC

Leland Olds
Unit 2 new LNB with
ASOFA and
SNCR 0.35 lb/MMBtu (30-day rolling) new Wet

Limestone

scrubber 0.15 lb/MMBtu (30-day rolling) no

GRE
Stanton

Unit 1 new LNB with
OFA and
SNCR 0.29 or 0.23
lb/MMBtu (30-day rolling) new Wet

Limestone

scrubbers 0.24 or 0.16
lb/MMBtu (30-day rolling) Note: limits on lignite and

subbituminous

MPC Milton R.Young
Unit 1 new LNB with
ASOFA and
SNCR 0.36 lb/MMBtu (30-day rolling) new Wet

Limestone

scrubber 0.15 lb/MMBtu (30-day rolling) no

MPC Milton R.Young
Unit 2 new LNB with
ASOFA and
SNCR 0.35 lb/MMBtu (30-day rolling) existing Wet

Limestone

scrubber 0.15 lb/MMBtu (30-day rolling) no

Average SNCR BART Limit 0.26 lb/MMBtu

Median SNCR BART Limit 0.27 lb/MMBtu

Lowest SNCR BART Limit 0.19 lb/MMBtuJuly 28, 2011

Mr. Brian Brazil

Re: Selective Non Catalytic Reduction (SNCR) Technology implementation at

Centralia Plant

Brian:

Station #1 & #2 boilers were retrofitted with Low NOx Burners (LNB) in 2002 and 2001, respectively. This modification, which included installation of Separate Over Fire Air (SOFA) and Close Coupled Over Fire Air (CCOFA) injec tion ports, allowed the NOx emissions to be lowered to 0.30 lbs/mm BTU. In 2008 as part of conversion to PRB fuels which are inherently lower in nitrogen content, and additional fine tuning of the bo ilers, the achievable NOx level

was further reduced to 0.24 lbs/mm BTU.

Earlier this year, we embarked on instal lation of SNCR technology on both boilers for additional reduction of NOx. In SNCR systems, a r eagent is injected into the flue gas in the furnace within an appropriate temperature window. The reagent generates ammonia and the process reaction converts NOx to nitrogen a nd water vapor. The performance of an SNCR system depends on a variety of factors su ch as the furnace baseline oxygen and carbon monoxide concentrations, injected reagent quant ity and distribution, residence time, and flue

gas temperature.

The influence of these parameters can have a significant impact on th e performance of an SNCR system. The theoretical reduction for SNCR r eaction is one mole of NOx to one mole of ammonia. However, experience has shown that a portion of ammonia can exit the boiler and cause numerous environmental and operational c oncerns such as formation of detached plumes, corrosion and boiler component pluggages. The unreacted ammoni a reacts with other compounds in the flue gas to form ammonia co mpound such as NH4 HSO4 or NH4 Cl. These compounds are corrosive and can create blockages of the air prehea ter baskets that will lead to forced unit outages. Free ammonia also has the potential to contaminate the captured fly ash and the station SO2 control system’s by-products creating additional problem.

Since the PRB fuels conversion at the plant we have had numerous issues unique to our boilers. These fireboxes, which were originally designed for combusting the native fuel fromPage 2

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the mine next door, are too short to allow su fficient heat adsorption from PRB fuels which generate higher radiant heat. This has resu lted in excessive furnace exit gas temperature leading to non stratified is othermal planes. The excessive heat also generates fluid slag (due to high sodium PRB ash) on the walls that plug up observation ports and in strumentation taps on the boiler walls. The SOFA injection can also create pocket of high CO gas and unpredictable mixing zones for the reaction between the SNCR r eagent and the NOx in the flue gas stream. These issues would significantly affect the pe rformance of SNCR system s relying on injection

above the furnace.

The SNCR systems using multi nozzle lances inj ecting at the superheater pendant positions, rely on rotary insertion systems identical to our long lance IK soot blower s. These lances are unreliable, experience routine fail ures from clinker falls, and rema in out of service on a regular basis. The long term viability of any SNCR system relying on multi nozzle lances is questionable.

We have had multiple conversations with pot ential suppliers of SNCR technology and there appears to be a significant reluctance to o ffer an ironclad guarantee regarding the removal efficiency and the free ammonia slip stream at th e boiler outlet. One of the contributors to this issue is the fact that we are already operat ing with extremely low NOx levels (0.24 lbs/mm BTU) that the actual realized system performance may be hard to predict.

We are currently working with a SNCR syst em vendor to determine what NOx reduction efficiency and emission rates will be achievable w ith their proposed design of SNCR systems.

We have also retained the services of an i ndependent consulting firm specializing in modeling of SNCR components and their in teraction with various parame ters within a boiler. The outcome of these models will provide additiona l insight as to the performance of the SNCR

system.

The above mentioned concerns and due to the fact that the actual long te rm performance of any SNCR system can only be verified by post co mmissioning optimization, we do not anticipate

to be able to achieve more than 19-20% NOX rem oval efficiency. However, it is our intention to push our system to its highest sustainable capability.

Please feel free to contact me if you have any questions regarding these comments.

Sincerely,

Jim Khorsand, P.E. Plant Lead Engineer

cc: Trevor Ebl1Implementation of NH3 measurement on PostCombustion NOx Reduction Systems.LADCO WORKSHOPMarch 24-25th, 2010Ammonia Slip MeasurementPost Combustion NOxReduction:3⁄4Selective non-catalytic reduction (SNCR)3⁄4Selective catalytic reduction (SCR)3⁄4Common requirement: introduction of NH34NO + 4NH4NO + 4NH3+ O2Æ4N2+ 6H2O2NO2+ 4NH3+ O2Æ3N2+ 6H2O2Ammonia Slip MeasurementConsequences of Ammonia Slip:zIf over-titrated NH3 escapes – pollutes andwasteszViolates permit limit if applicablezIf due to incomplete mixing – NOx escapeszWith high sulfur fuels ammonia sulfate andbisulphate formed – can foul air pre-heaterzAmmonia contaminates fly ash making ithazardous3Ammonia Slip Measurement4SNCR Slip MonitorStack Slip MonitorSCR Slip MonitorAmmonia Slip MeasurementMonitoring Methods:zFULLY EXTRACTIVE (DRY BASIS)zFULLY EXTRACTIVE (HOT-WET BASIS)zDILUTION EXTRACTIVE (WET BASIS)zIN-SITU (CROSS STACK or PROBE)Measurement Types:zChemiluminescence ,UV Absorption, FTIR, DOAS,z(TDLAS)5zAnalyzer GlossaryzChemiluminescence:(Chemical Light) a measurementtechnique for NO/NOx thatmeasures the light given off as a resultof the reaction between NO and Ozone. Thelight output is proportional tothe concentration of NO. NO2is converted to NO using ahigh temperature catalytic converter. NO2does not react with Ozone so it must beconverted to NO.zUV Absorption:a measurement technique that usesa UV spectrometer to measure aparticular wavelength wherethe gas of interest absorbs (measurement) and awavelength where the gas of interest doesnot absorb (reference). Most often used forSO2measurement in high concentrations.zTunable Diode Laser Absorption Spectroscopy (TDLAS):By scanning across avery narrow bandwidth in the IR region where no cross interferences occur, theabsorption of the IR sourceby the targeted gas is proportional to the target gasconcentration.zFourier Transform-Infrared Spectroscopy (FTIR):This technique measures theabsorption of infrared radiation by the sample gas versus wavelength. The infraredabsorption bands identify molecular components.zDifferential Optical Absorption Spectroscopy (DOAS):is a method to determineconcentrations of trace gases by measuring their specific narrow band absorptionstructures in the UV and visible spectral region6Ammonia Slip MeasurementAmmonia Slip MeasurementInlet/Outlet Differential NOx MethodzFirst method is based on the calculationof ammonia slip using the inlet/outletdifferential NOx method along with ammonia flow rate and stack flow calculation. Thismethod has been employed successfullyin many EPA permitted CEMS, theSCAQMD and many other AQMD’s for control and compliance monitoring. Thismethod is reliable and low in cost forsources where SCR inlet monitoring is arequirement.zThe inlet/outlet method is used where SCRcontrol is also a requirement since boththe SCR inlet NOx and SCR outlet NOx are measured on a continuous basis. Theoutlet measurement is usually the CEMS compliant system. The inlet system requiresa second probe mounted on the duct before the SCR anda second NOx analyzer.zThe NOx and NH3 react on a 1:1 basis. Therefore, the amount of NH3 reacted isequal to the amount of NOx reduced inthe SCR. The simplified formula is:NH3 slip = NH3 fed – (NOx in – NOx out)7Ammonia Slip MeasurementDifferential NOx/NH3 Converter Method:zAn alternate ammonia method using directmeasurement of differential NOx on thestack. This method utilizes two (2) NOxanalyzers on the outlet (stack) CEMS. Anammonia converter is included at the stack probe which converts NH3slip to NOx.The sample line includes an additional sample tube to transportthe NH3 convertedsample stream to an additional NOx analyzer.zOne analyzer is used to measure NOx emissions and the second is installed tomeasure the converted streamwhich includes the NOxand ammonia converted toNOx for the ammonia slip calculations.The NOx analyzers are identical – range,manufacturer, model number.zA special probe Is used to catalytically convert NH3 intoNOx. The increase in NOxthat results is NH3 slip. The probe contains an electrically heated oxidation catalystwhere NH3 is oxidized with oxygen on the catalyst surface into nitric oxide (NO) andwater, as follows:4 NH3 + 5 O2 = 4 NO + 6 H2OzThe NH3 conversion process has an efficiency of 90-98% depending on the sampleflowrates, age of converter,and NH3 concentrations. Conversion efficiencies of 95%+can be expected on typical combustion turbine applications.NH3 slip (ppm) = NOx (ppm) (totalconverted) – NOx (ppm) (unconverted)8Ammonia Slip MeasurementDirect measurement of NH3:zThis can be done using several methods, both across the stack or ductmeasurement or Insitu probe type systems.zTypical across duct measurements use the Tunable Diode Laser method, orDOAS monitor.910In-Situ...Advantages:No gas transport:Fast response time:No loss of components in a sample system:No filters, sample lines, pumps to cleanLower planning expenses:Support for heated sample gas lines:Analysis container:Disposal of sample gas and condensateLower installation and operation cost:No Heated sample gas lines($50/ft ):Larger component Inventoryand Replacementrequirements:Cost for shelter or spacein existing analyzer rooms.Ammonia Slip Measurement: Dan Kietzer June 30, 2009LasIRLAS Processing UnitLasIRDetectorDetectorSignalLAS Launch OpticsUCR TDL Test CellIR Laser LightProcess GasScanner andLensLegendFiber Optic CableCo-Ax CableBeam PathTunable Diode Laser AnalyzerAmmonia Slip MeasurementAmmonia Slip MeasurementTDLAS Ammonia slip Monitoring:•In-situ measurement avoids loss of sample integrity, to Minimize NH3 Slip•Single Indicator of direct measurement of Slip for compliance orperformance of DeNOx system•Fast response better then 60 seconds allows better feedback for control,less violations.12Ammonia Slip Measurement13EXTRACTIVE :Sample delivered to analyzer mounted in typicalcabinet , possibly integrated with CEMS.Useful for Dirty Applications such as certain CoalFired Plants.Measurement type: Chemiluminescence, UVAbsorption, FTIRMinimal performance at low concentrationsEasy to calibrate, since standard calibration gasprocedures are incorporated.Not the most cost effective when equipment, installand maintenance costs are accounted for.DEFOR, Dieter Deggim, September0914For measurement of1 to 3 UV componentsIncludiing O2UV photometerDEFORAmmonia Slip MeasurementAmmonia Slip MeasurementCertification of NH3 Slip MeasurementszThere are no performance standards against which NH3 monitors can be certified,and there are no adopted methodologies for the certification of continuous NH3monitoring.zCTM-027 defines how best toobtain representative stack test samples for verificationof stack conditions, against which any analyzer system would be referenced,.zIn addition, there are no NIST traceable Protocol calibration gases for NH3 at lowerlevels. The most accuratecalibration gas for NH3 is aworking class gas with anaccuracy of +/- 5%. Also, the lowest level that can becommercially obtained is 7 ppm.zSpiking is an accepted method by which relative accuracy data can be obtained butonce again no standards are seton how to achieve this.zMost Insitu analyzers have built in calibrationstandards either by filters or calibrationgas cells. All have the ability to do selfcheck zero and span,and most can bechecked against a standard gas ata higher value working class15Ammonia Slip MeasurementSUMMARY:Until a clear acceptable method for accurate measurement of NH3 at thelowest concentrations now seen (less than 2ppm) is commercially available,and one that can be applied to all applications, then Industry must rely on thevendors to assist in meeting their needs whether it be permit verification orprocess optimization.Insitu while giving the best accuracy will be considered the front runner formost applications, but without the ability todo all applications at the low levelmeasurements will struggle for acceptability.Extractive surrogate measurements will continue to dominate the Utilitymarket for now because of the ease of acceptability as part of a CEMS.Tunable Diode Laser technology is proving to be the most accurate method,but will have to wait until a suitable calibration methood has been definedand accepted.16