QEARTHJUSTICE ALASKA CALIFORNIA FLORIDA MID·PACIFIC NORTHEAST NORTHERN ROCKIES 

NORTHWEST ROCKY MOUNTAIN WASHINGTON, DC INTERNATIONAL 

Q() 

r: <:::) 

("-.J

August 22. 2011 	 w«o 

~l~ co 

() Q.. -'I) C'-l 

IX:. ww~ c...!::' James B. Martin. Regional Administrator 	 (/) ::::> ::i <t U.S. Environmental Protection Agency. Region VIII 


1595 Wynkoop Street 


Denver, Colorado 80202-1129 


Re: 	 Regional Haze Requirements for the Colstrip Coal-Fired Power Plant; Comments of 


Montana Environmental Information Center, Sierra Club, and National Parks 


Conservation Association 


Dear Mr. Martin: 

This letter is submitted on behalfofMontana Environmental Information Center, Sierra 


Club, and National Parks Conservation Association in advance ofourmeeting with you and y:Q!lr 


staffon AUID!st 25, 2..Q.!l;. These comments were prepared with the assistance of Vicki Stamper, 


an independent air quality expert consultant, and provide our detailed recommendations for the 


forthcoming U.S. Environmental Protection Agency ("EPA") rulemaking to implement regional 


haze requirements in Montana, and particularly, the Colstrip coal-fired power plant ("Colstrip"). 


Montana Environmental Information Center, Sierra Club, and National Parks 


Conservation Association have thousands ofmembers in the United States, including Montana, 


who are deeply committed to protecting and improving the air quality in national parks and 


wildness areas in Montana and the Northern Rockies. On behalf ofthese members, this letter 


seeks to support EPA in making an adequate regional haze determination in Montana. 


I. 	 BACKGROUND 

The United States Congress has established a national goal for the "prevention of any 


future, and the remedying of any existing, impairment ofvisibility in the mandatory class I 


Federal areas which impairment results from manmade air pollution." 42 U.S.C. § 7491(a)(1). 


Mandatory Class I areas include national parks and wilderness areas-the jewels of our federal 


public lands system. To protect these areas, a state, tribe, or EPA is required to design an 


implementation plan to reduce, and ultimately eliminate, haze-causing air pollution from sources 


that may reasonably be anticipated to cause or contribute to visibility impairment for one or more 


protected Class I areas located within or beyond that state's/tribe's boundaries. The state of 


Montana chose not to adopt a state haze implementation plan (SIP), and thus EPA is required to 


promulgate a Federal Implementation Plan (FIP) to address regional haze requirements in 


Montana. EPA has an unparalleled opportunity in Montana to improve regional air quality by 


stemming visibility-impairing emissions from the state's oldest and most polluting facilities, 


particularly Colstrip. 


705 SECOND AVENUE, SUITE 203 SEATTLE, WA 98104-1711 

T: 206.343.7340 F: 206.343.1526 E: eajuswa@earthjustice.org W: www.earthjustice.org 
While the Regional Haze Rule's primary thrust is to address visibility impairments, the 

pollutants that cause visibility impairments are also a significant concern for public health and 

the economy. Because the BART Guidelines expressly require the consideration of impacts in 

addition to visibility, EPA must consider impacts to public health when determining BART 

requirements for Colstrip and other BART -eligible sources. 

All ofthe haze pollutants at issue here- nitrogen oxides (NOx), sulfur dioxide (S02), 

and particulate matter (PM}-harm public health. NOx is a precursor to ground level ozone, 

which is associated with respiratory disease, asthma attacks, and decreased lung function. In 

addition, NOx reacts with ammonia, moisture, and other compounds to form particulates that can 

cause and worsen respiratory diseases, aggravate heart disease, and lead to premature death. 1 

Similarly, S02 increases asthma symptoms, leads to increased hospital visits, and can form 

particulates that aggravate respiratory and heart diseases and cause premature death.2 PM, 

especially the smaller particle sizes, can penetrate deep into the lungs and cause health problems 

such as aggravated asthma, chronic bronchitis and heart attacks. 3 

EPA has estimated that by 2015, full implementation ofthe Regional Haze Rule 

nationally will prevent 1,600 premature deaths, 2,200 non-fatal heart attacks, 960 hospital 

admissions, and over 1 million lost school and work days.4 As a result, the Regional Haze rule 

will result in health benefits valued at $8.4 to $9.8 billion annually.s 

EPA must consider the environmental health impacts of haze pollution under the "non-air 

quality environmental impacts of compliance" best available retrofit technology (BART) 

consideration as it makes its determinations for the Montana haze FIP. 40 C.F.R. § 51.308 

(e)(I)(A) 

Colstrip-a 4 unit coal-fired power plant with a generating capacity of approximately 

2,100 megawatts (MW}--is the largest source of air pollution in Montana. Units 1 and 2 became 

operational in 1975 and 1976, and are BART -eligible units. Units 3 and 4 obtained permits 

under the prevention ofsignificant deterioration (PSD) program and became operational in 1984 

and 1986, respectively. Because units 3 and 4 do not meet the definition of "existing source" 

(i.e., were not in existence on August 7, 1977), these units are not currently considered BARTeligible under the regional haze program requirements.6 However, these units are subject to 

1 EPA, Health-Nitrogen Dioxide, http://www.epa.gov/air/nitrogenoxides/heaIth.htrnl 

2 EPA, Health-Sulfur Dioxide, http://www.epa.gov/air/sulfurdioxide/health.htmL 

3 EPA, Health & Environment-Particulate Matter, http://www.epa.gov/air/particlepollutionlhealth.htrnl. 

See also Physicians for Social Responsibility, "Coal's Assault on Human Health," 

http://www.psr.orglresources/coals-assault-on-human-health.htrn1. 

4 EPA, Fact Sheet-Final Clean Air Visibility Rule, http://www.epa.gov/visibilitv/fs 2005 6 15.htrnl. 

5 Id. 

6 See 40 C.F.R. § 51.301 and §51.308(e). We also note, however, that the issue ofBART 

eligibility for units 3 and 4 is unclear based upon our review of the permitting and compliance 

history for these units. 

2 

control requirements under the reasonable progress requirements ofthe regional haze program. 

40 C.F.R. §51.306(d)(1) and (3). 

Under the regional haze program requirements, EPA is to impose emission limits 

reflective ofBART for those BART-eligible units that are also considered subject to BART. 

Specifically, if a BART-eligible source may reasonably be anticipated to cause or contribute to 

any impairment of visibility in any mandatory Class I Federal area, then the facility is considered 

subject to BART. See 40 C.F.R. §51.306(e). If an existing source causes a visibility impact of 

0.5 deciview or higher in a Class I area, EPA considers it contributing to visibility impairment in 

that Class I area

7

• 40 C.F.R. Part 51, Subpart Y, Section III.A.1. EPA considers a source that 

causes 1 deciview or higher visibility impact to "cause" visibility impairment. Id. Visibility 

modeling conducted on behalf ofthe owners of Colstrip showed that Colstrip Units 1 and 2 

cause, on average, visibility impacts of 1 deciview or higher at the following Class I areas: UL 

Bend Wilderness, North Absaroka Wilderness, Theodore Roosevelt National Park, and the 

Washakie Wilderness. The units cause impacts in excess of 0.5 deciviews on average at 

Yellowstone National Park. See August 2007 BART Assessment Colstrip Generating Station, 

Appendix B at Table 5-1 (page 24). Where multiple Class I areas are impacted by a source, it is 

incumbent upon EPA to consider the cumulative impact ofthe source on all impacted Class I 

airsheds in evaluating Step 5 ofthe case-by-case BART analysis. 40 C.F.R. Part 51, Subpart Y, 

Section Ill.E.5. 

The owners of Colstrip Units 1 and 2-Puget Sound Energy and PPL Montana (hereafter, 

"the Company")-submitted an initial BART analysis for these units in August 2007 and 

submitted an addendum to the BART analysis in June 2008. As a result of these analyses, the 

Company concluded that BART for Colstrip Units 1 and 2 consists ofthe existing pollution 

controls with no changes. We disagree: the Company's BART analysis provides support for a 

determination that additional controls and/or upgrades to controls to improve regional haze are 

necessary to achieve BART and meet the objectives of the regional haze program. 

Colstrip Units 1 and 2 have out-of-date pollution controls. The tangentially-fired units 

bum subbituminous coal of 0.7% sulfur content from the northern Powder River Basin. To 

control NOx, the units use a low NOx concentric firing system (LNCFS) with close coupled 

overfire air (CCOF A) and achieve NOx emission rates in the range of 0.30 to 0.35 IbIMMBtu. 

See June 2008 Addendum to PPL Montana's Colstrip BART Report at 2_1.8 To control S02 and 

PM, the units use wet venturi particulate scrubbers; the alkalinity ofthe fly ash in the scrubbers 

helps achieve S02 removal. Id. According to the Company's Colstrip BART report, the 

scrubbers remove 75-80% ofS02 emissions and are designed to remove 98% of PM emissions, 

7 EPA has also indicated that the threshold for determining whether a source contributes to 

visibility impairment in a Class I area may be lower than 0.5 deciviews, especially ifnumerous 

sources impact a Class I area. 40 C.F.R. Part 51, Subpart Y, Section lILA.l. 

8 Although the Company indicated in its June 2008 submission to EPA that Units 1 and 2 

employ LNCFS and CCOF A to control NOx emissions, no such requirement appears in 

Colstrip's Title V permit. EPA should clarify whether the Company is subject to an enforceable 

requirement to operate these NOx controls. 

3 

although the Company claims the scrubbers have been shown to achieve particulate control 

efficiencies approaching 99.5%. Id. The Company has indicated that these units emit S02 at 

0.40 IblMMBtu on a 30-day average basis. Id. at 2-3. Colstrip Units 1 and 2 typically emit 

filterable PM at rates of 0.05 to 0.06 IblMMBtu, respectively. Id. at 2-4. These emission rates 

are much higher than EPA's presumptive BART levels and do not reflect the maximum 

achievable emission reductions at the Colstrip units. 

Colstrip Units 3 and 4 also have substandard pollution controls, especially for NOx and 

PM. The owners ofUnits 3 and 4-Puget Sound Energy, PPL Montana, PGE, Northwestern 

Energy, Avista, and PacifiCorp (hereafter also referred to as "the Company"}-claim the units 

have already met BART under the terms ofthe 2007 consent decree with EPA and the Northern 

Cheyenne Tribe. The Company did not evaluate any additional NOx controls for Colstrip Units 

3 and 4 beyond those required by the 2007 consent decree. The NOx emission limits required in 

the consent decree are not even as stringent as the New Source Performance Standards (NSPS), 

let alone reflective ofBART. Regardless ofwhether Units 3 and 4 are subject to BART,9 EPA is 

obligated to adopt measures to achieve reasonable progress towards the national visibility goal. 

40 C.F.R. §51.308( d)( 1). Given that Colstrip is by far the largest emitter ofregional haze 

impairing pollutants in the state ofMontana, EPA must evaluate additional controls for Colstrip 

Units 3 and 4 to meet reasonable progress requirements. 

In this letter, we provide our analysis ofwhat should be required at the Colstrip units to 

meet BART based on the information submitted by the Company and on proposed and final 

BART emission limitations for other coal-fired power plants. We also provide comments on the 

controls that should be required at Colstrip Units 3 and 4 to meet reasonable progress 

requirements. 

II. BART FOR COLSTRIP UNITS 1 AND 2 

A. Legal Requirements 

EPA regulations mandate that regional haze plans include emission limitations 

representing BART for each BART-eligible source. 40 C.F.R. §51.308(e). Best available 

retrofit technology or BART is defined as follows: 

Best Available Retrofit Technology (BART) means an emission limitation based 

on the degree ofreduction achievable through the application ofthe best system 

of continuous emission reduction for each pollutant which is emitted by an 

existing stationary facility. 

40 C.F.R. § 51.301. EPA is required to determine BART for each unit on a case-by-case basis. 

based on a 5-factor analysis. See id.; see also 40 C.F.R. § 51.308(e)(1 )(ii)(A); 42 U.S.C. § 7491. 

These factors are: (a) the costs of compliance; (b) the energy and non-air quality environmental 

impacts of compliance; ( c) any existing pollution control technology in use at the source; (d) the 

9 Commenters do not concede the point of inapplicability ofBART to Units 3 and 4. 

4 

remaining useful life ofthe source; and (e) the degree ofvisibility improvement which may 

reasonably be anticipated from the use ofBART. See 40 C.F.R. §§ 51.301, 51.308(e)(1)(ii)(A). 

The existing pollution controls at Colstrip Units 1 and 2 are not the best systems of 

continuous emission reductions for the units' visibility impairing pollutant emissions (i.e., NOx, 

S02, and PM). Additional, cost-effective controls are available to significantly improve 

visibility in the region's Class I areas. 

B. 	 NOx 

Colstrip Units 1 and 2 are the largest emitters ofNOx of any BART -eligible source in 

Montana by a large margin. See Summary ofWRAP RMC BART Modeling for Montana, Draft 

#5, May 30,2007, at Table 1 (downloaded from EPA Region VIII's website at 

http://www.epa.gov/region8/air/mtregionalhaze.html). Further, the Colstrip power plant is the 

largest emitter ofNOx of any ofthe industrial facilities in Montana. to The Company's 

evaluation of combustion controls and post-combustion controls for NOx shows all options to be 

cost effective when compared to the costs required at other coal-fired electric utility units 

(EGUs). Nonetheless, the Company inexplicably proposed no additional controls for NOx. 

1. 	 SCR and SOFA can cost effectively achieve an adequate level ofNO x 

control for Colstrip Units 1 and 2. 

Although the Company claims that no additional NOx controls are justified, the 

Company's own analysis demonstrates that use of Selective Catalytic Reduction (SCR) in 

combination with separated overfired air (SOFA) represents the "best system of continuous 

emission reduction" and is cost effective. 40 C.F.R. § 51.301. 

At the request ofEPA, the Company evaluated a NOx emission rate ofO.06IbIMMBtu, 

lower than the presumptive BART levels, through the application ofSCR. The Company 

questioned whether such an emission rate was feasible for Colstrip Units 1 and 2, see June 2008 

Addendum to PPL Montana's Colstrip BART Report at 5-4, however, the Company's analysis 

demonstrates that a NOx emission rate of 0.06 IblMMBtu is readily achievable at these units 

with the application ofSCR. To meet a 0.061blMMBtu emission rate, the SCR needs to achieve 

80-82% NOx removal from current NOx emission rates. SCR systems are routinely designed to 

achieve at least 80% removal. Further, the SCR need only achieve 68% removal ifthe Company 

also installs SOFA to reduce boiler-out NOx rates to 0.19 IbIMMBtu. Colstrip Units 1 and 2 

should be able to reduce NOx to emission rates lower than 0.04 IbIMMBtu with the combination 

of SOFA and SCR at Colstrip Units 1 and 2. 

A review ofrecent SCR retrofits definitively shows that very high levels ofNOx removal 

are being achieved by recent SCR retrofit installations. NOx emission rates less than 0.05 

IbIMMBtu are routinely achieved, and NOx removal efficiencies are typically around 90%.11 

10 Based on emissions data available on EPA's AirData website. 

11 See Erickson, Clayton A. et aI., Selective Catalytic Reduction System Performance and 

Reliability Review, The 2006 MEGA Symposium, Paper # 121, Attachment 4. 

5 

Permitting agencies have required lower NOx limits in recent BACT determinations, with many 

proposed and required BACT limits of0.05-0.06 IblMMBtu and at least one NOx BACT limit as 

low as 0.035 IblMMBtu. 12 

There appears to be an emerging consensus within EPA that SCR generally represents 

BART for NOx. SCR along with combustion controls has been proposed or required as BART 

to meet regional haze progress goals at several coal-fIred power plants elsewhere, including the 

Boswell Energy Center Unit 3 and Alan S. King Unit 1 in Minnesota13, Naughton Unit 3 and Jim 

Bridger Units 3 and 4 in Wyomingl4, San Juan Units 1_415, and Four Comers Units 1-516. SCR 

along with installation of combustion controls including low NOx burners has been found to be 

cost effective at these units. According to data compiled by the National Park Service, the cost 

effectiveness ofthese controls ranged from $2,258 to $4,262/ton. 17 More recently, EPA 

determined the cost effectiveness for installation ofSCR at San Juan Units 1-4 to meet a NOx 

emission limit of0.05 IbIMMBtu, at between $1,579 and $1,920/ton ofNOx removed. 76 Fed. 

Reg. 502 (Jan. 5,2011). 

The Company presented cost effectiveness data for installation ofSCR on Colstrip Units 

1 and 2 to achieve a NOx emission rate ofO.06lblMMBtu that shows the costs are quite 

reasonable. SpecifIcally, the company projected it would cost $1,735/ton ofNOx removed to 

install an SCR system that would reduce current NOx emission rates of0.35 IblMMBtu down to 

0.06IbIMMBtu. See June 2008 Addendum to PPL Montana's Colstrip BART Report at 5-5 to 

5-6. This level of costs is within the range ofBART control costs that other EGUs will have to 

incur under regional haze requirements, and is very similar to the costs projected by EPA to 

install SCR at the San Juan Units 1-4. The NOx reductions required by state regional haze plans 

have been projected to cost $1,872/ton on average. 18 

12 The Desert Rock Energy Facility permit requires the facility to achieve, after a NOx 


optimization period, a NOx emission rate of0.035 IblMMBtu on a 365 day rolling average and 


an emission rate of 0.05 IblMMBtu on a 30-day rolling average. Attachment 5. See also the 


National Park Service spreadsheet on BACT limits for New PC Power Plants, Attachment 6. 


13 See Revised Draft Regional Haze State Implementation Plan, July 2009, Minnesota Air 


Pollution Control Agency, at 71, available at 


http://www.pca.state.mn.us/air/regionalhaze.html#sip. 


14 See January 2011 Draft Wyoming State Implementation Plan Regional Haze, available at 


http://deg.state.wy.us/agdiregionalhaze.asp. 


15 See 76 Fed. Reg. 504 (Jan. 5,2004). 


16 See 75 Fed. Reg. 64230 (Oct. 19,2010). 


17 See National Park Service Spreadsheet entitled "EGUs with proposed BART NOx Controls 


Mar 2011," Attachment 2. 


18 See id. 


6 

The Company's modeling showed almost a 1 deciview improvement in visibility with the 

installation ofSCR and the establishment ofa NOx emission limit ofO.061blMMBtu at UL 

Bend alone. See June 2008 Addendum to PPL Montana's Colstrip BART Report at 5-6. This is 

clearly a significant and perceptible improvement in visibility at this particular Class I area and 

the visibility improving benefits would likewise be realized at the other four Class I areas within 

the plant's airshed. 

If SOFA was also installed, visibility improvement could be even greater without 

impacting cost effectiveness ofthe controls. Although the Company did not evaluate the 

installation ofSOFA and SCR together, the NOx BART determination should be based on the 

combination ofSOFA and SCR because the use of combustion controls to reduce NOx to the 

greatest extent followed by an SCR system represents the best continuous system ofNOx 

emission reduction. Based on the Company's projected 0.19 IblMMBtu NOx emission rate with 

the addition of SOFA, the NOx BART emission limit based on SOFA plus SCR should be 0.04 

IblMMBtu or lower. And, while the Company did not provide cost effectiveness calculations for 

this combination of controls, the cost per ton ofNOx removed should be in the range ofthe 

$1,735Iton that the Company estimated for SCR to meet an emission rate ofO.06IblMMBtu. 

This is because with lower NOx concentrations coming into the SCR, that will decrease both 

capital and operating costs ofthe SCR. 

Based upon this information and analysis, the Company has demonstrated that 

installation of SCR is cost effective and will significantly improve visibility in affected Class I 

areas. Further, ifSCR is installed along with SOFA, the cost effectiveness will improve further, 

and the visibility benefits in the region will be even greater. SCR with SOFA is BART for 

Colstrip Units I and 2. 

2. 	 Installation ofSCR to meet BART for NOx will have other environmental 

benefits. 

Installation of an SCR system will provide other air quality and non-air quality 

environmental benefits, in addition to reduction ofhaze-forming NOx. First, because NOx is a 

precursor to ozone, reductions in NOx will decrease ozone formation. Since vegetation damage 

has been found to occur even where ozone concentrations are below the National Ambient Air 

Quality Standards (NAAQS), greater reductions in NOx emissions from Colstrip as would be 

obtained via SOFA plus SCR could also benefit the vegetation ofthe region's Class I areas and 

areas neighboring these protected spaces. 

Another issue in the region is nitrogen deposition, which is caused by wet and dry 

deposition ofnitrates derived from NOx emissions. The significant adverse impacts ofnitrogen 

deposition on ecological systems is well known. Critical loads (Le., the amount ofnitrogen 

deposition that an ecosystem can tolerate, and above which the systems become adversely 

impacted) are likely to soon be used to formally inform policy developments ~, NADP-CLAD 

Meeting, Pensacola, FL Spring 2009). In addition, greater reduction ofNOx emissions at 

Colstrip would also equate with reductions in PM2.5 formation. 

7 

Further, SCR systems have been shown to help oxidize mercury, which enables easier 

capture ofmercury in downstream particulate control and sulfur dioxide scrubbers. The SCR 

systems could thus help Colstrip Units I and 2 comply with mercury emission limits. 

In summary, numerous environmental benefits, in addition to the public health benefits 

identified above, flow from the use ofSCR systems to reduce haze-forming NOx emissions, and 

EPA must consider these benefits in determining NOx BART for Colstrip Units I and 2. 

C. 	 PM 

Colstrip Units 1 and 2 are the largest emitters of PM emissions of any BART-eligible 

source in Montana. See Summary of WRAP RMC BART Modeling for Montana, Draft #5, May 

30,2007, at Table 1 (downloaded from EPA Region VIII's website at 

http://www.epa.gov/region8/air/mtregionalhaze.html). These units also use sub-standard control 

technology for particulate matter-venturi particle scrubbers. To improve visibility, EPA should 

consider requiring the installation of a baghouse or, as a second choice, an ESP, upstream of the 

existing venturi scrubber as BART at each of these units. 

The EPA's BART guidelines specify that BART should be evaluated and defined for 

both PMlO and PM2.5. See 40 C.F.R. Part 51, Appendix Y, Section IV.A. Thus, EPA must 

evaluate and define BART limits for both PM1 0 and PM2.5 at Colstrip Units 1 and 2. As part of 

the PM2.5 BART determination, EPA must impose emission limits on condensable particulate 

matter which is typically in the size range of 2.5 microns or smaller. Alternatively, EPA could 

set limits on the pollutants which form condensable PM2.5, such as sulfuric acid mist and 

ammonia, as EPA has proposed as part ofthe San Juan BART rulemaking. 76 Fed. Reg. 503-4 

(Jan. 5,2011). 

1. 	 Venturi Scrubbers are not the best system of continuous emission 

reduction. 

Venturi scrubbers are not the best system for continuous emission reduction of particulate 

matter. Venturi scrubbers are not typically included in best available control technology (BACT) 

analyses for new or modified coal-fired electric utility steam generating units. Indeed, venturi 

scrubbers have not been considered as BACT technology since the beginning ofthe prevention 

ofsignificant deterioration (PSD) permitting program ofthe Clean Air Act because such particle 

scrubbers would not ensure compliance with the PM limits ofthe NSPS standards. Specifically, 

Subpart Da ofthe NSPS sets a PM limit for coal-fired electric utility steam generating units of 

0.031b1MMBtu based on the use ofan ESP. See 44 Fed. Reg. 33581 (June 11, 1979). Thus, 

venturi scrubbers could not be used for PM control at any new electrical generating units with 

heat input of250 MMBtulhr or greater that were constructed after September 18, 1978. 40 

C.F.R. § 60.40Da(a)(2). Further, since BACT cannot be any less stringent than the NSPS, there 

could not have been any BACT determinations for coal-fired electric utility boilers that weren't 

based on either an ESP or a baghouse for PM control. Thus, there is no question that the venturi 

scrubber technology does not reflect the best system of continuous emission reduction for PM. 

8 

In its BART proposal for the Four Comers Power Plant, EPA acknowledged as much, 

stating that such venturi scrubbers have not been installed at coal-fired EGUs since the early 

1970's because of concerns over the ability ofthe venturi scrubbers to continuously meet the PM 

standards ofthe 1971 New Source Performance Standard for coal-fired boilers of 0.10 

IblMMBtu. See 75 Fed. Reg. 64231 (Oct. 19,2010). Thus, for Four Comers Units 1-3, which 

currently utilize venturi scrubbers for PM control, EPA proposed a significant reduction in PM 

emissions with a filterable PM BART emission limit of0.012 IbIMMBtu. See 75 Fed. Reg. 

64225. The Four Corners Units 1-3 currently emit filterable PM at or below 0.03 IblMMBtu. 

See 75 Fed. Reg. 64231. In comparison, Colstrip Units 1 and 2 emit filterable PM at 0.047 and 

0.058IblMMBtu, respectively, close to twice the emission rates ofFour Corners Units 1-3. See 

June 2008 Addendum to PPL Montana's Colstrip BART Report at 2-4 (Table 2-2). 

Colstrip Units 1 and 2 emit almost five times the filterable PM emission rate achieved at 

coal-fired EGUs that use baghouses (i.e., O.OllblMMBtu or lower). The Company has indicated 

that its venturi scrubbers typically remove 98% ofthe PM, and the filterable PM emission rates 

ofColstrip Units 1 and 2 are 0.047 and 0.058 IbIMMBtu, respectively. By contrast, electrostatic 

precipitators (ESPs) can achieve PM control efficiencies greater than 99%, whereas baghouses 

can achieve PM control efficiencies of 99.9% or higher. 19 

Baghouses have been installed since the 1970's and are the PM control technology of 

choice for new coal-fired EGUs because oftheir superior ability to control fine particulate 

matter. There have been several recent permits issued with BACT limits at 0.010 IblMMBtu 

based on installation of a fabric filter baghouse, including the Plant Washington permit, the 

Longleafpermit, and the Desert Rock permit issued by EPA Region IX. See Attachments 3, 4, 

I and 5. Yet even these recent, lower emission limits fail to reflect the low levels of filterable PM 

emissions that can be achieved with fabric filter baghouses. Source test data have shown that 

even lower levels of emissions can be achieved. As early as May 2004, at least 147 performance 

tests at coal-fired plants in Florida measured filterable PMlPMIO at less than 0.010 IblMMBtu 

I 

, 

, and 82 recorded PMlPMIO emissions at less than 0.005 IbIMMBtu. The lowest reported 

PMlPMIO emission rate was 0.0004IbIMMBtu.20 

Further, Matt Haber, EPA Region IX's BACT expert and current Deputy Director ofthe 

Air Division, concluded in 2002 that BACT for filterable PM at two existing PC boilers firing 

Powder River Basin coal and equipped with a baghouse was 0.006 IblMMBtu based on a 3-hour 

average and monitored via EPA Method 5 and continuously using triboelectric broken bag 

detectors.21 Although the Colstrip Units 1 and 2 are subject to BART and not BACT, these 

limits reflect the best system for continuous emission reduction and thus are equally applicable 

under BART. Therefore, there is no reason that the Colstrip units could not achieve PM 

19 See, e.g., U.S. EPA AP-42 Compilation ofEmission Factors, section 1.1.4.1. 

20 Attachment 7, Florida Source Tests compilation. 

21 Attachment 8, Matt Haber, Best Available Control Technologies/or the Baldwin Generating 

Station, Baldwin, Illinois, Expert Report, Prepared for the United States in connection with U.S. 

v.lllinois Power Company and Dynegy Midwest Generation, Inc., April 2002, p. 3. 

9 

emission rates similar to rates at new units with baghouses. Accordingly, baghouses--not 

venturi scrubbers--represent the best system of continuous particulate emission reduction that 

could be used at Colstrip Units 1 and 2. 

2. 	 The Company appears to have overestimated the costs of installing new 

particulate controls at Colstrip Units 1 and 2 when compared to the costs 

for similar controls projected in other PM BART analyses. 

Recognizing that venturi scrubbers are far from the best system of continuous particulate 

emission reduction, the Company did evaluate the addition of an ESP or a fabric filter baghouse 

at Colstrip Units 1 and 2. The Company's determination that the controls would not be cost 

effective likely resulted in an overestimate of costs and an underestimate ofbenefits from the use 

of an ESP or a baghouse. Specifically, the Company estimated the annualized cost of installing 

an ESP to meet an emission limit of 0.010 IblMMBtu to be $17,748.667, and the annualized cost 

of a baghouse to meet the same limit to be $14,451,289. See Addendum to PPL Montana's 

Colstrip BART Report, Appendix 2, Tables 6.1-2 and 6.1-4. These estimates are high in 

comparison to those provided in other PM BART analyses. 

For example, the BART analysis for Naufton Unit 3 included an evaluation of a new 

full-scale fabric filter to replace an existing ESP. 2 Naughton Unit 3 has a heat input capacity of 

3,700 MMBtuIhr and is about the size of Colstrip Units 1 and 2. The total capital cost of 

installing a full-scale fabric filter for this unit was projected to be $121,000,000, and the 

annualized cost (assuming a 7.1 % interest rate and a 20-year life) was projected to be 

$12,631,543 per year.23 

In addition, the BART analysis for Dave Johnston Unit 4 evaluated the replacement of a 

venturi particle scrubber with a new fabric filter.24 Dave Johnston Unit 4 has a heat input 

capacity of4, 1 00 MMBtulhr. The total capital cost ofinstalling a fabric filter for this unit was 

projected to be $50,073,428, and the annualized cost (assuming a 7.1 % interest rate and a 20­

year life) was projected to be $6,047,573.25 These units bum similar coal to that burned at 

Colstrip Units 1 and 2 and are similarly sized, and yet Colstrip's cost projections for an ESP or a 

baghouse are inexplicably higher. 

Based on this information, EPA must carefully evaluate-and commenters believe EPA 

should reject-the assumptions behind the Company's ESP and baghouse cost estimates because 

they are higher than the projected costs for baghouses at similar EOUs and therefore suspect. 

22 See Attachment 9, May 28,2009 WY DEQ BART Application Analysis for Pacificorp 


Naughton Power Plant, at 18. 


23 Id. at 18,21 (Tables 16 and 17). 


24 See Attachment 10, May 28, 2009 WY DEQ BART Application Analysis for Pacificorp Dave 


Johnston Power Plant, at 14. 


25 Id. at 17. 

10 

3. 	 EPA should evaluate the ability to add an ESP or baghouse upstre~ of 

the particle scrubbers at Colstrip Units 1 and 2. 

EPA should evaluate the option of installing new particulate controls-an ESP or a 

baghouse-upstream ofthe existing scrubber to act as the primary PM control device. It appears

1 that the Company only evaluated the addition of an ESP or baghouse downstream ofthe existing 

I particle scrubber. Specifically, the Company has stated that, because the exhaust from the 

venturi scrubbers is reheated above the dew point, add-on particulate controls could be feasible. 

See August 2007 BART Assessment Colstrip Generating Station at 4-9. With an ESP or 1 baghouse added upstream ofthe scrubber, the Company could then optimize the scrubber for I S02 control and likely reduce the pressure drop on the scrubber. Installation in this manner I would make the baghouse or ESP the primary particulate control device. 

I 

The addition ofPM controls upstream ofthe existing scrubber would significantly change 

the cost effectiveness calculations. The Company assumed that the baghouse or ESP would only 

remove particulate from the particulate matter emissions exiting the venturi scrubber. However, 

with controls upstream ofthe scrubber, cost effectiveness should be calculated based on the j amount of PM removed from uncontrolled levels exiting the boiler-i.e., from 0% control to I 99+% control-rather than based on the incremental benefit of additional PM control beyond 

what the particle scrubber achieves. i 

1 

Installation of a baghouse or ESP before the flue gas stream even reaches the venturi 

scrubber would be cost-effective for Colstrip Units 1 and 2. To determine the amount of 

particulate matter that will be reduced with an ESP or a baghouse installed upstream ofthe I 

scrubber, one must estimate the PM emission rate exiting the boiler, which in turn requires , knowing the ash and heat value ofthe coal burned at Colstrip Units 1 and 2. It does not appear 

that the Company submitted such info to EPA. However, information from the United States f 

Geological t Survey for the Colstrip coal mining area permits us to venture a reliable estimate of 

uncontrolled PM emissions from the Colstrip plant. Specifically, it appears that the Colstrip I 

Units bum Rosebud mine coal, which has an average ash content of 8.24% and an average 

heating value of8,767 Btullb.26 Assuming that 80% ofthe ash is emitted as flyash, that means 

the uncontrolled PM exiting Colstrip's Unit 1 and 2 boilers is emitted at a rate of approximately 

7.52 IbIMMBtu. 	 \ 

If controlled filterable PM emissions are assumed to be 0.010 IblMMBtu (the emission J 

rate that EPA requested the Company to use as a basis for evaluation), then the reduction in PM t 

emissions from an ESP or baghouse installed upstream ofthe scrubber should be based on the 

product of: 1) the annual average heat input to Colstrip Units 1 and 2, and 2) the difference in the 

uncontrolled and controlled PM emission factor. The average annual heat input over 2001-2003 

(i.e., the same years the Company used for defining base case) was 27,408,013 MMBtu for 

26 See Chapter PC, Colstrip Coalfield, Powder River Basin, Montana: Geology, Coal Quality, 

and Coal Resources, in U.S. Geological Survey Professional Paper 1625-1 at PC-2 and PC-7 

(available at http://pubs.usgs.gov/pp/pI625a/ChaptersIPC.pdf). 

11 

Colstrip Unit I and 27,548,547 MMBtu for Colstrip Unit 2.27 Based on this annual heat input 

data, a filterable PM emission limit of0.010 IblMMBtu would equate to approximately 103,000 

tons of filterable PM reduced each year at each unit. Using the Company's annualized cost 

estimates of$17,748,667 for an ESP and $14,451,289 for a baghouse, the cost effectiveness of 

installing either ofthese controls upstream ofthe scrubber would be $ 172/ton for an ESP and 

$140/ton for a baghouse. These more realistic cost effectiveness numbers show that installing an 

ESP or a baghouse upstream ofthe scrubbers at Colstrip Units 1 and 2 would be extremely cost 

effective with the baghouse being the more cost effective option. As discussed below, a 

baghouse will provide greater environmental benefits than an ESP. Thus, a baghouse is plainly 

the control technology of choice for PM BART at Colstrip. 

4. 	 Installation of a baghouse to meet a PM emission limit of0.010 IblMMBtu 

will improve visibility. 

Installation of a baghouse or an ESP would improve visibility. Modeling conducted by 

the Company for installation of a baghouse or an ESP to meet a filterable PM emission rate of 

0.010 IblMMBtu demonstrated that such PM reductions would decrease visibility impairment by 

0.048 deciviews. See June 2008 Addendum to PPL Montana's Colstrip BART Report at ES-6. 

The Company determined that the visibility improvement would not discernable and thus that 

installation of PM controls is not warranted. Id. at ES-3. 

However, the Company did not model the installation of an ESP or a baghouse upstream 

ofthe scrubber. With this arrangement, the scrubber could be optimized for S02 control, 

thereby greatly reducing visibility-impairing S02. Thus, the visibility benefits ofthe reductions 

in PM should be evaluated in combination with the benefits of upgrading and optimizing the 

scrubber for higher levels of S02 removal. 

. In addition, EPA should evaluate whether the existing particle scrubbers at Colstrip Units 

1 and 2 are causing localized visibility impacts. EP A Region IX has noted that the existing 

venturi scrubbers at Four Corners Units 1-3 cause a secondary plume that is formed in the steam 

plume and that can be seen for quite some distance from the Four Corners Power Plant.28 

According to EPA, the use of a venturi scrubber at these units causes visibility impairment in the 

region around the plant. EPA states that the secondary ~lume formed at Four Corners Units 1-3 

could likely be due to the poor control of fine particles. 9 It is very plausible that the same 

problems occur with the use of a venturi scrubber at Colstrip Units 1 and 2. 

The installation of a baghouse upstream ofthe venturi scrubber could alleviate any 

problems with secondary plumes. Again, a baghouse is the superior PM technology for 

27 Based on data available on EPA's Clean Air Markets Database. 

28 EPA's Technical Support Document, Proposed Rule: Source Specific Federal Implementation 

Plan for Implementing Best Available Retrofit Technology at Four Corners Power Plant: Navajo 

Nation, at 81. (Attachment 11). 

29 Id. 

12 

removing fine particulate matter. The filtration media determines the control efficiency of a 

baghouse for very small particles. Filtration media are available that allow 99.99% ofthe PM2.5 

fraction to be removed. These include Daikin's AMIREXTM, PTFE membrane filters30 and W.L. 

Gore's L3650.31 See summary of U.S. EPA's ETV test results in Attachment 10.32 A bag leak 

detection system also greatly helps in reducing and eliminating spikes in PM emissions. Thus, if 

the venturi scrubbers at Colstrip Units 1 and 2 cause a secondary plume problem as occurs at 

Four Comers Units 1-3, the installation of a baghouse upstream of the scrubber to serve as the 

primary particulate control device could help address this issue. 

Further, as discussed above, use of a baghouse at Units 1 and 2 will likely reduce PM 

emissions lower than 0.010 IbIMMBtu. The Company's modeling of a filterable PM emission 

rate of 0.0 1 0 IblMMBtu does not reflect the lower emission rates which will likely occur with the 

use of a baghouse. 

f 

For all ofthese reasons, in determining whether it is appropriate to require new PM 

controls to meet BART, EPA cannot and should not rely on the Company's modeling, which is 

based only on lowering the PM emission rate to 0.010 IblMMBtu. The installation of a baghouse 

upstream ofthe existing venturi scrubber would likely have myriad benefits for visibility that go 

beyond attainment of a 0.010 IblMMBtu emission limit. The visibility impacts analysis for PM I

BART must consider all ofthe benefits that could be obtained from replacing the particle 1 

scrubber with an ESP or, preferably, a baghouse, and then optimizing the scrubber for S02 

removal. I

f 5. 	 The energy and environmental impacts analyses weigh strongly in favor of 

installation ofbaghouses at Colstrip Units 1 and 2. f 

Additional air-quality related factors support additional PM controls for Colstrip Units 1 l

I 

f and 2. 

a. 	 A baghouse will result in the greatest reduction in mercury i 

I 

l emissions and is likely necessary to meet mercury limits. 

It is very likely that a baghouse will be required to meet either Montana limits or the 

forthcoming maximum achievable control technology (MACT) standards for existing electrical 

generating steam generating units (EGUs). In May 2011, EPA published its proposed EGU f 

r 

30 McIlvaine Hot Topic Hour, Filter Media Selection for Coal-Fired Boilers, September 13, 

2007, Presentation by Todd Brown, Daikin America, Inc. Attachment 12. Voice recording 

available online to subscribers ofMcIlvaine Power Plant Knowledge System and available for 

purchase. 

31 USEPA, ETV Joint Verification Statement, Baghouse Filtration Products, W.L. Gore & 

Associates, L3650, Attachment 13 (http://epa.gov/etv/pubs/600etv06042s.pdf). 

32 Fabric Filtration Media are certified by the U.S. EPA Environmental Technology Verification 

Program using the "Generic Verification Protocol for Baghouse Filtration Products" to Achieve 

99.99% Removal ofPM2.5. 

13 

MACT standards, which will make the Colstrip units subject to a mercury emission limit of 1.2 

Ib/TBtu.33 

It is well known that coal-fired boilers equipped with baghouses achieve better control of 

mercury than those equipped with ESPs. Mercury control at bituminous coal-fired boilers with a 

cold-side ESP and a wet scrubber averaged 81% as compared to 98% control achieved with a I baghouse and wet scrubber.34 And boilers equipped with baghouses that use carbon injection 

can achieve higher levels ofmercury control with a lower carbon injection rate as compared to 

boilers equipped only with ESPs.35 

\ 

I 

! When coal is burned in a boiler, the mercury in the coal is volatilized and converted to 

elemental mercury vapor (Hgo). Hgo is insoluble in water and therefore must be adsorbed by a 

sorbent or converted to a soluble fonn so it can be captured in a wet scrubber or another J 

particulate control device such as a baghouse. According to EPA, the fonn ofmercury most I easily removed is HgCh and the fonnation ofthis compound is dependent on how much chlorine 

is in the coal-less chlorine equates to less formation of HgCh.36 Thus, EGUs that bum eastern 

bituminous coal with high chlorine levels often achieve high levels ofmercury control via 

existing S02 scrubbers and PM controls, while EGUs burning low chlorine coal, such as the 

northern Powder River Basin subbituminous coal used at Colstrip, often achieve lower control of 

mercury via the S02 and PM controls. I 

Compared to a particle scrubber or a dry ESP, a fabric filter baghouse provides additional 

opportunities for the mercury to adhere to the unburned carbon particles in the fly ash as the flue I 

t gas moves through the filter cake on the bags. Activated carbon, a sorbent which adsorbs i

mercury, is typically much more effective when a bapouse rather than an ESP is used, because 

the activated carbon becomes part ofthe filter cake.3 Thus, vendors have developed the 

Toxecon pollution control scheme to assist with mercury removal at units with existing ESPs, 

which involves adding a downstream polishing baghouse (or integrating a baghouse with the 

ESP) along with activated carbon injection to improve mercury removal. 

33 76 Fed. Reg. 24976 (May 3, 2011). See also May 18, 2011 Memo with Subject "National 

Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable Control 

Technology (MACT) Floor Analysis for Coal- and Oil-Fired Electric Utility Steam Generating 

Units - REVISED," available at http://www.epa.gov/ttnlatw/utilitY/utilitypg.html, in which EPA 

revised the existing EGU MACT floor detennination from 1.0 Ib/TBtu to 1.2Ib/TBtu. 

34 See Attachment 14, US EPA, Perfonnance and Cost ofMercury and Multi-Pollutant Emission 

Control Technology Applications on Electric Utility Boilers, EPA-600/R03-110 (Oct. 2003) at 7. 

35 See, e.g., http://hamon-researchcottrell.comltech_ff. 

36 See Attachment 14, US EPA, Perfonnance and Cost ofMercury and Multi-Pollutant Emission 

Control Technology Applications on Electric Utility Boilers, EPA-600/R03-110 (Oct. 2003) at 5. 

37 Id. at 8-9. 

14 
Therefore, use of a fabric filter baghouse at Colstrip Units I and 2 will not only greatly 

reduce particulate, but will also provide for the greatest control ofmercury pollution from these 

units. 

The greater reductions in mercury achievable with installation ofbaghouses at Colstrip 

Units I and 2 could help address mercury deposition levels in eastern Montana. Studies 

sponsored by EPA demonstrate that up to 70 percent oflocal deposition ofmercury from power 

plants and industrial sources can be linked to local sources during wet deposition events. 3 Fish 

consumption advisories due to mercury contamination have been issued for Castlerock Lake in 

the vicinity ofColstrip as well as for the Bighorn reservoir in southeastern Montana.39 The 

installation ofbaghouses to meet BART for PM at Colstrip Units I and 2 thus could reduce the 

levels mercury deposited in the region from these units. 

i 

b. 	 New PM controls will be needed to meet EPA's proposed PM limit J 

for non-mercury metal HAPs. 

,

f 

Updated PM controls will also be necessary at Colstrip Units 1 and 2 to meet EPA's j 

proposed PM limit for non-mercury metal HAPs. Specifically, EPA has proposed a PM limit of I 

I 0.03 IblMMBtu as a surrogate for non-mercury metal hazardous air pollutants (HAPs). EPA's 

proposed limit is a limit on total particulate matter (filterable plus condensable PM). Colstrip t 

Units 1 and 2 already emit filterable PM at rates close to twice that ofthe EPA's proposed 0.03 

IblMMBtu total PM limit (at 0.047 and 0.058IbIMMBtu, respectively40). Consequently, 

improved PM controls (and also likely improved S02 controls to reduce condensable PM) will I

be necessary for Colstrip Units 1 and 2 to meet a total PM MACT limit of0.03 IbIMMBtu. As I. 

I 

previously stated, a baghouse is typically more effective in removing PM than an ESP. This is 

especially true for fine particulate matter.41 In evaluating BACT for Desert Rock, EPA Region 9 

stated that baghouses are the top-rated control technology and that ESPs are not considered the 

top-rated PM control because they do not control fine particulate as well as baghouses and 

because they are not generally capable of additional control ofother pollutants such as acid gases 

and mercury.42 

Not only can a baghouse achieve lower filterable PM emission rates, but a baghouse also 

removes more sulfuric acid mist which is a condensable particulate. According to EPRI's 

"Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," a cold-side ESP for a 

38 Gerald Keeler, Matthew Landis, et al., Sources ofMercury Wet Deposition in Eastern Ohio, 

USA, 40 EnvtI. Sci. & Tech. 5874-5881 (Sept. 2006). 

39 See EPA' National Listing ofFish Consumption Advisories at 

http://oaspub.epa.gov /nlfwalnlfwa.advrpt. 

40 See June 2008 Addendum to PPL Montana's Colstrip BART Report at 2-4 (Table 2-2). 

41 See, e.g., the Institute ofClean Air Companies' information on particulate controls at 

http://www.icac.comli4a1pages/index.cfm?pageid=3398. 

42 See US EPA Region 9, Ambient Air Impact Report for Desert Rock Energy Project at 26. 

(Attachment 15). 

15 
plant burning subbituminous coal will remove approximately 38% ofthe sulfuric acid mist while 

a baghouse will remove 90%.43 

Furthermore, the BACT limits for fluorides, another condensable particulate, are 

typically the lowest at units that use baghouses along with wet scrubbers. In addition, baghouses I 

provide improved control of fine particulates (Le., PM2.5) as compared to ESPs, as discussed 

above. 

In addition, if a baghouse was installed upstream of the scrubbers at Colstrip Units 1 and I 

2, then the scrubber could be more readily optimized for S02 removal which would then result 

in significant reductions in condensable PM emissions. I 

New PM controls will be required to meet the PM limit ofthe proposed EGU MACT 

rule, and a baghouse will likely be the control technology needed to meet the total PM limit of I 

0.03IbIMMBtu. A baghouse has superior ability to remove sulfuric acid mist, fluorides, and fine 

particulate matter, and its use allows the scrubber to be optimized for S02 control. In its f 

f regulatory impact analysis for the proposed EGU MACT rule, EPA assumed that many EGUs 

would need to be retrofitted with baghouses to meet the total PM limit.44 And, it must be noted t 

that the compliance timeframe of the EGU MACT rule will be similar to that for BART. l Specifically, under a consent decree, EPA is required to finalize its EGU MACT rule by 

November 16,2011. Under the proposed MACT rule (and as required by the Clean Air Act), 

existing sources will be required to comply with the MACT rule within three years of 

promulgation or by approximately the end of2014. The Company has a similar timeframe in 

which to meet BART requirements. These other requirements should be taken into account in 

evaluating BART for PM at Colstrip Units 1 and 2. 

In sum, installation of new PM control devices at Colstrip Units 1 and 2 is necessary and 

justified under the BART requirements ofthe regional haze rule. Installation of a baghouse or an 

ESP upstream ofthe scrubber at each Colstrip unit is very cost effective, with installation of a 

baghouse being the most cost effective at $140lton compared to $172/ton for an ESP. A 

baghouse is a superior particulate control device to an ESP because it is the best system of 

continuous PM emission reduction, and a baghouse provides better ability to control fine 

particulate matter and acid gases. Further, the installation of a baghouse typically provides for 

much higher mercury removal than an ESP. Thus, installation ofbaghouses at Colstrip Units 1 

and 2 will very likely be required to meet MACT. Installing a baghouse upstream ofthe existing 

scrubbers will allow the company to upgrade and optimize the scrubber for improved S02 

removal, which will result in significant benefits to visibility (discussed further in the S02 

comments ofthis letter). 

43 See Attachment 16, EPRl's "Estimating Total Sulfuric Acid Emissions from Stationary Power 

Plants," Version 2010a, Table 4-4 at 4-20. The F2 factors in the table represent the fraction of 

SAM in the flue gas after the ESP or baghouse, so the percent removal can be determined by 

subtracting the F2 factors from 1. 

44 See Attachment 17, EPA, Regulatory Impact Analysis ofthe Proposed Toxics Rule: Final 

Report, March 2011, at 8-5, and also at 7-8. 

16 

D. 	 S02 

Existing S02 controls for Colstrip Units 1 and 2 are also sub-standard. According to the 

Company, these units are currently removing approximately 75% S02 emissions with the 

existing venturi scrubbers and the units' S02 emission rates are typically 0.40 IblMMBtu on a 

30-day rolling average. See August 2007 BART Assessment Colstrip Generating Station at 4-15 

to 4-16. This level ofS02 control fails to reflect the best system of continuous S02 emission 

reduction that can be achieved at the Colstrip Units 1 and 2. Additional S02 controls~, the 

addition of a lime-injection system, scrubber upgrades, or scrubber replacements-would 

improve visibility and are cost effective. 

1. 	 The existing scrubbers are not the best system of continuous S02 emission 

reduction 

According to the available information on the coal used at Colstrip, it appears that the I

I 

Company overstated the S02 removal efficiency being achieved with the venturi scrubbers at I 

Colstrip Units 1 and 2. The Company has indicated that the Powder River Basin coal burned at 

Colstrip has a sulfur content of 0.7%. See Addendum to Montana PPL's Colstrip BART Report I

at 2-1. According to data in a USGS Report, Rosebud mine coal, which Colstrip bums, has an 

average sulfur content of 0.65% and an average heating value of8,767 Btu/lb.45 This means that 

the average uncontrolled S02 emissions based on sulfur in the coal range from 1.5 to 1.6 

the 

IblMMBtu. 

sulfur in 

However, 

the coal falls 

this 

out 

does 

in 

not 

the bottom 

reflect the 

ash 

amount 

ofthe boiler. 

ofS02 

According 

going to the 

to 

scrubber, 

EPA, "[o]n 

as 

average, 

some of I

about 95 percent ofthe sulfur present in bituminous coal will be emitted as faseous SOx, 

whereas somewhat less will be emitted when subbituminous coal is fired.'.4 Using EPA's AP42 emission factors for subbituminous coal-fired boilers like Colstrip Units 1 and 2, the range of 

uncontrolled S02 emissions exiting the boiler, based on coal with sulfur content of0.65%-0.70% 

and heat value of8,767 Btu/lb, are 1.30 to 1.40 IbIMMBtu.47 Based on this range, the existing 

scrubbers at Colstrip Units 1 and 2 are only achieving 69 to 71 % S02 removal on average-not 

the 75-80% control stated by the Company. This is a substandard level of S02 removal for a 

coal-fired boiler and fails to reflect the best system ofcontinuous S02 emission reductions that 

could be achieved at Colstrip Units I and 2. 

45 See Chapter PC, Colstrip Coalfield, Powder River Basin, Montana: Geology, Coal Quality, 

and Coal Resources, in U.S. Geological Survey Professional Paper 1625-1 at PC-2 and PC-7 

(available at http://pubs.usgs.gov/pp/pI625a1ChapterslPC.pdf). 

46 See EPA's AP=42, Chapter 1.1 Bituminous and Subbituminous Coal Combustion, at 1.1-3. 

47 See AP-42, Table 1.1-3, S02 emission factor in Ib/ton of coal burned of 35 x sulfur content for 

tangentially-fired subbituminous coal-fired units. 

17 
j 

2. 	 Scrubber upgrades should be required to achieve lower S02 limits. r 

~ 

) Based on the Company's supplemental BART analysis, the S02 removal efficiency of 

the existing scrubbers at Colstrip Units 1 and 2 could be improved with the injection of lime or 

I 

! 

f limestone, the sorbents typically used for S02 control in scrubbers. The Colstrip scrubbers 

achieve approximately 70% S02 removal from the alkalinity ofthe fly ash in the flue gas. The 

BART Guidelines require evaluation ofscrubber upgrades 

Evaluation ofthe installation ofa lime injection system falls squarely under the BART 

Guidelines' direction to evaluate options that would" improve the system's overall removal 

efficiency." 40 C.F.R. Part 51, Subpart Y, Section IV.E.4. There is no basis for the Company's t 

claim that the BART guidelines do not require evaluation of adding a lime injection system to a 

scrubber that is achieving at least 50% S02 removal. 

r 

The Company has expressed concerns with lime injection that, due to lime scaling and 	 t 

the fact that the scrubber has no spare scrubber module, the scrubber module will need to be I 

taken offline more frequently for maintenance. See, e.g., June 2008 Addendum to PPL 

Montaha's Colstrip BART Report at ES-2. While scaling is a concern with any lime or 

limestone based wet scrubber, and techniques are available to deal with this issue, one option to 

deal with this issue is the use ofmagnesium-enhanced lime. Magnesium enhanced lime has been 

used in FGD systems since the 1970's, and it has been capable ofhigh S02 removal with little 

scaling, thus providing for a high availability.48 According to vendor literature on this 

technology, magnesium-enhanced lime scrubbers are capable ofvery high S02 removal 

efficiencies in excess of 95%.49 It is further significant that Reid Gardner Units 1-3 do not have 

spare absorber modules, and these units will be subject to a 0.15 IblMMBtu S02 BART limit 

(and are emitting S02 well below that limit) as discussed above, 50 

Additional upgrades to the scrubbers beyond the addition oflime injection could be made 

to further improve S02 removal. Those upgrades could include a redesign ofthe spray headers 

or nozzle configuration, improvements to scrubber auxiliary system equipment, other physical 

changes to improve liquid-to-gas contact, and changes in scrubber chemistry to improve S02 

removal. Other changes include improving gas flow distribution through ductwork changes, 

improving spray level coverage, adding frothing trays, increasing liquid to gas ratio (increasing 

recycle flow), and injecting dibasic acid.51 While the Company purportedly considered some 

48 See Roden, Bob et aI., New Magnesium-Enhanced Lime FGD Process, Carmeuse-North 

America Technology Center, Pittsburgh, PA (Attachment 22). 

49 Id.; see also Nolan, Paul S., Babcock & Wilcox Co., Flue Gas Desulfurization Technologies 

for Coal-Fired Power Plants, presented at Coal-Tech 2000 International Conference, November 

13-14,2000, Jakarta, Indonesia, at 3. Attachment 23. 

50 See Weilert, Carl & Emily Meyer, Bums & McDonnell, Utility FGD Design Trends at 22 

(Attachment 29). 

51 See Carstens, Andrew J. et aI., Performance Upgrades for Low-Sulfur Wet Scrubbers, Sargent 

& Lundy and CPS Energy, Paper # 134, at 6-12 (Attachment 30). 

18 
scrubber changes such as installation of liquid distribution rings and installation of perforated 

trays, there are numerous other options that should have been considered to improve liquid to gas 

contact in the scrubber. Ifan ESP or baghouse was installed upstream ofthe scrubber and the 

scrubber was no longer the primary PM control device, physical design changes could be made 

that could then improve the S02 removal efficiency and operating parameters ofthe scrubber. 

For example, at the Reid Gardner units, the venturi section will be opened up to improve draft 

flow. If that was done at the Colstrip scrubbers, it could allow for installation of additional trays 

or physical changes to improve scrubber to gas contact which would improve overall efficiency. 

Lower S02 limits should be achievable with scrubber upgrades. The Company only 

evaluated reducing S02 to an emission rate of 0.15 IblMMBtu in evaluating S02 BART. 

However, based on review ofthe S02 emission rates achieved at Colstrip Units 3 and 4 as well 

as the Reid Gardner units, Colstrip Units 1 and 2 should be able to achieve even lower S02 

emission rates with upgrades to the scrubbers. 

Colstrip Units 3 and 4 have particle/S02 scrubbers that rely on fly ash and lime injection. 

According to the company, these units achieve 95% S02 control and S02 emission rates of 0.08 

IblMMBtu. See January 31,2011 submittal to EPA from PPL Montana regarding Colstrip Units 

3 and 4, Ex. 2 at 2. The Reid Gardner units have installed baghouses upstream of their existing 

particle/S02 scrubber and also have average S02 emission rates of0.08 IblMMBtu or less.52 As 

previously stated, the Reid Gardner units do not have spare scrubber modules, although Colstrip 

Units 3 and 4 do. Based on the available info for these similar units, Colstrip Units 1 and 2 

should be able to achieve S02 emission rates much lower than 0.15 IblMMBtu. 

Even if the Company claims a spare scrubber module would be needed to consistently 

achieve lower S02 emission rates, it must be noted that EPA's BART guidelines specifically 

provide for the evaluation ofoptions to improve scrubber availability including by "increasing 

auxiliary equipment redundancy." 40 C.F.R. Part 51, Appendix Y, Section IV.E.4. Thus, it is 

entirely appropriate and required under the EPA's BART guidelines to evaluate the installation 

of a spare scrubber module to meet lower S02 emission limits as BART. Given that a 0.15 

IblMMBtu emission limit only reflects 89% S02 removal across the scrubber, the Company 

must be required to evaluate all options that would enable the Colstrip units to achieve the best 

continuous level ofS02 emission reductions as BART. EPA should consider scrubber upgrades, 

including the addition of a the lime injection system, for lowering S02 emissions from Colstrip 

Units 1 and 2. 

3. 	 The Company has demonstrated that scrubber upgrades to meet S02 

BART are extremely cost effective. 

As the Company demonstrated, it is very cost effective to add a lime injection system to 

improve S02 control at Colstrip Units 1 and 2 to meet an S02 emission limit of 0.15 IbIMMBtu. 

The Company determined that with a lime injection system, it could continually meet an S02 

52 See Attachment 19. 

19 

emission limit of 0.15 IbIMMBtu53 at a cost of $486/ton of S02 removed. See June 2008 

Addendum to PPL Montana's Colstrip BART Report at 4-1 to 4-2. This is well under the 

median cost per ton for S02 controls that have been required as BART as part of state regional 

haze plans. Specifically, the median cost ofS02 controls to meet BART is $1,571/ton ofS02 

removed and the average cost is $1,967/ton ofS02 removed. See National Park Service's 

spreadsheet entitled "EGUs with Proposed BART S02 Controls," Attachment 18. EPA recently 

proposed to require several EGUs in Oklahoma to install new S02 controls to meet a BART 

emission limit of 0.06 IbIMMBtu, finding new controls to be cost effective at costs ranging from 

$1,291 to $2,366 per ton ofS02 removed. 76 Fed. Reg. 16183 (Mar. 22,2011) (tables 4 and 6). 

The Company's projected costs to upgrade the scrubbers at Colstrip Units 1 and 2 of $486/ton of 

S02 removed are quite reasonable when compared to the costs other EGUs have to incur to meet 

BART. I 

Upgrades to the current scrubbers are well-justified even ifthe Company installs PM 

controls upstream. If an ESP or baghouse was installed upstream ofthe scrubber, then the 

amount of fly ash entering the wet scrubber would be significantly reduced and thus more lime 

f 

I 

! 

would be needed to achieve the same level ofS02 control. More lime will result in higher costs. 

However, that fact does not mean that the conversion ofthe current scrubber to a lime-based 

scrubber would not be cost effective. Even ifthe costs ofthe conversion ofthe current scrubbers 

to lime-based scrubbers were tripled or quadrupled (i.e., $1,458/ton to $1,944/ton) due to the 

need for additional lime, the cost per ton of S02 removed to meet a 0.15 IblMMBtu S02 

emission limit would be less than the average costs that are being required to meet S02 BART at 

similar coal-fired EGUs. 

Even a tripling or quadrupling ofthe total annual costs given in Table 4.1-4 ofPPL 

Montana's June 2008 Addendum to the Colstrip BART Report would equate to cost 

effectiveness values of$I,458 to $1,944 per ton ofS02 removed. This is less than the average 

cost for EGUs to meet BART controls of $1 ,967/ton removed, and it is within range ofcosts for 

scrubber upgrades that are being required as BART. For example, Jim Bridger Units 1-4 are all 

required to upgrade scrubbers to meet an S02 emission limit of0.15 IblMMBtu, and the cost 

effectiveness ofthese controls was projected to be $620-729/ton of S02 removed. Id. Laramie 

River Units 1 and 3 are required to upgrade scrubbers to meet a 0.15 IblMMBtu limit and the 

cost effectiveness ofthese controls is estimated to be $1,564-$1,571/ton ofS02 removed. Id. 

The installation ofbaghouses u~stream of scrubbers at other facilities has not impacted 

their ability to meet low levels of S02. 4 Several EGUs with existing partic1e/S02 scrubbers 

53 Although PPL Montana asserted that the scrubbers could achieve 91 % S02 removal and a 

0.15 IblMMBtu emission limit, this removal efficiency appears to be based on the uncontrolled 

S02 emissions in the coal rather than the uncontrolled S02 emission rate at the inlet to the 

scrubber. An S02 emission limit of 0.15 IblMMBtu reflects only 88% to 89% S02 removal 

across the scrubber based on current coal characteristics at Colstrip. 

54 Unfortunately, the Nevada Division ofEnvironmental Protection proposed an S02 BART 

emission limit for these units of 0.15 IblMMBtu as a limit that could be continuously met with a 

reasonable margin ofsafety, see Revised Nevada Division ofEnvironmental Protection BART 

20 
_.. _

have or soon will install baghouses upstream of the scrubber and will convert the existing 

PM/S02 scrubber into a scrubber focused solely on S02 removal For example, Units 1 3 at 

the Reid Gardner power plant each have venturi scrubbers that are also being used as wet soda 

ash S02 scrubbers. These units added baghouses to meet BART in 2008 and 2009. A review of 

2010 S02 emissions data from EPA's Clean Air Markets Database shows that the Reid Gardner 

Units 1-3 are meeting monthly average S02 emission rates of 0.08 IblMMBtu or less, with 0.06 

IblMMBtu being met on average55. 

At Cholla Unit 2, which is also equipped with venturi particle scrubbers with lime 

reagent used for S02 control, a baghouse is planned to meet PM BART requirements. The 

scrubber at this unit will benefit from the reduction in particulate loading which will improve 

S02 removal. Arizona Department ofEnvironmental Quality (AZDEQ) has indicated that it will 

propose an S02 BART limit for Cholla Unit 2 of 0.15 Ib1MMBtu.56 

At Sherburne County Units 1 and 2 which are both equipped with venturi scrubbers with 

integrated wet ESPs, Minnesota Power proposed to upgrade the scrubbers to meet BART to 

achieve an S02 emission limit of0.12 IblMMBtu based on the retrofitting of the existing 

scrubbers with sparger tubes and lime injection.57 The cost effectiveness for those scrubber 

upgrades were projected to be $237 to 238/ton ofS02 removed. See National Park Service's 

spreadsheet entitled "EGUs with Proposed BART S02 Controls," Attachment 18. 

Given that other similar EGUs are installing baghouses and converting existing 

particle/S02 scrubbers to be focused primarily on S02 to meet BART, the Colstrip units should 

be able to do the same. Even if a baghouse or ESP is installed upstream and the Company have 

to add more lime and/or make additional physical changes to improve S02 control, it will likely 

still be cost effective to upgrade the scrubber to achieve an S02 emission limit of 0.15 

IblMMBtu ifnot lower. 

4. 	 EPA should consider the option of requiring the Colstrip Units to replace 

the wet scrubbers with new wet or dry scrubbers to meet S02 BART. 

The Company has claimed that it is not required to evaluate the option ofinstalling new 

S02 controls because its scrubbers are achieving at least 50% S02 removal. This is incorrect as I 

! Determination Review ofNV Energy's Reid Gardner Energy Station Units 1,2, and 3, Revised ! October 22, 2009, at 8 (Attachment 20), which provides too high of a compliance margin than 

appears necessary based on current S02 data and which does not appear to comply with a proper 

BART determination. 

55 See Attachment 19, Spreadsheet with monthly emissions data for Reid Gardner Units 1-3 from 

2010, downloaded from EPA's Clean Air Markets Database. 

56 See "Arizona Regional Haze BART Summary" available at 

http://www.azdeq.gov/environ/air/haze/index.html. 

57 See Best Available Retrofit Technology Analysis for Sherburne County Generating Plant I 

Units 1 and 2, October 25, 2006 at 27 (Attachment 21). I 

21 

I 

, 
EPA's BART guidelines do not preclude evaluation ofreplacement flue gas desulfurization 

equipment. If the Company claims it cannot upgrade its existing scrubbers to meet high levels of 

S02 control, then the option of entirely new S02 scrubbers at each unit should be evaluated as 

BART. New scrubbers could provide significant benefits in terms of greatly reduced S02 

emissions compared to the O.lS IblMMBtu emission limit evaluated in the Company's S02 

BART analysis. 

Wet scrubbers can achieve 99% removal efficiency. A prime example is the Chiyoda 

CT-12l FGD. Vendor information for this technology indicates that this scrubber has achieved 

98-99% S02 removal even with low sulfur coa1.58 For example, the Chiyoda's bubbling jet 

reactor has consistently achieved >99% S02 removal during long-term operation at the ShinkoKobe power plant in Japan. This facility consists oftwo 100-MW coal-fired utility boilers. The 

wet FGD was designed to achieve 0.0141b S02IMMBtu (9 ppmv at 3% oxygen) on an 

instantaneous basis and has consistently exceeded this level of control while treating gases with 

inlet S02 concentrations of 1.18IbIMMBtu.59 This technology has been guaranteed by Chiyoda 

to achieve 99% S02 removal on three coal-fired boilers in Japan.60 It also has been demonstrated 

in the U.S. at the University ofIllinois's Abbott power plant, Geor~a Power's Plant Yates61 , I 

Dayton Power & Light's Killen Unit 2,62 and Plant Bowen Unit 3. It has also been licensed 

for installation on several additional units in the US, including the other three units at Plant t 

Bowen in Georgia, the other units at Dayton Power & Light's Killen plant, Dayton Power & 

Light's Stuart plant, and AEP's Big Sandy Unit 2, Conesville Unit 4, Cardinal Units 1 and 2, and 

Kyger Creek, among others.64 Black & Veatch and Southern Company are both U.S. licensees. 

Further, this technology also has shown to be very effective in removing fine particulates, 

oxidized and elemental mercury, and acid gases, and the technology uses less energy compared 

58 See Black & Veatch vendor brochure on CT-121, Attachment 24. 

59 Yasuhiko Shimogama, Hirokazu Yasuda, Naohiro Kaji, Fumiaki Tanaka, and David K. 

Harris, Commercial Experience ofthe CT-121 FGD Plant for 100 MW Shinko-Kobe Electric 

Power Plant, Paper No. 21, presented at MEGA Symposium, Air & Waste Management 

Association, May 19-22, 2003, Attachment 2S. 

60 CT-121 FGD Process - Jet Bubbling Reactor, http://www.bwe.dkJfgd-ct121.html. 

61 Emission-control Technologies Continue to Clear the Air, Power, May/June 2002. 

62 See Black & Veatch, First Black&VeatchlChiyoda Wet Flue Gas Desulfurization System in 

North America Successfully Goes Operational, available at 

http://www.bv.comIDownloadslResourceslBrochures/rsrc _ ENR _First W etFlueGasDesulfurizatio 

n.pdf. 

63 Blankinship, Steve, Go Take a Bath, Power Engineering, October 2008, available at 

http://pepei.pennnet.comldisplay_article/342991/6/ARTCUnonelnone/l/Go-Take-a-Bathl. 

64 Chiyoda Licenses Its Flue Gas Desulfurization Technology in USA Newly for S Coal-Fired 

Generation Units, Press Release, May 2, 200S (http://www.chiyodacorp.comlnews/enl200S/post_S3.html); Chiyoda Licenses its Flue Gas Desulfurization Process in 

USA for Georgia Power Owned 4 FGD Units, January 26, 200S (http://www.chiyodacorp.comlnews/enl200S/post _11.html). 

22 

to traditional wet scrubbers. Mitsubishi, a vendor ofscrubber systems, reports it has guaranteed 

S02 removal efficiencies up to 99.8 percent, including for coal-fired boilers.65, 66,67 

Ifthe Company installed new state-of-the-art wet scrubbers at Colstrip Units 1 and 2, I S02 emission limits should be based on no less than 99% S02 removal. Ninety-nine percent 	 ! 

I S02 removal would equate to an emission limit ofless than 0.014IblMMBtu. This would 

equate to S02 reductions of approximately 6,128 tons at each unit, compared to the company's 

projected 3,969 tpy S02 reduction with the addition oflime to the existing wet scrubbers to meet 

a 0.15 IblMMBtu limit68 • \ 

A new state-of-the-art dry scrubber can achieve up to 95% S02 removal efficiency. 69 

Dry scrubbers are commonly used at low sulfur subbituminous coal-fired units for S02 control. 

With 95% control, the Colstrip units could meet S02 emission limits of0.08 IblMMBtu. This 

would equate to S02 reductions of 5,081 tons per year at each unit. Conversion to dry scrubbing 

,

f would have a significant co-benefit oflimiting the wet waste stream that is disposed of in on-site 

r holding ponds that leak and have caused well-documented groundwater contamination.7o 

l 

f Either a new wet scrubber or a new dry scrubber would provide for significant further ~ 

reductions beyond the S02 reductions projected by the Company with upgrades to the scrubbers I 

to achieve a 0.15 IblMMBtu S02limit. Such new controls have been required as BART for \ 

S02. For example, Dave Johnston Unit 4 has an existing venturi scrubber that is designed to 

achieve 60% S02 remova1.71 This unit is being required to install a new dry scrubber and a 

65 Jonas S. Klingspor, Kiyoshi Okazoe, Tetsu Ushiku, and George Munson, High Efficiency 

Double Contact Flow Scrubber for the U.S. FGD Market, Paper No. 135 presented at MEGA 

Symposium, Air & Waste Management Association, May 19-22,2003, p.8, Table 4, Attachment 

26. 	 r 

66 Yoshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, Commercial Experience and ActualPlant-Scale Test Facility ofMHI Single Tower FGD, Attachment 27. 

67 Mitsubishi High S02 Removal Experience, Attachment 28. 

68 Projected emission reductions were calculated based on the average heat input capacity per 

boiler of 3,940 MMBtuJhr and an assumed 92% design capacity factor. See June 2008 

Addendum to PPL Montana's Colstrip BART Report, Ex. 2, Table 4.1-3. This table includes 

PPL Montana's projected S02 emission reductions under a 0.15 IblMMBtu emission limit. 

69 See discussion ofAcid Gas/S02 Control Technologies on the Institute ofClean Air 

Companies website at http://www.icac.comli4a1pages/index.cfm?pageid=3401. 

70 Wyoming's BART analysis for the Dave Johnston power plant in Wyoming would require 

PacifiCorp to replace the existing Unit 4 wet venturi scrubber with a full-scale fabric filter for 

PM control. See Attachment 10 at 49. And although not adopted by Wyoming, PacifiCorp 

proposed a fabric filter and dry FGD in place ofthe wet venturi scrubber as BART for S02. Id. 

A similar conversion to dry handling should also be feasible for Colstrip. I 

71 See Weilert, Carl & Emily Meyer, Burns & McDonnell, Utility FGD Design Trends at 11 	 I 

~. 

! (Attachment 29). 

t 

! 

l 

£ 

23 

baghouse to meet BART for S02 and PM, and the cost for S02 control to meet a 0.151b1MMBtu 

limit was projected to be $4,743/ton ofS02 removed. See National Park Service's spreadsheet 

entitled "EGUs with Proposed BART S02 Controls," Attachment 18. This new scrubber at a 

unit with an existing scrubber has been determined to be cost effective as BART for S02, and 

thus the Colstrip units should not be exempt from such an analysis to determine ifinstallation of 

a new scrubber is necessary to meet BART requirements. 

In summary, EPA should evaluate the addition ofnew scrubbers to ensure that Colstrip 

Units 1 and 2 are equipped with the best continuous system ofS02 emission reduction. Ifthe 

costs ofcontrol are reasonable when compared to the costs of control that other EGUs are 

required to incur to meet BART requirements, then such controls should be required as BART. 

There is no question that such controls will improve visibility in Montana's Class I areas, given 

that the Company already showed that just meeting an S02 emission limit of0.15 IblMMBtu 

based on lime injection to the scrubbers would provide for noticeable improvement in visibility 

as is discussed below. 

5. 	 Upgraded S02 controls will provide noticeable benefits to regional haze 

in Class I areas. 

Scrubber upgrades or replacement would significantly improve visibility. The Company 

modeled the visibility improvements expected from upgrades to the scrubber to comply with 

what they claimed to be 91% control, an emission limit ofO.15lblMMBtu (which more likely 

reflects 89% S02 removal across the scrubber as discussed above). The Company's modeling 

found that there would be an improvement in the 98th percentile visibility impacts of0.544 

deciviews. See June 2008 Addendum to PPL Montana's Colstrip BART Report at 4-3. A 0.5 

deciview impact is considered a "noticeable change" and is the threshold EPA has identified for 

determining whether an existing source contributes to visibility impairment in a Class I area. 40 

C.F.R. Part 51, Appendix Y, Section UI.A.I. Thus, the improvement to visibility ifthe scrubbers 

at the Colstrip Units 1 and 2 were upgraded to meet a 0.15 IblMMBtu S02 emission limit would 

provide a noticeable benefit to visibility. Consequently, the Company has shown it can cost 

effectively upgrade the scrubbers to achieve an S02 limit of0.15 IblMMBtu and that it will 

noticeably improve visibility. Based on the information we provided above, we think it is likely 

the units can reduce S02 even further while still being cost effective, and such additional S02 

emission reductions will only further improve visibility in the Class I areas in the region. 

6. 	 Related environmental benefits of improved S02 removal efficiency. 

With improved S02 removal efficiency at Colstrip Units 1 and 2, there will be other 

pollutants that will be reduced as a co-benefit ofthe S02 controls. Specifically, acid gas 

hazardous air pollutants such as hydrogen chloride and hydrogen fluoride will be reduced to a 

greater extent with a more efficient scrubber at Colstrip Units 1 and 2. In fact, the Colstrip Units 

1 and 2 might require scrubber upgrades to meet EPA's forthcoming acid gas MACT 

requirements. EPA has proposed acid gas MACT limits for HCI ofO.0021b1MMBtu or, 

alternatively, EGUs can select to comply with a surrogate limit on S02 of0.20 IblMMBtu. 76 

Fed. Reg. 25127 (May 3, 2011). Colstrip Units 1 and 2 emit S02 at twice the rate ofthe EPA's 

proposed surrogate S02 MACT limit, so they will likely be required to upgrade S02 removal 

24 


f 

! 

1 

1 

i 

! 

f 

[ 

! 

I 

\ 

I

f 

f

I 
efficiency to meet acid gas MACT requirements. The Colstrip units will have to comply with 

the acid gas MACT requirements by the end of2014, which is a similar requirement for BART 

compliance. Thus, EPA should take into account the forthcoming MACT rules in determining 

S02 BART for Colstrip Units 1 and 2. Improving S02 control will greatly improve control of 

acid gas toxic emissions. 

In addition, improved efficiency ofthe scrubbers at Colstrip Units 1 and 2 will also result 

in reductions on condensable PM, which will not only benefit visibility but will also help the 

Colstrip units to comply with EPA's proposed 0.03 IblMMBtu MACT standard on total PM 

emissions that EPA has proposed as a surrogate for non-mercury metal hazardous air pollutants. 

Further, given that condensable PM emissions are typically in the range of2.5 microns or 

smaller, improved efficiency ofthe scrubbers will result in less PM2.5 being emitted from 

Colstrip Units 1 and 2. These additional benefits need to be taken into account when 

determining BART for S02. 

Further, replacing the existing wet scrubber with a state-of-the-art dry scrubber could 

significantly limit the amount ofwet waste stored in the Company's leaking holding ponds. 

Indeed, the Company may be required to switch to dry handling procedures in any event to 

address ongoing violations ofits state Major Facility Siting Act certificate ofcompliance. 

Investment in dry scrubbing technology would therefore serve the additional purpose ofreducing 

harmful groundwater contamination due to the Company's leaking holding ponds. 

In sum, the Company has shown that it is extremely cost effective to upgrade the existing 

scrubbers to add lime injection to meet an S02 emission limit ofO.15IbIMMBtu, and the 

company has shown that meeting such a limit will provide for noticeable improvements to 

visibility. Based on this analysis, the Company must at least upgrade the existing scrubbers to 

add lime injection and meet a 0.15 IblMMBtu S02 BART limit. Even with the inst.allation ofa 

i baghouse upstream ofthe existing scrubber to meet BART for PM (as well as to meet mercury 

requirements and MACT for toxic metals), upgrading the scrubber to achieve an S02 emission t 

rate of at least 0.15 IbIMMBtu would be cost effective when compared to the costs that other 

EGUs are subject to under BART requirements. Moreover, given than a 0.151b1MMBtu S02 

emission limit does not even reflect 90% S02 control across the boiler, EPA must evaluate 

additional scrubber upgrades and new replacement scrubbers that could enable greater reductions 

in S02 emissions and greater benefits to regional haze. 

E. 	 Cumulative Impact and Benefit Must be Considered as Part of Fifth Step in 


BART Analysis 


I 

~, 

The cumulative impact of a Colstrip's emissions on visibility as well as the cumulative 

benefit of emission reductions must be considered as part ofthe fifth step in the BART analysis. 

In this regard we support the National Park Service's reasoning as articulated in the agency's ,

t 

comments on Salt River Project's proposed BART determination for Navajo Generating Station, ~ July 24, 2009: 	 I 

f 

I 

~ 

t ...[I]t is appropriate to consider both the degree ofvisibility improvement 

in a given Class 1 area as well as the cumulative effects ofimproving 

25 	 I 
visibility across all of the Class I areas affected. It simply does not make 

sense to use the same metric to evaluate the effects ofreducing emissions I 

from a BART source that impacts only the one Class I area as for a BART 

source that impacts multiple Class I areas. And, it does not make sense to 

evaluate impacts at one Class I area, while ignoring others that are i 

similarly significantly impaired. Ifwe look at only the most-impacted ! 

Class I area, we ignore that the other Class I areas are all suffering from 

impairment to visibility "caused" by the BART source. It follows that, if I 

emissions from the BART source are reduced, the benefits will be spread 

well beyond only the most impacted Class I area, and this must be 

accounted for. 

Emissions from Colstrip cause or contribute to visibility impairment at five pristine Class 

I area parks and wilderness areas. Considering impacts to UL Bend alone, as Puget Sound does 

in its BART analysis, discounts the facility's contributions to visibility impairment in four other 

Class I areas as well as the potential benefit, and therefore incentive, ofreducing haze-causing 

emissions from the source. Multiple states and EPA regions as well as the federal land 

management agencies have assessed the cumulative impact and benefits ofBART sources within 

their jurisdiction. We encourage EPA Region 8 to ensure that BART analyses are inclusive of 

cumulative impacts and benefits that reflect the degree ofvisibility improvement which may 

reasonably be anticipated from the use ofBART. 

III. 	 REASONABLE PROGRESS REQUIREMENTS FOR COLSTRIP UNITS 3 AND 4 

The FIP should establish emissions controls for Colstrip Units 3 and 4 as part ofits long­ f 

term strategy for achieving reasonable progress toward meeting natural visibility conditions at f mandatory Class I areas by 2064. 40 C.F.R. § 51.308(d)(1)(i)(B). The FIP's reasonable 

t progress goals "must provide for improved visibility on the most impaired days and ensure no 

degradation in visibility for the least impaired days." Id. In developing its long-term strategy for 

meeting reasonable progress goals, EPA must consider all anthropogenic sources ofvisibility ! 

impairment and evaluate different emission reduction strategies beyond those prescribed by the 

BART provisions. 40 C.F.R. §51.308(d). EPA should consider "major and minor stationary 

sources, mobile sources and area sources." Id. Given the substantial contribution ofColstrip I 

Units 3 and 4 to visibility impairment in the region's Class I areas, EPA's long-term strategy for 

meeting reasonable progress goals must include emissions limitations for these units. 

J 

A. 	 Colstrip Units 3 and 4 Should Be Required to Reduce NOx to Meet 


Reasonable Progress Requirements. 


i 

To ensure it meets reasonable progress requirements, EPA must consider imposing SCR 

on Colstrip Units 3 and 4. At a minimum, regardless ofBART applicability and determinations, I 

EPA is required to demonstrate that "it has included in its implementation plan all measures 

necessary to obtain its share ofthe emission reductions needed to meet the progress goals for the 

area," even when sources from outside the state contribute to visibility impairment in the State's 

Class I areas. 40 C.F.R. § 51.308(d)(3)(ii) (emphasis added). Further, EPA has a responsibility I 

26 I

f 

I 
to reduce emissions from Montana sources that are reasonably anticipated to impact visibility in 

other states' Class I areas. To this end, EPA should impose SCR on all four Colstrip units. 

The Colstrip plant is the largest industrial source ofNOx in the State ofMontana. Units 

3 and 4, being larger units that Units 1 and 2, emit roughly two-thirds ofthe NOx from the 

Colstrip power plant. Although these units recently upgraded combustion controls to reduce 

NOx emissions, the NOx emission rates at these units are still high. Specifically, Colstrip Units 

3 and 4 are achieving annual average NOx emission rates of 0.17 IblMMBtu, according to the 

Company. See January 31, 2011 submittal from PPL Montana to EPA regarding Colstrip Units 

3 and 4, Ex. 2 at 6. 

The Company's January 2011 submittal to EPA appears to state that Colstrip Units 3 and 

4 are already meeting BART for NOx, and thus the PPL Montana did not evaluate any additional 

NOx controls. Specifically, the submission discusses the 2007 Consent Decree that includes 

requirements to satisfy Condition 7 ofits 1979 prevention ofsignificant deterioration (PSD) 

permit. Id., Ex. 2 at 4. Condition 7 oftheir PSD permit required the company to conduct a 

"BART analysis" for NOx to address visibility impairment that the Colstrip Units 3 and 4 were 

projected to cause on the Northern Cheyenne Indian Reservation Class I area. Id. I

I 

Contrary to the Company's interpretation, the "BART" requirement in Condition 7 is not 

equivalent to BART under the Regional Haze Rule. Condition 7 was included in the Colstrip 

Units 3 and 4 PSD permit to address what is known as "reasonably attributable" visibility 

impairment, where visibility impairment in a Class I area is reasonably attributable to a source. 

Further, Condition 7 was included to address visibility impairment for a non-mandatory Class I 

area-the Northern Cheyenne Indian Reservation. See 40 C.F.R. §51.301. In contrast, regional 

haze applies to Mandatory Class I Federal Areas and it applies to visibility impairment that is 

caused by numerous sources located over a wide geographic area. Id. Further, EPA's BART 

guidelines require a case-by-case, five-factor analysis to determine what represents BART for a 

particular facility. To the best ofour knowledge, the Company has not submitted a BART 

analysis under the requirements ofEPA's BART guidelines in 40 C.F.R. Part 51, Appendix Y. 

The 2007 consent decree addressed a permit violation, not a regional haze requirement. Thus, 

the Company's claim that the 2007 consent decree exempts Units 3 and 4 from a complete 

BART analysis to determine what pollution controls can be cost effectively applied to meet 

reasonable progress goals ofthe regional haze program is not accurate. Indeed, the "reasonable 

progress" requirement envisions emissions controls above and beyond existing permit 

requirements, and even beyond BART. See 40 C.F.R. §51.308(d). 

It would be difficult to support the NOx requirements ofthe Consent Decree as meeting 

BART. Specifically, the Consent Decree specifies NOx limits ofO.181blMMBtu when loads 

are above 400 MW and 0.30 IblMMBtu when loads are less than or equal to 400 MW, applicable 

on a 30-day rolling average. The Consent Decree also sets 24-hour average limits of 0.25 

IblMMBtu at loads above 400 MW and 0.30 IblMMBtu at loads less than or equal to 400 MW. 

See January 31, 2011 submittal from PPL Montana to EPA regarding Colstrip Units 3 and 4, Ex. 

2 at 1-2. The Company states that Units 3 and 4 are emitting NOx at a rate of 0.17 IblMMBtu on 

an annual average basis. Id. at 6. While one cannot readily compare annual average NOx 

emission rates to 30-day or 24-hour average emission rates, the annual average NOx rates 

\ 

27 I 

i 
indicate that the units are likely operating well below the emission limits ofthe Consent Decree, 

especially the emission limits that apply at lower loads below 400 MW. Indeed, it is not clear 

why such higher limits at lower loads are even necessary. EPA's presumptive BART limits in 

40 C.F.R. Part 51, Appendix Y, do not include provisions for increased NOx emission rates at 

lower loads, and yet the majority ofEPA's presumptive NOx limits are based on the use of 

combustion controls like low NOx burners and overfire air.72 In fact, ifColstrip Units 3 and 4 

need higher NOx limits during lower loads, this indicates that the low NOx concentric firing 

burners and separated overfire air currently installed at Colstrip Units 3 and 4 do not reflect the 

best system of continuous emission reduction required to meet BART. 

Clearly, these units also are not achieving emission rates reflective ofthe best system of 

NOx reductions for coal-fired utility boilers. The units' NOx emissions do not even meet the 

current New Source Performance Standards (NSPS) of0.11 IbIMMBtu (30-day average) for a 

new unit to 0.151blMMBtu (30-day average) for a modified unit. 40 C.F.R. §60.44Da(e)(2). ( 

The units are also not meeting the presumptive NOx BART limit for tangentially-fired units like 

Colstrip Units 3 and 4 of0.15 IbIMMBtu. Thus, these Colstrip units can achieve lower NOx 

emission rates and, clearly, the emission limits ofthe Consent Decree are not reflective ofBART I 

or emission limits necessary to meet reasonable progress goals under the regional haze program. 

t 

It is also questionable that the low NOx concentric firing burners with SOFA currently 

installed at Colstrip Units 3 and 4 reflect state-of-the-art combustion controls, given that Units 3 1 

and 4 are only achieving 0.17 IbIMMBtu on an annual average. As previously discussed in this 

letter regarding NOx BART for Colstrip Units 1 and 2, ultra low NOx burners are available that 

can achieve NOx emission rates lower than 0.17IbIMMBtu, as low as 0.13 IblMMBtu.73 I

SCR is the best choice to reduce NOx at Colstrip Units 3 and 4, due to the very low NOx 

emission rates that can be achieved and the significant benefits to visibility that could be 

obtained with SCR. As we have discussed in this letter regarding Colstrip Units 1 and 2, 

Colstrip Units 3 and 4 should be able to easily achieve NOx emission rates ofO.04lblMMBtu or 

lower with SCR. Such emission rates have been required to meet best available control 

technology and other requirements and have been achieved in practice at numerous units. 74 

Given how the Company's cost evaluation of SCR for Colstrip Units 1 and 2 showed that SCR 

would be cost effective when compared to the costs that other power plant owners have to meet 

under regional haze requirements, one would expect the cost effectiveness calculations for 

installation ofSCR at Colstrip Units 3 and 4 to be even more cost effective due to economies of 

scale and the fact that Units 3 and 4 are larger units. IfSCR was installed at Colstrip Units 3 and 

4, the units could achieve additional NOx reductions ofroughly 4,300 tons per year each from 

72 See 40 C.F.R. Part 51, Appendix Y, Table 1; see also Technical Support Document for BART 

NOx Limits for Electric Generating Units and Technical Support Document for BART NOx 

Limits for Electric Generating Units Excel Spreadsheet, Memorandum to Docket OAR 2002­

0076, April 15, 2005. 

73 See Attachment 1. 

74 See Attachments 3, 4, and 5. 

28 
~~-: 

current NOx emission levels.75 The Company's SCR analysis for Units 1 and 2 assumed similar 

levels ofNO x reductions from Colstrip Units 1 and 2 and their modeling showed a 0.956 

deciview improvement in visibility impairment from installation ofSCR at Units 1 and 2. See 

June 2008 Addendum to PPL Montana's Colstrip BART Report at 5-6 and Appendix 2 (Table 

5.5-3). Similar improvements in visibility should occur with the installation of SCR at Colstrip 

Units 3 and 4. Thus, installation of SCR at Colstrip Units 3 and 4 should significantly improve 

visibility. 

In summary, EPA must evaluate additional controls on NOx emissions from Colstrip 

Units 3 and 4 to address Montana's largest source ofNO x emissions and to provide reasonable 

progress towards the national visibility goal in the Montana, Wyoming, and North Dakota Class I 

areas impacted by the Colstrip power plant. Based on the information provided for NOx BART 

for Colstrip Units 1 and 2, SCR should be required at Colstrip Units 3 and 4 as the most cost 

effective controls that provide for the greatest benefit to regional haze. 

B. EPA Must Adopt Reasonable Progress Requirements Pertaining to the S02 

and PM Emitted by Colstrip Units 3 and 4. 

Additional S02 and PM controls are also justified for Colstrip Units 3 and 4 to meet 

reasonable progress requirements. The Company has indicated that it cannot cost effectively 

upgrade the PM controls at Colstrip Units 3 and 4 because the S02 scrubber efficiency depends 

on the utilization of alkaline fly ash. Thus, the company indicated that if a baghouse or an ESP 

was installed upstream ofthe scrubber, they would likely need to also install new limestone 

forced oxidation scrubbers to achieve the same levels of S02 emissions. According to the 

Company, Colstrip Units 3 and 4 are achieving 95% S02 removal and annual average emission 

rates ofO.081blMMBtu. See January 31, 2011 submittal from PPL Montana to EPA regarding [ Colstrip Units 3 and 4, Ex. 2 at 8. Unlike the scrubbers at Colstrip Units 1 and 2, the company 

adds lime to the scrubbers at Units 3 and 4 and each has a spare absorber. The company has 1 

estimated that the combined costs ofinstalling a baghouse or an ESP and a new scrubber at each ! 

unit would be one billion dollars in total for both units. Id. at 17-18. 

There are several examples ofEGUs with venturi scrubbers that have or soon will install 

baghouses or ESPs upstream ofscrubbers, and no issues ofreduced S02 removal have been 

raised. In the discussion ofPM BART for Colstrip Units 1 and 2 in this letter, we have provided 

examples ofother power plant units that have installed, or soon will install, baghouses upstream 

ofparticle/S02 scrubbers without negatively impacting S02 emissions. Those EGUs include 

Reid Gardner Units 1-3, Cholla Unit 2, and Sherburne County Units 1 and 2.76 EPA Region 9 

has also proposed that the Four Comers Power Plant Units 1-3 install PM controls upstream of 

existing particle/S02 scrubbers to meet BART for PM, and EPA has not identified any concerns 

75 This was calculated based on the average annual heat input for Unit 3 from 2008-2009 for Unit t 

3 and 2007-2008 for Unit 4 (due to the lengthy period that Unit 4 was not operated in 2009), 


assuming current NOx emission rates of0.17 IblMMBtu and a controlled NOx emission rate I 

with I SCR ofO.041blMMBtu. 

76 See, e.g., Attachments 20 and 21. 

29 I

f 

r 

1 
with the reduced levels of S02 removal due to the removal of ash upstream ofthe scrubbers.77 

Thus, we question the Company's assumption that it could not operate or, if necessary, upgrade 

its existing scrubbers to achieve the same levels of S02 removal if a baghouse or ESP were 

added upstream ofthe scrubbers. For example, the Company could add more lime and/or make 

other physical changes to the scrubber to improve the effectiveness ofthe scrubber if a baghouse 

was added upstream ofthe current scrubber. See discussion on PM BART for Colstrip Units 1 

and 2 and Attachments 22 and 23 for further details on the upgrades that could be done to the 

scrubbers ifthe scrubber was designed and operated solely for S02 removal. 

EPA Region 9 found that the particle scrubbers at Four Comers Units 1-3 were causing a 

secondary plume that was adversely impacting visibility. Region 8 should conduct a similar 

analysis for the Colstrip power plant units. As Region 9 stated, venturi particle scrubbers are 

hardly used anymore for particulate control at coal-fired EGUs due to their substandard removal 

ofparticulates, and especially fine particulates, in comparison to a baghouse or ESP. See 75 Fed. 

Reg. 64231 (Oct. 19, 201 0). Ifthe scrubbers at Colstrip are causing a secondary plume, then 

installation of a baghouse or an ESP upstream ofthe scrubber will significantly improve 

visibility. 

In addition, Colstrip Units 3 and 4 will likely need to upgrade PM controls to meet EPA's 

forthcoming MACT rule. Specifically, EPA has proposed a PM limit of0.03 IblMMBtu as a 

surrogate for non-mercury metal HAPs. EPA's proposed limit is a limit on total particulate 

matter (filterable plus condensable PM). The Colstrip Units 3 and 4 emitted filterable PM at a 

rate ofO.026lblMMBtu on average over the past five years. See January 31,2011 submittal 

from PPL Montana to EPA regarding Colstrip Units 3 and 4, Ex. 2 at 15. With condensable PM 

added in, these units undoubtedly emit total PM at rates exceeding EPA's proposed PM MACT 

standard of0.03 IbIMMBtu. Thus, the Company will likely need to upgrade PM controls and/or 

S02 controls to meet EPA's proposed MACT limit on total PM of0.03 IblMMBtu. Further, 

improvements in PM controls may be necessary to meet EPA's proposed mercury MACT limits, 

as discussed in this letter regarding Colstrip Units 1 and 2. EPA should consider these future 

regulations in determining regional haze plan requirements for Colstrip Units 3 and 4. Ifthe 

units are going to have to install PM controls, whether upstream or downstream ofthe scrubbers, 

to meet MACT, then EPA should impose appropriate emission limits in the regional haze plan 

reflective ofthese forthcoming rules and the benefits that these forthcoming rules will have for 

visibility in the Class I areas in the region. 

Further, the Colstrip Units 3 and 4 are emitting S02 at much lower rates than currently 

allowed in the applicable requirements. Specifically, although Units 3 and 4 are currently 

emitting S02 at a rate of 0.08 IbIMMBtu, the units are subject to much less restrictive S02 

emission limits of0.18 IblMMBtu on a calendar day average. See January 31, 2011 submittal 

from PPL Montana to EPA regarding Colstrip Units 3 and 4, Ex. 2 at 8; see also May 17, 2011 

draft Title V permit, Section III.C. at 12. Thus, EPA should impose S021imits on Colstrip 

Units 3 and 4 in the regional haze SIP that are reflective ofthe 0.08 IblMMBtu S02 emission 

77 See 75 Fed. Reg. 64320-2 (Oct. 19,2010); see also Attachment 11. 

30 

rate currently being achieved at these units to ensure that no future degradation in visibility due 

to these units' S02 emissions is allowed. 

For all of the above reasons, EPA should, at the minimum, impose PM limits reflective of 

compliance with its proposed MACT standards and impose S02 limits reflective of current 

levels of S02 emission rates in the Montana regional haze plan. EPA must impose limits that 

ensure reasonable progress towards the national visibility goal and also ensure the prevention of 

any future visibility impairment due to S02 and PM emissions from Colstrip Units 1 and 2. 

We thank you for your consideration ofthese comments and would be pleased to answer 

any questions you have. We look forward to our meeting on August 25,2011. 

Sincerely, 

Jenny Harbine 

Janette Brimmer 

cc: 	 Steve Tuber, Assistant Regional Administrator for the Office ofPollution Prevention and 

Regulatory Assistance 

Callie Videtich, Deputy Assistant Regional Administrator for the Office ofPollution 

Prevention and Regulatory Assistance 


Laurel Dygowski, Environmental Protection Specialist 


Monica Morales, Unit Chief, Air Quality Planning Unit 


Sara Laumann, Attorney 


Vanessa Hinkle, Air Quality Planning Unit 


Anne Hedges, Montana Environmental Information Center 


Sanjay Narayan and Doug Howell, Sierra Club 


Stephanie Kodish, National Parks Conservation Association 


Vicki Stamper 


31 


J 

I 

f 

I 

t 

, 

l 

! 

I 

I 
I 

ATTACHMENTS 


,

f 

I 

1 

Attachment Number Description 

1 Bryk, S.A. et aI., First Commercial Application of DRB-4ZTM 

Ultra Low NOx Coal-Fired Burner, presented to POWERGEN International 2000, November 14-16, 2000, Orlando, 

FL. 

2 National Park Service's Spreadsheet "EGUs with proposed 

BART NOx Controls Mar 2011." 

3 Institute ofClean Air Companies, White Paper Selective 

Non-Catalytic Reduction (SNCR) for Controlling NOx 

Emissions, May 2000. 

4 Erickson, Clayton A. et aI., Selective Catalytic Reduction 

System Performance and Reliability Review, The 2006 

MEGA Symposium, Paper # 121. 

5 Desert Rock PSD permit. 

6 National Park Service spreadsheet on BACT limits for New 

PC Power Plants. 

7 Florida Source Tests com2ilation. 

8 Matt Haber, Best Available Control Technologies for the 

Baldwin Generating Station, Baldwin, Illinois, Expert Report, 

Prepared for the United States in connection with U.S. v. 

lllinois Power Company and Dynegy Midwest Generation, 

Inc., April 2002. 

9 May 28, 2009 WY DEQ BART Application Analysis for 

Pacificorp NaUghton Power Plant. 

10 May 28, 2009 WY DEQ BART Application Analysis for 

Pacificorp Dave Johnston Power Plant. 

11 EPA's Technical Support Document, Proposed Rule: Source 

Specific Federal Implementation Plan for Implementing Best 

Available Retrofit Technology at Four Corners Power Plant: 

Navajo Nation. 

12 McIlvaine Hot Topic Hour, Filter Media Selection for CoalFired Boilers, September 13,2007, Presentation by Todd 

Brown, Daikin America, Inc. 

13 USEP A, ETV Joint Verification Statement, Baghouse 

Filtration Products, W.L. Gore & Associates, L3650. 

14 US EPA, Performance and Cost ofMercury and MultiPollutant Emission Control Technology Applications on 

Electric Utility Boilers, EP A-6001R03-11 0 (October 2003). 

15 US EPA Region 9, Ambient Air Impact Report for Desert 

Rock Energy Project. 

16 EPRI's "Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants," Version 201Oa. 

17 EPA, Regulatory Impact Analysis of the Proposed Toxics 

32 

! Rule: Final Report, March 2011. 

18 National Park Service's spreadsheet entitled "EGUs with 

Proposed BART S02 Controls. 

19 Spreadsheet with monthly emissions data for Reid Gardner 

Units 1-3 from 2010, downloaded from EPA's Clean Air 

Markets Database. 

20 Revised Nevada Division ofEnvironmental Protection BART 

Determination Review ofNV Energy's Reid Gardner Energy 

Station Units 1,2, and 3, Revised October 22,2009. 

21 Best Available Retrofit Technology Analysis for Sherburne 

County Generating Plant Units 1 and 2, October 25, 2006. 

22 Roden, Bob et aI., New Magnesium-Enhanced Lime FGD 

Process, Carmeuse-North America Technology Center, 

Pittsburgh, P A. 

23 Nolan, Paul S., Babcock & Wilcox Co., Flue Gas 

Desulfurization Technologies for Coal-Fired Power Plants, 

presented at Coal-Tech 2000 International Conference, 

November 13-14,2000, Jakarta, Indonesia. 

24 Black & Veatch vendor brochure on CT -121. 

25 

I 

Yasuhiko Shimogama, Hirokazu Yasuda, Naohiro Kaji, 

Fumiaki Tanaka, and David K. Harris, Commercial 

Experience ofthe CT-121 FGD Plant for 700 MW ShinkoKobe Electric Power Plant, Paper No. 27, presented at 

MEGA Symposium, Air & Waste Management Association, 

May 19-22,2003. 

26 Jonas S. Klingspor, Kiyoshi Okazoe, Tetsu Ushiku, and 

George Munson, High Efficiency Double Contact Flow 

Scrubber for the U.S. FGD Market, Paper No. 135 presented 

at MEGA Symposium, Air & Waste Management 

Association. 

27 Y oshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, 

Commercial Experience and Actual-Plant-Scale Test Facility 

ofMHI Single Tower FGD. 

28 Mitsubishi High S02 Removal Experience. 

29 Weilert, Carl & Emily Meyer, Bums & McDonnell, Utility 

FGD Design Trends. 

30 Carstens, Andrew J. et aI., Performance Upgrades for LowSulfur Wet Scrubbers, Sargent & Lundy and CPS Energy, 

Paper # 134, EPRI-DOE-EPA-A WMA Combined Power 

Plant Air Pollutant Control Mega Symposium, 2008. 

33