# QEARTHJUSTICE
ALASKA CALIFORNIA FLORIDA MID·PACIFIC NORTHEAST NORTHERN ROCKIES NORTHWEST ROCKY MOUNTAIN WASHINGTON, DC INTERNATIONAL

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# ~l~ August 22. 2011 w«o co () Q.. -'I) C'-l**ww~** IX:. c...!::' James B. Martin. Regional Administrator (/) ::::> ::i <t U.S. Environmental ProtectionAgency. 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

DearMr. Martin:

This letter is submitted onbehalfofMontanaEnvironmental Information Center, Sierra Club, and National Parks Conservation Association in advance ofourmeetingwith you and y:Q!lr staffon AUID!st 25, 2..Q.!l;. These comments were prepared withthe assistance ofVicki Stamper,
an independent air quality expert consultant, and provide ourdetailedrecommendations for the forthcoming U.S. Environmental Protection Agency ("EPA") rulemaking to implement regional haze requirements inMontana, and particularly, the Colstrip coal-firedpowerplant ("Colstrip").

Montana Environmental Information Center, Sierra Club, and National Parks Conservation Association have thousands ofmembers in the United States, including Montana, who are deeplycommitted to protecting and improving the airquality in national parks and wildness areas in Montana and the Northern Rockies. Onbehalfofthese members, this letter seeks to support EPA in making an adequate regional haze determination inMontana.


### I. BACKGROUND

The United States Congress has established a national goal for the "preventionofany future, and the remedying ofany existing, impairment ofvisibility in the mandatory class I Federal areas which impairment results from manmade airpollution." 42 U.S.C. 

### § 7491(a)(1). Mandatory Class I areas include national parks and wilderness areas-thejewels ofour federal public lands system. To protectthese areas, a state, tribe, orEPA is required to design an implementationplan to reduce, and ultimately eliminate, haze-causing air pollution from sources that mayreasonablybe anticipated to cause or contribute to visibility impairment for oneormore protected Class I areas located within orbeyond that state's/tribe'sboundaries. The state of Montana chosenot to adopt a state haze implementationplan (SIP), and thus EPA is required to promulgate a Federal Implementation Plan (FIP) to address regional haze requirements in Montana. EPA has an unparalleled opportunityinMontanato improve regional air quality by stemming visibility-impairing emissions from the state's oldest and mostpolluting 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.orgWhile the Regional Haze Rule'sprimary 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 expresslyrequire the consideration ofimpacts in addition to visibility, EPA must consider impacts to public health when determining BART requirements for Colstrip and other BART-eligible sources. All ofthehaze pollutants at issue here- nitrogen oxides (NOx), sulfur dioxide (S02), and particulate matter (PM}-harmpublic 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, especiallythe smallerparticle sizes, can penetrate deep into the lungs and cause healthproblems such as aggravated asthma, chronicbronchitis 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 1million lost school and work days.4 As a result, the Regional Haze rule will result inhealth benefits valued at $8.4 to $9.8 billion annually.s
EPA must consider the environmental health impacts ofhaze pollutionunder the "non-air quality environmental impacts ofcompliance" 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-a4 unit coal-fired powerplant with a generating capacity ofapproximately 2,100 megawatts (MW}--is the largest source ofair 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. Becauseunits 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. 6However, these units are subject to

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

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

3EPA, 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 ourreview ofthe permitting and compliance history for these units.

2control requirements under the reasonable progress requirements ofthe regional haze program. 40 C.F.R. §51.306(d)(1) and (3).
Underthe 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, ifa BART-eligible source mayreasonablybe anticipated to cause or contribute to any impairment ofvisibility in anymandatory Class I Federal area, then the facility is considered subject to BART. See 40 C.F.R. §51.306(e). Ifan existing source causes a visibility impact of 0.5 deciview orhigher in a Class I area, EPA considers it contributing to visibility impairment in that Class I area7• 40 C.F.R. Part 51, Subpart Y, Section III.A.1. EPA considers a source that
causes 1deciview orhigher visibility impact to "cause" visibility impairment. Id. Visibility modeling conducted on behalfofthe owners ofColstrip showed that Colstrip Units 1 and 2 cause, on average, visibility impacts of 1deciview orhigherat the following Class I areas: UL Bend Wilderness, North Absaroka Wilderness, Theodore RooseveltNational Park, and the Washakie Wilderness. The units cause impacts in excess of0.5 deciviews on average at Yellowstone National Park. See August 2007 BARTAssessment Colstrip Generating Station, Appendix B at Table 5-1 (page 24). Where multiple Class I areas are impactedby 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 ofColstrip Units 1 and 2-Puget Sound Energy and PPLMontana (hereafter, "the Company")-submitted an initial BART analysis for these units in August 2007 and submitted an addendum to the BART analysis inJune 2008. As a result ofthese 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/orupgrades to controls to improve regional haze are necessaryto achieve BART and meet the objectives ofthe regional haze program. Colstrip Units 1 and 2 have out-of-date pollution controls. The tangentially-fired units bum subbituminous coal of0.7% sulfur content from the northern PowderRiverBasin. To control NOx, the units use a low NOx concentric firing system (LNCFS) with close coupled overfire air (CCOFA) and achieveNOx emission rates inthe range of0.30 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 BARTreport, the scrubbers remove 75-80% ofS02 emissions and are designed to remove 98% ofPM 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.



### 3although the Company claims the scrubbers have been shown to achieve particulate control efficiencies approaching 99.5%. Id. The Companyhas 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 of0.05 to 0.06 IblMMBtu, respectively. Id. at 2-4. These emissionrates are much higher than EPA'spresumptive BART levels and do not reflect the maximum achievable emissionreductions 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 "theCompany"}-claimthe units have alreadymet 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 bythe 2007 consent decree. TheNOx 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 EPAis obligated to adopt measures to achievereasonable progress towards the national visibility goal. 40 C.F.R. §51.308( d)(1). Given that Colstrip is byfar the largest emitter ofregional haze impairingpollutants in the state ofMontana, EPA must evaluate additional controls for Colstrip Units 3 and 4 to meetreasonable progress requirements.
In this letter, weprovide our analysis ofwhat should be required at the Colstrip units to meet BART based on the information submittedbythe Company and onproposed and final BART emission limitations for other coal-firedpowerplants. We also provide comments on the controls that shouldberequired at Colstrip Units 3 and 4 to meetreasonable progress requirements.


### II. BART FORCOLSTRIPUNITS 1AND 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 orBART is defined as follows:

BestAvailable Retrofit Technology (BART) means an emission limitationbased
onthe degree ofreduction achievable through the application ofthe best system ofcontinuous emission reduction for eachpollutant which is emitted byan existing stationary facility.
40 C.F.R. § 51.301. EPAis required to determine BART for each unit on a case-by-casebasis. 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 ofcompliance; (b) the energy and non-air quality environmental impacts ofcompliance; (c) any existing pollution control technology inuse at the source; (d) the

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

4remaining useful life ofthe source; and (e) the degree ofvisibility improvement which may reasonablybe anticipated from the use ofBART. See 40 C.F.R. §§ 51.301, 51.308(e)(1)(ii)(A).

The existingpollution controls at Colstrip Units 1 and 2 are notthe best systems of continuous emission reductions for the units' visibility impairingpollutant 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 ofany BART-eligible source in Montanabya large margin. See SummaryofWRAP RMC BARTModeling 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 powerplant is the largest emitter ofNOx ofany ofthe industrial facilities inMontana.to The Company's evaluation ofcombustion controls and post-combustion controls for NOx shows all options to be cost effective when comparedto the costs required at othercoal-fired electric utility units (EGUs). Nonetheless, the Companyinexplicably 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 claimsthat no additional NOx controls arejustified, the Company's own analysis demonstrates that use ofSelective Catalytic Reduction (SCR) in combination with separated overfired air (SOFA) represents the "best system ofcontinuous emission reduction" and is cost effective. 40 C.F.R. § 51.301.

At the request ofEPA, the Company evaluated a NOx emissionrate ofO.06IbIMMBtu, lower than thepresumptiveBART 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 PPLMontana's Colstrip BARTReport at 5-4, however, the Company's analysis demonstrates that a NOx emission rate of0.06 IblMMBtu is readily achievable at these units with the application ofSCR. Tomeet a 0.061blMMBtu emission rate, the SCR needs to achieve 80-82% NOx removal from currentNOx 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 shouldbe able to reduce NOx to emission rates lower than 0.04 IbIMMBtu with the combination ofSOFA and SCR at Colstrip Units 1 and 2.

A review ofrecent SCR retrofits definitively shows that veryhigh levels ofNOx removal
arebeing achieved byrecent SCRretrofit 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 AirDatawebsite. 11 SeeErickson, Clayton A. et aI., Selective Catalytic Reduction System Performance and Reliability Review, The 2006 MEGA Symposium, Paper # 121, Attachment4.

5Permitting agencies have required lowerNOx limits in recent BACT determinations, with many proposed and required BACT limits of0.05-0.06 IblMMBtu and at least oneNOx 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 beenproposed orrequired as BART to meet regional haze progress goals at several coal-fIred power plants elsewhere, including the Boswell Energy CenterUnit 3 and Alan S. King Unit 1 in Minnesota13

, NaughtonUnit 3 and Jim BridgerUnits 3 and 4 in Wyomingl4, San Juan Units 1_415

, and Four Comers Units 1-516. SCR along with installation ofcombustion controls including low NOx burners has been found to be cost effective at these units. According to data compiledbythe 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 Companypresented cost effectiveness data for installation ofSCR onColstrip Units 1 and 2 to achieve a NOx emissionrate ofO.06lblMMBtu that shows the costs are quite reasonable. SpecifIcally, the companyprojected 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 PPLMontana's Colstrip BART Report at 5-5 to 5-6. This level ofcosts is within the range ofBART control costs that other EGUs will have to incurunderregional haze requirements, and is very similar to the costs projectedbyEPA to install SCR at the San Juan Units 1-4. TheNOx reductions required by state regional haze plans have beenprojected to cost $1,872/ton on average. 18

12 The Desert Rock Energy Facilitypermit requires the facility to achieve, after a NOx optimizationperiod, a NOx emissionrate of0.035 IblMMBtu on a 365 day rolling average and
an emissionrate of0.05 IblMMBtu on a 30-day rolling average. Attachment 5. See also the National Park Service spreadsheet on BACT limits for New PC PowerPlants, 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 BARTNOx Controls Mar2011," Attachment 2. 18 See id.



### 6The Company's modeling showed almost a 1deciview improvement in visibility with the installation ofSCR and the establishment ofaNOx emission limit ofO.061blMMBtu at UL Bend alone. See June 2008 Addendum to PPLMontana'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 visibilityimprovingbenefits would likewiseberealized atthe other four Class I areas within the plant's airshed.

IfSOFA was also installed, visibility improvement couldbe even greaterwithout impacting cost effectiveness ofthe controls. Although the Companydid not evaluate the installation ofSOFA and SCRtogether, the NOx BART determination shouldbebased on the combination ofSOFA and SCRbecausethe useofcombustion controls to reduce NOx to the greatest extent followed byan SCR system represents thebest continuous system ofNOx emission reduction. Based on the Company'sprojected 0.19 IblMMBtu NOx emissionrate with the addition ofSOFA, theNOx BART emission limit based on SOFAplus SCR shouldbe0.04 IblMMBtu orlower. And, while the Company did not provide cost effectiveness calculations for this combination ofcontrols, the costperton ofNOx removed should bein the range ofthe $1,735Iton that the Company estimated for SCRto meet an emission rate ofO.06IblMMBtu. This is becausewith lowerNOx concentrations coming into the SCR, thatwill decrease both capital and operating costs ofthe SCR.
Basedupon this information and analysis, the Companyhas demonstrated that installation ofSCRis cost effective and will significantlyimprove visibilityin affected Class I
areas. Further, ifSCRis installed along with SOFA, the cost effectiveness will improve further, and the visibilitybenefits inthe region will be even greater. SCR with SOFA is BART for Colstrip Units I and 2.

2. Installation ofSCRto meet BART for NOx will have other environmental benefits.
Installation ofan SCR system will provide other air quality and non-air quality environmental benefits, in addition to reduction ofhaze-formingNOx. First, becauseNOx 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 SCRcould also benefit the vegetation ofthe region's Class I areas and
areas neighboring theseprotected spaces. Another issue in the region isnitrogen deposition, which is causedbywet and dry deposition ofnitrates derived from NOx emissions. The significant adverse impacts ofnitrogen deposition onecological systems is well known. Critical loads (Le., the amount ofnitrogen deposition that an ecosystem can tolerate, and above which the systemsbecome adversely impacted) are likely to soon be used to formally inform policy developments**~,** NADP-CLAD Meeting, Pensacola, FL Spring 2009). In addition, greaterreduction ofNOx emissions at Colstrip would also equate with reductions in PM2.5 formation.

7Further, 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 ofPM emissions ofany BART-eligible
source in Montana. 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). These units also use sub-standard control technology for particulate matter-venturi particle scrubbers. To improve visibility, EPA should consider requiring the installation ofa baghouse or, as a second choice, an ESP, upstream ofthe existing venturi scrubber as BART at each ofthese 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 bothPM10 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 of2.5 microns or smaller. Alternatively, EPA could set limits onthe 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 ofcontinuous emission reduction.
Venturi scrubbers are not the best system for continuous emission reduction ofparticulate matter. Venturi scrubbers are not typically included inbest available control technology (BACT) analyses for new ormodified 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 onthe use ofanESP. 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 utilityboilers 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 ofcontinuous emission reduction for PM.



### 8In its BART proposal for the FourComers PowerPlant, EPA acknowledged as much, stating that such venturi scrubbers have not been installed at coal-fired EGUs since the early 1970'sbecause ofconcerns over the ability ofthe venturi scrubbers to continuouslymeet the PM standards ofthe 1971 New Source Performance Standard for coal-firedboilers of0.10 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 significantreduction 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 orbelow 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 PPLMontana's Colstrip BART Report at 2-4 (Table 2-2). Colstrip Units 1 and 2 emit almost five times the filterable PM emissionrate 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. Bycontrast, electrostatic precipitators (ESPs) can achieve PM control efficiencies greaterthan 99%, whereas baghouses
can achieve PM control efficiencies of99.9% orhigher. 19 Baghouses have been installed since the 1970's and are the PM control technology of choice for new coal-fired EGUsbecause oftheir superior abilityto control fine particulate matter. There have been several recent permits issuedwith BACT limits at 0.010 IblMMBtu based oninstallation ofa fabric filter baghouse, including the Plant Washingtonpermit, the Longleafpermit, and the Desert Rock permit issued byEPA Region IX. See Attachments 3, 4, 

# I I and 5. Yet even these recent, lower emission limits fail to reflect the low levels offilterable PM emissions that canbe achieved with fabric filter baghouses. Sourcetest data have shown that
even lower levels ofemissions canbe 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 DeputyDirector ofthe AirDivision, concluded in 2002 that BACT for filterable PM at two existing PC boilers firing PowderRiver 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 emissionreduction and thus are equally applicable underBART. Therefore, there is no reason that the Colstrip units could not achieve PM

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

20 Attachment 7, Florida Source Tests compilation.

21 Attachment 8, Matt Haber, BestAvailable Control Technologies/or theBaldwin Generating Station, Baldwin, Illinois, ExpertReport, Prepared for the United States in connection with U.S. v.lllinois Power Company and DynegyMidwest Generation, Inc., April 2002, p. 3.



### 9emission rates similarto rates at new units withbaghouses. Accordingly, baghouses--not venturi scrubbers--represent the best system ofcontinuous particulate emissionreduction that could be used at Colstrip Units 1 and 2.

2. The Company appears to have overestimated the costs ofinstalling new particulate controls at Colstrip Units 

### 1 and 2 when compared to the costs for similar controls projected in otherPM BART analyses. Recognizing that venturi scrubbers are far from the best system ofcontinuous particulate emissionreduction, the Company did evaluate the addition ofan ESP ora 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 ofcosts and an underestimate ofbenefits from the use ofanESP ora baghouse. Specifically, the Company estimated the annualized cost ofinstalling
an ESP to meet an emission limit of0.010 IblMMBtu to be $17,748.667, and the annualized cost ofa 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 otherPM BART analyses.

Forexample, the BART analysis for NauftonUnit 3 included an evaluation ofa new full-scale fabric filter to replace an existing ESP. 2 NaughtonUnit 3 has a heat input capacity of 3,700 MMBtuIhr and is about the size ofColstrip 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 ofa venturi particle scrubber with a new fabric filter.24 Dave JohnstonUnit 4 has a heat input capacity of4,1 00 MMBtulhr. Thetotal 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 costprojections for an ESP or a baghouse are inexplicably higher.
Based onthis 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 similarEOUs and therefore suspect.

22 See Attachment 9, May 28,2009 WYDEQ 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 JohnstonPowerPlant, at 14.

25 Id. at 17.

10

### 3. EPA should evaluate the abilityto add an ESP orbaghouse**upstre~** of the particle scrubbers at Colstrip Units 1 and 2.

EPA should evaluate the option ofinstalling new particulate controls-anESP or a baghouse-upstreamofthe existing scrubber to act as the primaryPMcontrol device. It appears 

# 1 that the Company onlyevaluated the addition ofan ESP orbaghouse downstream ofthe existing 

# I particle scrubber. Specifically, the Companyhas stated that, because the exhaust from the venturi scrubbers is reheated above the dew point, add-on particulate controls couldbe 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 thebaghouse orESP the primaryparticulate 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 becalculated based on the 

## j amount ofPM removed from uncontrolled levels exiting the boiler-i.e., from 0% control to 

# I 99+% control-ratherthan based onthe incrementalbenefit ofadditional PMcontrol beyond what the particle scrubber achieves. i 

## 1 Installation ofabaghouse orESP before the flue gas stream even reaches the venturi scrubberwould be cost-effective for Colstrip Units 1 and 2. To determine the amount of particulate matter that will bereduced with an ESP or a baghouse installed upstream ofthe 

### I scrubber, one must estimate the PM emissionrate exiting the boiler, which inturn requires 

# , knowing the ash and heat value ofthe coalburned at Colstrip Units 1 and 2. Itdoes not appear that the Company submitted such info to EPA. However, information from the United States f 

### t Geological Survey for the Colstrip coal mining areapermits us to venture a reliable estimate of uncontrolled PM emissions from the Colstrip plant. Specifically, it appears that the Colstrip 

# I Units bumRosebud mine coal, which has an average ash content of8.24% 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'sUnit 1 and 2 boilers is emitted at a rate ofapproximately 7.52 IbIMMBtu. 

# \

Ifcontrolled filterable PM emissions are assumed to be 0.010 IblMMBtu (the emission 

## J rate that EPA requested the Companyto use as a basis for evaluation), then the reduction inPM 

### t emissions from an ESP orbaghouse installed upstream ofthe scrubber shouldbebased 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 PMemission factor. The average annual heat input over 2001-2003 (i.e., the same years the Companyused for defining base case) was 27,408,013 MMBtu for

26 See ChapterPC, Colstrip Coalfield, PowderRiver Basin, Montana: Geology, Coal Quality, and Coal Resources, in U.S. Geological SurveyProfessional Paper 1625-1 at PC-2 and PC-7 (available at http://pubs.usgs.gov/pp/pI625a/ChaptersIPC.pdf).



### 11Colstrip Unit I and 27,548,547 MMBtu for Colstrip Unit 2.27 Based onthis annual heat input data, a filterable PM emission limit of0.010 IblMMBtu would equate to approximately 103,000 tons offilterable 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 eitherofthese controls upstream ofthe scrubber would be $ 172/ton for an ESP and $140/ton for a baghouse. These more realistic cost effectiveness numbers showthat installing an ESP or abaghouse upstream ofthe scrubbers at Colstrip Units 1 and 2 would be extremely cost effective with the baghouse beingthe 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 ofchoice for PMBART at Colstrip.

4. Installation ofa baghouse to meet a PM emission limit of0.010 IblMMBtu will improve visibility.
Installation ofa baghouse oran ESP would improve visibility. Modeling conductedby the Company for installation ofa baghouse or an ESP to meet a filterable PM emissionrate 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 Companydetermined that the visibility improvement would not discernable and thus that installation ofPM controls is not warranted. Id. at ES-3.
However, the Company did not model the installation ofan ESP or a baghouse upstream ofthe scrubber. With this arrangement, the scrubber could be optimized for S02 control, thereby greatlyreducing visibility-impairing S02. Thus, the visibilitybenefits ofthe reductions inPM should be evaluated in combination with the benefits ofupgrading and optimizing the scrubber for higher levels ofS02removal.

. In addition, EPA should evaluate whether the existingparticle scrubbers at Colstrip Units 1 and 2 are causing localized visibility impacts. EPA Region IXhas noted that the existing venturi scrubbers at Four Corners Units 1-3 cause a secondary plume that is formed inthe steam plume and that canbe seen for quite some distance from the FourCorners PowerPlant.28 According to EPA, the use ofa venturi scrubber at these units causes visibility impairment in the region around the plant. EPA states that the secondary**~lume** formed at FourCorners Units 1-3 could likelybe due to the poorcontrol offine particles. 9 It is veryplausible that the same problems occurwith the use ofa venturi scrubber at Colstrip Units 1 and 2.
The installation ofa baghouse upstream ofthe venturi scrubber could alleviate any problems with secondaryplumes. Again, a baghouse is the superior PM technology for

27 Based ondata available on EPA's Clean Air Markets Database. 28 EPA'sTechnical Support Document, Proposed Rule: Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology at FourCorners PowerPlant: Navajo Nation, at 81. (Attachment 

### 11).
29 Id.



### 12removing fine particulate matter. The filtration media determines the control efficiency ofa baghouse for very small particles. Filtration media are available that allow 99.99% ofthePM2.5 fraction to beremoved. These include Daikin's AMIREXTM, PTFEmembrane filters30 and W.L. Gore's L3650. 31 See summary ofU.S. EPA's ETV testresults in Attachment 10.32 A bag leak detection system also greatly helps inreducing and eliminating spikes in PM emissions. Thus, if the venturi scrubbers at Colstrip Units 1 and 2 cause a secondaryplumeproblem as occurs at FourComers Units 1-3, the installation ofa baghouse upstream ofthe scrubberto serve as the primaryparticulate control device could help address this issue. Further, as discussed above, use ofa baghouse at Units 1 and 2 will likely reduce PM emissions lower than 0.010 IbIMMBtu. The Company's modeling ofa filterable PM emission rate of0.01 0 IblMMBtu does not reflect the lower emissionrates which will likely occurwith the
use ofa baghouse. 

### f For all ofthese reasons, indetermining whetherit is appropriate to require new PM controls to meet BART, EPA cannot and should not rely onthe Company's modeling, which is based only on lowering the PM emissionrate to 0.010 IblMMBtu. The installation ofa baghouse upstream ofthe existing venturi scrubber would likely have myriad benefits for visibilitythat go 

# I
beyond attainment ofa 0.010 IblMMBtu emission limit. The visibility impacts analysis for PM BART must consider all ofthebenefits that could be obtained from replacing the particle 

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

# I removal. 

### f 5. The energy and environmental impacts analyses weigh stronglyin favor of installation ofbaghouses at Colstrip Units 1 and 2. 

## f 

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

# I f and 2.

a. A baghouse will result inthe greatest reduction inmercury i

# I l emissions and is likely necessaryto meet mercury limits.


### It is very likelythat a baghouse will berequired to meet eitherMontana limits orthe forthcoming maximum achievable control technology (MACT) standards for existing electrical generating steam generating units (EGUs). 

### InMay 2011, EPApublished its proposed EGU 

# f r
30 McIlvaine Hot Topic Hour, FilterMedia Selection for Coal-Fired Boilers, September 13, 2007, PresentationbyToddBrown, Daikin America, Inc. Attachment 12. Voice recording available online to subscribers ofMcIlvaine PowerPlant Knowledge System and available for purchase.

31 USEPA, ETVJoint Verification Statement, Baghouse FiltrationProducts, W.L. Gore & Associates, L3650, Attachment 13 (http://epa.gov/etv/pubs/600etv06042s.pdf ).

32 Fabric Filtration Media are certifiedbythe U.S. EPA Environmental Technology Verification Program using the "Generic VerificationProtocol for Baghouse Filtration Products" to Achieve 99.99% Removal ofPM2.5.

13MACT standards, which will make the Colstrip units subject to a mercury emission limit of 1.2 Ib/TBtu.33

Itis well known that coal-fired boilers equipped withbaghouses achieve better control of mercurythan 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 onlywithESPs.35 

# \ 

# I ! When coal is burned in a boiler, the mercury inthe coal is volatilized and converted to elemental mercuryvapor (Hgo). Hgo is insoluble in water and therefore mustbe adsorbed by a sorbent or converted to a soluble fonn so it canbe captured in a wet scrubber or another J particulate control device such as a baghouse. According to EPA, the fonn ofmercury most 

# I easilyremoved is HgCh and the fonnation ofthis compound is dependent onhow much chlorine is inthe coal-less chlorine equates to less formation ofHgCh.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 EGUsburning low chlorine coal, such as the northern Powder River Basin subbituminous coal used at Colstrip, often achieve lower control of mercuryviathe S02 and PM controls. 

# I

Compared to a particle scrubber or a dry ESP, a fabric filter baghouse provides additional opportunities for the mercuryto adhere to the unburned carbonparticles inthe fly ash as the flue 

# I

t gas moves through the filter cake onthebags. Activated carbon, a sorbent which adsorbs 

### i mercury, is typically much more effective when a bapouserather than an ESP is used, because the activated carbonbecomes part ofthe filter cake.3 Thus, vendors have developed the Toxeconpollution 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 mercuryremoval.

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 TechnologyApplications onElectric 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 onElectric UtilityBoilers, EPA-600/R03-110 (Oct. 2003) at 5.

37 Id. at 8-9.

14Therefore, use ofa fabric filter baghouse at Colstrip Units I and 2 will not only greatly reduce particulate, but will also provide for the greatest control ofmercurypollution from these units.

The greater reductions in mercury achievable with installation ofbaghouses at Colstrip Units I and 2 couldhelp address mercury deposition levels in eastern Montana. Studies sponsoredbyEPA demonstratethat up to 70 percent oflocal deposition ofmercury from power plants and industrial sources canbe 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 Bighornreservoir 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'sproposed PM limit J for non-mercury metal HAPs.

, 

## f Updated PM controls will also benecessary at Colstrip Units 1 and 2 to meet EPA's j proposed PM limit for non-mercurymetal 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 closeto 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

benecessary for Colstrip Units 1 and 2 to meet a total PM MACT limit of0.03 IbIMMBtu. As I. I previously stated, a baghouse is typicallymore effective in removing PMthan an ESP. This is especiallytrue 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 theydo not control fine particulate as well as baghouses and because they are not generally capable ofadditional control ofotherpollutants 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 StationaryPowerPlants," a cold-side ESP for a

38 Gerald Keeler, Matthew Landis, 

### et al., Sources ofMercury Wet Deposition in Eastern Ohio, USA, 40EnvtI. Sci. 

### & Tech. 5874-5881 (Sept. 2006).

39 SeeEPA' 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 ofCleanAirCompanies' information onparticulate controls at http://www.icac.comli4a1pages/index.cfm?pageid=3398

. 42 SeeUS EPA Region 9, Ambient Air Impact Report for DesertRock EnergyProject at 26. (Attachment 15).

15plant burning subbituminous coal willremove approximately 38% ofthe sulfuric acid mistwhile a baghouse will remove 90%.43
Furthermore, the BACT limits for fluorides, another condensableparticulate, are typically the lowest at units that use baghouses along with wet scrubbers. In addition, baghouses 

# I provide improved control offine particulates (Le., PM2.5) as compared to ESPs, as discussed above.

In addition, ifa baghouse was installed upstream ofthe scrubbers at Colstrip Units 1 and 

# I
2, then the scrubber couldbemorereadily optimized for S02removal which would then result in significant reductions in condensable PM emissions. 

# I

New PM controls will be required to meet the PM limit oftheproposedEGUMACT 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 scrubberto be optimized for S02 control. In its 

## f f regulatoryimpact analysis for the proposed EGUMACT rule, EPA assumed that many EGUs would need to be retrofitted withbaghouses to meet the total PM limit.44 And, it mustbe noted 

### t that the compliance timeframe ofthe EGUMACT rule will be similarto 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 bythe Clean AirAct), existing sources will berequired to comply with the MACT rule within three years of promulgation orby approximatelythe end of2014. The Companyhas a similartimeframe in which to meet BARTrequirements. These otherrequirements shouldbe taken into account in evaluating BART for PM at Colstrip Units 1 and 2.

In sum, installation ofnew PM control devices at Colstrip Units 1 and 2 is necessary and justified underthe BARTrequirements ofthe regional haze rule. Installation ofa baghouse oran ESP upstream ofthe scrubber at each Colstrip unit is very cost effective, with installation ofa baghouse being the most cost effective at 

### $140lton compared to $172/ton for an ESP. A baghouse is a superiorparticulate control device to an ESP because it is the best system of continuous PM emissionreduction, and a baghouseprovidesbetter abilityto control fine particulate matter and acid gases. Further, the installation ofa baghouse typicallyprovides for much higher mercuryremoval 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 AcidEmissions from Stationary Power Plants," Version 2010a, Table 4-4 at 4-20. The F2 factors inthe table represent the fraction of SAM in the flue gas after the ESP orbaghouse, 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 currentlyremoving approximately 75% S02 emissions with the existing venturi scrubbers and the units' S02 emissionrates are typically 0.40 IblMMBtu ona 30-dayrolling average. See August 2007 BART Assessment Colstrip Generating Station at 4-15 to 4-16. This level ofS02 control fails to reflect thebest system ofcontinuous S02 emission reduction that canbe achieved at the Colstrip Units 1 and 2. Additional S02**controls~,** the addition ofa lime-injection system, scrubber upgrades, or scrubberreplacements-would improve visibility and are cost effective.

1. The existing scrubbers are not the best system ofcontinuous S02 emission reduction 

# I

Accordingto the available information onthe coal used at Colstrip, it appears that the I Company overstated the S02 removal efficiencybeing achieved with the venturi scrubbers at 

## I Colstrip Units 1 and 2. The Company has indicated that the PowderRiver Basin coal burned at 

# I Colstrip has a sulfur content of0.7%. See Addendum to Montana PPL's Colstrip BART Report at 2-1. According to data in a USGS Report, Rosebud mine coal, which Colstrip bums, has an average sulfur content of0.65% 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 IblMMBtu. However, this does not reflect the amount ofS02 going to the scrubber, as some of 

# I

the sulfur inthe coal falls out in the bottom ash ofthe boiler. According to EPA, "[o]naverage, about 95 percent ofthe sulfurpresent inbituminous coal will be emitted asfaseous SOx, whereas somewhat less will be emitted when subbituminous coal is fired.'.4 Using EPA's AP42 emission factors for subbituminous coal-firedboilers 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 bythe Company. This is a substandard level ofS02 removal for a coal-fired boiler and fails to reflect the best system ofcontinuous S02 emissionreductions that could be achieved at Colstrip Units I and 2.

45 See ChapterPC, Colstrip Coalfield, PowderRiver Basin, Montana: Geology, Coal Quality, and Coal Resources, inU.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 ofcoal burned of35 x sulfur content for tangentially-fired subbituminous coal-fired units.

17j 2. Scrubberupgrades should be required to achieve lower S02 limits. 

## r**~** 

# ) Based onthe Company's supplemental BART analysis, the S02 removal efficiencyof the existing scrubbers at Colstrip Units 1 and 2 could beimproved with the injection oflime 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 ofadding a lime injection system to a scrubber that is achieving at least 50% S02 removal. 

# !

r The Companyhas expressed concerns with lime injection that, due to lime scaling and 

## t the fact that the scrubber has no spare scrubbermodule, the scrubber module will need to be I taken offlinemore 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 limestonebasedwet scrubber, and techniques are available to deal with this issue, one optionto deal with this issue is the use ofmagnesium-enhanced lime. Magnesium enhanced lime has been used inFGD systems since the 1970's, and it has beencapable ofhigh S02removal with little scaling, thus providing for a high availability.48 According to vendor literature onthis technology, magnesium-enhanced lime scrubbers are capable ofvery high S02removal efficiencies in excess of95%.49 Itis 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 S02well below that limit) as discussed above,50
Additional upgrades to the scrubbers beyond the addition oflime injection couldbe made to further improve S02removal. Those upgrades could include a redesign ofthe spray headers
ornozzle configuration, improvements to scrubber auxiliary system equipment, other physical changes to improve liquid-to-gas contact, and changes in scrubber chemistryto improve S02 removal. Other changes include improving gas flow distributionthrough ductwork changes, improving spray level coverage, adding frothing trays, increasing liquid to gas ratio (increasing recycle flow), and injecting dibasic acid. 51 While the Companypurportedly 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 PowerPlants, presented at Coal-Tech 2000 International Conference, November 13-14,2000,Jakarta, Indonesia, at 3. Attachment 23.

50 See Weilert, Carl & EmilyMeyer, 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).

18scrubber changes such as installation ofliquid distribution rings and installation ofperforated trays, there are numerous other options that should have been considered to improve liquid to gas contact in the scrubber. Ifan ESP orbaghouse was installed upstream ofthe scrubberand the scrubber was no longer the primaryPM control device, physical design changes couldbe made that could then improve the S02removal efficiency and operatingparameters ofthe scrubber. Forexample, at the Reid Gardner units, theventuri section will be opened up to improve draft flow. Ifthat was done at the Colstrip scrubbers, it could allow for installation ofadditional trays orphysical changes to improve scrubberto gas contact which would improve overall efficiency.

Lower S02 limits shouldbe achievable with scrubberupgrades. The Company only evaluated reducing S02 to an emission rate of0.15 IblMMBtu in evaluating S02 BART. However, based onreview ofthe S02 emission rates achieved at Colstrip Units 3 and 4 as well
as the Reid Gardner units, Colstrip Units 1 and 2 shouldbe able to achieve even lower S02 emissionrates with upgrades to the scrubbers. Colstrip Units 3 and 4 have particle/S02 scrubbers that rely onfly ash and lime injection. According to the company, these units achieve 95% S02 control and S02 emissionrates of0.08 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 oftheir existing particle/S02 scrubber and also have average S02 emissionrates of0.08 IblMMBtu orless.52 As previously stated, the Reid Gardner units do nothave spare scrubbermodules, although Colstrip Units 3 and 4 do. Based onthe available info for these similar units, Colstrip Units 1 and 2 should be able to achieve S02 emissionrates much lower than 0.15 IblMMBtu.

Even ifthe Company claims a spare scrubbermodule wouldbe needed to consistently achieve lower S02 emissionrates, itmustbe noted that EPA's BART guidelines specifically provide for the evaluation ofoptions to improve scrubber availability includingby "increasing auxiliaryequipment 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 ofa spare scrubber module to meet lower S02 emission limits as BART. Given that a 0.15 IblMMBtu emission limit only reflects 89% S02removal 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 ofa the lime injection system, for lowering S02 emissions from Colstrip Units 1 and 2.
3. The Companyhas demonstrated that scrubberupgrades to meet S02 BART 

### are extremelycost effective.
As the Company demonstrated, it is very cost effective to add a lime injection system to improve S02 control at Colstrip Units 1and 2 to meet an S02 emission limit of0.15 IbIMMBtu. The Companydetermined that with a lime injection system, it could continually meet an S02

52 See Attachment 19.

19emission limit of0.15 IbIMMBtu53 at a cost of$486/ton ofS02removed. See June 2008 Addendum to PPL Montana's Colstrip BART Report at 4-1 to 4-2. This is well underthe median cost perton for S02 controls thathave been required as BART as part ofstate 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. SeeNational Park Service's spreadsheet entitled "EGUs with Proposed BART S02 Controls," Attachment 18. EPA recently proposed to require several EGUs in Oklahomato install new S02 controls to meet a BART emission limit of0.06 IbIMMBtu, finding new controls to be cost effective at costs ranging from $1,291 to $2,366 per ton ofS02removed. 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 quitereasonable when compared to the costs other EGUs have to incurto meet BART. 

### I Upgrades to the current scrubbers are well-justified even ifthe Companyinstalls PM controls upstream. Ifan ESP orbaghouse was installed upstream ofthe scrubber, then the amount offly ash entering the wet scrubberwould be significantlyreduced and thus more lime 

### f 

# I ! wouldbe 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 perton ofS02 removed to meet a 0.15 IblMMBtu S02 emission limit wouldbe less than the average costs that are being required to meet S02 BART at similarcoal-fired EGUs.

Even a tripling or quadrupling ofthetotal annual costs given in Table 4.1-4 ofPPL Montana'sJune 2008 Addendum to the Colstrip BART Report would equate to cost effectiveness values of$I,458 to $1,944 perton ofS02 removed. This is less than the average cost for EGUs to meet BART controls of$1,967/tonremoved, and it is within range ofcosts for scrubber upgradesthat are being required as BART. Forexample, Jim BridgerUnits 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 ofS02 removed. Id. Laramie RiverUnits 1 and 3 are required to upgrade scrubbers to meet a 0.15 IblMMBtu limit and the cost effectiveness ofthesecontrols is estimated to be $1,564-$1,571/ton ofS02 removed. Id.
The installation ofbaghouses**u~stream** ofscrubbers at other facilities has not impacted their abilityto meet low levels ofS02. 4 Several EGUs with existing partic1e/S02 scrubbers

53 AlthoughPPLMontana asserted that the scrubbers could achieve 91% S02removal and a 0.15 IblMMBtu emission limit, this removal efficiencyappears to bebased onthe uncontrolled S02 emissions inthe coal rather than the uncontrolled S02 emissionrate at the inlet to the scrubber. An S02 emission limit of0.15 IblMMBtu reflects only 88% to 89% S02 removal
across the scrubberbased on current coal characteristics at Colstrip.

54 Unfortunately, the NevadaDivision ofEnvironmental Protection proposed an S02 BART emission limit for these units of0.15 IblMMBtu as a limit that could be continuouslymet with a reasonable margin ofsafety, see Revised Nevada Division ofEnvironmental Protection BART

20-_

..

### _-----­

have or soon will install baghouses upstream ofthe scrubber and will convert the existing PM/S02 scrubber into a scrubber focused solely on S02removal For example, Units 1 3 at the Reid Gardnerpowerplant 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. Areview 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 of0.08 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, abaghouse is planned to meet PM BART requirements. The scrubber at this unit will benefit from the reduction in particulate loading which will improve S02removal. Arizona Department ofEnvironmental Quality (AZDEQ) has indicated that it will propose an S02BART limit for Cholla Unit 2 of0.15 Ib1MMBtu.56



### At Sherburne County Units 1and 2 which are both equipped with venturi scrubbers with integrated wet ESPs, Minnesota Powerproposed to upgrade the scrubbers to meet BART to achieve an S02 emission limit of0.12 IblMMBtu based on the retrofitting ofthe existing scrubbers with sparger tubes and lime injection.57 

### The cost effectiveness for those scrubber upgrades were projected to be $237 to 238/ton ofS02removed. See National Park Service's spreadsheet entitled "EGUs with Proposed BART S02 Controls," Attachment 18.
Given that other similarEGUs 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 ifabaghouse orESP 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 of0.15 IblMMBtu ifnot lower.
4. EPA should consider the option ofrequiring the Colstrip Units to replace the wet scrubbers with new wet or dry 

### scrubbers to meet S02BART.
The Company has claimed that it is not required to evaluate the option ofinstalling new S02controls because its scrubbers are achieving at least 50% S02removal. This is incorrect as 

# I ! DeterminationReview ofNVEnergy's Reid Gardner Energy Station Units 1,2, and 3, Revised 

## ! October 22, 2009, at 8 (Attachment 20), which provides too high ofa compliance margin than appears necessary based on current S02 data and which does not appear to comply with aproper BART determination.

55 

### See Attachment 19, Spreadsheetwith monthly emissions data for Reid GardnerUnits 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 1and 2, October 25, 2006 at 27 (Attachment 21). 

# I

21



### , 

# I

### EPA's BART guidelines do not preclude evaluation ofreplacement flue gas desulfurization equipment. Ifthe Company claims it cannot upgrade its existing scrubbers to meet high levels of S02control, then the option ofentirely new S02 scrubbers at each unit should be evaluated as BART. New scrubbers could provide significantbenefits in terms ofgreatly 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. Aprime example is the Chiyoda CT-12l FGD. Vendor information for this technology indicates that this scrubberhas achieved 98-99% S02 removal even with low sulfur coa1.58 

### For example, the Chiyoda'sbubblingjet reactorhas consistently achieved >99% S02 removal during long-term operation at the ShinkoKobe powerplant in Japan. This facility consists oftwo 100-MW coal-fired utilityboilers. 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 ofcontrol while treating gases with inlet S02 concentrations of 1.18IbIMMBtu.59 

### This technology hasbeen 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 powerplant,**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 Stuartplant, and AEP's Big Sandy Unit 2, Conesville Unit 4, Cardinal Units 1and 2, and Kyger Creek, among others.64 Black & Veatch and Southern Company are bothU.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 vendorbrochure 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 PowerPlant, PaperNo. 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 Clearthe 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 _FirstWetFlueGasDesulfurizatio 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 SCoal-Fired Generation Units, Press Release, May 2, 200S (http://www.chiyoda

corp.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.chiyoda

corp.comlnews/enl200S/post _11.html).

22to 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 Companyinstalled new state-of-the-art wet scrubbers at Colstrip Units 1 and 2, 

# I
S02 emission limits shouldbebased on no less than 99% S02 removal. Ninety-ninepercent ! I S02 removal would equate to an emission limit oflessthan 0.014IblMMBtu. This would equate to S02 reductions ofapproximately 6,128 tons at each unit, comparedto the company's projected 3,969 tpy S02 reduction with the addition oflimeto 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 commonlyused at low sulfur subbituminous coal-fired units for S02 control. With 95% control, the Colstrip units couldmeet S02 emission limits of0.08 IblMMBtu. This would equate to S02 reductions of5,081 tons per year at each unit. Conversionto dry scrubbing 

# , f would have a significant co-benefit oflimiting the wet waste stream that is disposed ofin on-site 

### r holdingponds that leak and have caused well-documented groundwater contamination.7o

l 

### f Either a new wet scrubber or a new dry scrubber wouldprovide for significant further**~** reductions beyondthe S02 reductions projectedbythe Companywith upgrades to the scrubbers 

## I
to achieve a 0.15 IblMMBtu S02limit. Suchnew controls havebeen required as BART for 

# \ S02. For example, Dave Johnston Unit 4 has an existing venturi scrubberthat is designed to achieve 60% S02 remova1. 71 This unit is beingrequired to install a new dry scrubber and a

65 Jonas S. Klingspor, Kiyoshi Okazoe, Tetsu Ushiku, and George Munson, High Efficiency Double ContactFlow Scrubber for the U.S. FGD Market, PaperNo. 135 presented at MEGA Symposium, Air & WasteManagement Association, May 19-22,2003,p.8, Table4, Attachment 26. 

## r

66 Yoshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, Commercial Experience and ActualPlant-Scale TestFacility ofMHI Single TowerFGD, Attachment 27.

67 Mitsubishi High S02 Removal Experience, Attachment 28.

68 Projected emission reductions were calculatedbased on the average heat input capacityper boiler of3,940 MMBtuJhr and an assumed 92% design capacity factor. See June 2008 Addendum to PPLMontana's Colstrip BARTReport, Ex. 2, Table 4.1-3. This table includes PPL Montana'sprojected S02 emissionreductions 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 powerplant in Wyoming wouldrequire PacifiCorp to replace the existing Unit 4 wet venturi scrubber with a full-scale fabric filter for PMcontrol. See Attachment 10 at 49. And although not adopted byWyoming, PacifiCorp proposed a fabric filter and dryFGD inplace ofthe wet venturi scrubber as BART for S02. Id. A similar conversion to dryhandling should also be feasible for Colstrip. 

# I

71 See Weilert, Carl & EmilyMeyer, Burns & McDonnell, UtilityFGD Design Trends at 11 I**~.** ! (Attachment 29). 

# t 

# ! l £ 23baghouse 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 notbe 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 emissionreduction. Ifthe costs ofcontrol are reasonable when compared to the costs ofcontrol that other EGUs are required to incurto meet BART requirements, then such controls should berequired as BART. There is no question that such controls will improve visibility in Montana's Class I areas, given that the Company already showed thatjustmeeting an S02 emission limit of0.15 IblMMBtu based on lime injection to the scrubbers wouldprovide 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 orreplacement would significantly improve visibility. The Company modeled the visibility improvements expected from upgrades to the scrubber to complywith 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 wouldbe 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 onthe information weprovided above, wethink itis likely the units canreduce S02 even further while still being cost effective, and such additional S02 emission reductions will only further improve visibility in the Class I areas inthe region.

6. Related environmental benefits ofimproved 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 airpollutants such as hydrogen chloride and hydrogen fluoride will bereduced 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 scrubberupgrades 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 Iefficiencyto meet acid gas MACT requirements. The Colstrip units will have to complywith the acid gas MACT requirements bythe end of2014, which is a similarrequirement 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 efficiencyofthe scrubbers at Colstrip Units 1 and 2 will also result in reductions on condensable PM, whichwill not onlybenefit visibilitybut will also help the Colstrip units to complywith EPA'sproposed 0.03 IblMMBtu MACT standard on total PM emissions that EPA has proposed as a surrogate for non-mercurymetal hazardous airpollutants. 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 existingwet scrubber with a state-of-the-art dry scrubbercould significantly limit the amount ofwet waste stored in the Company's leaking holding ponds. Indeed, the Company mayberequired to switch to dryhandling procedures in any event to address ongoing violations ofits state MajorFacility SitingActcertificate ofcompliance. Investment in 

### dry scrubbing technology would therefore serve the additional purpose ofreducing harmful groundwatercontamination due to the Company's leaking holding ponds.

In sum, the Companyhas 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 companyhas shown that meeting such a limit will provide for noticeable improvements to visibility. Based onthis 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

i baghouse upstream oftheexisting 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 ofat least 0.15 IbIMMBtu wouldbecost 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 greaterreductions in S02 emissions and greater benefits to regional haze.


### E. Cumulative Impact and BenefitMustbe Considered as PartofFifth Step in BART Analysis 

# I**~,** The cumulative impact ofa Colstrip's emissions on visibility as well as the cumulative benefit ofemission reductions must be considered as part ofthe fifth step in the BART analysis. In this regard we support the National Park Service'sreasoning 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 considerboth the degree ofvisibility improvement in a given Class 

### 1area as well as the cumulative effects ofimproving

25 

# Ivisibility across all ofthe 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, 

### itdoes 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"bythe BART source. Itfollows 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 areaparks 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 EPAregions as well as the federal land management agencies have assessed the cumulative impact and benefits ofBART sources within theirjurisdiction. 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 FORCOLSTRIPUNITS 3 AND 4
The FIP should establish emissions controls for Colstrip Units 3 and 4 as part ofits long­ 

## f term strategy for achieving reasonableprogress toward meeting natural visibility conditions at 

# f mandatory Class I areas by2064. 40 C.F.R. § 51.308(d)(1)(i)(B). The FIP's reasonable 

## t progress goals "mustprovide for improved visibility on the most impaired days and ensure no degradation in visibility for the least impaired days." Id. Indeveloping its long-term strategy for meeting reasonableprogress goals, EPAmust consider all anthropogenic sources ofvisibility ! impairment and evaluate different emissionreduction strategies beyond those prescribed bythe BART provisions. 40 C.F.R. §51.308(d). EPA should consider "majorand minor stationary sources, mobile sources and area sources." Id. Given the substantial contribution ofColstrip 

# I

Units 3 and 4 to visibility impairment intheregion's Class I areas, EPA's long-term strategy for meeting reasonableprogress 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 considerimposing SCR
onColstrip Units 3 and 4. At a minimum, regardless ofBART applicability and determinations, 

# I

EPA is required to demonstrate that "ithas included in its implementationplan 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 I
26 

## f Ito 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, emitroughlytwo-thirds ofthe NOx from the Colstrip powerplant. Althoughthese 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 emissionrates of0.17 IblMMBtu, according to the Company. See January 31, 2011 submittal from PPLMontana to EPA regarding Colstrip Units 3 and 4, Ex. 2 at 6.
The Company'sJanuary 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 ConsentDecreethat includes requirements to satisfy Condition 7 ofits 1979 prevention ofsignificant deterioration (PSD) permit. Id., Ex. 2 at 4. Condition 7 oftheir PSDpermit required the companyto conduct a "BART analysis" for NOx to address visibility impairment that the Colstrip Units 3 and 4 were 

# I

projected to cause on the Northern Cheyenne Indian Reservation Class I area. Id. 

# I Contraryto 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 isknown as "reasonably attributable" visibility impairment, where visibility impairment in a Class I area isreasonably attributable to a source. Further, Condition 7 was included to address visibility impairment for a non-mandatory Class I area-theNorthern 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 bynumerous 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 ofourknowledge, the Companyhas 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 hazerequirement. Thus, the Company's claimthat 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).
Itwould be difficult to support the NOx requirements ofthe Consent Decree as meeting BART. Specifically, the Consent Decree specifiesNOx limits ofO.181blMMBtu when loads
are above 400 MW and 0.30 IblMMBtu when loads are less than orequal to 400 MW, applicable
on a 30-dayrolling average. The ConsentDecree also sets 24-hour average limits of0.25 IblMMBtu at loads above 400 MW and 0.30 IblMMBtu at loads less than or equal to 400 MW. SeeJanuary 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 emittingNOx at a rate of0.17 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 emissionrates, the annual averageNOx rates 

# \

27 

# I iindicate 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'spresumptive BART limits in 40 C.F.R. Part 51, Appendix Y, do not includeprovisions for increased NOx emission rates at lower loads, and yet the majority ofEPA'spresumptive NOx limits are basedontheuse of combustion controls like low NOx burners and overfire air.72 In fact, ifColstrip Units 3 and 4 need higherNOx limits during lower loads, this indicates that the low NOx concentric firing burners and separated overfire air currentlyinstalled at Colstrip Units 3 and 4 do not reflect the best system ofcontinuous emissionreduction required to meet BART. Clearly, these units also are not achieving emissionrates reflective ofthebest system of NOx reductions for coal-fired utilityboilers. 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 presumptiveNOx BART limit for tangentially-fired units like Colstrip Units 3 and 4 of0.15 IbIMMBtu. Thus, these Colstrip units can achieve lowerNOx emissionrates and, clearly, the emission limits ofthe Consent Decree are not reflective ofBART 

# I

oremission limits necessary to meet reasonableprogress goals under the regional haze program. 

## t It is also questionable that the low NOx concentric firing burners with SOFA currently installed at ColstripUnits 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 letterregarding NOx BART for Colstrip Units 1 and 2, ultra low NOx burners are available that 

# I

can achieve NOx emissionrates lower than 0.17IbIMMBtu, as low as 0.13 IblMMBtu.73

SCR is the best choice to reduce NOx at Colstrip Units 3 and 4, due to the very low NOx emission rates that canbe achieved and the significantbenefits to visibility that couldbe obtained with SCR. As we have discussed in this letterregarding 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 beenrequired to meetbest available control technology and otherrequirements and have been achieved in practice at numerous units.74 Given how the Company's cost evaluation ofSCR for Colstrip Units 1 and 2 showed that SCR would be cost effective when compared to the costs that otherpowerplant owners have to meet under regional haze requirements, onewould expectthe 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. IfSCRwas 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 ofNOx 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 PPLMontana's Colstrip BART Report at 5-6 and Appendix 2 (Table 5.5-3). Similar improvements in visibility should occur with the installation ofSCR at Colstrip Units 3 and 4. Thus, installation ofSCR at Colstrip Units 3 and 4 should significantly improve visibility.
In summary, EPA must evaluate additional controls onNOx 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 inthe Montana, Wyoming, andNorth Dakota Class I
areas impacted bythe Colstrip powerplant. Based on the informationprovided for NOx BART for Colstrip Units 1 and 2, SCR shouldberequired 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 alsojustified for Colstrip Units 3 and 4 to meet reasonable progress requirements. The Companyhas 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 ofalkaline fly ash. Thus, the company indicated that ifa 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 ofS02 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 PPLMontanato 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 eachhas a spare absorber. The companyhas 

# 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 orESPs upstream ofscrubbers, and no issues ofreduced S02 removal have been raised. Inthe discussion ofPM BART for Colstrip Units 1 and 2 in this letter, we have provided examples ofotherpowerplant 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 existingparticle/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 lengthyperiod that Unit 4 was not operated in 2009), assuming current NOx emissionrates of0.17 IblMMBtu and a controlled NOx emission rate 

# I I with SCRofO.041blMMBtu.

76 See, e.g., Attachments 20 and 21. 

# I

29 

### f 

# r 1with thereduced levels ofS02 removal due to the removal ofash upstream ofthe scrubbers.77 Thus, we question the Company's assumption that it could not operate or, ifnecessary, upgrade its existing scrubbers to achieve the same levels ofS02 removal ifa baghouse or ESP were added upstream ofthe scrubbers. Forexample, the Companycould add more lime and/or make otherphysical changes to the scrubber to improve the effectiveness ofthe scrubberifa 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.

EPARegion 9 found that theparticle scrubbers at Four Comers Units 1-3 were causing a secondaryplumethat was adverselyimpacting visibility. Region 8 should conduct a similar analysis for the Colstrip powerplant units. As Region 9 stated, venturi particle scrubbers are hardlyused anymore for particulate control at coal-fired EGUs due to their substandardremoval ofparticulates, and especially fine particulates, in comparisonto a baghouse orESP. See 75 Fed. Reg. 64231 (Oct. 19, 2010). Ifthe scrubbers at Colstrip are causing a secondaryplume, then installation ofa baghouse or an ESP upstream ofthe scrubber will significantly improve visibility.


### In addition, Colstrip Units 3 and 4 will likelyneed to upgrade PM controls to meet EPA's forthcoming MACTrule. Specifically, EPA has proposed a PM limit of0.03 IblMMBtu as a surrogate for non-mercury metal HAPs. EPA'sproposed limit is a limit ontotal particulate matter (filterable plus condensable PM). The Colstrip Units 3 and 4 emitted filterable PM at a rate ofO.026lblMMBtu on average overthe past five years. See January 31,2011 submittal from PPLMontanato EPA regarding Colstrip Units 3 and 4, Ex. 2 at 15. With condensable PM added in, these units undoubtedly emit total PM atrates exceeding EPA'sproposedPM MACT standard of0.03 IbIMMBtu. Thus, the Company will likely need to upgrade PM controls and/or S02 controls to meet EPA'sproposed MACT limit ontotal PM of0.03 IblMMBtu. Further, improvements in PM controls maybenecessaryto meet EPA'sproposed mercuryMACT limits,
as discussed in this letter regarding Colstrip Units 1 and 2. EPA should considerthese future regulations in determining regional haze plan requirements for Colstrip Units 3 and 4. Ifthe units are going to haveto install PM controls, whetherupstream or downstream ofthe scrubbers, to meet MACT, then EPA should impose appropriate emission limits inthe regional haze plan reflective ofthese forthcoming rules and the benefits that these forthcoming rules will have for visibility inthe Class I areas in the region.
Further, the Colstrip Units 3 and4 are emitting S02 at much lowerrates than currently allowed in the applicable requirements. Specifically, although Units 3 and 4 are currently emitting S02 at a rate of0.08 IbIMMBtu, the units are subject to much less restrictive S02 emission limits of0.18 IblMMBtu on a calendar day average. SeeJanuary 31, 2011 submittal from PPLMontana 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 inthe 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.

30rate currentlybeing achieved at these units to ensure that no future degradation in visibilitydue to these units' S02 emissions is allowed.

For all ofthe above reasons, EPA should, at the minimum, impose PM limits reflective of compliance with its proposed MACT standards and impose S02 limits reflective ofcurrent levels ofS02 emission rates in the Montana regional haze plan. EPAmust impose limits that
ensure reasonableprogress towards the national visibility goal and also ensure theprevention 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 bepleased to answer any questions you have. We look forward to ourmeeting 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, DeputyAssistant Regional Administrator for the Office ofPollution Prevention and Regulatory Assistance Laurel Dygowski, Environmental Protection Specialist MonicaMorales, Unit Chief, Air QualityPlanning Unit SaraLaumann, Attorney Vanessa Hinkle, Air QualityPlanningUnit Anne Hedges, Montana Environmental Information Center SanjayNarayan and Doug Howell, Sierra Club Stephanie Kodish, National Parks Conservation Association Vicki Stamper



### 31 

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# I

f 

# I t

, 

# l !

# I I

### I ATTACHMENTS



# , f 

# I 1 Attachment Number Description 1 Bryk, S.A. et aI., First Commercial Application ofDRB-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 withproposed BARTNOx Controls Mar2011." 3 Institute ofClean AirCompanies, 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 PSDpermit. 6 National Park Service spreadsheet on BACT limits for New PC PowerPlants. 7 Florida Source Tests com2ilation. 8 Matt Haber, BestAvailable Control Technologiesfor the Baldwin GeneratingStation, 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 PowerPlant. 10 May28, 2009 WY DEQ BARTApplication Analysis for Pacificorp Dave Johnston PowerPlant. 11 EPA's Technical SupportDocument, ProposedRule: Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology at FourCorners PowerPlant: Navajo Nation. 12 McIlvaine Hot Topic Hour, FilterMedia Selection for CoalFired Boilers, September 13,2007,Presentation by Todd Brown, Daikin America, Inc. 13 USEPA, ETVJoint 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-6001R03-110 (October 2003). 15 US EPARegion 9, Ambient Air Impact Report for Desert Rock EnergyProject. 16 EPRI's "Estimating Total Sulfuric Acid Emissions from StationaryPowerPlants," Version 201Oa. 17 EPA, Regulatory Impact Analysis ofthe 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 CleanAir Markets Database. 20 Revised NevadaDivision ofEnvironmental ProtectionBART Determination Review ofNV Energy's Reid GardnerEnergy 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 AmericaTechnologyCenter, Pittsburgh, PA. 23 Nolan, Paul S., Babcock & Wilcox Co., Flue Gas Desulfurization Technologies for Coal-Fired PowerPlants, presented at Coal-Tech 2000 International Conference, November 13-14,2000, Jakarta, Indonesia. 24 Black & Veatch vendorbrochure 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 PowerPlant, PaperNo. 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, PaperNo. 135 presented at MEGA Symposium, Air & Waste Management Association. 27 Yoshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, Commercial Experience and Actual-Plant-Scale Test Facility ofMHI Single TowerFGD. 28 Mitsubishi High S02 Removal Experience. 29 Weilert, Carl & EmilyMeyer, 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-AWMA Combined Power Plant AirPollutant Control Mega Symposium, 2008.

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