Vol. 77 Tuesday, 

No. 181 September 18, 2012 

Part III 

Environmental Protection Agency 

40 CFR Part 52 

Approval and Promulgation of Implementation Plans; State of Montana; 

State Implementation Plan and Regional Haze Federal Implementation 

Plan; Final Rules 


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57864 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R08–OAR–2011–0851, FRL 9719–9] 

Approval and Promulgation of 

Implementation Plans; State of 

Montana; State Implementation Plan 

and Regional Haze Federal 

Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is promulgating a Federal 

Implementation Plan (FIP) to address 

regional haze in the State of Montana. 

EPA developed this FIP in response to 

the State’s decision in 2006 to not 

submit a regional haze State 

Implementation Plan (SIP) revision. The 

FIP satisfies requirements of the Clean 

Air Act (CAA or ‘‘the Act’’) that require 

states, or EPA in promulgating a FIP, to 

assure reasonable progress towards the 

national goal of preventing any future 

and remedying any existing man-made 

impairment of visibility in mandatory 

Class I areas. In addition, EPA is 

approving one of the revisions to the 

Montana SIP submitted by the State of 

Montana through the Montana 

Department of Environmental Quality 

on February 17, 2012, specifically, the 

revision to the Montana Visibility Plan 

that includes amendments to the 

‘‘Smoke Management’’ section, which 

adds a reference to Best Available 

Control Technology (BACT) as the 

visibility control measure for open 

burning as currently administered 

through the State’s air quality permit 

program. This change was made to meet 

the requirements of the Regional Haze 

Rule. EPA will act on the remaining 

February 17, 2012 revisions in the 

State’s submittal in a future action. 

DATES: This final rule is effective 

October 18, 2012. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–R08–OAR–2011–0851. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

e.g., Confidential Business Information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

www.regulations.gov, or in hard copy at 

the Air Program, Environmental 

Protection Agency (EPA), Region 8, 

1595 Wynkoop Street, Denver, Colorado 

80202–1129. EPA requests that if at all 

possible, you contact the individual 

listed in the FOR FURTHER INFORMATION

CONTACT section to view the hard copy 

of the docket. You may view the hard 

copy of the docket Monday through 

Friday, 8 a.m. to 4 p.m., excluding 

Federal holidays. 

FOR FURTHER INFORMATION CONTACT: 

Scott Jackson, Air Program, Mailcode 

8P–AR, Environmental Protection 

Agency, Region 8, 1595 Wynkoop 

Street, Denver, Colorado 80202–1129, 

(303) 312–6107, or 

Jackson.Scott@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Definitions 

For the purpose of this document, we 

are giving meaning to certain words or 

initials as follows: 

• The words or initials Act or CAA 

mean or refer to the Clean Air Act, 

unless the context indicates otherwise. 

• The initials A/F mean or refer to airto-fuel. 

• The initials ALM mean or refer to 

Ammonia Limiting Method 

• The initials ARM mean or refer to 

Administrative Rule of Montana. 

• The initials ARP mean or refer to 

the acid rain program. 

• The initials ARS mean or refer to 

Air Resources Specialists. 

• The initials ASOFA mean or refer to 

advanced separated overfire air. 

• The initials BACT mean or refer to 

Best Available Control Technology. 

• The initials BART mean or refer to 

Best Available Retrofit Technology. 

• The initials CAA mean or refer to 

the Clean Air Act. 

• The initials CAM mean or refer to 

compliance assurance monitoring. 

• The initials CAMD mean or refer to 

EPA Clean Air Markets Division. 

• The initials CAMx mean or refer to 

Comprehensive Air Quality Model. 

• The initials CBI mean or refer to 

confidential business information. 

• The initials CCM mean or refer to 

EPA Control Cost Manual. 

• The initials CCOFA mean or refer to 

close-coupled overfire air system. 

• The initials CDS mean or refer to 

circulating dry scrubber. 

• The initials CGA mean or refer to 

gas cylinder audit. 

• The initials CELP mean or refer to 

Colstrip Energy Limited Partnership. 

• The initials CEMS mean or refer to 

continuous emissions monitoring 

systems. 

• The initials CEPCI mean or refer to 

Chemical Engineering Plant Cost Index. 

• The initials CFAC mean or refer to 

Columbia Falls Aluminum Company. 

• The initials CFB mean or refer to 

circulating fluidized bed. 

• The initials CKD mean or refer to 

cement kiln dust. 

• The initials CMAQ mean or refer to 

Community Multi-Scale Air Quality 

modeling system. 

• The initials CPMS mean or refer to 

continuous parametric monitoring 

system. 

• The initials CO mean or refer to 

carbon monoxide. 

• The initials CPI mean or refer to 

Consumer Price Index. 

• The initials CRF mean or refer to 

Capital Recovery Factor. 

• The initials CSAPR mean or refer to 

Cross-State Air Pollution Rule. 

• The initials DAA mean or refer to 

Dry Absorbent Addition. 

• The initials DPCS mean or refer to 

digital process control system. 

• The initials D-R mean or refer to 

Dresser-Rand. 

• The initials DSI mean or refer to dry 

sorbent injection. 

• The initials EC mean or refer to 

elemental carbon. 

• The initials EGU mean or refer to 

Electric Generating Units. 

• The words EPA, we, us or our mean 

or refer to the United States 

Environmental Protection Agency. 

• The initials ESP mean or refer to 

electrostatic precipitator. 

• The initials FCCU mean or refer to 

fluid catalytic cracking unit. 

• The initials FGD mean or refer to 

flue gas desulfurization. 

• The initials FGR mean or refer to 

flue gas recirculation. 

• The initials FIP mean or refer to 

Federal Implementation Plan. 

• The initials FLMs mean or refer to 

Federal Land Managers. 

• The initials HAR mean or refer to 

hydrated ash reinjection. 

• The initials HDSCR mean or refer to 

high-dust selective catalytic reduction. 

• The initials HC mean or refer to 

hydrocarbons. 

• The initials gr/scf mean or refer to 

grains per standard cubic foot. 

• The initials IMPROVE mean or refer 

to Interagency Monitoring of Protected 

Visual Environments monitoring 

network. 

• The initials IPM mean or refer to 

Integrated Planning Model. 

• The initials IWAQM refer to 

Interagency Workgroup on Air Quality 

Modeling. 

• The initials LDSCR mean or refer to 

low-dust selective catalytic reduction. 

• The initials LEA mean or refer to 

low excess air. 

• The initials LNBs mean or refer to 

low NOX burners. 


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• The initials LSD mean or refer to 

lime spray drying. 

• The initials LSFO mean or refer to 

limestone forced oxidation. 

• The initials LTS mean or refer to 

Long-Term Strategy. 

• The initials MACT mean or refer to 

maximum achievable control 

technology. 

• The initials MATB mean or refer to 

Montanan’s Against Toxic Burning. 

• The initials MDEQ mean or refer to 

Montana’s Department of 

Environmental Quality. 

• The initials MDF mean or refer to 

medium density fiberboard. 

• The initials MISO mean or refer to 

Midwest Independent Transmission 

System Operator. 

• The initials MDU mean or refer to 

Montana-Dakota Utilities Company. 

• The initials MEL mean magnesiumenhanced lime. 

• The initials MKF mean or refer to 

mid-kiln firing of solid fuel. 

• The words Montana and State mean 

the State of Montana. 

• The initials MSCC mean or refer to 

Montana Sulphur and Chemical 

Company. 

• The initials NAAQS mean or refer 

to National Ambient Air Quality 

Standards. 

• The initials NC mean or refer to 

North Carolina. 

• The initials ND mean or refer to 

North Dakota. 

• The initials NEI mean or refer to 

National Emission Inventory. 

• The initials NESHAP mean or refer 

to National Emission Standards for 

Hazardous Air Pollutants. 

• The initials NH3 mean or refer to 

ammonia. 

• The initials NOX mean or refer to 

nitrogen oxides. 

• The initials NP mean or refer to 

National Park. 

• The initials NPS mean or refer to 

National Parks Service. 

• The initials NSCR mean or refer to 

non-selective catalytic reduction. 

• The initials NSPS mean or refer to 

New Source Performance Standards. 

• The initials NWR mean or refer to 

National Wildlife Reserve. 

• The initials OMB mean or refer to 

the Office of Management and Budget. 

• The initials OC mean or refer to 

organic carbon. 

• The initials OFA mean or refer to 

overfire air. 

• The initials PC mean or refer to 

pulverized coal. 

• The initials PH/PC mean or refer to 

preheater/precalciner. 

• The initials PM mean or refer to 

particulate matter. 

• The initials PM2.5 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers 

(fine particulate matter). 

• The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers 

(coarse particulate matter). 

• The initials PMCD mean or refer to 

particulate matter control device. 

• The initials ppb mean or refer to 

parts per billion. 

• The initials ppm mean or refer to 

parts per million. 

• The initials PRB mean or refer to 

Powder River Basin. 

• The initials PSAT mean or refer to 

Particulate Matter Source 

Apportionment Technology. 

• The initials PSD mean or refer to 

Prevention of Significant Deterioration. 

• The fraction Q/D means quantity of 

emissions over distance. 

• The initials RAA mean or refer to 

relative accuracy audit. 

• The initials RATA mean or refer to 

relative accuracy test audit. 

• The initials RAVI mean or refer to 

Reasonably Attributable Visibility 

Impairment. 

• The initials RICE mean or refer to 

Reciprocating Internal Combustion 

Engines. 

• The initials RMC mean or refer to 

Regional Modeling Center. 

• The initials ROFA mean or refer to 

rotating opposed fire air. 

• The initials RP mean or refer to 

Reasonable Progress. 

• The initials RPG or RPGs mean or 

refer to Reasonable Progress Goal(s). 

• The initials RPOs mean or refer to 

regional planning organizations. 

• The initials RRI mean or refer to 

rich reagent injection. 

• The initials RSCR mean or refer to 

regenerative selective catalytic 

reduction. 

• The initials SCOT mean or refer to 

Shell Claus Off-Gas Treatment. 

• The initials SCR mean or refer to 

selective catalytic reduction. 

• The initials SDA mean or refer to 

spray dryer absorbers. 

• The initials SIP mean or refer to 

State Implementation Plan. 

• The initials SMOKE mean or refer to 

Sparse Matrix Operator Kernel 

Emissions. 

• The initials SNCR mean or refer to 

selective non-catalytic reduction. 

• The initials SO2 mean or refer to 

sulfur dioxide. 

• The initials SOFA mean or refer to 

separated overfire air. 

• The initials SRU mean or refer to 

sulfur recovery unit. 

• The initials TAC mean or refer to 

Texas Administrative Code. 

• The initials TESCR mean or refer to 

tail-end selective catalytic reduction. 

• The initials TCEQ mean or refer to 

Texas Commission on Environmental 

Quality. 

• The initials tpy mean tons per year. 

• The initials TSD mean or refer to 

Technical Support Document. 

• The initials URP mean or refer to 

Uniform Rate of Progress. 

• The initials USFWS mean or refer to 

U.S. Fish and Wildlife Service. 

• The initials VOC mean or refer to 

volatile organic compounds. 

• The initials WA mean or refer to 

Wilderness Area. 

• The initials WEG mean or refer to 

WildEarth Guardians. 

• The initials WEP mean or refer to 

Weighted Emissions Potential. 

• The initials WETA mean or refer to 

Western Environmental Trade 

Association. 

• The initials WRAP mean or refer to 

the Western Regional Air Partnership. 

• The initials YELP mean or refer to 

Yellowstone Energy Limited 

Partnership. 

Table of Contents 

I. Background 

II. Basis for Our Final Action 

III. Final Action 

IV. Issues Raised by Commenters and EPA’s 

Responses 

A. Comments on Modeling 

B. General Comments on BART 

C. Comments on Cement Kilns 

D. Comments on Ash Grove 

E. Comments on Holcim 

F. Comments on CFAC 

G. Comments on Colstrip Units 1 and 2 

H. Comments on Corette 

I. Comments on Reasonable Progress and 

Long Term Strategy 

J. Comments on Colstrip 3 and 4 

K. Comments on Devon Energy 

L. Comments on Montana Dakota Utilities 

M. Comments on Montana Sulphur and 

Chemical Company 

N. Comments on Health, Ecosystem 

Benefits, Other Pollutants, and Coal Ash 

O. General Comments Supporting Our 

Proposal or for Stricter Controls 

P. General Comments That The Proposal Is 

Too Stringent 

Q. Comments on Visibility Improvement 

and Other Causes of Haze 

R. Comments on Cost, Economic Impact, 

Jobs and Price to Consumers 

S. Comments About Other Forms of Energy 

T. Other Miscellaneous Comments 

V. Changes From Proposed Rule and Reasons 

for the Changes 

A. Emission Limits for Corette 

B. Changes to 40 CFR 52.1396(c)(2)— 

Emission Limitations for Cement Kilns: 

C. Change to 40 CFR 52.1396(d)— 

Compliance date: 

D. Change to 40 CFR 52.1396(e)(3)—CEMS 

for cement kilns: 

E. Change to 40 CFR 52.1396(e)(4)(ii)— 

Compliance determination methods for 

SO2 and NOX at cement kilns: 

F. Change to 40 CFR 52.1396(f)(1) and 

(f)(2)—Compliance determinations for 


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PM BART limits at EGUs and cement 

kilns: 

G. Change to 40 CFR 52.1396(f)(2)— 

Compliance determinations for cement 

kiln PM BART limits: 

H. Change to 40 CFR 52.1396(h)(6)— 

Recordkeeping requirements for cement 

kilns: 

I. Change to 40 CFR 52.1396(i)—Reporting: 

J. Change to 40 CFR 52.1396(i)(1) and 

(i)(2)—Reporting for CEMS for SO2 and 

NOX: 

K. Changes to 40 CFR 52.1396 for Devon 

Energy, Blaine County #1 Compressor 

Station 

VI. Statutory and Executive Order Reviews 

I. Background 

We signed our notice of proposed 

rulemaking on March 20, 2012, and it 

was published in the Federal Register 

on April 20, 2012. In that notice, we 

proposed a FIP to address regional haze 

in the State of Montana for the first 

implementation period (through 2018) 

including determinations of Best 

Available Retrofit Technology (BART) 

for specific sources subject to that 

requirement. 77 FR 23988. Montana did 

not submit a SIP, knowing that as a 

consequence EPA would be required to 

propose and finalize a FIP. A detailed 

explanation of the CAA’s visibility 

requirements and the Regional Haze 

Rule as it applies to Montana was 

provided in the notice of proposed 

rulemaking and will not be restated 

here. In that notice, we also proposed to 

approve a revision to the Montana SIP 

submitted by the State of Montana 

through the Montana Department of 

Environmental Quality on February 17, 

2012. The State’s submittal contained 

revisions to the Montana Visibility Plan 

that included amendments to the 

‘‘Smoke Management’’ section, which 

adds a reference to Best Available 

Control Technology (BACT) as the 

visibility control measure for open 

burning as currently administered 

through the State’s air quality permit 

program. EPA’s rationale for proposing 

approval of the revisions to the Montana 

Visibility Plan that included 

amendments to the ‘‘Smoke 

Management’’ section was described in 

detail in the proposal and will not be 

restated here. We note that in the future, 

Montana retains the option of 

submitting a SIP meeting the 

requirements of the Regional Haze Rule, 

to replace the FIP. 

II. Basis for Our Final Action 

We have fully considered all 

significant comments on our proposal, 

and, except as noted in section V, 

below, have concluded that no other 

changes from our proposal are 

warranted. Our action is based on an 

evaluation of Montana’s Visibility SIP 

submittal and our FIP against the 

regional haze requirements at 40 CFR 

51.300—51.309 and CAA sections 169A 

and 169B. All general SIP requirements 

contained in CAA section 110, other 

provisions of the CAA, and our 

regulations applicable to this action 

were also evaluated. The purpose of this 

action is to ensure compliance with 

these requirements. Our authority for 

action on Montana’s Visibility SIP 

submittal is based on CAA section 

110(k). Our authority to promulgate our 

FIP is based on CAA section 110(c). 

III. Final Action 

With this final action we are 

approving Montana’s submittal 

containing revisions to the ‘‘Smoke 

Management’’ section of Montana’s 

Visibility Plan that was submitted by 

the State through the Montana DEQ on 

February 17, 2012. The SIP includes 

amendments to the ‘‘Smoke 

Management’’ section, which adds a 

reference to BACT as the visibility 

control measure for open burning as 

currently administered through the 

State’s air quality permit program as 

meeting the requirement of 40 CFR 

308(d)(3)(v) to consider smoke 

management techniques for agricultural 

and forestry management purposes 

including plans as they currently exist 

within the state for these purposes. We 

are promulgating a FIP for the remaining 

parts of the regional haze requirements. 

Table 1 shows the control technologies, 

associated cost, and emission reductions 

for each source that is subject to the FIP. 

TABLE 1—CONTROL TECHNOLOGIES, COST, EMISSIONS REDUCTIONS AND COST-EFFECTIVENESS

Source Technology 1 Total capital 

cost ($) 

Total 

annualized 

cost ($) 

Annual NOX/SO2 emissions 

reductions (tpy) 

Cost 

effectiveness 

($/ton) 

Ash Grove Cement ................ LNB + SNCR ........................ 1,191,632 2,238,893 1,088 NOX ............................ 2,058 

Holcim, Inc ............................. SNCR .................................... 1,312,800 650,399 556 NOX ............................... 1,170 

Colstrip Unit 1 ........................ SOFA + SNCR ..................... 13,380,673 3,278,964 2,097 NOX ............................ 1,564 

Colstrip Unit 2 ........................ Lime Injection + Additional 

Scrubber Vessel.

28,000,000 4,093,200 4,486 SO2 ............................. 912 

Colstrip Unit 2 ........................ SOFA + SNCR ..................... 13,380,673 3,256,127 2,072 NOX ............................ 1,571 

Colstrip Unit 2 ........................ Lime Injection + Additional 

Scrubber Vessel.

28,000,000 4,093,200 4,129 SO2 ............................. 991 

Devon Energy, Blaine County 

#1 Compressor Station, 

Engine #1.

NSCR .................................... –– 105,000 335 NOX ............................... 282 

Devon Energy, Blaine County 

#1 Compressor Station, 

Engine #2.

NSCR .................................... –– 105,000 335 NOX ............................... 282 

Cumulative Total Annual 

Cost.

............................................... ........................ 13,727,583 

–– Total Capital Cost was not calculated. 

1The technology listed is the technology evaluated as BART, but sources can choose to use another technology or combination of technologies to meet established emission limits. Also where additional control technologies are not required, existing controls may still be necessary 

to meet established emission limits. 

IV. Issues Raised by Commenters and 

EPA’s Responses 

This action addresses comments on 

the Montana Regional Haze FIP. The 

publication of EPA’s proposed rule on 

April 20, 2012 resulted in a 60-day 

public comment period that ended on 

June 19, 2012. We held four public 

hearings for this proposal. Two hearings 

were held in Helena, Montana on 

Tuesday, May 1, 2012 and two hearings 

were held in Billings, Montana on 


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Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57867 

1Protocol for BART-Related Visibility 

Impairment Modeling Analyses in North Dakota 

(Final), North Dakota Department of Health, 

Division of Air Quality, 1200 Missouri Avenue 

Bismarck, ND (Nov 2005), p 32–33. 2POSTUTIL is a part of the suite of programs 

associated with the CALPUFF modeling system and 

is used to repartition ammonia in overlapping puffs. 

The model is available at: http://www.src.com/ 

calpuff/calpuff1.htm. 

3 Interagency Workgroup on Air Quality Modeling 

(IWAQM) Phase 2 Report and Recommendations for 

Long-Range Transport Impacts. EPA–454/R–98– 

019. U.S. Environmental Protection Agency. 

Research Triangle Park, NC (‘‘IWAQM Phase II 

Report’’) (1998), p 18. 

Wednesday, May 2, 2012. During the 

public comment period we received 

numerous written comments from 

individual citizens, members of various 

organizations, and also from Ash Grove 

Cement (Ash Grove), Columbia Falls 

Aluminum Corporation (CFAC), 

EarthJustice, the U.S. Fish and Wildlife 

Service (USFWS), Holcim Inc. (Holcim), 

Montana Dakota Utilities (MDU), 

Montana Sulphur and Chemical 

Company, the National Parks Service 

(NPS), the owners of Colstrip Units 1– 

4, the State of Montana, and WildEarth 

Guardians (WEG). We have reviewed 

the comments and provided our 

responses below. Transcripts from the 

public hearings and full copies of the 

comment letters are available in the 

docket for review. 

A. Comments on Modeling 

Comment: PPL and others stated that 

the proposed BART at Colstrip 1 and 2 

for both NOX and SO2 would result in 

no reasonably anticipated visibility 

benefit, even assuming that EPA’s 

emissions reduction estimates and 

modeling are correct. In one specific 

comment, the commenter stated: 

A projected 0.066 dv is not a visibility 

improvement that ‘may reasonably be 

anticipated to result from the use’ of 

additional scrubber vessels at Colstrip Units 

1 and 2. 42 U.S.C. 7491(g)(2). Such an 

insignificant projected visibility change is 

beyond the modeling capability of the 

CALPUFF model version EPA used and is far 

below the threshold for human perceptibility. 

Response: We disagree that any 

controls required by our action must 

demonstrate a perceptible visibility 

improvement. In a situation where the 

installation of BART may not result in 

a perceptible improvement in visibility, 

the visibility benefit may still be 

significant. The Regional Haze Rule 

states: 

even though the visibility improvement from 

an individual source may not be perceptible, 

it should still be considered in setting BART 

because the contribution to haze may be 

significant relative to other source 

contributions in the Class I area. Failing to 

consider less-than-perceptible contributions 

to visibility impairment would ignore the 

CAA’s intent to have BART requirements 

apply to sources that contribute to, as well 

as cause, such impairment. 

70 FR 39129. 

Visibility impacts below the 

thresholds of perceptibility cannot be 

ignored because regional haze is 

produced by a multitude of sources and 

activities which are located across a 

broad geographic area. As stated in our 

proposal, with respect to Colstrip 1 and 

2, we weighed the relatively low costs 

for lime injection with the additional 

scrubber vessel against the anticipated 

visibility impacts and determined that 

the cost was justified by the visibility 

improvement. Similarly, we weighed 

the relatively low cost of separated 

overfire air (SOFA) + selective 

noncatalytic reduction (SNCR) against 

the anticipated visibility benefit and 

determined that the cost was justified by 

the visibility benefit. 

We respond to the modeling 

capabilities of CALPUFF in a response 

to a later comment. 

Comment: A commenter asserted that 

EPA’s modeling assumes constant levels 

of ammonia and failed to consider 

monitoring data showing that ammonia 

levels are lower during the winter 

months. 

Response: EPA recognizes that there 

can be seasonal variability in ambient 

ammonia concentrations and that it is 

preferable to use ambient ammonia 

measurements when such data are 

available rather than using default 

background ammonia concentrations. 

Ammonia monitoring data is not 

available in Montana, however, 

ammonia monitoring data is available in 

western North Dakota at the Beulah 

monitoring site. Theodore Roosevelt NP, 

located in western North Dakota, is 

impacted by Montana BART sources 

and EPA determined that it would be 

more appropriate to use the North 

Dakota ammonia monitoring data 

instead of using CALPUFF default 

ammonia concentrations. Therefore EPA 

used monthly average measured 

ammonia concentrations shown in 

Table 2 that were measured by North 

Dakota at their Beulah monitoring site.1

The monthly average ammonia 

concentrations values were derived 

from data collected during years 2001– 

2002 and the ambient data were filtered 

to eliminate data from wind directions 

associated with sources causing a local 

bias. North Dakota concluded in its 

regional haze modeling analysis that 

these monthly average ammonia values 

are generally representative of 

background ammonia concentrations in 

western North Dakota. As a result, we 

did not assume a constant level of 

ammonia as asserted by the commenter, 

and we did represent seasonal 

variability in ammonia concentrations. 

Additionally, EPA used the 

POSTUTIL 2 program with the 

Ammonia Limiting Method (ALM) to 

post-process the CALPUFF output to 

correct the assumption of constant 

ammonia availability in the model. The 

CALPUFF model represents multiple 

plumes that can overlap. The default 

model approach assumes that 

background ammonia is fully available 

to form nitrate in each plume. The ALM 

method corrects this assumption by 

partitioning the ammonia between 

overlapping plumes. Therefore, EPA has 

fully accounted for non-constant 

ammonia levels by using monthly 

measured background ammonia and by 

using the ALM in the analysis of 

CALPUFF model results. 

TABLE 2—MONTHLY AMMONIA

BACKGROUND CONCENTRATIONS

Month Value 

(ppb) 

Jan ................................................ 1.22 

Feb ................................................ 1.23 

Mar ................................................ 1.60 

Apr ................................................ 1.94 

May ............................................... 2.29 

Jun ................................................ 1.63 

Jul ................................................. 1.65 

Aug ............................................... 1.69 

Sep ............................................... 0.98 

Oct ................................................ 1.04 

Nov ............................................... 1.37 

Dec ............................................... 1.06 

Comment: A commenter stated that 

EPA failed to acknowledge uncertainty 

in the CALPUFF model at short 

distances, and the commenter further 

argues that model uncertainty increases 

at distances greater than 200 km and has 

a tendency to over predict impacts at 

greater distances. 

Response: The Interagency 

Workgroup on Air Quality Modeling 

(IWAQM) Phase 2 report (EPA, 1998) 3

reviewed model performance 

evaluations of CALPUFF as a function 

of distance from the source and 

concluded that: 

Based on the tracer comparison results 

presented in Section 4.6, it appears that 

CALPUFF provides reasonable 

correspondence with observations for 

transport distances of over 100 km. Most of 

these comparisons involved concentration 

values averaged over 5 to 12 hours. The 

CAPTEX comparisons, which involved 

comparisons at receptors that were 300 km to 

1000 km from the release, suggest that 

CALPUFF can overestimate surface 

concentrations by a factor of 3 to 4. Use of 


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4Anderson, B., K. Baker, R. Morris, C. Emery, A. 

Hawkins, E. Snyder ‘‘Proof-of-Concept Evaluation 

of Use of Photochemical Grid Model Source 

Apportionment Techniques for Prevention of 

Significant Deterioration of Air Quality Analysis 

Requirements’’ Presentation for Community 

Modeling and Analysis System (CMAS) 2010 

Annual Conference, (October 11–15, 2010) can be 

found at http://www.cmascenter.org/conference/ 

2010/agenda.cfm. 5 IWAQM Phase 2 report, p. 27. 

the puff splitting option in CALPUFF might 

have improved these comparisons, but there 

are serious conceptual concerns with the use 

of puff dispersion for very long-range 

transport (300 km and beyond). As the puffs 

enlarge due to dispersion, it becomes 

problematic to characterize the transport by 

a single wind vector, as significant wind 

direction shear may well exist over the puff 

dimensions. With the above thoughts in 

mind, IWAQM recommends use of CALPUFF 

for transport distances of order 200 km and 

less. Use of CALPUFF for characterizing 

transport beyond 200 to 300 km should be 

done cautiously with an awareness of the 

likely problems involved. 

Therefore, we modeled Class I areas 

within 300 km of each BART sources 

but did not model impacts at distances 

exceeding 300 km. 

EPA has acknowledged that there is 

uncertainty in the CALPUFF model 

predicted visibility impacts. However, 

the CALPUFF model can both 

underpredict and overpredict visibility 

impacts. For example, in a presentation 

for the 2010 annual Community 

Modeling and Analysis System 

conference, Anderson et al. (2010) 4

found that the CALPUFF model 

frequently predicted lower nitrate 

concentrations compared to the CAMx 

photochemical grid model which has a 

much more rigorous treatment of 

photochemical reactions. EPA 

recognized the uncertainty in the 

CALPUFF modeling results when EPA 

made the decision, in the final BART 

Guidelines, to recommend that the 

model be used to estimate the 98th 

percentile visibility impairment rather 

than the highest daily impact value. 

While recognizing the limitations of the 

CALPUFF model in the BART 

Guidelines Preamble, EPA concluded 

that, for the specific purposes of the 

Regional Haze Rule’s BART provisions, 

CALPUFF is sufficiently reliable to 

inform the decision making process. 

The Preamble states: 

Because of the scale of the predicted 

impacts from these sources, CALPUFF is an 

appropriate or a reasonable application to 

determine whether such a facility can 

reasonably be anticipated to cause or 

contribute to any impairment of visibility. In 

other words, to find that a source with a 

predicted maximum impact greater than 2 or 

3 deciviews meets the contribution threshold 

adopted by the States does not require the 

degree of certainty in the results of the model 

that might be required for other regulatory 

purposes. In the unlikely case that a State 

were to find that a 750 MW power plant’s 

predicted contribution to visibility 

impairment is within a very narrow range 

between exemption from or being subject to 

BART, the State can work with EPA and the 

FLM to evaluate the CALPUFF results in 

combination with information derived from 

other appropriate techniques for estimating 

visibility impacts to inform the BART 

applicability determination. Similarly for 

other types of BART eligible sources, States 

can work with the EPA and FLM to 

determine appropriate methods for assessing 

a single source’s impacts on visibility. 

77 FR 39123. 

Therefore, given that the IWAQM 

guidance provides for the use of the 

CALPUFF model at receptor distances 

of up to 200 to 300 km, and given that 

EPA has already addressed uncertainty 

in the CALPUFF model, we believe it is 

reasonable to use CALPUFF to evaluate 

visibility impacts up to 300 km. 

Comment: A commenter stated that 

the CALPUFF model cannot accurately 

predict visibility changes at the levels 

EPA predicted for Holcim using indirect 

firing alone (0.125 deciview) or even for 

the additional improvement from the 

combination of SNCR + indirect firing 

as compared to SNCR alone. The 

commenter believes that the EPA 

predicted visibility improvement of 

0.424 deciview for the combination of 

SNCR + indirect firing is within the 

uncertainty range of the CALPUFF 

model and cannot reliably predict 

visibility improvements. 

Response: We disagree. EPA has 

previously addressed the issue of 

uncertainty in the CALPUFF model. 

EPA recognized the uncertainty in the 

CALPUFF modeling results when EPA 

made the decision in the final BART 

Guideline to recommend that the model 

be used to estimate the 98th percentile 

visibility impairment rather than the 

highest daily impact value. While 

recognizing the limitations of the 

CALPUFF model in the Preamble, EPA 

concluded that, for the specific 

purposes of the Regional Haze Rule’s 

BART provisions, CALPUFF is 

sufficiently reliable to inform the 

decision making process. 70 FR 39123. 

We continue to maintain that it is 

appropriate to use CALPUFF for BART 

modeling for Holcim and other Montana 

BART sources. 

Comment: Some commenters stated 

that we should have modeled impacts to 

additional Class I areas. Some 

commenters stated that EPA should 

have modeled visibility impacts on 

Class I areas at a distance of up to 500 

km from the BART source and some 

commenters specified certain Class I 

areas that they thought should be 

included in the modeling for a 

particular source. 

Some commenters stated that the 

Western Regional Air Partnership 

(WRAP) subject to BART modeling 

indicated impacts from BART sources to 

additional Class I areas that we did not 

assess. One commenter stated that when 

assessing the impacts from the Big Stone 

I facility in the South Dakota SIP, EPA 

evaluated visibility as far away as 

Badlands National Park (NP), 470 km, 

Theodore Roosevelt NP, 555 km, and 

Boundary Waters Wilderness Area (WA) 

and Voyageurs NP, 431 and 438 km, 

respectively, and the commenter stated 

that, EPA should evaluate visibility 

impacts at more distant Class I areas for 

the Montana FIP. 

Response: We modeled all Class I 

areas within 300 km of the BART 

source. As discussed in a response to a 

previous comment, the IWAQM Phase 2 

report concluded that CALPUFF can 

overestimate surface concentrations at 

distances of 300 to 1,000 km by a factor 

of 3 to 4. Therefore, IWAQM 

recommends use of CALPUFF for 

transport distances of approximately 

200 km or less. Use of CALPUFF for 

characterizing transport beyond 200 to 

300 km should be done cautiously with 

an awareness of the likely problems 

involved. Therefore, we modeled Class 

I areas within 300 km of each BART 

source. We did not model impacts at 

distances exceeding 300 km. 

In the case of the Big Stone I facility 

in South Dakota, there were no Class I 

areas within a distance of 300 km of the 

source. Therefore, the State and the 

facility agreed in their modeling 

protocol to evaluate visibility impacts at 

more distant sources by using a nonregulatory option in CALPUFF called 

‘‘puff splitting’’. As discussed in the 

IWAQM Guidance,5 the use of the puff 

splitting option in CALPUFF might 

improve model performance at long 

distances, but there are also serious 

conceptual concerns with the use puff 

splitting to represent puff dispersion for 

very long-range transport at distances of 

more than 300 km. EPA concurred with 

South Dakota on this approach for Big 

Stone I because there were no Class I 

areas within 300 km of the source, and 

EPA approved the South Dakota SIP 

using these modeling results. In the case 

of Montana, there are several Class I 

areas less than 300 km from each BART 

source, and EPA based its analysis on 

CALPUFF visibility model results for 

these areas. 

EPA did not use the non-regulatory 

puff splitting option in CALPUFF to 

model more distant sources because of 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57869 

6CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class I areas in 

the Western United States Available at http:// 

pah.cert.ucr.edu/aqm/308/bart/ 

WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

7Summary of WRAP RMC BART Modeling for 

Montana, Draft #5 May 30, 2007. More information 

can be found at http://pah.cert.ucr.edu/aqm/308/ 

bart.shtml. 

the greater uncertainty in model results 

at distances of more than 300 km, as we 

have explained in previous responses. 

While WRAP performed CALPUFF 

modeling at Class I areas more distant 

than 300 km from Colstrip, WRAP also 

recognized the larger uncertainty in the 

model results for distances greater than 

300 km. and included the following 

caveat in their modeling protocol: 

Relevant guidance suggests that the 

CALPUFF model is generally applicable at 

distances from 50 km to 300 km downwind 

and may be used for distance less than 50 km 

when complex flows exist on a case by case 

basis. [citation omitted] Class I areas in the 

west generally are located in complex terrain 

resulting in complex flows. Consequently, 

the BART screening modeling conducted by 

the RMC will include results for potential 

BART eligible sources that reside within 50 

km of a Class I area. The WRAP RMC BART 

screening modeling may also apply 

CALPUFF to downwind distances greater 

than 300 km. When providing results to the 

States, the downwind distance between the 

BART source and the Class I area will be 

included, and a recommendation from the 

RMC as to the utility of applying the results 

for Class I areas less than 50 km and greater 

than 300 km from the source. The individual 

States will need to make their own regulatory 

assessment of the applicability of the model 

results at those distances less than 50 km and 

greater than 300 km.6

It also should be noted that WRAP 

found smaller visibility impacts at the 

distances of more than 300 km 

compared to Class I areas at distances of 

less than 300 km.7 The BART 

Guidelines explain that if the highest 

modeled effects are observed at the 

nearest Class I area, it may not be 

necessary to model other Class I areas. 

The BART Guidelines state: 

One important element of the protocol is 

in establishing the receptors that will be used 

in the model. The receptors that you use 

should be located in the nearest Class I area 

with sufficient density to identify the likely 

visibility effects of the source. For other Class 

I areas in relatively close proximity to a 

BART-eligible source, you may model a few 

strategic receptors to determine whether 

effects at those areas may be greater than at 

the nearest Class I area. For example, you 

might choose to locate receptors at these 

areas at the closest point to the source, at the 

highest and lowest elevation in the Class I 

area, at the IMPROVE monitor, and at the 

approximate expected plume release height. 

If the highest modeled effects are observed at 

the nearest Class I area, you may choose not 

to analyze the other Class I areas any further 

as additional analyses might be unwarranted. 

70 FR 39170. 

Comment: Commenters stated that 

EPA should have added the visibility 

impacts at each Class I area to assess 

cumulative visibility impacts. 

Response: Contrary to the 

commenter’s assertion, we did assess 

cumulative visibility impacts. In our 

analysis of visibility impacts, we 

considered the visibility improvement 

at all Class I areas within 300 km of the 

subject BART unit. For example, in our 

analysis of BART control options for 

Corette, we considered the visibility 

improvement at all Class I areas within 

300 km (Gates of the Mountains WA, 

North Absaroka WA, Red Rock Lakes 

WA, Teton WA, UL Bend WA, 

Washakie WA, and Yellowstone NP). 77 

FR 24042 and 77 FR 24046. In our 

proposal, for each of the BART sources 

we assessed the visibility improvement 

at each Class I area within 300 km of the 

source associated with the controls 

under consideration, as well as the 

number of days with a greater than 0.5 

deciview impact at each of these Class 

I areas. Therefore, our proposed rule did 

not ignore the visibility improvement 

that would be achieved at areas other 

than the most impacted Class I area, and 

we disagree with the assertions that we 

did not consider the impacts at multiple 

Class I areas. We did, however, in the 

proposed rule focus on the visibility 

benefits at those Class I areas with the 

most meaningful visibility impacts in 

determining whether NOX or SO2

controls should be determined to be 

BART. We took a similar approach for 

all the Montana BART units. We did not 

ignore the visibility benefits at the other 

Class I areas but did not consider the 

benefits sufficient to warrant a change 

in our determination as to the 

appropriate level of control. 

Comment: USFWS stated that for the 

three SO2 control alternatives, EPA 

made judgments on cost per deciview 

based on only the most impacted Class 

I area, Washakie WA and that USFWS 

continued to believe that it is 

appropriate to consider both the degree 

of visibility improvement in a given 

Class I area as well as the cumulative 

effects of improving visibility across all 

of the Class I areas affected. USFWS 

stated that it does not make sense to use 

the same metric to evaluate the effects 

of reducing emissions from a BART 

source that impacts only one Class I area 

as for a BART source that impacts 

multiple Class I areas and that it does 

not make sense to evaluate impacts at 

one Class I area, while ignoring others 

that are similarly significantly impaired. 

USFWS stated that if emissions from 

Corette are reduced, the benefits will be 

spread well beyond only the most 

impacted Class I area, and this must be 

accounted for. USFWS stated that, in 

the context of the multiple Class I areas 

that are affected by Corette, the Lime 

Spray Dryer (LSD) SO2 control 

alternative, the cumulative Class I area 

impact is $12.7 million per deciview of 

visibility improvement and costs $4,981 

per ton of SO2 removed USFWS stated 

that LSD should be considered as being 

a viable candidate for BART for Corette. 

USFWS made similar comments 

regarding NOX controls for Corette. 

Response: We disagree. In our 

analysis of visibility impacts, we 

considered the visibility improvement 

at all Class I areas within 300 km of the 

subject BART unit. As explained in the 

response to the previous comment, in 

our analysis of BART control options for 

Corette, we considered the visibility 

improvement at all Class I areas within 

300 km. In our proposal, for each of the 

BART sources we assessed the visibility 

improvement at each Class I area within 

300 km of the source associated with the 

controls under consideration, as well as 

the number of days with a greater than 

0.5 deciview impact at each of these 

Class I areas. Therefore, our proposed 

rule did not ignore the visibility 

improvement that would be achieved at 

areas other than the most impacted 

Class I area, and we disagree with the 

assertions that we did not consider the 

impacts at multiple Class I areas. We 

did, however, in the proposed rule focus 

on the visibility benefits at those Class 

I areas with the most meaningful 

visibility impacts in determining 

whether NOX or SO2 controls should be 

determined to be BART. We did not 

ignore the visibility benefits at the other 

Class I areas but did not consider the 

benefits sufficient to warrant a change 

in our determination as to the 

appropriate level of control. As we 

explained in other responses, we did 

not use the $/deciview ratio as a basis 

for our decision. 

Comment: EarthJustice’s consultant 

Air Resources Specialists (ARS) 

performed additional analysis on 

possible visibility benefits of SCR at 

Colstrip Units 1 and 2 combined with 

the benefits of BART controls on SO2

emissions. The commenter stated that 

the ARS analysis ‘‘demonstrates that 

EPA’s analysis of visibility benefits of 

selective catalytic reduction (SCR) 

controls is incomplete and inadequate.’’ 

The commenter also stated, ‘‘the 

evidence demonstrates that with SCR 

and SO2 controls, the visibility 

impairment at UL Bend WA and 

Theodore Roosevelt NP attributable to 


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57870 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

8 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency, September 2003. 

Colstrip would be virtually eliminated, 

the very goal of the CAA haze 

requirements.’’ 

The commenter also stated that when 

SCR + SOFA is coupled with a dry 

scrubber/baghouse, it is likely that 

Corette would no longer have any 

noticeable impact on haze in any Class 

I area, and this result complies with the 

Congressional directive to eliminate 

haze in Class I areas. 

Response: We disagree that our 

analysis was incomplete or inadequate. 

We analyzed visibility benefits for both 

SO2 and NOX emissions reductions 

following procedures established in the 

BART Guidelines, and we proposed 

emissions reductions consistent with 

the five factor analysis. The Regional 

Haze Rule has a goal that anthropogenic 

visibility impairment be eliminated by 

2064; however, it does not require that 

all anthropogenic contributions to 

visibility impacts be fully eliminated in 

the near term, nor is that the goal of the 

BART element of the Regional Haze 

program. 40 CFR 51.308 (e)(1)(ii)(A) 

requires that EPA consider the cost of 

compliance; the energy and nonair 

quality environmental impacts; any 

pollution control equipment in use at 

the source; the remaining useful life of 

the source; and the degree of 

improvement which may be reasonably 

anticipated to result from the use of 

such technology. Visibility 

improvement is only one of the five 

factors that are required to be 

considered. Our proposed BART 

controls achieve significant reductions 

in contributions to visibility impairment 

while also considering other 

components of the five factor analysis. 

Comment: EarthJustice stated that, 

‘‘ARS concluded that the incremental 

benefit of SCR compared to SNCR at 

Colstrip Units 1 and 2 is larger when 

viewed in combination with the SO2

emission controls at either emission 

rate.’’ 

Response: ARS estimated the relative 

improvement in SCR compared to SNCR 

for the case with baseline SO2 emissions 

and for the case with our proposed 

BART SO2 emissions. The ARS analysis 

showed that the incremental 

improvement in SCR compared to SNCR 

was almost identical for the 98% worst 

days regardless of the level of SO2

emissions used. For example, in EPA’s 

analysis the incremental improvement 

of SCR over SNCR for Theodore 

Roosevelt NP was 0.27, 0.23, and 0.28 

deciview, respectively, for 2006, 2007 

and 2008. The ARS analysis found 

incremental improvements of 0.28, 0.26, 

and 0.28 deciview, respectively, for 

2006, 2007 and 2008. Moreover, ARS 

did not perform additional CALPUFF 

simulations for this analysis, but only 

combined estimates of extinction 

contributions from different CALPUFF 

simulations. 

Comment: EarthJustice stated that that 

we aggregated Colstrip Units 1 and 2 for 

assessing visibility benefits of SNCR, 

but arbitrarily kept our assessment of 

benefits of SCR segregated by unit. 

Response: We disagree. Modeling was 

performed in the same manner for SCR 

as for SNCR. The modeling protocol, 

results, and final report were available 

in the docket. Our evaluation of the 

visibility benefits was made in 

consideration of all of the modeling 

results, which includes a visibility 

improvement assessment for application 

of SCR at Colstrip Units 1 and 2 

individually, as well as an assessment of 

the total visibility benefit from 

application of SCR at both units 

collectively. 

Comment: A commenter stated that 

we failed to examine the collective 

visibility benefit of SCR in combination 

with SO2 upgrades at Colstrip Units 1 

and 2. 

Response: We examined the 

individual benefits of NOX and SO2

controls to be able to assess the 

difference between pollutant-specific 

control options. Our evaluation of the 

visibility benefits was made in 

consideration of all of the modeling 

results. 

Comment: EarthJustice stated that 

their contractor (ARS) performed 

AERMOD simulations to evaluate the 

impacts of Colstrip SO2 emissions 

relative to the 1-hour average SO2

National Ambient Air Quality Standard 

(NAAQS) and reported modeled 

violations of the SO2 NAAQS. 

Response: EPA will address 

compliance with the 1-hour average SO2

NAAQS separately from Regional Haze 

requirements. It is beyond the scope of 

this rulemaking. It will be addressed by 

EPA at a later date. 

Comment: Holcim commented that 

EPA discarded all prior modeling and 

developed a new modeling analysis in 

2011. Holcim stated that EPA did not 

explain why it used a new modeling 

analysis and that EPA’s BART 

conclusions are therefore based on 

modeling that is not transparent and not 

available for review. 

Response: We disagree. As we 

explained in our proposal, we used 

CALPUFF modeling to evaluate 

emissions control scenarios that were 

consistent with the application of 

control scenarios for the Montana 

sources that were subject to BART. We 

did this because we were unable to 

obtain the modeling files from some of 

the sources and we wanted each source 

to be modeled consistently. The 

modeling protocol, final report, and all 

related files were available for review in 

the docket. 

Comment: The Western 

Environmental Trade Organization 

(WETA) commented that the EPA 

recently approved the SIP for regional 

haze developed by the State of North 

Dakota. WETA explained that the North 

Dakota plan relied on extensive 

modeling that demonstrated emissions 

control technology installations at 

certain facilities would result in 

insignificant improvement in visibility. 

WETA requested that the EPA develop 

a visibility plan for Montana that offers 

the same flexibility and cost-effective 

standards included in North Dakota’s 

plan. 

Response: WETA did not explain 

what flexibility it was seeking; 

therefore, we are not able to evaluate 

whether such flexibility could be 

accommodated. To the extent that 

WETA is stating that our proposed 

requirements are not cost-effective, we 

disagree. To the extent that WETA is 

stating that we are being inconsistent 

with decisions we made for regional 

haze in North Dakota, we disagree. We 

have responded to more specific 

comments on the cost-effectiveness of 

controls elsewhere. 

Comment: The commenter stated that 

EPA’s proposed BART determinations 

for Colstrip Units 1& 2 are erroneous 

because EPA’s modeling failed to 

include actual air quality 

measurements, including visual quality 

measurements, in its inputs to its 

regional haze model. The commenter 

further stated that real air quality data 

for Class I areas is critical to 

determining what the degree of 

visibility improvement may be in a 

given Class I area. 

Response: EPA used ambient 

monitoring data to evaluate the CMAQ 

and CAMx grid model simulations that 

were used for modeling the uniform rate 

of progress toward natural visibility 

conditions. However, the commenter 

appears to be referring specifically to 

the CALPUFF model simulations used 

to evaluate visibility impacts of BART 

sources. The BART Guidelines require 

that visibility impacts from BART 

sources be evaluated in comparison to 

natural visibility conditions. The 

procedures used to estimate natural 

visibility conditions are described in the 

‘‘Guidance for Estimating Natural 

Visibility Conditions Under the 

Regional Haze Rule.’’ 8 It would be 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57871 

Can be found at: http://www.epa.gov/ttncaaa1/t1/ 

memoranda/rh_envcurhr_gd.pdf. 

9 Guidance for Setting Reasonable Progress Goals 

Under the Regional Haze Program, U.S. 

Environmental Protection Agency, June 1, 2007, 

p.5–2. 

inappropriate to use ambient monitoring 

data for current degraded visibility 

conditions in the evaluation of BART 

source visibility impacts. EPA 

previously considered and responded to 

the comment that current visibility 

conditions should be used in BART 

source evaluations in 40 CFR part 51, 

appendix Y, promulgated at 70 FR 

39104. EPA considered the approach of 

assessing a BART-eligible source’s 

impacts on visibility by using current or 

near-term future conditions, and EPA 

determined that BART visibility impacts 

should be evaluated in comparison to 

natural background visibility. In the 

final rulemaking EPA wrote: 

Using existing conditions as the baseline 

for single source visibility impact 

determinations would create the following 

paradox: The dirtier the existing air, the less 

likely it would be that any control is 

required. This is true because of the 

nonlinear nature of visibility impairment. In 

other words, as a Class I area becomes more 

polluted, any individual source’s 

contribution to changes in impairment 

becomes geometrically less. Therefore the 

more polluted the Class I area would become, 

the less control would seem to be needed 

from an individual source. We agree that this 

kind of calculation would essentially raise 

the ‘‘cause or contribute’’ applicability 

threshold to a level that would never allow 

enough emission control to significantly 

improve visibility. Such a reading would 

render the visibility provisions meaningless, 

as EPA and the States would be prevented 

from assuring ‘‘reasonable progress’’ and 

fulfilling the statutorily-defined goals of the 

visibility program. Conversely, measuring 

improvement against clean conditions would 

ensure reasonable progress toward those 

clean conditions. 

70 FR 39124. 

Therefore, EPA correctly used 

estimates of natural visibility conditions 

in our evaluation of BART source 

visibility impacts, and we disagree with 

the comment that we failed to 

appropriately use air quality data at 

Class I areas. 

Comment: EarthJustice stated that 

they do not agree with EPA’s approach 

to use the fifth factor in determining the 

degree of visibility improvement from 

emissions control technologies where 

EPA adds an additional incremental 

benefit factor with an apparent but 

unstated threshold for improvement 

sufficiency that is contrary to the 

purpose and direction of the CAA. 

Response: We disagree that we only 

evaluated visibility benefit on an 

incremental basis and that we used a 

threshold for improvement sufficiency. 

In the proposed FIP, we included tables 

showing the visibility improvement for 

control options as compared to baseline 

conditions. Incremental improvement 

can be easily calculated from the data in 

the tables, however, we did not 

calculate this separately for each option. 

In addition, our modeling protocol, 

modeling report and tables of results 

were included in the docket. 

Comment: Commenters stated that we 

used incorrect baselines for modeling 

impacts from sources at Corette and 

Colstrip. 

Response: We explain our rationale 

for the chosen baseline periods in 

responses to other comments. 

B. General Comments on BART 

Comments: Montana Department of 

Environmental Quality (MDEQ) stated 

that EPA should have used a dollar-perdeciview ($/deciview) metric rather 

than the $/ton metric to evaluate BART 

and reasonable progress. MDEQ argued 

that the use of deciviews is consistent 

with the Regional Haze Rule, which 

expresses Reasonable Progress Goals 

(RPGs), baseline visibility, current 

visibility conditions and natural 

conditions in deciviews. MDEQ also 

referenced both the BART Guidance and 

the Reasonable Progress Guidance to 

support this argument. 

The NPS stated that one of the options 

suggested by the BART Guidelines to 

evaluate cost-effectiveness is cost/ 

deciview and that the NPS believes that 

visibility improvement must be a 

critical factor in any program designed 

to improve visibility. The NPS stated 

that compared to the typical control cost 

analysis in which estimates fall into the 

range of $2,000–$10,000 per ton of 

pollutant removed, spending millions of 

dollars per deciview to improve 

visibility may appear extraordinarily 

expensive, but that the NPS compilation 

of BART analyses across the United 

States reveals that the average cost per 

deciview proposed by either a state or 

a BART source is $14–$18 million, with 

a maximum of $51 million per deciview 

proposed by South Dakota at the Big 

Stone I power plant. The NPS noted that 

even though it has no Class I areas, 

Nebraska Department of Environmental 

Quality has chosen $40 million/ 

deciview as a cost criterion, which is 

also above the national average. The 

NPS compared its estimates for annual 

cost of adding SOFA + SCR to EPA’s 

estimates for visibility impacts and 

stated that the cost-effectiveness of 

adding SOFA + SCR to improve 

visibility at the five Class I areas 

modeled by EPA is less than $10 

million/deciview and significantly less 

than the $14–$18 million/deciview 

national average of BART proposals and 

determinations. 

Response: For BART, the BART 

Guidelines require that cost 

effectiveness be calculated in terms of 

annualized dollars per ton of pollutant 

removed, or $/ton. 70 FR 39167. MDEQ 

and the NPS are correct in that the 

BART Guidelines allows for the $/ 

deciview ratio as an additional cost 

effectiveness metric that can be 

employed along with $/ton for use in a 

BART evaluation. However, the use of 

this metric further implies that 

additional thresholds or notions of 

acceptability, separate from the $/ton 

metric, would need to be developed for 

BART determinations. We have not 

used this metric for BART purposes 

because (1) It is unnecessary in judging 

the cost effectiveness of BART, (2) it 

complicates the BART analysis, and (3) 

it is difficult to judge. The $/deciview 

metric has not been widely used and is 

not well-understood as a comparative 

tool. In our experience, $/deciview 

values tend to be very large because the 

metric is based on impacts at one Class 

I area on one day and does not take into 

account the number of affected Class I 

areas or the number of days of 

improvement that result from 

controlling emissions. In addition, the 

use of the $/deciview suggests a level of 

precision in the CALPUFF model that 

may not be warranted. As a result, the 

$/deciview can be misleading. We 

conclude that it is sufficient to analyze 

the cost effectiveness of potential BART 

controls using $/ton, in conjunction 

with an assessment of the modeled 

visibility benefits of the BART control. 

Within the context of reasonable 

progress, the Guidance for Setting 

Reasonable Progress Goals Under the 

Regional Haze Program, states that 

‘‘[y]ou should evaluate both average and 

incremental costs.’’ 9 This is consistent 

with the approach under BART. As 

commenters note, the guidance then 

stated that ‘‘simple cost effectiveness 

estimates based on a dollar-per-ton 

calculation may not be as meaningful as 

a dollar-per-deciview calculation, 

especially if the strategies reduce 

different groups of pollutants.’’ 

However, the guidance makes this 

statement on the basis that ‘‘different 

pollutants differently impact visibility 

impairment.’’ That is, for example, a one 

ton reduction in SO2 would have a 

greater visibility benefit than a one ton 

reduction of coarse mass. As only SO2

and NOX controls were evaluated for the 

reasonable progress point sources, the 

use of the $/deciview is not particularly 


tkelley on DSK3SPTVN1PROD with RULES3
57872 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

10We presume these units are the ‘‘coal-fired 

utilities’’ to which MDEQ is referring. 

relevant or informative. In addition, we 

did not use the $/deciview metric for 

our evaluation of reasonable progress 

controls for largely the same reasons as 

stated above for BART controls. 

Comment: The NPS stated that we 

used inconsistent criteria in selecting 

BART controls. 

Response: We disagree. As explained 

later, pursuant to 40 CFR 

51.308(e)(1)(ii)(A) we considered the 

following five factors in our analysis: 

The cost of compliance; the energy and 

nonair quality environmental impacts; 

any pollution control equipment in use 

at the source; the remaining useful life 

of the source; and the degree of 

improvement which may be reasonably 

anticipated to result from the use of 

such technology. The Regional Haze 

Rule defines BART as the best system of 

continuous emission control technology 

available and associated emission 

reductions achievable, as determined 

through an analysis of these five factors. 

The NPS is correct in that the BART 

Guidelines allows for the $/deciview 

ratio as an additional cost effectiveness 

metric that can be employed along with 

$/ton for use in a BART evaluation of 

the five statutory factors. 70 FR 39126 

to 70 FR 39127. While the Regional 

Haze Rule may not prevent us from 

establishing a bright line for some of the 

factors such as cost-effectiveness and 

visibility, we are not required to do so, 

and have not done so for this action as 

the cost and visibility factors are both 

weighed in making control decisions. 

Also, while the BART Guidelines allows 

for the $/deciview ratio as an additional 

cost effectiveness metric that can be 

employed along with $/ton for use in a 

BART evaluation, we have not used this 

metric in our evaluation. As explained 

in our determinations for each source, 

the cost effectiveness of controls on a 

dollar per ton basis and the visibility 

benefit of those controls were the two 

factors that had the most influence over 

our decision. 

Comment: MDEQ stated that in the 

North Dakota Regional Haze SIP/FIP, 

coal-fired utilities with much greater 

estimated visibility impact were 

required to install controls similar to 

those required at Colstrip 1 and 2. 

Response: We disagree that certain 

BART determinations from the North 

Dakota Regional Haze SIP/FIP are 

appropriate comparisons to our BART 

determinations in this FIP. Our 

determination on the NOX BART 

determinations at Milton R. Young 

Station Units 1 and 2 and Leland Olds 

Station Unit 210 is explained in our final 

action for regional haze for North 

Dakota. 77 FR 20893. Our BART 

determinations were made on a sourcespecific basis in consideration of the 

five statutory factors. 

Comment: MDEQ stated that we 

‘‘accept, discard or include new cost 

information without reason or 

justification.’’ MDEQ supported this 

claim by arguing that we used Integrated 

Planning Model (IPM) data in one 

instance, but used costs provided by 

sources and an outside consultant 

instead of IPM data for the North Dakota 

Regional Haze SIP/FIP. 

Response: The BART Guidelines 

provide some flexibility in how to 

calculate and consider costs. 70 FR 

39127. Generally, we followed a 

reasonable and supported approach. We 

have responded to specific comments 

regarding our cost analysis in other 

responses. 

Comment: MDEQ stated that the 

averaging times and compliance 

demonstrations for Colstrip 1 & 2, 

Corette and Devon Energy are not 

practically enforceable, and therefore 

counter to the BART Guidelines. MDEQ 

stated that the 30-day rolling average 

particulate matter (PM) emission limits 

for Colstrip 1, Colstrip 2 and Corette, 

and the NOX limit for Devon are not 

enforceable with an annual stack test. 

Response: We disagree with some 

aspects of this comment and have made 

changes in the final FIP to clarify 

requirements in response to other 

aspects of this comment. In the 

proposed FIP, we concluded that annual 

stack tests, along with emissions 

monitoring in accordance with the 

applicable Compliance Assurance 

Monitoring (CAM) plan are sufficient to 

determine compliance with BART PM 

limits. 77 FR 24099 (April 20, 2012). In 

its comments, MDEQ provides no 

evidence to the contrary aside from the 

general statements about practical 

enforceability described in the comment 

above. With regard to the Devon Energy 

Reasonable Progress determination, we 

have revised the monitoring, 

recordkeeping and reporting 

requirements in the final FIP. We have 

also clarified in a correction notice that 

the PM limits listed at 40 CFR 52.1396 

are not based on a 30-day average. 77 FR 

29270. 

Comment: MDEQ noted that CrossState Air Pollution Regulation (CSAPR) 

trading programs were recently 

determined by EPA to be an alternative 

to source-by-source BART 

determinations. 77 FR 33642 (April 20, 

2012). MDEQ argued that, because 

CSAPR is a health-based standard, ‘‘EPA 

in the East is advocating the position 

that Montana has taken for our own 

state: Realize the benefits (including 

visibility) from health-based standards 

and make compliance with those 

standards the demonstration for BART.’’ 

Response: Emissions trading programs 

and other alternative programs can be 

used in place of source specific BART 

controls ‘‘as long as the alternative 

provides greater reasonable progress 

towards improving visibility than 

BART.’’ 77 FR 33644. Because Montana 

is not within the geographic areas 

covered by CSAPR, and because the 

State did not submit an emissions 

trading program or alternative program 

that was subject to, let alone satisfied, 

the ‘‘greater reasonable progress’’ test, 

EPA does not agree that compliance 

with other standards may replace a 

BART demonstration for sources subject 

to BART in Montana. 

Comment: A commenter claimed that 

our elimination of best emission 

controls based on incremental benefit is 

not legally supportable and that EPA’s 

analyses do not satisfy the purpose or 

the regulatory requirements for BART 

determinations. The commenter stated 

that we applied additional filters with 

unstated thresholds or standards in our 

consideration of BART and that those 

filters eliminate or significantly 

diminish the weight and importance of 

the required five factors. The 

commenter stated that EPA used an 

incremental benefit test and reached a 

subjective conclusion. 

Response: We disagree that our 

determinations are not legally 

supportable. Pursuant to 40 CFR 

51.308(e)(1)(ii)(A) we considered the 

following five factors in our analysis: 

The cost of compliance; the energy and 

nonair quality environmental impacts; 

any pollution control equipment in use 

at the source; the remaining useful life 

of the source; and the degree of 

improvement which may be reasonably 

anticipated to result from the use of 

such technology. The Regional Haze 

Rule defines BART as the best system of 

continuous emission control technology 

available and associated emission 

reductions achievable, as determined 

through an evaluation of the five 

statutory factors. 70 FR 39126 to 70 FR 

39127. While the Regional Haze Rule 

may allow us to establish a bright line 

for some of the factors such as costeffectiveness and visibility, we are not 

required to do so, and have not done so 

for this action. 

Comment: MDEQ commented that 

EPA makes a case for ordering the 

installation of control equipment for 

measurable emissions reductions absent 

a visibility improvement goal to achieve 

reasonable progress as measured in 

deciviews. MDEQ stated that one of the 


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factors to consider when determining 

BART is any existing pollution control 

technology in use at the source and that 

EPA may be interpreting this provision 

to mean BART requires the installation 

of any new pollution control technology 

that is useful for reducing emissions 

generally. MDEQ stated that the statute 

and the Regional Haze Rule are both 

clear that a BART determination focuses 

on existing pollution controls and that 

the suitability of additional controls for 

co-beneficial purposes that may be 

tangentially related to the National Goal 

is not part of the analysis. MDEQ stated 

that overall purpose of any SIP, 

including Montana’s, is the control of 

emissions to comply with the NAAQS 

as set forth in 42 U.S. Code (USC) 

Section7410 and that the purpose of the 

Regional Haze Rule is to control 

emissions that cause or contribute to 

visibility impairment in Class I Federal 

areas. MDEQ stated that, ‘‘Montana is 

adamant on this point because it forms 

the basis for its reluctant renunciation of 

authority over Montana’s BART 

program.’’ MDEQ stated that, ‘‘the 

consideration of a co-benefit strategy is 

not without merit, but the imposition of 

BART is set forth very clearly in statute 

and rule. MDEQ stated that the 

determination of BART has everything 

to do with visibility impairment and 

improvement, not the attainment or 

maintenance of the NAAQS.’’ MDEQ 

suggested that, ‘‘EPA limit the BART 

criteria to that set forth in the rule at 40 

CFR 51.308(e) and refuse to propose 

new controls that are not calculated to 

fulfill BART criteria.’’ 

Response: We disagree that we have 

misinterpreted the BART provision to 

consider any existing pollution control 

technology at the source. We point out 

that considering existing pollution 

control technology in use at the source 

does not preclude the consideration of 

new technology. As listed in the BART 

Guidelines, Step 1 of the ‘‘Five Basic 

Steps of a Case-by-Case BART Analysis’’ 

is ‘‘Identify All Available Retrofit 

Technologies.’’ 70 FR 39164. A footnote 

to the word ‘‘All’’ in this step of the 

BART Guidelines reads as follows; ‘‘In 

identifying ‘all’ options, you must 

identify the most stringent option and a 

reasonable set of options for analysis 

that reflects a comprehensive list of 

available technologies. It is not 

necessary to list all permutations of 

available control levels that exist for a 

given technology—the list is complete if 

it includes the maximum level of 

control each technology is capable of 

achieving.’’ 70 FR 39164. Our analysis 

for each Montana source subject to 

BART included each of the ‘‘Five Basic 

Steps of a Case-by-Case BART 

Analysis,’’ as well as a complete fivefactor analysis which included 

consideration of ‘‘any existing pollution 

control technology in use at the source.’’ 

Existing pollution control technology 

was considered when identifying 

available control options, when 

establishing a baseline for determining 

visibility impacts or for determining 

annual emission reductions for available 

control options. Existing pollution 

control technology also was considered 

in establishing emission limits. With 

regard to MDEQ’s comment that we 

interpreted this provision to mean 

BART requires the installation of any 

new pollution control technology that is 

useful for reducing emissions generally, 

we point out that in many cases our 

BART determinations did not require 

additional pollution control technology 

to be installed for BART. 

We also disagree that we have 

interpreted BART to require the 

installation of any new pollution control 

technology that is useful for reducing 

emissions generally, that we used 

criteria other that those listed at 40 CFR 

51.308(e)(1)(ii)(A), or that we proposed 

new controls that are not calculated to 

fulfill BART criteria. As stated in other 

responses, pursuant to 40 CFR 

51.308(e)(1)(ii)(A) we considered the 

five factors in our analysis.. The 

Regional Haze Rule defines BART as the 

best system of continuous emission 

control technology available and 

associated emission reductions 

achievable, as determined through an 

evaluation of the five statutory factors. 

70 FR 39126 to 70 FR 39127. As stated 

in another response, at no point in the 

proposed FIP did we discuss public 

health impacts as a consideration in our 

analyses, as they were not. As stated 

elsewhere, we agree that the Regional 

Haze Rule is not a health-based 

standard, and that we are not authorized 

to consider public health impacts in 

promulgating our FIP for purposes of 

this action. 

Comment: The NPS commented that 

EPA determined that the incremental 

visibility improvement from a control 

option must exceed 0.5 deciview at a 

given Class I area if costs exceed $5,000/ 

ton in order to qualify as BART and 

stated that the NPS disagrees with this 

approach. The NPS stated that while the 

BART Guidelines do recommend 

estimation of incremental costs, it 

makes no mention of an incremental 

visibility improvement test. The NPS 

explained that if applied linearly, EPA’s 

cost estimate of $3,235/ton for SCR 

would correspond to a visibility 

improvement of 0.32 deciview, not 0.5 

deciview to justify SCR. The NPS stated 

that EPA concluded the benefit of SCR 

at Theodore Roosevelt NP is 0.4 

deciview and that therefore, by EPA 

criteria SCR is BART for each Units 1 

and 2. 

Response: We disagree. We have not 

determined that the incremental 

visibility improvement from a control 

option must exceed 0.5 deciview at a 

given Class I area if costs exceed $5,000/ 

ton in order to qualify as BART. As 

stated in other responses, while the 

Regional Haze Rule may allow us to 

establish a bright line for some of the 

factors such as cost-effectiveness and 

visibility, we are not required to do so, 

and have not done so for this action. 

C. Comments on Cement Kilns 

Comment: A commenter stated that 

we must not exempt cement kilns from 

BART for PM. The commenter described 

baseline visibility impacts from Ash 

Grove and Holcim and stated that the 

high degree of visibility impairment 

warrants analysis of whether PM 

emission limits should be lower to 

reflect BART. 

Response: We disagree that we have 

exempted cement kilns from BART for 

PM. In our proposal, Table 35 shows 

that Ash Grove’s greatest baseline 

visibility impact is 4.446 deciviews at 

Gates of the Mountains WA and Table 

49 shows that Holcim’s greatest baseline 

visibility impact is .980 deciview at 

Gates of the Mountains WA. 77 FR 

24011 and 77 FR 24017. While we agree 

with the commenter that the baseline 

impacts are significant, the PM 

contribution to this overall baseline 

impact is small. In our proposal, Table 

38 shows that for Ash Grove, coarse PM 

only contributes 0.84% and fine PM 

only contributes 4.77% to the overall 

baseline visibility impact of 4.446 

deciviews. 77 FR 24013. Table 64 shows 

that for Holcim, coarse PM only 

contributes 5.79% and fine PM only 

contributes 12.61% to the overall 

baseline visibility impact of .980 

deciview. 77 FR 24022. By contrast, our 

BART determination for Ash Grove for 

NOX is anticipated to achieve a 

visibility improvement of 1.248 

deciviews and our BART determination 

for Holcim is anticipated to achieve a 

visibility improvement of 0.424 

deciview. Any visibility improvement 

that could be achieved with 

improvements to the existing PM 

controls would be negligible. BART for 

PM was based on using the existing 

control equipment and the emission 

limit established in each facility’s Title 

V permit. The PM BART limits for Ash 

Grove and Holcim were listed in our 

proposal at 77 FR 24098 and are 


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11Letter from Molly Cagle to Chance Goodwin, 

Initial Control Strategy Development for DFW 

Ozone Nonattainment Area, July 30, 2010, p. 1. 

codified by our final action at 40 CFR 

52.1396. 

D. Comments on Ash Grove 

Comment: Ash Grove stated that they 

did not object to EPA’s conclusion that 

BART should be based on the 

installation of low NOX burner (LNB) 

and SNCR. However, the company 

stated that they objected to the 

assumptions made about what SNCR 

can achieve. Ash Grove stated that they 

explained in the prior correspondence 

that the company did not believe that it 

is appropriate to assume that the 

Montana City kiln can achieve 50% 

control effectiveness. Ash Grove stated 

that, as the data in Table 10 of the 

preamble clearly showed, only one of 

the three kilns at Ash Grove’s 

Midlothian plant is able to achieve 50% 

control effectiveness while the other 

two kilns had an average control 

efficiency of 37.7% and 40.5%. 

Ash Grove also believes that no other 

credible evidence is provided for our 

conclusion as to SNCR NOX control 

efficiency. Ash Grove stated that we 

referenced studies from other industry 

sectors and a marketing brochure from 

Cadence stating that ‘‘control efficiency 

of up to 50% can be achieved on long 

wet kilns’’ and that this quote states the 

upper end of what might be achievable. 

Ash Grove indicated that the brochure 

does not state that 50% control 

efficiency can be achieved on all long 

wet kilns, that Cadence’s experience 

with SNCR on long wet kilns is what is 

shown in Table 10, Ash Grove indicated 

that Cadence was Ash Grove’s partner in 

developing the Midlothian SNCR, 

which, according to Ash Grove, are the 

only long wet kilns in the United States 

with any track record of SNCR use. Ash 

Grove indicated that even after years of 

optimization on the Midlothian kilns, 

the data show that it has not been 

possible to bring all three kilns up to a 

50% control efficiency and that the 

Midlothian NOX reduction data reflect 

not only the benefits of SNCR, but also 

the mid-kiln firing of tires, use of a midkiln fan and other technologies that are 

not available to the Montana City kiln, 

but that were implemented concurrent 

with the SNCR installation/optimization 

at Midlothian to reduce NOX emissions. 

Ash Grove explained that in considering 

the Midlothian data, one needs to 

account for the direct control efficiency 

these technologies provide, in addition 

to the synergistic effects of using more 

than one control device/technique at a 

time at Midlothian and that these 

benefits would not be available at 

Montana City and should not be 

assumed. 

Ash Grove summarized that they 

continued to believe that a SNCR system 

at Montana City cannot be assumed to 

reach greater than 35% control 

efficiency and that EPA has produced 

no credible evidence in the record for 

supporting a different conclusion. Ash 

Grove stated that they recognized that 

their initial BART submittal listed 50% 

control as achievable for the 

combination of a low NOX burner and 

SNCR at the Montana City kiln but since 

then they have realized they cannot get 

to that level on all three kilns at 

Midlothian. Ash Grove stated that they 

are willing to not contest the 8.0 lb/ton 

clinker limit, and they anticipate that 

compliance could require additional 

control technologies/strategies; 

therefore, they need the maximum time 

allowable to find ways to consistently 

maintain NOX at or below that level. 

Response: We disagree that SNCR 

cannot achieve a 50% control 

effectiveness at Ash Grove. The data 

from Ash Grove’s Midlothian, Texas 

kilns in Table 10 of the proposed FIP, 

77 FR 24003, show the SNCR control 

effectiveness achieved. The data were 

not intended to imply that this is the 

upper bound of what might be achieved. 

Ash Grove did not submit any 

information demonstrating that this was 

the maximum reduction that could have 

been achieved. It was not necessary to 

achieve greater reductions from the 

Midlothian Texas kilns to comply with 

the required emission limit. In Texas, 

SNCR was used at Midlothian to comply 

with the emission limit established at 

Texas Administrative Code (TAC) 

117.3110(a)(1)(B) of 4.0 lb/ton clinker. 

TAC 117.3110(b) allowed an owner or 

operator of a long wet kiln to comply 

with the 4.0 lbs/ton clinker emission 

limit on the basis of a weighted average 

for multiple cement kilns. Thus, it was 

not necessary for each individual kiln to 

achieve the maximum percentage 

reduction possible; one or more kilns 

could emit more than 4.0 lbs/ton clinker 

as long as the weighted average 

complied with the emission limit. 

Ash Grove has not submitted any data 

to demonstrate that SNCR was 

optimized in an attempt to achieve the 

greatest control efficiency possible. For 

the Midlothian kilns, from June–August 

2009, the emission rate from kiln 1 was 

3.7 lbs/ton clinker and the emission rate 

from kiln 2 was 4.8 lbs/ton clinker and 

from June through August 2010, the 

emission rate from kiln 1 was 2.6 lbs./ 

ton clinker, the emission rate from kiln 

2 was 4.8 lbs/ton clinker, and the 

emission rate from kiln 3 was 4.4 lbs/ 

ton clinker. These emission rates are 

significantly higher than the emission 

rates from June to August 2008 (an 

average of 1.8 lbs/ton clinker for kiln 1, 

2.7 lbs/ton clinker for kiln 2, and 2.7 

lbs/ton clinker for kiln 3). An increase 

in NOX emissions over time would not 

be expected if the SNCR were being 

optimized. 

With regard to Ash Grove’s claim that 

we need to account for the direct control 

efficiency of other technologies that are 

not available to the Montana City Kiln, 

the tire-derived fuel system was already 

being used at Midlothian in 2006 and is 

already accounted for in the 2006 

baseline to which the 2008 post-SNCR 

emissions are compared.11 Thus, no 

further adjustment is necessary. Ash 

Grove has not provided data to 

demonstrate that a synergistic effect has 

occurred between mid-kiln firing of tires 

and SNCR at Midlothian. 

Ash Grove has not submitted data to 

support their claim that only 35% 

reduction can be achieved with SNCR at 

the Montana City kiln. All of the 

Midlothian kilns were able to achieve 

greater than 35% reduction with SNCR 

and there is no information to 

demonstrate that SNCR was optimized 

to its maximum potential. The BART 

Guidelines state, ‘‘In assessing the 

capability of the control alternative, 

latitude exists to consider special 

circumstances pertinent to the specific 

source under review, or regarding the 

prior application of the control 

alternative. However, you should 

explain the basis for choosing the 

alternate level (or range) of control in 

the BART analysis. Without a showing 

of differences between the source and 

other sources that have achieved more 

stringent emissions limits, you should 

conclude that the level being achieved 

by those other sources is representative 

of the achievable level for the source 

being analyzed.’’ 70 FR 39166. Ash 

Grove has not demonstrated the 

differences between their Montana City 

kiln and the Midlothian kilns. 

With regard to Ash Grove’s statement 

that we have not produced credible 

evidence in the record for supporting a 

greater than 35% control effectiveness 

for SNCR, we provided a detailed 

explanation in our proposed FIP at 77 

FR 24003. Ash Grove has used SNCR at 

its Midlothian kilns where it was shown 

to achieve the reductions ranging from 

37.7% to 62.5% and these are within 

the range of control effectiveness 

demonstrated at other kilns. 

Considering that control effectiveness is 

greater when initial NOX concentrations 

are greater, and that the baseline NOX

emissions of the Montana City kiln are 


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significantly greater than the Midlothian 

kilns, the Montana City kiln would be 

expected to achieve even greater control 

effectiveness when compared to the 

Midlothian kilns. 77 FR 24003 and 77 

FR 24004. 

Ash Grove’s comment that they are 

willing to not contest the 8.0 lb/ton 

clinker limit is noted. With regard to 

Ash Grove’s comment that they 

anticipate that compliance could require 

additional control technologies/ 

strategies and that therefore they need 

the maximum time allowable to find 

ways to consistently maintain NOX at or 

below that level, we disagree that 

additional control technologies/ 

strategies are necessary; however, the 

final FIP does not require specific 

control technologies/strategies to be 

used. The final FIP allows for the 

maximum time available to comply with 

the 8.0 lb/ton clinker limit. 

Comment: Ash Grove stated that the 

company supported the conclusions as 

to what constitutes BART for SO2. Ash 

Grove noted that in the preamble we 

stated that there is so little improvement 

in visibility associated with 

implementing add-on SO2 controls that 

there is no basis for requiring such 

controls under BART. Ash Grove stated 

that Clean Air Act Section 169A(g)(2) 

clearly states that ‘‘the degree of 

improvement in visibility which may 

reasonably be anticipated to result’’ 

must be used in evaluating potential 

BART controls. Ash Grove concluded 

that given the nominal improvement in 

visibility predicted from add-on 

controls, there is no basis under BART 

for requiring the addition of such 

controls. Ash Grove stated that the 

BART program has a very narrow 

statutory focus in that it exclusively 

addresses visibility improvement and 

that absent a material increase in 

visibility, the company believes that we 

would have been arbitrary and 

capricious if we had required add-on 

controls for SO2 utilizing our BART 

authority. Ash Grove stated that the 

company supported our ultimate 

conclusion. 

Response: The comment is noted. The 

final FIP makes no changes to the 

conclusions regarding SO2 controls for 

Ash Grove. 

Comment: Ash Grove stated that the 

company supported our conclusion that 

existing PM controls (an electrostatic 

precipitator (ESP)) constitute BART and 

that ESPs are well-accepted controls for 

wet kilns. Ash Grove stated that their 

compliance with the filterable 

particulate standard in the process 

weight rule applicable to the kiln is an 

appropriate limit for ensuring that the 

ESP is properly operating and that 

annual compliance demonstrations will 

ensure ongoing compliance. Ash Grove 

stated that they believe that this 

approach is particularly appropriate 

where the contribution of PM emissions 

to visibility impairment is nominal. 

Response: The comment is noted. The 

final FIP makes no changes to the 

conclusions regarding PM controls for 

Ash Grove. 

Comment: Ash Grove requests 

clarification on whether they must 

comply with BART limits for SO2 and 

PM within five years of the effective 

date of the rule, as specified in the 

proposed regulatory text at 40 CFR 

52.1396(d), or within 180 days for SO2

and 30 days for PM, as suggested by the 

preamble to the proposed rule. If the 

intent is to require compliance sooner 

than five years from the effective date, 

then Ash Grove requests that the rule be 

renoticed, and that if EPA will not allow 

five years from the effective date, then 

Ash Grove requests that the BART 

compliance date for these pollutants be 

30/180 days after the effective date, or 

the Portland cement National Emission 

Standards for Hazardous Air Pollutants 

(NESHAP) compliance date, whichever 

is later, in order to coordinate with the 

implementation of EPA’s Portland 

cement NESHAP and New Source 

Performance Standard (NSPS) 

requirements, including installation and 

certification of continuous emission 

monitoring systems (CEMS). Ash Grove 

stated that the monitoring that EPA is 

imposing as part of the concurrent 

Portland cement Maximum Achievable 

Control Technology (MACT) rulemaking 

is very complicated and must be able to 

work in concert with what EPA imposes 

under this BART rulemaking. Ash Grove 

also stated that critical components of 

Ash Grove’s envisioned monitoring 

scheme, such as installation of clinker 

weigh belts or the development of slurry 

conversion mechanisms, cannot be 

implemented within the 180 day period 

after the effective date. 

Response: We agree with aspects of 

this comment, but disagree with others. 

We agree that there is an omission in the 

proposed 40 CFR 52.1396(d). We failed 

to specify, in the rule language itself, the 

compliance deadline for SO2 of 180 

days after the effective date of the FIP, 

and the compliance deadline for PM of 

30 days after the effective date of the 

FIP. These deadlines were mentioned in 

the rule preamble. We have corrected 

the rule language at 40 CFR 52.1396(d) 

to specify these deadlines. For both SO2

and NOX, we further clarify that the 180- 

day deadline is applicable only where 

installation of additional controls is not 

necessary to comply with the BART 

limit; otherwise the compliance 

deadline is five years after the effective 

date of our rule. 

We disagree that the compliance 

deadline should be 30/180 days after the 

FIP effective date, or the Portland 

cement NESHAP compliance date, 

whichever is later. With regard to 

‘‘whichever is later,’’ EPA does not have 

the option of specifying an open-ended 

compliance deadline for BART. In our 

FIP proposal at 77 FR 23993, we 

explained that ‘‘Once EPA has made its 

BART determination, the BART controls 

must be installed and in operation as 

expeditiously as practicable, but no later 

than five years after the date of the final 

FIP. CAA section 169(g)(4) and 40 CFR 

51.308(e)(1)(iv).’’ Ash Grove’s comment 

does not dispute this explanation. 

Further, Ash Grove has not presented 

any specific reason for us to wait on the 

Portland cement MACT rulemaking 

before imposing PM and SO2 monitoring 

requirements for purposes of BART. 

First in regard to SO2 monitoring, the 

proposed amendments to the Portland 

cement MACT and NSPS rules do not 

include any changes to the SO2 CEMS 

monitoring requirements. In the 

proposed amendments, EPA is 

proposing to correct the emission rate 

calculation formula for SO2 in NSPS 

Subpart F, at 40 CFR 60.64(c), but since 

we are making the same correction in 

our final FIP rule (see our response 

below to the comment on NOX and SO2

emission rate calculation), this is not a 

valid reason to wait until the Portland 

cement MACT and NSPS amendments 

are finalized before imposing SO2

monitoring in the FIP. 

Further, the proposed amended 

Portland cement MACT and NSPS rules 

require a SO2 CEMS only if the kiln is 

subject to an SO2 limit under NSPS. Ash 

Grove has not indicated that their kiln 

in Montana is subject to an SO2 limit 

under NSPS, and even if it is, the 

proposed amended Portland cement 

MACT and NSPS rules will not impose 

any different requirements for an SO2

CEMS than those in existing NSPS rules 

at 40 CFR 60.63(f), which are crossreferenced by our proposed regulatory 

text at 40 CFR 52.1396(e)(3). Ash Grove 

has also not presented any specific 

reason, such as vendor unavailability or 

site-specific complications, why it 

should take more than 180 days to 

replace and certify their SO2 CEMS. We 

have already stated in our FIP proposal 

that 180 days would allow time for 

monitoring systems to be certified if 

necessary. We are clarifying that CEMS 

will have to be certified for BART 

purposes independent of NSPS 

requirements. 

Second, in regard to PM monitoring, 

the proposed amendments to the 


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Portland cement MACT and NSPS rules 

require a PM continuous parametric 

monitoring system (CPMS), whereas the 

existing Portland cement MACT and 

NSPS rules require a PM CEMS. Since 

our FIP proposal does not require PM 

CPMS nor PM CEMS, the proposed 

amendments to the Portland cement 

MACT and NSPS rules do not affect the 

FIP and are not a valid reason to extend 

the 30-day compliance deadline for PM 

in the FIP. 

With regard to Ash Grove’s statement 

that critical components of the 

monitoring scheme, such as installation 

of clinker weigh belts or the 

development of slurry conversion 

mechanisms, cannot be implemented 

within the 180 day period after the 

effective date of the FIP, Ash Grove has 

not presented any specific reason why 

it should take longer than 180 days. 

With regard to Ash Grove’s statement 

that the clinker monitoring must work 

in concert with the MACT rulemaking, 

our proposed regulatory text at 40 CFR 

52.1396(e)(4)(ii) cross-references 40 CFR 

60.63(b) for clinker production 

monitoring requirements. The proposed 

amendments to the Portland cement 

MACT and NSPS rules do not change 

the requirements in the existing section 

60.63(b) for determining the amount of 

clinker produced. Only minor language 

clarifications are proposed, and there is 

no change to actual requirements. 

We note that Ash Grove has no issue 

with the proposed PM BART emission 

limit. However, in preparing responses 

to Ash Grove’s comments on other 

aspects of our proposed FIP, we 

identified a typographical error in our 

emission limit table for cement kilns. 

We made a correction to the emission 

limit table for cement kilns at 

52.1396(c)(2), to clarify that the PM 

emission limit for Ash Grove is in lb/hr, 

not lb/ton clinker. Only the PM 

emission limit for Holcim is in lb/ton 

clinker. Similarly, we have clarified 40 

CFR 52.1396(f)(2) to indicate that the 

emission rate of particulate matter shall 

be reported in lb/hr for Ash Grove, and 

in lb/ton clinker for Holcim. Ash Grove 

is not required to monitor clinker 

production for purposes of 

demonstrating compliance with the PM 

BART limit. We have also included in 

40 CFR 52.1396(f)(2) the equation for 

calculating lb/ton clinker for PM at 

Holcim, rather than cross-reference 40 

CFR 52.1396(e)(4)(ii), which pertains to 

SO2 and NOX, not PM. 

Comment: Ash Grove does not object 

to the requirement in our proposed 

regulatory text at 40 CFR 52.1396(e)(3) 

to maintain, calibrate and operate SO2

and NOX CEMS on the cement kiln 

stack. Ash Grove requests, to be 

consistent with other requirements to 

which they are subject, that the 

language be revised and proposed 

creating an exception during CEMS 

breakdown, repairs, calibration checks, 

and zero and span adjustments. 

Response: We agree it is appropriate 

to address the language for consistency 

purposes. Rather than use the language 

proposed by Ash Grove, we are 

incorporating language from 40 CFR 

60.63(g), which says, 

You must operate the monitoring system 

and collect data at all required intervals at all 

times the affected source is operating, except 

for periods of monitoring systems 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality assurance 

or quality control activities (including, as 

applicable, calibration checks and required 

zero and span adjustments). 

We have revised the regulatory text at 

40 CFR 52.1396(e)(3) accordingly. 40 

CFR 60.63(g). 

Comment: Ash Grove also believes it 

is critical that the facility have adequate 

time to install, shake down and calibrate 

the necessary CEMS equipment. The 

facility currently lacks a flow meter and 

does not have certified CEMS. As a 

result, Ash Grove anticipates that it 

must replace its CEMS system, 

including the data acquisition and 

handling system (DAHS) as part of 

Portland cement MACT 

implementation. Ash Grove stated that 

this effort cannot be completed until the 

Portland cement MACT requirements 

are finalized, as Ash Grove understands 

that the NESHAP monitoring provisions 

are in flux. Therefore, Ash Grove 

believes that the BART CEMS 

requirements must be implemented at 

the same time that the Portland cement 

MACT CEMS requirements are 

implemented and not before. 

Response: We disagree. See our 

response on compliance deadlines 

above. EPA does not have the option of 

specifying an open-ended compliance 

deadline for BART. Further, Ash Grove 

has not presented any specific reason, 

such as vendor unavailability or sitespecific complications, why it should 

take longer than 180 days to install a 

flow meter and replace the CEMS 

system with a certified system. This 

comment has not resulted in any change 

to our proposal. 

Comment: Ash Grove supports the 

approach whereby the CEMS data are 

utilized to demonstrate compliance with 

the NOX and SO2 BART limits. 

However, Ash Grove believes there is a 

material error in the formula used in the 

proposed regulatory text at 40 CFR 

52.1396(e)(4)(ii). The formula expresses 

the concentrations of SO2 and NOX in 

grains per standard cubic foot (gr/scf). 

Ash Grove noted that a CEMS would not 

normally generate SO2 or NOX

concentrations in gr/scf, but in parts per 

million (ppm), consistent with the 

requirements of 40 CFR 60, Appendix B, 

Performance Specification 2. Ash Grove 

recognizes that this formula was likely 

intended to match Equation 3 in the 

2010 revised Subpart F NSPS. While 

Ash Grove appreciates the effort to 

maintain consistency between the 

requirements, Ash Grove believes that 

Equation 3 in the Subpart F NSPS is in 

error and will be corrected in the 

upcoming public notice addressing 

Subpart F. Ash Grove provided a 

suggested formula to replace the 

formula stated in the proposed 

regulatory text. 

Response: We agree for the reasons 

stated by Ash Grove that the formula for 

calculating the emissions should 

express SO2 and NOX concentrations in 

ppm, not in gr/scf. We have corrected 40 

CFR 52.1396(e)(4)(ii) accordingly; 

however, rather than use the language 

proposed by Ash Grove, we have used 

the formula and associated language 

found in the proposed amendments to 

the Portland cement NSPS. 77 FR 

42397. 

Comment: Ash Grove noted that the 

proposed regulatory text at 40 CFR 

52.1396(f) would require that Ash Grove 

perform EPA Method 5, 5B, 5D or 17, 40 

CFR Part 60, Appendix A, to 

demonstrate compliance with the PM 

limit and that the test consist of three 

runs with each run at least 120 minutes 

long and each run collecting a minimum 

sample of 60 dry standard cubic feet. 

Ash Grove supports the approach of 

identifying the specific source test 

methods in the rule. However, Ash 

Grove does not support specifying the 

duration of each test run and the 

minimum sample size. Ash grove stated 

that this BART FIP is being 

implemented with the intent that it will 

control emissions for many years to 

come. Ash Grove stated that placing this 

type of detailed data into the rule, rather 

than letting the test duration and sample 

size be determined based on the test 

method as it exists at the time of the 

test, invites future confusion and 

trouble. Therefore, Ash Grove suggested 

that EPA specify the test methods but 

delete the other language relating to the 

test duration and sample size. 

Response: We disagree. The test 

method does not determine the test 

duration and sample size, but crossreferences other rules in this regard. 

EPA Method 5 states in subsection 8.2.4, 

‘‘Select a total sampling time greater 

than or equal to the minimum total 

sampling time specified in the test 


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procedures for the specific industry, 

such that (1) the sampling time per 

point is not less than 2 minutes (or some 

greater time interval as specified by the 

Administrator), and (2) the sample 

volume taken (corrected to standard 

conditions) will exceed the required 

minimum total gas sample volume.’’ 

Methods 5B and 5D cross-reference 

Method 5 for sampling time and 

sampling volume. Method 17 does not 

cross-reference Method 5 for sampling 

time and sampling volume, but does not 

specify anything different. We consider 

three test runs, with each run at least 

120 minutes long, and each run 

collecting a minimum sample of 60 dry 

standard cubic feet, to be appropriate 

and necessary for purposes of the 

Montana Regional Haze FIP. We note 

that this has been specified in PM stack 

testing requirements in other regional 

haze FIPs. (See, for example, Proposed 

Final FIP by EPA Region 9 for the Four 

Corners Power Plant, 76 FR 52387, 

August 22, 2011.) This comment has not 

resulted in any change to our proposal. 

Comment: Ash Grove stated that the 

proposed regulatory text at 40 CFR 

52.1396(h)(6) would require that they 

maintain, among other things, records 

required by Part 75. Ash Grove is not 

subject to part 75 as that applies only to 

electrical generating units. Ash Grove 

believes that this reference to Part 75 

was just a ‘‘catch-all’’ and not intended 

to impose any obligations under Part 75 

upon cement kilns otherwise not subject 

to Part 75. However, due to the potential 

for misunderstanding and the lack of 

relevance of the Acid Rain provisions to 

cement kilns, Ash Grove requested that 

the reference to Part 75 be deleted. 

Response: We agree. Since the 

proposed monitoring requirements for 

cement kilns, at sections 52.1396(e)(3) 

and (4), and at section 52.1396(f)(2), do 

not cross-reference Part 75, there are no 

applicable Part 75 recordkeeping 

requirements under our FIP proposal. 

Therefore, the reference to Part 75 on 

recordkeeping, at 40 CFR 52.1396(h)(6), 

is not necessary and has been removed. 

Comment: Ash Grove stated that the 

proposed regulatory text at 40 CFR 

52.1396(i) would require that Ash Grove 

submit quarterly excess emission 

reports and CEMS performance reports. 

Ash Grove currently is subject to similar 

reporting requirements under the Title 

V and NESHAP programs. However, in 

both of those programs the reports are 

submitted semi-annually, not quarterly. 

Ash Grove sees no purpose gained by 

submitting the reports quarterly and the 

additional administrative burden is 

significant. Therefore, Ash Grove 

requested that EPA revise this reporting 

requirement to make it consistent with 

the similar reports submitted under 

Title V and NESHAP programs, i.e., 

semiannual reports. 

Response: We agree. We used 

provisions in NSPS Subparts A and F 

applicable to cement kilns as a model 

for the CEMS-related reporting 

requirements for cement kilns in our FIP 

proposal. The general provisions of 

NSPS Subpart A, at 40 CFR 60.7(c), 

require semiannual excess emission 

reports and monitoring systems 

performance reports, except when more 

frequent reporting is specifically 

required by an applicable subpart, or if 

the Administrator, on a case-by-case 

basis, determines that more frequent 

reporting is necessary to accurately 

assess the compliance status of the 

source. NSPS Subpart F for cement kilns 

does not specify more frequent 

reporting. Therefore, we have revised 

the required reporting frequency to 

semiannual in 40 CFR 52.1396(i)(1) and 

(i)(2) for cement kilns. The required 

reporting frequency for EGUs remains 

quarterly. 

Comment: Ash Grove requested that 

EPA revise its proposed regulatory text 

at 40 CFR 52.1396(i)(2)(ii) requiring the 

company to submit Relative Accuracy 

Audits (RAAs) and Cylinder Gas Audits 

(CGAs). Ash Grove does not object to 

the idea of submitting Relative Accuracy 

Test Audits (RATAs) as those are 

documented in a highly formalized test 

report prepared by a third party testing 

contractor. However, the RAAs and 

CGAs are not documented in the same 

type of formal third party report. Ash 

Grove believes that it is adequate to 

certify that the audits have been 

performed as part of the semiannual 

reports. 

Response: We disagree. Our proposed 

regulatory text at 40 CFR 52.1396(e)(3) 

states that the CEMS shall be used to 

determine compliance with the 

emission limitations in section 

52.1396(c), for each unit, in 

combination with data on actual clinker 

production. For cement kilns, 40 CFR 

section 52.1396(i)(2)(ii) requires 

submittal of results of any CEMS 

performance tests required by 40 CFR 

part 60, appendix F, Procedure 1, which 

is titled ‘‘Quality Assurance 

Requirements for Gas Continuous 

Emission Monitoring Systems Used for 

Compliance Determination.’’ Under 

Section 7 of Procedure 1 (Reporting 

Requirements), it is not adequate to 

merely certify that the RAAs and CGAs 

have been performed. Section 7 requires 

submittal of a Data Assessment Report 

for each quarterly audit, which must 

include ‘‘Assessment of CEMS data 

accuracy and date of assessment, as 

determined by a RATA, RAA or CGA 

described in Section 5, including * * *, 

the A [accuracy] for the RAA or CGA, 

the RM [reference method] results, the 

cylinder gases certified values, the 

CEMS responses, and the calculations 

results as defined in Section 6.’’ This 

information must be included in the 

semiannual reports referenced in our 

response to the previous comment 

above. We consider this information 

appropriate and necessary. This 

comment has not resulted in any change 

to our FIP proposal. 

Comment: Ash Grove requested that 

EPA drop the requirement proposed in 

40 CFR 52.1396(k)(2) to provide 

semiannual progress reports on 

construction of SO2 and NOX control 

equipment. Ash Grove does not object to 

filing notification of commencement of 

construction as this obligation is 

consistent with what Ash Grove is used 

to under the NSPS and state new source 

review program. However, semiannual 

construction progress reports are not 

something that Ash Grove is typically 

set up to generate and there seems to be 

little gained from such reports. 

Therefore, Ash Grove requested that this 

requirement be dropped from the rule. 

Response: We disagree. We consider 

construction progress reports necessary 

as part of ensuring that BART sources 

meet their five-year compliance 

deadlines. Since installation of 

substantial equipment may be involved, 

there could be unforeseen construction 

delays that we would want to be aware 

of well before the five-year deadline. We 

do not consider this reporting a 

burdensome requirement, as our FIP 

proposal does not specify any particular 

level of detail for these progress reports. 

This comment has not resulted in any 

change to our FIP proposal. 

Comment: Ash Grove noted that the 

BART limits are identified as applying 

at all times, including startup, 

shutdown and malfunction. Although 

the preamble states that the proposed 

limits allow ‘‘for a sufficient margin of 

compliance,’’ Ash Grove argued that 

these limits do not take into account the 

impact of sudden and unforeseen effects 

attributable to malfunctions. As 

compliance with all three limits (i.e., 

SO2, PM and NOX) could be affected by 

a malfunction, Ash Grove believes that 

it is appropriate for EPA to provide the 

same affirmative defense in the event of 

a malfunction as is provided in the 

Portland cement MACT rules. 

Specifically, Ash Grove requested that 

EPA incorporate the same affirmative 

defense provided in 40 C.F.R. 63.1344 to 

address malfunctions. 

Response: EPA disagrees with this 

comment. As stated in our proposal, to 

determine the BART NOX limit for Ash 


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Grove, we first applied the efficiency of 

the selected controls, LNB + SNCR at 

58%, to the 99th percentile 30-day 

rolling average NOX emission rate at this 

facility for May 26, 2006 through 

September 8, 2008, resulting in a figure 

of 7.82 lb/ton clinker. 77 FR at 24007 

n.45. We then set the BART limit above 

this, at 8.0 lb/ton clinker. Ash Grove 

provides no data to show that, at this 

facility, this limit cannot be achieved 

due to malfunctions, or that our use of 

the 99th percentile 30-day rollingaverage NOX emission rate in 

combination with the additional margin 

(from 7.82 to 8.0 lb/ton clinker) 

provides an insufficient margin of 

compliance. 

For SO2, we did not select any 

additional controls for BART. We based 

the BART SO2 limit on the 99th 

percentile 30-day rolling average SO2

emission rate at this facility for May 26, 

2006 through September 8, 2008, 11.02 

lb/ton clinker, and set the BART limit 

at 11.5 lb/ton clinker. 77 FR at 24013 

n.73. Ash Grove provides no data to 

show that, at this facility, this limit 

cannot be achieved due to malfunctions, 

or that our use of the 99th percentile 30- 

day rolling average SO2 emission rate at 

this facility in combination with the 

additional margin (from 11.02 to 11.5 

lb/ton clinker) provides an insufficient 

margin of compliance. 

We also did not select any additional 

controls for PM. Ash Grove currently 

has an electrostatic precipitator for PM 

control and is subject to a process 

weight-based PM10 emission rate set out 

in Montana’s approved SIP and Ash 

Grove’s title V operation permit. We set 

the BART limit, based on use of the 

current control technology, at the 

existing emission rate. Ash Grove has 

not provided any data to show that it is 

not able to meet the existing limit due 

to malfunctions. As a result, we 

continue to maintain that the NOX, SO2, 

and PM BART limits for Ash Grove 

provide for a sufficient margin of 

compliance, including taking into 

account malfunctions. 

With respect to the Portland cement 

MACT standard, we note that the MACT 

standard applies across the entire source 

category, while the BART limits 

imposed in this FIP reflect application 

of the five statutory BART factors to a 

particular facility, Ash Grove. Ash 

Grove does not explain why, in this 

circumstance, the existence of the 

affirmative defense in the MACT 

standard necessarily implies an 

affirmative defense is required for the 

BART limits, which as discussed above, 

for NOX and SO2 are based in part on 

actual emissions from Ash Grove, and 

for PM are based on an existing limit for 

Ash Grove. We therefore disagree that 

the affirmative defense provided for in 

40 CFR section 63.1344 should be also 

provided for in this FIP. 

Comment: The opening sentence of 

the proposed regulatory text at 40 CFR 

52.1396(i) states ‘‘All reports under this 

section, with the exception of 40 CFR 

53.1395(n) and (o) shall be submitted 

* * *’’ Ash Grove believes that this 

cross-reference is in error, as Ash Grove 

is not aware of there being a 40 CFR 

53.1395(n) or (o). Ash Grove believes 

this was intended to cite to 40 CFR 

52.1396(n) and (o). 

Response: We agree this was an error. 

We have corrected the language to cite 

to section 52.1396(n) and (o), instead of 

section 53.1395(n) and (o). 

E. Comments on Holcim 

Comment: Montanans Against Toxic 

Burning (MATB) applauded our 

proposed retrofit of the Holcim kiln to 

include LNB and SNCR. 

Response: We acknowledge MATB’s 

support. 

Comment: MATB believes that we 

should reanalyze the fuel-switching 

option for the Holcim cement kiln. 

Specifically, they stated that petroleum 

coke inputs should be reduced, which 

they believe would lead to significant 

reductions in SO2 emissions. They also 

stated that our analysis may be skewed 

by what MATB describes as Holcim’s 

‘‘low-ball’’ estimates of its sulfur 

emissions. MATB believes that a review 

of Holcim’s past monitoring data could 

lead to a different conclusion. 

Response: We disagree that it is 

necessary to reanalyze fuel switching 

options for Holcim. In our analysis, we 

used annual SO2 emissions as reported 

to the National Emissions Inventory and 

we have no reason to believe that these 

were underestimated. The annual 

emissions (50.2 tpy) are so minimal that 

fuel switching options resulting in 

increased annual cost would not be 

considered cost-effective on a dollar per 

ton basis. In addition, the visibility 

improvement from fuel switching is 

very low at 0.015 deciview for fuel 

switching option 1 and 0.024 deciview 

for fuel switching option 2. 

Comment: MATB commented that a 

‘‘real-time hourly’’ standard for NOX

and SO2, rather than the 30-day rolling 

averages based on clinker production 

proposed, is needed to assure 

compliance with protective limits. 

MATB explained that with the 30-day 

rolling averages, spikes due to 

malfunction or improper operation will 

‘‘disappear’’ in the averaging process. 

Response: We assume that by ‘‘realtime hourly’’ standard, the commenter 

means an emission limit in pounds per 

hour. We disagree that we should 

establish an hourly standard rather than 

a 30-day rolling average limit based on 

clinker production. As we explained in 

our proposal (77 FR 24007), we chose an 

output-based standard because it avoids 

rewarding a source for becoming less 

efficient, i.e., requiring more feed to 

produce a unit of product. An outputbased standard promotes the most 

efficient production process. With 

regard to 30-day versus hourly averaging 

time, EPA’s BART guideline calls for 

BART emission limits to be expressed as 

30-day rolling averages for electrical 

generating units. 70 FR 39172. We 

believe this is appropriate for other 

BART units as well. The proposed limit 

allows for a sufficient margin of 

compliance for a 30-day rolling average 

limit that would apply at all times, 

including startup, shutdown, and 

malfunction. 77 FR 24018. 

Comment: MATB believes that more 

oversight, transparency, and 

accountability are needed when it 

comes to reporting and record keeping. 

Response: We are confident that the 

information used to make our decision 

is accurate. With regard to reporting and 

recordkeeping requirements under the 

FIP, the commenter has not explained 

what oversight, transparency and 

accountability is lacking and what more 

is needed in this regard. That said, 

section 114 of the CAA allows EPA and 

the State to ask for monitoring data and 

reports as necessary. These documents 

are available to the public unless the 

information is claimed to be 

confidential business information. 

Comment: MATB commented that the 

efficiency of Holcim’s ESP is incorrect 

as stated in EPA’s analysis, and does not 

operate during most malfunctions. 

These malfunctions can last 24 hours or 

more. Additionally, MATB stated that 

EPA’s analysis fails to consider PM 

during periods of startup, shutdown and 

malfunction and considering the 

frequent upsets with the Trident kiln, 

that cause its ESP to be turned off, an 

additional control measure at Holcim is 

essential. MATB encouraged us to 

analyze the addition of a fabric filter. 

Response: We disagree that it is 

necessary to evaluate the installation of 

a fabric filter at Holcim. In our proposal, 

we explained that PM emissions from 

Holcim did not significantly contribute 

to visibility impairment. We used actual 

emission rates to model the visibility 

impact from Holcim. Because the 

baseline visibility impact from PM was 

low, improvements to the existing PM 

control device would not be significant. 

Comment: The commenter stated that 

an annual three-hour stack test is 


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12See Table 11, FR 77 24004, and Table 22, 77 

FR 24007 for Ash Grove. Holcim’s baseline NOX

emissions are 1,112 tpy. Revised emissions 

reduction for SNCR only for Holcim is 556 tpy and 

cost is $1,170/ton. 

inadequate to monitor PM emission 

limit compliance. 

Response: We disagree. The proposed 

requirements for demonstrating 

compliance with PM emission limits 

include more than just an annual threehour stack test. ‘‘In addition to annual 

stack tests, owner/operator shall 

monitor particulate emissions for 

compliance with the BART emission 

limits in accordance with the applicable 

Compliance Assurance Monitoring 

(CAM) plan developed and approved in 

accordance with 40 CFR part 64.’’ 77 FR 

24099. The requirements include the 

following: 

• 40 CFR 64.3(a) requires that a 

monitoring parameter be selected by the 

owner/operator as an indicator of 

emission control performance for the 

control device. 

• 40 CFR 64.3(b) requires that an 

indicator range for that parameter be 

selected ‘‘such that operation within the 

range provides a reasonable assurance of 

ongoing compliance with emission 

limitations or standards for the 

anticipated range of operating 

conditions.’’ 

• 40 CFR 64.7(d) requires the owner/ 

operator, upon detecting an excursion or 

exceedance of the CAM indicator range, 

to restore operation of the emitting unit 

and emission control device to its 

normal or usual manner of operation as 

expeditiously as practicable, in 

accordance with good air pollution 

control practices for minimizing 

emissions. 

• 40 CFR 64.8 says the Administrator 

or permitting authority may require the 

owner/operator, in the event of repeated 

excursions or exceedances of the CAM 

indicator range, to develop and 

implement a Quality Improvement Plan, 

to correct any control device 

performance problems. 

Further, 40 CFR 52.11396(l) states, 

‘‘At all times, owner/operator shall 

maintain each unit, including associated 

air pollution control equipment, in a 

manner consistent with good air 

pollution control practices for 

minimizing emissions’’ This applies to 

all sources in the FIP. 

Comment: MATB explained that there 

are inconsistencies in EPA’s proposed 

NOX and SO2 emissions limits, and 

there appears to be a mistake on Table 

53 dealing with fuel-switching options. 

Response: These inconsistencies were 

corrected in the FR notice dated May 17, 

2012. 77 FR 29270. 

Comment: Holcim commented that 

that the output-based standards we 

proposed reward a source for operating 

inefficiently. Holcim indicated that our 

proposed FIP is unfairly stringent with 

respect to Holcim as compared to Ash 

Grove. They stated that the kiln types 

and capacities of the two plants are 

substantially equal, but that Holcim’s 

emissions profiles are notably different. 

Holcim stated that they use proper kiln 

design and best combustion practices to 

control NOX emissions at their plant, 

and that Ash Grove has NOX emissions 

that are 42% higher than NOX emissions 

from the Holcim plant. Holcim further 

stated that our proposed FIP rewards 

Ash Grove with a NOX BART emission 

limit that is 60% higher than Holcim’s 

proposed NOX BART emission limit. 

Holcim pointed out that their kiln has 

substantially lower current NOX

emission rates, lower current visibility 

impacts, and a lower subsequent 

visibility improvement, yet our FIP 

requires substantially tighter emission 

limits for NOX and SO2.

Holcim commented that, based on 

EPA’s analysis, the proposed NOX limit 

would require Holcim to invest a total 

of $5.6 million in SNCR and indirect 

firing, which would result in an 

improvement in visibility at Gates of the 

Mountains WA that is significantly less 

than the 1.0 deciview perceptibility 

threshold and that our proposed FIP 

would require only a $1.19 million 

capital investment from Ash Grove, 

even though Ash Grove’s impact on 

Gates of the Mountains WA is more than 

double the impact from Holcim. Holcim 

also stated that we estimated that Ash 

Grove’s NOX emissions caused 

degradation in visibility of greater than 

0.5 deciview at Gates of the Mountains 

WA on approximately 33% of the days 

in the baseline period while Holcim 

impacted Gates of the Mountains WA at 

greater than 0.5 deciview only on 

approximately 4% of the days during 

the baseline period. Holcim stated that 

EPA’s approach would reward Ash 

Grove’s higher emissions and inefficient 

operation by creating an economic 

disadvantage for Holcim in a highly 

competitive market. 

Response: We disagree. Our 

explanation in the proposed FIP 

regarding the output-based standard was 

provided to explain the difference 

between a standard expressed in 

quantity of pollutant per amount of feed 

and quantity of pollutant per amount of 

product produced. As explained in our 

proposal, an output-based standard 

avoids rewarding a source for becoming 

less efficient, i.e., requiring more feed to 

produce a unit of product. 77 FR 24007. 

Our explanation did not imply that both 

sources should have exactly the same 

emission rate. The NOX standards for 

both Holcim and Ash Grove were 

determined by applying the control 

efficiency of the selected technologies to 

the current emission rates at each 

facility. This is the most appropriate 

method to determine emission limits for 

these two sources. As explained in other 

responses, we are not requiring Holcim 

to convert to indirect firing in the final 

FIP, so the information comparing 

capital investment is no longer relevant. 

In the final FIP, we have determined the 

emission rate for Ash Grove by applying 

the control effectiveness of LNB + SNCR 

(58%) to the current emission rate and 

as explained in other responses we have 

revised the emission rate for Holcim by 

applying the control effectiveness of 

SNCR (50%) to the current emission 

rate. In both cases, we have determined 

the emission rate based on the control 

effectiveness of the control technology 

that was chosen based on the five 

statutory BART factors listed at CAA 

section 169A(g)(2) and 40 CFR 

51.308(e)(1)(ii)(A). The five statutory 

factors include the costs of compliance 

and visibility improvement; therefore, 

these factors were evaluated and 

considered in the selection of controls. 

Applying the control effectiveness of the 

technology that was identified based on 

the five statutory factors to the current 

emission rates for each source is a 

logical method for determining emission 

rates. This same methodology was used 

for determining the emission rates for 

both sources. 

We note that in the final FIP, Ash 

Grove will reduce an estimated 1,088 

tons per year of NOX using LNB+SNCR 

at a total annual cost of $2,238,893, but 

Holcim will only reduce an estimated 

556 tons per year of NOX at a total 

annual cost of $650,399. Ash Grove will 

be reducing 946 tons per year of NOX

through the operation of SNCR, but 

Holcim will only be reducing 556 tons 

per year through the operation of 

SNCR.12 We provide this information to 

demonstrate that overall, more 

emissions will be reduced by Ash Grove 

and to also illuminate the fact that 

annual cost will be greater for Ash 

Grove. The cost of reagent is 

proportional to the amount of pollutant 

removed; therefore, annual reagent cost 

will be significantly greater for Ash 

Grove. 

We are not requiring additional 

controls for SO2 for either Holcim or 

Ash Grove and the SO2 limits for each 

facility were determined based on 

current emission rates. This 

determination was based on an 

evaluation of the five statutory factors 

and the SO2 emission rates were 

determined in the same manner for both 


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13Miller, F. M., ‘‘Management of Detached 

Plumes in Cement Plants’’ 2001 IEEE–IAWPCA 

Cement Industry Technical Conference Vancouver, 

British Colombia, Canada April 2001. 

facilities. There is no necessity for 

additional SO2 control at either facility; 

the current controls were considered to 

be BART. 

As for Holcim’s comment that the 

proposed FIP rewards Ash Grove’s 

higher emissions and inefficient 

operation by creating an economic 

disadvantage for Holcim in a highly 

competitive market, the BART 

Guidelines do allow for the 

consideration of unusual circumstances 

that justify taking into consideration the 

conditions of the plant and the 

economic effects of requiring the use of 

a given control technology. The BART 

Guidelines state: 

[t]hese effects would include effects on 

product prices, the market share, and 

profitability of the source. Where there are 

such unusual circumstances that are judged 

to affect plant operations, you may take into 

consideration the conditions of the plant and 

the economic effects of requiring the use of 

a control technology. Where these effects are 

judged to have a severe impact on plant 

operations you may consider them in the 

selection process, but you may wish to 

provide an economic analysis that 

demonstrates, in sufficient detail for public 

review, the specific economic effects, 

parameters, and reasoning. 

70 FR 39171. Holcim did not provide 

information for us to consider in such 

an analysis. 

The BART Guidelines also state, 

‘‘[a]ny analysis may also consider 

whether other competing plants in the 

same industry have been required to 

install BART controls if this information 

is available.’’ 70 FR 39171. In this case, 

Ash Grove is required to install BART 

controls. We have considered each plant 

individually, and based on the BART 

analyses both Holcim and Ash Grove 

plants are required to install BART 

controls. 

Comment: Holcim argued that the 

Texas kilns cited by EPA in the FIP are 

not representative and two of the three 

kilns did not achieve 50% NOX

reduction. Holcim cited several sitespecific factors that impact SNCR 

performance that they state EPA did not 

adequately consider, including 

turbulent mixing, heat transfer, spray 

droplet size, spray drop evaporation, 

devolatilization and others. Holcim also 

argued that the carbon monoxide (CO) 

levels at the Trident kiln are much 

lower than the CO levels at the Texas 

kilns, which will adversely impact NOX

reductions and ammonia slip at the 

Trident kiln relative to the Texas kilns. 

Holcim additionally argued that EPA 

did not adequately consider NOX

emissions variability in setting the limit 

because of the limited time frame 

considered for the data from the Texas 

kilns. 

Response: We disagree. EPA has 

assumed that 50% reduction is possible 

with SNCR; however, this does not rule 

out the possibility that Holcim may 

determine that other means, such as 

mid-kiln firing, may be better than 

SNCR alone in terms of cost or other 

factors for achieving 50% NOX

reduction. In any event, 50% NOX

reduction is achievable with SNCR and 

this is supported by the data cited in the 

proposed FIP. We address this in more 

detail in a response to Ash Grove. 

Holcim also noted that SNCR 

performance depends upon a wide 

range of site-specific factors. They list 

rate-limiting processes, including 

turbulent mixing, heat transfer, spray 

droplet size, spray drop evaporation, 

devolatilization and others. As detailed 

in a contractor’s report in the docket, we 

have considered these factors and none 

of them causes us to change our 

decision. In brief, spray droplet size is 

a factor the SNCR system designer can 

control and tailor to the needs of the 

system. Turbulent mixing may or may 

not be within the SNCR system 

designer’s ability to control, but in any 

case our selection of SNCR does not 

depend on optimal turbulent mixing. 

With respect to CO concentration, if 

the CO at the Trident kiln is much lower 

than at the Texas kilns referred to in the 

comments, as Holcim describes, this 

simply means that the SNCR reagent 

should be introduced at a point in the 

process where the gas temperature is 

higher than the injection point used at 

the Texas kilns where the CO levels are 

higher. This may in fact improve SNCR 

performance. 

With regard to NOX emission 

variability raised by Holcim, first, the 

data used by EPA in Table 10 of the 

proposed FIP cover a three month 

period which should be adequate time 

to address normal operating changes 

that would impact NOX. Second, SNCR 

can be used to mitigate variability in 

NOX emissions. This is confirmed by 

the data on the Midlothian kilns that is 

in the proposed FIP and as described in 

response to comments from Ash Grove. 

For every kiln, the standard deviation in 

the monthly NOX emission rate was 

lower after the application of SNCR than 

before, indicating a lower variation in 

NOX emissions. 

Comment: Holcim argued that a 

detached plume may result from 

operation of the SNCR in the winter 

months, which will make it necessary to 

not operate the SNCR system or to allow 

a condition where visibility is adversely 

impacted to continue. The detached 

plume could be the result of the 

formation of ammonium salt reactions 

with sulfate or chlorides. 

Response: We disagree. As discussed 

by Miller,13 there are several factors that 

could contribute to a visible detached 

plume, and these include moisture, 

temperature, and availability of the 

constituents that contribute to the 

plume—ammonia, sulfates and 

chlorides. Ammonia slip from the SNCR 

process can be well controlled in a 

cement kiln, and the SNCR system 

would not affect the amount of 

ammonia contributed by raw materials. 

Sulfates and chlorides are largely the 

result of impurities in the raw materials, 

and ammonia can be contributed by raw 

materials. Holcim’s SO2 emissions are 

low indicating low levels of sulfates in 

the exhaust. Therefore, the risk of an 

ammonium sulfate plume, even with 

ammonia present, is small. The 

presence of chlorides will depend upon 

the raw materials and whether the 

chlorides become bound to alkaline 

material before being emitted up the 

stack. 

Chlorides, if present, will typically 

preferentially be bound to alkaline 

material that is present rather than be 

emitted. Holcim did not provide any 

information on stack chloride emission 

levels at this site to support their 

concerns about detached plume from 

ammonium chloride. 

Because of the importance of 

impurities in the raw materials in 

contributing to the chemical 

constituents that form a plume, the 

experience at one kiln cannot be 

directly applied to another without 

more information. Therefore, while 

there may be a risk of a visible plume 

at the Trident kiln, Holcim has not 

provided enough data to indicate that 

addition of an SNCR system would 

increase this risk significantly. 

Furthermore, a localized plume would 

not necessarily impact a Class I area and 

Holcim has not provided any 

information indicating such an impact. 

Comment: Holcim indicated that EPA 

failed to consider the NOX control 

technology already installed at the 

Trident plant. Holcim explains that they 

changed the burner at Trident in May 

2009 to a multichannel LNB design as 

part of the company’s burner system 

modification for NOX control, as 

detailed in Holcim’s 2007 BART 

analysis. 

Holcim stated that EPA’s BART 

analysis ignored the installation of the 

multichannel LNB at the Trident plant, 

in contravention of EPA’s obligation to 

consider ‘‘any existing pollution control 


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Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57881 

14August 2009 Submittal (EPA–R08–OAR–2011– 

0851–0038); Letter from Callie A. Videtich to Ned 

Pettit (Nov. 26, 2007) (EPA–R08–OAR–2011–0851– 

0038). 

technology in use at the source’’ as part 

of the five-factor BART analysis. 42 

U.S.C. 7491(g)(2). Holcim’s BART 

analysis was prepared and submitted in 

2007, before the multichannel LNB 

technology was installed. 

Holcim explains that they originally 

installed a multichannel burner in April 

2008 but it caused operational issues 

and was removed in July 2008. The 

multichannel burner was redesigned, 

installed in May 2009, and has operated 

continuously since that time. According 

to Holcim, the multichannel design 

allows the fuels to be separated into 

different channels and enables Holcim 

to more precisely control the amount of 

air passing through each of the 

channels. Consequently, Holcim says, 

they can better control the flame 

characteristics in the kiln, which results 

in higher thermal efficiency of the kiln 

and improved product quality. 

Holcim stated that they also 

anticipated that the multichannel design 

would reduce NOX and SO2 emissions. 

Holcim acknowledges that the effects of 

the technology are difficult to quantify. 

Based on a comparison of NOX

emissions pre- and post-installation of 

the LNB technology where the fuel mix 

was generally the same, Holcim says the 

plant’s NOX emissions decreased by 

approximately 13% with the installation 

of the multichannel LNB. In addition to 

the multichannel LNB, Holcim stated 

that they installed an indirect firing 

system for the petroleum coke system. 

Holcim notes that EPA used a 

baseline for the Trident plant of years 

2008 through 2011, a period of time that 

already includes the effects of the LNB 

technology at the plant. Holcim stated 

that EPA assumed in its BART proposal 

for the Trident plant that the 

combination of LNB and indirect firing 

would achieve a NOX reduction of 15%. 

However, Holcim stated that a 13% 

reduction in NOX emissions has already 

been achieved through prior installation 

of the multichannel LNB. Holcim states 

there is no basis to assume that indirect 

firing would improve NOX emissions 

reductions at Trident and that 

additional NOX reductions can only be 

obtained through installation of SNCR. 

As a result, Holcim concludes that 

EPA’s analysis of the cost-effectiveness 

and visibility impact for the installation 

of indirect firing is, ‘‘clearly erroneous 

and should be disregarded’’. 

Response: We agree with aspects of 

this comment, but disagree with others. 

As described in more detail below, 

Holcim has not provided enough 

information to demonstrate that the 

installed multi-channel burner that 

Holcim installed is in fact a low NOX

burner. In any case, the baseline used 

for the BART analysis included 

emissions averaged over a four year 

period (2008–2011), which would have 

included the time that the multichannel burner was installed. We have 

decided that the incremental cost of 

indirect firing and a low NOX burner is 

not justified and have revised the BART 

emission limit accordingly. 

We agree that our BART proposal, did 

not consider installation of the new 

burners that Holcim describes as 

‘‘multichannel LNB’’ in its March 20, 

2008 letter to Vickie Walsh of the 

MDEQ. As the June 9, 2009 letter from 

Holcim to EPA notes, ‘‘a low NOX

burner modification would require low 

primary air and, thus, a conversion of 

Trident’s firing system from a direct to 

an indirect system.’’ Based on the 

information we have, it appears that the 

Trident kiln has not installed an 

indirect firing system for coal and 

therefore the multichannel burner does 

not meet the definition of LNB in 

Holcim’s letter. The burner is not 

capable of operating at low primary air 

levels on pulverized coal and cannot 

achieve the NOX reductions that an 

indirect firing system would achieve. 

However, we disagree that we must 

credit the newly installed burner with a 

13% reduction in NOX emissions, 

because we are lacking validation data 

that such a reduction has been achieved. 

Holcim has only presented summary 

information to support the claim of 13% 

reduction and has not provided the 

underlying data to validate its claim. 

Our examination of NOX emissions data 

provided by Holcim on March 2, 2012, 

covering the period from 2008 through 

2011 (referenced in our proposal at 77 

FR 24018, footnote 93), does not reveal 

any evidence of sustained NOX emission 

reduction after May of 2009. We have 

used data from the time period 2009– 

2011, after the new burner was 

installed, in calculating baseline 

emissions. 77 FR 24014, Table 39, 

footnote 1. This baseline accurately 

reflects current conditions and is 

appropriate for comparison to available 

control scenarios. 

Nevertheless, since a switch to 

indirect firing to accommodate 

installation of LNB, as described in our 

FIP proposal, would have an 

unreasonably high incremental costeffectiveness of $8,029/ton, with 

minimal visibility benefits (see our 

response below), we are not requiring a 

switch to indirect firing and LNB as 

BART in the final FIP. We also are 

clarifying that we intended this option 

to include switching to indirect firing 

and a LNB. We have recalculated the 

proposed BART limit for NOX to reflect 

a 50% reduction in NOX emissions from 

that baseline by addition of SNCR alone, 

rather than the 58% reduction we 

previously used, which reflected 

switching to indirect firing and adding 

a LNB plus SNCR. 

In recalculating our proposed BART 

emission limit for NOX, we continue to 

rely on the estimate of baseline NOX

emissions in lb/ton clinker provided in 

Holcim’s 2012 submittal, cited in our 

proposal at 77 FR 24018, footnote 93. 

That submittal listed a 99th percentile 

30-day rolling average NOX emission 

rate of 12.6 lb/ton clinker, for the period 

2008–2011. Applying a 50% reduction 

to the 99th percentile figure yields 6.3 

lb/ton clinker. To allow for a sufficient 

margin of compliance for a 30-day 

rolling average limit that would apply at 

all times, including startup, shutdown 

and malfunction (as explained in our 

proposal at 77 FR 24018), we are setting 

the BART limit at 6.5 lb/ton clinker in 

our final rule. 

Since the estimated baseline NOX

emissions have not changed from our 

proposal, and since our estimate of 50% 

NOX reduction for SNCR alone has not 

changed from our proposal, our estimate 

of 556 tons per year of expected NOX

reduction for SNCR alone has also not 

changed from our proposal. 

Comment: Holcim stated that EPA 

underestimated the costs of installing 

and maintaining a SNCR system. 

Holcim stated that the company 

calculated the direct annual costs of 

SNCR to be $443,341 and the indirect 

annual costs for SNCR to be $227,538, 

and that these calculations employed a 

15-year amortization schedule, as 

requested by EPA in 2007.14 Holcim 

noted that EPA’s estimated direct 

annual costs and indirect annual costs 

for SNCR are lower than Holcim’s 

estimates by approximately 67% and 

46%, respectively and suggested that 

the difference may be at least in part 

due to EPA’s use of a 20-year period in 

the proposal. 

Holcim stated that it is unclear how 

EPA derived its numbers and that EPA 

provided no explanation in the FIP 

proposal. Holcim requested clarification 

of EPA’s method for calculating these 

costs and urged EPA to instead use the 

cost calculation numbers provided by 

Holcim. 

Also, Holcim stated that if EPA 

reviews selective catalytic reduction 

(SCR) for cement kilns in subsequent 

reasonable progress planning periods, 

and determines that Holcim must install 

SCR instead of SNCR at that time then 


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57882 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

the 20-year amortization for SNCR costs 

would not accurately reflect the annual 

costs of installing SNCR. Holcim also 

stated that since the company 

conducted its original analysis, Holcim 

has installed SNCR at its plant in 

Hagerstown, Maryland in 2011, which 

also has a long kiln. Holcim stated that 

the total capital costs for the SNCR 

installation at Hagerstown were 

approximately $1,920,000, including the 

cost of commissioning and spare parts 

and that, in addition, Hagerstown 

budgeted $591,000 for 2012 operating 

costs ($1.35 per metric ton of clinker or 

$1.23 per metric ton of cement). Holcim 

stated that actual operating costs for 

2012 through the end of April have been 

$179,000 ($1.40 per metric ton of 

clinker or $1.28 per metric ton of 

cement). Holcim anticipates that similar 

capital and operating costs would apply 

to the installation of SNCR at Trident. 

Holcim requested that EPA use these 

updated figures in its analysis of the 

costs of SNCR at Trident. 

Response: We agree with aspects of 

this comment, but disagree with others. 

We note that the letter to which Holcim 

refers requested that Holcim reanalyze 

annualized costs using a 15-year 

amortization period for a scrubber, not 

SNCR. We agree that EPA 

underestimated the cost of SNCR and 

that clarification on cost is needed, but 

we disagree with the statement that EPA 

provided no explanation in its proposal 

on how EPA derived its cost numbers. 

We also disagree with the statement that 

EPA provided no explanation for use of 

a 20-year amortization period. We also 

disagree with the statement that SNCR 

costs at the Trident kiln should be 

similar to Holcim’s Hagerstown kiln. 

We agree that we underestimated the 

cost of SNCR and that clarification is 

needed. The underestimate arose from 

our omission of cost of reagent. In 

Holcim’s August 12, 2009 submittal, 

two versions of a SNCR cost spreadsheet 

were included. In one version, Holcim 

redacted the line item for reagent cost, 

on the basis of a Confidential Business 

Information (CBI) claim. This was the 

version we used for our proposal. 

However, in its cover letter for the 

August 12, 2009 submittal, Holcim 

stated that it later retracted its CBI 

claim. So the submittal included a 

second version of the same SNCR cost 

spreadsheet, in which the reagent line 

item now appears. The reagent cost is 

listed by Holcim in this second version 

at $379,183. 

We have recalculated the annual costs 

of SNCR to include the cost of reagent. 

Relying on the second version of the 

cost spreadsheet in Holcim’s August 12, 

2009 submittal, we now calculate the 

annual costs other than capital recovery 

at $526,471 and the total annual cost, 

including capital recovery, at $650,399. 

Using an estimated emission reduction 

of 556 tons per year of NOX, as we did 

in our proposal (which is a 50% 

reduction from the NOX emissions 

baseline of 1,112 tons per year), we have 

recalculated the cost-effectiveness of 

SNCR at $1,170/ton. At this costeffectiveness, we still consider SNCR to 

be BART for NOX. Holcim has given us 

no reason to think otherwise. 

We disagree with the statement that 

EPA provided no explanation in its 

proposal on how EPA derived its cost 

numbers. We explained that we relied 

on cost estimates supplied by Holcim 

for capital costs and annual costs of 

SNCR, with the exception of the Capital 

Recovery Factor (CRF) used. 77 FR 

24015. We included a footnote to Table 

44 to explain that we relied on Holcim’s 

capital cost estimate for SNCR. We 

included a second footnote to that table 

to explain what CRF we used. We also 

included a footnote to Table 45 to 

explain that we relied on Holcim’s 

estimate of direct annual operating 

costs. 77 FR 24016. 

We disagree with the statement that 

EPA provided no explanation for use of 

a 20-year amortization period. As 

explained at 77 FR 24015, we relied on 

Holcim’s estimates of SNCR capital cost 

and annual costs, with the exception of 

the capital recovery factor (CRF). We 

acknowledge that we wrote to Holcim in 

2007 to recommend 15-year 

amortization, and that our decision 

since then to use 20-year amortization 

instead needs clarification. We now 

clarify that after reviewing EPA national 

guidance on CRFs in more detail since 

2007, we determined that it would be 

more appropriate to use a CRF 

consistent with 20 years for the useful 

life of the kiln and associated SNCR 

controls. As explained below, our use of 

a 20-year period was not arbitrary. 

The guidance we relied on was EPA’s 

Air Pollution Control Cost Manual 

(CCM), which says, in regard to SNCR, 

that ‘‘In general, indirect annual costs 

(fixed costs) include the capital recovery 

cost, property taxes, insurance, 

administrative charges, and overhead. 

Capital recovery cost is based on the 

anticipated equipment lifetime and the 

annual interest rate employed. An 

economic lifetime of 20 years is 

assumed for the SNCR system.’’ EPA Air 

Pollution Control Cost Manual, Sixth 

Edition, EPA/452/B–02–001, January 

2002, Section 4.2, Chapter 1, page 1–37. 

We explained in our FIP proposal that 

without commitments for an early 

shutdown, EPA cannot consider a 

shorter amortization period. 77 FR 

24014. For consistency in comparing 

control options for NOX and SO2 for all 

Montana BART sources, our FIP 

proposal uses a 20-year equipment life 

in all the BART analyses (provided that 

the equipment life of each control 

option is 20 years or more). The CRF for 

a 20-year equipment life and 7% 

discount rate (the latter being 

recommended in Office of Management 

and Budget (OMB) Circular A–4, which 

we cited at 77 FR 24016) is 0.0944. As 

shown in Table 44 at 77 FR 24016, we 

multiplied Holcim’s estimated capital 

cost of $1,312,800 by this CRF to yield 

a capital recovery cost of $123,928. 

With regard to Holcim’s comment that 

a 20-year amortization would 

misrepresent actual costs in the event 

that SCR rather than SNCR were to be 

required in the next planning period, we 

cannot anticipate every event that might 

happen in the future and we are not 

required to do so in establishing an 

amortization period. 

We disagree with the statement that 

SNCR costs at the Trident kiln should 

be similar to Holcim’s Hagerstown kiln. 

The Trident kiln is much smaller than 

the Hagerstown kiln. The Trident kiln is 

permitted at 425,000 tons per year of 

clinker production. Montana Air 

Quality Permit #0982–11, Condition 

II.B.6. The Hagerstown kiln is rated at 

630,114 tons per year of clinker 

production capacity. Prevention of 

Significant Deterioration (PSD) Permit 

Application for Approval, Holcim 

Hagerstown, October 30, 2008. Also, the 

Hagerstown kiln—a dry kiln—likely has 

different emission rates than the Trident 

kiln. Without more information, it is not 

possible to determine how much of the 

claimed $1,920,000 capital cost of the 

Hagerstown kiln SNCR system, as well 

as operating costs, would be costs that 

are permissible for inclusion in a BART 

cost estimate. For these reasons, without 

more information, the costs of the SNCR 

system at the Hagerstown kiln are not 

useful for estimating the costs at the 

Trident kiln. Therefore, we continue to 

rely on the SNCR capital cost estimate 

of $1,312,800 and operating cost 

estimate of $147,288 for Trident, already 

supplied to us by Holcim in the August 

2009 submittal. We also note that, even 

with a capital cost of $1,920,000, it 

appears SNCR would remain costeffective; Holcim has provided no 

reason why our BART selection would 

change. This comment has not resulted 

in any changes to our regulatory text for 

NOX BART. 

Comment: Holcim indicated that EPA 

underestimated the costs of installing 

indirect firing at Trident. Holcim stated 

that the company did not include 

indirect firing in its 2007 BART analysis 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57883 

15Letter from Greg Gannon to Laurel Dygowski, 

June 9, 2009. (See EPA–R08–OAR–2011–0851– 

0038). 

and did not consider indirect firing to 

be an appropriate technology to evaluate 

to achieve NOX reductions at Trident. 

Holcim stated that at EPA’s request, the 

company submitted an estimate to EPA 

of the costs of installing indirect firing 

at Trident.15 Holcim stated that in EPA’s 

own analysis, the Agency ‘‘inexplicably 

and arbitrarily’’ eliminated a significant 

portion of the costs from Holcim’s 

analysis. Nonetheless, even using EPA’s 

underestimated costs for the installation 

of indirect firing and mistaken 

assumption that indirect firing could 

reduce NOX emissions at Trident by 

15%, neither the average costeffectiveness of indirect firing nor the 

incremental cost-effectiveness of 

indirect firing warrant a determination 

that indirect firing should be selected as 

BART. 

Holcim pointed out that EPA is 

proposing to require that Holcim install 

both SNCR and indirect firing at Trident 

based on its analysis of the average costeffectiveness of installing both 

technologies together. Holcim stated 

that the overwhelming majority of NOX

emissions reductions and improvements 

in visibility would result from the 

installation of SNCR alone and that by 

ignoring the incremental costs of SNCR 

+ indirect firing, and focusing solely on 

the average cost effectiveness, Holcim 

states that EPA tries to make the costs 

of SNCR + indirect firing appear 

reasonable. Holcim stated that the 

average cost-effectiveness for the 

installation of SNCR at Trident is well 

within the range of what EPA has 

considered for BART, but that EPA 

estimated the average cost effectiveness 

of indirect firing to be $4,279/ton, 

which is far outside the range of what 

EPA has considered to be reasonable for 

BART. With such high costs for indirect 

firing, the incremental cost-effectiveness 

of SNCR + indirect firing as compared 

to SNCR alone is $8,029/ton. Holcim 

stated that EPA should consider both 

the average and incremental cost 

effectiveness of its BART analysis for 

Trident. Holcim stated that, although 

EPA clearly identified the incremental 

cost effectiveness of SNCR + indirect 

firing, EPA ‘‘inexplicably ignored this 

unreasonable figure in concluding that 

the combination of technologies 

constitutes BART for Trident’’. Holcim 

stated that the incremental cost 

effectiveness of SNCR + indirect firing 

is unreasonable given the slight to 

nonexistent improvement in visibility 

that it would achieve and that EPA 

should eliminate this combination of 

technologies as BART. 

Holcim further stated that, based on 

modeling, the installation of indirect 

firing and SNCR at Trident, even if it 

could achieve EPA’s claimed 58% 

reduction in NOX emissions, would 

result in an improvement of visibility of 

only 0.424 deciview in Gates of the 

Mountains WA and that this does not 

constitute a significant or perceptible 

improvement in visibility. Holcim 

stated that EPA’s conclusion is even 

more unjustifiable considering the 

actual percentage reduction that Trident 

could be expected to achieve with the 

installation of SNCR of approximately 

35% on an annual average basis. 

Finally, Holcim stated that the 

average cost effectiveness estimates for 

indirect firing alone ($4,279/ton) and for 

SNCR + indirect firing ($1,528/ton) are 

well above what EPA used as a costeffectiveness threshold for NOX in the 

Cross-State Air Pollution Rule (CSAPR), 

which EPA promulgated last year to 

address health-based standards. Holcim 

stated that the company does not 

understand why EPA believes it 

appropriate to use a higher cost 

threshold for an aesthetic standard than 

it has for a health-based standard. 

Response: We agree with aspects of 

this comment, but disagree with others. 

We agree that an incremental cost 

effectiveness of $8,029/ton, for LNB/ 

indirect firing + SNCR, versus SNCR 

alone makes LNB/indirect firing + SNCR 

unreasonable for BART at the Trident 

kiln. 

As explained in a previous response 

above, we have removed switching to 

indirect firing and a LNB from 

consideration as an option for further 

reducing NOX emissions and are 

treating any NOX emission reduction 

that may have been achieved from 

installation of a new burner as part of 

the emissions baseline. We have 

recalculated the proposed BART limit 

for NOX to reflect a 50% reduction in 

NOX emissions from that baseline by 

addition of SNCR alone, rather than the 

58% reduction we previously used, 

which reflected a switch to indirect 

firing and a LNB plus SNCR. The 

recalculated NOX BART limit is 6.5 lb/ 

ton clinker. 

We disagree, however, with the 

statement that EPA analyzed for indirect 

firing as a separate control option. We 

did not. Throughout our proposal, we 

refer to the control option as LNB and 

are now clarifying that this option was 

intended to include switching to 

indirect firing and a LNB. We explained 

at 77 FR 24015 that the capital cost 

estimate of $4,385,307 for LNB includes 

the cost of converting from a direct to 

an indirect firing system to 

accommodate LNB, including 

installation of a baghouse, additional 

explosion prevention, pulverized coal 

storage, and dosing equipment. We cited 

Holcim’s additional response of August 

2009 as the source of this information. 

We disagree with the statement that 

SNCR could be expected to achieve only 

a 35% reduction in NOX emissions. See 

our response to Holcim’s comment 

above. 

We also disagree with the statement 

that any controls required by our action 

must demonstrate a perceptible 

visibility improvement. In a situation 

where the installation of BART may not 

result in a perceptible improvement in 

visibility, the visibility benefit may still 

be significant. The July 6, 2005 BART 

Guidelines state: 

even though the visibility improvement 

from an individual source may not be 

perceptible, it should still be considered in 

setting BART because the contribution to 

haze may be significant relative to other 

source contributions in the Class I area. Thus, 

we disagree that the degree of improvement 

should be contingent upon perceptibility. 

Failing to consider less-than-perceptible 

contributions to visibility impairment would 

ignore the CAA’s intent to have BART 

requirements apply to sources that contribute 

to, as well as cause, such impairment. 

70 FR 39129. Visibility impacts below 

the thresholds of perceptibility cannot 

be ignored because regional haze is 

produced by a multitude of sources and 

activities which are located across a 

broad geographic area. 

With regard to Holcim’s comment 

comparing the cost-effectiveness of 

controls required under the CSAPR, 

with cost-effectiveness of controls 

required under the Regional Haze Rule 

and the BART Guidelines, we reject the 

comparison. The two rules address 

different requirements of the CAA. 

Comment: Holcim agreed with EPA’s 

proposal that no additional controls 

constitute BART for SO2 at Trident but 

objected to the imposition of a 30-day 

SO2 limit. In Holcim’s view, imposing a 

30-day limit is neither reasonable nor 

necessary. Holcim’s Trident plant relies 

on inherent scrubbing to achieve its 

extremely low SO2 emissions. EPA’s 

modeling confirms that SO2 emissions 

from Trident have effectively zero 

visibility impact. Trident could more 

than double its current SO2 emissions 

and still not have any reliably 

predictable impact on visibility (less 

than 0.1 deciview). Even if all SO2

emissions from Trident were 

eliminated, visibility would improve in 

Gates of the Mountains WA by less than 

0.05 deciview; less than one-twentieth 

of a perceptible change in visibility. See 


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16Memo from Jim Staudt, Andover Technology 

Partners, to Doug Grano, July 10, 2012. 

77 FR at 24021. Id. at 24021, Table 63. 

Holcim stated that the kiln could not 

increase its emissions sufficiently to 

affect visibility without exceeding its 

currently enforceable limit. 

Consequently, Holcim stated that there 

simply is no need to impose short term 

SO2 limits to protect visibility. 

Second, Holcim stated that because 

Trident relies on inherent scrubbing to 

control SO2, the plant has no real 

control over the short-term emissions 

variability that results from the natural 

variability in limestone from its quarry. 

The emissions variability would never 

rise to a level that could affect visibility, 

but it could cause Trident to exceed the 

proposed 30-day limit. Thus, the only 

effect of the 30-day limit would be to 

impose unnecessary regulatory burdens 

on the plant and expose it to potential 

penalties for short-term emissions 

variability, over which Holcim has no 

control and which would not impact 

visibility. 

Holcim also commented that EPA is 

proposing to impose an SO2 limit that 

is not based on the installation of 

retrofit control technology or a process 

change and that offers no improvement 

in visibility. Holcim stated that because 

the proposed limit is based on current 

emissions and will not improve 

visibility, it cannot be considered 

BART; the CAA and EPA’s own BART 

Guidelines require that, in determining 

BART, the Administrator consider the 

degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

Holcim requested that EPA eliminate its 

proposed 30-day SO2 limit as it does not 

represent BART and would impose 

unnecessary regulatory burdens and 

new compliance risks while serving no 

visibility purpose. 

Response: We disagree. The July 6, 

2005 BART Guidelines state that 

‘‘* * * you must establish an 

enforceable emission limit for each 

subject emission unit at the source and 

for each pollutant subject to review that 

is emitted from the source.’’ 70 FR 

39172. Our FIP proposal states that 

‘‘States, or EPA if implementing a FIP, 

must address all visibility-impairing 

pollutants emitted by a source in the 

BART determination process. The most 

significant visibility impairing 

pollutants are SO2, NOX and PM.’’ 77 FR 

23993. Similarly, the BART Guidelines 

identify SO2, NOX and PM as visibilityimpairing pollutants. 70 FR 39160. 

Since these pollutants are subject to 

review, emission limits must be 

established. This comment has not 

resulted in any changes to our proposal. 

We note that Holcim has not provided 

any specific data to demonstrate that 

they may exceed the emission limit 

established for SO2. 

Comment: Holcim disagreed with 

EPA’s proposal to impose an emission 

limit for PM at Trident of 0.77 lb/ton 

clinker. Holcim stated that the proposed 

limit, which is based on Trident’s 

current emissions, is unjustified because 

it would result in no visibility impact 

and that as the company had already 

explained, the selected BART must 

consider the degree of improvement in 

visibility. Holcim stated that adding a 

duplicative applicable requirement to 

Trident’s Title V permit would serve no 

purpose other than to ‘‘create the 

potential for multiple penalties if the 

requirement were violated.’’ 

Response: See the previous response. 

F. Comments on CFAC 

Comments: CFAC requested that EPA 

conduct a BART analysis for their 

facility now, rather than in the future, 

so that CFAC has more information for 

planning a restart. The NPS commented 

similarly. CFAC also commented that 

not knowing what the BART controls 

may or may not be for their facility 

makes it difficult to know whether those 

controls could be installed within the 

five-year timeframe. Another 

commenter stated that we must either 

set BART limits for CFAC in the FIP, or 

we must require plant shutdown as part 

of the FIP. 

Response: We disagree that it is 

necessary to conduct the BART analysis 

at this time. The information necessary 

to complete such a BART analysis is not 

available until CFAC’s future 

operational plans are known. The 

requirements for CFAC at 40 CFR 

52.1396(n) are sufficient at this time. 

With regard to CFAC’s comment that 

not knowing what the BART controls 

may or may not be for their facility 

makes it difficult to know whether those 

controls could be installed within the 

five-year timeframe, the BART 

Guidelines state that we must require 

compliance with emission limits no 

later than five years following the final 

FIP. 70 FR 39172. CFAC can provide the 

necessary information to EPA to 

conduct a BART analysis at any time. 

G. Comments on Colstrip Units 1 and 2 

Comment: A commenter stated that 

PPL’s modeling files related to the June 

2008 Addendum to PPL Montana’s 

Colstrip BART Report should be placed 

in the docket. 

Response: We requested the modeling 

files from PPL and PPL responded that 

they could not locate those files. We 

based our decisions on the more recent 

modeling described at 77 FR 24002. 

Comment: Commenters stated that 

they object to our proposed BART 

determinations for NOX and SO2

because it would impose emission 

limits based on SNCR and an additional 

scrubber vessel, respectively. 

Commenters stated that EPA’s proposed 

BART analysis for Colstrip Units 1 and 

2 is inconsistent with our statutory 

obligations and our own Guidelines. 

Commenters suggested that our BART 

determinations contain significant 

errors. Commenters stated that we did 

not properly or correctly consider the 

costs of the proposed controls, the 

incremental cost-effectiveness of the 

controls, and the lack of any reasonably 

expected visibility improvements 

resulting from the proposed controls. 

Instead of the BART proposed by EPA, 

commenters supported the installation 

of SOFA for NOX control with an 

emission limit of 0.20 lb/MMbtu, and 

lime injection for SO2 control with an 

emission limit of 0.20 lb/MMBtu (both 

as a 30-day rolling average). 

Response: In proposing our BART 

determinations, we met the statutory 

requirements under section 169A of the 

CAA and also followed the BART 

Guidelines. Based on our consideration 

of the five statutory BART factors, we 

continue to find that BART for NOX is 

SOFA+SNCR with an emission limit of 

0.15 lb/MMBtu (30-day rolling average). 

Similarly, based on our consideration of 

the five statutory BART factors, we 

continue to find that BART for SO2 is 

lime injection and an additional 

scrubber vessel with an emission limit 

of 0.08 lb/MMBtu (30-day rolling 

average). Each specific issue raised by 

the commenters is addressed in a 

separate response to comments. 

Comment: Several commenters 

asserted that EPA’s costs for SNCR on 

Colstrip Units 1 and 2 were inaccurate 

and that SNCR is not cost effective. 

Commenters asserted that this was due 

to a number of errors, including use of 

an incorrect baseline, overstating the 

emission benefits that can be achieved 

with SNCR, and using improper cost 

estimation techniques. The commenters 

submitted their own cost estimates 

challenging those reported by EPA. 

Response: EPA estimated a cost 

effectiveness for SNCR+SOFA of about 

$1,550/ton. This estimate has been 

confirmed after the proposal through 

information supplied by SNCR 

vendors.16 For this control combination, 

Nalco Mobotec Inc. (Mobotec) estimated 

a cost effectiveness of roughly $1,395/ 

ton, while Fuel Tech Inc. (Fuel Tech) 

estimated a cost effectiveness of $1,642/ 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57885 

17 Id. 

18Letter from Dale T Pfaff, Fuel Tech, Inc. to 

Gordon Criswell, PPL Montana, May 29, 2012. 

19Letter from Gary Tonnemacher, Mobotec, to 

Gordon Criswell, PPL Montana, May 25, 2012. 

20Fuel Tech, May 29, 2012. 

21Mobotec, May 25, 2012. 

22BART Determination Support Document for 

Transalta Centralia Generation LLC Power Plant, 

Centralia, Washington, Prepared by Washington 

State Department of Ecology, Revised November 

2011, p. 14; Region 10 clarified the typographical 

error in their Federal Register notice via email from 

Steve Body to Aaron Worstell dated July 26, 2012. 

ton. The average vendor cost 

effectiveness of $1,518/ton is slightly 

lower than what was previously 

estimated by EPA. Likewise, EPA 

estimated a cost effectiveness for SNCR 

(after SOFA) of about $3,300/ton. For 

SNCR (after SOFA) Nalco Mobotec 

estimated a cost effectiveness of roughly 

$2,800/ton, while Fuel Tech estimated a 

cost effectiveness of $3,500/ton.17 The 

average vendor cost effectiveness of 

$3,150/ton is slightly lower than what 

was previously estimated by EPA. 

Further, the cost effectiveness of 

SNCR is of course highly dependent on 

the emission benefits that the control 

technology can achieve. The 

discrepancy between our cost 

effectiveness and that supplied by the 

commenters is largely driven by this 

factor. We address this issue, as well as 

other issues raised by commenters in 

regard to our SNCR cost estimates for 

Colstrip Units 1 and 2, separately below. 

Comment: Two commenters claimed 

that EPA used an incorrect baseline of 

2008–2010 for Colstrip pollutant 

emissions in our BART analyses. One 

commenter stated that the BART 

Guidelines require a baseline for BART 

analyses of 2000–2004, while another 

stated it requires a baseline of 2001– 

2003. Both of these baseline periods 

were prior to the installation of 

additional combustion controls at 

Colstrip Units 1 and 2. In addition, one 

commenter claimed that the 2008–2010 

baseline emissions are not 

representative as they reflect a period of 

economic downturn. 

Response: We disagree with these 

comments. The BART Guidelines 

require you to choose a representative 

baseline period, but do not specify that 

this period must be 2000–2004 or 2001– 

2003: 

The baseline emissions rate should 

represent a realistic depiction of anticipated 

annual emissions for the source. In general, 

for the existing sources subject to BART, you 

will estimate the anticipated annual 

emissions based upon actual emissions from 

a baseline period. 

70 FR 39167. 

As we discussed in our proposed rule, 

in 2007 PPL installed additional 

combustion controls on Colstrip Units 1 

and 2 in order to meet new Acid Rain 

Program emission limits. As these 

controls were not installed to meet 

BART requirements, we find that it is 

appropriate to reflect them in the 

baseline emissions. 

Furthermore, annual heat input data 

contained in the CAMD emissions 

system shows the baseline period of 

2008–2010 is representative of the 

operation of the Colstrip Unit 1 and 2. 

For example, the 2000–2010 annual heat 

input for Colstrip Unit 1 ranged from a 

low of 24,003,758 MMBtu/yr in 2006 to 

a high of 30,770,151 MMBtu/yr in 2004. 

The 2008–2010 annual average heat 

input used by EPA in our BART 

analysis of 26,578,089 MMBtu/yr falls 

about in the middle of this range. 

Therefore, the baseline period chosen by 

EPA is a realistic depiction of the heat 

input (and thereby annual emissions) of 

the Colstrip Units 1 and 2. 

Finally, the 2000–2004 annual 

average heat input (the period that one 

commenter asserted we should have 

used), was 26,966,516 MMBtu/yr, and 

only slightly higher than the heat input 

used by EPA of 26,578,089 MMBtu/yr. 

Therefore, even if we had used the 

2000–2004 heat input, it would not have 

affected the BART analysis in a 

meaningful way. 

Comment: Commenters asserted that 

EPA overstated the emissions benefit of 

SNCR and that it cannot achieve the 

level of control claimed. The 

commenters stated that SNCR cannot 

achieve a 25% emission reduction. They 

also stated that SNCR (in combination 

with combustion controls) cannot 

achieve an emission limit of 0.15 lb/ 

MMBtu on a 30-day rolling average. 

PPL based their assertions on analyses 

which they obtained from SNCR 

vendors, Nalco Mobotec, Inc. and Fuel 

Tech Inc. They stated that these 

analyses show that the lowest feasible 

emissions limit for these units on a 30- 

day rolling average would be in the 

range of 0.17 to 0.18 lbs/MMBtu. PPL 

estimates that only a 10% reduction in 

NOX emissions could be achieved since 

ammonia slip must be limited to 0.5 

ppm. 

NPS questioned whether SNCR can 

achieve 0.15 lb/MMBtu on a 30-day 

rolling average due to the sensitivity of 

SNCR to boiler operation, size, and 

configuration. NPS did not provide any 

data or information to support their 

concerns other than to state that a query 

of the CAMD emissions system revealed 

only two EGUs that are consistently 

meeting 0.15 lb/MMBtu on monthly 

basis. 

Response: We disagree that we have 

overstated the emissions benefit of 

SNCR. Neither the vendor analyses nor 

the SNCR performance data contained 

in the CAMD emissions system support 

a conclusion that we overstated the 

emission benefits of SNR. 

The vendor analyses provided by PPL 

confirm the assumptions made by EPA 

regarding the emissions benefits that 

can be achieved with SNCR. Both 

vendors indicate that a control 

efficiency of 25%, as assumed by EPA, 

can be achieved. For example, Fuel 

Tech indicates that a ‘‘10 ppm ammonia 

slip would result in ∼25% NOX

reduction.’’ 18 Similarly, Mobotec 

indicates that ‘‘[a]t 7 ppm of ammonia 

slip, NOX emissions could be reduced 

up to 25%, provided there would be no 

impact on the performance of the air 

preheater, or other plant systems.’’ 19

We realize that the control efficiency of 

SNCR is highly dependent on the level 

of ammonia slip. However, we find no 

reason that an ammonia slip level of 5 

to 10 ppm is unacceptable for the 

Colstrip Unit 1 and 2. These levels of 

ammonia slip are typical for SNCR. In 

fact, Fuel Tech stated that ‘‘[i]n the coalfired Utility market segment, the SNCR 

systems have been historically designed 

for a minimum of 5 ppm ammonia slip 

with some lower sulfur applications 

with NH3 slip levels of 10 ppm.’’ 20 (We 

address the potential impacts from 

ammonia slip in a separate response to 

comments). 

Further, we note that the control 

efficiencies provided by the vendors are 

for operation at full load, and that 

higher control efficiencies can be 

achieved at lower loads. For instance, 

Mobotec relates that ‘‘[h]igher NOX

reductions can be achieved at mid to 

low load heat inputs, possibly up to 

40%.’’ 21 Given that the Colstrip Unit 1 

and 2 frequently operate at below full 

load, it is likely that on an annual basis 

SNCR can achieve better than the 25% 

emission reduction assumed by EPA. 

PPL has erred in stating that the 

control efficiency of SNCR is no more 

than 10% since ammonia slip levels 

must be limited to 0.5 ppm. The 

commenter bases this claim on what 

they believe to be a precedent set in the 

Centralia Power Plant BART 

determination. However, the Centralia 

BART determination prepared by 

Washington stated that, ‘‘TransAlta’s 

cost analysis uses a urea-based SNCR 

system providing a nominal 25% 

reduction in NOX levels with a 5 ppm 

ammonia slip.’’ 22 And as established by 

the vendor analyses discussed above, 

much higher emission reductions than 

10% can be achieved with SNCR at 

ammonia slip levels of 5 to 10 ppm. 


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23Fuel Tech, May 29, 2012. 

24BART Determination Support Document for 

Transalta Centralia Generation LLC Power Plant, 

Centralia, Washington, Washington State 

Department of Ecology, revised November 2011, 

p. 13. 

Similarly, the performance data 

contained in CAMD emissions system 

only serves to reinforce the assumptions 

made by EPA regarding the emission 

benefits of SNCR. Based on our review 

of the CAMD emissions data, there are 

many EGUs equipped with SNCR (with 

combustion controls) that are achieving 

an emission rate of 0.15 lb/MMBtu or 

lower on a monthly basis. One unit in 

particular, Boswell Unit 4, is very 

comparable to the Colstrip Unit 1 and 2. 

Boswell Unit 4, like the Colstrip Unit 1 

and 2, burns sub-bituminous coal and is 

tangentially fired. In addition, Boswell 

Unit 4 had a baseline annual emission 

rate (with LNB and CCOFA, but prior to 

the installation of SNCR and SOFA) 

similar to the Colstrip Unit 1 and 2 of 

approximately 0.35 lb/MMBtu. Since 

the installation of full combustion 

controls and SNCR, the Boswell Unit 

has achieved a monthly emission rate of 

below 0.15 lb/MMBtu. For example, 

between April 2011 and April 2012, the 

most recent full year of emissions data 

available in the CAMD emissions 

system, the monthly emission rates for 

Boswell Unit 4 were between 0.11 and 

0.14 lb/MMbtu. This is a strong 

indicator of the performance rates that 

can be expected for Colstrip Units 1 and 

2. 

We acknowledge that a range of 

performance rates are currently being 

achieved with SNCR, and are in some 

cases not as low as at Boswell Unit 4. 

However, without a showing that there 

are circumstances unique to the Colstrip 

Unit 1 and 2 that would prevent SNCR 

from achieving the same reductions as 

at Boswell Unit 4, we find no reason 

that an emission limit higher than 0.15 

lb/MMBtu on a 30-day rolling average is 

warranted. This is consistent with the 

BART Guidelines: 

Without a showing of differences between 

the source and other sources that have 

achieved more stringent emissions limits, 

you should conclude that the level being 

achieved by those other sources is 

representative of the achievable level for the 

source being analyzed. 

70 FR 39166. 

Finally, due to the smaller size of 

Colstrip Unit 1 and 2 (333 MW each), 

we expect that SNCR would be more 

effective than at Boswell Unit 4 (525 

MW). This is because the effectiveness 

of SNCR on large boilers is somewhat 

reduced as the relatively larger crosssection of the boiler makes distribution 

of the reagent difficult. 

For the reasons stated here, we find 

no basis in claims that we overestimated 

the emission benefits for SNCR. 

Comment: Commenters stated that 

EPA did not properly consider the 

incremental cost-effectiveness of SNCR 

at Colstrip Units 1 and 2. Commenters 

stated that EPA improperly assessed the 

costs of SNCR when combined with 

SOFA, and not as an individual 

technology. Commenters stated that the 

incremental cost of adding SNCR to 

SOFA outweighs the benefits. One 

commenter cited portions of the BART 

Guidelines that address consideration of 

incremental costs between competing 

technologies. 

Response: We disagree with these 

comments. We addressed why these 

control technologies were analyzed 

together in our proposed rule: 

The post-combustion control technologies, 

SNCR and SCR, have been evaluated in 

combination with combustion controls. That 

is, the inlet concentration to the postcombustion controls is assumed to be 0.20 lb/ 

MMBtu. This allows the equipment and 

operating and maintenance costs of the postcombustion controls to be minimized based 

on the lower inlet NOX concentration. 

77 FR 22043. 

If we had not combined the control 

technologies, then the cost effectiveness 

would have been more favorable to 

SNCR. This is because the inlet to the 

SNCR would reflect the current annual 

baseline emissions (e.g., 0.308 lb/ 

MMbtu for Colstrip Unit 1, 2008–2010), 

as opposed to the anticipated postcombustion (i.e., with SOFA) rate of 

0.20 lb/MMBtu assumed by EPA. This 

would lead to larger emission 

reductions being achieved by SNCR, 

and thereby, more favorable cost 

effectiveness. 

Regardless, EPA did disclose the costs 

of SNCR alone (after SOFA) in our 

proposed rule. Consider for example our 

BART analysis for Colstrip Unit 1. See 

77 FR 24025–24027 and spreadsheet 

entitled ‘‘EPA SNCR Cost Colstrip Unit 

1 Final’’ located in the docket. The total 

annual cost of SNCR given in our 

proposed rule was $2,188,569, while the 

emission reductions were 664 tpy. This 

results in a cost effectiveness of $3,291/ 

ton, essentially the incremental cost 

effectiveness between SNCR+SOFA and 

SOFA as given in Table 77 of the 

proposed rule. EPA selected SNCR as 

BART in consideration of these costs, all 

of which were presented to the public 

in our proposed rule. 

Comment: Various commenters stated 

that EPA disregarded, or did not 

properly account for, issues associated 

with ammonia slip from SNCR systems. 

The commenters expressed concerns 

about both potential operational and 

environmental impacts. In regard to 

potential operational impacts, 

commenters expressed concerns about 

fouling of the air preheater. In regard to 

potential environmental impacts, 

commenters expressed concerns related 

to a visible wet plume, greenhouse 

gases, and toxic emissions. 

Response: We disagree with these 

comments. In our proposed rule, we 

explicitly considered issues associated 

with ammonia slip from SNCR systems. 

For example: 

As Colstrip Unit 1 burns sub-bituminous 

PRB coal having a low sulfur content of 0.91 

lb/MMBtu (equating to a SO2 rate of 1.8 lb/ 

MMBtu), [citation omitted] it was not 

necessary to make allowances in the cost 

calculations to account for equipment 

modifications or additional maintenance 

associated with fouling due to the formation 

of ammonium bisulfate. These are only 

concerns when the SO2 rate is above 3 lb/ 

MMBtu.[citation omitted] Moreover, 

ammonium bisulfate formation can be 

minimized by preventing excessive NH3 slip. 

Optimization of the SNCR system can 

commonly limit NH3 slip to levels less than 

the 5 parts per million (ppm) upstream of the 

pre-air heater. 

77 FR 24025. 

This observation has been verified by 

the vendor analyses submitted by PPL. 

For example, Fuel Tech stated that 

‘‘[s]ince the Colstrip 1&2 coal has low 

sulfur, there is less concern of 

ammonium bisulfate formation and its 

associated air preheater pluggage 

issues.’’ 23

We also find that concerns about the 

potential for adverse environmental 

impacts, such as a visible wet plume, 

toxic ammonia emissions, or greenhouse 

gas emissions, are unfounded or 

exaggerated. As previously discussed, 

optimization of the SNCR system would 

limit ammonia slip to acceptable levels 

(i.e., 5–10 ppm). Moreover, as noted in 

the BART determination for the 

Transalta Centralia Power Plant in 

Washington, ammonia in the gas stream 

is further removed when a wet scrubber 

is present.24 Since the Colstrip Units 1 

and 2 utilize wet scrubbers, no 

additional plume visibility or other 

local impacts would be anticipated. 

While we did not quantify increases 

in greenhouse gases associated with 

SNCR in our proposed rule, we did 

quantify the additional amount of coal 

that is needed to account for the loss in 

thermal efficiency and found it to be 

insignificant. For example: 

SNCR reduces the thermal efficiency of a 

boiler as the reduction reaction uses thermal 

energy from the boiler.[citation omitted] 

Therefore, additional coal must be burned to 

make up for the decreases in power 

generation. Using CCM calculations we 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57887 

25Memo from Jim Staudt, Andover Technology 

Partners, to Doug Grano, July 13, 2012, p. 9. 

26September 23, 2011 PPL submittal titled ‘‘NOX

Control Update to PPL Montana’s Colstrip 

Generating Station BART Report.’’ 

determined the additional coal needed for 

Unit 1 equates to 77,600 MMBtu/yr. 

77 FR 24026. 

We note that 77,600 MMBtu/yr is only 

0.3% of the 2008–2010 annual average 

heat input for Colstrip Unit 1. The 

increase in CO2 emissions would be 

proportional (that is, 0.3%). The 

formation of other greenhouse gases, 

such as nitrous oxide, would be highly 

dependent upon the reagent used, the 

amount of reagent injected and the 

injection temperature. Regardless, we 

note that the potential for CO2 increases 

also exists for SCR, the technology 

favored by some commenters. This is 

due to the energy penalty associated 

with the large pressure drop across the 

SCR reactor. Therefore, consideration of 

greenhouse gases would not have 

necessarily favored SNCR over SCR. 

Comment: MDEQ stated that EPA 

failed to provide analysis or 

consideration of the impact SNCR 

installation may have on mercury 

controls at Colstrip 1 & 2. MDEQ stated 

that this failure ignores factor 3 of the 

five-factor analysis, ‘‘Any existing 

pollution control technology in use at 

the source.’’ MDEQ contended that the 

application of SNCR will require these 

units to displace the sorbent injection 

systems which limit mercury emissions, 

and that this displacement will 

compromise the Montana Mercury Rule. 

Response: We disagree with this 

comment. SNCR should have no impact 

on mercury capture in the scrubber or 

with mercury capture from sorbent 

injection and will neither improve nor 

harm any efforts at Colstrip Units 1 and 

2 to comply with Montana’s Mercury 

Rule. There is no reason why Colstrip 

Units 1 and 2 cannot utilize both SNCR 

and sorbent injection (if sorbent 

injection is what PPL chooses to use at 

Colstrip 1 and 2). Injection points for 

SNCR and for sorbent injection are at 

different locations—the furnace for 

SNCR and the downstream ductwork for 

sorbent injection. A review of EPA’s 

National Electric Energy Data System 

(NEEDS) reveals that are currently 17 

utility boilers equipped with both SNCR 

and activated carbon injection 

systems.25 The list of facilities includes 

units ranging from 65 MW to 405 MW 

and burning both bituminous and 

subbituminous coals. Therefore, there is 

no basis for the assertion that these two 

pollution control systems cannot be 

used together on the same facility. 

Comment: MDEQ stated that EPA 

lacks consideration of Montana’s 

existing SIP requirements. For instance, 

sources required to add controls would 

have to provide ‘‘de minimis’’ 

notifications under ARM 17.8.745, or 

potentially a resource-intensive 

demonstration that the additional 

control would not contribute to a 

violation of an air quality standard. 

Additionally, MDEQ stated that some of 

the proposed controls might require 

either a minor source permit or a major 

modification under the NSR program. 

MDEQ expressed particular concern 

over EPA’s lack of analysis of PPL’s 

estimated increase in ammonia slip.26

MDEQ suggested that increases in 

ammonia slip could lead to increases in 

PM2.5 emissions at Colstrip 1 & 2, 

potentially requiring the unit(s) to 

submit a ‘‘politically controversial, 

legally complex, and technically 

challenging’’ NSR major modification 

permit. MDEQ also stated that an NSR 

major modification would significantly 

alter the time and cost required to 

implement the proposed BART. 

Response: We disagree with these 

comments. MDEQ has not provided any 

data or information to substantiate that 

our BART determinations would 

interfere with existing SIP requirements, 

including those for permitting. They 

have only speculated that these might 

be concerns. In addition, these concerns 

would not negate our obligation to 

prescribe BART controls. We have 

addressed concerns related to ammonia 

slip in a separate response to comments. 

Comment: Commenters stated that 

EPA asserted, with no analysis, that the 

energy needs associated with 

installation SNCR or SCR on the 

Colstrip Unit 1 and 2 are minimal and 

neither the additional energy 

requirements nor the nonair quality 

environmental impacts associated with 

disposal of the ash waste or 

transportation of the chemical reagents 

or catalysts warranted eliminating either 

SCR or SNCR. 

Response: We disagree with this 

comment. We provided analysis of the 

energy impacts associated with SNCR 

and SCR in our proposed rule. For 

example, for the application of SNCR to 

Colstrip Unit 1 we ‘‘determined the 

additional coal needed for Unit 1 

equates to 77,600 MMBtu/yr.’’ 77 FR 

24026. Similarly, we determined that 

SCR requires ‘‘additional electric power 

to meet fan requirements equivalent to 

approximately 0.3% of the plant’s 

electric output.’’ [citation omitted] 77 

FR 24026. We also provided analysis of 

the non- air-quality impacts associated 

with SNCR and SCR in our proposed 

rule. See for example 77 FR 24026. We 

did not find it necessary to quantify 

these impacts as they are negligible. 

Also, the nonair quality impacts would 

be no different than those at numerous 

other boilers where SNCR or SCR have 

been successfully applied. Regardless, 

the commenters did not present any 

data or information that establishes that 

the energy or nonair quality impacts of 

SNCR or SCR would make these control 

options unacceptable. 

Comment: NPS stated that allowing 

five years from promulgation of the rule 

to install SNCR on Colstrip Units 1 and 

2 is excessive since it can be installed 

in less than one year. 

Response: We agree that SNCR in 

some cases can be installed in less than 

one year. However, the BART 

Guidelines require compliance with the 

BART emission limit as expeditiously as 

possible but in no event later than five 

years after promulgation of the FIP. 40 

CFR 51.308(e)(1)(iv). Our FIP is 

consistent with that requirement. 

Comment: The NPS agreed with EPA 

that an annual emission rate of 0.05 lb/ 

MMBtu is achievable with SCR. 

Response: Comment noted. 

Comment: EarthJustice stated that 

EPA incorrectly rejected SCR as BART 

for NOX pollutant control for Colstrip 

Units 1 and 2. They asserted that EPA’s 

analysis was biased against the selection 

of SCR as BART. They also asserted that 

we manipulated data, made 

assumptions, and performed 

calculations where the results are 

specified but the calculation itself is 

absent from the public record. 

Response: We disagree with these 

comments. Our selection of 

SNCR+SOFA, and not SCR+SOFA, as 

BART was based on our objective 

consideration of the five statutory 

factors. Moreover, all of our analyses 

and assumptions were supported by the 

docket which was available for public 

review. 

Comment: EarthJustice stated EPA 

underestimated the NOX reductions that 

can be achieved with SCR technology. 

They stated that major SCR catalyst 

vendors routinely guarantee at least 

90% removal efficiency for SCR 

systems. 

Response: We disagree. EarthJustice 

has incorrectly assumed that a 90% 

control efficiency can be achieved in all 

applications regardless of the input NOX

emission rate or other parameters. The 

baseline annual emission rate for 

Colstrip BART units is around 0.31 lb/ 

MMBtu (annually). After the installation 

of SOFA, the emission rate is expected 

to be 0.20 lb/MMBtu (annually). 

Therefore, a 90% control efficiency for 

SCR would correspond to a controlled 

emission rate of 0.02 lb/MMBtu 


tkelley on DSK3SPTVN1PROD with RULES3
57888 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

27CCM, Section 4, Chapter 2, p. 2–41. 

28 IPM, Chapter 5, Appendix 5–2A, p. 2. 

29Office of Management and Budget, Circular A– 

4, Regulatory Analysis, http://www.whitehouse.gov/ 

omb/circulars_a004_a-4/. 30CCM, Section 4, Chapter 2, p. 2–48. 

(annually). We find that this is an 

unrealistic expectation of the level of 

control that can be achieved with SCR. 

Comment: EarthJustice stated that 

EPA incorrectly used the Integrated 

Planning Model (IPM) for the direct 

capital costs of SCR for Colstrip Units 1 

and 2 and that we failed to explain why 

we did so. They stated that the BART 

Guidelines require that the CCM be used 

for BART cost analyses, except for the 

site-specific cost of the equipment itself 

which will vary depending on sitespecific conditions. EarthJustice also 

stated that our use of IPM led to the 

double counting of installation costs. 

Response: We disagree with these 

comments. We explained our rationale 

for using IPM for direct costs for SCR in 

the proposed rule: 

We relied on a number of resources to 

assess the cost of compliance for the control 

technologies under consideration. In 

accordance with the BART Guidelines (70 FR 

39166 (July 6, 2005)), and in order to 

maintain and improve consistency, in all 

cases we sought to align our cost 

methodologies with the EPA’s Control Cost 

Manual (CCM).[citation omitted] However, to 

ensure that our methods also reflect the most 

recent cost levels seen in the marketplace, we 

also relied on control costs developed for the 

Integrated Planning Model (IPM) version 

4.10.[citation omitted] These IPM control 

costs are based on databases of actual control 

project costs and account for project specifics 

such as coal type, boiler type, and reduction 

efficiency. The IPM control costs reflect the 

recent increase in costs in the five years 

proceeding 2009 that is largely attributed to 

international competition. Finally, our costs 

were also informed by cost analyses 

submitted by the sources, including in some 

cases vendor data. 

77 FR 24024. 

As noted in the proposed rule, our use 

of IPM was intended to ensure that the 

direct capital costs reflect the most 

recent cost levels seen in the 

marketplace. Therefore, we disagree that 

this led to an overestimation of the costs 

of SCR. Also as noted in the proposal, 

while we did use IPM for direct capital 

costs, the remainder of our analysis for 

SCR conformed to the CCM. 

EarthJustice is mistaken in asserting 

that our use of IPM led to the double 

counting of installation costs. 

EarthJustice is also mistaken in asserting 

that ‘‘in the Cost Control Manual, those 

installation costs [direct installation 

costs] are included as indirect capital 

costs.’’ Direct installation costs are 

treated in the same way whether using 

the CCM or IPM. That is, both provide 

direct capital costs that are inclusive of 

the direct installation costs. For 

example, the CCM states: 

Direct capital costs (DCC) include 

purchased equipment costs (PEC) such as 

SCR system equipment, instrumentation, 

sales tax and freight. This includes costs 

associated with field measurements, 

numerical modeling and system design. It 

also includes direct installation costs such as 

auxiliary equipment (e.g., ductwork, fans, 

compressor), foundations and supports, 

handling and erection, electrical, piping, 

insulation, painting, and asbestos removal.27

(emphasis added) 

Similarly, the IPM documentation 

states the bare module costs include 

equipment, installation, buildings, 

foundations, electrical, and the retrofit 

factor.28 Since we used the bare module 

capital costs to replace the direct capital 

costs in the CCM calculations, we did 

not double count direct installation 

costs. For example, for Colstrip Unit 1 

we used the bare module capital cost of 

$55,578,137 (2010 dollars) as input for 

the direct capital cost. 

Comment: EarthJustice stated that 

EPA overestimated capital costs of SCR 

on Colstrip Units 1 and 2 by using an 

inflated capital recovery factor (CRF) 

that is not based on accurate, available, 

site-specific information and by 

underestimating the lifetime of SCR. 

EarthJustice asserted that EPA should 

have used a CRF based on a 5% interest 

rate and an equipment life of 30 years 

Response: We disagree that the CRF 

used by EPA led to an overestimation of 

capital costs for SCR. In our cost 

analysis for Colstrip Units 1 and 2, we 

used an interest (discount) rate of 7% 

for all control options. This is consistent 

with guidance contained in the Office of 

Management and Budget, Circular A–4, 

for regulatory analysis.29 In regard to the 

equipment life assumed by EPA for 

SCR, the BART Guidelines state: 

For example, the methods for calculating 

annualized costs in EPA’s OAQPS Control 

Cost Manual require the use of a specified 

time period for amortization that varies based 

upon the type of control. If the remaining 

useful life will clearly exceed this time 

period, the remaining useful life has 

essentially no effect on control costs and on 

the BART determination process. Where the 

remaining useful life is less than the time 

period for amortizing costs, you should use 

this shorter time period in your cost 

calculations. 

70 FR 39169 (emphasis added). 

And in regard to SCR, the CCM states: 

Capital recovery cost is based on the 

anticipated equipment lifetime and the 

annual interest rate employed. An economic 

lifetime of 20 years is assumed for the SCR 

system. The remaining life of the boiler may 

also be a determining factor for the system 

lifetime.30 (emphasis added) 

The equipment life assumed by EPA 

is consistent with that specified by the 

CCM for SCR (that is, 20 years). In 

addition, the consistent use of a 7% 

interest rate and 20 year equipment life 

ensures that the costs are comparable 

between all of the control options 

considered (provided that each option 

has an equipment life of at least 20 

years). It also ensures that the costs are 

comparable to other BART analyses 

where similar assumptions have been 

made. However, we acknowledge that 

there may be circumstances where it is 

reasonable to assume a shorter or longer 

equipment life. In particular, it may be 

appropriate to consider a shorter 

equipment life where the owner plans to 

shut a unit down in less than 20 years. 

Further, assuming a 30 year economic 

life would not change our conclusions 

regarding BART for Colstrip Units 1 and 

2. For example, for Colstrip Unit 1 we 

have recalculated the cost-effectiveness 

amortizing over 30 years. The resulting 

cost effectiveness for SCR+SOFA is 

$2,879/ton, as compared to the cost 

effectiveness of $3,195/ton amortizing 

over 20 years which we cited in our 

proposed rule. We find that the cost of 

SOFA+SCR is reasonable regardless of 

the assumed equipment life. However, 

we find that the limited visibility 

benefits would continue to preclude our 

selection of SCR+SOFA as BART. 

Comment: EarthJustice claimed that 

EPA skewed the cost effectiveness 

results away from SCR for Colstrip Units 

1 and 2 by overestimating the operations 

and maintenance costs associated with 

SCR by approximately $600,000. In 

particular, EarthJustice questioned our 

costs for maintenance, catalyst 

replacement, and reagent use. 

Response: We disagree. While 

EarthJustice has suggested alternate 

assumptions that could be made when 

estimating each of the operation and 

maintenance costs (that is, direct annual 

costs) noted, they have not substantiated 

that their assumptions are superior to 

those used by EPA. Moreover, they have 

not substantiated that EPA erred in 

making any of the cost assumptions 

related to operations and maintenance. 

They have only pointed out instances in 

which they would make different 

assumptions. Therefore, we see no 

reason that our cost assumptions for 

O&M should be supplanted by those 

that EarthJustice would otherwise 

choose in order to arrive at lower cost 

effectiveness. 

Regardless, if we were to incorporate 

each of the changes to the O&M costs 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57889 

31Letter from David Bowen, Burns & McDonnell, 

to James Parker, PPL Montana, February 7, 2012. 

32Bowen letter. 

33 Dr. Phyllis Fox, Revised BART CostEffectiveness Analysis for Tail End Selective 

Catalytic Reduction at Basin Electric Power 

Cooperative Leland Olds Station Unit 2. Report 

Prepared for U.S. EPA, RTI Project Number 

0209897.004.095, March 2011. 

34BART Assessment Colstrip Generating Station, 

prepared for PPL Montana, LLC, by TRC (‘‘Colstrip 

Initial Response’’), August 2007, Table A4–8(c). 

35Addendum to PPL Montana’s Colstrip BART 

Report Prepared for PPL Montana, LLC; Prepared by 

TRC, (‘‘Colstrip Addendum’’), June 2008, Table 5.3– 

3. 

36NOX Control Update to PPL Montana’s Colstrip 

Generating Station BART Report Prepared for PPL 

Montana, LLC, by TRC, September 2011, Table 2– 

3b. 

37 Documentation for EPA Base Case v.4.10 Using 

the Integrated Planning Model, August 2010, EPA 

#430R10010. 

38 IPM, Chapter 5, Appendix 5–2A, p. 1. 

suggested by EarthJustice, it would not 

change our BART determination. For 

example, for Colstrip Unit 1, reducing 

the O&M costs of SCR by $600,000 

would only moderately lower the cost 

effectiveness of SNR+SOFA from 

$3,195/ton to $3,019/ton. Though we 

find that both of these costs are 

reasonable, we continue to find that 

there is insufficient visibility benefit 

(0.404 deciview for Unit 1 and 0.423 

deciview for Unit 2 at the most 

improved Class I area) to support the 

selection of SCR as BART. 

Comment: EarthJustice stated that 

EPA made multiple errors in our SCR 

cost analysis for Colstrip Units 1 and 2. 

EarthJustice claims that EPA made 

errors in relation to the baseline NOX

emissions, the control efficiency of SCR, 

the cost estimation method for direct 

capital costs (CCM vs. IPM), specific 

operation and maintenance costs, and 

the calculation of indirect annual costs 

(by way of the CRF). EarthJustice 

provided their own cost estimates for 

SCR, addressing the errors which they 

claimed EPA made. EarthJustice’s cost 

effectiveness is 55–65% lower than the 

values calculated by EPA, making 

SCR+SOFA significantly more cost 

effective. 

Response: We disagree that we made 

multiple errors in our SCR cost analysis 

for SCR for Colstrip Units 1 and 2 which 

led to inaccurate cost effectiveness. 

Each of the errors which EarthJustice 

claims EPA made has been addressed in 

separate responses. Therefore, we find 

that the cost effectiveness for SCR in the 

proposed rule was accurate and a 

correct basis for rejecting SCR as BART 

(in consideration of the remaining 

statutory BART factors). 

Comment: The NPS commented that 

EPA has placed undue weight on the 

incremental cost effectiveness of 

SOFA+SCR at Colstrip Units 1 and 2. 

Response: We disagree. In our 

proposed rule, we estimated the 

incremental cost effectiveness of 

SCR+SOFA (over SNCR+SOFA) to 

$5,770/ton and $5,887/ton, respectively. 

These costs far exceed the 

corresponding average cost effectiveness 

of $3,195/ton and $3,235/ton. Given 

these costs, we continue to find that 

SCR+SOFA is not justified by the 

visibility improvement that would be 

provided. 

Comment: Some commenters stated 

that EPA properly concluded that SCR 

does not constitute BART for Colstrip 

Units 1 and 2, but that EPA incorrectly 

analyzed the capital costs and costeffectiveness of SCR. Commenters stated 

that EPA failed to consider SCR costs 

estimates which PPL submitted in 

February 2012.31 Commenters also 

stated that EPA’s reliance on outdated 

information is not consistent with its 

own guidance to use engineering 

estimates and that EPA should modify 

its rationale in the final rule to conclude 

that, when the actual costs of the 

technology are taken into consideration, 

SCR is not a cost-effective technology. 

In particular, commenters noted that 

EPA estimates the capital cost of the 

SCR at $78 million and rejects PPL’s 

cost estimate of $190 million 

Response: We disagree that we 

incorrectly analyzed the capital costs 

and cost-effectiveness of SCR. We did 

not accept the SCR cost estimates 

submitted by PPL in February 2012 that 

were based on cost estimates provided 

to PPL by a consultant. EPA rejected 

these cost estimates for a number of 

reasons. 

First, the cost estimates provided to 

PPL by the consultant do not represent 

site-specific costs. The BART 

Guidelines state that ‘‘[t]he basis for 

equipment cost estimates also should be 

documented, either with data supplied 

by an equipment vendor (i.e., budget 

estimates or bids) or by a referenced 

source (such as the OAQPS CCM Fifth 

Edition, February 1996, EPA 453/B–96– 

001).’’ 70 FR 39166. Since the costs 

submitted by PPL were simply adapted 

from another (undisclosed) utility 

boiler, and are not specific to Colstrip 

Units 1 and 2, they should not be 

considered a budgetary bid as described 

in the BART Guidelines. In fact, PPL’s 

consultant represents the costs as a 

‘‘feasibility capital cost estimate’’ and 

not as a budgetary bid.32

Second, the capital costs for SCR 

claimed in PPL’s February 2012 

submittal are far in excess of the range 

of capital costs documented by various 

studies for actual installations. Five 

industry studies conducted between 

2002 and 2007 have reported the 

installed unit capital cost of SCRs, or 

the costs actually incurred by owners, to 

range from $79/kW to $316/kW (2010 

dollars).33 These studies show actual 

capital costs are much lower than 

estimated by PPL for Colstrip Units 1 

and 2 ($571/kW for each unit; 2011 

dollars). Moreover, the capital costs 

surveyed by the studies represent a 

range of retrofit difficulties, including 

very difficult retrofits having 

significantly impeded construction 

access, extensive relocations, and 

difficult ductwork transitions. 

Therefore, to the extent that similar 

retrofit difficulties may exist for Colstrip 

Units 1 and 2, the high end of the range 

documented in the reports is 

representative. 

Third, we are concerned about the 

disparity among the various cost 

estimates submitted by PPL. Between 

August 2007 and February 2012, PPL 

submitted four separate SCR cost 

estimates for the Colstrip Unit 1 and 2. 

In the first SCR cost estimate, submitted 

in August 2007, PPL estimated capital 

costs of $25,282,233 ($76/kW), total 

annual costs of $7,289,482 and a cost 

effectiveness of $2,272/ton (each unit; 

2007 dollars).34 In the second SCR cost 

estimate, submitted in June 2008, PPL 

estimated capital costs of $29,581,465 

($88/kW), total annual costs of 

$7,987,179 and a cost effectiveness of 

$1,735/ton (each unit; 2008 dollars).35

PPL’s first and second cost estimates 

were generally performed in 

conformance with EPA’s CCM. The 

lower cost effectiveness in the second 

submittal was driven primarily by a 

change in the assumed maximum 

control level (from 0.15 lb/MMBtu to 

0.06 lb/MMbtu), and thereby greater 

annual emission reductions. In the third 

SCR cost estimate, submitted in 

September 2011, PPL estimated capital 

costs of $152,508,328 ($457/kW), total 

annual costs of $16,733,719 and a cost 

effectiveness of $7.405/ton (each unit; 

2011 dollars).36 The third cost estimates 

were largely based on control costs 

developed for the Integrated Planning 

Model.37 PPL assumed a retrofit factor 

of 2 when using the IPM approach. We 

note that this retrofit factor, equating to 

100% over the IPM base model capital 

costs, was unsupported and far in 

excess of the range described in the IPM 

documentation: ‘‘Retrofit difficulties 

associated with an SCR may result in 

capital cost increases of 30 to 50% over 

the base model.’’ 38 In the fourth SCR 

cost estimate, submitted in February 

2012, PPL estimated capital costs of 

$190,000,000 ($571/kW), total annual 


tkelley on DSK3SPTVN1PROD with RULES3
57890 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

39Letter from Mark M. Hultman, P.E., TRC, 

February 9, 2012. 

40Bowen letter, p. 2. 41Colstrip Addendum, p. 4–1. 

costs $19,956,767, and a cost 

effectiveness of $8,884/ton (each unit; 

2011 dollars).39 The fourth cost estimate 

was also largely based on control costs 

taken from IPM, but was augmented by 

capital cost estimates provided to PPL 

by a consultant. In all, the capital costs 

varied by a factor of more than seven 

($76/kW to 571/kW), and the cost 

effectiveness varied by a factor of more 

than 5 ($1,735/ton and $8,884/ton). The 

large disparity between PPL’s February 

2012 cost estimates and those in their 

previous submittals led us to question 

their accuracy. 

Finally, PPL’s February 2012 cost 

estimates contained cost items that are 

either speculative in nature or not well 

documented. For example, they include 

capital costs for duct and boiler 

reinforcement even though the potential 

for boiler implosion was not evaluated 

by PPL’s consultant.40

For the reasons stated above, EPA 

finds that no changes to the BART 

determinations or to the FIP are needed 

in response to this comment. 

Comment: Various commenters 

objected to EPA‘s BART determinations 

for Colstrip 1 and 2. EarthJustice urged 

EPA to require selective SCR+SOFA as 

the best system of continuous emission 

control to meet a 0.05 lb/MMBtu NOX

emission limit applicable on a 30-day 

rolling average basis. NPS also 

recommended that we require 

SCR+SOFA. PPL supported a BART 

emissions rate for NOX of 0.20 lb/ 

MMBtu on a 30-day rolling average 

basis, reflecting the installation of 

SOFA. 

Response: Based on our consideration 

of the five statutory BART factors, we 

continue to find that BART for NOX at 

each of the Colstrip Unit 1 and 2 is an 

emission limit of 0.15 lb/MMBtu (30- 

day rolling average) achievable with 

SNCR+SOFA. 

Comment: PPL stated that EPA’s 

proposed emission limit for PM of 0.10 

lb/MMbtu on a 30-day rolling average 

for each of the Colstrip Unit 1 and 2 is 

flawed. PPL asserted that the current 

PM limit is 0.10 lbs/MMBtu as an 

annual average, based on a compliance 

assurance monitoring plan together with 

annual stack testing. In order to 

accommodate the shorter averaging 

period, the PPL suggested that the 30- 

day rolling average emission limit 

proposed in the FIP be increased to 0.12 

lb/MMBtu. 

Response: We disagree with some 

aspects of this comment, but agree with 

others. PPL has erred in stating that the 

current PM limit is 0.10 lb/MMBtu as an 

annual average. The Final Title V 

Operating Permit (#OP0513–06) 

indicates that the emission limit is 0.10 

lb/MMbtu, but does not provide an 

averaging period. The Title V permit 

requires that compliance with the 

emission limit be demonstrated by a 

Method 5 or Method 5B stack test once 

per year. As these stack test methods 

typically consist of three sampling runs 

of at least 120 minutes in duration, and 

are not long-term continuous 

measurements, it is not possible to 

average the emissions over 30-days or a 

year. For this reason, we corrected the 

proposed PM emission limits in a 

correction notice. 77 FR 29270. We 

clarified that that emission limits for 

NOX and SO2, but not PM, shall apply 

on a 30-day rolling average. 

As we are not requiring that PM 

emission limits apply on a 30-day 

rolling average, PPL’s suggestion that 

the emission limit be increased to 0.12 

lb/MMBtu is no longer relevant. The PM 

emission limits will remain unchanged 

from those in the proposed rule which 

are identical to those in the Title V 

permit. 

Comment: EarthJustice stated that 

EPA’s exemption of Colstrip Units 1 and 

2 from BART for PM is improper and 

unsupported. EarthJustice asserts that 

EPA has not complied with its statutory 

and regulatory obligations to determine 

BART for PM emissions from Colstrip 

Units 1 and 2 in that EPA simply made 

a declaration and skipped the statutory 

process. EarthJustice stated that the 

existing venturi scrubbers are not best 

technology and have not been 

considered such for a long time because 

particle scrubbers do not remove 

particulates sufficient to comply with 

basic CAA requirements. In addition, 

EarthJustice stated that EPA should 

have considered more effective 

technologies, such as baghouses. 

Response: We disagree. As with 

existing SO2 controls, we do not find 

that it is necessary to consider the 

replacement of existing PM controls 

with new controls. This is particularly 

true for PM as the existing controls for 

Colstrip Units 1 and 2 currently reduce 

emissions by more than 98%. Moreover, 

the contribution to the baseline 

visibility impact from PM is very small 

(e.g., for Colstrip Unit 1, less than 4% 

of 0.922 deciview, or 0.037 deciview). 

The most visibility improvement that 

could be expected, even if all PM were 

eliminated, is 0.037 deciview. The 

visibility improvement that could be 

expected with upgrades to the existing 

PM controls is only a fraction of 0.037 

deciview. Therefore, it was reasonable 

for us to conclude that the existing 

controls represent BART. 

In addition, EarthJustice has conflated 

the most stringent controls with BART. 

BART is not necessarily the most 

stringent controls, but the best system of 

continuous emission reduction taking 

into consideration the five statutory 

factors. 

Comment: NPS stated that they 

disagree with the PM emissions that we 

used in modeling the visibility impacts 

for Colstrip Units 1 and 2. They stated 

that the PM emissions data provided by 

PPL is more representative because it 

included both condensable and 

filterable PM emissions, while the PM 

data used by EPA did not measure 

condensable PM. 

Response: The difference in the 

approach used to characterize PM 

emissions for visibility modeling 

purposes is negligible. Moreover, as the 

PM emissions were held constant for all 

of the control scenarios that EPA 

modeled, they had no impact on our 

BART determinations for NOX and SO2.

Comment: EarthJustice stated that 

EPA made the same error in calculating 

baseline emissions in its SO2 BART 

determination for Colstrip Units 1 and 

2 as it did in its NOX BART 

determination. EarthJustice asserted that 

EPA should have used a baseline of 

2001–2003. 

Response: We disagree with this 

comment. As discussed in a separate 

response to comments, we have 

established a baseline which provides a 

realistic depiction of anticipated annual 

emissions for the source. For example, 

the 2008–2010 baseline we used for 

Colstrip Unit 1 reflects annual average 

emissions of 5,548 tons/yr. By 

comparison the annual average 

emissions for 2000–2010, 5,504 tons/yr, 

were only slightly lower. 

Comment: PPL stated that EPA’s 

estimate of the performance that can be 

achieved with lime addition on Colstrip 

Units 1 and 2 was wrong. The 

commenter stated that EPA’s assumed 

emission rate for SO2 of 0.15 lbs/MMBtu 

was overly optimistic, and that a rate of 

0.20 lbs/MMBtu on a 30-day rolling 

average basis is achievable. 

Response: We disagree with this 

comment. The emission rate which EPA 

assumed for limestone lime addition 

(injection) on Colstrip Units 1 and 2 was 

0.15 lb/MMBtu on an annual basis, not 

on a 30-day rolling average basis. This 

was based on PPL’s amended BART 

submittal of August of June 2008.41 We 

did not specify a 30-day rolling average 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57891 

42On September 27, 2011 Aaron Worstell and 

Vanessa Hinkle conducted a site visit at Colstrip. 

43Staudt memo, p. 4. 

44Report on the Fourth Scrubber Module Cost 

Estimate for PPL, Burns and McDonnell, p. 4–3. 

45Letter from Jonas Klingspor, URS Corporation, 

to Gordon Criswell, PPL Montana, June 15, 2012. 46Burns and McDonnell, p. 1–1. 

47 IPM, Chapter 5, Table 5–4 shows a range of 

illustrative $/kW costs. 

emission limit for limestone injection 

since we did not select it as BART. 

Comment: PPL commented that 

installation of an additional scrubber 

vessel is technically impracticable, if 

not infeasible, due to space constraints 

and the potential for equipment scaling. 

Response: First, addition of a fourth 

scrubber vessel for each of Colstrip units 

1 and 2 does not appear to be 

impracticable due to space constraints. 

PPL’s argument that there is no space 

availability for an additional scrubber 

vessel is not supported by its own 

consultant. In addition, the site visit 

conducted by EPA 42 verified and the 

site plan provided by PPL shows ample 

space for locating additional equipment. 

A satellite image of units 1 and 2 

located in the docket.43 In fact, PPL’s 

consultant, Burns & McDonnell was able 

to find space for a new vessel with 

associated ductwork: ‘‘[t]here is 

sufficient space behind the stacks for 

installation of the fourth scrubber 

module, ID fan, ductwork and 

accessories.’’ 44 As URS pointed out, 

this might require an additional booster 

fan, which is included in the Burns & 

McDonnell estimate.45

Second, an additional scrubber vessel 

may not be necessary to avoid scaling. 

It is possible to inject lime and mitigate 

the risk of scaling through addition of a 

forced oxidation system or by use of 

chemical additives that mitigate scaling. 

The current system uses natural 

oxidation. Forced oxidation will enable 

higher lime injection rates while 

avoiding scaling. Forced oxidation 

systems will require blowers and 

piping, and agitators that could be 

retrofit on the existing scrubber vessels 

at what is likely to be a much lower cost 

than the cost of a new absorber vessel. 

An alternative to forced oxidation is use 

of chemical additives that address 

scaling. These additives are available 

from companies such as Nalco Chemical 

Company. 

We find that it is acceptable for PPL 

to reduce emissions by means other 

than installing an additional scrubber 

vessel, provided that the emission limit 

of 0.08 lb/MMBtu on a 30-day rolling 

average is met. 

Comment: PPL stated that EPA 

overstated the emissions benefit of an 

additional scrubber vessel. 

Response: PPL argues that an 

additional vessel would not in fact 

reduce emissions because velocity 

through the existing scrubber vessel tray 

will be reduced. As noted in responses 

to other comments, an additional 

scrubber vessel may not be necessary to 

achieve 95% SO2 capture. Nevertheless, 

with regard to addition of another 

scrubber vessel and the impact on SO2

reduction, PPL relies on a June 15, 2012, 

letter from Jonas Klingspor of URS 

Corporation that states the reduced gas 

velocity would reduce SO2 reduction. 

The URS letter and PPL, however, 

overlook the fact that the openings in 

the tray for the existing vessels could be 

reduced to restore gas velocity to the 

original level. 

URS provided estimates of emission 

rates possible under different 

conditions. The analyses performed by 

URS were limited either by increased 

scaling (the lowest rate of 0.13 lb/ 

MMBtu with three vessels) or lower 

absorber gas velocity (0.16 lb/MMBtu 

with four vessels). Since URS did not 

evaluate addition of a forced oxidation 

system or any other means to address 

scaling, it is likely that a significantly 

lower emission rate than 0.13 lb/MMBtu 

is possible while using three vessels. 

And, addition of a fourth scrubber 

vessel, with tray openings in the three 

original vessels adjusted to maintain gas 

velocity, in combination with a forced 

oxidation system would certainly 

increase SO2 capture performance even 

more. 

Regardless, if PPL uses the additional 

scrubber vessel as a spare in a manner 

similar to that for Colstrip Units 3 and 

4, then gas flow will remain unchanged. 

In this mode of operation, the spare 

scrubber vessel helps allow for 

maintenance that is needed due to the 

scaling caused by the additional lime. 

Without the spare vessel, the unit must 

be shut down to perform the 

maintenance. This is the mode of 

operation proposed by PPL in their 

August 2007 submittal. 

Comment: Commenters stated that an 

additional scrubber vessel costs far more 

than EPA proposed and is therefore not 

cost-effective. Commenters stated that it 

was inappropriate for EPA to rely on 

outdated costs for an additional 

scrubber vessel in our proposed rule. 

PPL provided cost estimates obtained 

from Burns & McDonnell 46 showing 

higher costs than estimated by EPA. 

Response: Foremost, we note that the 

costs that we cited for an additional 

scrubber vessel in our proposed rule 

were costs provided by PPL in their 

BART submittals of August 2007 and 

June 2008. PPL did not explain why the 

cost estimates submitted by PPL during 

the comment period are more than two 

and a half times their original cost 

estimates. 

The cost estimated by Burns & 

McDonnell of adding a single module to 

treat 25% of the flue gas is 

unreasonable, equating to around $213/ 

kW ($71 million divided by 333,000 

kW),– or the equivalent of $853/kW 

when adjusting for the fact that only one 

fourth of the flue gas is being treated. To 

put this in perspective, this is more 

costly on a $/kW basis than the typical 

cost of a complete limestone forced 

oxidation wet FGD system (around 

$500/kW) that would provide over 95% 

removal for 100% of the flue gas.47 Also, 

according to the 2010 EIA Form 860 

Enviroequip data, the original scrubber 

structure with three modules for 

Colstrip Unit 1 cost $34 million in 1975 

(slightly over $100/kW). Using the 

Chemical Engineering Plant Cost Index 

(CEPCI) to escalate to 2011 dollars, the 

cost in today’s dollars would be about 

$109 million ($34 million times 585.7/ 

182.4, or about $327/kW). This would 

suggest the cost of an additional vessel 

to be on the order of $27 million, or 

about 38% of what Burns & McDonnell 

estimated and consistent with what EPA 

has previously estimated. Moreover, the 

difference in cost between EPA’s 

estimate and what Burns & McDonnell 

has estimated is far too large to be 

explained by the additional ductwork 

and fans associated with the retrofit, 

which PPL asserts are necessary. 

Additionally, Table 4–1 of the 

documentation from Burns & 

McDonnell has several costs that are 

questionable or high ($900,000 for 

Owner’s Project Management and 

$400,000 for Owner’s Legal Counsel and 

$3.4 million in Escalation) and others 

that are very high and therefore require 

better explanation ($8.1 million for 

furnish and erect packages plus the 

estimates for Mechanical, Electrical and 

Civil and Structural Construction that 

total over $12 million). Engineering 

costs as well as many other costs are 

typically determined as a percentage of 

the other costs, therefore the effect of 

overestimation of one cost is 

compounded because it contributes to 

overestimation of other costs. Because 

the estimate by Burns & McDonnell is so 

much higher than what is reasonably 

expected and includes several 

unsubstantiated and questionable cost 

elements. In any event, an additional 

scrubber vessel may not be necessary if 

a forced oxidation system or other 

means to control scaling is used on the 

existing three scrubber vessels. PPL may 

determine that other means may be 


tkelley on DSK3SPTVN1PROD with RULES3
57892 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

better than adding an additional 

scrubber vessel in terms of cost or other 

factors for achieving the BART emission 

rate. 

Comment: Commenters stated that 

EPA did not properly consider the 

incremental cost-effectiveness of 

additional scrubber vessels at Colstrip 

Units 1 and 2. Commenters stated that 

while the average cost-effectiveness of 

lime injection and an additional 

scrubber vessel is $912/ton, the 

incremental cost-effectiveness of a 

scrubber vessel is $2,379/ton, nearly 

three times higher. 

Commenters also stated that it was 

improper for EPA to evaluate lime 

injection and an additional scrubber 

vessel together. Commenters stated that 

the incremental cost of adding an 

additional scrubber vessel to lime 

injection outweighs the benefits. In 

particular, they noted that use of lime 

injection alone would cost $1,883,200, 

while the addition of a scrubber vessel 

adds $2,217,000 to the total cost. By 

contrast, they noted that the SO2

reductions achieved from the addition 

of the scrubber vessel are 929 tpy, while 

the use of lime injection alone results in 

emission reductions of 3,557 tpy. 

Response: We agree with this 

comment in part. We miscalculated the 

incremental cost effectiveness of an 

additional scrubber vessel at Colstrip 

Unit 1 (which we stated to be $1,975/ 

ton), but not at Colstrip Unit 2 ($2,410/ 

ton). The correct incremental cost 

effectiveness for an additional scrubber 

vessel at Colstrip Unit 1 is $2,380/ton, 

not $1,975/ton as given in our proposed 

rule. 

However, we disagree that it was 

improper to evaluate lime injection with 

an additional scrubber vessel together. 

We also disagree that cost of the 

additional scrubber vessel outweighs 

the benefits. For example, for Colstrip 

Unit 2, individually the total annual 

cost of an additional scrubber vessel is 

$2,210,000, while the emission 

reduction is 917 tons per year. This 

results in a cost effectiveness of $2,410, 

essentially the same as the incremental 

cost effectiveness between the two 

control options. The visibility 

improvement from lime injection alone 

is 0.225 deciview (at Theodore 

Roosevelt NP), while the improvement 

from lime injection with an additional 

scrubber vessel is 0.280 deciview (at 

Theodore Roosevelt NP). We continue to 

find that the cost is reasonable given the 

visibility benefits and that lime 

injection with an additional scrubber 

vessel represents BART. 

Comment: PPL commented that in 

proposing SNCR, EPA appears to rely on 

its determination that relevant Class I 

areas are currently above the Regional 

Haze Glide Path (RHGP). 77 FR 24,038. 

The RHGP is an important factor for the 

reasonable progress goals, but it is not 

one of the five statutory factors specified 

for EPA to consider in its BART 

analysis. Furthermore, as discussed 

above, there is no incremental benefit in 

visibility from installation of SNCR that 

would affect the area improvement in 

visibility relative to the glide path. 

Response: We agree with some 

aspects of this comment and disagree 

with others. We agree that the Regional 

Haze glidepath is not one of the five 

statutory factors specified for EPA to 

consider in its BART analysis. We based 

our decision solely on the five statutory 

factors. 

Comment: EarthJustice stated that 

EPA settled for minor adjustments for 

SO2 pollutants from Colstrip Units 1 

and 2 instead of proper BART controls. 

In particular, EarthJustice stated that 

EPA failed to examine a full suite of 

options for SO2 BART, including 

replacement of the existing scrubbers 

with state-of-the-art scrubbers that could 

remove 98% of the SO2 from Colstrip 

Units 1 and 2. 

In addition, EarthJustice claimed that 

EPA failed to consider all feasible 

upgrades to the existing venturi 

scrubbers, including the use of 

magnesium enhanced lime. EarthJustice 

stated that significant emission 

reductions could be achieved via these 

upgrades, even without the installation 

of an additional scrubber vessel. 

EarthJustice held that an emission limit 

of 0.06 lb/MMbtu can be achieved with 

these upgrades. 

Response: We disagree that we should 

have considered replacement of the 

existing controls. As noted in our 

proposed rule, for example: 

The Colstrip Unit 1 venturi scrubber 

currently achieves greater than 50% removal 

of SO2. For units with preexisting postcombustion SO2 controls achieving removal 

efficiencies of at least 50%, the BART 

Guidelines state that upgrades to the system 

designed to improve the system’s overall 

removal efficiency should be considered. 

77 FR 24028. 

The BART Guidelines only 

recommend evaluating constructing a 

new FGD system ‘‘[f]or coal-fired EGUs 

with existing post-combustion SO2

controls achieving less than 50 percent 

removal efficiencies.’’ 70 FR 39171. 

Therefore, it was appropriate for us to 

not consider new state-of-the art 

scrubbers, or for that matter, any 

replacement technology. 

As noted in a separate response, we 

agree that it may not be necessary to add 

an additional scrubber vessel in order to 

achieve an emission limit of 0.08 lb/ 

MMBtu on a 30-day rolling average. We 

acknowledge that it may be possible to 

achieve the emission limit with 

modifications to the existing scrubbers, 

such as a forced oxidation system or by 

use of chemical additives that mitigate 

scaling. However, these alternative 

approaches would likely be at a lower 

cost than an additional scrubber vessel. 

Given that equivalent emission 

reductions would be achieved at lower 

costs, the cost effectiveness would be 

even more reasonable. Accordingly, we 

are extending flexibility to PPL to meet 

the emission limit using the lowest cost 

approach. 

Regardless of whether PPL chooses to 

meet the emission limit with an 

additional scrubber vessel or 

modifications to the existing scrubber 

vessels, we continue to find that an 

emission limit of 0.08 lb/MMBtu, and 

not 0.06 lb/MMBtu as suggested by the 

commenter, is appropriate. As noted in 

the proposed rule, this is based on the 

level of performance being achieved by 

Colstrip Units 3 and 4 which already 

employ scrubbing systems similar to 

that being contemplated for Colstrip 

Units 1 and 2. 

The use of MEL is addressed in a 

separate response to a similar comment 

from EarthJustice in regard to Colstrip 

Units 3 and 4. 

H. Comments on Corette 

Comment: EarthJustice indicated that 

EPA‘s decision not to impose BART on 

Corette violates the statutory 

requirements for BART and is not 

supported by the facts. EarthJustice 

stated that EPA engaged in the same 

kind of non-BART result oriented 

process for Corette as it did for Colstrip. 

They asserted that EPA’s approach is no 

more legitimate or compliant with the 

haze requirements in the case of Corette. 

Based on their own BART analyses, they 

determined that BART for Corette is 

installation of a dry scrubber and 

baghouse for the control of SO2 and PM 

emissions, and SCR+SOFA for NOX.

Response: We disagree with this 

comment. Our selection of BART for 

Corette was based on our objective 

consideration of the five statutory 

factors. We continue to find no 

additional controls are necessary for 

Corette. Below, we address specific 

issues raised by EarthJustice in regard to 

our BART determination for Corette. 

Comment: EarthJustice stated that, as 

with Colstrip Units 1 and 2, we used an 

improper baseline in our BART 

evaluation of 2008–2010. EarthJustice 

asserted that using these years 

artificially depresses the emissions 

baselines, which in turn makes visibility 

improvement appear less than they 


tkelley on DSK3SPTVN1PROD with RULES3
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48NOX Control Update to PPL Montana’s J.E. 

Corette Generating Station BART Report, September 

2011, Prepared for PPL Montana, LLC by TRC, at 

ES–1 (‘‘NOX Control Update’’); SO2 Control Update 

to PPL Montana’s J.E. Corette Generating Station 

BART Report, August 2011, Prepared for PPL 

Montana, LLC by TRC, at ES–1 (‘‘SO2 Control 

Update’’) 

49See NOX Control Update to PPL Montana’s J.E. 

Corette Generating Station BART Report, September 

2011, Prepared for PPL Montana, LLC by TRC, at 

ES–1 (‘‘NOX Control Update’’); SO2 Control Update 

to PPL Montana’s J.E. Corette Generating Station 

BART Report, August 2011, Prepared for PPL 

Montana, LLC by TRC, at ES–1 (‘‘SO2 Control 

Update’’). 

50NOX Control Update, at ES–3. 

51SO2 Control Update, at 14. 

52United Conveyer Corporation Dry Sorbent 

Injection FAQ (http://unitedconveyor.com/ 

dsi_systems/). 

53Ref 2: SO2 Control Update to PPL Montana’s 

J.E. Corette Generating Station BART Report, 

Prepared for PPL Montana, LLC, by TRC, August 

2011, p. ES–2. 

actually are and thereby makes BART 

alternatives look less cost-effective than 

they actually are. 

Response: See response to similar 

comments made by EarthJustice in 

regard to Colstrip Units 1 and 2. Here 

again, as required by the BART 

Guidelines, we used a baseline that is 

reflective of actual operations. We 

acknowledge that the 2008–2010 

emissions for both SO2 and NOX were 

in fact somewhat lower than the longterm trend. For example, the 2000–2010 

SO2 emissions were 3,129 tpy, while the 

2008–2010 emissions were 2,723 tpy. 

Similarly, the 2000–2010 NOX

emissions were 1,748 tpy, while the 

2008–2010 emissions were 1,625 tpy. 

Nonetheless, the difference in the 

baseline emissions would not have 

impacted the cost-effectiveness 

calculations in an appreciable manner. 

Comment: EarthJustice stated that 

EPA understated the cost effectiveness 

of SCR+SOFA. 

Response: See response to similar 

comment made by EarthJustice in regard 

to Colstrip Units 1 and 2. 

Comment: EarthJustice stated that 

EPA’s cost-effectiveness calculations for 

SO2 controls for Corette contain a 

number of incorrect assumptions. In 

particular, EarthJustice stated that much 

lower emission reductions can be 

achieved with LSD (90% with low 

sulfur coal) than assumed by EPA. Also, 

EarthJustice stated that EPA’s approach 

of using IPM for capital costs resulted in 

a double counting of installation costs. 

Response: We disagree. See response 

to similar comment made by 

EarthJustice in regard to Colstrip Units 

1 and 2. 

As we have noted previously, 

EarthJustice has erred in assuming that 

a given control efficiency can be 

achieved in all applications regardless 

of the input emission rate or other 

parameters. The level of performance 

assumed by EPA for LSD (0.065 lb/ 

MMBtu annually) is generally reflective 

of what can be achieved with this 

technology. 

Further, we used IPM based 

calculations for both capital costs and 

O&M costs for SO2 controls at Corette. 

(This is unlike for NOX controls, where 

we used IPM based capital costs to 

reflect recent market trends). Therefore, 

we could not have double counted the 

installation costs for SO2 controls (from 

IPM and the CCM). 

Comment: EarthJustice stated that 

EPA wrongly exempted Corette from 

BART for PM. 

Response: See response to a similar 

comment made by EarthJustice in regard 

to PM BART for Colstrip Units 1 and 2. 

Comment: PPL stated that they 

support our conclusions with respect to 

BART for Corette that further controls 

are not justified. 

Response: Comment noted. The final 

FIP does not require additional controls 

for Corette. 

Comment: Commenters stated that 

they disagree with EPA’s cost analysis 

for NOX and SO2 control technologies at 

Corette and that EPA incorrectly 

concluded that a number of the control 

technologies are cost-effective. 

Commenters noted that PPL submitted a 

five factor BART analysis for Corette in 

August 2007, and later supplemented 

with the analysis with updated 

information in June 2008 and September 

2011.48 Commenters stated that in view 

of the information that PPL provided, 

EPA incorrectly concluded that SOFA, 

SOFA+SNCR, and SOFA+SCR are ‘‘all 

cost effective technologies’’ (77 FR 

24043) and that the proposed FIP also 

incorrectly concluded that dry sorbent 

injection (DSI) for SO2 is cost-effective 

at $3,940/ton. 77 FR 24047. 

Commenters stated that as 

documented in PPL’s 2011 submissions, 

the company used the IPM control 

technology cost estimation techniques, 

which are more robust than those used 

in previous BART reports submitted by 

PPL.49 Commenters stated that with 

respect to NOX, PPL determined the 

cost-effectiveness of SNCR to be 

approximately $13,544/ton (as 

compared to EPA’s $2,596 for 

SOFA+SNCR) and the cost-effectiveness 

for SCR to be $8,457/ton of additional 

NOX controlled (as compared to EPA’s 

$4,491 for SOFA + SCR).50 The 

company stated that for SO2 controls, 

the updated analysis determined that 

the cost-effectiveness of DSI is $10,920/ 

ton (as compared to EPA’s $3,940/ 

ton).51 Commenters stated that the 

proposed FIP failed to consider that the 

installation of DSI would most likely 

require upgrades to the existing 

particulate controls to achieve the SO2

reductions that EPA evaluated and that 

EPA relied on the outdated and 

inaccurate CCM to develop these 

estimates. 

Response: We disagree. See our 

response to similar comments made by 

PPL in regard to cost analyses for 

Colstrip Units 1 and 2. PPL’s cost 

estimates for Corette included many of 

the same incorrect methods and 

assumptions that the company used 

when developing cost estimates for 

Colstrip Units 1 and 2. In particular, 

PPL used unsupported retrofit factors 

that were well in excess of the range 

described in the IPM documentation. 

Also, we disagree that installation of 

DSI would most likely require upgrades 

to the existing particulate controls to 

achieve the SO2 reductions that EPA 

evaluated. In fact, DSI using trona 

would ‘‘typically either improve 

performance or have little impact, even 

at high injection rates.’’ 52 It would not 

require the replacement of the existing 

ESP with a new baghouse as reflected in 

PPL’s cost effectiveness estimate of 

$10,920/ton.53 Therefore, we find that 

EPA’s cost estimate of $3,490 is 

accurate. 

Comment: Commenters stated that our 

proposed SO2 and NOX emission limits 

for Corette were flawed. One commenter 

stated that EPA must increase the limits 

to no less than 0.81 lb/MMBtu for SO2

and 0.46 lb/MMBtu for NOX in order to 

account for compliance over a 30-day 

rolling average. By contrast, another 

commenter stated that our proposed 

emission limits were too high and 

would actually result in increased 

emissions. 

Response: Based on these comments, 

we have reassessed our SO2 and NOX

emission limits for Corette. As we have 

not prescribed any additional controls 

for Corette, the emission limits should 

reflect emission rates currently being 

achieved with existing controls. In order 

to establish appropriate emission limits, 

we have conducted a statistical analysis 

of the monthly emissions data contained 

in the CAMD emissions system. For the 

period 2000–2010, the 99th percentile 

monthly SO2 emission rate was 0.548 

lb/MMbtu. Similarly, the 99th 

percentile monthly NOX emission rate 

was 0.335 lb/MMBtu. In our final 

action, we are establishing emission 

limits slightly above these 99th 

percentile emission rates in order to 

allow a sufficient margin for 

compliance. This is because the 

emission limits must apply at all times, 


tkelley on DSK3SPTVN1PROD with RULES3
57894 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

including during startup, shutdown, 

and malfunction. The revised emission 

rates are 0.57 lb/MMBtu for SO2 and 

0.35 lb/MMBtu for NOX, both on a 30- 

day rolling average. We have revised the 

emission limits for Corette contained in 

section 52.1396(c)(1) accordingly. Our 

complete analysis of SO2 and NOX

emission limits for Corette can be found 

in the docket.0.5480.3350.57 We have 

addressed the emission limit for PM at 

Corette in a separate response to 

comments. 

Comment: PPL stated that EPA’s PM 

emission limit for Corette was flawed. 

PPL noted that over the past five years, 

stack test results have shown that PM 

emissions have ranged from 0.059 lb/ 

MMBtu to 0.252 lb/MMBtu. PPL stated 

that an emission limit of 0.30 lb/MMBtu 

would be necessary to account for a 30- 

day rolling average. 

Response: We agree, in part. In our 

proposed rule, we incorrectly specified 

a PM emission limit of 0.10 lb/MMBtu 

on a 30-day rolling average. In 

consideration of the stack test data 

provided by PPL, we have determined 

that that a limit of 0.26 lb/MMBtu is 

more appropriate. In addition, and as 

discussed in response to a similar 

comment made by PPL in regard to 

Colstrip, we find that it is not feasible 

to require compliance with this 

emission limit on a 30-day rolling 

average. Again, this is because 

compliance is shown using stack 

methods such as Method 5 and 5B. 

These stack test methods typically 

consist of three sampling runs of at least 

120 minutes in duration, and are not 

long-term continuous measurements. As 

such, it is not possible to average the 

emissions over 30 days or a year. 

Accordingly, we are revising our FIP 

to reflect a PM emission limit for Corette 

of 0.26 lb/MMBtu. We are also removing 

the 30-day averaging period requirement 

for the PM emission limit at Corette. 

More specifically, we are revising 

section 52.1396(c)(1) to clarify that 

emission limits for NOX and SO2, but 

not PM, shall apply on a 30-day rolling 

average. Note that we are retaining the 

requirement that compliance with the 

PM emission limit shall be monitored in 

accordance with the CAM plan. 

As we are not requiring that the PM 

emission limit applies on a 30-day 

rolling average, PPL’s suggestion that 

the emission limit be increased to 0.30 

lb/MMBtu is no longer relevant. 

Comment: The USFWS commented 

that there are at least two other 

similarly-sized installations 

implementing lime spray drying (LSD) 

for SO2 control that justify the positions 

taken by EPA in the proposed BART 

determination. USFWS stated that in 

justifying emission limits of small units 

burning clean coal, Newmont Nevada is 

a 200 MW plant that attains a 30-day 

rolling average 0.065 lb/MMBtu SO2

emission limit with an SO2 control 

efficiency of 93.1% and that capital cost 

of LSD units is corroborated by Great 

River Energy’s 188 MW Stanton #1 plant 

costing $79,514,000. 

Response: We acknowledge that the 

USFWS has provided information from 

two other similarly-sized installations 

which are implementing LSD for SO2

corroborating our LSD cost estimates for 

Corette. However, as noted in our 

proposed rule, the cost of controls is not 

justified by the visibility improvement 

(0.253 deciview). 

Comment: The USFWS stated that the 

capital costs proposed by EPA for dry 

sorbent injection (DSI) and LSD should 

be considered as maximums, because 

the costs should only decrease due to 

significant curtailment of construction 

of air pollution control devices during 

the economic downturn and 

cancellation or postponement of many 

coal burning electrical generation units. 

The USFWS stated that quantified 

estimates of the decreases could provide 

for firm reductions in the capital cost 

estimates, but it is agreed that they 

would be difficult to affirm with 

confidence at this time. 

Response: We agree that any changes 

in cost associated with economic 

downturn would be difficult to affirm 

with confidence at this time. 

Comment: The USFWS stated that the 

paragraph following Table 123 states 

that EPA considers $4,659 per ton of 

SO2 emissions reduction using DSI as 

reasonable, but that $5,442 per ton for 

LSD is not cost effective. The USFWS 

stated that other proposed SO2 BART 

determinations resulting in cost 

efficiency in the range of Corette 

include PacifiCorp’s Dave Johnston, 

WY–$4,743; Northshore Mining’s Silver 

Bay Power, MN–$7,309 and Xcel 

Energy’s Taconite Harbor, MN–$5,300 

and as stated above, the capital cost of 

an LSD unit on Great River Energy’s 188 

MW Stanton #1 plant is $79,514,000. 

USFWS stated that such a total capital 

cost incorporated as the cost of LSD at 

Corette would result in a cost per ton of 

SO2 removed of $4,891 and that the LSD 

alternative might then also be 

considered by EPA as being cost 

effective along with DSI. 

Response: We disagree. We continue 

to find that the cost of LSD for Corette 

is not justified by the visibility 

improvement. Moreover, the capital cost 

that we estimated for LSD is specific to 

Corette, and we see no reason to 

supplant that cost with costs from 

Taconite Harbor or other individual 

facilities. 

Comment: The USFWS stated that 

regarding the cost-effectiveness of 

visibility improvement for SO2 controls, 

the second paragraph after Table 123 in 

the draft proposed BART determination 

states, ‘‘ * * * the cost of controls is not 

justified by the visibility improvement’’ 

and that this proposed conclusion 

warrants further scrutiny. The USFWS 

stated that implementation of the DSI 

alternative results in a 0.176 deciview 

improvement at Washakie WA, the 

highest impacted Class I area, at a cost 

of $3.4 million per deciview of 

improvement and that this is a very 

reasonable cost for visibility 

improvement. The UFWS stated that the 

cost of visibility improvement for SO2

controls proposed in other BART 

determinations for a single mostimpacted Class I area include: Colorado 

Springs Utilities, Martin Drake, CO– 

$49.9 million/deciview; PacifiCorp, 

Wyodak, WY–$44.7 million/deciview; 

PacifiCorp, Jim Bridger, WY–$37.1 

million/deciview; PG&E, Boardman, 

OR–$35.2 million/deciview; and 

Dominion, Brayton Point, MA–$33.9 

million/deciview; Northshore Mining, 

Silver Bay Power, MN–$26.2 million/ 

deciview; Dominion, Salem Harbor, 

MA–$25.1 million/deciview; Great 

River Energy, Stanton #1, ND–$21.9 

million/deciview; PacifiCorp, Naughton, 

WY–$18.2 million/deciview; PacifiCorp, 

Dave Johnson, WY–$16.7 million/ 

deciview. The USFWS stated that the 

conclusion from the above is that since 

the cost per ton of SO2 removal and the 

cost per deciview of visibility 

improvement are both reasonable, DSI 

should be considered as a feasible and 

cost-effective SO2 control alternative 

and be accepted as BART for the PPL 

Montana, J.E. Corette Generating 

Station. 

Response: We disagree. The total 

annual cost of DSI for Corette, as cited 

in our proposed rule was $5,363,896, 

while the greatest visibility 

improvement was 0.176 deciview 

(Washakie WA). This results in cost of 

$30 million per deciview, not $3.4 

million per deciview. We continue to 

find that the cost of LSD for Corette is 

not justified by the visibility 

improvement. 

Comment: The USFWS commented 

that Table 110 states the visibility 

improvement associated with each of 

the three NOX control alternatives and 

by dividing respective Total Annual 

Costs by their visibility improvements, 

they result in cost per deciview of 

visibility improvement from $16.7 

million to $17.8 million at the Washakie 

WA, the highest impacted Class I area. 


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The USFWS stated that when these 

values are compared to other single 

Class I area impacts for some other NOX

BART proposals as summarized below, 

it would indicate that they each could 

be considered as reasonable. The 

USFWS stated that when total annual 

cost for each of the three NOX control 

alternatives is divided by the respective 

visibility improvement for all affected 

Class I areas (as discussed above for 

SO2) they result in cost per deciview of 

visibility improvement from $4.7 

million to $5.0 million, which is a very 

reasonable visibility cost. USFWS stated 

that since the cost per ton of NOX

removal and the cost per deciview of 

visibility improvement are both 

reasonable, at least the Separated Overfire Air (SOFA)-only or, preferably 

SOFA plus Selective Non-Catalytic 

Reduction (SNCR) should definitely be 

considered as feasible and cost-effective 

NOX control alternatives and be 

accepted as BART for Corette. 

Response: We disagree that SOFA or 

SOFA+SNCR should be accepted as 

BART for Corette. The BART Guidelines 

require that cost effectiveness be 

calculated in terms of annualized 

dollars per ton of pollutant removed, or 

$/ton. 70 FR 739167. The BART 

Guidelines list the $/deciview ratio as 

an additional cost effectiveness metric 

that can be employed along with $/ton 

for use in a BART evaluation. However, 

we did not use this metric for the 

reasons that were explained in other 

responses. As we stated in the proposed 

FIP, we weighed costs against the 

anticipated visibility impacts and we 

explained that any of the control 

options would have a positive impact 

on visibility; however, the cost of 

controls was not justified by the 

visibility improvement. As we have 

explained elsewhere, in our proposal, 

we considered the visibility 

improvement at all Class I areas within 

300 km of the subject BART unit. 

In addition, we note that the UFWS 

seems to have miscalculated the dollars 

per deciview values for the NOX control 

options. 

Comment: The USFS stated the BART 

determinations for Corette are not 

consistent with previous BART 

demonstrations that have been made for 

other facilities in Montana, as well as 

with decisions EPA has approved in 

other SIPs. And that EPA has identified 

control options for both NOX and SO2

that are technically feasible and cost 

effective. USFS stated that it is their 

understanding that EPA has also 

determined that the visibility 

improvement does not justify the cost of 

the additional controls. 

Response: We disagree. As the 

commenter has noted, we rejected 

additional controls for Corette since the 

visibility improvement does not justify 

the cost of controls. Moreover, the 

USFWS has not identified how this is 

inconsistent with other BART 

determinations in Montana or 

elsewhere. 

Comment: WEG stated that EPA 

arbitrarily rejected requiring SCR as 

BART for NOX emissions from Corette 

and that we stated in the proposed FIP 

that the control technology would be 

cost-effective and achieve greater 

visibility benefits—in favor of no 

additional controls. WEG stated that the 

EPA’s proposed BART determination is 

inconsistent with the CAA and the 

Agency’s own record. WEG stated that 

that under the factors required to be 

considered by EPA in determining 

BART under the CAA, SCR would 

constitute BART. WEG stated that EPA 

found that SCR for Corette would not be 

cost-prohibitive and that the Agency 

also identified no energy and nonair 

quality impacts that would mitigate 

against the use of SCR, or any remaining 

useful life issues that would preclude 

the use of SCR. WEG stated that with 

regard to visibility improvement, the 

EPA further found that SCR, as opposed 

to doing nothing, would achieve greater 

visibility improvements and that given 

that SCR represents ‘‘the best system of 

continuous emission control technology 

available’’ (40 CFR 51.308(e)(1)(ii)), 

there appears to be no reason to dismiss 

SCR as BART for Corette. WEG stated 

that the EPA asserted that SCR for 

Corette ‘‘is not justified by the visibility 

improvement.’’ Yet, the proposed FIP 

indicates that with the use of SCR, 

visibility improvements in the most 

impacted Class I area, the Washakie 

WA, would be 264%, an enormous 

improvement from current conditions. 

WEG stated that SCR would have a 

visibility improvement of 0.264 

deciview and that SCR would reduce 

visibility impairment at seven different 

Class I areas, and that SCR would 

cumulatively improve visibility amongst 

the seven impacted Class I areas by 

0.939 deciview. 77 FR 24042. 

WEG stated that such cumulative 

visibility improvements do not appear 

to be unreasonable, but that in this case, 

the EPA appears to believe that the level 

of visibility improvement is not 

significant enough to justify the use of 

SCR. WEG stated that the proposed FIP 

provides no information or analysis to 

indicate that EPA’s belief is not 

anything more than an arbitrary claim 

and that there is no explanation as to 

why the EPA believed the level of 

improvement with the use of SCR was 

somehow discountable or insignificant. 

WEG stated that the EPA’s logic is 

further belied by the fact that the FIP 

will fail to achieve meaningful 

reasonable progress in attaining natural 

visibility conditions in Class I areas in 

Montana and that given the prospect of 

such dismal progress in achieving 

natural visibility, it is reasonable to 

presume that any improvement in 

visibility, no matter how small, would 

be significant. WEG stated that the EPA 

failed to provide any information or 

analysis in the proposed FIP or the 

supporting record suggesting otherwise. 

WEG stated that although it is true that 

EPA is allowed to consider the degree 

in improvement in visibility in 

determining BART, there is no 

indication that this factor could be 

interpreted to allow the Agency to make 

arbitrary determinations that a 264% 

improvement in visibility under a plan 

that already contains unreasonable 

RPGs is insignificant or otherwise not 

worthy of regulatory action under the 

CAA’s regional haze program. 

Response: We disagree. We did not 

arbitrarily reject SCR. Our proposal 

clearly laid out the bases for our 

proposed BART determination for NOX

for Corette. Our regulations define 

BART as an emission limitation based 

on the degree of reduction achievable 

through the application of the best 

system of continuous emission 

reduction for each pollutant which is 

emitted by an existing stationary 

facility. The emission limitation must be 

established, on a case-by-case basis, 

taking into consideration the technology 

available, the costs of compliance, the 

energy and nonair quality 

environmental impacts of compliance, 

any pollution control equipment in use 

or in existence at the source, the 

remaining useful life of the source, and 

the degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

The BART analysis identifies the best 

system of continuous emission 

reduction taking into account: 

(1) The available retrofit control 

options, (2) Any pollution control 

equipment in use at the source (which 

affects the availability of options and 

their impacts), (3) The costs of 

compliance with control options, (4) 

The remaining useful life of the facility, 

(5) The energy and nonair quality 

environmental impacts of control 

options (6) The visibility impacts 

analysis. 70 FR 39163. 

As the final BART Guidelines explain, 

both the 2001 proposal and the 2004 

reproposal requested comments on two 

options for evaluating the ranked 

options. The first option was similar to 


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the process that WEG implies should 

have been followed, where the most 

stringent control option must be chosen 

as long as it does not impose 

unreasonable costs of compliance or 

energy and nonair quality 

environmental impacts would justify 

selection of an alternative control 

option. 70 FR 39130. The second option 

was: 

An alternative decision-making approach 

that would not begin with an evaluation of 

the most stringent control option. For 

example, States could choose to begin the 

BART determination process by evaluating 

the least stringent technically feasible control 

option or by evaluating an intermediate 

control option drawn from the range of 

technically feasible control alternatives. 

Under this approach, States would then 

consider the additional emissions reductions, 

costs, and other effects (if any) of 

successively more stringent control options. 

Under such an approach, States would still 

be required to (1) display all of the options 

and identify the average and incremental 

costs of each option; (2) consider the energy 

and nonair quality environmental impacts of 

each option; and (3) provide a justification 

for adopting the technology selected as the 

‘‘best’’ level of control, including an 

explanation of its decision to reject the other 

control technologies identified in the BART 

determination. 

In the final guidelines, EPA ‘‘decided 

that States should retain the discretion 

to evaluate control options in whatever 

order they choose, so long as the State 

explains its analysis of the CAA 

factors.’’ 70 FR 39130. The BART 

Guidelines state that we ‘‘have 

discretion to determine the order in 

which you should evaluate control 

options for BART’’ and that we ‘‘should 

provide a justification for adopting the 

technology that you select as the ‘‘best’’ 

level of control, including an 

explanation of the CAA factors that led 

you to choose that option over other 

control levels.’’ 70 FR 39170. 

We explained our analysis of the five 

factors and explained that the CAA 

factors that led to our decision were 

cost-effectiveness and visibility 

improvement. The cost-effectiveness of 

SOFA + SCR was determined to be 

$4,491/ton and the visibility 

improvement at the most impacted 

Class I area, Washakie WA, was 0.264 

deciview. The impact at additional 

Class I areas was shown in Tables 123 

and 124. 77 FR 24042. When we 

weighed the costs against the 

anticipated visibility improvement for 

Corette the cost of controls was not 

justified by the limited visibility 

improvement. 77 FR 24043. 

With regard to WEG’s claim that SCR 

would result in a visibility improvement 

of 264%, WEG used a fundamentally 

flawed approach to calculate visibility 

improvements. Using WEG’s approach, 

a 0.1 deciview change would produce a 

1000% improvement in visibility 

compared to a 0.01 deciview change. In 

fact, the change would be 0.09 deciview 

or about 1% relative to natural visibility 

conditions. The approach that WEG 

used to calculate percent visibility 

improvement is mathematically 

incorrect. WEG compared a 0.264 

deciview change to a zero deciview 

change and arbitrarily called this a 

264% improvement in visibility. To get 

a more accurate estimate, you can use 

the rule of thumb that 0.5 deciview is 

approximately equivalent to a 5% 

change in perceived visibility. The 

0.264 deciview change would be 

approximately a 2.6% improvement in 

visibility relative to natural visibility 

conditions. WEG makes the same 

mistake on page 3 in the comment on 

Colstrip where they state: ‘‘with the use 

of SCR, visibility improvements in the 

most impacted Class I areas would be 

around 50% greater than with the use of 

SNCR.’’ Here they compared 0.784 

deciview with SCR to 0.518 deciview 

with SNCR, and concluded that SCR 

provides a 50% visibility improvement 

over SNCR. Again, using the rule of 

thumb, this would be about a 2.6% 

difference in perceived visibility 

between SCR and SNCR relative to 

natural visibility conditions. 

The BART Guidelines state that to 

make the net visibility improvement 

determination you should, ‘‘assess the 

visibility improvement based on the 

modeled change in visibility impacts for 

the pre-control and post-control 

emission scenarios. You have flexibility 

to assess visibility improvements due to 

BART controls by one or more methods. 

You may consider the frequency, 

magnitude, and duration components of 

impairment.’’ 70 FR 39170. The BART 

Guidelines also state that, ‘‘Comparison 

thresholds can be used in a number of 

ways in evaluating visibility 

improvement (e.g. the number of days or 

hours that the threshold was exceeded, 

a single threshold for determining 

whether a change in impacts is 

significant, or a threshold representing 

an x percent change in improvement.’’ 

70 FR 39170. Our proposal shows the 

baseline visibility impact in deciviews, 

the visibility improvement in deciviews, 

the number of Class I areas impacted 

within 300 km, and fewer days 

impacted more than 0.5 deciview in 

Tables 123 and 124 and these are more 

appropriate metrics for evaluating 

visibility impact. 

We disagree with WEG’s statement 

that the FIP will fail to achieve 

meaningful reasonable progress in 

attaining natural visibility conditions in 

Class I areas in Montana and that given 

the prospect of such dismal progress in 

achieving natural visibility, it is 

reasonable to presume that any 

improvement in visibility, no matter 

how small, would be significant. We 

have explained in other responses that 

40 CFR 51.308(d)(1)(ii) states that, ‘‘if 

the State establishes a reasonable 

progress goal that provides for a slower 

rate of improvement in visibility that 

the rate that would be needed to attain 

natural conditions by 2064, the State 

must demonstrate, based on the factors 

in paragraph (d)(1)(i)(A) of this section, 

that the rate of progress for the 

implementation plan to attain natural 

conditions by 2064 is not reasonable; 

and that the progress goal adopted by 

the State is reasonable. The State must 

provide the public for review as part of 

its implementation plan an assessment 

of the number of years it would take to 

attain natural conditions if visibility 

improvement continues at the rate of 

progress selected by the State as 

reasonable.’’ We explained in other 

responses how we have met those 

requirements. 

I. Comments on Reasonable Progress 

and Long Term Strategy 

Comment: A commenter stated that 

based on the WRAP emissions inventory 

and air quality modeling, EPA proposed 

reasonable progress goals for the 20% 

worst visibility days for the Montana 

Class I areas that are significantly less 

(16–51%) than the uniform rate of 

progress by 2018 and that no Montana 

Class I area is projected to achieve 

natural visibility conditions by 2064. 

The commenter stated that EPA projects 

that, at best, the national goal will not 

be met for 135 years at Cabinet 

Mountains WA and, at worst, for 437 

years at the Medicine Lake WA. 

The commenter stated that the WRAP 

inventory indicates that point sources 

contribute 71% of Montana’s total SO2

emissions, yet point source SO2

emissions in Montana are projected to 

be reduced by less than 1% by 2018 

(this includes SO2 reductions for BART 

for Colstrip Units 1 and 2). This change 

in point source emissions inventory is 

considerably less than projected by 

other states in Region 8, yet EPA has 

determined that no additional SO2

controls are reasonable. The commenter 

stated that the WRAP inventory projects 

that point source NOX emissions would 

be reduced by 3% (23,000 tons per 

year), primarily due to estimated NOX

reductions at Colstrip and that EPA’s RP 

analyses determined that $282 per ton 

for NOX reduction at Devon Energy was 

cost effective, but NOX controls for all 


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other facilities were not cost effective. 

Several controls were below the cost of 

$4,659 for SO2 controls at Corette 

Generating Station that EPA determined 

were cost effective for BART. Given the 

lack of progress in improving visibility 

at the Class I areas, EPA needs to 

reconsider the cost effectiveness of 

point source SO2 and NOX controls. 

Response: We disagree that we should 

reconsider the cost effectiveness of 

point source controls given the lack of 

progress in improving visibility at the 

Class I areas. In determining the 

measures necessary to make reasonable 

progress and in selecting RPGs for 

mandatory Class I areas within 

Montana, we took into account the 

following four factors into 

consideration: costs of compliance; time 

necessary for compliance; energy and 

nonair quality environmental impacts of 

compliance; and remaining useful life of 

any potentially affected sources. CAA 

section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). In the FIP, we 

demonstrated how these four factors 

were considered. 40 CFR 51.308(d)(1)(ii) 

allows for a slower rate of improvement 

in visibility than the URP, as long as it 

is demonstrated that based on these four 

factors, it is not reasonable to achieve 

the URP and that the selected RPG is 

reasonable. CAA section 169A(g)(1) and 

40 CFR 51.308(d)(1)(i)(A). We respond 

to specific critiques of our four-factor 

analyses elsewhere. To the extent that 

the commenter is stating that costeffectiveness is a fixed value and must 

be the same whether a source is subject 

to BART or RP, we disagree. While the 

Regional Haze Rule may allow us to 

establish a bright line for some of the 

factors such as cost-effectiveness and 

visibility, we are not required to do so, 

and have not done so for this action. 

Comment: A commenter stated that 

oil and gas development has increased 

markedly in Montana and neighboring 

states since the initial inventory 

projections provided by the WRAP in 

2007 and that EPA should compare the 

most recent (Phase III) oil and gas 

emissions inventory to that used in the 

WRAP source apportionment modeling 

and discuss the implications of future 

oil and gas development for visibility at 

Montana Class I areas. 

Response: We disagree that we should 

reevaluate the oil and gas inventory and 

discuss the implications of future oil 

and gas development for visibility at 

Montana Class I areas at this time. 40 

CFR 51.308(d)(3)(iii) requires us to 

document the technical basis, including 

modeling, monitoring and emissions 

information on which we relied. It also 

requires that we identify the baseline 

emission inventory on which our 

strategies are based. As stated in the 

proposal, an emissions inventory for 

each pollutant was developed by WRAP 

for Montana and these inventories were 

used as inputs to photochemical 

modeling that was used to determine 

the 2018 reasonable progress goal. 77 FR 

24047 and 77 FR 24054. 40 CFR 

51.308(d)(3)(iii) allows us to rely on the 

technical analysis developed by the 

WRAP, which we have done. We 

recognize that emission inventories are 

dynamic, but at this time it is not 

necessary to reevaluate the emission 

inventories. The Regional Haze Rule 

recognizes the need for periodic 

progress evaluation and requires 

progress reports to be submitted every 

five years. 40 CFR 51.308(g)(4) requires 

this report to include, ‘‘[A]an analysis 

tracking the change over the past five 

years in emissions of pollutants 

contributing to visibility impairment 

from all sources and activities within 

the state.’’ As we explained in our 

proposal, we will update the statewide 

emissions inventories periodically or as 

necessary and review emissions 

information from other states and future 

emissions projections. 

Comment: MDEQ stated that EPA fails 

to consider the potential benefits of the 

Mercury Air Toxics Standard, the new 

NOX and SO2 NAAQS, the forthcoming 

Boiler MACT, and other rules that will 

significantly impact PM2.5, SO2 and NO2

emissions in its LTS. 

Response: We are sensitive to the 

challenges of coordinating compliance 

with a variety of rules. However, to the 

extent that MDEQ is implying that we 

should have considered the potential 

benefits of possible future regulations in 

our LTS, we disagree. As explained in 

our proposed FIP, in order to establish 

RPGs for the Class I areas in Montana 

and to determine the controls needed 

for the LTS, we followed the process 

established in the Regional Haze Rule. 

The anticipated visibility improvement 

in 2018 in all Montana Class I areas 

accounting for all existing enforceable 

federal and state regulations already in 

place was considered. 77 FR 24055. 

With regard to regulations that are not 

yet final, we cannot speculate on 

unknown reductions from anticipated 

future federal or state regulations prior 

to those actions completing the full 

regulatory process. None of the Montana 

sources have notified us that they will 

be reducing emissions as a result of 

future regulation and we have no basis 

for estimating what those emissions may 

be. Without an enforceable 

commitment, we cannot assume that 

additional reductions will be achieved 

and we cannot account for them in our 

LTS for the Regional Haze FIP. MDEQ 

has not provided information to indicate 

that anything in the Regional Haze FIP 

will interfere with the requirements of 

other regulations. In fact, where 

additional controls are required, we 

would expect that the lower emission 

limit would make it easier to comply 

with future regulations that also require 

lower emission limits. We note that the 

Regional Haze FIP requires compliance 

with a specific emission limit and not 

necessarily the installation of a specific 

control technology and that sources 

have a full five years after the 

finalization of the FIP to comply with 

any emission limit that would require 

the installation of additional control 

technology. 

Comment: MDEQ suggested that we 

include all smoke emissions from open 

burning and wildfires in the natural 

background estimates and recalculate 

URP and RPGs in each of the State’s 

Class I areas with these adjusted 

background levels. MDEQ perceived fire 

to be the major contributing factor to the 

State’s visibility impairment, and 

claimed that EPA does not make a 

realistic allowance for smoke 

contributions to haze in Montana. 

Response: We agree that industrial 

facilities are not the only causes of haze, 

but we disagree that we should make 

adjustments to the inventories, the URP, 

or the RPGs. Our action considered the 

many contributors to haze including 

industrial facilities. It is not appropriate 

to consider open burning as natural 

background because open burning is 

anthropogenic. In our proposal, the 

emissions inventory appropriately 

included natural (non-anthropogenic) 

wildfire and anthropogenic sources 

such as open burning. 77 FR 24093. In 

developing a LTS, 40 CFR 

51.308(d)(3)(iv) requires us to consider 

all anthropogenic sources. More 

specifically, 40 CFR 51.308(d)(3)(v)(E) 

requires the LTS to address smoke 

management techniques for agricultural 

and forestry management techniques. 

We note that our proposed action also 

proposed to approve the revisions to the 

paragraph titled ‘‘Smoke Management’’ 

of Title 17, Chapter 8, Subchapter 6, 

Open Burning as meeting the 

requirement in 40 CFR 308(d)(3)(v)(E) 

because the plan control emissions from 

these sources by requiring BACT and 

takes into consideration the visibility 

impacts on mandatory Class I areas. 

Regardless of the contribution from 

smoke emissions, 40 CFR 

51.308(d)(3)(iv) states, ‘‘The State must 

identify all anthropogenic sources of 

visibility impairment considered by the 

State in developing its long-term 

strategy. The State should consider 

major and minor stationary sources, 


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54 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency, September 2003. 

http://www.epa.gov/ttncaaa1/t1/memoranda/rhenvcurhr-gd.pdf, page 1–1 (Guidance for Estimating 

Natural visibility Conditions). The guidance states 

that, ‘‘Natural visibility conditions represent the 

long-term degree of visibility that is estimated to 

exist in a given mandatory Federal Class I area in 

the absence of human-caused impairment. It is 

recognized that natural visibility conditions are not 

constant, but rather they vary with changing natural 

processes (e.g., windblown dust, fire, volcanic 

activity, biogenic emissions). Specific natural 

events can lead to high short-term concentrations of 

particulate matter and its precursors. However, for 

the purpose of this guidance and implementation of 

the regional haze program, natural visibility 

conditions represents a long-term average condition 

analogous to the 5-year average best- and worst-day 

conditions that are tracked under the regional haze 

program.’’ 

55The preamble further stated that, ‘‘with each 

subsequent SIP revision, the estimates of natural 

conditions for each mandatory Federal Class I area 

may be reviewed and revised as appropriate as the 

technical basis for estimates of natural conditions 

improve.’’ 

56 Guidance for Estimating Natural Visibility 

Conditions, p.3–1 to 3–4. 

57 Guidance for Setting Reasonable Progress Goals 

Under the Regional Haze Program, U.S. 

Environmental Protection Agency, (‘‘Reasonable 

Progress Guidance’’) (June 1, 2007) p.4–2—4–3. 

mobile sources, and area sources.’’ In 

this case, we acted in the place of 

Montana and were required to abide by 

the same requirement to consider point 

sources. 40 CFR 51.308(d)(1)(ii) states 

that, ‘‘if the State establishes a 

reasonable progress goal that provides 

for a slower rate of improvement in 

visibility that the rate that would be 

needed to attain natural conditions by 

2064, the State must demonstrate, based 

on the factors in paragraph (d)(1)(i)(A) 

of this section, that the rate of progress 

for the implementation plan to attain 

natural conditions by 2064 is not 

reasonable; and that the progress goal 

adopted by the State is reasonable. The 

State must provide the public for review 

as part of its implementation plan an 

assessment of the number of years it 

would take to attain natural conditions 

if visibility improvement continues at 

the rate of progress selected by the State 

as reasonable.’’ In this case, we are 

acting in the place of Montana. In 

determining the measures necessary to 

make reasonable progress and in 

selecting RPGs for mandatory Class I 

areas within Montana, we evaluated 

major and minor point sources 

according to the four factors required by 

40 CFR 51.308 (d)(1)(i)(A) (costs of 

compliance; time necessary for 

compliance; energy and nonair quality 

environmental impacts of compliance; 

and remaining useful life of any 

potentially affected sources CAA section 

169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A)). In addition, 40 CFR 

51.308(e) requires states to make a 

BART determination for each BARTeligible source and in that 

determination, the state must consider 

the five statutory factors. 

The requirements of 40 CFR 

51.308(d)(3)(iv) and 40 CFR 51.308(e) 

are not dependent on the showing of a 

certain amount of impairment from 

point sources. 

EPA recognized that variability in 

natural sources of visibility impairment 

causes variability in natural haze levels 

as described in its ‘‘Guidance for 

Estimating Natural Visibility Conditions 

Under the Regional Haze Rule.’’ 54 The 

preamble to the BART Guidelines (70 

FR 39124) describes an approach used 

to measure progress toward natural 

visibility in Mandatory Class I areas that 

includes a URP toward natural 

conditions for the 20% worst days and 

no degradation of visibility on the 20% 

best days. The use of the 20% worst 

natural conditions days in the 

calculation of the URP takes into 

consideration visibility impairment 

from wild fires, windblown dust and 

other natural sources of haze.55 70 FR 

39124. The Guidance for Estimating 

Natural Visibility Conditions also 

discusses the use of the 20% best and 

worst estimates of natural visibility, 

provides for revisions to these estimates 

as better data becomes available, and 

discusses possible approaches for 

refining natural conditions estimates.56

For the evaluation of visibility 

impacts for BART sources, EPA 

recommended the use of the natural 

visibility baseline for the 20% best days 

for comparison to the ‘‘cause or 

contribute’’ applicability thresholds. 

This estimated baseline is reasonably 

conservative and consistent with the 

goal of attaining natural visibility 

conditions. While EPA recognizes that 

there are natural sources of haze, the use 

of the 20% worst natural visibility days 

is inappropriate for the ‘‘cause or 

contribute’’ applicability thresholds. For 

example, if BART source visibility 

impacts were evaluated in comparison 

to days with very poor natural visibility 

resulting from nearby wild fires or dust 

storms, the BART source impacts would 

be significantly reduced relative to these 

poor natural visibility conditions and 

would not be protective of natural 

visibility on the best 20% days. 

Comment: MDEQ insisted that 

visibility issues in the Western U.S. are 

less stationary source driven than in the 

Eastern U.S., and that greater 

understanding of this difference has 

developed since Congress passed the 

Visibility Protection Act of 1977 and the 

visibility statute of the CAA 

Amendments of 1990. 

Response: To the extent that MDEQ is 

implying that we are not required to 

analyze controls for stationary sources, 

we disagree. As explained in other 

responses, 40 CFR 51.308(d)(3)(iv) 

requires us to identify all anthropogenic 

sources of visibility impairment 

considered in developing our long term 

strategy. It specifically states that we 

should consider major and minor 

stationary sources, mobile sources, and 

area sources. Please see the language of 

40 CFR 51.308(e) in the response to the 

previous comment. The requirements of 

40 CFR 51.308(d)(3)(iv) and 40 CFR 

51.308(e) are not dependant on the 

showing of a certain amount of 

impairment from point sources. 

Comment: A commenter stated that 

BART sources such as Corette should 

also be considered under reasonable 

progress and that this would be 

consistent with actions EPA has 

approved in other SIPs. The commenter 

stated that EPA is using visibility 

improvement as measured by Q over D 

values as an indirect measure of the 

benefit of additional controls under 

reasonable progress and that it is their 

understanding that this is not supported 

under the Regional Haze Rule as 

reasonable progress decisions do not 

consider visibility improvement. The 

commenter requested that control 

options considered technologically 

feasible and cost effective under BART 

also be considered under reasonable 

progress. 

Response: We disagree that BART 

sources need to be re-evaluated for the 

purposes of reasonable progress and 

that, under the Regional Haze Rule, 

reasonable progress determinations may 

not consider visibility improvement. 

Our RP Guidance states, ‘‘Since the 

BART analysis is based, in part, on an 

assessment of many of the same factors 

that must be addressed in establishing 

the RPG, it is reasonable to conclude 

that any control requirements imposed 

in the BART determination also satisfy 

the RPG-related requirements for source 

review in the first RPG planning period. 

Hence you may conclude that no 

additional emissions controls are 

necessary for these sources in the first 

planning period.’’ 57 The EPA has 

concluded that, based on the similarity 

of many of the same factors for both 

BART and reasonable progress, that no 

additional emissions controls are 

necessary for BART sources for this 

planning period. The commenter has 

given us no basis to change that 

conclusion: Regardless of whether any 

states have chosen to reevaluate BART 

sources for reasonable progress, the 


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58Reasonable Progress Guidance, p.5–1. 

59Reasonable Progress Guidance, p. 4–2—4–3. 

60Reasonable Progress Guidance, p. 5–1. 

Regional Haze Rule does not require 

states to do so. With regard to the 

statement about using visibility 

improvement to evaluate additional 

controls under reasonable progress, 

EPA’s reasonable progress guidance 

states: ‘‘In determining reasonable 

progress, CAA section 169A(g)(1) 

requires States to take into 

consideration a number of factors. 

However, you have flexibility in how to 

take into consideration these statutory 

factors and any other factors that you 

have determined to be relevant.’’ 58 The 

potential reduction in quantity over 

distance (Q/D) is a factor that we 

consider to be relevant because the goal 

of the Regional Haze Rule is to improve 

visibility. The commenter has not cited 

any authority supporting the position 

that visibility improvements may not be 

considered in reasonable progress 

determinations and therefore has given 

us no basis to change our use of this 

factor. 

Comment: A commenter stated that 

the proposal fails to achieve reasonable 

progress. The commenter explained that 

the proposal will leave visibility in the 

parks and WAs that are affected by 

Montana sources impaired for hundreds 

of years into the future, nonetheless, we 

propose no additional emission 

reductions from Montana’s stationary 

sources. 

Response: We disagree that the FIP 

fails to achieve reasonable progress. 40 

CFR 51.308(d)(1)(ii) states: 

If the State establishes a reasonable 

progress goal that provides for a slower rate 

of improvement in visibility than the rate 

that would be needed to attain natural 

conditions by 2064, the State must 

demonstrate, based on the factors in 

paragraph (d)(1)(i)(A) of this section, that the 

rate of progress for the implementation plan 

to attain natural conditions by 2064 is not 

reasonable; and that the progress goal 

adopted by the State is reasonable. The State 

must provide the public for review as part of 

its implementation plan an assessment of the 

number of years it would take to attain 

natural conditions if visibility improvement 

continues at the rate of progress selected by 

the State as reasonable. 

In determining the measures 

necessary to make reasonable progress 

and in selecting RPGs for mandatory 

Class I areas within Montana, we took 

into account the following four factors 

into consideration: Costs of compliance; 

time necessary for compliance; energy 

and nonair quality environmental 

impacts of compliance; and remaining 

useful life of any potentially affected 

sources. CAA section 169A(g)(1) and 40 

CFR 51.308(d)(1)(i)(A). In the FIP, we 

demonstrated how these four factors 

were considered and we also provided, 

in Table 197, an assessment of the 

number of years it would take to attain 

natural conditions if visibility 

improvement continues at the rate of 

progress that we selected was 

reasonable. We respond to specific 

critiques of our four-factor analyses 

elsewhere. 

Comment: A commenter stated that 

EPA failed to evaluate controls on all 

BART-subject sources to meet 

reasonable progress requirements and 

that EPA stated that the BART analyses 

for these facilities are similar to the 

requisite reasonable progress analysis. 

77 FR at 24059. The commenter stated 

that EPA has ensured that Montana will 

not achieve reasonable progress toward 

natural visibility conditions at Class I 

areas affected by Colstrip and Corette 

and that EPA’s approach is flawed 

legally and factually. The commenter 

stated that EPA’s approach fails to 

distinguish between the purposes of 

BART and the long-term strategy under 

the Regional Haze Rule and that while 

both are mechanisms to help states 

achieve reasonable progress, BART is 

applied to a given source—for the 

purpose of eliminating or reducing 

visibility impairment caused or 

contributed to by that source. 42 U.S.C. 

section 7491(b)(2)(A). The commenter 

stated that rather than focusing on 

specific sources, the development of a 

long-term strategy requires EPA to look 

at existing visibility impairment—after 

emissions reductions due to BART and 

other strategies are accounted for—and 

attribute responsibility for eliminating 

that impairment among sources and 

categories. 40 CFR 51.308(d)(1). The 

commenter stated that in this way, the 

states and EPA maintain flexibility to 

determine the most effective and 

efficient way to eliminate haze pollution 

when technology mandates on specified 

sources have not done the job. The 

commenter stated that therefore, 

measures within a long-term strategy are 

required to achieve reasonable progress 

above and beyond BART and that by 

categorically eliminating all BARTsubject sources from its reasonable 

progress analysis, EPA has failed to 

meet its obligation to determine whether 

emissions reductions from these sources 

beyond those required by BART are 

necessary to achieve the national goal of 

eliminating visibility impairment. 

Response: We disagree that BART 

sources need to be re-evaluated for the 

purposes of reasonable progress. Our 

reasonable progress guidance states: 

Since the BART analysis is based, in part, 

on an assessment of many of the same factors 

that must be addressed in establishing the 

RPG, it is reasonable to conclude that any 

control requirements imposed in the BART 

determination also satisfy the RPG-related 

requirements for source review in the first 

RPG planning period. Hence you may 

conclude that no additional emissions 

controls are necessary for these sources in the 

first planning period.59

The commenter has given no reason 

for us to change this position. 

Comment: A commenter stated that 

EPA’s approach essentially duplicates 

all of the errors from its BART analysis 

in its reasonable progress analysis and 

that in particular, EPA’s incremental 

visibility justification for dismissing the 

most stringent pollution control 

technologies is especially inappropriate 

in the reasonable progress framework. 

The commenter stated that incremental 

visibility improvement is not included 

among the four factors to be considered 

in establishing reasonable progress 

measures. 40 CFR 51.308(d)(1)(i)(A). 

The commenter stated that if this 

justification is applied to eliminate the 

most effective pollution-reduction 

measures at every source—especially 

the largest and oldest sources that are 

subject to BART—then Montana may 

never make reasonable progress toward 

achieving natural visibility conditions. 

Response: We disagree that there are 

errors in our approach for BART and 

reasonable progress for the same reasons 

we have discussed previously. Pursuant 

to 40 CFR 51.308(e)(A) for our BART 

analyses, we considered the following 

five factors in our analysis: The 

appropriate level of BART control; the 

cost of compliance; the energy and 

nonair quality environmental impacts; 

any pollution control equipment in use 

at the source; the remaining useful life 

of the source; and the degree of 

improvement which may be reasonably 

anticipated to result from the use of 

such technology. We agree that visibility 

improvement is not one of the four 

factors required by CAA section 

169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A), however, it (along 

with other relevant factors) can be 

considered when determining controls 

that should be required for reasonable 

progress. Our reasonable progress 

guidance states: ‘‘In determining 

reasonable progress, CAA section 

169A(g)(1) requires States to take into 

consideration a number of factors. 

However, you have flexibility in how to 

take into consideration these statutory 

factors and any other factors that you 

have determined to be relevant.’’ 60 For 

certain potentially affected sources, we 

considered Q/D and potential 

reductions in Q/D, which are relevant to 


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the goal of the Regional Haze Rule, 

improving visibility. 

Comments: A commenter stated that 

EPA failed to require that Colstrip Units 

1 and 2 and Corette make emissions 

reductions that were relied upon by the 

WRAP, EPA, and states neighboring 

Montana in establishing reasonable 

progress goals, and that if EPA fails to 

revise its BART determinations for 

Colstrip Units 1 and 2 and Corette, EPA 

must require additional reductions of 

visibility-impairing pollutants in its 

long-term strategy. Another commenter 

stated that EPA should have required 

SCR+SOFA as BART for Colstrip Units 

1 and 2 and should have required 

SOFA+SCR and a dry scrubber/ 

baghouse for Corette, but even if EPA 

were to justify its contrary BART 

finding in response to these comments, 

EPA should have required SCR+SOFA 

and a dry scrubber/baghouse at these 

units as part of its long term strategy. 

The commenter explained that where 

sources within a state contributes to 

visibility within another state’s Class I 

area or areas, the state has an obligation 

to adopt controls necessary to ensure it 

achieves its share of the pollution 

reductions that are required to meet the 

reasonable progress goals set for the 

subject Class I area. 

Response: We do not agree that we 

must revise our BART determinations 

for Colstrip Units 1 and 2 and Corette. 

We have stated in other actions 

addressing regional haze that a plan that 

provides for emission reductions 

consistent with the assumptions 

underlying the WRAP modeling will 

ensure that a State is not interfering 

with measures designed to protect 

visibility in other states. See e.g. 76 FR 

491, 496–497 (Jan. 5, 2011). Similarly, a 

plan that is consistent with the 

assumptions underlying the modeling 

used to establish RPGs in a state likely 

will include the measures necessary to 

achieve those RPGs. However, there is 

no requirement that a SIP (or FIP) adopt 

the assumptions underlying the models 

as enforceable requirements. The air 

quality models used to support the 

regional haze SIPs are extremely 

complex, and due to the time 

consuming nature of performing the 

modeling, this work was performed 

early in the process. The emissions 

projections by the RPOs, relied upon in 

the air quality modeling, incorporated 

the best available information at the 

time from the states, and utilized the 

appropriate methods and models to 

provide a prediction of emissions from 

all source categories into the future. 

There was an inherent amount of 

uncertainty in the assumed emissions 

from all sources, including emissions 

from BART-eligible sources, as the final 

control decisions by all of the states 

were not yet complete. The WRAP used 

their best estimates of what regional 

haze SIPs would achieve as inputs for 

the modeling. In the end, reductions 

resulting from BART determinations 

based on the statutory factors may differ 

from those estimates. 

One relevant requirement cited by the 

commenter, at 40 CFR 51.308(d)(3)(ii), is 

that EPA must demonstrate that it has 

included all measures necessary to 

obtain its share of the emission 

reductions needed to meet the RPGs for 

Class I areas where it causes or 

contributes to impairment. Montana’s 

neighboring Class I states originally set 

the reasonable progress goals in their 

SIP based on emission reductions 

expected to be achieved through 

application of presumptive BART and 

other emission reductions qualified for 

that purpose. These neighboring states 

had the opportunity to comment on the 

regional haze FIP, and did not ask for 

additional emission reductions. We also 

note that the RPGs are not enforceable 

goals. Neighboring states will have the 

responsibility to consider whether other 

reasonable control measures are 

appropriate to ensure reasonable 

progress during subsequent periodic 

progress reports and regional haze SIP 

revisions as required by 40 CFR 

51.308(f)–(h), and may at that time 

consider asking EPA for additional 

emission reductions. 

With respect to Colstrip Units 1 and 

2, we note that our FIP achieves SO2

emissions reductions well beyond those 

assumed in the WRAP PRP18b 

emissions inventory. Specifically, at 

Units 1 and 2, assuming operation at 

85% of capacity, our FIP achieves 

reductions of 7,538 tpy of SO2, which is 

1,504 tpy better than indicated by the 

PRP18b projections. By way of 

comparison, again assuming operation 

at 85% of capacity, our FIP achieves 

reductions of 6,652 tpy of NOX for 

Colstrip Units 1 and 2, which is 1,709 

tpy below that indicated by the PRP18b 

projections. Because the additional SO2

reductions are close to the shortfall in 

NOX reductions at Colstrip Units 1 and 

2, and as SO2 may have a greater impact 

than NOX on visibility in Montana, we 

find that the overall emissions 

reductions achieved at Colstrip Units 1 

and 2 will result in similar visibility 

improvement to the emissions 

reductions assumed in the WRAP 

PRP18b projections. 

With respect to Corette, the 

commenter has overstated the 

discrepancy between the emissions 

associated with our BART 

determination and the PRP18b 

projections, because the commenter has 

compared WRAP projections based on 

annual emissions with emissions limits 

that are on a 30-day rolling average. In 

addition, we note that we have revised 

the NOX and SO2 emission limits for 

Corette in our FIP to be somewhat more 

stringent than what we proposed (and 

more reflective of actual emissions with 

existing controls). Finally, the WRAP 

projections do not reflect application of 

SOFA+SCR or a dry scrubber/baghouse 

to Corette. Therefore, the projections do 

not support the commenter’s position 

that these controls are required. 

Moreover, there are NOX reductions at 

other BART sources that are greater than 

assumed by WRAP. At Ash Grove and 

Holcim, the total reductions from our 

FIP are significantly more relative to the 

PRP18b projections that the WRAP 

used. In conclusion, our FIP contains 

additional emission reductions at BART 

sources that largely offset any shortfall 

at Colstrip Units 1 and 2 and Corette. 

Comment: A commenter stated that 

our reasonable progress goals are 

unreasonable, unsupported, and 

effectively contrary to the CAA’s 

requirements that we assure reasonable 

progress in achieving natural visibility 

conditions in Class I areas. The 

commenter stated that the proposed 

RPGs, at a minimum, double the 

timeframe required to achieve natural 

visibility conditions for every Class I 

area in Montana and that this is not 

reasonable. The commenter also stated 

that the reasonable progress goals are 

unreasonable based on the statutory 

factors that must be considered by EPA 

under 42 U.S.C. 7491(g)(1), and that we 

provided two reasons for asserting that 

the reasonable progress goals are 

reasonable: That our four factor analyses 

resulted in limited opportunities for 

reasonable progress controls for point 

sources and that significant visibility 

impairment is caused by nonanthropogenic sources in and outside 

Montana. The commenter stated that 

with regard to the latter issue of nonanthropogenic sources in and outside of 

Montana, this is not a statutory factor 

that EPA is allowed to consider in 

establishing RPGs. 

Response: We disagree. It is not 

necessarily unreasonable for the RPGs to 

reflect a longer period of time than the 

URP. The URP is simply calculated by 

dividing the difference between the 

present visibility conditions and natural 

visibility conditions by the number of 

years between the baseline and 2064. It 

assumes a steady rate of progress and 

does not take into account the four 

statutory factors for determining 

reasonable progress or any additional 

factors that warrant consideration. As a 


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61Reasonable Progress Guidance, p. 5–1. 62Reasonable Progress Guidance, p.5–1. 

result, the RPGs, which do reflect 

consideration of these factors, may well 

vary from the URP. 

In determining reasonable progress 

controls, EPA did consider the statutory 

factors for determining reasonable 

progress set out in 42 U.S.C. 7491(g)(1). 

To the extent that the commenter argues 

with our evaluation of these factors, we 

respond to specific comments on our 

evaluation of these factors elsewhere. 

The commenter is correct that 

consideration of non-anthropogenic 

sources in and outside of Montana is not 

one of the statutory four factors that 

must be considered under 42 U.S.C. 

7491(g)(1). However, EPA’s reasonable 

progress guidance states: ‘‘In 

determining reasonable progress, CAA 

section 169A(g)(1) requires States to 

take into consideration a number of 

factors. However, you have flexibility in 

how to take into consideration these 

statutory factors and any other factors 

that you have determined to be 

relevant.’’ 61 The data demonstrating 

that significant visibility impairment is 

caused by non-anthropogenic sources in 

and outside Montana is relevant because 

it diminishes the potential improvement 

that might be realized through 

controlling an individual point source 

within Montana. Therefore, it was 

proper for EPA to consider this 

additional factor. 

Comment: A commenter stated that 

based on the four factors set forth under 

the CAA, it appears that EPA grossly 

overstated its assertion that there are 

only limited opportunities for 

reasonable controls for point sources. 

The commenter stated that this is 

particularly the case with regard to NOX

emissions from coal-fired EGUs in 

Montana. The commenter stated that 

our proposal disclosed that for every 

coal-fired EGU assessed under the fourfactor analysis for determining RPGs, 

including Colstrip units 3 and 4, 

Colstrip Energy, and the Lewis and 

Clark Station, that cost-effective SCR 

control technology could achieve greater 

NOX emissions reductions and greater 

visibility improvements than under our 

FIP. The commenter stated that despite 

this, we rejected SCR as a control option 

and ultimately adopted no NOX

emission controls for these four sources. 

The commenter stated that we also 

rejected SCR as BART for Colstrip Units 

1 and 2 and the Corette coal-fired EGUs, 

even though we found SCR to be a costeffective and reasonable technology, we 

rejected it in favor of weaker controls. 

The commenter concluded that we did 

not show that any of the four factors 

would mitigate against additional 

control and stronger RPGs. The 

commenter stated that our assertion that 

there would be no degradation is not 

reasonable or legally justified and that 

we must establish our reasonable 

progress goals based on all coal-fired 

EGUs using SCR to reduce NOX

emissions. 

Response: We disagree that the four 

factor analyses for EGUs that are 

potentially affected reasonable progress 

sources mandate the addition of SCR 

and that visibility, although not one of 

the four statutory factors that are 

required to be considered, cannot be 

considered in determining appropriate 

controls under reasonable progress. 

EPA’s reasonable progress guidance 

states: ‘‘In determining reasonable 

progress, CAA section 169A(g)(1) 

requires States to take into 

consideration a number of factors. 

However, you have flexibility in how to 

take into consideration these statutory 

factors and any other factors that you 

have determined to be relevant.’’ 62 For 

example, the potential reduction in Q/ 

D is a factor that we consider to be 

relevant because the goal of the Regional 

Haze Rule is to improve visibility at 

Class I areas. We note that the 

commenter, in citing potential visibility 

improvement at the facilities 

mentioned, undercuts their own 

argument that the four statutory RP 

factors by themselves, without 

consideration of other factors, 

demonstrate that EPA ‘‘grossly 

overstated’’ its conclusion that there are 

only limited opportunities for 

reasonable controls for point sources. 

Commenter misstated EPA’s 

conclusions by stating that EPA ‘‘found 

SCR to be a cost-effective and 

reasonable technology’’ for the BART 

EGUs. While we did state that the cost 

on a dollars per ton basis was costeffective, we also explained that the cost 

of SOFA + SCR was not justified by the 

visibility improvement. 77 FR 24027, 77 

FR 24035, and 77 FR 24043. The 

commenter misstated the requirements 

of the Regional Haze Rule. In examining 

potentially affected sources for possible 

controls and setting RPGs, EPA is not 

required to ‘‘show that any of the four 

factors would mitigate against 

additional controls and stronger 

reasonable progress goals.’’ Instead, EPA 

is required to consider the four statutory 

reasonable progress factors. In addition, 

EPA may consider additional, relevant 

factors such as visibility improvement 

from controls. To the extent that the 

comment argues with our 

determinations for particular potentially 

affected sources, we respond to specific 

criticisms elsewhere. With regard to 

commenter’s statement that our basis for 

determining there would be no 

degradation on the least impaired days 

was unreasonable and not legally 

justified, we note that the commenter 

did not identify any flaw in our data or 

methodology in deriving Table 198 in 

the proposal. We therefore disagree with 

the statement. 

Comment: PPL commented that to try 

to address visibility impairment only 

within the universe of point sources 

subject to potential EPA regulation 

within the United States is not 

reasonable and will not lead to 

achievement of Reasonable Progress 

Goals (RPGs). PPL stated further that 

EPA, in conjunction with other federal 

and state agencies and the FLMs, should 

re-evaluate some of the conclusions as 

to the uncontrollable nature of several 

listed significant contributors of SO2

and NOX. PPL stated that application of 

the BART analysis excludes 

consideration of a number of factors, 

including outside domain sources. PPL 

pointed out that the RPGs in the 

proposed FIP do not take into account 

the contribution of international 

emissions to the visibility, and do not 

address challenges faced by the state of 

Montana. 

Response: To the extent that PPL 

commented that we are addressing 

visibility impairment only within the 

universe of point sources subject to 

potential EPA regulation within the 

United States, that we did not consider 

other sources of emissions, we disagree. 

As explained elsewhere, our action 

considered the many contributors to 

haze including all anthropogenic 

sources as required by 40 CFR 

51.308(d)(3)(iv) and smoke management 

techniques for agricultural and forestry 

management techniques as required by 

40 CFR 51.308(d)(3)(v)(E). In our 

proposal, the emissions inventory 

appropriately included natural (nonanthropogenic) wildfire and 

anthropogenic sources such as open 

burning and international emissions. 

We proposed approve the revisions to 

the smoke management section of 

Montana’s Visibility SIP as meeting the 

requirement in 40 CFR 308(d)(3)(v)(E). 

Comment: The NPS commented that 

EPA used inconsistent criteria in 

selecting reasonable progress controls. 

Response: We disagree. As explained 

in other responses, in determining the 

measures necessary to make reasonable 

progress and in selecting RPGs for 

mandatory Class I areas within 

Montana, we took the following four 

factors into consideration: costs of 

compliance; time necessary for 

compliance; energy and nonair quality 


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environmental impacts of compliance; 

and remaining useful life of any 

potentially affected sources. CAA 

section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). As also explained in 

other responses, we also considered 

potential visibility improvement in a 

general sense by considering the 

potential reduction in haze causing 

pollutants and also the distance from 

the source to the nearest Class I area. 

For Colstrip 3 and 4, we also considered 

visibility modeling results and have 

explained the reasoning for that 

decision in another response. 

J. Comments on Colstrip Units 3 and 4 

Comment: Some commenters agreed 

with EPA’s conclusion not to require 

additional emissions controls at Colstrip 

Units 3 and 4. Commenters asserted 

that, given the aggressive pollution 

control technologies already in place, 

EPA properly concluded that additional 

controls for Reasonable Progress are not 

appropriate. 

Response: We acknowledge the 

commenters’ support for our decision 

not to require additional emission 

controls on Colstrip Units 3 and 4 in 

this planning period. Whether 

additional emission reductions from 

reasonable progress sources, including 

Colstrip Units 3 and 4, are necessary 

will be re-evaluated in subsequent 

planning periods. 

Comment: Various commenters stated 

that we underestimated the costs of 

SNCR for Colstrip Units 3 and 4. 

Response: We disagree that we 

underestimated the costs of SNCR for 

Colstrip Unit 3 and 4. For a further 

explanation, see our response to similar 

comments made in relation to SNCR 

costs for Colstrip Unit 1 and 2. 

Comment: Commenters stated that 

they disagree with EPA’s cost analysis 

for NOX control technologies for 

Colstrip Units 3 and 4. In particular, 

commenters stated that we 

underestimated the capital costs and 

cost-effectiveness of these controls. 

Commenters referenced cost estimates 

submitted by PPL in September 2011 

and February 2012, which show much 

higher capital costs and costeffectiveness than those estimated by 

EPA. 

Response: We disagree. We have 

rejected PPL’s cost estimates for NOX

control options for Colstrip Units 3 and 

4 for the same reasons that we rejected 

them for Colstrip Units 1 and 2. See 

previous responses to comments. 

Comment: NPS stated that EPA 

modeled baseline visibility impacts at 

five Class I areas from Colstrip Units 3 

& 4 using 2008–2010 emissions, while 

PPL modeled visibility impacts using 

2001–2003 emissions. NPS agreed with 

the PPL modeling approach because it is 

consistent with EPA guidance to use the 

2001–2003 pre-control emissions. 

Response: See our response to a 

similar comment made in regard to the 

baseline emissions used for Colstrip 

Units 1 and 2. 

Comment: NPS stated that after EPA 

concluded its statutory four-factor 

analysis of Colstrip 3 and 4, it created 

a new, ‘‘Optional Factor: Modeled 

Visibility Impacts’’ fifth factor, only for 

Colstrip 3 & 4. NPS further stated that 

this ‘‘optional’’ fifth factor is not 

required by statute or regulation, and 

that EPA only used it on one reasonable 

progress source (2 units) and did not 

explain what criteria it used to evaluate 

it. 

Response: As we explained 

elsewhere, our RP Guidance allows for 

consideration of additional factors such 

as visibility impacts or benefits. Given 

the large annual emissions of NOX and 

SO2 from Colstrip Units 3 and 4 

compared to other reasonable progress 

sources, we found that it was reasonable 

to model the visibility benefits and 

consider them when evaluating 

controls. 

Comment: NPS stated that EPA has 

not provided criteria used in making the 

determination of what ‘‘Costs of 

Compliance’’ are reasonable, and its 

determinations vary significantly across 

Montana facilities. 

Response: As we have explained 

elsewhere, while the Regional Haze 

Rule and BART Guidelines allow states 

to establish thresholds for costeffectiveness, we are not required to do 

so and have not done so for this action. 

Also, our Reasonable Progress 

determinations were made based not 

just on the cost of compliance, but with 

consideration of the four factors along 

with additional information that was 

pertinent. 

Comment: EarthJustice stated that 

EPA must set NOX emission limits for 

Colstrip Units 3 and 4 based on SCR to 

help achieve reasonable progress. 

EarthJustice stated that EPA’s analysis is 

skewed to underestimate the benefits of 

SCR, both in terms of control 

effectiveness and visibility 

improvement, and overestimates the 

costs. EarthJustice made claims 

regarding our cost analysis for Colstrip 

Units 3 and 4 that were very similar to 

the claims they made regarding Colstrip 

Units 1 and 2. 

Response: We disagree. Below we 

address each of EarthJustice’s arguments 

that support their assertion that SCR 

must be required for Colstrip Units 3 

and 4. 

Comment: EarthJustice stated that 

EPA underestimated the control 

effectiveness of SCR. 

Response: See our response to similar 

comment made by EarthJustice in regard 

to Colstrip Units 1 and 2. 

Comment: EarthJustice stated that 

EPA overestimated the cost of SCR. 

Response: See our response to similar 

comment made by EarthJustice in regard 

to Colstrip Units 1 and 2. 

Comment: EarthJustice claimed that 

the visibility benefit of SCR on Units 3 

and 4 is substantial and therefore SCR 

should be required. EarthJustice noted 

that EPA modeled visibility benefits of 

SNCR and SCR and found a visibility 

benefit of 0.273 dv per unit from 

application of SCR. EarthJustice stated 

that application of SCR at both units 

would approximately halve the units’ 

emissions of visibility impairing 

pollutants and would reduce the 

number of days of visibility impairment 

at Theodore Roosevelt NP to just 2 days 

and would eliminate visibility 

impairment caused by Units 3 and 4 at 

four other Class I areas. EarthJustice 

stated that, in light of this, we lacked a 

basis for our determination to not 

impose SCR at Colstrip Units 3 and 4. 

EarthJustice noted that, in North Dakota, 

we imposed LNB on two units at 

Antelope Valley Station based on a 

combined visibility benefit of 0.39 

deciview, which we stated was 

significant even on a unit-by-unit basis 

of 0.2 deciview. 

Response: We disagree that SCR 

should be required based solely on the 

modeled visibility benefits. As we 

explained in our proposal, we 

considered the four factors and the 

modeled visibility benefits of controls 

and determined that no additional 

controls should be required for this 

planning period. 77 FR 24066. Also, we 

stated that specifically, for SCR, the 

modeled visibility benefits (0.273 

deciview and 0.260 deciview) were not 

sufficient for us to consider it 

reasonable to impose SCR in this 

planning period. 77 FR 24066. In 

making this determination, we noted 

that SCR was the more expensive option 

($4,574/ton at Unit 3 and $4,607/ton at 

Unit 4). The cost of compliance is one 

of the four statutory factors, and 

EarthJustice has not provided a reason 

why it should be ignored. For the same 

reason, we reject the comparison with 

our North Dakota action. There, the 

cost-effectiveness of LNB at Antelope 

Valley Station was $586/ton for Unit 1 

and $661/ton at Unit 2. 76 FR 58631. 

We explicitly considered these costs in 

making our determination to impose 

LNB. Here, the cost-effectiveness of SCR 

at Colstrip Units 3 and 4 is far above the 


tkelley on DSK3SPTVN1PROD with RULES3
Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57903 

63See EIA Form 860 data. 

64Email from Bob Roden, Carmeuse, to Jim 

Staudt, Andover Technologies, July 31, 2012. 

65Sargent & Lundy, ‘‘IPM Model—Revisions to 

Cost and Performance for APC Technologies, SDA 

FGD Cost Development Methodology FINAL’’, 

Prepared for US EPA, August 2010 see table 2. 66Reasonable Progress Guidance, p. 5–1. 

cost-effectiveness of LNB at Antelope 

Valley Units 1 and 2. Thus, the 

comparison gives us no basis to change 

our determination that SCR should not 

be required in this planning period. 

Comment: EarthJustice stated that 

EPA should set more stringent SO2

emission limits at Colstrip Units 3 and 

4 to help achieve reasonable progress. 

EarthJustice stated that EPA incorrectly 

found that no additional upgrades are 

feasible and that 98% SO2 removal to 

meet an SO2 emission limit of 0.05 lb/ 

MMBtu at Units 3 and 4, which is 

readily achievable at little expense 

using MEL. 

Response: EarthJustice cites a 1984 

paper presented at the American Power 

Conference to support their argument of 

a lower emission rate. Colstrip 3 had 

only started operation in 1984 and 

Colstrip 4 did not commence operation 

until 1986,63 the data cited by 

EarthJustice cannot be more than shortterm tests of Unit 3 that are not 

representative of longer term 

performance. Annual emissions from 

1985 and 1990 emissions from CAMD 

can be found in the docket. At the time 

these scrubbers were built, wet MEL 

scrubbers and wet caustic scrubbers 

were the only scrubbers that could 

deliver high capture rates (over 90%) 

with reasonable reliability. Scrubber 

technology has improved and other, less 

expensive, reagents are now preferred. 

Although Colstrip Units 3 & 4 used MEL 

in the past, MEL is not readily available 

in the region near the Colstrip plant. 

MEL is produced from a blending of 

dolomitic lime with high calcium lime 

to achieve a lime with a magnesium 

content of 3–6% or so. The lime is 

produced by calcination of limestone. 

Dolomitic limestone is limestone with a 

significant amount of dolomite, or 

calcium magnesium carbonate. Because 

there are no dolomitic limestone 

deposits near the Colstrip plant, the 

dolomitic lime must be sourced from 

remote locations. This increases the cost 

of the lime (that is made from the 

dolomitic limestone). According to 

Carmeuse, a supplier of MEL, the closest 

source of dolomitic lime is 1,000 miles 

away from the Colstrip plant and 

transportation would cost $0.12 per 

mile per short ton plus a 24% fuel 

surcharge to transport,64 or close to 

$150/short ton just for transportation of 

the reagent. Because the lime would be 

blended in closer to the plant with high 

calcium lime at perhaps an 8:1 ratio 

(reducing magnesium content from 

about 40% to about 4–5% this would 

result in an increased reagent cost of 

$15–$20 per ton. Assuming a highcalcium lime cost of about $95/ton,65

this raises the cost of reagent by close 

to 20% assuming constant reduction. 

Reagent use might be improved 

somewhat for a given reduction level, 

but considering this is a unique 

scrubber design, it is difficult to assess 

what the impact may be. Regardless, 

reliance on a reagent source that is 1,000 

miles away may cause operating risks 

during the winter months if delivery 

was interrupted. 

We also note that EarthJustice did not 

provide site-specific cost information, 

for us to evaluate MEL. The cost of 

compliance is one of the factors 

required to be considered by CAA 

section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). Based on all four 

factors, we continue to find that the 

level of performance of the current SO2

removal system for Colstrip Units 3 and 

4 is satisfactory for this planning cycle. 

We will re-evaluate additional SO2

controls for Colstrip Units 3 and 4 in the 

next planning cycle. 

Comment: PPL stated that EPA 

properly concluded that RPGs do not 

require additional emissions controls on 

Colstrip Units 3 and 4 and that existing 

emissions controls at Units 3 and 4 

already limit emissions to levels below 

the presumptive BART limit. PPL stated 

that EPA’s RP conclusion should not be 

affected by EPA’s ultimate 

determination with respect to BART 

requirements for Colstrip Units 1 and 2 

and that no further controls are 

warranted based on conclusions 

regarding the extent of existing 

emissions controls and the costineffectiveness of further controls. 

Response: PPL did not provide 

specific information for us to consider 

in making a change to our FIP. In any 

case, we have not required additional 

controls for Colstrip Units 3 and 4 in 

our final FIP. 

K. Comments on Devon Energy 

Comment: MDEQ stated that we failed 

to provide information or analysis of 

any visibility benefit that would result 

from the application of NSCR for Devon 

Energy. MDEQ suggested that we must 

consider visibility benefits as part of the 

Devon Energy reasonable progress 

analysis, as the BART Guidelines 

include evaluation of visibility impacts 

‘‘which would also appear to be 

required under the reasonable progress 

guidelines.’’ 

Response: The four reasonable 

progress factors are the costs of 

compliance, the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, and the remaining useful 

life of any potentially affected sources 

CAA section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). Our Reasonable 

Progress Guidance states: ‘‘In 

determining reasonable progress, CAA 

section 169A(g)(1) requires States to 

take into consideration a number of 

factors. However, you have flexibility in 

how to take into consideration these 

statutory factors and any other factors 

that you have determined to be 

relevant.’’ 66 As stated in our proposal at 

77 FR 24069, for Devon, we considered 

Q/D and potential reductions in Q/D, 

which are relevant to the goal of the 

Regional Haze Rule, improving 

visibility. 

Comment: MDEQ commented that 

EPA should review the NOX limit for 

Devon with respect to its averaging time 

and compliance determining method for 

practical enforceability. 

Response: In the final FIP, we have 

made changes to the language in 40 CFR 

52.1396 to clarify the requirements for 

Devon Energy. 

L. Comments on Montana-Dakota 

Utilities 

Comment: Montana-Dakota Utilities 

(MDU) commented that the company 

did not disagree with our Reasonable 

Progress determination. MDU stated 

that, for EPA’s reference, paragraph 3 on 

page 1 of the Sargent & Lundy IPM 

model method document cautions as 

follows with respect to the application 

of the model to smaller units: 

The costs for retrofitting a plant smaller 

than 100 MW increase rapidly due to the 

economy of size. The older units which 

comprise a large proportion of the plants in 

this range generally have more compact sites 

with very short flue gas ducts running from 

the boiler house to the chimney. Because of 

the limited space, the SCR reactor and new 

duct work can be expensive to design and 

install. Additionally, the plants might not 

have enough margins in the fans to overcome 

the pressure drop due to the duct work 

configuration and SCR reactor and therefore 

new fans may be required. 

MDU stated that Lewis & Clark 

Station is a small, 52 MW net capacity 

unit. In addition, MDU believes that the 

fan margin is not present at Lewis & 

Clark Unit 1 to overcome the pressure 

drop as discussed in the Sargent & 

Lundy guidance. 

Response: MDU has not provided the 

information that would be necessary for 


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us to determine whether or not to agree 

with the implied point of this comment, 

which seems to be that EPA 

underestimated the cost of SCR. First, 

MDU has not indicated whether there 

are, in fact, space limitations at Lewis & 

Clark Station that would cause 

installation of an SCR reactor and 

associated ductwork to be more 

expensive than the cost estimate in our 

analysis. Second, MDU has not 

indicated whether the additional 

pressure drop from installation of SCR 

at Lewis & Clark Station would, in fact, 

require installation of new fans, and if 

so, whether or not our cost analysis 

failed to factor in the cost of new fans. 

Comment: MDU indicated that EPA 

uses a Retrofit Factor value of 1 for 

Lewis & Clark Station Unit 1 in the IPM 

Model calculation (factor B in the EPA 

cost sheets) which indicates an average 

retrofit cost, however, a higher value 

would be expected for Lewis & Clark 

since it is a small facility (as discussed/ 

cautioned above by Sargent & Lundy) 

and could be difficult to retrofit. A more 

appropriate value between 1.3 and 2.0 is 

therefore recommended. 

Response: We disagree. MDU has not 

provided any data or information to 

substantiate that a retrofit factor other 

than 1 is warranted for Lewis & Clark 

Station. The IPM capital cost 

calculations for retrofits already account 

for unit size. We note that capital cost 

does not vary linearly with size in IPM. 

Instead, in the capital cost formula in 

IPM, the cost varies exponentially with 

unit size (a least squares fit). The IPM 

document states, ‘‘The least squares 

curve fit was based upon an average of 

the SCR retrofit projects.’’ IPM Model— 

Revisions to Cost and Performance for 

APC Technologies, SCR Cost 

Development Methodology, Final, 

Sargent & Lundy, August 2010, Chapter 

5, Appendix 5–2A, page 4–5. 

We also disagree with the statement 

that a more appropriate retrofit factor 

should be 1.3 to 2.0. The 

aforementioned IPM document states 

that, ‘‘Retrofit difficulties associated 

with an SCR may result in capital cost 

increases of 30 to 50% over the base 

model.’’ Therefore, the highest retrofit 

factor that might be considered would 

be 1.5. 

This comment has not resulted in any 

change to our FIP proposal or to our cost 

calculations for SCR. 

Comment: MDU stated that the model 

‘‘Type of Coal’’ input indicates ‘‘PRB’’, 

but should be ‘‘Lig,’’ since Lewis & 

Clark burns lignite coal. That stated, the 

‘‘Coal Factor’’ value in the cell below 

‘‘Type of Coal’’ indicates lignite coal 

was actually considered. As such, this 

recommendation is clerical in nature. 

Response: As shown in the ‘‘Given/ 

Assumptions’’ spreadsheet in our SCR 

cost analysis, we used a heating value 

of 6,714 Btu/lb, which we considered to 

be representative of lignite coal. PRB 

coal would have a much higher heating 

value. 

Comment: MDU stated that EPA used 

a NOX input emission rate to the SCR 

of 0.26 lb/MMBtu, which is the low load 

emissions rate of low NOX burners 

(LNB) and Separated Overfire Air 

(SOFA) that MDU estimated in Table 

C.2–1 of Appendix C.2 of the Emissions 

Control Analysis for Lewis & Clark 

Station Unit 1. The 0.25 lb/MMBtu for 

LNB/SOFA at high load is a more 

appropriate rate to use as the inlet to an 

SCR. While this does not result in a 

significant change to the overall 

conclusions in the report, it is 

nonetheless important because the EPAderived cost was based on full load 

operation, as opposed to lower load. 

Response: We disagree with the 

statement that we obtained the emission 

rate of 0.26 lb/MMBtu from the low-load 

scenario presented in Table C.2–1 of 

Appendix C.2 of MDU’s Emissions 

Control Analysis. Instead, as indicated 

in the ‘‘Given/Assumptions’’ 

spreadsheet of our SCR cost analysis, we 

obtained the rate of 0.26 lb/MMBtu from 

Table C.2–6 of MDU’s analysis. Table 

C.2–6 is not identified by MDU as a lowload scenario. 

Comment: MDU stated that, from the 

IPM model guidance, EPA did not 

include factors N through V in the 

model calculations for operating costs 

for Lewis & Clark Station’s evaluations. 

Although factors N through R and T 

through V are utility costs that were not 

needed in EPA’s evaluation, the catalyst 

cost (factor S) was applied based on an 

alternative source. EPA references 

‘‘Cichanowicz (Jan 2010)’’ with a cost of 

$170/ft3 as compared to the IPM value 

of $8,000/m3 ($226.53/ft3 in 2009$) and 

MDU’s value of $214.29/ft3. MDU 

recognized that a range of potential 

costs exist, and believes that either the 

IPM value or the value MDU provided 

would be more appropriate for EPA to 

use since they are based on industry and 

vendor data respectively and are 

expected to represent a more site 

specific value as opposed to a literature 

based value. 

Response: We disagree. The 

Cichanowicz document we used 

provided actual catalyst costs observed 

over time. It demonstrates that catalyst 

costs continue to decline. In fact, based 

on the trend displayed in the graph on 

page 6–6 of the document, it is likely 

that catalyst costs in upcoming years 

will be even lower than the $6,000/m3

assumed in our FIP proposal. Current 

Capital Cost and Cost-Effectiveness of 

Power Plant Emissions Control 

Technologies, J. Edward Cichanowicz, 

Prepared for Utility Air Regulatory 

Group, January 2010, page 6–6, Figure 

6–6. This comment has not resulted in 

any change to our FIP proposal or to our 

cost calculations for SCR. 

Comment: Similarly, to item e above, 

MDU noted that the cost EPA associated 

with aqueous ammonia ($0.12/lb) is 

lower than the cost MDU estimated of 

$0.70/lb. MDU recognized that a range 

of ammonia costs exists, that the price 

of ammonia fluctuates over time, and 

that the price is related to natural gas 

prices. As such, if SCR were to be 

considered in the future, MDU would 

ask that site specific, local, as delivered 

cost be evaluated at that time. 

Response: We disagree. In its own 

SCR cost spreadsheet, MDU did not 

indicate the basis for its estimate of 

$0.70/lb. We used $0.12/lb based on 

data provided to us by control 

technology vendors on cost of aqueous 

ammonia. This comment has not 

resulted in any change to our FIP 

proposal or to our cost calculations for 

SCR. 

Comment: MDU stated that, through 

the FR correction, EPA changed the 

language on 77 FR 24071 to state that an 

85% control efficiency was used instead 

of the initially quoted 95% control 

efficiency for SDA and baghouse. MDU 

believes this correction was in error. 

Table 172 in the FR lists the control 

efficiency as 85% for SDA and baghouse 

and this value should be corrected to 

95% control efficiency for SDA and 

baghouse as the textual representation 

in the FR was correct. 

Response: We disagree. We made the 

correction from 95% to 85% because 

MDU’s Emissions Control Analysis 

dated June 2011, at Table 1 on page 14, 

shows an expected SO2 emission 

reduction of 850.3 tons per year, for 

SDA with baghouse. The baseline SO2

emissions listed in the table are 1,002.1 

tons per year. This amount of reduction 

represents 85% control efficiency. We 

presented these figures at 77 FR 24071, 

Table 172. MDU later wrote to us on 

February 10, 2012, to say that 70–90% 

control is the generally anticipated 

range of SO2 control for this control 

option, and that 95% control was also 

assumed and represented a screening 

level assumption for a high degree of 

SO2 control. In its February 10, 2012 

submittal, MDU did not indicate that 

Table 1 of their June 2011 submittal 

should be revised, so we used the 

figures presented in MDU’s Table 1. 

Comment: In Table 172 of the 

proposed FIP (77 FR 24071), EPA 

provides a 10% control effectiveness for 


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67Commenter’s speculation that the existing 

pipeline could be upgraded does not provide 

sufficient basis for us to supplant MDU’s estimated 

cost for a new pipeline with some other cost. We 

note that, even if the upgrade were feasible and had 

zero cost, the cost effectiveness of the SO2

reductions would still be well over $4,000/ton. 

both DSI with baghouse and existing 

scrubber mod; however, MDU stated 

that this value should be changed to 

70% to reflect the overall reduction and 

not the incremental reduction as shown 

in Table 1 of MDU’s Emissions Control 

Analysis for Lewis & Clark Station Unit 

1. 

Response: We disagree. We stated that 

we did use 70% overall SO2 control 

effectiveness for DSI with baghouse, as 

well as for existing scrubber mod, in our 

analysis. 77 FR 24071. However, we also 

stated that existing SO2 controls at 

Lewis & Clark Station, consisting of a 

flooded disc wet scrubber, have 

achieved up to 60% control under 

certain operating conditions. 77 FR 

24070. We obtained this information 

from MDU’s analyses. 77 FR 24070, 

footnote 265. MDU’s Emissions Control 

Analysis dated June 2011, at Table 1 on 

page 14, lists an expected emissions 

reduction of 100.2 tons per year for DSI 

with baghouse, and the same amount of 

reduction for existing scrubber mod. 

This is a 10% reduction from the 

baseline emissions of 1,002.1 tons per 

year listed in that table. We relied on 

these figures from MDU in listing a 

control effectiveness of 10% for DSI 

with baghouse, as well as a control 

effectiveness of 10% for existing 

scrubber mod. For all control options 

analyzed in our FIP proposal, we 

present control effectiveness in terms of 

the reduction that might be achieved 

from baseline emissions. In this case, 

the baseline emissions already reflected 

a 60% level of SO2 control. 

Comment: EarthJustice argued that 

EPA should require Lewis and Clark to 

switch from lignite fuel to natural gas as 

a reasonable progress measure. The unit 

already uses natural gas for startup, 

there is a natural gas supply close by, 

and thus switching to natural gas is, in 

commenter’s view, quite feasible and 

cost effective for Lewis and Clark 

station. Switching to natural gas should 

be required in the FIP to help achieve 

reasonable progress, as this measure 

would virtually eliminate the unit’s SO2

and PM emissions and would also 

reduce NOX emissions. Although EPA 

dismissed fuel switching as not cost 

effective, commenter argues that EPA 

vastly understated the cost effectiveness 

of this measure. 

Commenter first stated that EPA has 

overstated the costs of switching to 

natural gas, in large part because it has 

underestimated, and in some cases 

ignored, the tremendous cost savings 

that would result from not operating the 

facility’s scrubber, multi-cyclone dust 

collector, and coal preparation systems. 

EPA also relied on inflated estimates for 

natural gas and natural gas supply 

pipelines provided by MDU, which 

owns Lewis and Clark. 

Commenter also stated that EPA has 

improperly calculated the emissions 

reductions achievable from fuel 

switching. EPA failed to take into 

account the fact that the use of natural 

gas would replace the existing SO2 and 

PM controls. Commenter stated that, in 

view of the 54 kilometer distance from 

Lewis and Clark to the closest Class I 

area, filterable PM must be considered. 

Thus, EPA should have accounted for 

the pollution reductions that would be 

achieved with natural gas from 

uncontrolled levels of SO2 and PM. 

Properly calculated, fuel switching 

would eliminate 24,000 tons per year of 

SO2, NOX and filterable PM. As EPA 

noted, Lewis and Clark’s remaining 

emissions would be ‘‘negligible.’’ 

Commenter concluded that, even 

using EPA’s inflated cost estimate, when 

uncontrolled rates of SO2 and PM are 

used as the baseline, the cost 

effectiveness of switching to natural gas 

at Lewis and Clark station is $909/ton 

of SO2, NOX and PM removed. This 

measure is highly cost effective and 

should be required to help achieve 

reasonable progress. 

Response: We disagree. Although we 

do not believe it was necessarily an 

error for us to rely on MDU’s estimate 

of the price of natural gas, we 

acknowledge that price estimates for 

natural gas can vary, and that the $3.07/ 

Mscf price of natural gas cited on page 

129 of the commenter’s Technical 

Support Document, obtained from the 

Energy Information Administration 

(EIA), is substantially lower than MDU’s 

estimate of $7.91/Mscf. However, even 

if we rely on the price cited by the 

commenter, the cost of a fuel switch 

would still be excessive. Using $3.07/ 

Mscf, along with MDU’s estimate of 

3,282,876 Mscf of natural gas which 

would be needed to fuel Lewis and 

Clark station year-round solely on 

natural gas (not disputed by the 

commenter), we calculate the annual 

cost of natural gas at $10,078,429. MDU 

estimated the annual cost of coal at 

$5,754,732. The annual fuel cost 

differential would therefore be 

$4,324,197. To this result we add the 

annualized cost of constructing a 

natural gas pipeline ($1,699,200), as we 

did in our FIP proposal.67 This yields a 

total annual cost of $6,023,397. Dividing 

this result by an expected SO2 emission 

reduction of 1,002 tons per year yields 

cost effectiveness of $6,011/ton. Based 

on this cost and other factors for Lewis 

and Clark station described in our FIP 

proposal at 77 FR 24072, we would still 

eliminate fuel switching as a control 

option for SO2.

We disagree with the statement that a 

fuel switch would yield ‘‘tremendous’’ 

cost savings from not operating the 

facility’s scrubber, multi-cyclone dust 

collector, and coal preparation systems. 

Commenter has not quantified the cost 

savings. We have no reason to believe 

they would be ‘‘tremendous.’’ We 

believe the cost savings would be 

minimal in comparison to other 

components of our cost calculations for 

a fuel switch. The cost savings would 

likely consist primarily of avoidance of 

electricity and maintenance costs for the 

equipment cited by the commenter. 

Also, we disagree with the statement 

that we should have calculated 

reductions from uncontrolled levels of 

SO2 and PM. In every cost analysis of 

control options for our FIP, we calculate 

reductions from an emissions baseline 

which is the current actual annual 

emissions, consistent with the approach 

laid out in the 2005 Regional Haze Rule, 

at 70 FR 39167, for calculating cost 

effectiveness of control options. 

Commenter’s citation to a 2008 letter 

sent by EPA in the course of developing 

initial information for a FIP ignores the 

basis for the action we actually 

proposed. 

We also disagree with the statement 

that a ‘‘proper cost analysis’’ would 

result in cost-effectiveness of $909/ton. 

Commenter apparently calculated $909/ 

ton based on reduction from 

uncontrolled emissions, for the sum of 

three pollutants (PM, SO2 and NOX). We 

have explained above why we do not 

use uncontrolled emissions as the 

baseline. We also explained in our 

proposal that, in our reasonable progress 

determinations, we were not evaluating 

controls for PM for potentially affected 

sources, based on our analysis of the 

emissions inventory and results from 

BART modeling. 77 FR 24055–56. 

Commenter has not disputed those 

bases; commenter merely notes the 54 

kilometer distance to Theodore 

Roosevelt NP. Given these flaws, the 

commenter’s cost analysis provides no 

basis for us to reconsider our decision. 

Comment: Commenter noted that, 

although MDU proposed upgrades to its 

existing SO2 and NOX pollution 

controls, EPA failed even to require 

these measures to help achieve 

reasonable progress. See 77 FR 24074. 

Commenter stated that MDU’s proposal 

is vastly inferior to fuel switching at 

reducing haze pollution, but MDU’s 


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68Several commenters cited numbers that were 

similar to these, but did not match them exactly. 

proposed controls are the bare 

minimum that EPA should have 

required for reasonable progress. 

Commenter noted that MDU proposed 

to improve SO2 removal to 70% by 

optimizing the existing particulate 

scrubber and lime injection system with 

a proposed limit of 0.45 lb/MMBtu. EPA 

estimated the cost effectiveness of this 

modification at $1,383/ton SO2

removed. MDU also proposed SOFA 

and low NOX burners (upgraded) to 

achieve a NOX emission rate of 0.25 lb/ 

MMBtu. EPA estimated the cost 

effectiveness of this option as $1,213/ 

ton of NOX removed. Commenter stated 

that, although the emissions reductions 

from these measures are modest, they 

are highly cost effective and are the 

minimum that EPA should have 

required from Lewis and Clark to 

achieve reasonable progress. 

Response: We disagree. MDU’s 

proposal to improve SO2 and NOX

emission control was contained in its 

June 2011 Emissions Control Analysis, 

which was submitted in response to a 

CAA section 114 information request 

from us. Under the Regional Haze Rule, 

we are not bound by controls that a 

source has proposed when we make our 

reasonable progress determination based 

on the four statutory factors. 

With regard to the statement that costeffectiveness of $1,383/ton for SO2 and 

$1,213/ton for NOX is ‘‘highly costeffective’’ and should result in a 

requirement for emissions reductions, 

commenter has not provided a basis for 

this conclusion. As explained in our FIP 

proposal at 77 FR 24072 (for SO2) and 

24074 (for NOX), in making our 

reasonable progress determination for 

Lewis and Clark Station, we considered 

the following four reasonable progress 

factors: cost of compliance, the time 

necessary for compliance; the energy 

and nonair quality environmental 

impacts of compliance; and the 

remaining useful life of the source. We 

also took into account the following 

additional factors: size of the facility, 

the baseline Q/D of the facility, and the 

potential reduction in Q/D from the 

controls. Commenter has not disputed 

the appropriateness of using the four 

reasonable progress factors and other 

factors in our proposal. 

Comment: WEG commented that the 

determination in the proposed rule that 

no additional SO2 controls are required 

on Lewis & Clark Station is 

unreasonable. WEG notes that two 

highly effective control options are 

available (fuel switch to natural gas at 

99% control effectiveness and SDA with 

baghouse at 85% control effectiveness) 

and should be further considered. 

Response: We disagree. EPA did not 

evaluate control options for Regional 

Haze FIP development solely based on 

emission control effectiveness. As 

indicated in EPA’s analysis, the cost of 

fuel switching is estimated at $21,875 

per ton of pollutant removed and the 

cost of SDA with baghouse is estimated 

at $11,825 per ton of pollutant removed. 

77 FR 24072, Table 173. EPA has 

already explained that this cost is 

excessive. WEG has not provided a 

reason to not consider the cost 

excessive. Besides the cost of 

compliance, EPA also explained that 

other factors were taken into 

consideration in determining whether 

additional SO2 controls should be 

required at Lewis & Clark Station, those 

being the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, the remaining useful life of 

the facility, the size of the facility, the 

baseline Q/D of the facility, and the 

potential reduction in Q/D from the 

controls. WEG did not provide a reason 

to re-evaluate these other factors. 

Comment: WEG comments that EPA 

should re-examine its decision to 

eliminate all control options for NOX

and move to require HDSCR + SOFA/ 

LNB at Lewis & Clark Station. WEG 

notes that this control option has a high 

control effectiveness of 87.5% and 

considers the cost of $4,853 per ton of 

pollutant removed to be reasonable. To 

rule it out alongside a fuel switch to 

natural gas, which has a much higher 

cost of $41,934 per ton of pollutant 

removed, lacks reason. WEG stated that 

the cost and visibility benefits of 

HDSCR + SOFA/LNB should be 

considered individually, and the control 

option should be implemented because 

of the great emissions reduction it 

achieves, and because the FIP is far from 

attaining a Uniform Rate of Progress 

(URP) akin to the regulatory rate. WEG 

also stated that the final analysis of 

control options took into account only 

‘‘the most cost effective option (SOFA/ 

LNB)’’ when weighing cost against 

overall reductions in emissions. 

Response: We disagree. EPA did 

consider control options individually. 

At Step 5 of its NOX analysis, EPA 

mentioned cost of HDSCR + SOFA/LNB 

in the same sentence as cost of a fuel 

switch only because those two options 

happened to be the most expensive. 77 

FR 24074. Besides the cost of 

compliance, EPA also explained that 

other factors were taken into 

consideration in determining whether 

additional NOX controls should be 

required at Lewis & Clark Station, those 

being the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, the remaining useful life of 

the facility, the size of the facility, the 

baseline Q/D of the facility, and the 

potential reduction in Q/D from the 

controls. At Step 5, EPA explained how 

these factors were considered with 

respect to all control options, not just 

SOFA/LNB. In the case of HDSCR + 

SOFA/LNB, EPA explained that this 

control option was eliminated on the 

basis of not only cost, but also on the 

basis of the small size of the facility and 

the relatively small baseline Q/D of the 

facility. WEG has not provided a reason 

to re-evaluate these other factors. With 

regard to URP, that comment was 

addressed in a previous response. 

M. Comments on Montana Sulphur and 

Chemical Company 

Comment: MSCC commented that the 

company agrees with the conclusion in 

the proposed FIP that additional 

controls are not required at this time. 

MSCC also stated it does not believe we 

should have considered it to be a BARTeligible source. The company referenced 

several letters and discussions with 

MDEQ that were previously submitted 

and had as part of development of the 

regional haze plan for Montana. 

Response: Because the commenter 

ultimately agrees with the final 

conclusion and controls are not required 

for MSCC, at this time, we find the 

comment to be non-substantive. 

N. Comments on Health, Ecosystem 

Benefits, Other Pollutants, and Coal Ash 

Comment: Several commenters stated 

that haze pollution significantly impacts 

human health and ecosystem health. 

Specifically, commenters asserted that 

haze pollution, including haze 

pollutants NOX, SO2 and PM, 

contributes to heart attacks, asthma 

attacks, chronic bronchitis and 

respiratory illness, decreased lung 

function, increased hospital admissions, 

and even premature death. Another 

commenter stated that NOX and SO2 can 

combine to create photochemical smog 

and ozone, which can exacerbate health 

problems. 

Some commenters cited a 2010 Clean 

Air Task Force report in stating that the 

Colstrip coal-fired power plant put 31 

people at risk of premature death, 48 

people at risk of a heart attack, 47 

people at risk of acute bronchitis, and 

534 at risk of an asthma attack each 

year.68 Several commenters encouraged 

EPA to finalize the regional haze 

proposal citing their own health 


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problems, or the health problems of 

family members. 

Some commenters stated that the 

negative health impacts of this pollution 

disproportionately harm vulnerable 

populations, specifically the young and 

elderly, and that this disproportionate 

harm potentially makes this a case of 

environmental justice. A commenter 

claimed that Colstrip causes a dark 

shadow on snow and takes human lives. 

One commenter stated the rate of 

asthma in children in Rosebud County 

is the third highest of all counties in the 

State, while another stated the rate of 

birth abnormality in the area downwind 

of Colstrip is much higher (34%) than 

in most other counties in Montana 

(10%). One commenter stated that over 

10% of Montana high school students 

were estimated to have asthma in 2009. 

A commenter surmised that a 50% 

reduction in pollution from Colstrip 

would help human health more than 

eliminating pollutants from all other 

Montana sources. 

Some commenters expressed a 

willingness to pay more for power in 

support of pollution control technology, 

with others stating that we should all 

pay the full cost of energy and not pass 

it on as healthcare costs. Another 

commenter stated that the cost of 

pollution controls, especially at 

Colstrip, was small when compared to 

the health-related benefits. Other 

commenters stated that the sources 

should not be allowed to externalize the 

costs of their pollution onto the people, 

who must pay for them in the form of 

health-related costs. 

Some commenters stated that haze 

pollution negatively impacts ecosystem 

health. Commenters expressed concern 

for the effects of haze pollution on 

plants and water bodies. Some 

commenters specifically expressed 

concern over acid deposition from SO2

and NOX emissions, which they argued 

can leach into drinking water sources 

and harm crops. One commenter 

attributed high levels of mercury in 

some Montana back country lakes to 

coal-fired power plant emissions. 

Other commenters supported EPA’s 

position that consideration of health 

benefits is not relevant under the 

regional haze program. 

One commenter stated that we should 

regulate coal ash at Colstrip. Another 

commenter expressed concern about 

acid rain, and one commenter stated 

that various pollutants such as dioxin 

and formaldehyde were byproducts of 

coal pollution. 

Response: We acknowledge the 

commenters’ concerns regarding the 

negative health impacts of haze-causing 

emissions. We agree that the same PM2.5

emissions that cause visibility 

impairment can cause respiratory 

problems, decreased lung function, 

aggravated asthma, bronchitis, and 

premature death. We also agree that the 

same NOX emissions that cause 

visibility impairment also contribute to 

the formation of ground-level ozone, 

which has been linked with respiratory 

problems, aggravated asthma, and even 

permanent lung damage. We agree that 

these pollutants may have negative 

impacts on vegetation, and reduce crop 

yields. However, for purposes of this 

action, we are not authorized to 

consider these impacts in promulgating 

our FIP, and we have not done so. 

However, to the extent that this FIP will 

lead to reductions in these pollutants, 

there will be co-benefits for public 

health. 

We recognize the importance of 

considering environmental justice; for 

this action, we are finalizing emission 

limitations that will result in emissions 

reductions that will benefit potential 

environmental justice communities. 

Therefore, this action will have no high 

adverse and disproportionate impact on 

potential environmental justice 

communities. 

Mercury is not a visibility impairing 

pollutant, and was therefore not 

included in our analysis. We also are 

not authorized to regulate coal ash in 

this action. 

Comment: Some commenters noted 

that regional haze is not a health-based 

standard, and that there are other 

recently enacted rules that protect 

human health. 

Response: We agree that the Regional 

Haze Rule was not intended to address 

health concerns. Regional Haze is not a 

health-based standard. 

O. General Comments Supporting Our 

Proposal or for Stricter Controls 

Comment: NPCA and MATB 

commended EPA’s required controls for 

the Ash Grove and Holcim cement kilns. 

The Northern Cheyenne Tribe expressed 

support of our proposal as a whole. 

Response: We acknowledge the 

support provided by these commenters. 

Comment: Overall, we received more 

than 47,000 comment letters from 

members representing various 

organizations and concerned citizens 

requesting that EPA mandate more 

stringent and effective controls, most 

notably SCR, on eligible Montana 

sources. These comments were received 

at the public hearings in Billings and 

Helena, Montana, by Internet, and 

through the mail. Many of these 

commenters argued that SCR is required 

at over 200 facilities in the U.S., and 

that SCR should therefore also be 

required at the coal-fired plants in 

Montana. A mass mailer from WEG 

claimed that SCR was shown to be costeffective, but is not required. Several 

comments more generally stated that 

EPA should require the most modern, 

effective pollution controls on Montana 

sources, but did not specifically discuss 

the desired requirements. The Montana 

Conservation Voters pointed out that 

pollution from Colstrip will be three 

times higher than if SCR were required. 

Response: Although we acknowledge 

the commenters’ encouragement that we 

adopt even stricter standards, the 

standards discussed in our proposal are 

appropriate considering the costs and 

visibility improvement. 

Comment: One commenter pointed 

out that Colstrip emits more pollutants 

than the nine next largest haze 

producers, combined. 

Response: The commenter did not 

explain specifically what they were 

requesting. 

Comment: A commenter pointed out 

that Colstrip 3 and 4 are as highly 

polluting as Colstrip 1 and 2, and 

thought that Colstrip 3 and 4 should 

also be required to install additional 

controls. 

Response: As explained in our 

proposal, the modeled visibility benefits 

are not sufficient for us to consider it 

reasonable to impose additional controls 

for Colstrip units 3 and 4 for this 

planning period. 77 FR 24066 and 77 FR 

24067. 

Comment: One commenter stated that 

the upgrading of pollution controls on 

coal-burning facilities also helps 

mitigate the effects of climate change. A 

separate commenter requested that 

EPA’s plan consider CO2 because of its 

impacts on climate change, while 

another stated that coal should no 

longer be burned, as such action would 

slow global climate change. 

Response: While we understand the 

commenters’ concerns with respect to 

climate change, consideration of climate 

change is outside the scope of this 

action. CO2 is a greenhouse gas (GHG) 

and is not considered a visibility 

impairing pollutant. However, EPA 

implements regulations that address 

GHGs in order to protect the public and 

the environment from the negative 

impacts of climate change. 

P. General Comments That the Proposal 

Is Too Stringent 

Comment: Various commenters 

generally stated they did not support the 

proposed rulemaking. Their reasons 

included: It will negatively affect the 

local economy; it will negatively affect 

the coal power plant industry; 

electricity costs will increase; health 


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69One commenter also mentioned idling trucks, 

oil refineries and farms as causes of haze. 

concerns are exaggerated; direct and 

indirect jobs/businesses would be 

adversely affected; the costs outweigh 

the benefits; Colstrip is already 

significantly regulated; there are no air 

quality issues in Colstrip; and it will not 

result in noticeable visibility 

improvements. One commenter insisted 

our proposal is part of a broader anticoal plan to shut down coal plants, 

while another stated that Congress 

should legislate national energy policy 

rather than involving federal agencies. 

One commenter stated that PPL is very 

committed to clean air and 

environmental stewardship and another 

stated that Colstrip is already heavily 

regulated and additional controls are 

unnecessary. One commenter stated that 

mismanagement of forests causes more 

haze and that Colstrip provides good 

jobs and has a good compliance record. 

Response: We acknowledge these 

general comments that opposed our 

proposed action as being too stringent. 

We provide responses that address some 

of these issues elsewhere in this action. 

This action is based on the statutory and 

regulatory requirements for regional 

haze which we have followed. 

Q. General Comments on Visibility 

Improvement and Other Causes of Haze 

Comment: Some commenters stated 

that any controls required by our action 

must demonstrate a perceptible 

visibility improvement and some stated 

that the reductions in the proposal will 

not produce perceptible visibility 

improvement. Other commenters said 

that there were no haze issues in 

Montana and that the change in 

visibility is subjective. The Montana 

Chamber of Commerce commented that 

our FIP is not based on sound science, 

accurate measures, or proven measures 

that will solve the problem. 

Some commenters stated that gravel 

roads and forest fire are the real causes 

of haze.69 WETA commented that under 

the FIP, haze would not be effectively 

reduced and EPA’s regional haze plan 

should consider all established sources 

of emissions and not just industrial 

facilities. Another commenter suggested 

that money to clean up pollution should 

be spent in urban areas where there are 

real problems, not in rural areas like 

Montana. An individual submitted 

information comparing Montana 

emissions from different sources. 

One commenter noted that the 

proposed rule delays, by hundreds of 

years, in some cases, achievement of the 

2064 natural visibility goal. Numerous 

commenters stated that EPA should not 

forego cost-effective pollution controls 

when more progress is clearly needed to 

protect air quality. Some commenters 

stated that there is currently haze at 

Yellowstone that was not visible years 

ago. 

With regard to Colstrip, a commenter 

said that shutting down Colstrip would 

not clear the haze and that areas outside 

Montana, including Oregon, 

Washington, and China influence the 

haze at Yellowstone. Another 

commenter stated that there is no haze 

in the town of Colstrip and that the 

wind does not blow in the directions of 

Yellowstone and Roosevelt. 

Response: We disagree that any 

controls required by our action must 

demonstrate a perceptible visibility 

improvement. In a situation where the 

installation of BART may not result in 

a perceptible improvement in visibility, 

the visibility benefit may still be 

significant. The Regional Haze Rule 

states ‘‘even though the visibility 

improvement from an individual source 

may not be perceptible, it should still be 

considered in setting BART because the 

contribution to haze may be significant 

relative to other source contributions in 

the Class I area. Failing to consider lessthan-perceptible contributions to 

visibility impairment would ignore the 

CAA’s intent to have BART 

requirements apply to sources that 

contribute to, as well as cause, such 

impairment.’’ 70 FR 39129. Visibility 

impacts below the thresholds of 

perceptibility cannot be ignored because 

regional haze is produced by a 

multitude of sources and activities 

which are located across a broad 

geographic area. 

We agree that industrial facilities are 

not the only causes of haze. Our action 

considered the many contributors to 

haze including industrial facilities. In 

this action, we also proposed changes to 

Montana’s Visibility SIP that would 

require BACT for open burning. 

Even though some Class I areas will 

not attain natural visibility conditions 

by 2064, our action requires the controls 

that were determined to be effective 

according to our evaluation. For those 

sources subject to BART, we evaluated: 

(1) Cost of compliance, (2) the energy 

and nonair quality environmental 

impacts of compliance, (3) any existing 

pollution control technology in use at 

the source, (4) remaining useful life of 

source, and (5) degree of improvement 

in visibility which may reasonably be 

anticipated to result from the use of 

such technology and we determined 

which controls should be required 

according to that evaluation. In 

determining the measures necessary to 

make reasonable progress and in 

selecting RPGs for mandatory Class I 

areas within Montana, we took into 

account the following four factors: (1) 

Costs of compliance, (2) time necessary 

for compliance, (3) Energy and nonair 

quality environmental impacts of 

compliance; and (4) remaining useful 

life of any potentially affected sources. 

CAA section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). 

For Colstrip, we evaluated visibility 

improvement at all Class I areas within 

300 km. As stated above we evaluated 

other sources of haze, including but not 

limited to, gravel roads and forest fires. 

The most impacted Class I areas were 

Theodore Roosevelt NP and UL Bend 

WA. While sources outside Montana do 

contribute to haze in the Class I areas 

within Montana, that does not preclude 

our obligation to evaluate Colstrip Units 

1 and 2 according to the five BART 

factors and to evaluate Colstrip Units 3 

and 4 according to the four reasonable 

progress factors and to require 

additional controls where necessary. 

R. Comments on Cost, Economic 

Impact, Jobs and Price to Consumers 

Comment: Some commenters stated 

that the proposed rule would have a 

negative economic impact and a 

negative impact on job creation and 

growth. Some commenters stated that 

PPL might shut down Colstrip Units 1 

and 2 as a result of this action. One 

commenter explained that shutting 

down power plants removes jobs, and 

prevents other businesses from using 

the energy from the power plant, 

causing a domino effect. A commenter 

submitted documents describing 

Colstrip’s positive economic and 

community impact. Another commenter 

said that specifically, Montana has a 

large percentage of low income and 

senior citizens who would be majorly 

burdened by an increase in utility cost 

and another commenter said that the 

cost would also be very burdensome for 

the small business community in the 

area. The Southeastern Montana 

Development Corporation stated that the 

economic impact of this action would 

be devastating to consumers. One 

commenter said that the costs were 

prohibitively expensive and another 

said that the costs could put the plants 

at risk for future investments due to lack 

of economic viability. A commenter 

suggested that the initial cost of 

investment at Colstrip 1 and 2, 

including the cost of debt and capital, 

would be in excess of $82 million and 

that the capital cost, plus operating cost 

of $377 million could result in a 19.6% 

increase in the cost of production. 

Another commenter suggested that the 

cost of electricity could increase by a 


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70Commenter cited the trade publication 

‘‘Clearing Up,’’ which commenter stated reports on 

prices at the Mid-Columbia trading club. 

factor of 20 in 3–4 years. One 

commenter urged us to consider the 

indirect ways that controls on Colstrip 

3 & 4 could affect electric rates. 

Numerous commenters stated that the 

reason EPA was not requiring SCR was 

to save polluters money. 

Other commenters said that the health 

costs of pollution and economic benefit 

from tourism should be considered. One 

commenter said that the health related 

costs from Colstrip are estimated to be 

$230 million annually. Another 

commenter stated that air pollution 

controls are cost effective based on an 

EPA report. One commenter said that 

pollution hinders the Billings economy 

because the city’s economic vitality is 

linked to high quality life-styles, while 

another noted that haze diminishes 

tourists’ scenic vistas. 

Some commenters pointed out that 

the proposed rule would create jobs. 

One commenter stated that complying 

with the rule would create good, highpaying jobs for Montana’s skilled work 

force, including boilermakers, laborers 

and pipefitters. Numerous commenters 

stated that nearly 1,000 full-time jobs 

could be created at Colstrip from 

installing pollution control equipment. 

One commenter said that the Colstrip 

plant will not shut down just because 

added technology is required. 

Many commenters expressed a 

willingness to pay more for power in 

support of pollution control technology. 

Others similarly stated that we should 

all pay the full cost of energy and not 

pass it on to healthcare. Some 

commenters stated that they thought 

PPL could afford to pay for additional 

controls based on the company’s profit. 

A report submitted by Power 

Consulting, Inc. found that the typical 

residential customer’s bill would 

increase by 55 to 89 cents if SCR were 

required on Colstrip unit 4. The overall 

conclusion from that report was that the 

impact of a required SCR retrofit on 

customer’s rates would be small enough 

that it would not disrupt household 

budgets nor cause a significant impact 

on the Montana economy. 

Response: EPA’s evaluation of capital 

and annual expenses associated with 

implementation of the FIP shows such 

expenses to be justified by the degree of 

improvement in visibility in 

relationship to the cost of 

implementation. BART requires that we 

evaluate: (1) Cost of compliance, (2) the 

energy and nonair quality 

environmental impacts of compliance, 

(3) any existing pollution control 

technology in use at the source, (4) 

remaining useful life of source, and (5) 

degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

In determining the measures necessary 

to make reasonable progress and in 

selecting reasonable progress goals for 

mandatory Class I areas within 

Montana, we must take into account the 

following four factors: (1) Costs of 

compliance, (2) time necessary for 

compliance, (3) Energy and nonair 

quality environmental impacts of 

compliance; and (4) remaining useful 

life of any potentially affected sources. 

CAA section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). The cost of electricity 

to consumers and the overall impact on 

the economy is outside the scope of our 

evaluation for this action. 

Although we did not consider the 

potential positive benefits to local 

economies in making our decision, we 

do expect that improved visibility 

would have a positive impact on 

tourism-dependent local economies. 

Also, the retrofits required are large 

construction projects that will take up to 

five years to complete. These projects 

will require well-paid, skilled labor 

which can potentially be drawn from 

the local area and support local growth. 

Comment: A commenter stated that 

EPA should have included, as 

associated per-unit costs, consideration 

of the ‘‘wider market consequences’’ of 

a potential shutdown of generating 

capacity at Colstrip 1 and 2. The 

commenter says that, ‘‘[i]f the cost of 

production resulting from this rule 

* * * exceeds the market value of 

power, PPL may make a decision to 

shutter the plant.’’ The commenter also 

states that, ‘‘[b]ased on an analysis of 

production cost data, there is at least 

some chance that Colstrip Units 1 and 

2 would become uneconomical as a 

result of mandated upgrades.’’ 

Specifically, commenter estimated that 

the ‘‘all-in’’ cost of production of 

electricity post-controls is $25.591 per 

megawatt-hour, a 19.6% increase over 

the current $21.40 per megawatt-hour 

cost of production reported in Federal 

Regulatory Commission filings. 

Commenter stated that, compared to 

current market prices from a regional 

trade publication,70 Colstrip 1 and 2 

would often be uneconomical at that 

estimated cost. 

The commenter also argued that a 

closure at Colstrip 1 and 2 would 

decrease available electrical generation 

in the northwestern U.S. The 

commenter stated that we wrongly 

failed to consider these factors of 

potential plant closure and the 

subsequent constriction of power 

supply in our analyses. 

Response: Analyzing the wider 

market consequences of a potential 

shutdown of generating capacity at 

Colstrip 1 and 2 involves many 

complicated factors and it is unclear 

from the information provided by the 

commenter that Colstrip Units 1 and 2 

would, in fact, shut down. As noted 

previously, we have received conflicting 

information regarding potential rate 

increases. Specifically, a report 

submitted by Power Consulting, Inc. 

found that the typical residential 

customer’s bill would increase by 55 to 

89 cents if SCR were required on 

Colstrip unit 4. The BART Guidelines 

allow for the consideration of unusual 

circumstances that justify taking into 

consideration the conditions of the 

plant and the economic effects of 

requiring the use of a given control 

technology. The BART Guidelines state: 

[t]hese effects would include effects on 

product prices, the market share, and 

profitability of the source. Where there are 

such unusual circumstances that are judged 

to affect plant operations, you may take into 

consideration the conditions of the plant and 

the economic effects of requiring the use of 

a control technology. Where these effects are 

judged to have a severe impact on plant 

operations you may consider them in the 

selection process, but you may wish to 

provide an economic analysis that 

demonstrates, in sufficient detail for public 

review, the specific economic effects, 

parameters, and reasoning. 

70 FR 39171. The commenter has not 

provided any basis that unusual 

circumstances exist here. Nor has the 

commenter providing any information 

that indicates a shutdown will occur 

that we could have taken into account 

in our analysis. The owners of Colstrip 

Units 1 and 2 have made no indication 

that there are unusual circumstances 

present that warrant taking wider 

market consequences into 

consideration. 

S. Comments About Other Forms of 

Energy 

Comment: We received comments 

regarding alternative forms of energy. 

Some commenters believed that wind 

energy would create more jobs while 

others believed that it would not create 

as many jobs compared to coal fired 

power plants. Some commenters stated 

that wind energy was cheaper to 

produce while one commenter pointed 

out that the government subsidizes 

wind energy. One commenter believed 

that the wind farm in Judith Gap 

produces energy more cheaply 

compared to the Colstrip coal plant. One 

commenter stated that our energy 


tkelley on DSK3SPTVN1PROD with RULES3
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71We corrected some technical information in the 

Holcim SO2 BART analysis. See 77 FR 29270. 

should be focused on renewable sources 

rather than coal and another commenter 

stated that the most important thing we 

can do to slow global warming is to stop 

burning coal. 

Response: While we do generally 

acknowledge that many kinds of 

renewable energy do not produce hazecausing pollutants, and transitioning to 

those sources of energy could lead to 

visibility improvements. In this action 

we are required to review specific 

retrofit options for specific sources 

subject to BART or the sources analyzed 

under reasonable progress. Renewable 

energy technology is not a retrofit 

option for these sources and is outside 

the scope of our determinations and 

regulatory requirements in this action. 

T. Other Miscellaneous Comments 

Comment: One commenter asked 

whether EPA was concerned that 

requiring these facilities to install 

emissions control equipment to address 

fine particles and precursors might 

impact the effectiveness of equipment 

installed to address other pollutants. 

Response: The control technologies 

that are required will not negatively 

impact the effectiveness of equipment 

installed to address other pollutants. 

Comment: One commenter asked 

whether the agency was concerned that 

the technologies prescribed to address 

particles and precursors might also 

impact the efficiency and reliability of 

kilns, boilers, generators and other 

essential equipment. 

Response: The control technologies 

required will not negatively impact the 

efficiency and reliability of kilns, 

boilers, generators and other essential 

equipment. As required under BART, 

we evaluated the energy impacts for 

each control option considered. 70 FR 

39168 and 70 FR 39169. These impacts 

are discussed in the relevant sections of 

the proposed rule and in all cases are 

minor. In addition, as required under 

BART, we evaluated the technical 

feasibility for each control option 

considered. Where we have selected 

additional controls, the controls are 

shown to be technically feasible at 

similar facilities. Issues associated with 

the reliability of the emission units, if 

any, are resolvable. 

Comment: MDEQ requested that EPA 

extend the comment period to sixty 

days from the date of the publication of 

corrections, or July 16, 2012. 

Response: The comment period for 

our proposal closed on June 19, 2012. 

We carefully considered the request for 

an extension to the comment period. We 

took into consideration how an 

extension might affect our ability to 

consider comments received on the 

proposed action and still comply with 

our consent decree deadlines. We do 

note that our May 1, 2012, public 

hearing in Helena, Montana and May 2, 

2012, public hearing in Billings, 

Montana were well attended and 

provided an opportunity for people to 

comment on our proposal. We also note 

that the corrections published May 17, 

2012, (77 FR 29270) primarily amended 

typographical errors.71

Comment: MDEQ suggested that EPA 

issue a request for additional comment 

to clarify the scope of the proposed FIP. 

MDEQ asserted that such a clarification 

is necessary to prevent confusion among 

the public regarding the Regional Haze 

Rule’s prevention and correction of 

adverse health effects, about which EPA 

received multiple comments. MDEQ 

warned that ‘‘the level of this 

misperception threatens to pervert not 

only the National Goal, but, ostensibly, 

the public health goals of Section 110.’’ 

Response: We do not agree that the 

scope of the proposed FIP requires 

clarification. At no point in the 

proposed FIP did we discuss public 

health impacts as a consideration in our 

analyses, as they were not. As stated 

elsewhere, we agree that the Regional 

Haze Rule is not a health-based 

standard, and that we are not authorized 

to consider public health impacts in 

promulgating our FIP for purposes of 

this action. However, we have not been 

presented any information from the 

public to indicate that there is confusion 

that that reduction of visibility 

impairing pollutants also provides 

health benefits. 

Comment: One commenter stated that 

the Cheyenne Reservation was given 

Class I air quality designation and that 

according to that designation there is 

not supposed to be any degradation of 

that air. 

Response: The Regional Haze Rule 

requires analysis for the 156 mandatory 

Class I areas listed at 40 CFR Part 81. 

The Cheyenne Reservation is not one of 

these federally mandated Class I areas. 

Comment: WEG stated that EPA 

overlooked, in two respects, the 

requirement of section 110(l) of the Act 

to prevent interference with attainment 

or maintenance of the NAAQS. First, 

WEG stated that EPA has not 

demonstrated that this FIP adequately 

safeguards the 2006 PM2.5 NAAQS, the 

2008 ozone NAAQS, the 2010 1-hour 

NO2 NAAQS, and the 2010 1-hour SO2

NAAQS. In particular, WEG noted that 

the FIP emissions limitations are 

generally expressed as 30-day rolling 

averages, which, in WEG’s view, do not 

adequately protect short-term NAAQS 

such as the 2010 1-hour SO2 and NO2.

Second, WEG argued that several BART 

emissions limitations are relaxations 

that may impact the NAAQS. As an 

example, WEG cited another portion of 

its comments in which WEG argued that 

the BART emissions limitations for 

Corette will allow actual emissions from 

Corette to increase. WEG concluded that 

EPA must conduct a 110(l) 

demonstration in order to protect public 

health and not interfere with 

maintenance and attainment of the 

NAAQS. 

Response: EPA disagrees with WEG. 

In relevant part, section 110(l) provides 

that EPA shall not approve a revision of 

a plan if the revision would interfere 

with any applicable requirement 

concerning attainment and reasonable 

further progress or any other applicable 

requirement of the CAA. First, WEG 

does not explain how section 110(l) 

applies to EPA’s initial promulgation of 

a FIP for certain regional haze 

requirements when there is no existing 

SIP to meet those requirements. Second, 

to the extent that section 110(l) applies, 

EPA’s promulgation of this FIP satisfies 

its requirements. It is EPA’s consistent 

interpretation of section 110(l) that a SIP 

revision does not interfere with 

attainment and maintenance of the 

NAAQS if the revision at least preserves 

the status quo air quality by not relaxing 

or removing any existing emissions 

limitation or other SIP requirement. 

EPA does not believe that a full 

attainment or maintenance 

demonstration for each NAAQS is 

required for every SIP revision under 

section 110(l). 

In this case, the FIP imposes new 

emissions limitations on a number of 

existing sources, and it does not relax 

any existing emissions limitations or 

other SIP requirements. WEG’s 

statement that actual emissions at 

Corette and other BART sources might 

rise to the BART limit misses the point: 

In the absence of the BART limit (or any 

other limit), those actual emissions 

could increase much more. In other 

words, imposing an emissions 

limitation where one did not exist 

before is necessarily a more stringent 

requirement, regardless of actual 

emissions. Nor does WEG explicitly 

identify any existing emissions 

limitation or other SIP requirement that 

is relaxed by the FIP. For that matter, 

nothing in the proposal, or in the 

preamble or regulatory text for this rule, 

purports to modify any existing SIPapproved emissions limitation or other 

SIP requirement. Thus, even if there 

were such a requirement—and WEG has 

identified none—it would not be 


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Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57911 

relaxed by this FIP. EPA therefore 

concludes that, to the extent that section 

110(l) is applicable to this FIP, its 

requirements are satisfied. 

Comment: Commenter stated that the 

input of Montana residents should be 

given more weight than the input of 

special interest groups that receive 

support from outside the State. 

Commenter also requested that future 

hearings be held in areas of impact. 

Response: Any commenter who 

submits a comment on the proposed 

FIP, either orally or written, during the 

public comment period is entitled to do 

so. EPA takes all comments into 

consideration in making its final 

decision on the FIP. If future hearings 

are required for any reason, we will do 

the best we can to ensure access is 

available to all those who wish to 

participate. 

V. Changes From Proposed Rule and 

Reasons for the Changes 

A. Emission Limits for Corette 

We proposed a PM emission limit of 

0.10 lb/MMBtu for Corette at 40 CFR 

52.1396(c). We inadvertently stated that 

we were imposing an emission limit of 

0.10 lb/MMBtu in the preamble to our 

proposed FIP (77 FR 24047) and also at 

40 CFR 53.1396(c)(1). PPL commented 

that the emission limit in the proposed 

FIP was flawed and PPL provided 

additional information indicating that 

over the past five years, stack test results 

have shown that PM emissions have 

ranged from 0.059 lb/MMBtu to 0.252 

lb/MMBtu. We have changed the 

emission limit in the final regulatory 

requirements at 40 CFR 1396(c)(1). In 

the final FIP, we are establishing a PM 

emission limit of 0.26 lb/MMBtu. 

We proposed a SO2 emission limit of 

0.70 lb/MMBtu and a NOX emission 

limit of 0.40 lb/MMBtu for Corette at 40 

CFR 52.1396(c). In the final FIP, we are 

establishing a SO2 emission limit of 0.57 

lb/MMBtu and a NOX emission limit of 

0.35 lb/MMBtu. We have made this 

change as a result of the comments we 

received. One commenter stated that 

EPA must increase the limits to no less 

than 0.81 lb/MMBtu for SO2 and 0.46 

lb/MMBtu for NOX in order to account 

for compliance over a 30-day rolling 

average. By contrast, another commenter 

stated that our proposed emission limits 

were too high and would actually result 

in increased emissions. 

Based on these comments, we have 

reassessed the SO2 and NOX emission 

limits for Corette. In order to establish 

appropriate emission limits, we 

conducted a statistical analysis of the 

monthly emissions data contained in 

the CAMD emissions system. For the 

period 2000–2010, the 99th percentile 

monthly SO2 emission rate was 0.548 

lb/MMbtu. Similarly, the 99th 

percentile monthly NOX emission rate 

was 0.335 lb/MMBtu. In our final 

action, we are establishing emission 

limits slightly above these 99th 

percentile emission rates in order to 

allow a sufficient margin for 

compliance. This is because the 

emission limits must apply at all times, 

including during startup, shutdown, 

and malfunction. The revised emission 

rates are 0.57 lb/MMBtu for SO2 and 

0.35 lb/MMBtu for NOX, both on a 30- 

day rolling average. We have revised the 

emission limits for Corette contained in 

section 52.1396(c)(1) accordingly. 

B. Changes to 40 CFR 52.1396(c)(2)— 

Emission Limitations for Cement Kilns 

In response to a comment from 

Holcim that EPA failed to consider the 

NOX control technology already 

installed at the Trident cement plant, 

and that EPA failed to give proper 

weight to the excessively high average 

cost-effectiveness ($4,279/ton) and 

incremental cost-effectiveness ($8,029/ 

ton) of a switch to indirect firing and a 

Low-NOX Burner (LNB), we have 

removed switching to indirect firing and 

a LNB from consideration as an option 

for further reducing NOX emissions and 

are treating any NOX emission reduction 

that may have been achieved from 

installation of a new burner as part of 

the emissions baseline. We have 

recalculated the BART limit for NOX to 

reflect a 50% reduction in NOX

emissions from that baseline by addition 

of SNCR alone, rather than the 58% 

reduction we previously used, which 

reflected a switch to indirect firing and 

LNB plus SNCR. The recalculated NOX

BART limit is 6.5 lb/ton clinker. We 

have replaced the NOX emission limit of 

5.5 lb/ton clinker from our proposal 

with 6.5 lb/ton clinker, on a 30-day 

rolling average. 

Also, during our evaluation of 

comments on PM BART from Ash 

Grove, we found that the table of 

emission limits for cement kilns, at 

section 52.1396(c)(2) of our proposal, 

needed to clarify that the PM emission 

limit for Ash Grove is in lb/hr, not lb/ 

ton clinker. Only the PM emission limit 

for Holcim is in lb/ton clinker. The 

column header for PM emission limits 

for both cement kilns erroneously said 

‘‘lb/ton clinker.’’ We have corrected this 

error by changing the header from ‘‘PM 

Emission Limit (lb/ton clinker)’’ to ‘‘PM 

Emission Limit.’’ We did not change the 

text of the PM emission limit for Ash 

Grove, as it is already clear in that text 

that the limit is in lb/hr. However, at the 

bottom of the column, we have clarified 

the PM emission limit for Holcim to say 

‘‘0.77 lb/ton clinker’’ rather than‘‘0.77 

lb/ton.’’ 

C. Change to 40 CFR 52.1396(d)— 

Compliance Date 

In response to a comment from Ash 

Grove which identified the failure of our 

regulatory text at 40 CFR 52.1396(d) to 

specify the SO2 and PM compliance 

dates described in the preamble to our 

proposed rule, we have revised 40 CFR 

52.1396(d) to read as follows: 

The owners and operators of the BART 

sources subject to this section shall comply 

with the emissions limitations and other 

requirements of this section as follows, 

unless otherwise indicated in specific 

paragraphs: Compliance with PM limits is 

required within 30 days of the effective date 

of this rule. Compliance with SO2 and NOX

limits is required within 180 days of the 

effective date of this rule, unless installation 

of additional emission controls is necessary 

to comply with emission limitations under 

this rule, in which case compliance is 

required within five years of the effective 

date of this rule. 

D. Change to 40 CFR 52.1396(e)(3)— 

CEMS for Cement Kilns 

In response to a comment from Ash 

Grove Cement that this section should 

be revised to include an exception from 

CEMS data collection during CEMS 

breakdowns, repairs, calibration checks 

and zero and span adjustments, we have 

added the following language from 40 

CFR part 60, subpart F, New Source 

Performance Standards for cement kilns, 

at 40 CFR 60.63(b): 

You must operate the monitoring system 

and collect data at all required intervals at all 

times the affected source is operating, except 

for periods of monitoring systems 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality assurance 

or quality control activities (including, as 

applicable, calibration checks and required 

zero and span adjustments). 

Also, during our evaluation of 

comments from Ash Grove on CEMS 

requirements, we found that section 

52.1396(e)(3) inadvertently failed to 

cross-reference the requirements for 

CEMS for cement kilns at 40 CFR 

60.63(g). Section 52.1396(e)(3) only 

cross-referenced 60.63(f). There are 

important requirements for cement kiln 

CEMSs at 40 CFR 60.63(g), as well as 

important CEMS requirements at 

60.63(h) which are cross-referenced 

only by 60.63(g) and not by 60.63(f). We 

have therefore added ‘‘and (g),’’ such 

that the first sentence of section 

52.1396(e)(3) now reads as follows: 

At all times after the compliance date 

specified in paragraph (d) of this section, the 

owner/operator of each unit shall maintain, 


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calibrate, and operate a CEMS, in full 

compliance with the requirements found at 

40 CFR 60.63(f) and (g), to accurately 

measure concentration by volume of SO2 and 

NOX emissions into the atmosphere from 

each unit. 

E. Change to 40 CFR 52.1396(e)(4)(ii)— 

Compliance Determination Methods for 

SO2 and NOX at Cement Kilns 

In response to a comment from Ash 

Grove that the formula at section 

52.1396(e)(4)(ii) of our proposal 

incorrectly expresses the concentrations 

of SO2 and NOX in grains per dry 

standard cubic foot, rather than in parts 

per million, we have deleted the 

equation E = (CsQs)/(PK) from this 

section, as well as the definitions of 

terms in that equation, and replaced it 

with the following equation, which 

appears in the proposed amendments to 

40 CFR part 60, subpart F, New Source 

Performance Standards for cement kilns, 

published in the Federal Register on 

July 18, 2012: 

Where: 

ED = 30 kiln operating day average emission 

rate of NOX or SO2, lb/ton of clinker; 

Ci = Concentration of NOX or SO2 for hour 

i, ppm; 

Qi = volumetric flow rate of effluent gas for 

hour i, where 

Ci and Qi are on the same basis (either wet 

or dry), scf/hr; 

Pi = total kiln clinker produced during 

production hour i, ton/hr; 

k = conversion factor, 1.194 × 10¥7 for NOX

and 1.660 × 10¥7 for SO2

n = number of kiln operating hours over 30 

kiln operating days, n = 1 to 720. 

For each kiln operating hour for which you 

do not have at least one valid 15-minute 

CEMS data value, use the average 

emissions rate (lb/hr) from the most 

recent previous hour for which valid 

data are available. 

F. Change to 40 CFR 52.1396(f)(1) and 

(f)(2)—Compliance Determinations for 

PM BART Limits at EGUs and Cement 

Kilns 

In response to a verbal comment from 

Holcim, in a meeting with EPA in June 

of 2012 on the proposed FIP, that BART 

sources should be allowed to retain the 

PM stack testing schedule already 

established under State permits, we 

have added the following sentence, after 

the sentence in sections 52.1396(f)(1) 

and (f)(2) that requires the first annual 

PM performance stack test for PM 

within 60 days after the PM compliance 

deadline: 

The results from a stack test meeting the 

requirements of this paragraph that was 

completed within 12 months prior to the 

compliance deadline can be used in lieu of 

the first stack test required. If this option is 

chosen, then the next annual stack test shall 

be due no more than 12 months after the 

stack test that was used. 

The meeting between Holcim and 

EPA is documented in the docket for 

this rulemaking. 

G. Change to 40 CFR 52.1396(f)(2)— 

Compliance Determinations for Cement 

Kiln PM BART Limits 

Consistent with our clarification of 

the table of PM emission limits for 

cement kilns at 40 CFR 52.1396(c)(2), 

we have clarified 40 CFR 52.1396(f)(2), 

to indicate that the emission rate of PM 

shall be reported in lb/hr for Ash Grove 

and in lb/ton clinker for Holcim. We 

have also clarified that the average of 

the results of three test runs for PM shall 

be used for demonstrating compliance. 

Specifically, we have added the 

following language after the third 

sentence of section 52.1396(f)(2): 

The average of the results of three test runs 

shall be used for demonstrating compliance. 

For Ash Grove, the emission rate of 

particulate matter shall be computed for each 

run in pounds per hour (lb/hr). For Holcim, 

the emission rate (E) of particulate matter 

shall be computed for each run in lb/ton 

clinker, using the following equation: * * * 

We have also revised section 

52.1396(f)(2) in response to a comment 

from Ash Grove that the equation at 40 

CFR 52.1396(e)(4)(ii), cross-referenced 

by this section 52.1396(f)(2), for 

calculating emissions in lb/ton clinker, 

is not valid for calculating SO2 and NOX

emissions, but is only valid for 

calculating PM emissions. Therefore, we 

have moved this equation from section 

52.1396(e)(4)(ii) to section 52.1396(f)(2). 

We have also changed the pollutant in 

the equation to PM. We have also 

clarified (as explained above) that the 

equation is to be used for calculating 

PM in lb/ton clinker only for Holcim, 

not for Ash Grove (which, as explained 

above, is subject to a PM emission limit 

in lb/hr, not in lb/ton clinker). Below is 

the equation we have now inserted into 

section 52.1396(f)(2), immediately after 

the revised text described above: 

E = (CsQs)/(PK) 

Where: 

E = emission rate of PM, lb/ton of clinker 

produced 

Cs = concentration of PM in grains per 

standard cubic foot (gr/scf) 

Qs = volumetric flow rate of effluent gas, 

where Cs and Qs are on the same basis 

(either wet or dry), scf/hr 

P = total kiln clinker production rate, tons/ 

hr, and 

K = conversion factor, 7000 gr/lb 

We have also deleted the crossreference to section 52.1396(e)(4)(ii) for 

this equation. 

H. Change to 40 CFR 52.1396(h)(6)— 

Recordkeeping Requirements for 

Cement Kilns 

In response to a comment from Ash 

Grove that the reference to ‘‘40 CFR Part 

75’’ should be deleted because Part 75 

applies only to electrical generating 

units, not to cement kilns, we have 

deleted that reference. We note that 

since the monitoring requirements for 

cement kilns in the FIP, at 40 CFR 

52.1396(e)(3) and (4), and at 40 CFR 

52.1396(f)(2), do not cross-reference Part 

75, there are no applicable Part 75 

recordkeeping requirements in the FIP. 

Section 52.1396(h)(6) now reads as 

follows: 

Any other records required by 40 CFR part 

60, subpart F, or 40 CFR part 60, Appendix 

F, Procedure 1. 

I. Changes to 40 CFR 52.1396(i)— 

Reporting 

In response to a comment from Ash 

Grove that the first sentence of this 

section mistakenly references 40 CFR 

53.1395(n) and (o), rather than 

52.1396(n) and (o), we have made the 

correction. 

J. Change to 40 CFR 52.1396(i)(1) and 

(i)(2)—Reporting for CEMS for SO2 and 

NOX

In response to a comment from Ash 

Grove that the reporting frequency for 

CEMS excess emission reports and 

CEMS performance reports for cement 

kilns should be changed from quarterly 

to semiannual, because reporting 

requirements under other programs 

(Title V and NESHAP) only require 

semiannual reporting, we have changed 

the frequency to semiannual, but have 

kept the frequency at quarterly for 

EGUs. 

We note that the general provisions of 

NSPS subpart A, at 40 CFR 60.7(c), 

which we used as a template for our FIP 

provisions for CEMS reporting, require 

semiannual excess emission reports and 

monitoring system performance reports, 

except when more frequent reporting is 

specifically required by an applicable 

subpart, or if the Administrator, on a 

case-by-case basis, determines that more 

frequent report is necessary to 

accurately assess the compliance status 

of the source. NSPS subpart F for 

cement kilns does not specify more 

frequent reporting. 

Therefore, we have deleted 

‘‘quarterly’’ from the first sentence of 

section 52.1396(i)(1) and from the first 

sentence of section 52.1396(i)(2). After 

the first sentence in each of those 


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sections, we have inserted the following 

sentence: ‘‘Reports shall be submitted 

quarterly for EGUs and semiannually for 

cement kilns.’’ 

K. Changes to 40 CFR 52.1396 for Devon 

Energy, Blaine County #1 Compressor 

Station 

In the final FIP, we are clarifying 

testing requirements, monitoring, 

recordkeeping and reporting 

requirements, and emission limitations 

for Devon Energy, Blaine County #1 

Compressor Station. We made these 

changes in response to a comment 

stating that the requirements for this 

source were not practically enforceable. 

We have changed the text at 40 CFR 

52.1396(c)(3) to read, ‘‘The owners/ 

operators of LP, Blaine County #1 

Compressor Station shall not emit or 

cause to be emitted from each 5,500 

horsepower Ingersoll Rand 616 natural 

gas-fired compressor engine installed at 

the facility, total NOX in excess of 21.8 

lbs/hr (average of three stack test runs).’’ 

We have made this change to clarify that 

the emission limit of 21.8 lbs/hr applies 

to each of the 5,500 horsepower 

Ingersoll Rand 616 natural gas-fired 

compressor engines installed at the 

facility and that the emission rate will 

be determined by averaging the results 

of three stack test runs. 

We have changed the text at 40 CFR 

52.1396(e)(5) to read, ‘‘The owner/ 

operator of Blaine County #1 

Compressor Station shall install a 

temperature-sensing device (i.e. 

thermocouple or resistance temperature 

detectors) before the catalyst in order to 

monitor the inlet temperatures of the 

catalyst for each engine. The owner/ 

operator shall maintain the exhaust 

temperature at the inlet to the catalyst 

for each engine at a minimum of least 

750 °F and no more than 1250 °F in 

accordance with the catalyst 

manufacturer’s specifications. Also, the 

owner/operator shall install gauges 

before and after the catalyst for each 

engine in order to monitor pressure 

drop across the catalyst, and that the 

owner/operator maintain the pressure 

drop within ± 2’’ water at 100% load 

plus or minus 10% from the pressure 

drop across the catalyst measured 

during the initial performance test. The 

owner/operator shall follow the 

manufacturer’s recommended 

maintenance schedule and procedures 

for each engine and its respective 

catalyst. The owner/operator shall only 

fire each engine with natural gas that is 

of pipeline-quality in all respects except 

that the CO2 concentration in the gas 

shall not be required to be within 

pipeline-quality.’’ We have made this 

change to clarify that it is the exhaust 

temperature that must be maintained at 

a minimum of at least 750 °F and no 

more than 1250 °F in accordance with 

the catalyst manufacturer’s 

specifications, and not the engine 

temperature that must be kept within 

this temperature range. We are also 

making this change to clarify that the 

temperature range must be kept in 

accordance with the catalyst 

manufacturer’s specifications and not 

the engine manufacturer’s 

specifications. 

We have added a new section, 40 CFR 

52.1396(j) which includes testing 

requirements for Blaine County #1 

Compressor Station. This section was 

inadvertently omitted from the 

proposed FIP, but is necessary to ensure 

adequate testing is performed to ensure 

compliance with the NOX emission 

limit for Blaine County #1 Compressor 

Station. 

We have changed 40 CFR 

52.1396(k)(1) to read: ‘‘The owner/ 

operator shall measure NOX emissions 

from each engine at least semi-annually 

or once every six-month period to 

demonstrate compliance with the 

emission limits. To meet this 

requirement, the owner/operator shall 

measure NOX emissions from each 

engine using a portable analyzer and a 

monitoring protocol approved by EPA.’’ 

We have changed the first sentence from 

referring to engines to refer to each 

engine to clarify that NOX emissions 

must be measured from each engine. 

We have added a new paragraph at 40 

CFR 52.1396(k)(9) to read, ‘‘The owner/ 

operator shall keep records of all 

deviations from the emission limit or 

operating requirements (e.g., catalyst 

inlet temperature, pressure drop across 

the catalyst) for each engine. The 

records shall include: The date and time 

of the deviation, the name and title of 

the observing employee and a brief 

description of the deviation and the 

measures taken to address the deviation 

and prevent future occurrences.’’ We 

have made this change to ensure that 

adequate records are kept by the owner 

or operator of Blaine County #1 

Compressor Station to demonstrate 

compliance with the required emission 

limit and appropriate operation of the 

NSCR system. 

We have changed the text of 40 CFR 

52.1396(k)(10) to correct a typographical 

error and to add to the requirements that 

the owner/operator of Blaine County #1 

Compressor Station must maintain 

records of deviations from operating 

requirements for a period of at least five 

years and that these records must be 

made available upon request by EPA. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 13563 

This action will finalize a SIP 

approval for a revision to Montana’s 

Smoke Management plan and a sourcespecific Regional Haze FIP for imposing 

federal controls to meet BART 

requirements for PM, NOX and SO2

emissions on five specific units at four 

sources in Montana (Ash Grove, Holcim, 

Colstrip Units 1 and 2, and Corette) and 

imposing controls to meet RP 

requirements for NOX emissions at one 

additional source (Devon) in Montana. 

The net result of the FIP action is that 

EPA is proposing direct emission 

controls on selected units at five 

sources. The sources in question are two 

large electric generating plants (one 

plant includes two units), two cement 

plants, and one gas compressor station. 

This action also imposes notification 

requirements on CFAC and M2Green 

Redevelopment LLC. This type of action 

is exempt from review under Executive 

Orders 12866 (58 FR 51735, October 4, 

1993) and 13563 (76 FR 3821, January 

21, 2011). 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Under the 

Paperwork Reduction Act, a ‘‘collection 

of information’’ is defined as a 

requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *. ’’ 44 U.S.C. 3502(3)(A). 

Because the FIP applies to just seven 

sources, the Paperwork Reduction Act 

does not apply. See 5 CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a federal 

agency. This includes the time needed 

to review instructions; develop, acquire, 

install, and utilize technology and 

systems for the purposes of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 


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An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OMB 

control numbers for our regulations in 

40 CFR are listed in 40 CFR Part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

The Regional Haze FIP that EPA is 

finalizing consists of imposing federal 

controls to meet BART and RP 

requirements for PM, NOX and SO2

emissions on specific sources as 

described above in section A. None of 

these sources are owned by small 

entities, and therefore are not small 

entities. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for state, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. 

Table 1 notes that the cumulative total 

annual costs for this action are $13.7 

million. Thus, this rule is not subject to 

the requirements of sections 202 or 205 

of UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the State of Montana 

not meeting its obligation to adopt a SIP 

that meets the regional haze 

requirements under the CAA. Thus, 

Executive Order 13132 does not apply 

to this action. In the spirit of Executive 

Order 13132, and consistent with EPA 

policy to promote communications 

between EPA and state and local 

governments, EPA specifically solicited 

comment on this rule from state and 

local officials. A summary of each 

comment and EPA’s response to those 

comments is provided in section IV of 

this preamble. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). This action applies to only seven 

sources in Montana. Thus, Executive 

Order 13175 does not apply to this rule. 

Although Executive Order 13175 does 

not apply to this action, EPA did send 

letters, dated October 7, 2011, to each of 

the Montana tribes explaining our 

regional haze FIP action and offering 

consultation. We did not receive any 

written or verbal requests from the 

Montana tribes for more information or 

for consultation. As a follow-up to our 

letter, we invited all of the tribes to a 

January 5, 2012 conference call. The call 

was attended by tribal Air Program 

Managers and one Environmental 

Director from tribes from four 

reservations. We also met with the 

Montana tribes prior to the start of the 

public hearings held in Helena and 

Billings, Montana. EPA specifically 

solicited additional comment on this 

rule from tribal officials and we 

received comments and responded to 

them in section IV of this preamble. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this rule limits emissions of NOX,

SO2, and PM, the rule will have a 

beneficial effect on children’s health by 

reducing air pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. 

The EPA believes that VCS are 

inapplicable to this action. Today’s 

action does not require the public to 

perform activities conducive to the use 

of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this rule 

will not have disproportionately high 

and adverse human health or 

environmental effects on minority or 


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low-income populations because it 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority or 

low-income population. This rule limits 

emissions of NOX, SO2, and PM from 

five sources in Montana. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. Section 804 

exempts from section 801 the following 

types of rules (1) rules of particular 

applicability; (2) rules relating to agency 

management or personnel; and (3) rules 

of agency organization, procedure, or 

practice that do not substantially affect 

the rights or obligations of non-agency 

parties. 5 U.S.C 804(3). EPA is not 

required to submit a rule report 

regarding today’s action under section 

801 because this action is a rule of 

particular applicability. This rule 

finalizes a FIP for seven sources. 

L. Judicial Review 

Under section 307(b)(1) of the CAA, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by November 19, 2012. Pursuant 

to CAA section 307(d)(1)(B), this action 

is subject to the requirements of CAA 

section 307(d) as it promulgates a FIP 

under CAA section 110(c). Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this action for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. See CAA 

section 307(b)(2). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Intergovernmental 

relations, Incorporation by Reference, 

Nitrogen dioxides, Particulate matter, 

Reporting and recordkeeping 

requirements, Sulfur dioxide, Volatile 

organic compounds. 

Dated: August 15, 2012. 

Lisa P. Jackson, 

Administrator. 

40 CFR part 52 is amended as follows: 

PART 52—[AMENDED] 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart BB—Montana 

■ 2. Section 52.1370 is amended by 

revising paragraph (c)(27)(i)(H) to read 

as follows: 

§ 52.1370 Identification of plan. 

* * * * * 

(c) * * * 

(27) * * * 

(i) * * * 

(H) Appendix G–2, Montana Smoke 

Management Plan, effective April 15, 

1988, is removed and replaced by 

§ 52.1395. 

* * * * * 

■ 3. Add section 52.1395 to read as 

follows: 

§ 52.1395 Smoke management plan. 

The Department considers smoke 

management techniques for agriculture 

and forestry management burning 

purposes as set forth in 40 CFR 

51.308(d)(3)(v)(E). The Department 

considers the visibility impact of smoke 

when developing, issuing, or 

conditioning permits and when making 

dispersion forecast recommendations 

through the implementation of Title 17, 

Chapter 8, subchapter 6, ARM, Open 

Burning. 

■ 4. Add section 52.1396 to read as 

follows: 

§ 52.1396 Federal implementation plan for 

regional haze. 

(a) Applicability. This section applies 

to each owner and operator of the 

following coal fired electric generating 

units (EGUs) in the State of Montana: 

PPL Montana, LLC, Colstrip Power 

Plant, Units 1, 2; and PPL Montana, 

LLC, JE Corette Steam Electric Station. 

This section also applies to each owner 

and operator of cement kilns at the 

following cement production plants: 

Ash Grove Cement, Montana City Plant; 

and Holcim (US) Inc. Cement, Trident 

Plant. This section also applies to each 

owner or operator of Blaine County #1 

Compressor Station. This section also 

applies to each owner and operator of 

CFAC and M2 Green Redevelopment 

LLC, Missoula site. 

(b) Definitions. Terms not defined 

below shall have the meaning given 

them in the Clean Air Act or EPA’s 

regulations implementing the Clean Air 

Act. For purposes of this section: 

Boiler operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

EGU. It is not necessary for fuel to be 

combusted for the entire 24-hour period. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by this section to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes (using an automated 

data acquisition and handling system 

(DAHS)), a permanent record of SO2 or 

NOX emissions, other pollutant 

emissions, diluent, or stack gas 

volumetric flow rate. 

Kiln operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which the 

kiln operates. 

NOX means nitrogen oxides. 

Owner/operator means any person 

who owns or who operates, controls, or 

supervises an EGU identified in 

paragraph (a) of this section. 

PM means filterable total particulate 

matter. 

SO2 means sulfur dioxide. 

Unit means any of the EGUs or 

cement kilns identified in paragraph (a) 

of this section. 

(c) Emissions limitations. (1) The 

owners/operators of EGUs subject to this 

section shall not emit or cause to be 

emitted PM, SO2 or NOX in excess of the 

following limitations, in pounds per 

million British thermal units (lb/ 

MMBtu), averaged over a rolling 30-day 

period for SO2 and NOX: 

Source name 

PM emission 

limit 

(lb/MMBtu) 

SO2 emission 

limit 

(lb/MMBtu) 

NOX emission 

limit 

(lb/MMBtu) 

Colstrip Unit 1 .............................................................................................................................. 0.10 0.08 0.15 

Colstrip Unit 2 .............................................................................................................................. 0.10 0.08 0.15 

JE Corette Unit 1 ......................................................................................................................... 0.26 0.57 0.35 


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57916 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

(2) The owners/operators of cement 

kilns subject to this section shall not 

emit or cause to be emitted PM, SO2 or 

NOX in excess of the following 

limitations, in pounds per ton of clinker 

produced, averaged over a rolling 30- 

day period for SO2 and NOX: 

Source name PM emission limit 

SO2 emission 

limit 

(lb/ton clinker) 

NOX emission 

limit 

(lb/ton clinker) 

Ash Grove Cement ................................. If the process weight rate of the kiln is less than or equal to 30 

tons per hour, then the emission limit shall be calculated using E 

= 4.10p 0.67 where E = rate of emission in pounds per hour and p 

= process weight rate in tons per hour; however, if the process 

weight rate of the kiln is greater than 30 tons per hour, then the 

emission limit shall be calculated using E = 55.0p0.11¥40, where 

E = rate of emission in pounds per hour and P = process weight 

rate in tons per hour.

11.5 8.0 

Holcim (US) Inc ....................................... 0.77 lb/ton clinker ............................................................................... 1.3 6.5 

(3) The owners/operators of LP, 

Blaine County #1 Compressor Station 

shall not emit or cause to be emitted 

from each 5,500 horsepower Ingersoll 

Rand 616 natural gas-fired compressor 

engine installed at the facility total NOX

in excess of 21.8 lbs/hr (average of three 

stack test runs). 

(4) These emission limitations shall 

apply at all times, including startups, 

shutdowns, emergencies, and 

malfunctions. 

(d) Compliance date. The owners and 

operators of Blaine County #1 

Compressor Station shall comply with 

the emissions limitation and other 

requirements of this section as 

expeditiously as practicable, but no later 

than July 31, 2018. The owners and 

operators of the BART sources subject to 

this section shall comply with the 

emissions limitations and other 

requirements of this section as follows, 

unless otherwise indicated in specific 

paragraphs: Compliance with PM limits 

is required within 30 days of the 

effective date of this rule. Compliance 

with SO2 and NOX limits is required 

within 180 days of the effective date of 

this rule, unless installation of 

additional emission controls is 

necessary to comply with emission 

limitations under this rule, in which 

case compliance is required within five 

years of the effective date of this rule. 

(e) Compliance determinations for 

SO2 and NOX. (1) CEMS for EGUs. At all 

times after the compliance date 

specified in paragraph (d) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR part 75, 

to accurately measure SO2, NOX, 

diluent, and stack gas volumetric flow 

rate from each unit. The CEMS shall be 

used by the owner/operator to 

determine compliance with the 

emission limitations in paragraph (c) of 

this section for each unit. 

(2) Method for EGUs. (i) For any hour 

in which fuel is combusted in a unit, the 

owner/operator of each unit shall 

calculate the hourly average SO2 and 

NOX concentration in lb/MMBtu at the 

CEMS in accordance with the 

requirements of 40 CFR part 75. At the 

end of each boiler operating day, the 

owner/operator shall calculate and 

record a new 30-day rolling average 

emission rate in lb/MMBtu from the 

arithmetic average of all valid hourly 

emission rates from the CEMS for the 

current boiler operating day and the 

previous 29 successive boiler operating 

days. 

(ii) An hourly average SO2 or NOX

emission rate in lb/MMBtu is valid only 

if the minimum number of data points, 

as specified in 40 CFR part 75, is 

acquired by the owner/operator for both 

the pollutant concentration monitor 

(SO2 or NOX) and the diluent monitor 

(O2 or CO2). 

(iii) Data reported by the owner/ 

operator to meet the requirements of 

this section shall not include data 

substituted using the missing data 

substitution procedures of subpart D of 

40 CFR part 75, nor shall the data have 

been bias adjusted according to the 

procedures of 40 CFR part 75. 

(3) CEMS for cement kilns. At all 

times after the compliance date 

specified in paragraph (d) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR 60.63(f) 

and (g), to accurately measure 

concentration by volume of SO2 and 

NOX emissions into the atmosphere 

from each unit. The CEMS shall be used 

by the owner/operator to determine 

compliance with the emission 

limitations in paragraph (c) of this 

section for each unit, in combination 

with data on actual clinker production. 

The owner/operator must operate the 

monitoring system and collect data at all 

required intervals at all times the 

affected unit is operating, except for 

periods of monitoring system 

malfunctions, repairs associated with 

monitoring system malfunctions, and 

required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments). 

(4) Method for cement kilns. (i) The 

owner/operator of each unit shall record 

the daily clinker production rates. 

(ii) The owner/operator of each unit 

shall calculate and record the 30- 

operating day rolling emission rates of 

SO2 and NOX, in lb/ton of clinker 

produced, as the total of all hourly 

emissions data for the cement kiln in 

the preceding 30 days, divided by the 

total tons of clinker produced in that 

kiln during the same 30-day operating 

period, using the following equation: 

Where: 

ED = 30 kiln operating day average emission 

rate of NOX or SO2, lb/ton of clinker; 

Ci = Concentration of NOX or SO2 for hour 

i, ppm; 

Qi = volumetric flow rate of effluent gas for 

hour i, where 

Ci and Qi are on the same basis (either wet 

or dry), scf/hr; 

Pi = total kiln clinker produced during 

production hour i, ton/hr; 

k = conversion factor, 1.194 × 10¥7 for NOX

and 1.660 × 10¥7 for SO2; and.

n = number of kiln operating hours over 30 

kiln operating days, n = 1 to 720. 

For each kiln operating hour for 

which the owner/operator does not have 

at least one valid 15-minute CEMS data 

value, the owner/operator must use the 

average emissions rate (lb/hr) from the 

most recent previous hour for which 

valid data are available. Hourly clinker 

production shall be determined by the 

owner/operator in accordance with the 

requirements found at 40 CFR 60.63(b). 


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Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57917 

(iii) At the end of each kiln operating 

day, the owner/operator of each unit 

shall calculate and record a new 30-day 

rolling average emission rate in lb/ton 

clinker from the arithmetic average of 

all valid hourly emission rates for the 

current kiln operating day and the 

previous 29 successive kiln operating 

days. 

(5) Method for compressor station. 

The owner/operator of Blaine County #1 

Compressor Station shall install a 

temperature-sensing device (i.e. 

thermocouple or resistance temperature 

detectors) before the catalyst in order to 

monitor the inlet temperatures of the 

catalyst for each engine. The owner/ 

operator shall maintain the exhaust 

temperature at the inlet to the catalyst 

for each engine at a minimum of least 

750 °F and no more than 1250 °F in 

accordance with the catalyst 

manufacturer’s specifications. Also, the 

owner/operator shall install gauges 

before and after the catalyst for each 

engine in order to monitor pressure 

drop across the catalyst. During the 

initial performance test the owner/ 

operator maintain the pressure drop 

within ± 2′′ water at 100 percent load 

plus or minus 10 percent from the 

pressure drop across the catalyst 

measured. The owner/operator shall 

follow the manufacturer’s recommended 

maintenance schedule and procedures 

for each engine and its respective 

catalyst. The owner/operator shall only 

fire each engine with natural gas that is 

of pipeline-quality in all respects except 

that the CO2 concentration in the gas 

shall not be required to be within 

pipeline-quality. 

(f) Compliance determinations for 

particulate matter. 

(1) EGU particulate matter BART 

limits. Compliance with the particulate 

matter BART emission limits for each 

EGU BART unit shall be determined by 

the owner/operator from annual 

performance stack tests. Within 60 days 

of the compliance deadline specified in 

paragraph (d) of this section, and on at 

least an annual basis thereafter, the 

owner/operator of each unit shall 

conduct a stack test on each unit to 

measure particulate emissions using 

EPA Method 5, 5B, 5D, or 17, as 

appropriate, in 40 CFR part 60, 

Appendix A. A test shall consist of three 

runs, with each run at least 120 minutes 

in duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. Results shall be reported by 

the owner/operator in lb/MMBtu. The 

results from a stack test meeting the 

requirements of this paragraph that were 

completed within 120 days prior to the 

compliance date can be used by the 

owner/operator in lieu of the first stack 

test required. In addition to annual stack 

tests, owner/operator shall monitor 

particulate emissions for compliance 

with the BART emission limits in 

accordance with the applicable 

Compliance Assurance Monitoring 

(CAM) plan developed and approved in 

accordance with 40 CFR part 64. 

(2) Cement kiln particulate matter 

BART limits. Compliance with the 

particulate matter BART emission limits 

for each cement kiln shall be 

determined by the owner/operator from 

annual performance stack tests. Within 

60 days of the compliance deadline 

specified in paragraph (d) of this 

section, and on at least an annual basis 

thereafter, the owner/operator of each 

unit shall conduct a stack test on each 

unit to measure particulate matter 

emissions using EPA Method 5, 5B, 5D, 

or 17, as appropriate, in 40 CFR part 60, 

Appendix A. A test shall consist of three 

runs, with each run at least 120 minutes 

in duration and each run collecting a 

minimum sample of 60 dry standard 

cubic feet. The average of the results of 

three test runs shall be used by the 

owner/operator for demonstrating 

compliance. 

Clinker production shall be 

determined in accordance with the 

requirements found at 40 CFR 60.63(b). 

Results of each test shall be reported by 

the owner/operator as the average of 

three valid test runs. In addition to 

annual stack tests, owner/operator shall 

monitor particulate emissions for 

compliance with the BART emission 

limits in accordance with the applicable 

Compliance Assurance Monitoring 

(CAM) plan developed and approved in 

accordance with 40 CFR part 64. 

(i) For Ash Grove Cement, the 

emission rate of particulate matter shall 

be computed by the owner/operator for 

each run in pounds per hour (lb/hr). 

(ii) For Holcim, the emission rate (E) 

of particulate matter shall be computed 

by the owner/operator for each run in 

lb/ton clinker, using the following 

equation: 

E = (CsQs)/PK 

Where: 

E = emission rate of PM, lb/ton of clinker 

produced; 

Cs = concentration of PM in grains per 

standard cubic foot (gr/scf); 

Qs = volumetric flow rate of effluent gas, 

where Cs and Qs are on the same basis 

(either wet or dry), scf/hr; 

P = total kiln clinker production, tons/hr; and 

K = conversion factor, 7000 gr/lb, 

(g) Recordkeeping for EGUs. The 

owner/operator shall maintain the 

following records for at least five years: 

(1) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(2) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR Part 75. 

(3) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(4) Any other records required by 40 

CFR part 75. 

(5) All particulate matter stack test 

results. 

(h) Recordkeeping for cement kilns. 

The owner/operator shall maintain the 

following records for at least five years: 

(1) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

(2) All particulate matter stack test 

results. 

(3) All records of clinker production. 

(4) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix F, Procedure 1. 

(5) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, CEMS 

and clinker production measurement 

devices. 

(6) Any other records required by 40 

CFR part 60, Subpart F, or 40 CFR part 

60, Appendix F, Procedure 1. 

(i) Reporting. All reports under this 

section, with the exception of 40 CFR 

52.1396(n) and (o), shall be submitted 

by the owner/operator to the Director, 

Office of Enforcement, Compliance and 

Environmental Justice, U.S. 

Environmental Protection Agency, 

Region 8, Mail Code 8ENF–AT, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129. 

(1) The owner/operator of each unit 

shall submit excess emissions reports 

for SO2 and NOX BART limits. Reports 

shall be submitted quarterly by the 

owner/operator for EGUs and 

semiannually for cement kilns, no later 

than the 30th day following the end of 

each calendar quarter or semiannual 

period, respectively. Excess emissions 

means emissions that exceed the 

emissions limits specified in paragraph 

(c) of this section. The reports shall 

include the magnitude, date(s), and 

duration of each period of excess 

emissions, specific identification of 

each period of excess emissions that 

occurs during startups, shutdowns, and 

malfunctions of the unit, the nature and 

cause of any malfunction (if known), 

and the corrective action taken or 

preventative measures adopted. 


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57918 Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 

(2) The owner/operator of each unit 

shall submit CEMS performance reports, 

to include dates and duration of each 

period during which the CEMS was 

inoperative (except for zero and span 

adjustments and calibration checks), 

reason(s) why the CEMS was 

inoperative and steps taken to prevent 

recurrence, and any CEMS repairs or 

adjustments. The owner/operator shall 

submit reports quarterly for EGUs and 

semiannually for cement kilns. 

(i) For EGUs: The owner/operator of 

each unit shall also submit results of 

any CEMS performance tests required 

by 40 CFR part 75 (Relative Accuracy 

Test Audits, Relative Accuracy Audits, 

and Cylinder Gas Audits). 

(ii) For cement kilns: Owner/operator 

of each unit shall also submit results of 

any CEMS performance tests required 

by 40 CFR part 60, appendix F, 

Procedure 1 (Relative Accuracy Test 

Audits, Relative Accuracy Audits, and 

Cylinder Gas Audits). 

(3) When no excess emissions have 

occurred or the CEMS has not been 

inoperative, repaired, or adjusted during 

the reporting period, the owner/operator 

shall state such information in the 

quarterly reports required by sections 

(h)(1) and (2) of this section. 

(4) The owner/operator of each unit 

shall submit results of any particulate 

matter stack tests conducted for 

demonstrating compliance with the 

particulate matter BART limits in 

paragraph (c) of this section within 60 

days after the completion of the test. 

(5) The owner/operator of each unit 

shall submit semi-annual reports of any 

excursions under the approved CAM 

plan in accordance with the schedule 

specified in the source’s title V permit. 

(j) Testing requirements for Blaine 

County #1 Compressor Station: 

(1) An initial performance test shall 

be conducted by the owner/operator for 

each engine for measuring NOX

emissions from the engines to 

demonstrate initial compliance with the 

emission limits. The initial performance 

test shall be conducted by the owner/ 

operator as expeditiously as practicable, 

but no later than October July 31, 2018. 

(2) Upon change out of the catalyst for 

each engine a performance test shall be 

conducted by the owner/operator for 

measuring NOX from the engines to 

demonstrate compliance with the 

emission limits and re-establish 

temperature and pressure correlations. 

The performance test shall be conducted 

by the owner/operator within 90 

calendar days of the date of the catalyst 

change out. 

(3) The performance tests for NOX

shall be conducted by the owner/ 

operator in accordance with the test 

methods specified in 40 CFR Part 60, 

Appendix A. EPA Reference Method 7E 

shall be used to measure NOX

emissions. 

(4) All tests conducted by the owner/ 

operator for NOX emissions must meet 

the following requirements: 

(i) All tests shall be performed at a 

maximum operating rate (90 to 110 

percent of engine capacity at site 

elevation). 

(ii) During each test run, data shall be 

collected on all parameters necessary to 

document how NOX emissions in 

pounds per hour were measured or 

calculated (such as test run length, 

minimum sample volume, volumetric 

flow rate, moisture and oxygen 

corrections, etc.). The temperature at the 

inlet to the catalyst and the pressure 

drop across the catalyst shall also be 

measured and recorded during each test 

run for each engine. 

(iii) Each source test shall consist of 

at least three 1-hour or longer valid test 

runs. Emission results shall be reported 

as the arithmetic average of all valid test 

runs and shall be in terms of the 

emission limits (pounds per hour). 

(iv) A source test plan for NOX

emissions shall be submitted to EPA at 

least 45 calendar days prior to the 

scheduled performance test. 

(v) The source test plan shall include 

and address the following elements: 

(A) Purpose of the test; 

(B) Engines and catalysts to be tested; 

(C) Expected engine operating rate(s) 

during test; 

(D) Schedule/date(s) for test; 

(E) Sampling and analysis procedures 

(sampling locations, test methods, 

laboratory identification); 

(F) Quality assurance plan (calibration 

procedures and frequency, sample 

recovery and field documentation, chain 

of custody procedures); and 

(G) Data processing and reporting 

(description of data handling and 

quality control procedures). 

(k) Monitoring, recordkeeping, and 

reporting requirements for Blaine 

County #1 Compressor Station: 

(1) The owner/operator shall measure 

NOX emissions from each engine at least 

semi-annually or once every six month 

period to demonstrate compliance with 

the emission limits. To meet this 

requirement, the owner/operator shall 

measure NOX emissions from each 

engine using a portable analyzer and a 

monitoring protocol approved by EPA. 

(2) The owner/operator shall submit 

the analyzer specifications and 

monitoring protocol to EPA for approval 

within 45 calendar days prior to 

installation of the NSCR unit. 

(3) Monitoring for NOX emissions 

shall commence during the first 

complete calendar quarter following the 

owner/operator’s submittal of the initial 

performance test results for NOX to EPA. 

(4) The owner/operator shall measure 

the engine exhaust temperature at the 

inlet to the oxidation catalyst at least 

once per week and shall measure the 

pressure drop across the oxidation 

catalyst monthly. 

(5) The owner/operator shall ensure 

that each temperature-sensing device is 

accurate to within plus or minus 0.75% 

of span and that the pressure sensing 

devices be accurate to within plus or 

minus 0.1 inches of water. 

(6) The owner/operator shall keep 

records of all temperature and pressure 

measurements; vendor specifications for 

the thermocouples and pressure gauges; 

vendor specifications for the NSCR 

catalyst and the air-to-fuel ratio 

controller on each engine. 

(7) The owner/operator shall keep 

records sufficient to demonstrate that 

the fuel for the engines is pipelinequality natural gas in all respects, with 

the exception of the CO2 concentration 

in the natural gas. 

(8) The owner/operator shall keep 

records of all required testing and 

monitoring that include: The date, 

place, and time of sampling or 

measurements; the date(s) analyses were 

performed; the company or entity that 

performed the analyses; the analytical 

techniques or methods used; the results 

of such analyses or measurements; and 

the operating conditions as existing at 

the time of sampling or measurement. 

(9) The owner/operator shall keep 

records of all deviations from the 

emission limit or operating 

requirements (e.g., catalyst inlet 

temperature, pressure drop across the 

catalyst) for each engine. The records 

shall include: The date and time of the 

deviation, the name and title of the 

observing employee and a brief 

description of the deviation and the 

measures taken to address the deviation 

and prevent future occurrences. 

(10) The owner/operator shall 

maintain records of all required 

monitoring data, support information 

(e.g., all calibration and maintenance 

records, all original strip-chart 

recordings for continuous monitoring 

instrumentation, and copies of all 

reports required) and deviations from 

operating requirements for a period of at 

least five years from the date of the 

monitoring sample, measurement, or 

report and that these records be made 

available upon request by EPA. 

(11) The owner/operator shall submit 

a written report of the results of the 

required performance tests to EPA 

within 90 calendar days of the date of 

testing completion. 


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Federal Register / Vol. 77, No. 181 / Tuesday, September 18, 2012 / Rules and Regulations 57919 

(l) Notifications. (1) The owner/ 

operator shall submit notification of 

commencement of construction of any 

equipment which is being constructed 

to comply with the SO2 or NOX

emission limits in paragraph (c) of this 

section. 

(2) The owner/operator shall submit 

semi-annual progress reports on 

construction of any such equipment. 

(3) The owner/operator shall submit 

notification of initial startup of any such 

equipment. 

(m) Equipment operation. At all 

times, the owner/operator shall 

maintain each unit, including associated 

air pollution control equipment, in a 

manner consistent with good air 

pollution control practices for 

minimizing emissions. 

(n) Credible evidence. Nothing in this 

section shall preclude the use, including 

the exclusive use, of any credible 

evidence or information, relevant to 

whether a source would have been in 

compliance with requirements of this 

section if the appropriate performance 

or compliance test procedures or 

method had been performed. 

(o) CFAC notification. CFAC shall 

notify EPA 60 days in advance of 

resuming operation. CFAC shall submit 

such notice to the Director, Air Program, 

U.S. Environmental Protection Agency, 

Region 8, Mail Code 8P–AR, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129. Once CFAC notifies EPA 

that it intends to resume operation, EPA 

will initiate and complete a BART 

determination after notification and 

revise the FIP as necessary in 

accordance with regional haze 

requirements, including the BART 

provisions in 40 CFR 51.308(e). CFAC 

will be required to install any controls 

that are required as soon as practicable, 

but in no case later than five years 

following the effective date of this rule. 

(p) M2Green Redevelopment LLC 

notification. M2Green Redevelopment 

LLC shall notify EPA 60 days in 

advance of resuming operation. 

M2Green Redevelopment LLC shall 

submit such notice to the Director, Air 

Program, U.S. Environmental Protection 

Agency, Region 8, Mail Code 8P–AR, 

1595 Wynkoop Street, Denver, Colorado 

80202–1129. Once M2 Green 

Redevelopment LLC notifies EPA that it 

intends to resume operation, EPA will 

initiate and complete a four factor 

analysis after notification and revise the 

FIP as necessary in accordance with 

regional haze requirements including 

the ‘‘reasonable progress’’ provisions in 

40 CFR 51.308(d)(1). M2 Green 

Redevelopment LLC will be required to 

install any controls that are required as 

soon as practicable, but in no case later 

than July 31, 2018. 

[FR Doc. 2012–20918 Filed 9–17–12; 8:45 am] 

BILLING CODE 6560–50–P 


tkelley on DSK3SPTVN1PROD with RULES3