Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 76871 

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 section 307(b)(2).) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Particulate matter. 

Dated: November 28, 2012. 

Judith A. Enck, 

Regional Administrator, Region II. 

Dated: December 11, 2012. 

H. Curtis Spalding, 

Regional Administrator, Region I. 

Part 52, chapter I, title 40 of the Code 

of Federal Regulations is amended as 

follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart H—Connecticut 

■ 2. Section 52.379 is amended by 

adding paragraph (g) to read as follows: 

§ 52.379 Control strategy: PM2.5. 

* * * * * 

(g) Determination of Attainment. EPA 

has determined, as of December 31, 

2012, that the New York-N. New JerseyLong Island, NY-NJ-CT fine particle 

(PM2.5) nonattainment area has attained 

the 2006 PM2.5 National Ambient Air 

Quality Standard. This determination 

suspends the requirements for this area 

to submit an attainment demonstration, 

associated reasonably available control 

measures, a reasonable further progress 

plan, contingency measures, and other 

planning SIPs related to attainment of 

the standard for as long as the area 

continues to attain the 2006 PM2.5

NAAQS. 

Subpart FF—New Jersey 

■ 3. Section 52.1602 is amended by 

adding paragraph (e) to read as follows: 

§ 52.1602 Control strategy and 

regulations: PM2.5. 

* * * * * 

(e) Determination of Attainment. EPA 

has determined, as of December 31, 

2012, that the New York-N. New JerseyLong Island, NY-NJ-CT fine particle 

(PM2.5) nonattainment area has attained 

the 2006 PM2.5 National Ambient Air 

Quality Standard. This determination 

suspends the requirements for this area 

to submit an attainment demonstration, 

associated reasonably available control 

measures, a reasonable further progress 

plan, contingency measures, and other 

planning SIPs related to attainment of 

the standard for as long as the area 

continues to attain the 2006 PM2.5

NAAQS. 

Subpart HH—New York 

■ 4. Section 52.1678 is amended by 

adding paragraph (f) to read as follows: 

§ 52.1678 Control strategy and 

regulations: Particulate matter. 

* * * * * 

■ (f) Determination of Attainment. EPA 

has determined, as of December 31, 

2012, that the New York-N. New JerseyLong Island, NY-NJ-CT fine particle 

(PM2.5) nonattainment area has attained 

the 2006 PM2.5 National Ambient Air 

Quality Standard. This determination 

suspends the requirements for this area 

to submit an attainment demonstration, 

associated reasonably control available 

measures, a reasonable further progress 

plan, contingency measures, and other 

planning SIPs related to attainment of 

the standard for as long as the area 

continues to attain the 2006 PM2.5

NAAQS. 

[FR Doc. 2012–31214 Filed 12–28–12; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R08–OAR–2011–0770, FRL–9734–8] 

Approval and Promulgation of 

Implementation Plans; State of 

Colorado; Regional Haze State 

Implementation Plan 

AGENCY: Environmental Protection 

Agency. 

ACTION: Final rule. 

SUMMARY: EPA is approving a State 

Implementation Plan (SIP) revision 

submitted by the State of Colorado on 

May 25, 2011 that addresses regional 

haze. Colorado submitted this SIP 

revision to meet the requirements of the 

Clean Air Act (CAA or ‘‘the Act’’) and 

our rules that require states to prevent 

any future and remedy any existing 

man-made impairment of visibility in 

mandatory Class I areas caused by 

emissions of air pollutants from 

numerous sources located over a wide 

geographic area (also referred to as the 

‘‘regional haze program’’). EPA is taking 

this action pursuant to section 110 of 

the CAA. 

DATES: This final rule is effective 

January 30, 2013. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–R08–OAR–2011–0770. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

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: 

Laurel Dygowski, Air Program, 

Mailcode 8P–AR, Environmental 

Protection Agency, Region 8, 1595 

Wynkoop Street, Denver, Colorado 

80202–1129, (303) 312–6144, 

dygowski.laurel@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Background 

A. Regional Haze 

B. Lawsuits 

C. Our Proposal 

D. Public Participation 

II. Final Action 

III. Basis for Our Final Action 

IV. Issues Raised by Commenters and EPA’s 

Response 

A. NOX BART for Tri-State Craig Unit 1 

and Unit 2 

B. NOX BART Determination for Martin 

Drake Units 5, 6, and 7 

C. BART Determination for Colorado 

Energy Nations (CENC) Unit 4 and Unit 

5 

D. NOX BART Determination for Cemex 

Lyons Kiln 

E. NOX BART Determination for Comanche 

Unit 1 and Unit 2 

F. NOX Reasonable Progress Determination 

for Craig Unit 3 

G. NOX Reasonable Progress Determination 

for Nucla 

H. Reasonable Progress for Rio Grande 

Cement Company (GCC) 

I. Legal Issues 

1. Public Service Company of Colorado 

(PSCO) BART Alternative 

2. Timing of Implementation 

3. Compliance With Section 110(l) 

J. Comments Generally in Favor of Our 

Proposal 

V. Statutory and Executive Order Reviews 

Definitions 

For the purpose of this document, we 

are giving meaning to certain words or 

initials as follows: 

i. The words or initials Act or CAA mean 

or refer to the Clean Air Act, unless the 

context indicates otherwise. 


ebenthall on DSK5TPTVN1PROD with 
76872 Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 

1We note that our proposed rule contained 

certain errors, as follows: (1) In Table 2, at 77 FR 

18060, ‘‘Tri-State Generation and Transmission, 

Inc.’’ should have read ‘‘Tri-State Generation and 

Transmission Association, Inc.;’’ (2) In Table 13, at 

77 FR 18068, the visibility improvement for SCR for 

Craig Unit 2 should have read 0.98 deciviews 

instead of 1.01 deciviews; and (3) In Table 38, at 

77 FR 18085, the annualized costs for the limestone 

injection improvements (LII) option should have 

read $2,188,595 instead of $914,290. None of these 

errors impact our analysis or decision. In particular, 

the cost effectiveness value for the LII option in 

Table 38 already accounted for the correct 

annualized cost value. 

ii. The initials APEN mean or refer to Air 

Pollution Emissions Notice. 

iii. The initials AQCC mean or refer to the 

Air Quality Control Commission. 

iv. The initials BACT mean or refer to Best 

Available Control Technology. 

v. The initials BART mean or refer to Best 

Available Retrofit Technology. 

vi. The initials CMA mean or refer to the 

Colorado Mining Association. 

vii. The words Colorado and the State 

mean the State of Colorado. 

viii. The initials EGUs mean or refer to 

Electric Generating Units. 

ix. The words EPA, we, us, our, or the 

Agency mean or refer to the United States 

Environmental Protection Agency. 

x. The initials LNB mean or refer to low 

NOX burner. 

xi. The initials NAAQS mean or refer to the 

National Ambient Air Quality Standards. 

xii. The initials NOX mean or refer to 

nitrogen oxides. 

xiii. The initials NPS mean or refer to 

National Park Service. 

xiv. The initials PM2.5 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 2.5 micrometers. 

xv. The initials SCR mean or refer to 

selective catalytic reduction. 

xvi. The initials SIP mean or refer to State 

Implementation Plan. 

xvii. The initials SNCR mean or refer to 

selective non-catalytic reduction. 

xviii. The initials SO2 mean or refer to 

sulfur dioxide. 

xix. The initials TSD mean or refer to 

Technical Support Document. 

I. Background 

The CAA requires each state to 

develop plans, referred to as SIPs, to 

meet various air quality requirements. A 

state must submit its SIPs and SIP 

revisions to us for approval. Once 

approved, a SIP is enforceable by EPA 

and citizens under the CAA, also known 

as being federally enforceable. This 

action addresses the requirement that 

states have SIPs that address regional 

haze. 

A. Regional Haze 

In 1990, Congress added section 169B 

to the CAA to address regional haze 

issues, and we promulgated regulations 

addressing regional haze in 1999 (64 FR 

35714, July 1, 1999, codified at 40 CFR 

part 51, subpart P). The requirements for 

regional haze, found at 40 CFR 51.308 

and 51.309, are included in our 

visibility protection regulations at 40 

CFR 51.300–309. The requirement to 

submit a regional haze SIP applies to all 

50 states, the District of Columbia and 

the Virgin Islands. States were required 

to submit a SIP addressing regional haze 

visibility impairment no later than 

December 17, 2007 (40 CFR 51.308(b)). 

Few states submitted a regional haze 

SIP prior to the December 17, 2007, 

deadline, and on January 15, 2009, EPA 

found that 37 states, including 

Colorado, the District of Columbia, and 

the Virgin Islands, had failed to submit 

SIPs addressing the regional haze 

requirements (74 FR 2392). Once EPA 

has found that a state has failed to make 

a required submission, EPA is required 

to promulgate a Federal Implementation 

Plan (FIP) within 2 years unless the 

state submits a SIP and the Agency 

approves it within the 2-year period. 

CAA section 110(c)(1). 

Colorado submitted a SIP addressing 

regional haze on May 25, 2011. 

B. Lawsuits 

In a lawsuit in the U.S. District Court 

for the District of Colorado, 

environmental groups sued us for our 

failure to take timely action with respect 

to the regional haze requirements of the 

CAA and our regulations. In particular, 

the lawsuits alleged that we had failed 

to promulgate FIPs for these 

requirements within the 2-year period 

allowed by CAA section 110(c) or, in the 

alternative, fully approve SIPs 

addressing these requirements. 

As a result of these lawsuits, we 

entered into a consent decree. The 

consent decree requires that we sign a 

notice of final rulemaking addressing 

the regional haze requirements for 

Colorado by September 10, 2012. We are 

meeting that requirement with the 

signing of this notice of final 

rulemaking. 

C. Our Proposal 

We signed our notice of proposed 

rulemaking on March 15, 2012, and it 

was published in the Federal Register 

on March 26, 2012 (77 FR 18052). In 

that notice, we provided a detailed 

description of the various regional haze 

requirements. We are not repeating that 

description here; instead, the reader 

should refer to our notice of proposed 

rulemaking for further detail.1 In our 

proposal, we proposed to approve 

Colorado’s May 25, 2011, regional haze 

SIP. 

D. Public Participation 

We requested comments on all 

aspects of our proposed action and 

provided a 60-day comment period, 

with the comment period closing on 

May 25, 2012. We received comments 

on our proposed rule that generally 

supported our proposed action and 

comments that were critical of certain 

aspects of our proposed action. In this 

action, we are responding to the 

comments we have received, taking 

final rulemaking action, and explaining 

the bases for our action. 

II. Final Action 

With this action, EPA is approving a 

SIP revision submitted by the State of 

Colorado on May 25, 2011, that 

addresses regional haze. We are 

approving the State’s regional haze SIP, 

including revisions submitted as part of 

the regional haze SIP to: 

• Regulation No. 3, Part F, Section VI 

and Section VII. 

• Regulation No. 3, Part D, Section 

XIV.F. 

• Regulation No. 7, Section 

XVII.E.3.a. 

III. Basis for Our Final Action 

We have fully considered all 

significant comments on our proposal 

and have concluded that no changes 

from our proposal are warranted. Our 

action is based on an evaluation of 

Colorado’s regional haze SIP submittal 

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 Colorado’s SIP submittal is 

based on CAA section 110(k). 

We are approving the State’s regional 

haze SIP provisions because they meet 

the relevant regional haze requirements. 

Most of the adverse comments we 

received concerning our proposed 

approval of the regional haze SIP 

pertained to the State’s best available 

retrofit technology (BART) and 

reasonable progress determinations. 

With respect to the BART 

determinations, we understand that 

there is room for disagreement about 

certain aspects of the State’s analyses. 

Furthermore, we may have reached 

different conclusions had we been 

performing the determinations in the 

first instance. However, the comments 

have not convinced us that the State, 

conducting specific case-by-case 

analyses for the relevant units, acted 

unreasonably or that we should 

disapprove the State’s BART 

determinations. 

With respect to the State’s reasonable 

progress determinations, the State 


ebenthall on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 76873 

2Letter from Callie A. Videtich, Director, Air 

Program, EPA Region 8, to Paul Tourangeau, Air 

Director, Colorado Department of Public Health and 

the Environment, October 26, 2010, Re: Regional 

Haze State Implementation Plan. (October 26, 2010 

letter). 

3NPS Comments on Best Available Retrofit 

Technology (BART) Analysis of Control Options for 

Tri-State Generation & Transmission Association, 

Inc.—Craig Station Units 1 & 2, December 1, 2010. 

4The presumptive limit for dry-bottom wall-fired 

EGUs firing bituminous coal is 0.39 lb/MMBtu (70 

FR 39172). 

included emission limits in the SIP that 

reflect reasonable levels of control for 

reasonable progress for this initial 

planning period. Here again, we 

understand that there is room for 

disagreement about the State’s analyses 

and appropriate limits. And, again, we 

may have reached different conclusions 

had we been performing the 

determinations. However, the comments 

have not convinced us that the State, 

conducting specific case-by-case 

analyses for the relevant units, made 

unreasonable determinations for this 

initial planning period or that we 

should disapprove the State’s SIP. 

IV. Issues Raised by Commenters and 

EPA’s Response 

A. NOX BART for Tri-State Craig Unit 1 

and Unit 2 

Comment: We received comments 

that the State and EPA did not follow 

the BART guidelines or otherwise meet 

the intent of the BART requirements 

because the State and we did not 

evaluate the most stringent control 

efficiencies associated with operating 

selective catalytic reduction (SCR). The 

commenters pointed out that State and 

EPA evaluations assumed that SCR is 

capable of achieving 0.07 lb/MMBtu on 

an annual average and 0.07–0.08 lb/ 

MMBtu on a 30-day rolling average. 

Commenters stated that this level 

reflects 74–75% reduction from baseline 

emissions from these units, and SCR is 

well known to be capable of control 

efficiencies greater than 90% and limits 

of 0.05 lb/MMBtu or less on a 30-day 

rolling average. One commenter pointed 

out that in a November 2010 report, TriState’s own consultants evaluated a 0.05 

lb/MMBtu design emission rate for SCR. 

One commenter also pointed out that 

previous statements by EPA and the 

National Park Service (NPS) to the State 

about the Colorado regional haze plan 

reflect this.2 3

One commenter went on to say that if 

an emission rate of 0.05 lb/MMBtu had 

been used to assess the cost of SCR, the 

State would have found the cost to be 

$5,879 per ton of NOX reduced for Unit 

1 and $5,728 per ton of NOX reduced for 

Unit 2. Commenters provided numerous 

examples of electric generating units 

(EGUs) that are achieving or will be 

required to achieve a NOX emission rate 

of 0.05 lb/MMBtu or less on an annual 

and 30-day rolling average. 

Response: We agree that SCR in some 

cases can achieve annual NOX emission 

rates as low as 0.05 lb/MMBtu. 

However, the annual emission rate 

assumed by Colorado, 0.07 lb/MMBtu, 

is within the range of actual emission 

rates demonstrated at similar facilities 

in EPA’s Clean Air Markets Division 

(CAMD) emission database. 

Comment: The proposed emission 

limit of 0.27 lb/MMBtu for selective 

non-catalytic reduction (SNCR) does not 

reflect what is achievable for that 

control technology. The State’s 

technical support document (TSD) 

shows that Craig Unit 1 is already 

meeting an emission rate of 0.27 lb/ 

MMBtu, even without SNCR. 

Furthermore, as noted by EPA in its 

October 26, 2010, letter, SNCR is 

capable of achieving emission 

reductions of 20–30% below baseline. 

This would mean that SNCR would 

actually be capable of achieving an 

emission rate of around 0.20 lb/MMBtu 

or lower at Units 1 and 2, not 0.27 lb/ 

MMBtu. 

Response: We disagree that the State’s 

TSD shows that Craig 1 is already 

achieving a 30-day rolling average 

emission rate of 0.27 lb/MMBtu, even 

without SNCR. The commenter has 

confused actual average annual 

emission rates that Colorado used for 

cost calculations with 30-day rolling 

average emission rates. Colorado’s TSD 

shows that the maximum actual 30-day 

rolling average emission rate during this 

period was 0.304 lb/MMBtu. Therefore, 

Craig 1 is currently operating above, not 

below, the BART emission limit. 

However, we understand that the 

commenter’s larger point is that the 

emission limit for Craig Unit 1 does not 

reflect the level of control that can be 

achieved with SNCR. 

As noted by the commenter, SNCR 

can typically achieve a 20–30% 

reduction after combustion controls. By 

contrast, Colorado assumed that at Craig 

SNCR could achieve a 15% reduction 

after combustion controls. This in turn 

was based on Tri-State’s assertion that 

the Craig BART units can only meet this 

level of control since the effectiveness of 

SNCR is lower for wall-fired boilers 

similar to those at Craig. Under the 

circumstances, we do not find that the 

State’s conclusion was unreasonable. 

Comment: EPA provided no insight as 

to what it considers presumptive BART 

to be for Craig Units 1 and 2. 

Presumptive BART for the Craig units 

should be based on the primary type of 

coal burned there, which is subbituminous. EPA should establish the 

presumptive BART limit for Craig at 

0.23 lb/MMBtu. On this basis, the limits 

proposed by EPA exceed presumptive 

BART. 

Response: The presumptive limits for 

EGUs, which are reflective of 

combustion controls for all but cyclone 

boilers, are clearly stated in the BART 

guidelines. The presumptive limit for 

dry-bottom wall-fired EGUs firing subbituminous coal, such as the Craig 

BART units, is 0.23 lb/MMBtu (70 FR 

39172, July 6, 2005). 

Colorado has stated that the Craig 

BART units fire sub-bituminous coal 

that is ‘‘bituminous-like’’ with respect to 

NOX formation.4 That is, they exhibit 

relatively higher NOX emissions. This is 

supported by actual emissions data, 

which show that the units fail to 

achieve the presumptive limit with the 

existing ultra low-NOX burners and 

overfire air, the same combustion 

controls that EPA assumed for sources 

when it established the presumptive 

limit. The State’s analysis of CEMs data 

in EPA’s CAMD emissions database 

shows an actual maximum 30-day 

rolling average emission rate of 0.304 lb/ 

MMBtu at each unit (2006–2008). Thus, 

we conclude that the presumptive limit 

that applies to Craig—0.23 lb/MMBtu— 

does not provide a meaningful 

benchmark for evaluating the State 

selected limits at Craig. Furthermore, 

our BART guidelines are clear that the 

BART analysis may result in a limit that 

differs from the presumptive limit. 

Comment: One of the options 

suggested by the BART Guidelines to 

evaluate cost effectiveness is cost/ 

deciview. Applying the cost/deciview 

metric to SCR at Craig yields about $10 

million/deciview for Mt. Zirkel and $2.6 

million/deciview on a cumulative basis. 

Both values are reasonable when 

compared to the national average of 

$14–$18 million/deciview. 

Response: The BART Guidelines 

require that cost effectiveness be 

calculated in terms of annualized 

dollars per ton of pollutant removed, or 

$/ton (70 FR 39167). The commenters 

are correct in that 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, the State 

was not required to use this metric. We 

do not generally recommend the use of 

this metric as it can be complicated to 

use and the results can be difficult to 

assess. We also note that the $/deciview 

metric has not been widely used as a 

comparative tool. It is sufficient to 

analyze the cost effectiveness of 


ebenthall on DSK5TPTVN1PROD with 
76874 Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 

5The overnight cost method represents the cost 

of building the plant as if all the supplies could be 

purchased and all the labor paid within a very short 

period of time. In contrast, when forecasting 

revenue requirements for environmental retrofits, 

utilities typically attempt to estimate the costs that 

would actually be reflected in their future rate cases 

as a result of the retrofits in what is known as the 

‘‘all in’’ method. According to commenters, the 

results from these two cost calculating methods 

cannot and should not be compared. Commenters 

also asserted the following: (1) Relative to the EPA 

CCM, the utility method typically overstates the 

cost of control per ton of avoided emissions by 

about 36%; and (2) National consistency in cost 

allocation method is necessary to ensure that no 

company or state receives an economic advantage 

by using a different cost method. 

6According to commenters, this cost is not 

allowed because Tri-State is not a rate-regulated 

utility and the AFUDC cost is not already included 

in the base case, as per a utility commission 

decision. 

7For the highest-performing NOX postcombustion control options (i.e., SCR systems for 

EGUs) that do not exceed $5,000/ton of pollutant 

reduced by the State’s calculation, and which 

provide a modeled visibility benefit of 0.5 deciview 

or greater at the primary Class I Area affected, the 

State views that level of control as generally 

reasonable. For lesser-performing NOX postcombustion control options (e.g., SNCR 

technologies for EGUs) that do not exceed $5,000/ 

ton of pollutant reduced by the State’s calculation, 

and which provide a modeled visibility benefit of 

0.2 deciview or greater at the primary Class I Area 

affected, the State views that level of control as 

generally reasonable. 

potential BART controls using $/ton, in 

conjunction with an assessment of the 

modeled visibility benefits of the BART 

control. 

Comment: Because the control 

efficiency for SCR was underestimated, 

the visibility benefits from SCR are 

underestimated by the modeling. 

Response: We disagree with this 

comment. As stated above, while we 

recognize that lower annual emission 

rates for SCR have been demonstrated at 

some facilities, the annual emission rate 

of 0.07 lb/MMBtu assumed by Colorado 

in estimating the costs and benefits of 

SCR is within the overall range for 

similar facilities in EPA’s CAMD 

emission database. Given this, we find 

that it was not unreasonable for 

Colorado to use 0.07 lb/MMBtu to 

model the predicted visibility 

improvement from SCR. 

Other Comments: A number of 

commenters objected to our proposed 

approval of the State’s BART 

determination for Craig Unit 1 on other 

grounds and asserted that the State 

should have selected SCR as BART. 

These commenters articulated several 

bases for their comments. The 

comments fall into four main categories, 

as follows: 

(1) Costs 

We received numerous comments that 

the State, relying on Tri-State’s cost 

analysis, significantly overestimated 

capital costs for SCR at Craig Unit 1 and 

Unit 2, and that EPA did not conduct a 

detailed review of Tri-State’s cost 

analysis. Commenters cited numerous 

sources to show that the expected 

capital costs for SCR at Unit 1 and Unit 

2 should be lower than what Tri-State 

assumed in its cost estimates. 

Commenters noted limited or missing 

information, such as lack of vendor 

quotes or detailed cost estimates. 

According to a commenter, this type of 

information is necessary for the public 

or other agencies to be able to 

thoroughly review and comment on the 

proposed determinations. According to 

commenters, the absence of this 

underlying information renders EPA’s 

proposed approval of the BART 

determinations for these sources 

arbitrary. Commenters said that, to the 

extent that the State or EPA relied on 

such information, failure to include it in 

the docket further illegally impaired and 

deprived the public of its notice and 

comment rights, by concealing 

important grounds for the proposed 

action and preventing the public from 

examining and offering meaningful 

comment thereon. 

Commenters noted several items in 

Tri-State’s and the State’s cost analyses 

that are not allowed by or are 

inconsistent with EPA’s Control Cost 

Manual (CCM). According to 

commenters, Tri-State and the State: (1) 

Disregarded EPA’s cost method, often 

referred to as the ‘‘overnight cost 

method;’’ 5 (2) included Allowance for 

Funds During Construction (AFUDC);6

(3) used escalation, which is 

inappropriate and generally not 

allowed; (4) included lost generation 

costs with no support or justification for 

the costs, the duration of outages 

needed, and why time beyond normal 

scheduled outages would be necessary; 

(5) provided no justification for the 

inclusion of owner’s costs as 10% of the 

direct cost; (6) included a 50-hour 

workweek in their cost estimate without 

any justification; (6) included no 

consideration of the cost savings when 

controls like SCR are applied to 

multiple units at the same facility; and 

(7) used an unrealistic equipment life 

and interest rate. 

Commenters provided revised cost 

analyses for SCR at Craig Units 1 and 2. 

One commenter calculated that a more 

accurate cost effectiveness value would 

be no higher than $3,460/ton and 

$3,370/ton at Unit 1 and Unit 2, 

respectively. Another commenter 

calculated that average costs would be 

$2,209/ton for Unit 1 and $1,962/ton for 

Unit 2. Commenters pointed out that 

these costs were below the threshold 

established by the State for choosing 

SCR. 

(2) Visibility Improvement 

Commenters point out that EPA only 

provides the impacts to the most 

impacted Class I area, Mt. Zirkel, and 

that the cumulative impact of a source’s 

emissions on visibility, as well as the 

cumulative benefit of emission 

reductions, is a necessary consideration 

as part of the fifth step in the BART 

analysis. Commenters provided 

examples where other EPA regions 

(Region 6 and Region 9) have 

considered cumulative visibility 

benefits. The NPS performed modeling 

and submitted the results as part of its 

comments. NPS modeling shows that 

the cumulative visibility impact from 

Craig Units 1 and 2 is 17.61 deciviews, 

while SCR at both units would provide 

a cumulative visibility improvement of 

8.99 deciviews. The modeling also 

shows that SCR at both units would 

achieve at least a 0.5 deciview 

improvement at each of five Class I 

areas. 

(3) Determination of BART 

Commenters identified numerous 

issues with the State’s determination of 

BART and consideration of the five 

factors. First, commenters pointed out 

that the State relied on a predetermined 

set of thresholds applicable only to postcombustion NOX controls for 

determining what is BART,7 and that 

the State attempted to justify this by a 

short discussion of its belief that ‘‘the 

costs of control should have a 

relationship to visibility improvement.’’ 

According to commenters, the State 

articulated no governing principle or 

rational explanation for how it 

considered the five factors within the 

context of this threshold. 

Commenters asserted that EPA, in its 

October 26, 2010, comment letter to 

Colorado, anticipated some of the 

reasons the State’s threshold is 

untenable. One commenter went on to 

say that in the unlikely scenario that the 

appropriate cost of SCR at Craig Units 

1 and 2 is in fact above $5,000/ton, the 

State’s criteria ‘‘preclude a reasonable 

weighing of the five factors,’’ as EPA 

had foretold. Commenters indicated that 

EPA relied on the State’s vague and 

unsubstantiated criteria without 

resolving or even discussing its prior 

concerns. 

Commenters noted that the Craig 

analysis presented data for each of the 

five BART factors, but pointed out that 

when it came to the crux of the BART 

determination, the actual weighing of 

the factors, EPA’s proposed rulemaking 

failed to explain how EPA determined 


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that costs were unjustified in light of 

anticipated visibility benefits and the 

other considerations. As such, 

commenters said that EPA had failed to 

require a reasoned basis for weighing 

the five factors in the Craig BART 

analysis and determination. One 

commenter went on to say that to 

comply with the Administrative 

Procedure Act, the Agency must provide 

a reasoned basis for its BART 

determination, including a reasonable 

explanation why certain benefits do not 

justify certain costs, why EPA’s chosen 

methods for evaluating costs and 

benefits are appropriate, and what 

significance the Agency has accorded to 

each of the five BART factors. The 

commenter argued that EPA’s failure to 

identify its method of decision making 

amounts to an arbitrary decision. 

One commenter stated that it was 

concerned that, although the State 

found SCR to be reasonable as BART for 

Craig Unit 2, it found the control 

technology to be unreasonable for Unit 

1, even though according to the five 

factors, it would meet the same 

reasonability threshold as for Unit 2. 

Notably, the State found the cost of SCR 

for Unit 2, $5,728 per ton of NOX

reduced, to be reasonable as it was 

ultimately adopted as BART. 

(4) BART Alternative 

Commenters pointed out that the 

Craig BART alternative fails to provide 

for greater reasonable progress than 

would be achieved if an adequate 

source-specific BART limit were 

required of both subject-to-BART Craig 

units. Commenters went on to say that 

BART should have been SCR on both 

Craig units and thus, the BART 

alternative of SNCR on Unit 1 and SCR 

on Unit 2 is not better than BART. 

According to commenters, given that 40 

CFR 51.308(e)(2)(C) requires states to 

make a BART determination for any 

source subject to an alternative to 

BART, the State’s flawed BART analysis 

fails to support an alternative to BART 

pursuant to EPA regulations. 

Response: While we agree with some 

aspects of the commenters’ assertions in 

these four categories, we disagree with 

others and ultimately conclude that 

Colorado’s plan achieves a reasonable 

result overall. We acknowledged in our 

October 26, 2010, comment letter to the 

State that the cost analysis was not 

conducted by Colorado in accordance 

with EPA’s Control Cost Manual, and 

we agreed that the costs for SCR at Craig 

Units 1 and 2 appeared to be 

substantially overestimated, which the 

commenters also pointed out. In 

addition, as we suggested during the 

State’s public comment period, the State 

should have more thoroughly 

considered the visibility impacts of 

controlling emissions from Craig 1 on 

the various impacted Class I areas and 

not just have focused on the most 

impacted Class I area. 

EPA acknowledges that Colorado’s 

approach appears to be a novel and 

comprehensive strategy for addressing 

regional haze requirements and other air 

quality goals. In 2010, the Colorado 

General Assembly adopted legislation 

authorizing the Air Quality Control 

Commission and the Public Utilities 

Commission to develop a 

comprehensive plan for coal-fired 

electric generating units in the state that 

would address not only regional haze 

but also potential new ozone standards 

and mercury standards, as well as other 

requirements that, in the State’s view, 

could apply to coal-fired electric 

generation units in the foreseeable 

future. The State desired to address 

these issues in a coordinated way in 

order to achieve the most cost-effective 

strategy that accounted for not only 

current, but other imminent regulatory 

requirements. This approach appears to 

be unique and, as noted below, will 

yield significant emissions reductions 

not only of pollutants that affect 

visibility in Class I areas, but also 

significant reductions in pollutants that 

contribute to ozone formation, nitrogen 

deposition, and mercury emissions and 

deposition. The State spent considerable 

time and conducted sequential and 

extended hearings to develop a plan 

which seeks to balance a number of 

variables beyond those that would be 

involved in a simpler and narrower 

regional haze determination. 

Colorado’s BART requirements for the 

Craig units reflect a balance struck by 

Tri-State Generation & Transmission 

Association, Inc. and several 

environmental groups before the 

Colorado Air Quality Control 

Commission during an extensive and 

formal proceeding; at the conclusion of 

the proceeding, the Commission 

adopted the agreement reached by TriState and those environmental groups as 

part of Colorado’s regional haze plan. As 

a result, the plan requires installation of 

SCR at one of the two Craig BARTeligible units even though the 

Commission previously had concluded 

that installation of SCR was not 

warranted at either unit. In addition, we 

note that Colorado has imposed SCR as 

BART on two other EGUs in western 

Colorado—Hayden Units 1 and 2—and 

at the Pawnee plant in eastern Colorado. 

Moreover, Colorado has exceeded the 

minimum requirements for BART and 

reasonable progress for sources included 

in the PSCO BART Alternative (as 

described in our notice of proposed 

rulemaking, 77 FR 18073–18075), and 

has imposed substantial and meaningful 

controls, that go beyond what EPA’s 

regulations otherwise might have 

required, to address reasonable progress 

sources for the initial planning period. 

Under the unique circumstances 

discussed above, EPA concludes that 

Colorado’s plan achieves a reasonable 

result overall. Based on this, we are 

approving the entirety of the Colorado 

regional haze SIP, even though the 

State’s BART analysis for Craig 1 only 

analyzed visibility impacts at the most 

impacted Class I area and appears to 

overestimate the costs of SCR controls. 

We expect Colorado to revisit the 

appropriateness of SCR controls on 

Craig Unit 1 in the next reasonable 

progress planning period. 

Finally, we note that the State’s plan 

will result in NOX emission reductions 

of 34,774 tons per year, SO2 emission 

reductions of 35,776 tons per year, and 

PM reductions of 532 tons per year. As 

many of the NOX emission reductions 

will occur along Colorado’s Front 

Range, the State’s plan should help 

reduce ozone levels in Colorado’s ozone 

non-attainment area and nitrogen 

deposition in Rocky Mountain National 

Park. In addition, portions of Colorado’s 

plan includes retirement and fuelswitching of existing coal-fired units, 

resulting in significant reductions of 

emissions of mercury into the 

atmosphere at levels that exceed what a 

straightforward application of emission 

reduction technology to satisfy BART 

and reasonable progress would have 

conferred on sources throughout the 

state. 

B. NOX BART Determination for Martin 

Drake Units 5, 6, and 7 

Comment: The NOX BART 

determination for Martin Drake 

underestimates the control efficiency of 

SCR. A conservative, but more 

appropriate control efficiency would be 

an annual average of 0.05 lb/MMBtu. 

This would result in additional 

reductions of 41, 69, and 105 tons of 

NOX per year at Units 5, 6, and 7, 

respectively. This would also result in 

larger modeled visibility benefits. 

Response: We agree that at some 

facilities, SCR has achieved annual NOX

emission rates as low as 0.05 lb/MMBtu; 

however, the annual emission rate of 

0.07 lb/MMBtu assumed by Colorado in 

estimating the costs and benefits of SCR 

is within the range of actual emission 

rates demonstrated at similar facilities 

in EPA’s CAMD emission database. 

Given this, we find that it was not 

unreasonable for Colorado to use 0.07 

lb/MMBtu to model the predicted 


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8See Colorado Department of Public Health and 

Environment, Operating Permit, Trigen-Colorado 

Energy Corporation Golden Facility (Feb. 1, 2003). 

Attached as Exhibit 1 to the comment. 

visibility improvement from SCR. 

Moreover, while we do agree that 

assuming a control efficiency of 0.05 lb/ 

MMBtu would have resulted in greater 

modeled visibility benefits, we do not 

agree that the difference in visibility 

benefits would have led Colorado to a 

different conclusion given the 

magnitude of the benefits associated 

with SCR. 

Comment: The costs of SCR were 

overestimated in the Martin Drake 

analysis in the following ways: (1) The 

SCR costs were estimated using the 

Integrated Emissions Control Cost 

(IECCOST) model, not the CCM as 

required by the BART Guidelines; (2) 

the calculated costs included items that 

are expressly disallowed or typically 

excluded when following the CCM 

methodology, including royalties, initial 

catalyst and chemicals, and escalation. 

These costs add millions of dollars to 

the total amount attributed to SCR; (3) 

the $/kW costs were extremely high. 

While SCR retrofits typically range from 

$83—$300/kW, including the most 

complex and space constrained projects, 

the costs for the Martin Drake units 

were $558/kW, $448/kW, and $325/kW, 

for Units 5, 6, and 7, respectively; and 

(4) the analysis did not consider the cost 

savings when controls like SCR are 

applied to multiple units at the same 

facility. This discount is on the order of 

4–10%. 

Response: We agree with several 

points in this comment. In fact, we 

raised many of the same issues related 

to cost analysis in our October 26, 2010, 

comment letter to the State. However, 

we note that Colorado eliminated SCR 

from consideration for the Martin Drake 

BART units primarily on the basis of the 

level of visibility improvement. The 

visibility improvement associated with 

SCR at Units 5, 6, and 7, is 0.12, 0.27, 

and 0.37 deciviews, respectively. In 

addition, as the State noted, the 

incremental visibility improvement 

from SCR versus ultra-low NOX burners 

and overfire air (the control technology 

upon which the State’s NOX BART 

limits are based) is even lower—0.04, 

0.07, and 0.11 deciview, respectively, at 

Units 5, 6, and 7. The State concluded 

that lower costs would not change its 

BART determination. Based on these 

visibility improvement values and the 

expectation that cost effectiveness 

values for SCR calculated in accordance 

with the CCM would still be relatively 

high compared to the selected control 

option, we find that the State’s NOX

BART determination for Martin Drake 

Units 5, 6, and 7 was reasonable. 

Comment: A cost analysis consistent 

with the CCM would indicate that SCR 

is cost effective for the Martin Drake 

units. A revised costs analysis would 

show that the revised cost effectiveness 

for SCR is under the State’s $5000/ton 

threshold. 

Response: The commenter did not 

provide sufficient data or analysis to 

support this assertion regarding a 

revised cost analysis. Regardless, for the 

reasons stated above, we conclude that 

the State’s BART determination was 

reasonable. Even if a control technology 

is arguably cost-effective on a dollar per 

ton basis, a State may conclude that the 

control technology is not warranted 

based on a consideration of all BART 

factors. 

Comment: EPA failed to consider the 

cumulative visibility benefits on all of 

the impacted Class I areas. Additionally, 

the predicted improvement for SCR at 

the most affected Class I area, at least 

0.12 deciview, 0.27 deciview, and 0.37 

deciview, for Units 5, 6, and 7, 

respectively, are not insignificant. 

Response: While we agree that 

Colorado should have considered 

impacts to the various impacted Class I 

areas, we have no reason to believe that 

the cumulative visibility benefits would 

warrant a change in our approval of the 

State’s NOX BART determination for 

Martin Drake Units 5, 6, and 7. 

Regarding the predicted improvement at 

the most affected Class I area, while we 

agree that the levels are not 

insignificant, they are not significant 

enough for us to conclude that the 

State’s BART determination was 

unreasonable, particularly when the 

incremental visibility improvement and 

expected costs of SCR are considered. 

Comment: Cost-effective visibility 

benefits were rejected as a result of 

Colorado’s criteria that holds postcombustion controls and SCR in 

particular to a higher standard of 

visibility benefits. As EPA itself 

previously pointed out in its October 26, 

2010, letter: ‘‘* * * the criteria appear 

to discriminate against SCR as a 

potential control option. Under the 

criteria, if the cost of SCR is under 

$5,000/ton and the modeled visibility 

benefit is 0.20 delta-deciview or greater 

but less than 0.50 delta-deciview, the 

State would reject SCR. Using the 

State’s criteria, the State would find 

SNCR reasonable with the same $/ton 

and delta-deciview values. We are not 

aware of a valid basis for applying 

different criteria to the two control 

options.’’ 

This example proves EPA’s point. By 

this logic, if the evaluated technology in 

this instance were SNCR instead of SCR, 

it would be BART for at least Units 6 

and 7, and possibly Unit 5. We concur 

with EPA’s previous critique: this 

distinction has no basis and is 

untenable. 

Response: While we do not 

necessarily agree with the State’s 

criteria for post-combustion controls, we 

find the State’s NOX BART 

determination for Martin Drake Units 5, 

6, and 7 to be reasonable within the 

context of the five factors for the reasons 

stated above. 

C. BART Determination for Colorado 

Energy Nations (CENC) Unit 4 and Unit 

5 

Comment: In determining BART for 

Units 4 and 5, the State failed to identify 

and analyze alternative fueling 

scenarios that would lead to greater 

reductions in NOX, sulfur dioxide (SO2), 

and particulate matter. The proposed 

rule notes, and the underlying record 

clearly explains, that Units 4 and 5 are 

capable of burning (and do in fact burn) 

fuels other than coal. In particular, the 

proposed rule states that Unit 4 can and 

does burn natural gas or fuel oil and that 

Unit 5 can and does burn fuel oil. Both 

boilers may fire ethanol or sludge from 

the Coors Brewery. 

Despite this, the State did not assess 

whether alternative fueling scenarios, 

such as a full or partial shift from coal 

to natural gas or fuel oil at Units 4 and 

5 would represent BART. This is a 

concern because according to the CAA 

Title V Operating Permit for the facility, 

both Units 4 and 5 could meet stronger 

SO2 and NOX emission rates than have 

been proposed by the State as BART. 

The operating permit shows that the 

permitted emission rates for Units 4 and 

5, when firing natural gas and/or fuel 

oil, are already lower than the proposed 

BART emission rates.8 Given that 

permitted emission rates are higher than 

actual emissions, this means that the 

facility is most likely capable of 

achieving far greater emission 

reductions under an alternative fueling 

scenario. Indeed, for Unit 4, whether 

firing natural gas or fuel oil, both 

permitted SO2 and NOX emission rates 

are lower than the proposed BART 

limits. For Unit 5, when firing fuel oil, 

the permitted SO2 emission rate is lower 

than proposed BART. Furthermore, 

although the permitted NOX emission 

rate for Unit 5 when firing fuel oil is 

higher than the proposed BART, it is 

based on a 3-hour average (as opposed 

to a 30-day average) and even then, 

actual emissions are likely to be lower 

than the proposed BART 

Here, alternative fueling scenarios, 

such as a full or partial shift away from 


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9The State sent an email to EPA Region 8 on July 

16, 2012 containing its cost estimates for fuel 

switching. The cost analysis can be found in the 

docket. 

10See Armendariz, A, The Costs and Benefits of 

Selective Catalytic Reduction on Cement Kilns for 

Multi-Pollutant Control and the Applicability to the 

CEMEX Lyons Cement Plant (February 15, 2008) at 

19. This report is attached as Exhibit 2 to this 

comment. 

11See Letter from Armendariz, A. to Dann, C. in 

re: SCR and Cement Kilns (July 22, 2008). This 

letter is attached as Exhibit 3 to this comment. 

coal to fuels that are already being 

burned in Units 4 and 5 (including 

natural gas and fuel oil) both seem to 

represent the ‘‘best system of 

continuous emission control 

technology’’ and seem entirely 

reasonable when considering the five 

factors required to be assessed by states 

when determining BART. The State 

failed to analyze alternative fueling in 

its SIP. Alternative fueling is an 

available technology that should have 

been analyzed by the State given that 

the visibility benefits to Class I areas 

could be tremendous. Although the 

State purported to identify ‘‘all available 

technologies’’ in its BART analysis, 

clearly it did not identify all available 

technologies. 

The failure to analyze alternative 

fueling scenarios is especially confusing 

because the State did, apparently, 

identify in its TSD for the CENC facility 

a fuel switch to natural gas as an 

available technology and in analyzing 

‘‘SO2 Emissions Management’’ as 

potential BART, noted that an option to 

reduce emissions could involve a 

‘‘dispatch [of] natural gas-fired 

capacity.’’ There is, however, no 

explanation in the TSD as to why ‘‘fuel 

switching,’’ or otherwise increased 

reliance on natural gas, would not 

constitute BART or would be contrary to 

the five factors required to be 

considered in establishing BART under 

the CAA. 

The failure to analyze alternative 

fueling scenarios is further confusing 

because the EPA’s BART guidelines 

indicate that alternative fueling 

scenarios should be analyzed by states 

when determining BART. The 

guidelines specifically state that 

‘‘potentially applicable retrofit control 

alternatives’’ can include the ‘‘use of 

inherently lower-emitting processes/ 

practices’’ or ‘‘combinations of 

inherently lower-emitting processes and 

add-on controls.’’ Appendix Y at 

Section IV.D.3. Above all, states should 

‘‘identify potentially applicable retrofit 

technologies that represent the full 

range of demonstrated alternatives.’’ Id. 

The guidelines clearly indicate that 

inherently ‘‘lower-emitting processes,’’ 

such as alternative fueling, are squarely 

within the realm of what may be 

considered BART. 

Given the State’s failure to take into 

consideration an available technology, 

the EPA must disapprove the BART 

determinations for CENC Units 4 and 5 

and in accordance with the CAA 

promulgate a FIP that establishes BART 

limits based on a full consideration of 

alternative fueling scenarios. 

Response: Although the State did not 

present the information in the SIP and 

was not required to analyze such 

scenarios, the State in fact analyzed 

alternative fueling scenarios for Unit 4 

and Unit 5.9 The State examined fuel 

switching to a number of different fuels. 

The State determined that Units 4 and 

5 are not capable of burning wood or 

other biomass fuels and the use of 

sludge as the primary fuel is not 

technically feasible due to handling and 

storage issues. The State determined 

residual oil, distillate oil, ethanol, and 

natural gas were technically feasible 

options. 

The State determined residual oil 

would not result in pollutant 

reductions, and that distillate oil, 

ethanol, and biodiesel are high cost 

fuels for boilers of this size, with prices 

about two to three times the cost of 

natural gas, and six to seven times the 

cost of coal (at the time of analysis— 

December 2009) and highly volatile. 

Thus, the State eliminated these fuels 

from further consideration. 

Furthermore, the State determined the 

cost effectiveness of fuel-switching to 

natural gas for SO2 and NOX control for 

Units 4 and 5. The State determined the 

costs for fuel switching to natural gas for 

SO2 would be $29,985/ton removed for 

Unit 4 and $30,945/ton removed for 

Unit 5. The State determined the costs 

for fuel switching to natural gas for NOX

would be $64,102/ton removed for Unit 

4 and $82,834/ton removed for Unit 5. 

Because of the high cost effectiveness 

values, the State did not perform any 

visibility modeling for fuel switching to 

natural gas and the State eliminated it 

from further consideration for BART. 

We have reviewed the State’s cost 

calculations and find them reasonable. 

Based on the above statement from 

our BART guidelines, and based on the 

State’s analysis, we agree with the 

State’s conclusion that fuel switching to 

natural gas is not BART at CENC Units 

4 and 5. 

D. NOX BART Determination for Cemex 

Lyons Kiln 

Comment: Colorado did not 

appropriately analyze whether SCR was 

reasonable as BART for the kiln at the 

Cemex Lyons cement plant. In 

particular, the State rejected SCR as not 

an available technology. EPA itself did 

not agree with this finding. Despite this, 

EPA allowed the State to reject SCR due 

to perceived uncertainty over its cost 

effectiveness. However, because the 

State rejected SCR as an available 

technology, no analysis of the costs of 

SCR was actually undertaken and 

therefore, EPA’s claims are baseless. 

SCR has been an available emission 

control technology for NOX emissions 

for many years. Although its use on 

cement kilns has come about recently, 

several sources indicate that the 

technology is available and costeffective, contrary to claims by the State. 

A report commissioned by Rocky 

Mountain Clean Air Action, which later 

merged with WildEarth Guardians, 

found that SCR ‘‘is an effective and 

proven technology to reduce nitrogen 

oxide emissions from cement kilns.’’ 10

The report concluded that: ‘‘The 

installation of SCR on the [Cemex] 

Lyons Cement Plant could be expected 

to achieve substantial reductions (85– 

95%) in emissions of NOX.’’ The report 

also found that the cost effectiveness of 

utilizing SCR ranges between $1,500 

and $3,800 per ton of NOX reduced, 

which is ‘‘easily within regulatory cost 

thresholds for many NOX control 

programs.’’ Follow up correspondence 

from the author of the report, Dr. 

Armendariz to the State further 

confirmed that SCR was available and 

cost-effective.11

EPA cannot come to conclusions on 

the cost effectiveness of SCR without 

analytical support, and there is no 

support for approving the State BART 

determination for the Cemex Lyons 

cement kiln. We request the EPA 

promulgate a FIP that objectively and 

thoroughly analyzes SCR as an available 

technology for purposes of establishing 

BART limits for the Cemex Lyons 

cement kiln. 

Response: We disagree with this 

comment and stand by the rationale 

presented in our proposal (77 FR 

18062). As we said there, we accept the 

State’s decision, not to analyze SCR 

further for the purposes of regional 

haze. EPA has acknowledged, in the 

context of establishing the New Source 

Performance Standards (NSPS) for 

Portland Cement Plants, substantial 

uncertainty regarding the cost 

effectiveness associated with the use of 

SCR at such plants (75 FR 54995). In 

particular, while EPA noted that SCR 

had been used at three cement kilns in 

Europe, and had been agreed to by one 

domestic cement kiln as part of a 

settlement, EPA also noted the potential 

for dust buildup on the catalyst, ‘‘which 


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76878 Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 

12The State indicated that CEMEX consulted four 

potential SCR vendors but was unable to obtain 

meaningful quotes from any of them. 

[could] be influenced by site specific 

raw material characteristics present in 

the facility’s proprietary quarry, such as 

trace contaminants that may produce a 

stickier particulate than is experienced 

at sites where the technology has been 

installed.’’ Id. at 54994, 54995. EPA 

went on to state in the NSPS rulemaking 

that ‘‘[t]his buildup could reduce the 

effectiveness of the SCR technology, and 

make cleaning of the catalyst difficult 

resulting in kiln downtime and 

significant costs.’’ Id. Because of the 

uncertainty, EPA was unable to estimate 

these costs. Id. For the reasons stated in 

our NSPS rulemaking and in the State’s 

regional haze SIP, there is also 

substantial uncertainty regarding the 

costs and control effectiveness of SCR at 

Cemex. We are not convinced that cost 

and control effectiveness information 

from the European plants or from SCR 

applications at other types of sources is 

sufficiently reliable to guide a BART 

determination for Cemex.12 Under the 

circumstances, we find that Colorado 

reasonably eliminated SCR as a 

potential BART control technology. As 

we stated in our proposal, we expect the 

State to reevaluate SCR technology in 

subsequent reasonable progress 

planning periods as more information 

regarding the use of SCR at cement kilns 

becomes available. 

E. NOX BART Determination for 

Comanche Unit 1 and Unit 2 

Comment: Comanche Units 1 and 2 

are currently meeting lower NOX

emission rates than the emission limits 

the State proposed for BART. With 

regard to the proposed BART limits, the 

State has proposed, and EPA has 

proposed to approve, a 30-day emission 

rate for Units 1 and 2 of 0.20 lb/MMBtu 

and a combined annual average 

emission rate of 0.15 lb/MMBtu for 

Units 1 and 2. According to the State, 

these limits will be met with no 

additional controls on Unit 1 or Unit 2. 

The State’s own BART analysis notes 

that currently Unit 1 is emitting at an 

average annual rate of 0.124 lb/MMBtu 

and Unit 2 is emitting at an average 

annual rate of 0.165 lb/MMBtu. This 

means that both on a 30-day rolling 

average basis and on an annual average 

basis, both units are capable of emitting, 

and indeed do emit, at rates below the 

proposed BART limits of 0.20 lb/ 

MMBtu on a 30-day rolling average and 

0.15 lb/MMBtu on an annual basis. In 

essence, Colorado’s BART proposal 

actually allows Comanche Units 1 and 

2 to emit more pollution than what they 

currently emit. 

Under the State’s proposed BART, 

emissions will be allowed to increase on 

an annual basis. Using annual heat 

input totals from the baseline year of 

2009 obtained from the EPA’s Air 

Markets Program Data Web site 

(24,247,113.27 MMBtu for unit 1 and 

27,423,612.26 MMBtu for unit 2) and 

using the proposed annual combined 

average BART limits, it appears that 

under the annual BART limits, NOX

emissions will be allowed to increase by 

at least 14 tons per year (tpy). 

Concerning the 30-day rolling average 

limits, there will definitely be allowed 

emission increases. During the baseline 

year of 2009, both Comanche Unit 1 and 

Unit 2 emitted far lower than the 

proposed BART limit of 0.20 lb/MMBtu. 

During the baseline year of 2009, 30-day 

rolling average NOX emissions were 

consistently far below 0.20 lb/MMBtu 

for the year. Even the peak 30-day 

rolling averages of 0.142 and 0.179 lb/ 

MMBtu for Units 1 and 2, respectively, 

are below the proposed limit. Based on 

this, the proposed BART would actually 

allow Unit 1 to emit at least 40% more 

NOX than the baseline 30-day rolling 

average peak and Unit 2 to emit 12% 

more NOX. However, this is just in the 

context of the baseline peak 30-day 

rolling average. In all reality, actual 30- 

day rolling average emission will 

remain even further below the proposed 

BART limit of 0.20 lb/MMBtu. 

Clearly, Comanche Units 1 and 2 

could easily meet lower emission limits 

as BART. We do not suggest that the 

State was required to set the emission 

limits exactly at the levels emitted, but 

clearly when the data demonstrates that 

Unit 1 could meet a 30-day rolling 

average NOX emission limit of 0.15 lb/ 

MMBtu and Unit 2 could meet a limit 

of 0.18 lb/MMBtu without any trouble, 

the BART limits should reflect what is 

achievable. 

Although the State and the EPA may 

claim the proposed limits are necessary 

to provide a margin or cushion of 

compliance, nothing in the CAA or the 

EPA’s regulations suggests that it is 

appropriate to build in such margins or 

cushions into BART limits, especially 

given that BART must represent that 

‘‘best system of continuous emission 

reduction.’’ If Comanche Units 1 and 2 

can do better, than clearly, the proposed 

BART limits are not the best. Nothing in 

the CAA or the EPA’s regulations 

implementing the regional haze program 

suggest or remotely imply that a state 

could allow emission increases as 

BART. 

Accordingly, EPA must disapprove of 

Colorado’s NOX BART determinations 

for Comanche Unit 1 and Unit 2 and 

adopt a FIP that establishes BART limits 

that are consistent with the CAA and 

that represent actual emission 

reductions. 

Response: In our October 26, 2010, 

comment letter to Colorado, we asked 

Colorado to evaluate tightening 

Comanche’s NOX limits as potential 

BART. As discussed in Colorado’s 

BART analysis for the Comanche units, 

Colorado did in fact evaluate emission 

limit tightening in response to our 

concerns. Colorado subsequently 

concluded that a 0.20 lb/MMBtu 30-day 

rolling average emission limit was 

necessary to account for uncertainty 

regarding load fluctuations, coldweather operating, start-up, and cycling 

for renewable energy. Colorado noted 

that greater future reliance on renewable 

energy will lead to increased cycling of 

the Comanche units and more frequent 

start-ups. This in turn may lead to 

increased emissions over shorter 

averaging periods compared to past 

actual emissions. Colorado also noted 

the limited amount of actual emissions 

data for the two units since controls 

were installed for SO2, and the same is 

true for NOX. Thus, while Colorado 

established an annual NOX BART limit 

of 0.15 lb/MMBtu that is lower than the 

average actual emissions of 0.16 lb/ 

MMBtu for Units 1 and 2 between 

January and October 2010, Colorado 

allowed greater leeway in the 30-day 

rolling average limit than would result 

from the strict application of a 15% 

buffer to 0.16 lb/MMBtu (0.20 lb/ 

MMBtu versus 0.184 lb/MMBtu). Given 

some of the uncertainties regarding 

future operations and emissions, we 

have determined that the State acted 

reasonably in setting the emission limits 

for Comanche Units 1 and 2. We also 

note that commenter’s own analysis 

suggests that the difference in annual 

emissions between maximum emissions 

under the BART limit using 2009 heat 

inputs and 2009 actuals would only be 

14 tons per year. This is not significant 

when compared to Comanche’s annual 

NOX emissions of approximately 3,860 

tons; it does not warrant disapproval 

and a subsequent FIP. 

In addition, Comanche’s actual 

emissions following the installation of 

low NOX burners and over-fire air 

occurred under permit limits that are 

identical to those the State selected as 

BART. The commenter has provided no 

evidence that the State’s adoption of the 

same limits as BART limits will cause 

an increase in actual emissions. 

Comment: The State failed to assess 

appropriately the cost of SCR. In 

particular, the State assumed that SCR 

would achieve an emission rate of 0.07 


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lb/MMBtu. However, as EPA itself noted 

in its October 26, 2010, comment letter 

to the State, SCR does achieve emission 

rates as low as 0.04 lb/MMBtu on an 

annual basis, and a 0.05 lb/MMBtu 

emission rate is a more appropriate 

benchmark from which to assess the 

cost effectiveness of SCR. 

In this case, the State did not assess 

the cost effectiveness of SCR based on 

a rate of 0.05 lb/MMBtu. Thus, it did not 

reasonably take into account the cost of 

compliance with SCR in accordance 

with the CAA. Without an adequate 

case-specific cost analysis, there is 

simply no support for concluding SCR, 

particularly for Unit 2, is unreasonable. 

Response: As stated above, we agree 

that SCR has in some cases achieved 

annual NOX emission rates as low as 

0.05 lb/MMBtu, the emission rate that 

commenters suggest would have been a 

more appropriate benchmark in 

assessing the costs of SCR at 

Commanche; however, the 0.07 lb/ 

MMBtu annual emission rate assumed 

by Colorado in estimating the costs and 

visibility benefits associated with SCR is 

within the range of actual emission rates 

demonstrated at similar facilities in 

EPA’s CAMD emission database. 

Moreover, as with Martin Drake, we do 

not believe that if Colorado had used a 

more stringent emission rate that the 

impact on the BART analysis would 

have led Colorado to a different 

conclusion given the magnitude of the 

benefits associated with SCR. Given 

this, we conclude that the State’s use of 

0.07 lb/MMBtu to evaluate the cost 

effectiveness of SCR at Comanche was 

not unreasonable. 

Comment: The State appears to have 

overestimated the capital cost of SCR. 

Both the EPA and the NPS previously 

commented to the State that the State 

should have used the EPA’s CCM and 

noted that the CUECost model relied 

upon by the State is not appropriate. 

Nowhere in the record does the State 

explain why CUECost was reasonable, 

particularly in light of the concerns 

expressed by the EPA and the NPS. It 

appears that the reliance on CUECost 

led to artificially inflated capital costs, 

which in turn overestimated the true 

cost of SCR. 

Response: We agree that there were 

flaws in Colorado’s approach to 

estimating the costs of SCR for the 

Comanche BART units. However, we 

find that the State’s NOX BART 

determination to be reasonable within 

the context of the five factors, 

particularly based on the relatively 

modest visibility improvement 

associated with SCR—0.14 deciviews at 

Unit 1, and 0.17 deciviews at Unit 2— 

and the expectation that cost 

effectiveness values for SCR calculated 

in accordance with the CCM would still 

be relatively high compared to the 

selected control option. 

Comment: Although the State and 

EPA may claim that, even if the costs 

were accurately assessed, the visibility 

benefits of SCR would not be 

significant, even for Unit 2, there is no 

support for this assertion. In particular, 

it appears as if the State’s assessment of 

visibility improvements is based on an 

assumption that the proposed BART 

limits (i.e., the ‘‘do nothing’’ BART) 

would actually improve visibility. Given 

that the proposed BART limits would 

allow increased emissions, it would not 

actually improve visibility. When 

compared to the real impacts of the 

State’s proposed BART for Comanche 

unit 1, SCR would appear to provide 

significant visibility improvements 

because, as opposed to the proposed 

BART, SCR would actually achieve 

improvements. For Unit 2, this is 

especially significant because SCR was 

the only available technology analyzed 

for BART. Thus, by all indications, SCR 

is the only means of actually achieving 

visibility improvements at Comanche 

Unit 2. 

Response: We disagree with this 

comment. As shown in Colorado’s 

visibility impact analysis for the 

Comanche BART units, Colorado 

assessed the benefit of control options 

relative to both the subject-to-BART 

baseline and to the installation of new 

LNB in 2007 and 2008. In addition, the 

subject-to-BART modeling emission 

rates were based on the maximum 24- 

hr rate consistent with the BART 

guidelines. Colorado’s analysis shows 

visibility benefits for all of the control 

options considered, not just SCR. 

Moreover, relative to the subject-toBART baseline, Colorado’s BART 

selection (combustion controls), does in 

fact show visibility improvement (0.16 

deciview and 0.31 deciview for Units 1 

and 2, respectively). Therefore, EPA 

finds that no changes to the BART 

determinations or to the SIP are needed 

in response to this comment. 

Comment: It is unclear why the State 

rejected SNCR for Comanche Unit 1, 

particularly given that the proposed 

BART limit for Unit 1 is less stringent 

than Unit 1’s current actual emissions. 

Under an SNCR scenario, Unit 1 would 

meet a 30-day rolling average emission 

rate of 0.10 lb/MMBtu according to the 

EPA. According to the State, the cost, 

coupled with the State’s perceived ‘‘low 

visibility improvement’’ warranted a 

determination that SNCR was not 

reasonable. However, according to the 

State’s analysis, SNCR is cost effective 

at Unit 1, costing $3,644 per ton of NOX

reduced, which is squarely within the 

range of what the State considers to be 

cost-effective. 

Response: We find that the State’s 

rejection of SNCR was reasonable based 

on its weighing of the BART factors. The 

State reasonably concluded that the cost 

of SNCR was not warranted given the 

relatively modest visibility 

improvement that would result—0.11 

deciviews. Even if a control technology 

is arguably cost-effective on a dollar per 

ton basis, a State may conclude that the 

control technology is not warranted 

based on a reasonable consideration of 

all BART factors. 

Comment: With regard to visibility 

benefits, the State’s analysis also 

indicates that SNCR would achieve 

greater improvement than an emission 

rate of 0.20 lb/MMBtu on a 30-day 

rolling average. Although the State 

asserts that the improvement would 

amount to 0.11 deciviews, it is unclear 

why such improvements are not 

reasonable or are otherwise 

insignificant, particularly given that the 

purpose of BART is to reduce or 

eliminate visibility impairment, and 

indeed there is no explanation in the 

record supporting the State’s assertion. 

It also appears as if the State’s 

assessment of visibility improvements is 

based on an assumption that the 

proposed BART limits would actually 

improve visibility. Given that the 

proposed BART allows increased 

emissions, it would not improve 

visibility. When compared to the real 

impacts of the State’s proposed BART 

for Comanche Unit 1, SNCR appears to 

provide significant visibility 

improvements because, as opposed to 

the proposed BART, SNCR would 

actually achieve improvements. This 

further underscores why the State’s 

BART determination for Comanche Unit 

1 is flawed and why EPA must 

promulgate a FIP that establishes 

appropriate NOX BART limits. 

Response: The commenter is correct 

that the State predicted that SNCR 

would result in additional improvement 

in visibility over the control technology 

the State selected as BART. However, 

this does not mean the CAA or our 

regulations required the State to select 

SNCR as BART. For the reasons stated 

above, we find that it was reasonable for 

the State to reject SNCR based on 

consideration of all the BART factors. 

Regarding the commenter’s suggestion 

that the State’s selected limits will lead 

to an increase in emissions, as noted 

above, the commenter has presented no 

evidence that this will occur. Moreover, 

as indicated in a separate response to 

comments, above, Colorado assessed the 

benefit of control options relative to 


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both the subject-to-BART baseline and 

to the installation of new LNB in 2007 

and 2008. Relative to the subject-toBART baseline, Colorado’s BART 

determination does in fact result in 

visibility benefits. The installation of 

LNB resulted in a visibility 

improvement of 0.16 deciview and 0.31 

deciview for Comanche Units 1 and 2, 

respectively. 

F. NOX Reasonable Progress 

Determination for Craig Unit 3 

Comment: We received comments 

that the reasonable progress evaluation 

of Craig Unit 3 includes the same flaws 

as for Units 1 and 2 (see comments in 

section IV.A.1—4 above). One 

commenter indicated that the estimated 

cost effectiveness is no higher than 

$3,190/ton, and likely lower, 

considering the conservative $300/kW 

starting point for their analysis. Another 

commenter estimated the cost 

effectiveness of SCR at Unit 3 as $2,385/ 

ton. 

Based on visibility modeling from the 

NPS, commenters pointed out that the 

visibility benefits of adding SCR to Unit 

3 are similar to those at Units 1 and 2— 

over 0.5 deciview at five Class I areas, 

and additional benefits at several more. 

The commenters asserted that, 

cumulatively, Unit 3 has an 8.39 

deciview impact, with SCR providing a 

cumulative visibility improvement of 

4.56 deciviews. Commenters went on to 

say that SCR at a limit of 0.05 lb/MMBtu 

should be required as reasonable 

progress for Craig Unit 3. 

Response: We agree that the State 

likely overestimated the cost associated 

with SCR at Unit 3, but we are not 

prepared to disapprove the State’s 

reasonable progress determination for 

Craig Unit 3. Assuming the commenters’ 

assessments of the cost effectiveness of 

SCR are reasonably accurate, the values 

are not so low that it is clear that the 

State would have been unreasonable to 

reject SCR, especially given the State’s 

requirement that Craig Unit 3 install 

SNCR and the resulting visibility 

benefits. We expect the State to reevaluate SCR for Unit 3 in the next 

planning period. 

G. NOX Reasonable Progress 

Determination for Nucla 

Comment: The State’s proposed SIP 

appears to allow increased emissions 

from the Nucla coal fired power plant 

under the reasonable progress aspect of 

the proposed SIP. In light of this, it is 

unclear how the proposed emission 

limits for NOX and SO2 actually meet 

the State’s reasonable progress goals. 

Under the reasonable progress prong of 

the regional haze requirements of the 

CAA, the State determined that 

additional controls at the Nucla plant 

were reasonable to protect Class I areas. 

Accordingly, the State proposed to 

require the power plant to achieve a 

NOX emission limit of 0.5 lb/MMBtu 

and an SO2 limit of 0.4 lb/MMBtu, both 

over a 30-day rolling average period. 

However, according to data from EPA’s 

Air Markets Program Database, Nucla 

has been meeting emission rates far 

below these proposed reasonable 

progress limits. 

Indeed, data from the EPA 

demonstrates that between January 1, 

2009, and December 31, 2011, Nucla has 

been meeting an average monthly NOX

emission rate of 0.367 lb/MMBtu and an 

average monthly SO2 emission rate of 

0.301 lb/MMBtu. These rates indicate 

that Nucla is able to meet more stringent 

emission rates at no additional cost. The 

monthly SO2 and NOX emission rates 

actually achieved by Nucla in the past 

3 years clearly demonstrate that the 

power plant has consistently emitted at 

rates below the reasonable progress 

limits proposed by the State. Nucla is 

capable of achieving NOX and SO2

emission rates lower than 0.30 lb/ 

MMBtu on a 30-day basis. 

More importantly though, these rates 

indicate that the State’s proposed 

reasonable progress limits actually 

allow more air pollution to be emitted 

from Nucla than is currently emitted. 

An increase in emissions would not 

appear to ensure reasonable progress in 

restoring visibility in Colorado’s Class I 

areas. Thus, the State’s proposed SIP is 

not approvable by EPA because it fails 

to ensure reasonable progress in 

accordance with 42 U.S.C. 7491(g)(1) 

and 40 CFR 51.308(d)(1)(i). At the least, 

the proposed reasonable progress 

emission limits for Nucla demonstrate 

that the State failed to appropriately 

assess the costs of compliance in 

accordance with the CAA. Indeed, if the 

State had appropriately assessed the 

costs of compliance, it would have 

found that lower emission rates would 

be equally cost-effective and more 

protective of visibility. Such a flawed 

analysis of reasonable progress in 

relation to the Nucla plant cannot be 

approved by EPA. 

The EPA must promulgate a FIP that 

establishes reasonable progress limits at 

the Nucla plant that actually achieve 

cost-effective emissions reductions. To 

this end, we request EPA adopt 

reasonable progress limits that limit 

NOX emissions to no more than 0.25 lb/ 

MMBtu and SO2 emissions to no more 

than 0.28 lb/MMBtu. Such limits are 

achievable and appear to be very costeffective given that they would cost 

nothing. 

Response: We disagree with this 

comment. Colorado based the SO2

emission limit of 0.4 lb/MMBtu on the 

existing limestone injection system for 

SO2, and it based the NOX limit of 0.5 

lb/MMBtu on the inherent low-NOX

nature of the circulating fluidized bed 

boiler. A review of recent (2008–2010) 

monthly data in EPA’s CAMD emissions 

database shows monthly NOX emission 

rates as high as 0.45 lb/MMBtu and 

monthly SO2 emission rates as high as 

0.33 lb/MMBtu. These rates are 

commensurate with the reasonable 

progress emission limits established by 

Colorado. Based on its reasonable 

progress analysis, Colorado concluded 

that no additional controls were 

reasonable. We concur with that 

conclusion. 

H. Reasonable Progress for Rio Grande 

Cement Company (GCC) 

Comment: The State should have 

analyzed visibility impacts due to GCC, 

as either a permit modification or as a 

reasonable progress source. To date, the 

State has not considered the impacts of 

the source under either program. Had 

the State compared GCC’s emissions (Q) 

as a function of distance (d) to the 

threshold Q/d > 20 used to determine 

whether a source would be included in 

the reasonable progress analysis, GCC 

would have qualified for reasonable 

progress review. The State contends that 

GCC was not included in the reasonable 

progress review because the State used 

2007 emissions to determine which 

sources were subject to reasonable 

progress review, and GCC did not begin 

normal operations until 2009. However, 

in its analysis of the proposed permit 

modification, the State asserts that 

GCC’s actual emissions should be based 

upon the current permit limits, not zero 

emissions. In that case, GCC’s permit 

emissions should have been used to 

trigger inclusion in the Colorado 

reasonable progress analysis. 

It is essential that any regulatory 

program try to maintain a ‘‘level playing 

field.’’ There are two other cement 

plants in Colorado, and additional NOX

controls are being required on both 

under Colorado’s regional haze SIP. 

GCC has installed SNCR but the 

current permit does not require these 

controls to be operated. We believe that, 

because the GCC permit allows 

emissions that exceed the State’s 

threshold for determining which 

sources are subject to a reasonable 

progress analysis, GCC should have 

been included as a reasonable progress 

source. It is likely, based on the State’s 

actions regarding the other two cement 

plants that the State would have 

required continuous operation of SNCR. 


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EPA should require GCC to reduce NOX

emissions by 45% on a continuous 

basis. 

Response: The State based its 

evaluation of potential reasonable 

progress sources on stationary sources 

with actual emissions of 100 tpy or 

greater of PM, NOX, and SO2 based on 

Air Pollution Emissions Notice (APEN) 

reports from 2007. The APEN reports for 

2007 are based on data reported to the 

State by April 30, 2007, which is based 

on the previous full year of production 

(2006). The State formalized its 

reasonable progress analysis process in 

2009. At that time, the APEN report data 

the State had (that had undergone full 

quality assurance and quality control) 

were the 2007 APEN reports based on 

the source reported 2006 data. 

In 2006, Rio Grande Cement reported 

zero emissions because it did not 

operate. In 2007, Rio Grande Cement 

did report APEN emissions (based on 

permitted limits) resulting in a Q/d≤20, 

but those emissions were not actual 

emissions because the source did not 

actually begin producing cement until 

April 2008. Because the State based its 

reasonable progress evaluation on 2006 

actual emissions, we find it reasonable 

that the State did not further evaluate 

GCC for purposes of reasonable 

progress. We expect the State to do so 

for the next reasonable progress 

planning period. 

I. Legal Issues 

1. Public Service Company of Colorado 

(PSCO) BART Alternative 

Comment: Phase III of the SIP 

Rulemaking (at which the PSCO BART 

Alternative was adopted), to which 

Colorado Mining Association (CMA) 

was a party, was based upon numerous 

irregularities and violations of the 

Colorado Administrative Procedures 

Act, the Colorado Air Pollution 

Prevention and Control Act, and H. B. 

10–1365. CMA filed a complaint 

challenging the Air Quality Control 

Commission’s (AQCC) SIP Rulemaking 

on March 16, 2011, in Denver District 

Court. The CMA case is pending review 

by the District Court. The issues before 

the court are numerous and establish 

the AQCC’s Phase III rulemaking was 

improper and that the PSCO BART 

Alternative should be stricken from the 

Colorado regional haze SIP. If the Court 

determines that the Phase III rulemaking 

was improper, and therefore, portions of 

the proposed Colorado SIP were invalid 

under State law, those same portions of 

the proposed Colorado SIP would be 

unenforceable under federal law. 

As a result of the AQCC’s egregious 

failures in Phase III of the SIP 

Rulemaking, the PSCO BART 

Alternative should not be included in 

the Colorado regional haze SIP. Until 

the Court has completed its review, EPA 

should not act to include the PSCO 

BART Alternative in the State’s regional 

haze SIP. 

Response: Once a state has submitted 

a SIP revision to us, we must approve 

it if it meets the CAA’s minimum 

requirements. One of the relevant 

requirements is that the State have 

adequate authority under State law to 

carry out the plan. See CAA section 

110(a)(2)(E). Absent a stay or 

determination by a court that a plan is 

invalid, or some other clear indication 

that the State lacks authority to 

implement the plan, we have no basis 

to disapprove it under 110(a)(2)(E). 

Here, there is no indication that 

Colorado lacks authority to implement 

the PSCO BART Alternative. Indeed, it 

is our understanding that CMA’s lawsuit 

has been dismissed by the Denver 

District Court as moot. We have 

included a copy of the court’s June 6, 

2012 order in the docket for this action. 

If a court subsequently invalidates the 

PSCO BART Alternative, we will need 

to evaluate the Colorado SIP at that 

time, but the possibility of future 

invalidation does not provide a basis for 

us to disapprove the PSCO BART 

Alternative. 

2. Timing of Implementation 

Comment: Colorado’s proposed SIP 

appears to contain a blanket schedule of 

BART compliance that states, ‘‘sources 

must comply as expeditiously as 

practicable, but no later than 5 years 

from EPA approval of the SIP.’’ This 

blanket schedule of compliance, which 

applies to all subject-to-BART sources 

under the proposed Colorado SIP, is 

contrary to the CAA. It is true that the 

CAA requires that subject-to-BART 

sources ‘‘procure, install, and operate, 

as expeditiously as practicable’’ any 

additional controls that may represent 

BART. However, simply stating 

verbatim in the SIP that ‘‘sources must 

comply as expeditiously as practicable’’ 

fails to give force and effect to this 

statutory provision. In this case, it is 

unclear what ‘‘as expeditiously as 

practicable’’ means, particularly in the 

context of individual subject-to-BART 

sources. The lack of any specificity 

renders this provision unenforceable, 

which further undermines the adequacy 

of the SIP under CAA section 110 and 

frustrates the statutory mandate set forth 

under the CAA. 

Additionally, the CAA is clear that in 

mandating ‘‘expeditious’’ compliance, 

SIPs must ensure that subject-to-BART 

sources comply as soon as possible. In 

this case, Colorado’s SIP simply fails to 

ensure compliance with BART as soon 

as possible. It lacks any concrete dates 

by which subject-to-BART sources must 

comply, other than to state that sources 

must comply within the statutory 

maximum compliance date of 5 years. 

However, the CAA is clear that if a 

source can comply with BART before 5 

years, it must comply by that earlier 

date. See 42 U.S.C. 7491(g)(4). Simply 

deferring to the 5-year deadline 

undermines the Congressional intent 

behind the ‘‘as expeditiously as 

practicable’’ provision. 

It is notable that in other situations, 

the EPA has proposed to require 

concrete compliance dates to satisfy the 

CAA’s ‘‘as expeditiously as practicable’’ 

provisions under the regional haze 

program. For example, in proposing a 

FIP for BART for the San Juan 

Generating Station in New Mexico, the 

EPA proposed a 3-year compliance date, 

finding it to be ‘‘as expeditiously as 

practicable’’ (76 FR 504). Although EPA 

ultimately concluded that a 5-year 

schedule of compliance was 

appropriate, the Agency’s proposed 

action clearly signaled that a concrete 

date is needed to satisfy the CAA. 

The EPA must therefore disapprove of 

Colorado’s blanket schedule of BART 

compliance. In its place, the Agency 

must promulgate a FIP that sets forth 

concrete dates by which all subject-toBART sources must ‘‘procure, install, 

and operate’’ BART that represent the 

most expeditious dates practicable. 

Response: We have reviewed the 

compliance dates for meeting BART 

limits that are contained in the SIP. 

These dates are reasonable given the 

magnitude of the retrofits being 

undertaken. We note that the State’s 

Regulation Number 3—Stationary 

Source Permitting And Air Pollutant 

Emission Notice Requirements that we 

are approving as part of this action 

provides for compliance as 

expeditiously as practicable, but in no 

event later than 5 years from EPA final 

approval of the SIP. 

3. Compliance With Section 110(l) 

Comment: The EPA is duty-bound to 

ensure the proposed SIP does not 

interfere with attainment and 

maintenance of the National Ambient 

Air Quality Standards (NAAQS), in 

accordance with section 110(l) of the 

CAA. Thus, the EPA must ensure that 

the proposed SIP adequately limits air 

pollution in order to safeguard public 

health. 

In this case, we are concerned that in 

proposing to approve Colorado’s 

regional haze plan that the EPA has not 

demonstrated that the proposal 


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adequately safeguards the 2008 8-hour 

ozone NAAQS, the newly promulgated 

1-hour nitrogen dioxide NAAQS, the 

newly promulgated 1-hour SO2 NAAQS, 

and the 2006 fine particulate matter 

(PM2.5) NAAQS. Thus, EPA has not 

shown the extent to which public health 

is likely to be protected under the 

proposed SIP. 

We are particularly concerned that the 

EPA overlooked its 110(l) obligations 

under the CAA given that, although the 

proposed rule may lead to emission 

reductions, no analysis or assessment 

has been prepared to demonstrate that 

even after these emission reductions, 

the recently promulgated NAAQS will 

be met. In this case, we are particularly 

concerned that the recently promulgated 

1-hour NO2 and SO2 NAAQS could be 

jeopardized. Indeed, many, if not most, 

of the proposed emission rates are based 

on 30-day rolling averages. There is no 

indication that meeting emission rates 

on a 30-day rolling average will ensure 

that 1-hour NAAQS will be sufficiently 

protected. Indeed, a source could 

comply with a 30-day rolling average 

limit, yet still emit enough pollution on 

an hourly basis to cause or contribute to 

violations of the NAAQS, thereby 

interfering with attainment or 

maintenance. 

We are further concerned over the fact 

that several BART limits allow for 

increased emissions. For example, the 

proposed NOX BART determinations for 

Comanche Units 1 and 2 allow for 

greater emissions than are currently 

released by the units. This raises 

concerns over the impacts to the 

NAAQS. These impacts must be 

addressed by EPA. 

In this case, the EPA must either 

disapprove of the Colorado SIP over the 

State’s failure to perform a 110(l) 

analysis or prepare its own 110(l) 

analysis to demonstrate that the SIP will 

effectively protect public health and not 

interfere with attainment or 

maintenance of the NAAQS. 

Response: CAA 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. It is not clear that the regional 

haze SIP submitted by Colorado is a 

‘‘revision of a plan’’ within the meaning 

of CAA section 110(l) as it is the first 

implementation plan due under the 

regional haze program. See, e.g., 

§ 51.308(b). However, even if such an 

analysis were required, the commenter 

has not provided any evidence that the 

Colorado regional haze SIP will interfere 

with any applicable requirement 

concerning attainment and reasonable 

progress or any other applicable 

requirement of the CAA, or that further 

analysis under 110(l) is necessary. 

Although the Colorado regional haze 

SIP will lead to emission reductions, the 

commenter asserts that that even so EPA 

must determine that the SIP revision 

will ensure the NAAQS are met. We 

disagree with this interpretation of CAA 

section 110(l). The Act and EPA’s 

regulations require the regional haze SIP 

to address visibility impairment in 

mandatory Class I areas—attainment of 

the NAAQS is provided for through a 

separate SIP process. 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 

interpret section 110(l) to require a full 

attainment or maintenance 

demonstration for each NAAQS for 

every SIP revision. See, e.g., Kentucky 

Resources Council, Inc., v. EPA, 467 

F.3d 986 (6th Cir. 2006); see also, 61 FR 

16050, 16051 (April 11, 1996) (actions 

on which the Kentucky Resources 

Council case were based). 

Thus, in this action, we need not 

determine whether a 30-day limit is 

adequate to protect a shorter-term 

NAAQS because the regional haze SIP is 

not required to ensure attainment of the 

NAAQS. The fact that the regional haze 

SIP specifies 30-day limits will not 

preclude Colorado from adopting limits 

with a shorter averaging time, if at some 

future date such limits are found to be 

necessary and required by the CAA to 

protect the NAAQS. 

The commenter also alleges that 

‘‘several BART limits allow for 

increased emissions’’ over current 

actual source emissions and cites as an 

example the NOX BART limits for 

Comanche Units 1 and 2. The 

commenter claims this raises concerns 

over impacts to the NAAQS. However, 

the Colorado regional haze SIP imposes 

new emissions limits on a number of 

existing sources, and it does not relax 

any existing emissions limits or other 

SIP requirements. In fact, the regional 

haze SIP makes violations of the 

NAAQS less likely because without the 

BART limits, actual emissions could 

increase even more. And, the regional 

haze SIP does not prevent the State from 

adopting lower limits in the future as 

necessary to protect the NAAQS. Thus, 

the regional haze SIP revision and its 

BART limits will not interfere with ‘‘any 

applicable requirement concerning 

attainment and reasonable further 

progress * * *, or any other applicable 

requirement of’’ the CAA. 

J. Comments Generally in Favor of our 

Proposal 

Comment: We received comment 

letters fully in support of our 

rulemaking from Xcel Energy, Tri-State 

Generation, and a letter on behalf of 

Colorado Environmental Coalition, 

Environment Colorado, Environmental 

Defense Fund, and Western Resource 

Advocates. We received 84 comments 

from members of National Parks 

Conservation Association generally in 

support of our action. These comments 

from National Parks Conservation 

Association members also urged EPA to 

finalize stricter NOX controls on TriState Craig Unit 1, which we have 

addressed above. We also received 

comments from National Parks 

Conservation Association, the NPS, and 

WildEarth Guardians that supported the 

majority of our action, but pointed out 

some concerns, to which we have 

responded above. 

Response: We acknowledge the 

support of these commenters for part or 

all of our proposed action. 

V. Statutory and Executive Order 

Reviews 

Under the Clean Air Act, the 

Administrator is required to approve a 

SIP submission that complies with the 

provisions of the Act and applicable 

Federal regulations. 42 U.S.C. 7410(k); 

40 CFR 52.02(a). Thus, in reviewing SIP 

submissions, EPA’s role is to approve 

state choices, provided that they meet 

the criteria of the Clean Air Act. 

Accordingly, this action merely 

approves state law as meeting Federal 

requirements and does not impose 

additional requirements beyond those 

imposed by state law. For that reason, 

this action: 

• Is not a ‘‘significant regulatory 

action’’ subject to review by the Office 

of Management and Budget under 

Executive Order 12866 (58 FR 51735, 

October 4, 1993); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have Federalism 

implications as specified in Executive 


ebenthall on DSK5TPTVN1PROD with 
Federal Register / Vol. 77, No. 250 / Monday, December 31, 2012 / Rules and Regulations 76883 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the Clean Air Act; 

and 

• Does not provide EPA with the 

discretionary authority to address, as 

appropriate, disproportionate human 

health or environmental effects, using 

practicable and legally permissible 

methods, under Executive Order 12898 

(59 FR 7629, February 16, 1994). 

In addition, this rule does not have 

tribal implications as specified by 

Executive Order 13175 (65 FR 67249, 

November 9, 2000), because the SIP is 

not approved to apply in Indian country 

located in the state, and EPA notes that 

it will not impose substantial direct 

costs on tribal governments or preempt 

tribal law. 

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. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by March 1, 2013. 

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, Incorporation by 

reference, Nitrogen dioxide, Ozone, 

Particulate matter, Sulfur oxides. 

Dated: September 10, 2012. 

James B. Martin, 

Regional Administrator, Region 8. 

For the reasons discussed in the 

preamble, 40 CFR chapter I is amended 

as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for Part 52 

continues to read as follows: 

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

Subpart G—Colorado 

■ 2. Section 52.320 is amended by 

adding paragraph (c)(108)(i)(C) and 

adding paragraph (c)(124) to read as 

follows: 

§ 52.320 Identification of plan. 

* * * * * 

(c) * * * 

(108) * * * 

(i) * * * 

(C) Colorado Air Quality Control 

Commission, Regulation Number 3, 5 

CCR 1001–5, Stationary Source 

Permitting and Air Pollutant Emission 

Notice Requirements, Part D, 

Concerning Major Stationary Source 

New Source Review and Prevention of 

Significant Deterioration, Section XIV.F, 

Long Term Strategy, subsection XIV.F.1. 

introductory text and XIV.F.1.c; adopted 

January 7, 2011; effective February 14, 

2011. 

* * * * * 

(124) On May 25, 2011 the State of 

Colorado submitted revisions to its State 

Implementation Plan to address the 

requirements of EPA’s regional haze 

rule. 

(i) Incorporation by reference. 

(A) Colorado Air Quality Control 

Commission, Regulation Number 3, 5 

CCR 1001–5, Stationary Source 

Permitting and Air Pollutant Emission 

Notice Requirements, Part F, Regional 

Haze Limits—Best Available Retrofit 

Technology (BART) and Reasonable 

Progress (RP), Section VI, Regional Haze 

Determinations, and Section VII, 

Monitoring, Recordkeeping, and 

Reporting for Regional Haze Limits; 

adopted January 7, 2011; effective 

February 14, 2011. 

(B) Colorado Air Quality Control 

Commission, Regulation Number 7, 5 

CCR 1001–9, Control of Ozone via 

Ozone Precursors (Emissions of Volatile 

Organic Compounds and Nitrogen 

Oxides), Section XVII, (State Only, 

except Section XVII.E.3.a. which was 

submitted as part of the Regional Haze 

SIP) Statewide Controls for Oil and Gas 

Operations and Natural Gas-Fired 

Reciprocating Internal Combustion 

Engines, subsection E.3.a, (Regional 

Haze SIP) Rich Burn Reciprocating 

Internal Combustion Engines; adopted 

January 7, 2011; effective February 14, 

2011. 

[FR Doc. 2012–31192 Filed 12–28–12; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 52 and 81 

[EPA–R05–OAR–2011–0468; FRL–9764–9] 

Approval and Promulgation of 

Implementation Plans and Designation 

of Areas for Air Quality Planning 

Purposes; Ohio; Redesignation of the 

Ohio Portion of the HuntingtonAshland 1997 Annual Fine Particulate 

Matter Nonattainment Area to 

Attainment 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is approving, under the 

Clean Air Act (CAA), the state of Ohio’s 

request to redesignate the Ohio portion 

of the Huntington-Ashland (OH–WV– 

KY) nonattainment area (Lawrence, 

Scioto, and portions of Adams and 

Gallia Counties) to attainment for the 

1997 annual National Ambient Air 

Quality Standard (NAAQS or standard) 

for fine particulate matter (PM2.5). The 

Ohio Environmental Protection Agency 

(Ohio EPA) submitted its request on 

May 4, 2011. EPA determined that the 

entire Huntington-Ashland area has 

attained the 1997 annual PM2.5

standard, and proposed to approve 

Ohio’s request to redesignate the Ohio 

portion of the area on December 22, 

2011. EPA’s final rulemaking involves 

several related actions. EPA has 

determined that the entire HuntingtonAshland area continues to attain the 

1997 annual PM2.5 standard. EPA is 

approving, as a revision to the Ohio 

State Implementation Plan (SIP), the 

state’s plan for maintaining the 1997 

annual PM2.5 NAAQS in the area 

through 2022. EPA is also approving the 

2005 and 2008 emissions inventories for 

the Ohio portion of the HuntingtonAshland area as meeting the 

comprehensive emissions inventory 

requirement of the CAA. EPA finds 

adequate and is making a finding of 


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