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[Federal Register Volume 77, Number 250 (Monday, December 31, 2012)]
[Rules and Regulations]
[Pages 76871-76883]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-31192]

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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.

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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.

[[Page 76872]]

    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.
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    \1\ We 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.
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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

[[Page 76873]]

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, Tri-State'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
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    \2\ Letter 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).
    \3\ NPS 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.
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    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 sub-bituminous. 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 sub-bituminous 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.
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    \4\ The presumptive limit for dry-bottom wall-fired EGUs firing 
bituminous coal is 0.39 lb/MMBtu (70 FR 39172).
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    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

[[Page 76874]]

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.
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    \5\ The 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.
    \6\ According 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.
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    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 post-combustion 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.
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    \7\ For the highest-performing NOX post-combustion 
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 post-combustion 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.
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    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

[[Page 76875]]

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 Tri-
State 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 BART-eligible 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 fuel-switching 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

[[Page 76876]]

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 post-combustion 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
---------------------------------------------------------------------------

    \8\ See 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.
---------------------------------------------------------------------------

    Here, alternative fueling scenarios, such as a full or partial 
shift away from

[[Page 76877]]

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.
---------------------------------------------------------------------------

    \9\ The 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.
---------------------------------------------------------------------------

    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 cost-effective, 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\
---------------------------------------------------------------------------

    \10\ See 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.
    \11\ See 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.
---------------------------------------------------------------------------

    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

[[Page 76878]]

[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.
---------------------------------------------------------------------------

    \12\ The State indicated that CEMEX consulted four potential SCR 
vendors but was unable to obtain meaningful quotes from any of them.
---------------------------------------------------------------------------

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, cold-weather 
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

[[Page 76879]]

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-to-BART 
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

[[Page 76880]]

both the subject-to-BART baseline and to the installation of new LNB in 
2007 and 2008. Relative to the subject-to-BART 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 re-evaluate 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 cost-effective 
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.

[[Page 76881]]

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-to-BART 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

[[Page 76882]]

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., Sec.  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 Tri-State 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

[[Page 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

0
1. The authority citation for Part 52 continues to read as follows:

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

Subpart G--Colorado

0
2. Section 52.320 is amended by adding paragraph (c)(108)(i)(C) and 
adding paragraph (c)(124) to read as follows:

Sec.  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
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