[Federal Register Volume 77, Number 71 (Thursday, April 12, 2012)]
[Proposed Rules]
[Pages 21896-21908]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-8713]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R09-OAR-2011-0130, FRL-9658-5]


Approval and Promulgation of Air Quality Implementation Plans; 
State of Nevada; Regional Haze State and Federal Implementation Plans; 
BART Determination for Reid Gardner Generating Station

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to partially approve and partially disapprove 
the remaining portion of a revision to the Nevada State Implementation 
Plan (SIP) to implement the regional haze program for the first 
planning period through July 31, 2018. This Notice proposes to approve 
the chapter of Nevada's Regional Haze SIP that requires Best Available 
Retrofit Technology (BART) for emissions limits of oxides of nitrogen 
(NO<INF>X</INF>) from Units 1 and 2 at the Reid Gardner Generating 
Station (RGGS). We are proposing to disapprove the NO<INF>X</INF> 
emissions limit for Unit 3. We are also proposing to disapprove the 
provision of the RGGS BART determination that sets a 12-month rolling 
average for Units 1 through 3. This Notice proposes to promulgate a 
Federal Implementation Plan (FIP) that establishes certain requirements 
for which the State, in a letter dated March 22, 2012, has agreed to 
submit a SIP revision. The FIP sets an emissions limit of 0.20 lbs/
MMBtu (pounds per million British thermal units) for Unit 3 as BART and 
requires the determination of emissions from Units 1 through 3 based on 
a 30-day rolling average (averaged across all three units). In a prior 
action, EPA approved Nevada's Regional Haze SIP except for its BART 
determination for NO<INF>X</INF> for RGGS Units 1 through 3.

DATES: Comments: Written comments must be received at the address below 
on or before May 14, 2012.
    Public Hearing: We will hold a public hearing in early May at a 
location near the Facility. We will post information on the specifics 
on our Web site at http://www.epa.gov/region9/air/actions/nv.html#haze 
and by publishing a notice in a general circulation newspaper at least 
15 days before the date of the hearing.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R09-
OAR-2011-0130 by one of the following methods:

[[Page 21897]]

    1. Federal Rulemaking portal: http://www.regulations.gov. Follow 
the on-line instructions for submitting comments.
    2. Email: <a href="/cdn-cgi/l/email-protection#4d1a282f2f63192522202c3e0d283d2c632a223b"><span class="__cf_email__" data-cfemail="c790a2a5a5e993afa8aaa6b487a2b7a6e9a0a8b1">[email protected]</span></a>.
    3. Fax: 415-947-3579 (Attention: Thomas Webb)
    4. Mail: Thomas Webb, EPA Region 9, Planning Office, Air Division, 
75 Hawthorne Street, San Francisco, California 94105.
    5. Hand Delivery or Courier: Such deliveries are only accepted 
Monday through Friday, 8:30 a.m.-4:30 p.m., excluding federal holidays. 
Special arrangements should be made for deliveries of boxed 
information.
    Instructions: Direct your comments to Docket ID No. EPA-R09-OAR-
2011-0130. Our policy is that EPA will include all comments received in 
the public docket without change. EPA may make comments available 
online at http://www.regulations.gov, including any personal 
information provided, unless the comment includes information claimed 
to be Confidential Business Information (CBI) or other information 
whose disclosure is restricted by statute. Do not submit information 
that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an email comment directly to EPA, without 
going through http://www.regulations.gov, EPA will include your email 
address as part of the comment that is placed in the public docket and 
made available on the Internet. If you submit an electronic comment, 
EPA recommends that you include your name and other contact information 
in the body of your comment and with any disk or CD-ROM you submit. If 
EPA cannot read your comment due to technical difficulties and cannot 
contact you for clarification, EPA may not be able to consider your 
comment. Electronic files should avoid the use of special characters, 
any form of encryption, and be free of any defects or viruses. For 
additional information about EPA's public docket visit the EPA Docket 
Center homepage at http://www.epa.gov/epahome/dockets.htm.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although it is listed in the index, some 
information is not publicly available (e.g., CBI or other information 
whose disclosure is restricted by statute). Certain other material, 
such as copyrighted material, voluminous records or large maps, will be 
publicly available only in hard copy form. Publicly available docket 
materials are available either electronically at http://www.regulations.gov or in hard copy at the Planning Office of the Air 
Division, Air-2, EPA Region 9, 75 Hawthorne Street, San Francisco, CA 
94105. EPA requests you contact the individual listed in the FOR 
FURTHER INFORMATION CONTACT section to view the hard copy material of 
the docket. You may view the hard copy material of the docket Monday 
through Friday, 9-5:30 PST, excluding federal holidays.

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9, 
Planning Office, Air Division, Air-2, 75 Hawthorne Street, San 
Francisco, CA 94105. Thomas Webb can be reached at telephone number 
(415) 947-4139 and via electronic mail at <a href="/cdn-cgi/l/email-protection" class="__cf_email__" data-cfemail="fb8c9e9999d58f9394969a88bb9e8b9ad59c948d">[email protected]</a>.

Definitions

    For the purpose of this document, we are giving meaning to certain 
words or initials as follows:

(1) The initials BART mean or refer to Best Available Retrofit 
Technology
(2) The initials CAA mean or refer to Clean Air Act
(3) The initials CCM mean or refer to EPA's Control Cost Manual
(4) The words or initials EPA, we, us or our mean or refer to the 
United States Environmental Protection Agency
(5) The initials GCNP mean or refer to Grand Canyon National Park
(6) The initials IMPROVE mean or refer to Interagency Monitoring of 
Protected Visual Environments
(7) The word Jarbidge means or refers to the Jarbidge Wilderness Area
(8) The initials LNB mean or refer to low NO<INF>X</INF> burners
(9) The initials LTS mean or refer to Long-Term Strategy
(10) The initials NDEP mean or refer to Nevada Division of 
Environmental Protection
(11) The words Nevada and State mean or refer to the State of Nevada
(12) The initials NO<INF>X</INF> mean or refer to nitrogen oxides
(13) The initials OFA mean or refer to overfire air
(14) The initials RGGS means or refers to Reid Gardner Generating 
Station Units 1 through 3
(15) The initials RHR mean or refer to Regional Haze Rule
(16) The initials ROFA mean or refer to rotating overfire air
(17) The word Rotamix means or refers to a technology that combines a 
conventional SNCR system with a proprietary air and reagent injection 
system
(18) The initials RPG mean or refer to Reasonable Progress Goal
(19) The initials SCR mean or refer to selective catalytic reduction
(20) The initials SIP mean or refer to State Implementation Plan
(21) The initials FIP mean or refer to Federal Implementation Plan
(22) The initials SNCR mean or refer to selective non-catalytic 
reduction
(23) The initials TSD mean or refer to Technical Support Document

Table of Contents

I. Background
II. State Submittals and EPA's Prior Action
III. Overview of Proposed Action
IV. Requirements for Regional Haze SIPs
    A. Regional Haze Rule
    B. Best Available Retrofit Technology
    C. Roles of Agencies in Addressing Regional Haze
    D. Lawsuits
V. EPA's Analysis of Nevada's RH SIP
    A. Affected Class I Areas
    B. Identification of Sources Subject to BART
    C. Evaluation of Nevada's NO<INF>X</INF> BART Determination for 
Reid Gardner Generating Station
    1. Costs of Compliance
    2. Degree of Visibility Improvement
    3. Existing Pollution Control Technology
    4. Remaining Useful Life of the Source
    5. Energy and Non-Air Quality Impacts
VI. Federal Implementation Plan To Address NO<INF>X</INF> BART for 
Reid Gardner
    A. Unit 1 Through 3 Averaging Period
    B. Unit 3 Emission Limit
    C. Control Technology Basis
VII. EPA's Proposed Action
VIII. Statutory and Executive Order Reviews

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, and is, therefore, 
federally enforceable. If a state fails to make a required SIP 
submittal or if we find that a state's required submittal is incomplete 
or unapprovable, then we must promulgate a FIP to fill this regulatory 
gap. CAA section 110(c)(1). 40 U.S.C. 7410(c).
    This proposed action is intended to fulfill the requirement that 
states adopt and EPA approve SIPs that address 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. For a more 
detailed discussion please see our prior proposed action at 76 FR 36450 
(June 22, 2011).

[[Page 21898]]

II. State Submittals and EPA's Prior Action

    The Nevada Division of Environmental Protection (NDEP) adopted and 
transmitted its ``Nevada Regional Haze State Implementation Plan'' 
(Nevada RH SIP) to EPA Region 9 with a letter dated November 18, 2009. 
The Nevada RH SIP was complete by operation of law on May 18, 2010. 
Nevada provided public notice and held a public hearing on the proposed 
Best Available Retrofit Technology (BART) controls for four stationary 
sources, including RGGS, on April 23, 2009. The State submitted to EPA 
additional documentation of public process and adoption of a more 
stringent emission limit for one of the BART sources on February 18, 
2010. Revised Nevada Division of Environmental Protection BART 
Determination Review of NV Energy's Reid Gardner Generation Station 
Units 1, 2 and 3, Revised October 22, 2009 (hereinafter ``RGGS BART 
Determination''). Nevada included in its SIP submittal NDEP's responses 
to written comments from EPA Region 9, the National Park Service, and a 
consortium of conservation organizations. NDEP responded to comments on 
its RGGS BART Determination for NO<INF>X</INF> in two sections of its 
documents.\1\
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    \1\ See Appendix C (starting at C-8) and D (starting at D-141) 
of the NV Regional Haze SIP, available as attachments to EPA-R09-
OAR-2011-0130-0003.
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    On June 22, 2011, EPA proposed to approve the entire Nevada 
Regional Haze SIP submittal, including the RGGS BART Determination. 76 
FR 36450 (June 22, 2011). EPA received adverse comments on the proposed 
approval, including specific comments on NDEP's modeling and cost 
analysis of the RGGS BART Determination for NO<INF>X</INF>. See 
Modeling for the Reid Gardner Generating Station: Visibility Impacts in 
Class I Areas, Prepared by H. Andrew Gray, Ph.D., August 2011 and 
Review of EPA's Proposed Approval of a Revision to the State of 
Nevada's State Implementation Plan to Implement the Regional Haze 
Program, Comments on Determination of Best Available Retrofit 
Technology, August 22, 2011, prepared by Petra Pless, D. Env. and Bill 
Powers, P.E. \2\ (``Pless Powers Report'').
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    \2\ Both reports can be found as attachments to EPA-R09-OAR-
2011-0130-0062, with supporting information located in -0063.
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    On December 13, 2011, EPA signed its final approval of the Nevada 
RH SIP submittal that was published in the Federal Register on March 
26, 2012. 77 FR 17334 (March 26, 2012). In our final approval, we 
delayed taking any action on the Nevada's RGGS BART Determination for 
NO<INF>X</INF>.\3\ EPA indicated that we needed additional time to 
consider the substantial comments submitted on the RGGS BART 
Determination for NO<INF>X</INF>.
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    \3\ 77 FR 17334.
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    On December 22, 2011, we sent a letter via email to NDEP requesting 
clarification on several issues related to the comments on the RGGS 
BART Determination for NO<INF>X</INF>.\4\ NDEP responded on February 6 
and February 14, 2012 by providing us with cost-related information. 
These cost estimates consisted of updates to specific line items in 
order to reflect September 2011 material costs, but did not include any 
supporting information such as detailed equipment lists, vendor quotes, 
or the design basis for line item costs.
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    \4\ Email dated December 22, 2011, from Colleen McKaughan (EPA) 
to Mike Elges (NDEP) and others.
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    EPA requested further information from NDEP on March 14, 2012 
regarding the emissions limit that NDEP had proposed as BART for Unit 
3.\5\ Comments submitted on our June 22, 2011, proposed approval 
indicated that the actual average emission rate that RGGS reported for 
Unit 3 was significantly lower than NDEP's BART emissions limit for 
NO<INF>X</INF> of 0.28 lb/MMBtu. Pless Powers at 48. EPA also requested 
information regarding NDEP's basis for allowing a 12-month rolling 
average for NO<INF>X</INF> for Units 1-3, which was also raised as an 
issue in the comments. Pless Powers at 52.
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    \5\ Email dated March 14, 2012, from Colleen McKaughan (EPA) to 
Mike Elges (NDEP).
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    In response, NDEP informed EPA on March 22, 2012 that it had 
conducted further analysis resulting in NDEP's conclusion to lower the 
BART emissions limit for Unit 3 BART for NO<INF>X</INF> to 0.20 lb/
MMBtu.\6\ NDEP also informed EPA that its further analysis supported 
determining the NO<INF>X</INF> BART limit for all RGGS Units based on a 
30-day rolling average rather than the 12-month rolling average 
contained in the adopted rules and submitted SIP, provided that 
compliance is determined based on a three-unit average. Finally, NDEP 
indicated that it had evaluated requiring Selective Non-Catalytic 
Reduction (SNCR) with LNB and OFA rather than ROFA with Rotamix as 
BART. NDEP stated that Nevada Energy had installed ROFA on Unit 4 but 
that it has not operated as expected. NDEP anticipated SNCR with LNB 
and OFA would produce more reliable performance.
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    \6\ Letter dated March 22, 2012 from Mike Elges (NDEP) to 
Deborah Jordan (EPA).
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    The Nevada RH SIP included an evaluation of SNCR finding that it 
would result in a higher emissions limit for each unit than ROFA with 
Rotamix.\7\ NDEP's recent re-evaluation has concluded that SNCR with 
LNB and OFA would result in a NOx BART emissions limit of 0.20 lb/MMBtu 
for Units 1 through 3. NDEP indicates that it will submit a SIP 
revision by September 2012 that evaluates the substitution of SNCR with 
LNB and OFA for ROFA with Rotamix, lowers the NO<INF>X</INF> BART limit 
for RGGS Unit 3, and requires a NO<INF>X</INF> emissions limit of 0.20 
lb/MMBtu on a 30-day rolling average (averaged across all three 
units).\8\
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    \7\ As indicated by controlled emission rates summarized in 
Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. 
Available as Docket Item No. EPA-R09-OAR-2011-0130-0005.
    \8\ Letter dated March 22, 2012, from Mike Elges (NDEP) to 
Deborah Jordan (EPA).
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III. Overview of Proposed Action

    Today's proposal addresses the RGGS BART Determination for 
NO<INF>X</INF>, and if finalized, will complete our action on the 
Nevada Regional Haze SIP submitted on November 18, 2009. In its BART 
determination of RGGS, NDEP considered several control technologies, 
including Selective Catalytic Reduction (SCR), SNCR and ROFA with 
Rotamix. NDEP concluded that SCR would result in a very small 
incremental improvement of visibility over other technologies, which 
did not justify the incremental cost of installing and operating SCR. 
The results of our own analysis of the incremental visibility 
improvement and cost for SCR differ from NDEP's analysis in certain 
respects, but support NDEP's decision to establish a NO<INF>X</INF> 
BART emission limit that could be achieved with ROFA and Rotamix (or 
SNCR) rather than requiring an emission limit consistent with SCR 
technology. This proposal and our TSD provide additional information 
concerning our approval of NDEP's determination that SCR is not 
required as BART for RGGS. We considered the comments that we received 
on our June 22, 2011, proposed approval. We also conducted an 
independent modeling analysis to evaluate the incremental visibility 
improvement attributable to the NO<INF>X</INF> emission rates indicated 
in the RH SIP. Our analysis examined the visibility improvement that 
would be expected by requiring RGGS to meet a NO<INF>X</INF> emission 
limit of 0.06 lbs/MMbtu based on installation and operation of SCR. Our 
proposed approval is based in large part on this modeling analysis, 
discussed in detail below and in the TSD, showing that SCR controls at 
RGGS would not result in enough incremental visibility improvement at a

[[Page 21899]]

single Class I area to justify the incremental cost of the 
technology.\9\
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    \9\ In NDEP/Nevada Energy's analysis, and in our analysis, the 
highest impacted Class I area is Grand Canyon National Park.
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    Therefore, we are proposing to approve NDEP's determination that 
NO<INF>X</INF> BART for Units 1 and 2 is a limit of 0.20 lbs/MMBtu, 
which can be achieved with ROFA with Rotamix, or with SNCR with LNB and 
OFA. We are proposing to disapprove NDEP's NO<INF>X</INF> BART 
determination for RGGS Unit 3 and the SIP's provision to measure 
NO<INF>X</INF> emissions from Units 1 through 3 on a 12-month rolling 
average. Because we are proposing to disapprove these provisions of the 
SIP, we are concurrently proposing a FIP. Our FIP proposes promulgating 
a NO<INF>X</INF> BART emissions limit for RGGS Unit 3 of 0.20 lbs/
MMbtu. We are also proposing a FIP provision requiring that 
NO<INF>X</INF> emissions for RGGS Units 1 through 3 are measured on a 
rolling 30-day average (across all three units). Our justification for 
our proposed disapproval and proposed FIP provisions is discussed in 
detail in our Technical Support Document (TSD) in the docket for this 
Notice.

IV. Requirements for Regional Haze SIPs

A. Regional Haze Rule

    Regional haze SIPs must establish a long-term strategy that ensures 
reasonable progress toward achieving natural visibility conditions in 
each Class I area affected by the state's emissions. For a further 
discussion of this topic, please see our Notice of Proposed Rulemaking. 
76 FR 36450 (June 22, 2011).

B. Best Available Retrofit Technology

    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often uncontrolled, older 
stationary sources in order to address visibility impacts from these 
sources. Specifically, section 169A(b)(2)(A) of the CAA requires states 
to revise their SIPs to contain such measures as may be necessary to 
make reasonable progress towards the natural visibility goal, including 
a requirement that certain categories of existing major stationary 
sources \10\ built between 1962 and 1977 procure, install, and operate 
the ``Best Available Retrofit Technology'' as determined by the state. 
Under the RHR, states are directed to conduct BART determinations for 
such ``BART-eligible'' sources that may be anticipated to cause or 
contribute to any visibility impairment in a Class I area.
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    \10\ The set of ``major stationary sources'' potentially subject 
to BART is listed in CAA section 169A(g)(7).
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C. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the regional haze program will require 
long-term coordination among states, tribal governments and various 
federal agencies. EPA published on July 6, 2005, the Guidelines for 
BART Determinations under the Regional Haze Rule at Appendix Y to 40 
CFR part 51 (hereinafter referred to as the ``BART Guidelines'') to 
assist states in determining which of their sources should be subject 
to the BART requirements and in determining appropriate emission limits 
for each applicable source. In making a BART determination for a fossil 
fuel-fired electric generating plant with a total generating capacity 
in excess of 750 megawatts, a state must use the approach set forth in 
the BART Guidelines. In contrast, however, our BART Guidelines 
encourage, but do not require, States to follow the BART Guidelines in 
making BART determinations for other types of sources, including fossil 
fuel-fired electric generating plants with a total generating capacity 
that is less than 750 megawatts. 70 FR 39104, 39108 (July 6, 2005) 
(``The better reading of the Act indicates that Congress intended the 
guidelines to be mandatory only with respect to 750 megawatt power 
plants.'') The CAA, therefore, allows States to exercise broader 
discretion in applying the BART guidelines to power plants that are 
smaller than 750 megawatts, such as RGGS. Id.
    In their SIPs, states must document their BART control 
determination analyses. In making BART determinations, section 
169A(g)(2) of the CAA requires that states consider the following 
factors: (1) The costs of compliance; (2) the energy and non-air 
quality environmental impacts of compliance; (3) any existing pollution 
control technology in use at the source; (4) the remaining useful life 
of the source; and, (5) the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology. States are free to determine the weight and significance 
assigned to each factor, and as discussed above, generally have greater 
latitude in this determination for power plants that are smaller than 
750 megawatts.
    A regional haze SIP must include source-specific BART emission 
limits and compliance schedules for each source subject to BART. Once a 
state has made its BART determination, the BART controls must be 
installed and in operation as expeditiously as practicable, but no 
later than five years after the date EPA approves the regional haze 
SIP. CAA section 169(g)(4). 40 CFR 51.308(e)(1)(iv). In addition to 
what is required by the RHR, general SIP requirements mandate that the 
SIP must also include all regulatory requirements related to 
monitoring, recordkeeping and reporting for the BART controls on the 
source.

D. Lawsuits

    In two separate lawsuits, environmental groups sued EPA 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 two-year period allowed by CAA section 110(c) 
or, in the alternative, fully approve SIPs addressing these 
requirements. EPA entered into a Consent Decree agreeing to sign a 
Federal Register Notice taking action on the Nevada RH SIP by December 
13, 2011. The litigants agreed to extend our time for taking action on 
the RGGS NO<INF>X</INF> BART determination portion of the Nevada SIP 
given the extensive comments we received on our June 22, 2011, proposed 
approval. Our proposed action today meets our agreement with the 
litigants.

V. EPA's Analysis of Nevada's RH SIP

A. Affected Class I Areas

    There are four Class I areas within a 300 kilometer (km) radius of 
RGGS: Grand Canyon National Park, Bryce Canyon National Park, Zion 
National Park and Sycamore Canyon Wilderness. Joshua Tree National 
Monument is just on the border of the 300 km radius of RGGS. Of these, 
GCNP is the nearest area to RGGS, located at a distance of 85 km.

B. Identification of Sources Subject to BART

    EPA's final approval of the Nevada RH SIP agreed with NDEP's 
determination of its BART-eligible sources within the state, and its 
determination of which sources were subject to BART based on their 
contribution to visibility impairment. EPA's final approval included 
NDEP's BART determinations for the Tracy, Fort Churchill, and Mohave 
electrical generating stations.\11\ In our final approval of the Nevada 
RH SIP, we took no action on NDEP's NO<INF>X</INF> BART Determination 
for RGGS.
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    \11\ 77 FR 17334.

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[[Page 21900]]

C. Evaluation of Nevada's NO<INF>X</INF> BART Determination for Reid 
Gardner Generating Station

    Background: Reid Gardner is a coal-fueled, steam-electric 
generating plant with four operating units producing a total of 557 MW. 
Three of the units, built in 1965, 1968, and 1976 are BART-eligible, 
and were determined by NDEP to be subject to BART. Each of these units 
produces about 100 MW with steam boilers that drive turbine-generators. 
At present, the units are equipped with LNB and over-fire air (OFA) 
systems, mechanical collectors for particulate control, wet scrubbers 
that use soda ash for sulfur dioxide (SO<INF>2</INF>) removal, as well 
as recently installed baghouses. NDEP's review of Nevada Energy's BART 
report for RGGS resulted in NDEP agreeing only with the control 
technologies proposed as BART for SO<INF>2</INF> and 
PM<INF>10.</INF>\12\
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    \12\ EPA approved that portion of NDEP's BART determination for 
RGGS on December 13, 2011.
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    NOX BART Determination: NDEP performed a five-factor analysis for 
the BART-eligible units at RGGS that included several feasible 
technologies including SCR, SNCR, and ROFA with Rotamix, among other 
control technologies. NDEP eliminated SCR-based options and determined 
that BART controls for NO<INF>X</INF> are rotating opposed fire air 
(ROFA) with Rotamix for Units 1 through 3. For this control technology, 
NDEP determined emission limits, based on a rolling 12-month average, 
of 0.20 lb/MMBtu for Units 1 and 2, and 0.28 lb/MMBtu for Unit 3. In 
its five factor analysis, NDEP eliminated SCR because it gave 
significant weight to the incremental cost of compliance. NDEP also 
cited the relatively low visibility improvement at GCNP that would 
result from SCR over ROFA with Rotamix.
    EPA has carefully reviewed NDEP's BART analysis, focusing primarily 
on the incremental cost of compliance and incremental degree of 
improvement of visibility between SCR and ROFA with Rotamix. After 
receiving extensive comments in August 2011, we performed a significant 
amount of additional analysis for these two factors, including 
revisions to control cost calculations and new CALPUFF visibility 
modeling.
1. Costs of Compliance
    NDEP's analysis: NDEP evaluated the costs of compliance for each 
feasible NO<INF>X</INF> control option by analyzing the average and 
incremental cost effectiveness of each control technology. Average cost 
effectiveness ($/ton) is based on the total annualized cost ($) of a 
control option divided by the total amount of NO<INF>X</INF> removed 
(tons) by that control option. Incremental cost effectiveness is 
calculated when considering one control technology in relation to 
another, and examines the differing costs and the differing 
NO<INF>X</INF> removal ability of the two control options.
    When moving from a less stringent to a more stringent 
NO<INF>X</INF> control technology, the more stringent technology will 
result in greater amounts of NO<INF>X</INF> removal, but will also 
typically be more expensive. Incremental cost ($/ton) is calculated by 
dividing the difference in annualized costs ($) of the two technologies 
by the difference in NO<INF>X</INF> removal (ton) of the two 
technologies. Incremental costs are typically calculated ``in order'', 
by comparing one control technology with the less stringent technology 
immediately preceding it. The control cost data that NDEP included in 
the RH SIP and relied upon in making its NO<INF>X</INF> BART 
determination is summarized in Table 1 below.

                      Table 1--Summary of NDEP NOX BART Determination Results for RGGS Unit 1 Through 3 (as Included in the RH SIP)
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                                                                                                Emission
                                                                      Control      Emission    reduction    Annualized   Average cost   Incremental cost
                          Control option                             efficiency    rate \1\    \1\ (ton/    costs \1\    effectiveness    effectiveness
                                                                      \1\ (%)     (lb/MMBtu)      yr)         ($MM)       \1\ ($/ton)      \1\ ($/ton)
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                                                                   Reid Gardner Unit 1
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LNB + OFA (enhanced)..............................................         21.3         0.36          483        $0.55          $1,143            $1,143
LNB + OFA + SNCR..................................................         40.9         0.27          927         1.13           1,222             1,308
ROFA + Rotamix....................................................         57.7          0.2         1308         1.45           1,109               833
SCR + LNB + OFA...................................................         81.6        0.085         1850         4.75           2,566             6,085
SCR + ROFA \3\....................................................         81.6        0.085         1850         5.39           2,916             7,280
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                                                                   Reid Gardner Unit 2
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LNB + OFA (enhanced)..............................................         23.7        0.355          580         0.55             952               952
LNB + OFA + SNCR..................................................         42.7        0.267         1044         1.16           1,106             1,299
ROFA + Rotamix....................................................         59.0         0.19         1443         1.50           1,038               860
SCR + LNB + OFA...................................................         82.2        0.083         2010         4.80           2,386             5,813
SCR + ROFA \3\....................................................         82.2        0.083         2010         5.47           2,721             7,001
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                                                                   Reid Gardner Unit 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNB + OFA (enhanced)..............................................          6.5         0.42          147         0.55           3,742             3,742
LNB + OFA + SNCR..................................................         29.9        0.316          678         1.08           1,596             1,000
ROFA + Rotamix....................................................         38.0        0.278          869         1.38           1,588             1,560
SCR + LNB + OFA...................................................         78.2        0.098         1774         4.72           2,660             3,688
SCR + ROFA \2\....................................................         78.2        0.098         1774         5.40           3,045             4,444
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ As summarized in Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005.
\2\ Incremental cost effectiveness based on ROFA + Rotamix as previous control technology.


[[Page 21901]]

    The annualized costs listed in Table 1 are based on total capital 
installation costs and certain annual operating costs submitted to NDEP 
by Nevada Energy in its BART analysis. These costs were relied upon by 
NDEP and included in the SIP without modification. These cost 
calculations provided line item summaries of capital costs and annual 
operating costs, but did not provide further supporting information 
such as detailed equipment lists, vendor quotes, or the design basis 
for line item costs.
    In its RH SIP, NDEP indicated that it based its NO<INF>X</INF> BART 
determination of ROFA with Rotamix rather than SCR primarily on the 
incremental costs of compliance. NDEP judged the costs of ROFA with 
Rotamix as cost effective based on an average cost effectiveness of 
approximately $1100-1600/ton, as seen in Table 1. NDEP then eliminated 
more stringent control options, such as the SCR-based options, based on 
high incremental cost effectiveness. Specifically, NDEP stated that 
``the $/ton of NO<INF>X</INF> removed increased significantly * * * 
without correspondingly significant improvements in visibility.'' \13\ 
Per NDEP estimates, the incremental cost effectiveness of SCR with LNB 
and OFA is approximately $3,600-6,100/ton. NDEP determined that this 
additional incremental cost per ton for SCR technologies did not appear 
cost effective compared to the incremental visibility improvement 
achieved by the SCR-based control options.
---------------------------------------------------------------------------

    \13\ Revised NDEP Reid Gardner BART Determination Review, page 
6. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005.
---------------------------------------------------------------------------

    EPA's analysis: In reviewing the Nevada RH SIP and public comments, 
we identified several aspects of NDEP's approach to this factor with 
which we disagreed, and for which we have performed additional 
analysis. We received several public comments that NDEP's cost 
calculations were overestimated and based on methodology inconsistent 
with EPA's Control Cost Manual (CCM).\14\ We agree that NDEP included 
inappropriate costs and our analysis excludes those costs that are not 
allowed by the CCM. Therefore, we have revised these cost calculations 
and adjusted the value of specific variables to conform to values 
allowed by the CCM. Aside from these items, other commenters alleged 
that aspects of NDEP's cost estimates were unjustified or 
overestimated, such as a failure to account for multiple unit discount 
and overestimated reagent costs.\15\ We agree that the record does not 
support the positions that NDEP has taken on these cost items. However, 
we did not account for these additional discrepancies in our revised 
cost estimate since disallowing those costs not in the CCM resulted in 
our finding that SCR is cost effective. The disallowed costs result in 
a decrease of 25-33 percent in the average and incremental cost 
effectiveness of the control technology options. Detailed cost 
calculations, in which we revised the original cost calculations (as 
included in the RH SIP) and the updated cost calculations (as provided 
by NDEP on February 14, 2012) for each NO<INF>X</INF> control 
technology, are included in Appendix A of our TSD. Summarized in Table 
2 below is a comparison of the updated NDEP cost calculations (as 
provided on February 14, 2012) and our revised cost calculations for 
the SCR with LNB and OFA control technology option.
---------------------------------------------------------------------------

    \14\ See comments from NPCA Consortium (EPA-R09-OAR-2011-0130-
0062), National Park Service and U.S. Fish and Wildlife Service 
(EPA-R09-OAR-2011-0130-0054) and in expert report by Petra Pless/
Bill Powers (attachment to EPA-R09-OAR-2011-0130-0062).
    \15\ These items were primarily noted in the expert report by 
Petra Pless/Bill Powers (attachment to EPA-R09-OAR-2011-0130-0062).

      Table 2--Cost Effectiveness Comparison--SCR With LNB and OFA
------------------------------------------------------------------------
                                  Average cost        Incremental cost
                               effectiveness  ($/    effectiveness  ($/
                                      ton)                  ton)
          Unit No.           -------------------------------------------
                                            EPA                   EPA
                                 NDEP     revised      NDEP     revised
------------------------------------------------------------------------
Unit 1......................     $2,827     $2,110     $6,370     $4,534
Unit 2......................      2,627      1,967      6,080      4,330
Unit 3......................      2,932      2,183      3,856      2,756
------------------------------------------------------------------------

    Based on our revised cost estimates, we do not consider these 
average and incremental cost effectiveness values for SCR with LNB and 
OFA as cost prohibitive. Our analysis of this factor indicates that 
costs of compliance (average and incremental) are not sufficiently 
large to warrant eliminating SCR from consideration.
    The incremental cost effectiveness values for Units 1 and 2 are 
around $4,500/ton. Although EPA does not consider this incremental cost 
prohibitive, we note that the State has certain discretion in weighing 
this cost. Because RGGS is not a facility over 750 megawatts and 
therefore not subject to EPA's presumptive BART limits, the State may 
exercise its discretion more broadly in this particular determination.
2. Degree of Visibility Improvement
    NDEP's Analysis: As part of its BART analysis, Nevada Energy 
performed visibility modeling in order to evaluate the visibility 
improvement attributable to each of the NO<INF>X</INF> control 
technologies that it considered. Results of the visibility modeling 
performed by Nevada Energy in its submittal to NDEP are summarized in 
Table 3 below.

[[Page 21902]]



                     Table 3--Summary of Nevada Energy Estimates of Visibility Benefit \16\
----------------------------------------------------------------------------------------------------------------
                                                           Visibility improvement (from WRAP        Visibility
                                                                    baseline) \17\                  improvement
                                                     --------------------------------------------  (incremental,
                   Control option                                                                  from control)
                                                        RGGS1      RGGS2      RGGS3      Total   ---------------
                                                         (dv)       (dv)       (dv)       (dv)      Total  (dv)
----------------------------------------------------------------------------------------------------------------
LNB + OFA (enhanced)................................      0.440      0.479      0.407       1.33  ..............
LNB + OFA + SNCR....................................      0.521      0.560      0.485       1.57            0.24
ROFA + Rotamix......................................      0.592      0.630      0.514       1.74            0.17
SCR + LNB + OFA.....................................      0.698      0.735      0.652       2.09            0.35
SCR + ROFA \18\.....................................      0.698      0.735      0.652       2.09            0.35
----------------------------------------------------------------------------------------------------------------

    Based upon these results, the installation of SCR with LNB and OFA 
would result in an incremental visibility improvement at Grand Canyon 
National Park of 0.35 deciviews (dv). This visibility improvement is 
based upon the NO<INF>X</INF> emission rates estimated by Nevada Energy 
in their BART analysis for each control technology option, and is 
relative to visibility impacts based on emissions used by the Western 
Regional Air Partnership (WRAP). In preparing the RH SIP, however, NDEP 
developed its own set of NO<INF>X</INF> emission estimates for the 
various control technology options. The differences between Nevada 
Energy's estimates and the emission estimates that form the basis of 
the Nevada RH SIP are summarized in Table 4 below.
---------------------------------------------------------------------------

    \16\ Visibility improvement listed here are for the Class I area 
with the highest impact, Grand Canyon National Park. They represent 
the change in the 98th percentile impacts from three modeled years. 
The ``total'' is the simple total of the impacts from the three 
individual units, which Nevada Energy modeled separately.
    \17\ From Table 5-4 of NVE BART Analysis Reports, Reid--
Gardner--1--10-03-08.pdf, Reid--Gardner--2--10-03-08.pdf, Reid--
Gardner--3--10-03-08.pdf. Available in Docket Item No. EPA-R09-OAR-
2011-0130-0007. The improvements here are relative to the ``WRAP 
baseline'', impacts from emission levels used by the Western 
Regional Air Partnership and modeled by Nevada Energy. This is a 
different ``baseline'' than used for the cost estimates below.
    \18\ Incremental visibility benefit of SCR + ROFA is based upon 
ROFA + Rotamix as previous control technology.

               Table 4--Comparison of Nevada Energy and NDEP Control Technology Emission Estimates
----------------------------------------------------------------------------------------------------------------
                                                                    Nevada energy                 NDEP
                                                             ---------------------------------------------------
                       Control option                           Emission     Control      Emission     Control
                                                               factor \1\   efficiency   factor \3\   efficiency
                                                               (lb/MMBtu)    \2\ (%)     (lb/MMBtu)    \3\ (%)
----------------------------------------------------------------------------------------------------------------
                                               Reid Gardner Unit 1
----------------------------------------------------------------------------------------------------------------
Baseline (LNB + OFA)........................................         0.38  ...........        0.462  ...........
LNB + OFA (enhanced)........................................         0.30         21.3        0.360         21.3
LNB + OFA + SNCR............................................         0.23         40.9        0.270         40.9
ROFA + Rotamix..............................................         0.16         57.7        0.200         57.7
SCR + LNB + OFA.............................................         0.07         81.6        0.085         81.6
SCR + ROFA..................................................         0.07         81.6        0.085         81.6
----------------------------------------------------------------------------------------------------------------
                                               Reid Gardner Unit 2
----------------------------------------------------------------------------------------------------------------
Baseline (LNB + OFA)........................................        0.393  ...........        0.466  ...........
LNB + OFA (enhanced)........................................         0.30         23.7        0.355         23.7
LNB + OFA + SNCR............................................         0.23         42.7        0.267         42.7
ROFA + Rotamix..............................................         0.16         59.0        0.190         59.0
SCR + LNB + OFA.............................................         0.07         82.2        0.083         82.2
SCR + ROFA..................................................         0.07         82.2        0.083         82.2
----------------------------------------------------------------------------------------------------------------
                                               Reid Gardner Unit 3
----------------------------------------------------------------------------------------------------------------
Baseline (LNB + OFA)........................................         0.32  ...........        0.451  ...........
LNB + OFA (enhanced)........................................         0.30          6.5        0.420          6.5
LNB + OFA + SNCR............................................         0.23         29.9        0.316         29.9
ROFA + Rotamix..............................................         0.20         38.0        0.278         38.0
SCR + LNB + OFA.............................................         0.07         78.2        0.098         78.2
SCR + ROFA..................................................         0.07         78.2        0.098         78.2
----------------------------------------------------------------------------------------------------------------
\1\ From each respective unit's NVE BART Analysis, Table 3-1. Available in Docket Item No. EPA-R09-OAR-2011-0130-
  0007.
\2\ From each respective unit's NVE BART Analysis, Table 3-2. Available in Docket Item No. EPA-R09-OAR-2011-0130-
  0007.
\3\ As summarized in Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. Available as Docket Item
  No. EPA-R09-OAR-2011-0130-0005. Baseline emission factor is not explicitly calculated by NDEP. The factor
  listed in this table represents the listed annual emissions divided by ``Base Heat Input''.


[[Page 21903]]

    As seen in these tables, NDEP's estimates of controlled emission 
rates differ from Nevada Energy's estimates. These differences are a 
result of NDEP's use of a different emission baseline in its 
calculations than Nevada Energy, which is discussed below in our 
discussion of existing pollution control technology. Since NDEP elected 
to calculate controlled emission rates by retaining the respective 
percent reduction values for each control technology, rather than each 
control technology's emission rate (lb/MMBtu), the use of a higher 
baseline emission rate results in higher emission estimates for each 
control technology option. As a result, NDEP's estimated performance 
for each control technology is less stringent than Nevada Energy's 
estimates. NDEP, however, did not perform additional modeling to 
determine the visibility improvement attributable to its emission 
estimates, and continued to rely on the visibility modeling performed 
by Nevada Energy.
    As noted in the discussion of cost of compliance, part of NDEP's 
basis for rejecting control technology options more stringent that ROFA 
with Rotamix as BART was that the incremental costs of more stringent 
control options were not justified relative to their corresponding 
increases in visibility improvement. However, without updated 
visibility modeling that indicates the visibility improvement 
attributable to NDEP's emission estimates, we do not consider NDEP to 
have properly considered the appropriate magnitude of incremental 
visibility improvement in reaching its determination. As discussed 
below, we have performed our own visibility modeling to determine these 
visibility impacts.
    EPA's Analysis: In performing our own visibility modeling, the 
primary goal of our approach was to determine the visibility 
improvement associated with the NO<INF>X</INF> emission estimates 
relied upon in the RH SIP. In developing a modeling strategy, we 
decided that an approach that consisted of simply using Nevada Energy's 
modeling with model emission rates updated to reflect NDEP's estimates 
was not appropriate. As a result of changes to CALPUFF regulatory 
guidance that have occurred in the intervening time since Nevada Energy 
performed its visibility modeling, we elected to perform our visibility 
modeling in a manner that more closely adheres with current EPA 
regulatory guidance on CALPUFF modeling. Key elements of our modeling 
approach that differ from Nevada Energy's modeling include:

--CALPUFF system version: We performed our visibility modeling using 
version 5.8 of the CALPUFF model, and version 5.8 of the CALMET 
meteorological preprocessor, which are the current regulatory-approved 
versions. Nevada Energy's modeling used CALPUFF version 6.112, and 
CALMET version 6.211.
--Meteorological inputs: We used the meteorological inputs developed by 
the Western Regional Air Partnership, augmented with upper air data. 
Nevada Energy's modeling used some different inputs, and did not 
incorporate upper air data.
--SCR catalyst conversion efficiency: We performed our visibility 
modeling using an SCR catalyst SO<INF>2</INF> to SO<INF>3</INF> 
conversion efficiency of 0.5 percent for purposes of calculating 
sulfuric acid emissions. Nevada Energy's modeling relied upon 1 percent 
conversion efficiency.
--Calculation of visibility impact: We calculated our visibility 
impacts using the revised IMPROVE equation (Method 8, mode 5) \19\ in 
addition to the original IMPROVE equation (Method 6). Nevada Energy's 
modeling was performed before the availability of modeling guidance 
regarding the use of the revised IMPROVE equation and its incorporation 
into CALPUFF as Method 8.
---------------------------------------------------------------------------

    \19\ The IMPROVE equation translates modeled or monitored 
concentrations of pollutants like sulfate and nitrate into 
extinction, a measure of visibility. See: http://vista.cira.colostate.edu/improve/Extinction, in turn, is used to 
calculate deciviews, the visibility impact metric used in the BART 
Guidelines. The various visibility ``methods'' in CALPUFF differ in 
how they account for background concentrations and adjustments for 
relative humidity. Method 8, mode 5 is the currently-recommended 
method. ``Federal Land Managers' Air Quality Related Values 
Workgroup (FLAG) Phase I Report'' (December 2000), U.S. Forest 
Service, National Park Service, U.S. Fish And Wildlife Service. See: 
http://www.nature.nps.gov/air/Pubs/pdf/flag/FlagFinal.pdf.
---------------------------------------------------------------------------

--Control technology performance: We performed our visibility modeling 
using the NO<INF>X</INF> baseline emission rate and NO<INF>X</INF> 
control technology emission rates listed under the ``NDEP'' column in 
Table 4, which had not previously been modeled.
--In addition, we modeled another SCR control technology case 
corresponding to a NO<INF>X</INF> emission rate of 0.06 lb/MMBtu. As 
indicated in Table 4, both Nevada Energy and NDEP used control 
efficiency values in the range of 78 to 82 percent to estimate SCR 
performance. Typical SCR catalyst vendor guarantees can indicate 90 
percent NO<INF>X</INF> reduction.\20\ We have elected to model 0.06 lb/
MMBtu based on a selection of a mid-range control efficiency of 85 
percent reduction from Nevada Energy's NO<INF>X</INF> emission 
baseline.
---------------------------------------------------------------------------

    \20\ We received public comments to this effect that included 
multiple vendor quotes. Available as attachments to Docket Items 
EPA-R09-OAR-2011-0130-0062 and -0063.
---------------------------------------------------------------------------

    A more detailed discussion of our visibility modeling, including 
full visibility results for all Class I areas located within 300 km of 
RGGS, is in our TSD and associated emission calculation spreadsheet. A 
summary of visibility results is presented in Table 5 below.

                 Table 5--Summary of Visibility Impacts
------------------------------------------------------------------------
                                                 Visibility improvement
                                   Visibility --------------------------
                                   Impact \1\               Incremental,
         Control option            (all three      From         from
                                  units) (dv)    baseline     previous
                                                   (dv)      option (dv)
------------------------------------------------------------------------
Baseline (LNB w/OFA)............         0.59  ...........  ............
LNB w/OFA (enhanced)............         0.51         0.08          0.08
SNCR + LNB w/OFA................         0.37         0.21          0.13
ROFA w/Rotamix..................         0.31         0.28          0.06
SCR w/LNB + OFA.................         0.22         0.36          0.09

[[Page 21904]]

 
SCR w/LNB + OFA \2\ (0.06 lb/            0.20         0.38          0.10
 MMBtu, each unit)..............
------------------------------------------------------------------------
\1\ Visibility impact summarized here represents the three-year 98th
  percentile impact at the Class I area with the highest impact, Grand
  Canyon National Park All three units were modeled together. The
  CALPUFF model output was post-processed using CALPOST visibility
  Method 8, the revised IMPROVE equation, and using natural background
  concentrations for the best 20% of days. For full visibility results,
  including impacts at other Class I areas within 300 km and using other
  visibility methods, please see the TSD in today's docket.
\2\ Incremental visibility improvement compared to ROFA with Rotamix.

    As seen in these results, the total incremental visibility 
improvement resulting from the installation of SCR with LNB and OFA 
compared to ROFA with Rotamix is 0.09 dv. This occurred at Grand Canyon 
National Park, the Class I area with the highest impact. In addition, 
we note that even our additional scenario that models the SCR control 
option at a 0.06 lb/MMBtu level of performance results in an 
incremental visibility improvement of only 0.10 dv relative to ROFA 
with Rotamix. Based on this small quantity of incremental visibility 
improvement, we agree with NDEP's conclusion that the control options 
more stringent than ROFA with Rotamix (or SNCR with LNB and OFA 
achieving the same emission limit) are not justified.
3. Existing Pollution Control Technology
    NDEP's analysis: Nevada Energy prepared and submitted a BART 
analysis to NDEP that accounted for the presence of low-NO<INF>X</INF> 
burners by using baseline NO<INF>X</INF> emission factors corresponding 
to 2004 actual emissions data.\21\ In preparing the RH SIP, NDEP 
developed a baseline NO<INF>X</INF> emission factor that was based upon 
past actual emission data over a 2001-07 time frame.\22\ This resulted 
in baseline NO<INF>X</INF> emission rates that are approximately 15 
percent higher than those presented in Nevada Energy's BART analysis.
---------------------------------------------------------------------------

    \21\ Baseline emission factors as listed in Table 2-2 of each 
unit's respective Nevada Energy BART Analysis. Available as 
attachments to EPA-R09-OAR-2011-0130-0007.
    \22\ Per NDEP's Reid Gardner BART Determination Summary, NDEP 
used the average of the two consecutive years with highest annual 
emissions. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005.
---------------------------------------------------------------------------

    EPA's analysis: While NDEP's use of a set of baseline emissions 
different from those presented in Nevada Energy's BART analysis does 
result in a higher baseline emission rate, NDEP's baseline emissions 
still reflect the use of low-NO<INF>X</INF> burners. We find that 
NDEP's approach to this factor is reasonable, and have not modified 
NDEP's NO<INF>X</INF> emission baseline in performing our own analysis. 
We do note that due to the emission calculation methodology NDEP used 
to calculate NO<INF>X</INF> control scenario emissions, increases to 
the NO<INF>X</INF> emission baseline will affect emission estimates for 
NO<INF>X</INF> control scenarios. These effects are discussed further 
in the analysis of degree of visibility impact.
4. Remaining Useful Life of the Source
    NDEP's analysis: In its BART analysis submittal to NDEP, Nevada 
Energy used a plant economic life of 20 years and performed control 
technology cost calculations based on control equipment lifetime equal 
to the plant economic life. In developing the RH SIP, NDEP relied upon 
these cost calculations without revision.
    EPA's analysis: Use of a 20-year equipment life is consistent with 
assumptions made in EPA's Control Cost Manual for the equipment 
lifetime of certain NO<INF>X</INF> control technologies such as SCR and 
SNCR. Commenters alleged that without a firm shutdown date to ensure a 
plant lifetime of 20 years, a longer equipment life should be used in 
cost calculations. Use of a longer equipment life would result in lower 
annualized costs, thereby making control technologies more cost 
effective. As discussed further in the analysis of costs of compliance, 
we already consider certain control technology options more stringent 
than ROFA with Rotamix, such as SCR with LNB and OFA, to be cost 
effective. As a result, we decline to pursue an analysis examining 
whether use of a 20-year plant economic life is appropriate.
5. Energy and Non-Air Quality Impacts
    NDEP's Analysis: In its BART analysis submitted to NDEP, Nevada 
Energy identified certain energy impacts such as increased energy usage 
associated with ROFA as a result of induced draft fan installations. 
For SCR installations, increased energy usage is expected in order for 
existing fan systems to compensate for the additional pressure drop 
created by the SCR catalyst bed. Nevada Energy quantified these energy 
impacts as annual operating cost line items in cost calculations.
    Non-air quality impacts identified by Nevada Energy in its BART 
analysis include the potential for ammonia slip from SCR or SNCR to 
impact the salability and disposal of fly ash, as well as to create a 
visible stack plume. The potential for transportation and storage of 
ammonia to result in an accidental release was also identified as a 
potential non-air quality impact. Nevada Energy cited these as negative 
impacts in its consideration of SCR and SNCR control options. In 
preparing the RH SIP, NDEP did not further expand on these impacts in 
determining ROFA with Rotamix as BART for NO<INF>X</INF>.
    EPA's Analysis: Although we consider the energy impacts accounted 
for by Nevada Energy to be reasonable, we note that supporting 
calculations were not provided for the line item cost associated with 
these impacts in control cost calculations. At this time, we decline to 
provide our own estimate of these impacts. Regarding non-air quality 
impacts, while we acknowledge that the items described by Nevada Energy 
are indeed potential concerns for the control technologies considered, 
we note that neither Nevada Energy's analysis nor the RH SIP provide 
further information discussing the extent to which these are site-
specific concerns for RGGS Units 1 through 3. As a result, we consider 
these non-air quality impacts as not sufficiently significant at RGGS 
to warrant eliminating any of the control technology options.

VI. Federal Implementation Plan To Address NO<INF>X</INF> BART for Reid 
Gardner

    Although our analysis supports NDEP's decision to not require 
control technology options more stringent than ROFA with Rotamix (or 
SNCR with LNB and OFA achieving the same emissions

[[Page 21905]]

limit) as BART, completion of the BART process requires establishing 
enforceable emission limits that reflect the BART control technology 
requirements.\23\ As described in the sections below, we find certain 
elements of the emission limits established for RGGS in the RH SIP as 
either unsupported by the record or inconsistent with BART Guidelines. 
NDEP notified us in a letter dated March 22, 2012 that it intends to 
submit a RH SIP revision that will address these elements, which 
include establishing a NO<INF>X</INF> limit of 0.20 lb/MMBtu for Unit 
3, and establishing NO<INF>X</INF> limits for each unit on a 30-day 
rolling average (averaged across all three units), rather than a 12-
month rolling average. In addition, NDEP has indicated that the RH SIP 
revision it intends to submit will revise the selected control 
technology from ROFA with Rotamix to SNCR with LNB and OFA.
---------------------------------------------------------------------------

    \23\ 70 FR 39172.
---------------------------------------------------------------------------

    In order to meet the terms of our consent decree, it is necessary 
for EPA to propose action on Nevada's RH SIP at this time. As a result, 
we are proposing the promulgation of a FIP that will address the 
elements described below. We expect these elements to match the content 
of the revised RH SIP that Nevada has indicated it intends to submit.
    Based upon the March 22, 2012 letter sent by NDEP indicating its 
intent to submit a revised RH SIP, we do not expect to receive the 
revised RH SIP prior to our consent decree deadline for final action on 
this proposal. Although we will not receive the revised RH SIP prior to 
our final action, we do intend to act expeditiously on the revised RH 
SIP once it is submitted to EPA.

A. Unit 1 Through 3 Averaging Period

    We are proposing to promulgate a FIP to establish a NO<INF>X</INF> 
emission limit of 0.20 lb/MMBtu for Unit 3. In its RH SIP, NDEP 
proposed a NO<INF>X</INF> emission limit of 0.28 lb/MMBtu for Unit 3. 
This limit for Unit 3 (0.28 lb/MMBtu) was higher than the emission 
limit NDEP proposed for Units 1 or 2 (0.20 lb/MMBtu each). The higher 
emission limit appears to be partially attributable to the fact that 
the application of control technology to Unit 3 was projected to result 
in less stringent levels of performance relative to Units 1 and 2. As 
shown in Table 4 of this notice, Nevada Energy's emission estimates 
indicate that application of ROFA with Rotamix achieves nearly 60 
percent reduction from baseline on Units 1 and 2, but only a 38 percent 
reduction from baseline on Unit 3. These percent reduction values were 
used by NDEP in developing its own estimate of NO<INF>X</INF> 
emissions, which form the basis for the proposed NO<INF>X</INF> limits.
    Nevada Energy's BART analysis for Unit 3 did not provide a unit-
specific explanation for this difference in control effectiveness. In 
responding to comments on this issue, NDEP indicated that it deferred 
to Nevada Energy's operational experience in developing control 
efficiency data, and had no reason to question Nevada Energy's 
estimates.\24\ The case-by-case nature of the BART determination 
process does provide for the consideration of site-specific and unit-
specific characteristics in the BART analysis.\25\ While there may be 
unique characteristics associated with Unit 3 that justify the lower 
percent reduction values used by Nevada Energy and NDEP, we do not find 
the record on this issue to be sufficiently detailed to support this 
determination. In the absence of what we consider sufficient 
justification by Nevada Energy and NDEP, we have evaluated Unit 3 
control option emissions predicated upon similar levels of performance 
relative to Units 1 and 2. Based upon the Unit 3 baseline emissions 
relied upon by NDEP (described in the `NDEP' column in Table 4), if a 
percent reduction similar to Units 1 and 2 were applied to Unit 3 
baseline emissions, it can be expected to attain a NO<INF>X</INF> 
emission rate of 0.20 lb/MMBtu using the ROFA with Rotamix control 
option.
---------------------------------------------------------------------------

    \24\ Page D-37, Appendix D and C-9, Appendix C, Nevada RH SIP. 
Available as attachments to EPA-R09-OAR-2011-0130-0003.
    \25\ For example, when determining what control options are 
considered technically feasible at a specific unit, 70 FR 39165.
---------------------------------------------------------------------------

B. Unit 3 Emission Limit

    We are proposing to promulgate a FIP to establish a 30-day rolling 
average, averaged across all three units, as the basis for the 
NO<INF>X</INF> emission limits for RGGS Units 1 through 3. In its RH 
SIP, NDEP proposed NO<INF>X</INF> limits for Units 1 through 3 based 
upon a 12-month rolling average, which is a longer averaging period 
than the 30-day rolling average indicated by the BART Guidelines. 
Longer averaging periods allow operators the flexibility to ``smooth 
out'' short-term emission spikes by averaging those values with periods 
of lower emission rates. In responding to comments on this issue in its 
RH SIP, NDEP indicated that it specified the longer averaging period 
because Nevada Energy expected a high degree of operational variability 
with the ROFA with Rotamix control option based upon previous 
operational experience with ROFA.\26\ Although operational flexibility 
can be a legitimate consideration when establishing an enforceable 
limit, we consider use of a rolling 12-month averaging period instead 
of a rolling 30-day average to be inconsistent with BART 
Guidelines.\27\ We believe the fluctuations of the NO<INF>X</INF> 
emissions from each of the units is better dealt with by averaging the 
emissions from the three units to determine compliance over the 30-day 
rolling average.
---------------------------------------------------------------------------

    \26\ Page D-60, Appendix D, Nevada RH SIP. Available as 
attachments to EPA-R09-OAR-2011-0130-0003.
    \27\ 70 FR 39172.
---------------------------------------------------------------------------

C. Control Technology Basis

    In its RH SIP, NDEP proposed emission limits for Units 1 through 3 
based upon a control technology determination of ROFA with Rotamix. In 
its March 22, 2012 letter, NDEP indicated that it intends to submit an 
RH SIP revision that will revise the control technology determination 
to SNCR with LNB and OFA. In addition, the corresponding BART emission 
limits for NO<INF>X</INF> that NDEP has indicated it will establish for 
Units 1 through 3 are of equal or greater stringency than those 
included in the current RH SIP.
    In its RH SIP, NDEP estimated that SNCR with LNB and OFA would be 
capable of achieving a NO<INF>X</INF> emission rate in the range of 
0.27 to 0.31 lb/MMBtu (as summarized in Table 1 of this notice). These 
emission rates indicate that the SNCR with LNB and OFA control option 
is less stringent than ROFA with Rotamix, which NDEP estimated would be 
capable of achieving a NO<INF>X</INF> emission rate in the range of 
0.20 to 0.28 lb/MMBtu. As noted in the BART Guidelines, BART ``means an 
emission limitation based on the degree of reduction achievable through 
the application of the best system of continuous emission reduction.'' 
\28\ Although NDEP may propose a less stringent control technology 
determination in a future RH SIP revision, we would not consider the 
final BART determination to be less stringent if the selected control 
option is capable of meeting the NO<INF>X</INF> emission limit of 0.20 
lb/MMBtu (30-day rolling average, averaged across all three units) 
established in our FIP.
---------------------------------------------------------------------------

    \28\ 70 FR 39163.
---------------------------------------------------------------------------

VI. Federal Implementation Plan To Address NO<INF>X</INF> BART for Reid 
Gardner

    With the exception of the NO<INF>X</INF> BART emission limit for 
Unit 3 and the NO<INF>X</INF> averaging time for all three units, EPA 
is proposing to find the Nevada RH BART determination for 
NO<INF>X</INF> fulfills all

[[Page 21906]]

the relevant requirements of CAA Section 169A and the Regional Haze 
Rule. Therefore, we are proposing to approve NDEP's conclusion that SCR 
is not required as BART for NO<INF>X</INF>. NDEP weighed the 
incremental cost of requiring SCR against the relatively small 
visibility improvement that would be achieved from installing and 
operating SCR. NDEP's incremental cost included costs that 
inappropriately increased the cost estimate. However, NDEP is allowed 
to weigh the incremental cost against the incremental visibility 
improvement. Our independent modeling found that incremental visibility 
improvement at adjacent Class I areas would be significantly lower than 
the improvement modeled by NDEP. This information supports our 
determination that NDEP is within the discretion allowed by the BART 
Guidelines to establish the NO<INF>X</INF> emissions limit that can be 
achieved with ROFA and Rotamix (or SNCR with LNB and OFA achieving the 
same emissions limit) as BART rather than requiring an emission limit 
consistent with SCR technology.
    NDEP, however, failed to support applying a higher emission limit 
for Unit 3 and failed to provide a sufficient basis for approving the 
emissions limit on a 12-month rolling average. Therefore, EPA is 
disapproving the RGGS NO<INF>X</INF> BART determination for Unit 3 and 
promulgating a FIP setting the same emission limit for Unit 3 that NDEP 
set for Units 1 and 2. EPA is also promulgating a FIP requiring Units 1 
through 3 to meet the NO<INF>X</INF> emissions limit of 0.20 lbs/mmbtu 
on a rolling 30-day average (across all three units).

VII. EPA's Proposed Action

A. Executive Order 12866: Regulatory Planning and Review

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 
1993), and is therefore not subject to review under the Executive 
Order. The proposed FIP applies to only one facility and is therefore 
not a rule of general applicability.

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Under the Paperwork Reduction Act, a ``collection of 
information'' is defined as a requirement for ``answers to * * * 
identical reporting or recordkeeping requirements imposed on ten or 
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP 
applies to just one facility, the Paperwork Reduction Act does not 
apply. See 5 CFR 1320(c).
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any requirements; train personnel to be able to respond to 
a collection of information; search data sources; complete and review 
the collection of information; and transmit or otherwise disclose the 
information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid Office of Management and Budget (OMB) control number. 
The OMB control numbers for our regulations in 40 CFR are listed in 40 
CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this proposed action on 
small entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
The Regional Haze FIP for the single facility being proposed today does 
not impose any new requirements on small entities. The proposed partial 
approval of the SIP, if finalized, merely approves state law as meeting 
Federal requirements and imposes no additional requirements beyond 
those imposed by state law. See Mid-Tex Electric Cooperative, Inc. v. 
FERC, 773 F.2d 327 (D.C. Cir. 1985)

D. Unfunded Mandates Reform Act (UMRA)

    Under sections 202 of the Unfunded Mandates Reform Act of 1995 
(``Unfunded Mandates Act''), signed into law on March 22, 1995, EPA 
must prepare a budgetary impact statement to accompany any proposed or 
final rule that includes a Federal mandate that may result in estimated 
costs to State, local, or tribal governments in the aggregate; or to 
the private sector, of $100 million or more (adjusted to inflation) in 
any 1 year. Under section 205, EPA must select the most cost-effective 
and least burdensome alternative that achieves the objectives of the 
rule and is consistent with statutory requirements. Section 203 
requires EPA to establish a plan for informing and advising any small 
governments that may be significantly or uniquely impacted by the rule.
    Under Title II of UMRA, EPA has determined that this proposed rule 
does not contain a Federal mandate that may result in expenditures that 
exceed the inflation-adjusted UMRA threshold of $100 million by State, 
local, or Tribal governments or the private sector in any 1 year. In 
addition, this proposed rule does not contain a significant Federal 
intergovernmental mandate as described by section 203 of UMRA nor does 
it contain any regulatory requirements that might significantly or 
uniquely affect small governments.

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces 
Executive Orders 12612 (Federalism) and 12875 (Enhancing the 
Intergovernmental Partnership). Executive Order 13132 requires EPA to 
develop an accountable process to ensure ``meaningful and timely input 
by State and local officials in the development of regulatory policies 
that have federalism implications.'' ``Policies that have federalism 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.'' Under Executive Order 13132, EPA may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not

[[Page 21907]]

required by statute, unless the Federal government provides the funds 
necessary to pay the direct compliance costs incurred by State and 
local governments, or EPA consults with State and local officials early 
in the process of developing the proposed regulation. EPA also may not 
issue a regulation that has federalism implications and that preempts 
State law unless the Agency consults with State and local officials 
early in the process of developing the proposed regulation.
    This rule will not have substantial direct effects on the States, 
on the relationship between the national government and the States, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132, because it 
merely addresses elements of the State's Regional Haze SIP that are 
inconsistent with the Regional Haze Rule. In addition, the State has 
indicated that it intends to submit a SIP revision, the contents of 
which are intended to match the content of the FIP proposed in this 
rule. Thus, Executive Order 13132 does not apply to this action. In the 
spirit of Executive Order 13132, and consistent with EPA policy to 
promote communications between EPA and State and local governments, EPA 
specifically solicits comment on this proposed rule from State and 
local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled Consultation and Coordination with 
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' We note that the SIP is not approved 
to apply in Tribal lands located in the State, will not impose 
substantial direct costs on tribal governments or preempt tribal law, 
and does not affect the distribution of power and responsibilities 
between the Federal Government and any Indian tribes. As a result, 
while this rule applies to an emissions source that is adjacent to the 
Moapa Reservation, it does not have direct tribal implications as 
specified by Executive Order 13175 (65 FR 67249, November 9, 2000). 
However, we acknowledge that concerns about the environmental impacts 
of this facility have been raised by the Moapa Tribe. We have formally 
consulted with the Moapa Tribe regarding those concerns, and have 
visited the reservation and the facility. We will continue to work with 
the Moapa Tribe as we proceed with our action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children from Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) Is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health or 
safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency.
    This rule is not subject to Executive Order 13045 because it does 
not involve decisions intended to mitigate environmental health or 
safety risks. However, to the extent this proposed rule will limit 
emissions of NO<INF>X</INF>, the rule will have a beneficial effect on 
children's health by reducing air pollution.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical. The EPA believes that VCS are inapplicable to this action. 
Today's action does not require the public to perform activities 
conducive to the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

VIII. Statutory and Executive Order Reviews

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States. We have determined that this proposed 
rule, if finalized, will not have disproportionately high and adverse 
human health or environmental effects on minority or low-income 
populations because it increases the level of environmental protection 
for all affected populations without having any disproportionately high 
and adverse human health or environmental effects on any population, 
including any minority or low-income population. This proposed rule 
limits emissions of NO<INF>X</INF> from a single facility in Nevada. 
The partial approval of the SIP, if finalized, merely approves state 
law as meeting Federal requirements and imposes no additional 
requirements beyond those imposed by state law.

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Intergovernmental 
relations, Nitrogen oxides, Reporting and recordkeeping requirements.

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

    Dated: April 2, 2012.
Jared Blumenfeld,
Regional Administrator, Region 9.

    For the reasons stated in the preamble, Part 52, chapter I, title 
40 of the Code of Federal Regulations is proposed to be amended as 
follows:

PART 52--[AMENDED]

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

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

    2. Part 52 is amended by adding Sec.  52.1488(e) to 52.1488 
Visibility Protection, to read as follows:


Sec.  52.1488  Visibility protection.

* * * * *
    (e) This paragraph (e) applies to each owner and operator of the 
coal-fired

[[Page 21908]]

electricity generating units (EGUs) designated as Units 1, 2, and 3 at 
the Reid Gardner Generating Station in Clark County, Nevada.
    (1) Definitions. Terms not defined below shall have the meaning 
given to them in the Clean Air Act or EPA's regulations implementing 
the Clean Air Act. For purposes of this section:
    Ammonia injection shall include any of the following: anhydrous 
ammonia, aqueous ammonia or urea injection.
    Combustion controls shall mean new low NO<INF>X</INF> burners, new 
overfire air, and/or rotating overfire air.
    Continuous emission monitoring system or CEMS means the equipment 
required by 40 CFR Part 75 to determine compliance with this section.
    NOX means nitrogen oxides expressed as nitrogen dioxide 
(NO<INF>2</INF>).
    Owner/operator means any person who owns or who operates, controls, 
or supervises an EGU identified in paragraph (e) of this section.
    Unit means any of the EGUs identified in paragraph (e) of this 
section.
    Unit-wide means all of the EGUs identified in paragraph (e) of this 
section.
    (2) Emission limitations--The NO<INF>X</INF> limit, expressed as 
nitrogen dioxide, for Units 1, 2, and 3 shall be 0.20 lb/MMBtu based on 
a unit-wide heat input weighted average determined over a rolling 30-
calendar day period. NO<INF>2</INF> emissions for each calendar day 
shall be determined by summing the hourly emissions measured in pounds 
of NO<INF>2</INF> for all operating units. Heat input for each calendar 
day shall be determined by adding together all hourly heat inputs, in 
millions of BTU, for all operating units. Each day the thirty-day 
rolling average shall be determined by adding together that day and the 
preceding 29 days' pounds of NO<INF>2</INF> and dividing that total 
pounds of NO<INF>2</INF> by the sum of the heat input during the same 
30-day period. The results shall be the 30-calendar day rolling pound 
per million BTU emissions of NO<INF>2.</INF>
    (3) Compliance date. The owners and operators subject to this 
section shall comply with the emissions limitations and other 
requirements of this section within 5 years from promulgation of this 
paragraph and thereafter.
    (4) Testing and Monitoring. (i) The owner or operator shall use 40 
CFR Part 75 monitors and meet the requirements found in 40 CFR Part 75. 
In addition to these requirements, relative accuracy test audits shall 
be performed for both the NO<INF>2</INF> pounds per hour measurement 
and the hourly heat input measurement, and shall have relative 
accuracies of less than 20%. This testing shall be evaluated each time 
the 40 CFR Part 75 monitors undergo relative accuracy testing. 
Compliance with the emission limit for NO<INF>2</INF> shall be 
determined by using data that is quality assured and considered valid 
under 40 CFR Part 75, and which meets the relative accuracy of this 
paragraph.
    (ii) If a valid NO<INF>X</INF> pounds per hour or heat input is not 
available for any hour for a unit, that heat input and NO<INF>X</INF> 
pounds per hour shall not be used in the calculation of the unit-wide 
rolling 30-calendar day average. Each Unit shall obtain at least 90% 
valid hours of data over each calendar quarter. 40 CFR Part 60 Appendix 
A Reference Methods may be used to supplement the Part 75 monitoring.
    (iii) Upon the effective date of the unit-wide NO<INF>X</INF> 
limit, the owner or operator shall have installed CEMS software that 
meets with the requirements of this section for measuring 
NO<INF>2</INF> pounds per hour and calculating the unit-wide 30-
calendar day rolling average as required in paragraph (e)(2) of this 
section.
    (iv) Upon the completion of installation of ammonia injection on 
any of the three units, the owner or operator shall install, and 
thereafter maintain and operate, instrumentation to continuously 
monitor and record levels of ammonia consumption for that unit.
    (5) Notifications. (i) The owner or operator shall notify EPA 
within two weeks after completion of installation of combustion 
controls or ammonia injection on any of the units subject to this 
section.
    (ii) The owner or operator shall also notify EPA of initial start-
up of any equipment for which notification was given in paragraph 
(e)(5)(i).
    (6) Equipment Operations. After completion of installation of 
ammonia injection on any of the three units, the owner or operator 
shall inject sufficient ammonia to minimize the NO<INF>X</INF> 
emissions from that unit while preventing excessive ammonia emissions.
    (7) Recordkeeping. The owner or operator shall maintain the 
following records for at least five years:
    (i) For each unit, CEMS data measuring NO<INF>X</INF> in lb/hr, 
heat input rate per hour, the daily calculation of the unit-wide 30-
calendar day rolling lb NO<INF>2</INF>/MMbtu emission rate as required 
in paragraph (e)(2) of this section.
    (ii) Records of the relative accuracy test for NO<INF>X</INF> lb/hr 
measurement and hourly heat input
    (iii) Records of ammonia consumption for each unit, as recorded by 
the instrumentation required in paragraph (e)(4)(iv) of this section.
    (8) Reporting. Reports and notifications shall be submitted to the 
Director of Enforcement Division, U.S. EPA Region IX, at 75 Hawthorne 
Street, San Francisco, CA 94105. Within 30 days of the end of each 
calendar quarter after the effective date of this section, the owner or 
operator shall submit a report that lists the unit-wide 30-calendar day 
rolling lb NO<INF>2</INF>/MMBtu emission rate for each day. Included in 
this report shall be the results of any relative accuracy test audit 
performed during the calendar quarter.
    (9) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.

[FR Doc. 2012-8713 Filed 4-11-12; 8:45 am]
BILLING CODE 6560-50-P


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