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, 21896-21908 [2012-8713]
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Federal Register / Vol. 77, No. 71 / Thursday, April 12, 2012 / Proposed Rules
that this action is one of a category of
actions that do not individually or
cumulatively have a significant effect on
the human environment. A preliminary
environmental analysis checklist
supporting this preliminary
determination is available in the docket
where indicated under ADDRESSES. This
proposed rule involves the
establishment of a safety zone and
therefore paragraph (34)(g) of figure
2–1 applies. We seek any comments or
information that may lead to the
discovery of a significant environmental
impact from this proposed rule.
List of Subjects in 33 CFR Part 165
Harbors, Marine safety, Navigation
(water), Reporting and recordkeeping
requirements, Security measures,
Waterways.
For the reasons discussed in the
preamble, the Coast Guard proposes to
amend 33 CFR part 165 as follows:
PART 165—REGULATED NAVIGATION
AREAS AND LIMITED ACCESS AREAS
1. The authority citation for part 165
continues to read as follows:
Authority: 33 U.S.C. 1231; 46 U.S.C.
Chapter 701, 3306, 3703; 50 U.S.C. 191, 195;
33 CFR 1.05–1, 6.04–1, 6.04–6, and 160.5;
Pub. L. 107–295, 116 Stat. 2064; Department
of Homeland Security Delegation No. 0170.1.
2. Add § 165.T09–0200 to read as
follows:
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§ 165.T09–0200 Safety Zone International
Bridge 50th Anniversary Celebration
Fireworks, St. Mary’s River, U.S. Army
Corps of Engineers Locks, Sault Sainte
Marie, MI.
(a) Location. The following area is a
temporary safety zone: All U.S.
navigable waters of the St. Mary’s River
within a 750-foot radius around the
eastern portion of the U.S. Army Corp
of Engineers Soo Locks North East Pier,
centered in position: 46°30′19.66″ N,
084°20′31.61″ W [DATUM: NAD 83].
(b) Effective and Enforcement period.
This regulation is effective and will be
enforced from 10 p.m. until 12 p.m. on
June 28, 2012.
(1) The Captain of the Port, Sector
Sault Sainte Marie may suspend at any
time the enforcement of the safety zone
established under this section.
(2) The Captain of the Port, Sector
Sault Sainte Marie, will notify the
public of the enforcement and
suspension of enforcement of the safety
zone established by this section via any
means that will provide as much notice
as possible to the public. These means
might include some or all of those listed
in 33 CFR 165.7(a). The primary method
of notification, however, will be through
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Broadcast Notice to Mariners and local
Notice to Mariners.
(c) Definitions. The following
definitions apply to this section:
(1) Designated representative means
any Coast Guard commissioned,
warrant, or petty officer designated by
the Captain of the Port Sault Sainte
Marie to monitor these safety zones,
permit entry into these safety zones,
give legally enforceable orders to
persons or vessels within these safety
zones, or take other actions authorized
by the Captain of the Port.
(2) Public vessel means a vessel
owned, chartered, or operated by the
United States or by a State or political
subdivision thereof.
(d) Regulations. (1) The general
regulations in 33 CFR 165.23 apply.
(2) All persons and vessels must
comply with the instructions of the
Coast Guard Captain of the Port Sault
Sainte Marie or a designated
representative. Upon being hailed by the
U.S. Coast Guard by siren, radio,
flashing light or other means, the
operator of a vessel shall proceed as
directed.
(3) When the safety zone established
by this section is being enforced, all
vessels must obtain permission from the
Captain of the Port Sault Sainte Marie
or his or her designated representative
to enter, move within, or exit that safety
zone. Vessels and persons granted
permission to enter the safety zone shall
obey all lawful orders or directions of
the Captain of the Port or his or her
designated representative. While within
the safety zone, all vessels shall operate
at the minimum speed necessary to
maintain a safe course.
(e) Exemption. Public vessels, as
defined in paragraph (c) of this section,
are exempt from the requirements in
this section.
Dated: March 28, 2012.
J.C. McGuiness,
Captain, U.S. Coast Guard, Captain of the
Port Sault Sainte Marie.
[FR Doc. 2012–8808 Filed 4–11–12; 8:45 am]
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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
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
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 (NOX) from Units 1 and 2 at the
Reid Gardner Generating Station
(RGGS). We are proposing to disapprove
the NOX 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 NOX 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
https://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:
SUMMARY:
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1. Federal Rulemaking portal: https://
www.regulations.gov. Follow the on-line
instructions for submitting comments.
2. Email: Webb.Thomas@epa.gov.
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
https://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 https://
www.regulations.gov or email. The
https://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 https://
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 https://
www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket
are listed in the https://
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
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form. Publicly available docket
materials are available either
electronically at https://
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
webb.thomas@epa.gov.
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
NOX 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 NOX 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
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(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 NOX 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
NOX 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).
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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 NOX in two
sections of its documents.1
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 NOX. 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’’).
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 NOX.3 EPA indicated
that we needed additional time to
consider the substantial comments
submitted on the RGGS BART
Determination for NOX.
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 NOX.4 NDEP
responded on February 6 and February
14, 2012 by providing us with costrelated 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.
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 NOX 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 NOX for Units 1–3, which
was also raised as an issue in the
comments. Pless Powers at 52.
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
NOX to 0.20 lb/MMBtu.6 NDEP also
informed EPA that its further analysis
supported determining the NOX BART
limit for all RGGS Units based on a 30day rolling average rather than the 12month 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.
The Nevada RH SIP included an
evaluation of SNCR finding that it
III. Overview of Proposed Action
Today’s proposal addresses the RGGS
BART Determination for NOX, 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 NOX 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 NOX emission rates indicated in the
RH SIP. Our analysis examined the
visibility improvement that would be
expected by requiring RGGS to meet a
NOX 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
3 77
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.
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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FR 17334.
dated December 22, 2011, from Colleen
McKaughan (EPA) to Mike Elges (NDEP) and others.
5 Email dated March 14, 2012, from Colleen
McKaughan (EPA) to Mike Elges (NDEP).
6 Letter dated March 22, 2012 from Mike Elges
(NDEP) to Deborah Jordan (EPA).
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
NOX BART limit for RGGS Unit 3, and
requires a NOX emissions limit of 0.20
lb/MMBtu on a 30-day rolling average
(averaged across all three units).8
4 Email
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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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single Class I area to justify the
incremental cost of the technology.9
Therefore, we are proposing to
approve NDEP’s determination that NOX
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 NOX BART
determination for RGGS Unit 3 and the
SIP’s provision to measure NOX
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 NOX BART
emissions limit for RGGS Unit 3 of 0.20
lbs/MMbtu. We are also proposing a FIP
provision requiring that NOX 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
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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
9 In NDEP/Nevada Energy’s analysis, and in our
analysis, the highest impacted Class I area is Grand
Canyon National Park.
10 The set of ‘‘major stationary sources’’
potentially subject to BART is listed in CAA section
169A(g)(7).
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anticipated to cause or contribute to any
visibility impairment in a Class I area.
C. Roles of Agencies in Addressing
Regional Haze
Successful implementation of the
regional haze program will require longterm 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
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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 NOX 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 NOX BART
Determination for RGGS.
11 77
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C. Evaluation of Nevada’s NOX BART
Determination for Reid Gardner
Generating Station
Background: Reid Gardner is a coalfueled, 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 BARTeligible, and were determined by NDEP
to be subject to BART. Each of these
units produces about 100 MW with
steam boilers that drive turbinegenerators. 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
(SO2) 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 SO2 and PM10.12
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 SCRbased options and determined that
BART controls for NOX 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
NOX 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 NOX 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 NOX
removal ability of the two control
options.
When moving from a less stringent to
a more stringent NOX control
technology, the more stringent
technology will result in greater
amounts of NOX 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 NOX 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 NOX
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)
Control
efficiency 1
(%)
Control option
Emission
rate 1
(lb/MMBtu)
Emission
reduction 1
(ton/yr)
Annualized
costs 1
($MM)
Average cost
effectiveness 1
($/ton)
Incremental cost
effectiveness 1
($/ton)
483
927
1308
1850
1850
$0.55
1.13
1.45
4.75
5.39
$1,143
1,222
1,109
2,566
2,916
$1,143
1,308
833
6,085
7,280
580
1044
1443
2010
2010
0.55
1.16
1.50
4.80
5.47
952
1,106
1,038
2,386
2,721
952
1,299
860
5,813
7,001
147
678
869
1774
1774
0.55
1.08
1.38
4.72
5.40
3,742
1,596
1,588
2,660
3,045
3,742
1,000
1,560
3,688
4,444
Reid Gardner Unit 1
LNB + OFA (enhanced) .......................................
LNB + OFA + SNCR ............................................
ROFA + Rotamix .................................................
SCR + LNB + OFA ..............................................
SCR + ROFA 3 .....................................................
21.3
40.9
57.7
81.6
81.6
0.36
0.27
0.2
0.085
0.085
Reid Gardner Unit 2
LNB + OFA (enhanced) .......................................
LNB + OFA + SNCR ............................................
ROFA + Rotamix .................................................
SCR + LNB + OFA ..............................................
SCR + ROFA 3 .....................................................
23.7
42.7
59.0
82.2
82.2
0.355
0.267
0.19
0.083
0.083
Reid Gardner Unit 3
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LNB + OFA (enhanced) .......................................
LNB + OFA + SNCR ............................................
ROFA + Rotamix .................................................
SCR + LNB + OFA ..............................................
SCR + ROFA 2 .....................................................
6.5
29.9
38.0
78.2
78.2
0.42
0.316
0.278
0.098
0.098
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.
12 EPA approved that portion of NDEP’s BART
determination for RGGS on December 13, 2011.
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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 NOX 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 NOX 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.
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
NOX 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.
TABLE 2—COST EFFECTIVENESS COMPARISON—SCR WITH LNB AND OFA
Average cost
effectiveness
($/ton)
Unit No.
NDEP
Unit 1 ...............................................................................................................................................
Unit 2 ...............................................................................................................................................
Unit 3 ...............................................................................................................................................
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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.
13 Revised NDEP Reid Gardner BART
Determination Review, page 6. Available as Docket
Item No. EPA–R09–OAR–2011–0130–0005.
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).
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EPA
revised
$2,827
2,627
2,932
$2,110
1,967
2,183
Incremental cost
effectiveness
($/ton)
NDEP
$6,370
6,080
3,856
EPA
revised
$4,534
4,330
2,756
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 NOX 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.
15 These items were primarily noted in the expert
report by Petra Pless/Bill Powers (attachment to
EPA–R09–OAR–2011–0130–0062).
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TABLE 3—SUMMARY OF NEVADA ENERGY ESTIMATES OF VISIBILITY BENEFIT 16
Visibility improvement (from WRAP baseline) 17
Control option
RGGS1
(dv)
LNB + OFA (enhanced) .......................................................................................
LNB + OFA + SNCR ............................................................................................
ROFA + Rotamix .................................................................................................
SCR + LNB + OFA ..............................................................................................
SCR + ROFA 18 ...................................................................................................
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 NOX emission rates estimated by
RGGS2
(dv)
0.440
0.521
0.592
0.698
0.698
RGGS3
(dv)
0.479
0.560
0.630
0.735
0.735
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 NOX emission estimates
0.407
0.485
0.514
0.652
0.652
Visibility
improvement
(incremental,
from control)
Total
(dv)
Total
(dv)
1.33
1.57
1.74
2.09
2.09
........................
0.24
0.17
0.35
0.35
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.
TABLE 4—COMPARISON OF NEVADA ENERGY AND NDEP CONTROL TECHNOLOGY EMISSION ESTIMATES
Nevada energy
Control option
Control
efficiency 2
(%)
Emission
factor 1
(lb/MMBtu)
NDEP
Emission
factor 3
(lb/MMBtu)
Control
efficiency 3
(%)
Reid Gardner Unit 1
Baseline (LNB + OFA) .....................................................................................................
LNB + OFA (enhanced) ...................................................................................................
LNB + OFA + SNCR .......................................................................................................
ROFA + Rotamix .............................................................................................................
SCR + LNB + OFA ..........................................................................................................
SCR + ROFA ...................................................................................................................
0.38
0.30
0.23
0.16
0.07
0.07
....................
21.3
40.9
57.7
81.6
81.6
0.462
0.360
0.270
0.200
0.085
0.085
....................
21.3
40.9
57.7
81.6
81.6
0.393
0.30
0.23
0.16
0.07
0.07
....................
23.7
42.7
59.0
82.2
82.2
0.466
0.355
0.267
0.190
0.083
0.083
....................
23.7
42.7
59.0
82.2
82.2
0.32
0.30
0.23
0.20
0.07
0.07
....................
6.5
29.9
38.0
78.2
78.2
0.451
0.420
0.316
0.278
0.098
0.098
....................
6.5
29.9
38.0
78.2
78.2
Reid Gardner Unit 2
Baseline (LNB + OFA) .....................................................................................................
LNB + OFA (enhanced) ...................................................................................................
LNB + OFA + SNCR .......................................................................................................
ROFA + Rotamix .............................................................................................................
SCR + LNB + OFA ..........................................................................................................
SCR + ROFA ...................................................................................................................
Reid Gardner Unit 3
Baseline (LNB + OFA) .....................................................................................................
LNB + OFA (enhanced) ...................................................................................................
LNB + OFA + SNCR .......................................................................................................
ROFA + Rotamix .............................................................................................................
SCR + LNB + OFA ..........................................................................................................
SCR + ROFA ...................................................................................................................
1 From
each respective unit’s NVE BART Analysis, Table 3–1. Available in Docket Item No. EPA–R09–OAR–2011–0130–0007.
each respective unit’s NVE BART Analysis, Table 3–2. Available in Docket Item No. EPA–R09–OAR–2011–0130–0007.
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’’.
2 From
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3 As
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.
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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
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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.
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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 NOX 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 SO2 to SO3
conversion efficiency of 0.5 percent
for purposes of calculating sulfuric
acid emissions. Nevada Energy’s
21903
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.
—Control technology performance: We
performed our visibility modeling
using the NOX baseline emission rate
and NOX 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 NOX 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 NOX reduction.20
We have elected to model 0.06 lb/
MMBtu based on a selection of a midrange control efficiency of 85 percent
reduction from Nevada Energy’s NOX
emission baseline.
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
(all three
units)
(dv)
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Control option
Baseline (LNB w/OFA) ............................................................................................................................
LNB w/OFA (enhanced) ..........................................................................................................................
SNCR + LNB w/OFA ...............................................................................................................................
ROFA w/Rotamix .....................................................................................................................................
SCR w/LNB + OFA ..................................................................................................................................
19 The IMPROVE equation translates modeled or
monitored concentrations of pollutants like sulfate
and nitrate into extinction, a measure of visibility.
See: https://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
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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
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0.59
0.51
0.37
0.31
0.22
From
baseline
(dv)
Incremental,
from
previous
option
(dv)
....................
0.08
0.21
0.28
0.36
....................
0.08
0.13
0.06
0.09
And Wildlife Service. See: https://www.nature.nps.
gov/air/Pubs/pdf/flag/FlagFinal.pdf.
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.
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TABLE 5—SUMMARY OF VISIBILITY IMPACTS—Continued
Visibility improvement
Visibility
Impact 1
(all three
units)
(dv)
Control option
SCR w/LNB + OFA 2 (0.06 lb/MMBtu, each unit) ....................................................................................
0.20
From
baseline
(dv)
0.38
Incremental,
from
previous
option
(dv)
0.10
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.
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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-NOX burners by using
baseline NOX emission factors
corresponding to 2004 actual emissions
data.21 In preparing the RH SIP, NDEP
developed a baseline NOX emission
factor that was based upon past actual
emission data over a 2001–07 time
frame.22 This resulted in baseline NOX
emission rates that are approximately 15
percent higher than those presented in
Nevada Energy’s BART analysis.
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-NOX burners. We find that NDEP’s
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.
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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 NOX 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.
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 NOX.
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.
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,
VI. Federal Implementation Plan To
Address NOX 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
approach to this factor is reasonable,
and have not modified NDEP’s NOX
emission baseline in performing our
own analysis. We do note that due to
the emission calculation methodology
NDEP used to calculate NOX control
scenario emissions, increases to the
NOX emission baseline will affect
emission estimates for NOX control
scenarios. These effects are discussed
further in the analysis of degree of
visibility impact.
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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
NOX limit of 0.20 lb/MMBtu for Unit 3,
and establishing NOX 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.
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 NOX emission limit of 0.20
lb/MMBtu for Unit 3. In its RH SIP,
NDEP proposed a NOX 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
23 70
FR 39172.
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used by NDEP in developing its own
estimate of NOX emissions, which form
the basis for the proposed NOX 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 sitespecific 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 NOX emission rate of 0.20 lb/
MMBtu using the ROFA with Rotamix
control option.
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 NOX emission limits for
RGGS Units 1 through 3. In its RH SIP,
NDEP proposed NOX 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
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.
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21905
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 NOX 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.
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 NOX 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 NOX 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 NOX 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 NOX emission
limit of 0.20 lb/MMBtu (30-day rolling
average, averaged across all three units)
established in our FIP.
VI. Federal Implementation Plan To
Address NOX BART for Reid Gardner
With the exception of the NOX BART
emission limit for Unit 3 and the NOX
averaging time for all three units, EPA
is proposing to find the Nevada RH
BART determination for NOX fulfills all
26 Page D–60, Appendix D, Nevada RH SIP.
Available as attachments to EPA–R09–OAR–2011–
0130–0003.
27 70 FR 39172.
28 70 FR 39163.
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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 NOX. 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 NOX 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 NOX 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 NOX 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.
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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).
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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
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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 costeffective 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
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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
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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 NOX, 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.
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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
NOX 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
§ 52.1488(e) to 52.1488 Visibility
Protection, to read as follows:
§ 52.1488
Visibility protection.
*
*
*
*
*
(e) This paragraph (e) applies to each
owner and operator of the coal-fired
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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 NOX 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 (NO2).
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 NOX
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. NO2
emissions for each calendar day shall be
determined by summing the hourly
emissions measured in pounds of NO2
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 NO2 and
dividing that total pounds of NO2 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 NO2.
(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 NO2 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
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monitors undergo relative accuracy
testing. Compliance with the emission
limit for NO2 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 NOX pounds per hour or
heat input is not available for any hour
for a unit, that heat input and NOX
pounds per hour shall not be used in the
calculation of the unit-wide rolling 30calendar 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 NOX limit, the owner or
operator shall have installed CEMS
software that meets with the
requirements of this section for
measuring NO2 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 NOX
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 NOX in lb/hr, heat input rate
per hour, the daily calculation of the
unit-wide 30-calendar day rolling lb
NO2/MMbtu emission rate as required
in paragraph (e)(2) of this section.
(ii) Records of the relative accuracy
test for NOX 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.
PO 00000
Frm 00034
Fmt 4702
Sfmt 4702
(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 30calendar day rolling lb NO2/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
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[EPA–R03–OAR–2009–0882; FRL–9656–9]
Approval and Promulgation of Air
Quality Implementation Plans;
Pennsylvania; Streamlining
Amendments to the Plan Approval
Regulations
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
EPA is proposing to grant
limited approval to a State
Implementation Plan (SIP) revision
submitted by the Pennsylvania
Department of Environmental Protection
(PADEP) on April 14, 2009. The revision
pertains to PADEP’s plan approval
requirements for the construction,
modification, and operation of sources,
and is primarily intended to streamline
the process for minor permitting
actions. This action is being taken under
the Clean Air Act (CAA).
DATES: Written comments must be
received on or before May 14, 2012.
ADDRESSES: Submit your comments,
identified by Docket ID Number EPA–
R03–OAR–2009–0882 by one of the
following methods:
A. www.regulations.gov. Follow the
on-line instructions for submitting
comments.
SUMMARY:
E:\FR\FM\12APP1.SGM
12APP1
]]>Agencies
[Federal Register Volume 77, Number 71 (Thursday, April 12, 2012)]
[Proposed Rules]
[Pages 21896-21908]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-8713]
=======================================================================
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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
(NOX) from Units 1 and 2 at the Reid Gardner Generating
Station (RGGS). We are proposing to disapprove the NOX
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 NOX 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 https://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: https://www.regulations.gov. Follow
the on-line instructions for submitting comments.
2. Email: Webb.Thomas@epa.gov.
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 https://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 https://www.regulations.gov or email. The https://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 https://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 https://www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket are listed in the https://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 https://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 webb.thomas@epa.gov.
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 NOX 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 NOX 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 NOX 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 NOX 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 NOX in two sections of its
documents.\1\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 NOX. 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'').
---------------------------------------------------------------------------
\2\ Both reports can be found as attachments to EPA-R09-OAR-
2011-0130-0062, with supporting information located in -0063.
---------------------------------------------------------------------------
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
NOX.\3\ EPA indicated that we needed additional time to
consider the substantial comments submitted on the RGGS BART
Determination for NOX.
---------------------------------------------------------------------------
\3\ 77 FR 17334.
---------------------------------------------------------------------------
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 NOX.\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.
---------------------------------------------------------------------------
\4\ Email dated December 22, 2011, from Colleen McKaughan (EPA)
to Mike Elges (NDEP) and others.
---------------------------------------------------------------------------
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
NOX 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 NOX for Units 1-3, which was also raised as an
issue in the comments. Pless Powers at 52.
---------------------------------------------------------------------------
\5\ Email dated March 14, 2012, from Colleen McKaughan (EPA) to
Mike Elges (NDEP).
---------------------------------------------------------------------------
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 NOX to 0.20 lb/
MMBtu.\6\ NDEP also informed EPA that its further analysis supported
determining the NOX 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.
---------------------------------------------------------------------------
\6\ Letter dated March 22, 2012 from Mike Elges (NDEP) to
Deborah Jordan (EPA).
---------------------------------------------------------------------------
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 NOX BART limit
for RGGS Unit 3, and requires a NOX emissions limit of 0.20
lb/MMBtu on a 30-day rolling average (averaged across all three
units).\8\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
III. Overview of Proposed Action
Today's proposal addresses the RGGS BART Determination for
NOX, 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 NOX
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 NOX emission rates indicated
in the RH SIP. Our analysis examined the visibility improvement that
would be expected by requiring RGGS to meet a NOX 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\
---------------------------------------------------------------------------
\9\ In NDEP/Nevada Energy's analysis, and in our analysis, the
highest impacted Class I area is Grand Canyon National Park.
---------------------------------------------------------------------------
Therefore, we are proposing to approve NDEP's determination that
NOX 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 NOX BART
determination for RGGS Unit 3 and the SIP's provision to measure
NOX 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 NOX BART emissions limit for RGGS Unit 3 of 0.20 lbs/
MMbtu. We are also proposing a FIP provision requiring that
NOX 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.
---------------------------------------------------------------------------
\10\ The set of ``major stationary sources'' potentially subject
to BART is listed in CAA section 169A(g)(7).
---------------------------------------------------------------------------
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 NOX 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 NOX BART Determination
for RGGS.
---------------------------------------------------------------------------
\11\ 77 FR 17334.
---------------------------------------------------------------------------
[[Page 21900]]
C. Evaluation of Nevada's NOX 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 (SO2) 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 SO2 and
PM10.\12\
---------------------------------------------------------------------------
\12\ EPA approved that portion of NDEP's BART determination for
RGGS on December 13, 2011.
---------------------------------------------------------------------------
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 NOX 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 NOX 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 ($) of a
control option divided by the total amount of NOX removed
(tons) by that control option. Incremental cost effectiveness is
calculated when considering one control technology in relation to
another, and examines the differing costs and the differing
NOX removal ability of the two control options.
When moving from a less stringent to a more stringent
NOX control technology, the more stringent technology will
result in greater amounts of NOX removal, but will also
typically be more expensive. Incremental cost ($/ton) is calculated by
dividing the difference in annualized costs ($) of the two technologies
by the difference in NOX removal (ton) of the two
technologies. Incremental costs are typically calculated ``in order'',
by comparing one control technology with the less stringent technology
immediately preceding it. The control cost data that NDEP included in
the RH SIP and relied upon in making its NOX BART
determination is summarized in Table 1 below.
Table 1--Summary of NDEP NOX BART Determination Results for RGGS Unit 1 Through 3 (as Included in the RH SIP)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission
Control Emission reduction Annualized Average cost Incremental cost
Control option efficiency rate \1\ \1\ (ton/ costs \1\ effectiveness effectiveness
\1\ (%) (lb/MMBtu) yr) ($MM) \1\ ($/ton) \1\ ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Reid Gardner Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Reid Gardner Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX 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 SO2 to SO3
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: https://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:
https://www.nature.nps.gov/air/Pubs/pdf/flag/FlagFinal.pdf.
---------------------------------------------------------------------------
--Control technology performance: We performed our visibility modeling
using the NOX baseline emission rate and NOX
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 NOX 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 NOX 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 NOX 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-NOX
burners by using baseline NOX emission factors corresponding
to 2004 actual emissions data.\21\ In preparing the RH SIP, NDEP
developed a baseline NOX emission factor that was based upon
past actual emission data over a 2001-07 time frame.\22\ This resulted
in baseline NOX 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-NOX burners. We find that
NDEP's approach to this factor is reasonable, and have not modified
NDEP's NOX emission baseline in performing our own analysis.
We do note that due to the emission calculation methodology NDEP used
to calculate NOX control scenario emissions, increases to
the NOX emission baseline will affect emission estimates for
NOX 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 NOX 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 NOX.
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 NOX 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 NOX limit of 0.20 lb/MMBtu for Unit
3, and establishing NOX 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 NOX
emission limit of 0.20 lb/MMBtu for Unit 3. In its RH SIP, NDEP
proposed a NOX 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 NOX
emissions, which form the basis for the proposed NOX 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 NOX
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
NOX emission limits for RGGS Units 1 through 3. In its RH
SIP, NDEP proposed NOX 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 NOX
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 NOX 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 NOX 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 NOX 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 NOX emission limit of 0.20
lb/MMBtu (30-day rolling average, averaged across all three units)
established in our FIP.
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\28\ 70 FR 39163.
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VI. Federal Implementation Plan To Address NOX BART for Reid
Gardner
With the exception of the NOX BART emission limit for
Unit 3 and the NOX averaging time for all three units, EPA
is proposing to find the Nevada RH BART determination for
NOX 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 NOX. 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 NOX 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 NOX 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 NOX 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 NOX, 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 NOX 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 NOX 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
(NO2).
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 NOX 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. NO2 emissions for each calendar day
shall be determined by summing the hourly emissions measured in pounds
of NO2 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 NO2 and dividing that total
pounds of NO2 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 NO2.
(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 NO2 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 NO2 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 NOX pounds per hour or heat input is not
available for any hour for a unit, that heat input and NOX
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 NOX
limit, the owner or operator shall have installed CEMS software that
meets with the requirements of this section for measuring
NO2 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 NOX
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 NOX in lb/hr,
heat input rate per hour, the daily calculation of the unit-wide 30-
calendar day rolling lb NO2/MMbtu emission rate as required
in paragraph (e)(2) of this section.
(ii) Records of the relative accuracy test for NOX 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 NO2/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
