Revisions to the California State Implementation Plan, San Joaquin Valley Unified Air Pollution Control District, 66548-66554 [2012-26779]
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66548
Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations
under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.);
• Does not contain any unfunded
mandate or significantly or uniquely
affect small governments, as described
in the Unfunded Mandates Reform Act
of 1995 (Pub. L. 104–4);
• Does not have Federalism
implications as specified in Executive
Order 13132 (64 FR 43255, August 10,
1999);
• Is not an economically significant
regulatory action based on health or
safety risks subject to Executive Order
13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action
subject to Executive Order 13211 (66 FR
28355, May 22, 2001);
• Is not subject to requirements of
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (15 U.S.C. 272 note) because
application of those requirements would
be inconsistent with the CAA; and
• Does not provide EPA with the
discretionary authority to address, as
appropriate, disproportionate human
health or environmental effects, using
practicable and legally permissible
methods, under Executive Order 12898
(59 FR 7629, February 16, 1994).
In addition, this rule does not have
tribal implications as specified by
Executive Order 13175 (65 FR 67249,
November 9, 2000), because the SIP is
not approved to apply in Indian country
located in the state, and EPA notes that
it will not impose substantial direct
costs on tribal governments or preempt
tribal law.
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this action and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General of the United
States prior to publication of the rule in
the Federal Register. A major rule
cannot take effect until 60 days after it
is published in the Federal Register.
This action is not a ‘‘major rule’’ as
defined by 5 U.S.C. 804(2).
Under section 307(b)(1) of the CAA,
petitions for judicial review of this
action must be filed in the United States
Court of Appeals for the appropriate
circuit by January 7, 2013. Filing a
petition for reconsideration by the
Administrator of this final rule does not
affect the finality of this action for the
purposes of judicial review nor does it
extend the time within which a petition
for judicial review may be filed, and
shall not postpone the effectiveness of
such rule or action. This action may not
be challenged later in proceedings to
enforce its requirements. (See section
307(b)(2).)
List of Subjects in 40 CFR Part 52
Environmental protection, Air
pollution control, Incorporation by
reference, Particulate matter, Reporting
and recordkeeping requirements.
Dated: October 19, 2012.
Susan Hedman,
Regional Administrator, Region 5.
40 CFR part 52 is amended as follows:
PART 52—APPROVAL AND
PROMULGATION OF
IMPLEMENTATION PLANS
1. The authority citation for part 52
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
2. In § 52.1170 the table in paragraph
(e) is amended by adding a new entry
for ‘‘1997 Annual Fine Particulate
Matter 2005 Base Year Emissions
Inventory’’ at the end of the table to read
as follows:
■
§ 52.1170
*
Identification of plan.
*
*
(e) * * *
*
*
EPA-APPROVED MICHIGAN NONREGULATORY AND QUASI–REGULATORY PROVISIONS
Applicable geographic
or nonattainment area
Name of nonregulatory SIP provision
State submittal date
*
*
*
*
1997 Annual Fine Particulate Matter 2005 Base Detroit-Ann Arbor area
Year Emissions Inventory.
(Livingston, Macomb,
Monroe, Oakland, St.
Clair, Washtenaw,
and Wayne Counties).
BILLING CODE 6560–50–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
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[EPA–R09–OAR–2012–0266; FRL–9736–9]
Revisions to the California State
Implementation Plan, San Joaquin
Valley Unified Air Pollution Control
District
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
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*
*
11/6/12 [INSERT CITATION OF PUBLICATION].
EPA is approving revisions to
the San Joaquin Valley Unified Air
Pollution Control District (SJVUAPCD)
portion of the California State
Implementation Plan (SIP). This action
was proposed in the Federal Register on
April 26, 2012 and concerns oxides of
nitrogen (NOX) from solid fuel fired
boilers. We are approving a local rule
that regulates these emission sources
under the Clean Air Act (CAA or the
Act).
DATES: This rule will be effective on
December 6, 2012.
ADDRESSES: EPA has established docket
number EPA–R09–OAR–2012–0266 for
this action. Generally, documents in the
docket for this action are available
electronically at https://
SUMMARY:
[FR Doc. 2012–26962 Filed 11–5–12; 8:45 am]
6/13/08
EPA approval date
PO 00000
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Comments
*
www.regulations.gov or in hard copy at
EPA Region IX, 75 Hawthorne Street,
San Francisco, California. While all
documents in the docket are listed at
https://www.regulations.gov, some
information may be publicly available
only at the hard copy location (e.g.,
copyrighted material, large maps, multivolume reports), and some may not be
available in either location (e.g.,
confidential business information
(CBI)). To inspect the hard copy
materials, please schedule an
appointment during normal business
hours with the contact listed in the FOR
FURTHER INFORMATION CONTACT section.
FOR FURTHER INFORMATION CONTACT:
´
Idalia Perez, EPA Region IX, (415) 972–
3248, perez.idalia@epa.gov.
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Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations
Table of Contents
I. Proposed Action
I. Proposed Action
II. Public Comments and EPA Responses
III. EPA Action
IV. Statutory and Executive Order Reviews
SUPPLEMENTARY INFORMATION:
Throughout this document, ‘‘we,’’ ‘‘us’’
and ‘‘our’’ refer to EPA.
On April 26, 2012 (77 FR 24883), EPA
proposed to approve the following rule
into the California SIP.
Rule
No.
Local agency
SJVUAPCD ...................................
Rule title
4352
66549
Adopted
Solid Fuel Fired Boilers, Steam Generators and Process Heaters ....
We proposed to approve this rule
based on our conclusion that it complies
with the relevant CAA requirements.
Our proposed rule and Technical
Support Document (TSD) 1 contain
moreinformation onthe rule and our
evaluation.
II. Public Comments and EPA
Responses
EPA’s proposed action provided a 30day public comment period. During this
period, we received comments from the
following party.
1. Adenike Adeyeye, Earthjustice;
letter dated and received May 29, 2012.
The comments and our responses are
summarized below.
Comment #1: Earthjustice stated that
these revisions are an improvement over
prior versions of this rule.
Response #1: No response needed.
Comment #2: Earthjustice disagreed
with EPA’s proposal to approve the NOX
emission limit in Rule 4352 for
municipal solid waste (MSW) fired
units as RACT. Earthjustice provided
several arguments in support of its
objection to EPA’s proposal, each of
which we address following separate
comment summaries below.
Comment #2.a: Earthjustice stated
that the New Jersey Department of
Environmental Protection (NJDEP) has
set NOX emissions limits for MSW-fired
boilers at 150 ppmv at 7% O2
(approximately 142 ppmv at 12% CO2).
Quoting from a SIP submission from
NJDEP, Earthjustice asserted that NJDEP
established this limit based on ‘‘the
capability of existing selective noncatalytic reduction (SNCR) emission
controls to reduce emissions more than
are now being achieved.’’ The
commenter stated that the District’s
unsupported assertion that it is
impossible to meet a limit lower than
165 ppmv at 12% CO2 is simply false.
Response #2.a: We disagree with the
commenter’s suggestion that the NOX
emissions limits established in NJDEP’s
rule generally represent NOX RACT for
existing MSW-fired boilers equipped
with SNCR controls. As the commenter
correctly notes, under Title 7, Chapter
27, Subchapter 19, Section 12 of the
New Jersey Administrative Code
(N.J.A.C. 7:27–19.12), NJDEP limits NOX
emissions from MSW combustors to 150
ppm at 7% O2 averaged over 24 hours
(approximately 142 ppm at 12% CO2).
In lieu of complying with this emissions
limit, however, the rule allows an owner
or operator of an MSW incinerator to
comply with an alternative emission
limit or a ‘‘facility-specific NOX control
plan’’ upon receipt of written approval
from NJDEP, pursuant to section 13 of
the rule (N.J.A.C. 7:27–19.13). See
N.J.A.C. 7:27–19.12(b). Section 13
identifies, among other things, the types
of information that an owner or operator
must submit to NJDEP as part of a
request for such an alternative emission
limit or facility-specific NOX control
12/15/11
Submitted
02/23/12
plan, including a list of all NOX control
technologies available for use with the
equipment or source operation, an
analysis of the technological feasibility
and costs of installing and operating
each such control technology, and
estimates of the NOX emissions
reductions attainable through the use of
each control technology which is
technologically feasible. See N.J.A.C.
7:27–19.13(d). The rule authorizes
NJDEP to approve a request for an
alternative emission limit or facilityspecific NOX control plan only if, among
other things, the request identifies all
available NOX control options and
demonstrates that any control options
that the owner/operator has rejected are
ineffective or unsuitable for the
particular equipment or would involve
disproportionately high costs, in
comparison to the associated NOX
reductions or costs borne by other like
facilities. See N.J.A.C. 7:27–19.13(g)(3).
According to NJDEP, three of the five
MSW incinerators subject to N.J.A.C.
7:27–19.12 appear to have obtained
alternative emission limits pursuant to
Section 13 of the rule and are not
currently subject to the 24-hour NOX
limit of 150 ppm at 7% O2. See email
dated July 24, 2012, from Michael Klein
(NJDEP) to Stanley Tong (EPA Region
9). Table 1 below shows the current
NOX limits in the operating permits for
each of these five MSW incinerators
under NJDEP jurisdiction.
TABLE 1
Emission limit
(ppm at 7% O2)
Facility
Emission limit
(approximate
ppm at 12%
CO2)
Averaging
time
(hours)
300
155
285
147
1
24
Warren 3 ...................................................................................................................................
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Essex 2 .....................................................................................................................................
300
205
285
195
3
24
1 See U.S. EPA Region 9, ‘‘Technical Support
Document for EPA’s Notice of Proposed
Rulemaking for the California State Implementation
Plan, San Joaquin Valley Unified Air Pollution
Control District’s Rule 4352, Solid Fuel Fired
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Boilers, Steam Generators and Process Heaters,’’
April 2012 (TSD).
2 See Air Pollution Control Operating Permit,
Permit Activity No. BOP090001, Covanta Essex Co.
(Essex PTO) at pg. 57 of 95.
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3 See Air Pollution Control Operating Permit,
Permit Activity No. BOP090002, Covanta Warren
Energy Resource Co. LP (Warren PTO) at pp. 57 and
60 of 101.
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TABLE 1—Continued
Emission limit
(ppm at 7% O2)
Facility
Emission limit
(approximate
ppm at 12%
CO2)
Averaging
time
(hours)
225
180
214
171
3
24
Gloucester 5 .............................................................................................................................
350
150
333
143
3
24
Camden 6 .................................................................................................................................
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Union 4 .....................................................................................................................................
300
150
285
143
3
24
Of the three New Jersey facilities that
have obtained permit limits exceeding
the 24-hour NOX limit of 150 ppm (at
7% O2) in NJDEP’s rule (Essex, Warren,
and Union), two facilities (Warren and
Union) have permit limits that also
exceed the 24-hour NOX limit of 165
ppm (at 12% CO2) in SJVUAPCD’s Rule
4352. See Table 1. The remaining two
facilities, which are subject to the 150
ppm limit in NJDEP’s rule (Gloucester
and Camden), are both equipped with
SNCR using urea injection as a NOX
control technique. See Gloucester PTO
at pp. 45–46 of 106; Camden PTO at pg.
183 (of electronic file). Both of these
facilities became subject to the 24-hour
NOX limit of 150 ppm (at 7% O2) in
N.J.A.C. 7:27–19.12 effective May 1,
2011. See Gloucester PTO at pp. 38 of
106; Camden PTO at pg. 34 of 99.
Notably, for the Camden facility, the 150
ppm limit applied ‘‘on and after May 1,
2011, if compliance is achieved by
installing a new NOX air pollution
control system on an existing MSW
incinerator or by physically modifying
an existing MSW incinerator.’’ Camden
PTO at pg. 34 of 99. The Gloucester and
Camden facilities are the only MSW
incinerators we know of that are subject
to the 24-hour NOX limit of 150 ppm (at
7% O2) in N.J.A.C. 7:27–19.12.
Only one existing facility in the SJV
(Covanta Stanislaus, Inc.) currently
operates MSW-fired boilers subject to
SJVUAPCD’s Rule 4352. The two MSWfired boilers at the Covanta Stanislaus
facility are equipped with SCNR using
ammonia injection systems, instead of
urea injection systems, for NOX control.
See Facility-wide Permit to Operate for
Covanta Stanislaus, Inc., San Joaquin
Valley Air Pollution Control District,
Permit Unit: N–2073–1–10 (expiration
date 10/31/2016), ‘‘Equipment
Description’’ (Stanislaus PTO).
Although ammonia and urea injection
both serve as reducing agents for NOX
4 See Air Pollution Control Operating Permit,
Permit Activity No. BOP080001, Covanta Union
(Union PTO) at pp. 56 and 57 of 90.
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emissions in combination with SNCR
control systems, these control methods
require operation at different
temperature windows and generally are
not interchangeable without facility
retrofits. See Alternative Control
Techniques Document—NOX Emissions
from Industrial/Commercial/
Institutional (ICI) Boilers, U.S. EPA 453/
R–94–022 (March 1994) (1994 ACT) at
sections 5.5.1.1 (‘‘Ammonia-based
SNCR’’) and 5.5.1.2 (‘‘Urea-based
SNCR’’). For example, the optimum
reaction temperature range for the
reduction of NOX by ammonia is 870° to
1,100 °C, while the optimum range for
the reduction of NOX by urea is 900° to
1,150 °C, and ammonia can be injected
both in aqueous solution or anhydrous
form while urea may only be injected in
aqueous form. Id. These technological
distinctions between ammonia-based
SNCR and urea-based SNCR highlight
uncertainties about whether the controls
implemented by the Gloucester and
Camden incinerators in New Jersey (i.e.,
urea-based SNCR) are
technologicallyand economically
feasiblefor implementation at the one
existing MSW-fueled facility in SJV.
Additionally, according to
information submitted by SJVUAPCD at
EPA’s request, four of the five MSW
incinerators subject to the NJDEP rule
have equipment that differs significantly
from the equipment at the Covanta
Stanislaus facility in SJV. See emails
dated September 4, 2012 and September
11, 2012, from Nichole Corless
(SJVUAPCD) to Idalia Perez (EPA
Region 9), with attachments.
Specifically, SJVUAPCD states that the
Covanta Stanislaus facility is configured
with stoker grates whereas the New
Jersey MSW incinerators have
5 See Air Pollution Control Operating Permit,
Permit Activity No. BOP090002, Wheelabrator
Gloucester Company (Gloucester PTO) at pp. 38 and
68 of 106.
6 See Air Pollution Control Operating Permit,
Permit Activity No. BOP080002, Camden Cnty
Energy Recovery Assoc LP (Camden PTO) at pp. 34
and 66 of 99.
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reciprocating, horizontal, and roller
grates, which enable them to meet a
slightly lower NOX limit. Id. These
technological distinctions raise
additional questions about whether the
controls implemented by the New Jersey
facilities are feasible for implementation
in SJV. Moreover, the fact that both the
Gloucester and Camden incinerators in
New Jersey became subject to the 150
ppm limit in N.J.A.C. 7:27–19.12 only as
of May 1, 2011, and in Camden’s case
only if the facility made physical
modifications to, or installed new air
pollution control equipment on, the
existing MSW incinerator, further
highlights uncertainties about whether
the chosen control methods at these two
facilities are ‘‘reasonably available’’ for
implementation at existing MSW-fired
boilers in SJV.
Finally, information submitted by the
SJVUAPCD indicates that retrofits to
existing SNCR systems to achieve
additional NOX reductions are not costeffective in light of the relatively
insignificant difference between the
NOX limit in NJDEP’s rule (150 ppm at
7% O2, or approximately 142 ppm at
12% CO2, 24-hour average) and the limit
in SJVUAPCD’s Rule 4352 (165 ppm at
12% CO2, 24-hour average).
Specifically, with respect to staged
combustion retrofits to an ammoniabased SNCR control system, SJVUAPCD
submitted information indicating that
the cost per ton of reductions in NOX
emissions from 165 to 142 ppm at 12%
CO2 would be $27,650/ton. See email
dated September 4, 2012, from Nichole
Corless (SJVUAPCD) to Idalia Perez
(EPA Region 9), with attachment.
Further taking into account certain
operational conditions at the Covanta
Stanislaus facility which indicate that
the limit in NJDEP’s rule (150 ppm at
7% O2) would equate to approximately
148 ppm (rather than 142 ppm) at 12%
CO2, the cost per ton of NOX emission
reductions from 165 ppm to 148 ppm at
12% CO2 would be $37,404/ton. See id.
These costs exceed the levels generally
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considered to be ‘‘reasonable’’ within
the meaning of RACT.
In sum, the information before us
raises significant questions about the
technical and economic feasibility of
achieving a 24-hour NOX emission limit
of 150 ppm at 7% O2 (approximately
142 ppm at 12% CO2) at existing MSWfired boilers equipped with ammoniabased SNCR in the SJV, and the
commenter has provided little
information to substantiate its claim in
this regard. Absent specific information
to support a conclusion that further
NOX controls are ‘‘reasonably available’’
for implementation at existing MSWfired boilers in the SJV, we find that the
24-hour NOX emission limit of 165 ppm
at 12% CO2 in SJVUAPCD’s Rule 4352
represents current RACT for these
units.7
Comment #2.b: Earthjustice asserted
that the District has not adequately
analyzed and considered the feasibility
of either injecting more ammonia or
adding more nozzles to existing SNCR
controls to meet a lower NOX emissions
limit. The commenter stated that
according to the NJDEP State
Implementation Plan (SIP) Revision for
the Attainment and Maintenance of the
Fine Particulate Matter (PM2.5) National
Ambient Air Quality Standard (NJDEP
2009 PM2.5 SIP) submitted to EPA in
2009, 11 regulated units at 4 facilities in
New Jersey would meet the lower NOX
emissions limit in N.J.A.C. 7:27–19.12
by injecting more ammonia or adding
more nozzles to existing SNCR controls.
The commenter stated that ‘‘technical
analysis of these demonstrated options
must be conducted before EPA can
accept ammonia slip as an excuse for
rejecting tighter SNCR limits.’’
Response #2.b: We have generally
evaluated the technical feasibility of
injecting more ammonia or adding
nozzles to existing SNCR controls but
do not have sufficient information to
conclude that these control methods
represent RACT for existing MSW-fired
boilers in SJV at this time. According to
information submitted by SJVUAPCD at
our request, the orientation of the
nozzles in the combustion gas stream
has a much greater impact on the
resulting NOX emissions than the
7 The commenter states that ‘‘the District’s
unsupported assertion that it is impossible to meet
a limit lower than 165 ppmv at 12% CO2 is simply
false,’’ but this assertion mischaracterizes the
District’s position, as test data for Covanta
Stanislaus submitted by the District clearly show
average NOX emission levels below the 165 ppm
limit in Rule 4352. See TSD at 6. An emission limit
of 165 ppm at 12% CO2 ensures that the source is
obligated to continually operate its emission control
system while leaving the facility a small
compliance buffer to account for occasional shortterm variabilities inherent in its process. Id.
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number of nozzles in the system, and
the Covanta Stanislaus facility’s nozzles
have already been optimized based on
the ‘‘temperature window where SNCR
works to reduce NOX effectively.’’ See
email dated September 4, 2012, from
Nichole Corless (SJVUAPCD) to Idalia
Perez (EPA Region 9), with attachments.
SJVUAPCD also stated that the amount
of ammonia injected into the flue gas at
Covanta Stanislaus is closely controlled
to maximize NOX reductions and to
prevent excessive ammonia slip, and
that increases in ammonia injection
would ‘‘result in negligible NOX
reductions and would exit the system
and cause a detached plume,’’ causing
violations of permit conditions
regarding visible emissions, ammonia
slip, and condensable particulate
matter. Id. (citing continuous emissions
monitoring data submitted by Covanta
Stanislaus to support these
conclusions).
EPA’s Alternative Control Techniques
document for NOX emissions from
Industrial/Commercial/Institutional
Boilers (1994 ACT) supports the general
conclusion that simply injecting more
ammonia or adding nozzles will not
necessarily reduce NOX emissions in an
ammonia-based SNCR system. The 1994
ATC describes the process in an
ammonia-based SNCR system as
follows:
In this process, aqueous or anhydrous
ammonia is vaporized and injected into the
flue gas through wall-mounted nozzles at a
location selected for optimum reaction
temperature and residence time. The
optimum reaction temperature range for this
process is 870 to 1,100 °C (1,600 to 2,000 °F).
* * * At temperatures above 1,100 °C (2,000
°F), ammonia injection becomes
counterproductive, resulting in additional
NO formation. Below 870 °C (1,600 °F), the
reaction rate drops and undesired amounts of
ammonia are carried out in the flue gas.
Unreacted ammonia is commonly referred to
as ammonia slip, breakthrough, or carryover.
The amount of ammonia slip also depends in
part on the amount of ammonia injected.
Although the chemical reaction requires one
mole of NH3 for each mole of NO, the NH3/
NOX ratio used is usually greater than 1 to
avoid an undesired reaction which results in
formation of NO. * * * Achievable NOX
reductions for an individual boiler depend
on the flue gas temperature, the residence
time at that temperature, the initial NOX
concentration, the NH3/NOX ratio, the excess
oxygen level, and the degree of ammonia/flue
gas mixing. Also, stratification of both
temperature and NOX in the flue gas can
affect the performance of the SNCR control.
The optimum placement of SNCR injectors
requires a detailed mapping of the
temperature profile in the convective passes
of the boiler, because of the narrow
temperature window. 1994 ACT at Section
5.5.1.1.
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66551
Thus, even assuming it is
technologically feasible to inject more
ammonia and/or to install additional
ammonia injection nozzles, it is not
clear that these methods would further
reduce NOX emissions in an ammoniabased SNCR system, and technical
information indicates that such methods
could instead lead to increased
ammonia slip if not carefully adjusted to
account for the specific temperature
profile, NH3/NOX ratio, oxygen levels,
degree of ammonia/flue gas mixing, and
other factors specific to the particular
boiler and control system.
As the commenter correctly notes,
Appendix C of the NJDEP 2009 PM2.5
SIP states that ‘‘the NJDEP anticipates
that the facilities will decrease their
emissions due to optimizing their
existing NOX control systems (i.e., either
injecting more ammonia or adding more
nozzles).’’ See NJDEP 2009 PM2.5 SIP,
App. C., at 5. This statement alone,
however, does not establish that the
NOX emission limit in N.J.A.C. 7:27–
19.12 (150 ppm at 3% O2) represents
RACT for existing MSW-fueled boilers.
As discussed above in Response 2.a,
four of the five MSW incinerators
subject to the NJDEP rule have
equipment configurations that appear to
differ significantly from the Covanta
Stanislaus facility, and NJDEP has
approved alternate, higher NOX limits
for three of the five subject sources
based on the agency’s assessment of
source-specific technological and/or
economic factors. Other than
referencing statements of general intent
in a New Jersey SIP submission, the
commenter provides no technological or
economic information to support its
assertion that existing MSW-fired
boilers, either generally or in SJV
specifically, are capable of meeting a 24hour NOX emission limit of 150 ppm at
3% O2 (142 ppm of at 12% CO2) by the
application of control technology that is
reasonably available considering
technological and economic feasibility.
Comment #2.c: Earthjustice asserted
that the New Jersey rule, along with data
presented in EPA’s TSD for the
proposed rule, ‘‘highlights the need for
further analysis of potential NOX
controls by the District.’’ Earthjustice
stated that information available in
EPA’s 1994 ACT, which shows NOX
emissions from MSW-fired boilers with
SNCR controls ranging from 35 to 167
ppmv at 12% CO2, calls into question
the 165 to 210 ppmv at 12% CO2 range
provided in the District’s 2011 Staff
Report and places the District’s NOX
emissions limit of 165 ppmv at 12%
CO2 at the highest end of the range.
Earthjustice also asserted that ‘‘[g]iven
that the Valley is in nonattainment of
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the PM2.5 NAAQS and is in extreme
nonattainment of the 1-hour and 8-hour
ozone NAAQS, EPA must require the
District to conduct further analysis and
ensure that MSW-fired boilers meet the
lowest emission limit that can be
achieved through the application of
RACT.’’
Response #2.c: First, with respect to
the commenter’s assertions about the
NJDEP rule (N.J.A.C. 7:27–19.12), we
addressed these comments above in
Response #2.a. Second, with respect to
the commenter’s assertion about data
presented in EPA’s TSD, although we
agree with the commenter’s observation
that the NOX emission limit in Rule
4352 (165 ppmv at 12% CO2) is at the
highest end of the range of NOX levels
identified in EPA’s 1994 ACT for MSWfired boilers operating SNCR controls
with ammonia or urea injection, we
disagree with the assertion that this
necessarily compels further evaluation
of the NOX limit in Rule 4352.
Municipal solid waste varies widely
in composition—often including
durable goods, non-durable goods,
demolition and construction wastes,
containers and packaging, food wastes
and yard trimmings, and/or
miscellaneous inorganic wastes—and
the exact makeup of MSW at a
particular facility may vary both
seasonally and geographically. See 1994
ACT at Section 3.4.3. Variability in
MSW can affect emissions both due to
differences in the availability of fuelbound nitrogen as well as differences in
the heat content of the fuel, which can
affect its combustion characteristics.
Given the broad technical diversity of
existing MSW-fired boilers and their
varying fuel compositions, the NOX
emission level that one MSW-fired unit
achieves by the application of
reasonably available controls may not
necessarily be achievable for others
using similar controls. Even where
boiler type, control technology, and fuel
type are the same, emission levels may
differ significantly from boiler to boiler
depending on a number of site-specific
factors, including furnace dimensions
and operating characteristics, design
and condition of burner controls, design
and condition of stream control systems,
and fan capacity. See, for example, 1994
ACT at Appendix B (page B–21),
showing achievable NOX emission
levels ranging from 44 to 210 ppm at 3%
O2 for MSW boilers equipped with
SNCR.
ACT documents describe available
control techniques and their cost
effectiveness but do not define
presumptive RACT levels as EPA’s
Control Techniques Guidelines (CTGs)
do. The wide range of emission levels
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provided in the 1994 ACT for MSWfired boilers equipped with SNCR and
using ammonia or urea injection as a
control technique (35 to 167 ppmv at
12% CO2) reflects the significant
variation in emission levels that may
result from site-specific technological
considerations and fuel compositions at
different MSW-fired units. Notably, the
NOX emission ranges provided in
Appendix B of the 1994 ACT do not
identify applicable averaging periods
and therefore may not be directly
comparable to the 24-hour NOX
emission limit in Rule 4352. See 1994
ACT at Appendix B.
EPA has evaluated the control
techniques and applicable permit
conditions for the two MSW
incinerators in New Jersey that are
currently subject to the 24-hour NOX
emission limit of 150 ppm (at 3% O2)
in N.J.A.C. 7:27–19.12 (Gloucester and
Camden) and concluded that technical
distinctions between these facilities and
the Covanta Stanislaus facility in SJV
raise significant questions about the
technological and economic feasibility
of those same emission control methods
at existing MSW-fired boilers in the SJV.
See Response #2.a. We do not currently
have information sufficient to support a
conclusion that existing MSW-fired
boilers using ammonia-based SNCR
systems, either generally or specifically
in the SJV, are capable of meeting a 24hour NOX emission limit of 150 ppm at
3% O2 (142 ppm of at 12% CO2) by the
application of control technology that is
reasonably available considering
technological and economic feasibility.
Finally, with respect to the
commenter’s statement about the SJV
area’s air quality designations for the
PM2.5 and ozone National Ambient Air
Quality Standards (NAAQS), we note
that attainment status designations are
not relevant to our evaluation of Rule
4352 for compliance with the
technology-based RACT control
requirement in CAA section 182(b)(2).
The RACT requirement in CAA section
182 is a control mandate that applies
independent of the emission reductions
needed for attainment of the NAAQS.
See, e.g., EPA’s Proposed Rule to
Implement the 8-Hour Ozone [NAAQS],
68 FR 32802, 32837 (June 2, 2003)
(explaining that ‘‘[u]nder subpart 2,
RACT requirements for ozone
nonattainment areas apply independent
of the emissions reductions needed to
attain the standard’’). We note, however,
that the general requirement in CAA
section 172(c)(1) to adopt all
‘‘reasonably available control measures’’
(RACM) continues to apply in the SJV
area for purposes of attaining the ozone
and PM2.5 NAAQS (see, e.g., 40 CFR
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51.912(d) and 51.1010). Given the
severity of the ozone and PM2.5
pollution problems in the SJV and the
NOX and PM2.5 emission reduction
commitments contained in the SIPapproved plans for attainment of the
1997 PM2.5 and 1997 8-hour ozone
standards in the SJV,8 we encourage the
District to further evaluate potential
NOX and PM control options at its
earliest opportunity to determine
whether additional controls for existing
MSW-fired boilers may be reasonably
available for implementation in the
Valley.
Comment #3: Earthjustice asserted
that EPA should urge the District to
reevaluate the startup and shutdown
provisions in Rule 4352 as the rule
allows units to emit excess emissions
for far longer than necessary. In support
of this assertion, the commenter referred
to rules adopted by the Placer County
Air Pollution Control District
(PCAPCD), Yolo Solano Air Quality
Management District (YSAQMD) and
Sacramento Metropolitan Air Quality
Management District (SMAQMD), each
of which contain shorter time periods
for startup and shutdown operations.
Citing a 1999 EPA policy document
providing that startup and shutdown
periods should be limited ‘‘to the
maximum degree practicable,’’ the
commenter asserted that the District had
neglected to evaluate the possibility of
requiring shorter startup and shutdown
times under Rule 4352 for solid fuelfired boilers.
Response #3: We disagree with the
commenter’s assertion that the startup
and shutdown provisions in Rule 4352
are deficient. EPA policy for SIPs
regarding excess emissions during
malfunctions, startup, shutdown, and
maintenance provides that for some
source categories, ‘‘given the types of
control technologies available, there
may exist short periods of emissions
during startup and shutdowns when,
despite best efforts regarding planning,
design, and operating procedures, the
otherwise applicable emission
limitation cannot be met.’’ Thus, with
limited exceptions, it may be
appropriate in consultation with EPA to
create ‘‘narrowly-tailored SIP revisions’’
that take these technological limitations
into account and state that the otherwise
applicable emissions limitations do not
apply during these periods. See
Memorandum dated September 20,
1999, from Steven A. Herman, Assistant
Administrator for Enforcement and
Compliance Assurance and Robert
8 See, e.g., SIP-approved NO emission reduction
X
commitments in 40 CFR 52.220(c)(356)(ii)(B)(2) and
52.220(c)(356)(ii)(B)(4), and 52.220(c)(397)(ii)(B)(2).
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Perciasepe, Assistant Administrator for
Air and Radiation, to Regional
Administrators, Regions I–X, ‘‘State
Implementation Plans: Policy Regarding
Excess Emissions During Malfunctions,
Startup, and Shutdown’’ (1999 SSM
Policy) at Attachment, pp. 4–5.
According to the 1999 SSM Policy, SIP
provisions addressing these
circumstances should, among other
things, be limited to specific, narrowlydefined source categories. Id.
Additionally, use of the control
technology for the source category
should be technically infeasible during
startup or shutdown periods; the
frequency and duration of operation in
startup or shutdown mode should be
minimized to the maximum extent
practicable; and all possible steps
should be taken to minimize the impact
of emissions during startup and
shutdown on ambient air quality. Id.
Rule 4352 generally applies to any
boiler, steam generator or process heater
fired on ‘‘solid fuel’’ that is operated at
a stationary source with a potential to
emit at least 10 tons per year of NOX or
VOC. See Rule 4352 at sections 2.0,
3.18, and 4.0. Section 5.3 of the rule
states that the applicable emission
limits established for this defined
source category ‘‘shall not apply during
start-up or shutdown provided an
operator complies with the
requirements specified below.’’ The rule
then limits the duration of each start-up
to 96 hours, except that if curing of the
refractory is required after a
modification to the unit is made, the
duration of start-up is limited to 192
hours, with exceptions only as approved
by the District, CARB, and EPA. See
Rule 4352 at section 5.3.2. The rule also
limits the duration of each shutdown to
12 hours, with exceptions only as
approved by the District, CARB, and
EPA. Id. at section 5.3.1. Significantly,
Rule 4352 requires, in all cases, that
‘‘the emission control system shall be in
operation and emissions shall be
minimized insofar as technologically
feasible during start-up or shutdown.’’
Id. at section 5.3.3. These provisions for
start-up and shutdown apply to all solid
fuel-fired boilers subject to Rule 4352,
including biomass-fired and MSW-fired
boilers.
Earthjustice refers to rules adopted by
the PCAPCD, YSAQMD and SMAQMD
to support its assertion that the District
should consider establishing shorter
exemption periods for startup and
shutdowns, but these other California
rules apply to source categories that
differ from the source category subject
to Rule 4352. Both YSAQMD Rule 2.43
and PCAPCD Rule 233, which apply to
boilers fueled entirely or primarily with
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biomass, limit normal startups and all
shutdowns to 24 hours and curing
startups to 96 hours. See YSAQMD Rule
2.43 at sections 102 and 302, and
PCAPCD Rule 233 at sections 101, 206,
214 and 215. Thus, although both the
YSAQMD rule and PCAPCD rule limit
the allowed duration of startup and
shutdown to periods that are shorter
than the limits in Rule 4352, both rules
apply only to a subset of the boilers
subject to Rule 4352. Biomass-fired
boilers may not require start-up or
shutdown periods as long in duration as
those needed by the range of solid fuelfired boilers subject to SJVUAPCD’s
Rule 4352, which combust more
complex and heterogeneous fuel mixes,
including biomass, MSW, coal, and
other solid fuels. Notably, neither the
YSAQMD rule nor the PCAPCD rule
explicitly requires continued operation
of emission control systems to the
extent feasible during start-up and
shutdown periods, as does Rule 4352.9
SMAQMD Rule 411, which applies to
units fueled with gaseous and nongaseous fuels, limits startup to a
maximum of two hours after a period in
which the gas flow is shut off for a
continuous period of 30 minutes or
longer and limits shutdown to two
hours. See SMAQMD Rule 411 at
sections 102, 220–222. We are not
aware, however, of any solid fuel fired
boilers operating in the Sacramento
metro area subject to Rule 411. Thus,
SMAQMD Rule 411 does not appear to
establish that shorter limits on startup
and shutdown periods are
technologically feasible for solid fuelfired boilers.
In sum, the start-up and shutdown
provisions in SJVUAPCD’s Rule 4352
are narrowly-tailored to address the
technological limitations of emissions
controls at solid fuel-fired boilers and
require, unlike the other California
district rules cited by the commenter,
that source owners/operators continue
to operate emission control systems and
to minimize emissions to the extent
technologically feasible, even during
start-up or shutdown periods. We
conclude that these provisions in Rule
4352 are consistent with EPA’s 1999
SSM policy and appropriate for SIP
approval for this particular source
category. We agree with the commenter,
however, that the District should
reevaluate these provisions at its earliest
9 The YSAQMD rule states that ‘‘the frequency
and duration of startup and shutdown periods and
their associated emissions shall be minimized as
much as technologically feasible.’’ YSAQMD Rule
2.43 at section 302.3. The PCAPCD rule includes
alternative pound per hour emission limits for NOX
and CO during startup and shutdown periods. See
PCAPCD Rule 233 at section 302.2.
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66553
opportunity to determine whether
shorter limits on the duration of startup
and shutdown periods may be feasible
for certain types of solid fuel-fired
boilers covered by the rule, and to
consider establishing limits on the
frequency of such events, to ensure that
emissions during start-up and shutdown
events are minimized to the maximum
extent practicable. We also encourage
the District to carefully review the
CEMS data required by section 5.4 of
Rule 4352 (monitoring provisions), in
particular NOX emissions data during
start-up and shutdown periods, to
ensure that owners/operators of solid
fuel-fired boilers are in fact operating
emission control systems and
minimizing emissions insofar as
technologically feasible during start-up
or shutdown as required by Rule 4352,
section 5.3.3.
III. EPA Action
For the reasons provided in our
proposed rule and above, and pursuant
to section 110(k)(3) of the Act, EPA is
fully approving Rule 4352 into the San
Joaquin Valley portion of the California
SIP. This final approval of Rule 4352
satisfies California’s obligation to
implement RACT under CAA section
182(b)(2) for solid fuel-fired boilers in
the SJV for the 1-hour ozone and 1997
8-hour ozone NAAQS and thereby
terminates all CAA sanctions clocks and
Federal Implementation Plan (FIP)
clocks associated with this source
category. See 75 FR 60623 (October 1,
2010) (final limited approval and
disapproval of Rule 4352); 77 FR 1417
(January 10, 2012) (final partial approval
and disapproval of SJV RACT SIP); and
77 FR 24857 (April 26, 2012) (interim
final determination to stay and defer
sanctions).
IV. Statutory and Executive Order
Reviews
Under the Clean Air Act, the
Administrator is required to approve a
SIP submission that complies with the
provisions of the Act and applicable
Federal regulations. 42 U.S.C. 7410(k);
40 CFR 52.02(a). Thus, in reviewing SIP
submissions, EPA’s role is to approve
State choices, provided that they meet
the criteria of the Clean Air Act.
Accordingly, this action merely
approves State law as meeting Federal
requirements and does not impose
additional requirements beyond those
imposed by State law. For that reason,
this action:
• Is not a ‘‘significant regulatory
action’’ subject to review by the Office
of Management and Budget under
Executive Order 12866 (58 FR 51735,
October 4, 1993);
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Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations
• Does not impose an information
collection burden under the provisions
of the Paperwork Reduction Act (44
U.S.C. 3501 et seq.);
• Is certified as not having a
significant economic impact on a
substantial number of small entities
under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.);
• Does not contain any unfunded
mandate or significantly or uniquely
affect small governments, as described
in the Unfunded Mandates Reform Act
of 1995 (Pub. L. 104–4);
• Does not have Federalism
implications as specified in Executive
Order 13132 (64 FR 43255, August 10,
1999);
• Is not an economically significant
regulatory action based on health or
safety risks subject to Executive Order
13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action
subject to Executive Order 13211 (66 FR
28355, May 22, 2001);
• Is not subject to requirements of
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (15 U.S.C. 272 note) because
application of those requirements would
be inconsistent with the Clean Air Act;
and
• Does not provide EPA with the
discretionary authority to address
disproportionate human health or
environmental effects with practical,
appropriate, and legally permissible
methods under Executive Order 12898
(59 FR 7629, February 16, 1994).
In addition, this rule does not have
tribal implications as specified by
Executive Order 13175 (65 FR 67249,
November 9, 2000), because the SIP is
not approved to apply in Indian country
located in the State, and EPA notes that
it will not impose substantial direct
costs on tribal governments or preempt
tribal law.
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this action and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General of the United
States prior to publication of the rule in
the Federal Register. A major rule
cannot take effect until 60 days after it
is published in the Federal Register.
This action is not a ‘‘major rule’’ as
defined by 5 U.S.C. 804(2).
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Under section 307(b)(1) of the Clean
Air Act, petitions for judicial review of
this action must be filed in the United
States Court of Appeals for the
appropriate circuit by January 7, 2013.
Filing a petition for reconsideration by
the Administrator of this final rule does
not affect the finality of this action for
the purposes of judicial review nor does
it extend the time within which a
petition for judicial review may be filed,
and shall not postpone the effectiveness
of such rule or action. This action may
not be challenged later in proceedings to
enforce its requirements (see section
307(b)(2)).
List of Subjects in 40 CFR Part 52
Environmental protection, Air
pollution control, Incorporation by
reference, Intergovernmental relations,
Nitrogen dioxide, Ozone, Particulate
matter, Reporting and recordkeeping
requirements.
Dated: September 13, 2012.
Jared Blumenfeld,
Regional Administrator, Region IX.
Part 52, Chapter I, Title 40 of the Code
of Federal Regulations is amended as
follows:
PART 52—[AMENDED]
1. The authority citation for part 52
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart F—California
2. Section 52.220 is amended by
adding paragraphs (c)(411) (i)(B)(4) to
read as follows:
■
§ 52.220
Identification of plan.
*
*
*
*
*
(c) * * *
(411) * * *
(i) * * *
(B) * * *
(4) Rule 4352, ‘‘Solid Fuel Fired
Boilers, Steam Generators and Process
Heaters,’’ amended on December 15,
2011.
*
*
*
*
*
[FR Doc. 2012–26779 Filed 11–5–12; 8:45 am]
BILLING CODE 6560–50–P
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GENERAL SERVICES
ADMINISTRATION
41 CFR Part 303–70
[FTR Amendment 2012–07; FTR Case 2011–
308; Docket Number 2011–0022, Sequence
1]
RIN 3090–AJ21
Federal Travel Regulation (FTR);
Payment of Expenses Connected With
the Death of Certain Employees
Office of Government-wide
Policy, General Services Administration
(GSA).
ACTION: Final rule.
AGENCY:
GSA has adopted as final, an
interim rule amending the Federal
Travel Regulation (FTR) to establish
policy for the transportation of the
immediate family, household goods,
personal effects, and one privately
owned vehicle of a covered employee
whose death occurred as a result of
personal injury sustained while in the
performance of the employee’s duty as
defined by the agency.
DATES: Effective date: November 6,
2012.
Applicability date: This final rule
applies to travel relating to employees
who died on or after June 9, 2010.
FOR FURTHER INFORMATION CONTACT: The
Regulatory Secretariat (MVCB), 1275
First Street NE. Washington, DC 20417,
(202) 501–4755, for information
pertaining to status or publication
schedules. For clarification of content,
contact Rick Miller, Office of
Government-wide Policy, Travel and
Relocation Policy Division, at (202)
501–3822 or email at
rodney.miller@gsa.gov. Please cite FTR
Amendment 2012–07, FTR Case 2011–
308.
SUPPLEMENTARY INFORMATION:
SUMMARY:
A. Background
Pursuant to 5 U.S.C. 5707, the
Administrator of General Services is
authorized to prescribe necessary
regulations to implement laws regarding
Federal employees who travel in the
performance of official business away
from their official stations. Similarly, 5
U.S.C. 5738 mandates that the
Administrator of General Services
prescribe regulations relating to official
relocation. In addition, the Presidential
Memorandum, ‘‘Delegation Under
Section 2(a) of the Special Agent
Samuel Hicks Families of Fallen Heroes
Act,’’ dated September 12, 2011,
published in the Federal Register on
September 15, 2011 (76 FR 57621),
delegates to the Administrator of
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]]>Agencies
[Federal Register Volume 77, Number 215 (Tuesday, November 6, 2012)]
[Rules and Regulations]
[Pages 66548-66554]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-26779]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R09-OAR-2012-0266; FRL-9736-9]
Revisions to the California State Implementation Plan, San
Joaquin Valley Unified Air Pollution Control District
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is approving revisions to the San Joaquin Valley Unified
Air Pollution Control District (SJVUAPCD) portion of the California
State Implementation Plan (SIP). This action was proposed in the
Federal Register on April 26, 2012 and concerns oxides of nitrogen
(NOX) from solid fuel fired boilers. We are approving a
local rule that regulates these emission sources under the Clean Air
Act (CAA or the Act).
DATES: This rule will be effective on December 6, 2012.
ADDRESSES: EPA has established docket number EPA-R09-OAR-2012-0266 for
this action. Generally, documents in the docket for this action are
available electronically at https://www.regulations.gov or in hard copy
at EPA Region IX, 75 Hawthorne Street, San Francisco, California. While
all documents in the docket are listed at https://www.regulations.gov,
some information may be publicly available only at the hard copy
location (e.g., copyrighted material, large maps, multi-volume
reports), and some may not be available in either location (e.g.,
confidential business information (CBI)). To inspect the hard copy
materials, please schedule an appointment during normal business hours
with the contact listed in the FOR FURTHER INFORMATION CONTACT section.
FOR FURTHER INFORMATION CONTACT: Idalia P[eacute]rez, EPA Region IX,
(415) 972-3248, perez.idalia@epa.gov.
[[Page 66549]]
SUPPLEMENTARY INFORMATION: Throughout this document, ``we,'' ``us'' and
``our'' refer to EPA.
Table of Contents
I. Proposed Action
II. Public Comments and EPA Responses
III. EPA Action
IV. Statutory and Executive Order Reviews
I. Proposed Action
On April 26, 2012 (77 FR 24883), EPA proposed to approve the
following rule into the California SIP.
----------------------------------------------------------------------------------------------------------------
Rule
Local agency No. Rule title Adopted Submitted
----------------------------------------------------------------------------------------------------------------
SJVUAPCD.................................. 4352 Solid Fuel Fired Boilers, Steam 12/15/11 02/23/12
Generators and Process Heaters.
----------------------------------------------------------------------------------------------------------------
We proposed to approve this rule based on our conclusion that it
complies with the relevant CAA requirements. Our proposed rule and
Technical Support Document (TSD) \1\ contain more information on the
rule and our evaluation.
---------------------------------------------------------------------------
\1\ See U.S. EPA Region 9, ``Technical Support Document for
EPA's Notice of Proposed Rulemaking for the California State
Implementation Plan, San Joaquin Valley Unified Air Pollution
Control District's Rule 4352, Solid Fuel Fired Boilers, Steam
Generators and Process Heaters,'' April 2012 (TSD).
\2\ See Air Pollution Control Operating Permit, Permit Activity
No. BOP090001, Covanta Essex Co. (Essex PTO) at pg. 57 of 95.
\3\ See Air Pollution Control Operating Permit, Permit Activity
No. BOP090002, Covanta Warren Energy Resource Co. LP (Warren PTO) at
pp. 57 and 60 of 101.
---------------------------------------------------------------------------
II. Public Comments and EPA Responses
EPA's proposed action provided a 30-day public comment period.
During this period, we received comments from the following party.
1. Adenike Adeyeye, Earthjustice; letter dated and received May 29,
2012.
The comments and our responses are summarized below.
Comment #1: Earthjustice stated that these revisions are an
improvement over prior versions of this rule.
Response #1: No response needed.
Comment #2: Earthjustice disagreed with EPA's proposal to approve
the NOX emission limit in Rule 4352 for municipal solid
waste (MSW) fired units as RACT. Earthjustice provided several
arguments in support of its objection to EPA's proposal, each of which
we address following separate comment summaries below.
Comment #2.a: Earthjustice stated that the New Jersey Department of
Environmental Protection (NJDEP) has set NOX emissions
limits for MSW-fired boilers at 150 ppmv at 7% O2
(approximately 142 ppmv at 12% CO2). Quoting from a SIP
submission from NJDEP, Earthjustice asserted that NJDEP established
this limit based on ``the capability of existing selective non-
catalytic reduction (SNCR) emission controls to reduce emissions more
than are now being achieved.'' The commenter stated that the District's
unsupported assertion that it is impossible to meet a limit lower than
165 ppmv at 12% CO2 is simply false.
Response #2.a: We disagree with the commenter's suggestion that the
NOX emissions limits established in NJDEP's rule generally
represent NOX RACT for existing MSW-fired boilers equipped
with SNCR controls. As the commenter correctly notes, under Title 7,
Chapter 27, Subchapter 19, Section 12 of the New Jersey Administrative
Code (N.J.A.C. 7:27-19.12), NJDEP limits NOX emissions from
MSW combustors to 150 ppm at 7% O2 averaged over 24 hours
(approximately 142 ppm at 12% CO2). In lieu of complying
with this emissions limit, however, the rule allows an owner or
operator of an MSW incinerator to comply with an alternative emission
limit or a ``facility-specific NOX control plan'' upon
receipt of written approval from NJDEP, pursuant to section 13 of the
rule (N.J.A.C. 7:27-19.13). See N.J.A.C. 7:27-19.12(b). Section 13
identifies, among other things, the types of information that an owner
or operator must submit to NJDEP as part of a request for such an
alternative emission limit or facility-specific NOX control
plan, including a list of all NOX control technologies
available for use with the equipment or source operation, an analysis
of the technological feasibility and costs of installing and operating
each such control technology, and estimates of the NOX
emissions reductions attainable through the use of each control
technology which is technologically feasible. See N.J.A.C. 7:27-
19.13(d). The rule authorizes NJDEP to approve a request for an
alternative emission limit or facility-specific NOX control
plan only if, among other things, the request identifies all available
NOX control options and demonstrates that any control
options that the owner/operator has rejected are ineffective or
unsuitable for the particular equipment or would involve
disproportionately high costs, in comparison to the associated
NOX reductions or costs borne by other like facilities. See
N.J.A.C. 7:27-19.13(g)(3).
According to NJDEP, three of the five MSW incinerators subject to
N.J.A.C. 7:27-19.12 appear to have obtained alternative emission limits
pursuant to Section 13 of the rule and are not currently subject to the
24-hour NOX limit of 150 ppm at 7% O2. See email
dated July 24, 2012, from Michael Klein (NJDEP) to Stanley Tong (EPA
Region 9). Table 1 below shows the current NOX limits in the
operating permits for each of these five MSW incinerators under NJDEP
jurisdiction.
Table 1
----------------------------------------------------------------------------------------------------------------
Emission limit
Emission limit (approximate ppm Averaging
Facility (ppm at 7% at 12% time
O[ihel2]) CO[ihel2]) (hours)
----------------------------------------------------------------------------------------------------------------
Essex \2\...................................................... 300 285 1
155 147 24
----------------------------------------------------------------------------------------------------------------
Warren \3\..................................................... 300 285 3
205 195 24
----------------------------------------------------------------------------------------------------------------
[[Page 66550]]
Union \4\...................................................... 225 214 3
180 171 24
----------------------------------------------------------------------------------------------------------------
Gloucester \5\................................................. 350 333 3
150 143 24
----------------------------------------------------------------------------------------------------------------
Camden \6\..................................................... 300 285 3
150 143 24
----------------------------------------------------------------------------------------------------------------
Of the three New Jersey facilities that have obtained permit limits
exceeding the 24-hour NOX limit of 150 ppm (at 7%
O2) in NJDEP's rule (Essex, Warren, and Union), two
facilities (Warren and Union) have permit limits that also exceed the
24-hour NOX limit of 165 ppm (at 12% CO2) in
SJVUAPCD's Rule 4352. See Table 1. The remaining two facilities, which
are subject to the 150 ppm limit in NJDEP's rule (Gloucester and
Camden), are both equipped with SNCR using urea injection as a
NOX control technique. See Gloucester PTO at pp. 45-46 of
106; Camden PTO at pg. 183 (of electronic file). Both of these
facilities became subject to the 24-hour NOX limit of 150
ppm (at 7% O2) in N.J.A.C. 7:27-19.12 effective May 1, 2011.
See Gloucester PTO at pp. 38 of 106; Camden PTO at pg. 34 of 99.
Notably, for the Camden facility, the 150 ppm limit applied ``on and
after May 1, 2011, if compliance is achieved by installing a new
NOX air pollution control system on an existing MSW
incinerator or by physically modifying an existing MSW incinerator.''
Camden PTO at pg. 34 of 99. The Gloucester and Camden facilities are
the only MSW incinerators we know of that are subject to the 24-hour
NOX limit of 150 ppm (at 7% O2) in N.J.A.C. 7:27-
19.12.
---------------------------------------------------------------------------
\4\ See Air Pollution Control Operating Permit, Permit Activity
No. BOP080001, Covanta Union (Union PTO) at pp. 56 and 57 of 90.
---------------------------------------------------------------------------
Only one existing facility in the SJV (Covanta Stanislaus, Inc.)
currently operates MSW-fired boilers subject to SJVUAPCD's Rule 4352.
The two MSW-fired boilers at the Covanta Stanislaus facility are
equipped with SCNR using ammonia injection systems, instead of urea
injection systems, for NOX control. See Facility-wide Permit
to Operate for Covanta Stanislaus, Inc., San Joaquin Valley Air
Pollution Control District, Permit Unit: N-2073-1-10 (expiration date
10/31/2016), ``Equipment Description'' (Stanislaus PTO). Although
ammonia and urea injection both serve as reducing agents for
NOX emissions in combination with SNCR control systems,
these control methods require operation at different temperature
windows and generally are not interchangeable without facility
retrofits. See Alternative Control Techniques Document--NOX Emissions
from Industrial/Commercial/Institutional (ICI) Boilers, U.S. EPA 453/R-
94-022 (March 1994) (1994 ACT) at sections 5.5.1.1 (``Ammonia-based
SNCR'') and 5.5.1.2 (``Urea-based SNCR''). For example, the optimum
reaction temperature range for the reduction of NOX by
ammonia is 870[deg] to 1,100 [deg]C, while the optimum range for the
reduction of NOX by urea is 900[deg] to 1,150 [deg]C, and
ammonia can be injected both in aqueous solution or anhydrous form
while urea may only be injected in aqueous form. Id. These
technological distinctions between ammonia-based SNCR and urea-based
SNCR highlight uncertainties about whether the controls implemented by
the Gloucester and Camden incinerators in New Jersey (i.e., urea-based
SNCR) are technologically and economically feasible for implementation
at the one existing MSW-fueled facility in SJV.
---------------------------------------------------------------------------
\5\ See Air Pollution Control Operating Permit, Permit Activity
No. BOP090002, Wheelabrator Gloucester Company (Gloucester PTO) at
pp. 38 and 68 of 106.
\6\ See Air Pollution Control Operating Permit, Permit Activity
No. BOP080002, Camden Cnty Energy Recovery Assoc LP (Camden PTO) at
pp. 34 and 66 of 99.
---------------------------------------------------------------------------
Additionally, according to information submitted by SJVUAPCD at
EPA's request, four of the five MSW incinerators subject to the NJDEP
rule have equipment that differs significantly from the equipment at
the Covanta Stanislaus facility in SJV. See emails dated September 4,
2012 and September 11, 2012, from Nichole Corless (SJVUAPCD) to Idalia
Perez (EPA Region 9), with attachments. Specifically, SJVUAPCD states
that the Covanta Stanislaus facility is configured with stoker grates
whereas the New Jersey MSW incinerators have reciprocating, horizontal,
and roller grates, which enable them to meet a slightly lower
NOX limit. Id. These technological distinctions raise
additional questions about whether the controls implemented by the New
Jersey facilities are feasible for implementation in SJV. Moreover, the
fact that both the Gloucester and Camden incinerators in New Jersey
became subject to the 150 ppm limit in N.J.A.C. 7:27-19.12 only as of
May 1, 2011, and in Camden's case only if the facility made physical
modifications to, or installed new air pollution control equipment on,
the existing MSW incinerator, further highlights uncertainties about
whether the chosen control methods at these two facilities are
``reasonably available'' for implementation at existing MSW-fired
boilers in SJV.
Finally, information submitted by the SJVUAPCD indicates that
retrofits to existing SNCR systems to achieve additional NOX
reductions are not cost-effective in light of the relatively
insignificant difference between the NOX limit in NJDEP's
rule (150 ppm at 7% O2, or approximately 142 ppm at 12%
CO2, 24-hour average) and the limit in SJVUAPCD's Rule 4352
(165 ppm at 12% CO2, 24-hour average). Specifically, with
respect to staged combustion retrofits to an ammonia-based SNCR control
system, SJVUAPCD submitted information indicating that the cost per ton
of reductions in NOX emissions from 165 to 142 ppm at 12%
CO2 would be $27,650/ton. See email dated September 4, 2012,
from Nichole Corless (SJVUAPCD) to Idalia Perez (EPA Region 9), with
attachment. Further taking into account certain operational conditions
at the Covanta Stanislaus facility which indicate that the limit in
NJDEP's rule (150 ppm at 7% O2) would equate to
approximately 148 ppm (rather than 142 ppm) at 12% CO2, the
cost per ton of NOX emission reductions from 165 ppm to 148
ppm at 12% CO2 would be $37,404/ton. See id. These costs
exceed the levels generally
[[Page 66551]]
considered to be ``reasonable'' within the meaning of RACT.
In sum, the information before us raises significant questions
about the technical and economic feasibility of achieving a 24-hour
NOX emission limit of 150 ppm at 7% O2
(approximately 142 ppm at 12% CO2) at existing MSW-fired
boilers equipped with ammonia-based SNCR in the SJV, and the commenter
has provided little information to substantiate its claim in this
regard. Absent specific information to support a conclusion that
further NOX controls are ``reasonably available'' for
implementation at existing MSW-fired boilers in the SJV, we find that
the 24-hour NOX emission limit of 165 ppm at 12%
CO2 in SJVUAPCD's Rule 4352 represents current RACT for
these units.\7\
---------------------------------------------------------------------------
\7\ The commenter states that ``the District's unsupported
assertion that it is impossible to meet a limit lower than 165 ppmv
at 12% CO2 is simply false,'' but this assertion
mischaracterizes the District's position, as test data for Covanta
Stanislaus submitted by the District clearly show average
NOX emission levels below the 165 ppm limit in Rule 4352.
See TSD at 6. An emission limit of 165 ppm at 12% CO2
ensures that the source is obligated to continually operate its
emission control system while leaving the facility a small
compliance buffer to account for occasional short-term variabilities
inherent in its process. Id.
---------------------------------------------------------------------------
Comment #2.b: Earthjustice asserted that the District has not
adequately analyzed and considered the feasibility of either injecting
more ammonia or adding more nozzles to existing SNCR controls to meet a
lower NOX emissions limit. The commenter stated that
according to the NJDEP State Implementation Plan (SIP) Revision for the
Attainment and Maintenance of the Fine Particulate Matter
(PM2.5) National Ambient Air Quality Standard (NJDEP 2009
PM2.5 SIP) submitted to EPA in 2009, 11 regulated units at 4
facilities in New Jersey would meet the lower NOX emissions
limit in N.J.A.C. 7:27-19.12 by injecting more ammonia or adding more
nozzles to existing SNCR controls. The commenter stated that
``technical analysis of these demonstrated options must be conducted
before EPA can accept ammonia slip as an excuse for rejecting tighter
SNCR limits.''
Response #2.b: We have generally evaluated the technical
feasibility of injecting more ammonia or adding nozzles to existing
SNCR controls but do not have sufficient information to conclude that
these control methods represent RACT for existing MSW-fired boilers in
SJV at this time. According to information submitted by SJVUAPCD at our
request, the orientation of the nozzles in the combustion gas stream
has a much greater impact on the resulting NOX emissions
than the number of nozzles in the system, and the Covanta Stanislaus
facility's nozzles have already been optimized based on the
``temperature window where SNCR works to reduce NOX
effectively.'' See email dated September 4, 2012, from Nichole Corless
(SJVUAPCD) to Idalia Perez (EPA Region 9), with attachments. SJVUAPCD
also stated that the amount of ammonia injected into the flue gas at
Covanta Stanislaus is closely controlled to maximize NOX
reductions and to prevent excessive ammonia slip, and that increases in
ammonia injection would ``result in negligible NOX
reductions and would exit the system and cause a detached plume,''
causing violations of permit conditions regarding visible emissions,
ammonia slip, and condensable particulate matter. Id. (citing
continuous emissions monitoring data submitted by Covanta Stanislaus to
support these conclusions).
EPA's Alternative Control Techniques document for NOX
emissions from Industrial/Commercial/Institutional Boilers (1994 ACT)
supports the general conclusion that simply injecting more ammonia or
adding nozzles will not necessarily reduce NOX emissions in
an ammonia-based SNCR system. The 1994 ATC describes the process in an
ammonia-based SNCR system as follows:
In this process, aqueous or anhydrous ammonia is vaporized and
injected into the flue gas through wall-mounted nozzles at a
location selected for optimum reaction temperature and residence
time. The optimum reaction temperature range for this process is 870
to 1,100 [deg]C (1,600 to 2,000 [deg]F). * * * At temperatures above
1,100 [deg]C (2,000 [deg]F), ammonia injection becomes
counterproductive, resulting in additional NO formation. Below 870
[deg]C (1,600 [deg]F), the reaction rate drops and undesired amounts
of ammonia are carried out in the flue gas. Unreacted ammonia is
commonly referred to as ammonia slip, breakthrough, or carryover.
The amount of ammonia slip also depends in part on the amount of
ammonia injected. Although the chemical reaction requires one mole
of NH3 for each mole of NO, the NH3/
NOX ratio used is usually greater than 1 to avoid an
undesired reaction which results in formation of NO. * * *
Achievable NOX reductions for an individual boiler depend
on the flue gas temperature, the residence time at that temperature,
the initial NOX concentration, the NH3/
NOX ratio, the excess oxygen level, and the degree of
ammonia/flue gas mixing. Also, stratification of both temperature
and NOX in the flue gas can affect the performance of the
SNCR control. The optimum placement of SNCR injectors requires a
detailed mapping of the temperature profile in the convective passes
of the boiler, because of the narrow temperature window. 1994 ACT at
Section 5.5.1.1.
Thus, even assuming it is technologically feasible to inject more
ammonia and/or to install additional ammonia injection nozzles, it is
not clear that these methods would further reduce NOX
emissions in an ammonia-based SNCR system, and technical information
indicates that such methods could instead lead to increased ammonia
slip if not carefully adjusted to account for the specific temperature
profile, NH3/NOX ratio, oxygen levels, degree of
ammonia/flue gas mixing, and other factors specific to the particular
boiler and control system.
As the commenter correctly notes, Appendix C of the NJDEP 2009
PM2.5 SIP states that ``the NJDEP anticipates that the
facilities will decrease their emissions due to optimizing their
existing NOX control systems (i.e., either injecting more
ammonia or adding more nozzles).'' See NJDEP 2009 PM2.5 SIP, App. C.,
at 5. This statement alone, however, does not establish that the
NOX emission limit in N.J.A.C. 7:27-19.12 (150 ppm at 3%
O2) represents RACT for existing MSW-fueled boilers. As
discussed above in Response 2.a, four of the five MSW incinerators
subject to the NJDEP rule have equipment configurations that appear to
differ significantly from the Covanta Stanislaus facility, and NJDEP
has approved alternate, higher NOX limits for three of the
five subject sources based on the agency's assessment of source-
specific technological and/or economic factors. Other than referencing
statements of general intent in a New Jersey SIP submission, the
commenter provides no technological or economic information to support
its assertion that existing MSW-fired boilers, either generally or in
SJV specifically, are capable of meeting a 24-hour NOX
emission limit of 150 ppm at 3% O2 (142 ppm of at 12%
CO2) by the application of control technology that is
reasonably available considering technological and economic
feasibility.
Comment #2.c: Earthjustice asserted that the New Jersey rule, along
with data presented in EPA's TSD for the proposed rule, ``highlights
the need for further analysis of potential NOX controls by
the District.'' Earthjustice stated that information available in EPA's
1994 ACT, which shows NOX emissions from MSW-fired boilers
with SNCR controls ranging from 35 to 167 ppmv at 12% CO2,
calls into question the 165 to 210 ppmv at 12% CO2 range
provided in the District's 2011 Staff Report and places the District's
NOX emissions limit of 165 ppmv at 12% CO2 at the
highest end of the range. Earthjustice also asserted that ``[g]iven
that the Valley is in nonattainment of
[[Page 66552]]
the PM2.5 NAAQS and is in extreme nonattainment of the 1-
hour and 8-hour ozone NAAQS, EPA must require the District to conduct
further analysis and ensure that MSW-fired boilers meet the lowest
emission limit that can be achieved through the application of RACT.''
Response #2.c: First, with respect to the commenter's assertions
about the NJDEP rule (N.J.A.C. 7:27-19.12), we addressed these comments
above in Response 2.a. Second, with respect to the commenter's
assertion about data presented in EPA's TSD, although we agree with the
commenter's observation that the NOX emission limit in Rule
4352 (165 ppmv at 12% CO2) is at the highest end of the
range of NOX levels identified in EPA's 1994 ACT for MSW-
fired boilers operating SNCR controls with ammonia or urea injection,
we disagree with the assertion that this necessarily compels further
evaluation of the NOX limit in Rule 4352.
Municipal solid waste varies widely in composition--often including
durable goods, non-durable goods, demolition and construction wastes,
containers and packaging, food wastes and yard trimmings, and/or
miscellaneous inorganic wastes--and the exact makeup of MSW at a
particular facility may vary both seasonally and geographically. See
1994 ACT at Section 3.4.3. Variability in MSW can affect emissions both
due to differences in the availability of fuel-bound nitrogen as well
as differences in the heat content of the fuel, which can affect its
combustion characteristics. Given the broad technical diversity of
existing MSW-fired boilers and their varying fuel compositions, the
NOX emission level that one MSW-fired unit achieves by the
application of reasonably available controls may not necessarily be
achievable for others using similar controls. Even where boiler type,
control technology, and fuel type are the same, emission levels may
differ significantly from boiler to boiler depending on a number of
site-specific factors, including furnace dimensions and operating
characteristics, design and condition of burner controls, design and
condition of stream control systems, and fan capacity. See, for
example, 1994 ACT at Appendix B (page B-21), showing achievable
NOX emission levels ranging from 44 to 210 ppm at 3%
O2 for MSW boilers equipped with SNCR.
ACT documents describe available control techniques and their cost
effectiveness but do not define presumptive RACT levels as EPA's
Control Techniques Guidelines (CTGs) do. The wide range of emission
levels provided in the 1994 ACT for MSW-fired boilers equipped with
SNCR and using ammonia or urea injection as a control technique (35 to
167 ppmv at 12% CO2) reflects the significant variation in
emission levels that may result from site-specific technological
considerations and fuel compositions at different MSW-fired units.
Notably, the NOX emission ranges provided in Appendix B of
the 1994 ACT do not identify applicable averaging periods and therefore
may not be directly comparable to the 24-hour NOX emission
limit in Rule 4352. See 1994 ACT at Appendix B.
EPA has evaluated the control techniques and applicable permit
conditions for the two MSW incinerators in New Jersey that are
currently subject to the 24-hour NOX emission limit of 150
ppm (at 3% O2) in N.J.A.C. 7:27-19.12 (Gloucester and
Camden) and concluded that technical distinctions between these
facilities and the Covanta Stanislaus facility in SJV raise significant
questions about the technological and economic feasibility of those
same emission control methods at existing MSW-fired boilers in the SJV.
See Response 2.a. We do not currently have information
sufficient to support a conclusion that existing MSW-fired boilers
using ammonia-based SNCR systems, either generally or specifically in
the SJV, are capable of meeting a 24-hour NOX emission limit
of 150 ppm at 3% O2 (142 ppm of at 12% CO2) by
the application of control technology that is reasonably available
considering technological and economic feasibility.
Finally, with respect to the commenter's statement about the SJV
area's air quality designations for the PM2.5 and ozone
National Ambient Air Quality Standards (NAAQS), we note that attainment
status designations are not relevant to our evaluation of Rule 4352 for
compliance with the technology-based RACT control requirement in CAA
section 182(b)(2). The RACT requirement in CAA section 182 is a control
mandate that applies independent of the emission reductions needed for
attainment of the NAAQS. See, e.g., EPA's Proposed Rule to Implement
the 8-Hour Ozone [NAAQS], 68 FR 32802, 32837 (June 2, 2003) (explaining
that ``[u]nder subpart 2, RACT requirements for ozone nonattainment
areas apply independent of the emissions reductions needed to attain
the standard''). We note, however, that the general requirement in CAA
section 172(c)(1) to adopt all ``reasonably available control
measures'' (RACM) continues to apply in the SJV area for purposes of
attaining the ozone and PM2.5 NAAQS (see, e.g., 40 CFR
51.912(d) and 51.1010). Given the severity of the ozone and
PM2.5 pollution problems in the SJV and the NOX
and PM2.5 emission reduction commitments contained in the
SIP-approved plans for attainment of the 1997 PM2.5 and 1997
8-hour ozone standards in the SJV,\8\ we encourage the District to
further evaluate potential NOX and PM control options at its
earliest opportunity to determine whether additional controls for
existing MSW-fired boilers may be reasonably available for
implementation in the Valley.
---------------------------------------------------------------------------
\8\ See, e.g., SIP-approved NOX emission reduction
commitments in 40 CFR 52.220(c)(356)(ii)(B)(2) and
52.220(c)(356)(ii)(B)(4), and 52.220(c)(397)(ii)(B)(2).
---------------------------------------------------------------------------
Comment #3: Earthjustice asserted that EPA should urge the District
to reevaluate the startup and shutdown provisions in Rule 4352 as the
rule allows units to emit excess emissions for far longer than
necessary. In support of this assertion, the commenter referred to
rules adopted by the Placer County Air Pollution Control District
(PCAPCD), Yolo Solano Air Quality Management District (YSAQMD) and
Sacramento Metropolitan Air Quality Management District (SMAQMD), each
of which contain shorter time periods for startup and shutdown
operations. Citing a 1999 EPA policy document providing that startup
and shutdown periods should be limited ``to the maximum degree
practicable,'' the commenter asserted that the District had neglected
to evaluate the possibility of requiring shorter startup and shutdown
times under Rule 4352 for solid fuel-fired boilers.
Response #3: We disagree with the commenter's assertion that the
startup and shutdown provisions in Rule 4352 are deficient. EPA policy
for SIPs regarding excess emissions during malfunctions, startup,
shutdown, and maintenance provides that for some source categories,
``given the types of control technologies available, there may exist
short periods of emissions during startup and shutdowns when, despite
best efforts regarding planning, design, and operating procedures, the
otherwise applicable emission limitation cannot be met.'' Thus, with
limited exceptions, it may be appropriate in consultation with EPA to
create ``narrowly-tailored SIP revisions'' that take these
technological limitations into account and state that the otherwise
applicable emissions limitations do not apply during these periods. See
Memorandum dated September 20, 1999, from Steven A. Herman, Assistant
Administrator for Enforcement and Compliance Assurance and Robert
[[Page 66553]]
Perciasepe, Assistant Administrator for Air and Radiation, to Regional
Administrators, Regions I-X, ``State Implementation Plans: Policy
Regarding Excess Emissions During Malfunctions, Startup, and Shutdown''
(1999 SSM Policy) at Attachment, pp. 4-5. According to the 1999 SSM
Policy, SIP provisions addressing these circumstances should, among
other things, be limited to specific, narrowly-defined source
categories. Id. Additionally, use of the control technology for the
source category should be technically infeasible during startup or
shutdown periods; the frequency and duration of operation in startup or
shutdown mode should be minimized to the maximum extent practicable;
and all possible steps should be taken to minimize the impact of
emissions during startup and shutdown on ambient air quality. Id.
Rule 4352 generally applies to any boiler, steam generator or
process heater fired on ``solid fuel'' that is operated at a stationary
source with a potential to emit at least 10 tons per year of
NOX or VOC. See Rule 4352 at sections 2.0, 3.18, and 4.0.
Section 5.3 of the rule states that the applicable emission limits
established for this defined source category ``shall not apply during
start-up or shutdown provided an operator complies with the
requirements specified below.'' The rule then limits the duration of
each start-up to 96 hours, except that if curing of the refractory is
required after a modification to the unit is made, the duration of
start-up is limited to 192 hours, with exceptions only as approved by
the District, CARB, and EPA. See Rule 4352 at section 5.3.2. The rule
also limits the duration of each shutdown to 12 hours, with exceptions
only as approved by the District, CARB, and EPA. Id. at section 5.3.1.
Significantly, Rule 4352 requires, in all cases, that ``the emission
control system shall be in operation and emissions shall be minimized
insofar as technologically feasible during start-up or shutdown.'' Id.
at section 5.3.3. These provisions for start-up and shutdown apply to
all solid fuel-fired boilers subject to Rule 4352, including biomass-
fired and MSW-fired boilers.
Earthjustice refers to rules adopted by the PCAPCD, YSAQMD and
SMAQMD to support its assertion that the District should consider
establishing shorter exemption periods for startup and shutdowns, but
these other California rules apply to source categories that differ
from the source category subject to Rule 4352. Both YSAQMD Rule 2.43
and PCAPCD Rule 233, which apply to boilers fueled entirely or
primarily with biomass, limit normal startups and all shutdowns to 24
hours and curing startups to 96 hours. See YSAQMD Rule 2.43 at sections
102 and 302, and PCAPCD Rule 233 at sections 101, 206, 214 and 215.
Thus, although both the YSAQMD rule and PCAPCD rule limit the allowed
duration of startup and shutdown to periods that are shorter than the
limits in Rule 4352, both rules apply only to a subset of the boilers
subject to Rule 4352. Biomass-fired boilers may not require start-up or
shutdown periods as long in duration as those needed by the range of
solid fuel-fired boilers subject to SJVUAPCD's Rule 4352, which combust
more complex and heterogeneous fuel mixes, including biomass, MSW,
coal, and other solid fuels. Notably, neither the YSAQMD rule nor the
PCAPCD rule explicitly requires continued operation of emission control
systems to the extent feasible during start-up and shutdown periods, as
does Rule 4352.\9\
---------------------------------------------------------------------------
\9\ The YSAQMD rule states that ``the frequency and duration of
startup and shutdown periods and their associated emissions shall be
minimized as much as technologically feasible.'' YSAQMD Rule 2.43 at
section 302.3. The PCAPCD rule includes alternative pound per hour
emission limits for NOX and CO during startup and
shutdown periods. See PCAPCD Rule 233 at section 302.2.
---------------------------------------------------------------------------
SMAQMD Rule 411, which applies to units fueled with gaseous and
non-gaseous fuels, limits startup to a maximum of two hours after a
period in which the gas flow is shut off for a continuous period of 30
minutes or longer and limits shutdown to two hours. See SMAQMD Rule 411
at sections 102, 220-222. We are not aware, however, of any solid fuel
fired boilers operating in the Sacramento metro area subject to Rule
411. Thus, SMAQMD Rule 411 does not appear to establish that shorter
limits on startup and shutdown periods are technologically feasible for
solid fuel-fired boilers.
In sum, the start-up and shutdown provisions in SJVUAPCD's Rule
4352 are narrowly-tailored to address the technological limitations of
emissions controls at solid fuel-fired boilers and require, unlike the
other California district rules cited by the commenter, that source
owners/operators continue to operate emission control systems and to
minimize emissions to the extent technologically feasible, even during
start-up or shutdown periods. We conclude that these provisions in Rule
4352 are consistent with EPA's 1999 SSM policy and appropriate for SIP
approval for this particular source category. We agree with the
commenter, however, that the District should reevaluate these
provisions at its earliest opportunity to determine whether shorter
limits on the duration of startup and shutdown periods may be feasible
for certain types of solid fuel-fired boilers covered by the rule, and
to consider establishing limits on the frequency of such events, to
ensure that emissions during start-up and shutdown events are minimized
to the maximum extent practicable. We also encourage the District to
carefully review the CEMS data required by section 5.4 of Rule 4352
(monitoring provisions), in particular NOX emissions data
during start-up and shutdown periods, to ensure that owners/operators
of solid fuel-fired boilers are in fact operating emission control
systems and minimizing emissions insofar as technologically feasible
during start-up or shutdown as required by Rule 4352, section 5.3.3.
III. EPA Action
For the reasons provided in our proposed rule and above, and
pursuant to section 110(k)(3) of the Act, EPA is fully approving Rule
4352 into the San Joaquin Valley portion of the California SIP. This
final approval of Rule 4352 satisfies California's obligation to
implement RACT under CAA section 182(b)(2) for solid fuel-fired boilers
in the SJV for the 1-hour ozone and 1997 8-hour ozone NAAQS and thereby
terminates all CAA sanctions clocks and Federal Implementation Plan
(FIP) clocks associated with this source category. See 75 FR 60623
(October 1, 2010) (final limited approval and disapproval of Rule
4352); 77 FR 1417 (January 10, 2012) (final partial approval and
disapproval of SJV RACT SIP); and 77 FR 24857 (April 26, 2012) (interim
final determination to stay and defer sanctions).
IV. Statutory and Executive Order Reviews
Under the Clean Air Act, the Administrator is required to approve a
SIP submission that complies with the provisions of the Act and
applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a).
Thus, in reviewing SIP submissions, EPA's role is to approve State
choices, provided that they meet the criteria of the Clean Air Act.
Accordingly, this action merely approves State law as meeting Federal
requirements and does not impose additional requirements beyond those
imposed by State law. For that reason, this action:
Is not a ``significant regulatory action'' subject to
review by the Office of Management and Budget under Executive Order
12866 (58 FR 51735, October 4, 1993);
[[Page 66554]]
Does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
Is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
Does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4);
Does not have Federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
Is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
Is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
Is not subject to requirements of Section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because application of those requirements would be inconsistent
with the Clean Air Act; and
Does not provide EPA with the discretionary authority to
address disproportionate human health or environmental effects with
practical, appropriate, and legally permissible methods under Executive
Order 12898 (59 FR 7629, February 16, 1994).
In addition, this rule does not have tribal implications as
specified by Executive Order 13175 (65 FR 67249, November 9, 2000),
because the SIP is not approved to apply in Indian country located in
the State, and EPA notes that it will not impose substantial direct
costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2).
Under section 307(b)(1) of the Clean Air Act, petitions for
judicial review of this action must be filed in the United States Court
of Appeals for the appropriate circuit by January 7, 2013. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements (see section 307(b)(2)).
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Nitrogen dioxide, Ozone,
Particulate matter, Reporting and recordkeeping requirements.
Dated: September 13, 2012.
Jared Blumenfeld,
Regional Administrator, Region IX.
Part 52, Chapter I, Title 40 of the Code of Federal Regulations is
amended as follows:
PART 52--[AMENDED]
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart F--California
0
2. Section 52.220 is amended by adding paragraphs (c)(411) (i)(B)(4) to
read as follows:
Sec. 52.220 Identification of plan.
* * * * *
(c) * * *
(411) * * *
(i) * * *
(B) * * *
(4) Rule 4352, ``Solid Fuel Fired Boilers, Steam Generators and
Process Heaters,'' amended on December 15, 2011.
* * * * *
[FR Doc. 2012-26779 Filed 11-5-12; 8:45 am]
BILLING CODE 6560-50-P
