[Federal Register Volume 77, Number 215 (Tuesday, November 6, 2012)]
[Rules and Regulations]
[Pages 66548-66554]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-26779]


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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.

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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 http://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 http://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, [email protected].

[[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.
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    \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.
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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
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                                                                                    Emission limit
                                                                  Emission limit   (approximate ppm   Averaging
                            Facility                                (ppm at 7%          at 12%           time
                                                                     O[ihel2])        CO[ihel2])       (hours)
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Essex \2\......................................................               300               285            1
                                                                              155               147           24
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Warren \3\.....................................................               300               285            3
                                                                              205               195           24
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[[Page 66550]]

 
Union \4\......................................................               225               214            3
                                                                              180               171           24
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Gloucester \5\.................................................               350               333            3
                                                                              150               143           24
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Camden \6\.....................................................               300               285            3
                                                                              150               143           24
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    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.
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    \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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    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.
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    \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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    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\
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    \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.
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    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.
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    \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).
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    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