Revisions to the California State Implementation Plan, San Joaquin Valley Unified Air Pollution Control District, 60623-60632 [2010-24686]
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Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[EPA–R09–OAR–2009–0711; FRL–9207–7]
Revisions to the California State
Implementation Plan, San Joaquin
Valley Unified Air Pollution Control
District
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
EPA is finalizing a limited
approval and limited disapproval of
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 December 9, 2009 and
concerns oxides of nitrogen (NOX)
SUMMARY:
emissions from solid fuel fired boilers,
steam generators and process heaters.
Under authority of the Clean Air Act as
amended in 1990 (CAA or the Act), this
action simultaneously approves a local
rule that regulates these emission
sources and directs California to correct
rule deficiencies.
DATES: Effective Date: This rule is
effective on November 1, 2010.
ADDRESSES: EPA has established docket
number EPA–R09–OAR–2009–0711 for
this action. The index to the docket is
available electronically at https://
www.regulations.gov and in hard copy
at EPA Region IX, 75 Hawthorne Street,
San Francisco, California. While all
documents in the docket are listed in
the index, some information may be
publicly available only at the hard copy
location (e.g., copyrighted material), and
some may not be publicly available in
either location (e.g., CBI). To inspect the
60623
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.
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 12/09/09 (74 FR 65042), EPA
proposed a limited approval and limited
disapproval of the following rule that
the SJVUAPCD submitted for
incorporation into the California SIP.
Rule No.
Rule title
Adopted
Submitted
SJVUAPCD .....................................................
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Local agency
4352
Solid Fuel Fired Boilers, Steam Generators
and Process Heaters.
05/18/06
10/05/06
We proposed a limited approval
because we determined that this rule
improves the SIP and is largely
consistent with the relevant CAA
requirements. We simultaneously
proposed a limited disapproval because
some rule provisions do not satisfy the
requirements of section 110 and part D
of the Act. Specifically:
• Section 5.1 of the Rule establishes
the emission limits. We proposed to
find that, with the exception of the NOX
emission limit for biomass fuel-fired
units, SJVUAPCD has not adequately
demonstrated that the NOX emission
limits (i.e., NOX limits for units burning
municipal solid waste or other solid
fuels, such as coal) satisfy Reasonably
Available Control Technology (RACT)
requirements. As explained further in
the TSD for the proposed action, EPA’s
1994 Alternative Control Techniques
Document for NOX emissions from
Industrial/Commercial/Institutional
Boilers (1994 ACT) contains lower
emission ranges for similar boilers.
Source-specific information from the
SJVUAPCD also indicates that emission
limits lower than those in Rule 4352 are
reasonably achievable.
We are now disapproving all of the
NOX emission limits in Rule 4352,
including the limit for biomass fuelfired units, because the District has not
adequately demonstrated that these
limits satisfy RACT. Our proposed
action and our response to comments
below contain more information on the
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basis for this rulemaking and our
evaluation of the submittal.
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 parties.
1. Sarah Jackson, Earthjustice; letter
and e-mail dated and received January
8, 2010.
2. Seyed Sadredin, SJVUAPCD; letter
dated January 8, 2010 and received
January 11, 2010.
The comments and our responses are
summarized below.
Comment #1: Earthjustice supported
EPA’s proposed disapproval of the NOX
emission limits in Rule 4352 for
municipal solid waste-burning and
other solid fuel-burning units and
agreed that the District had failed to
demonstrate that these limits satisfy
CAA RACT requirements.
Response #1: No response needed.
Comment #2: Earthjustice disagreed
with EPA’s proposal to approve the NOX
emission limit in Rule 4352 for biomassfired units as RACT. Earthjustice
provided several arguments in support
of its objection to EPA’s proposal, each
of which we address in separate
comment summaries below.
Response #2: Although we do not
agree with all of the arguments provided
in support of this comment, we have
changed our position based on this
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comment and agree that the District has
failed to provide adequate support for
its conclusion that the NOX emission
limit in Rule 4352 for biomass-fired
units satisfies RACT. We believe our
conclusion on this issue is a logical
outgrowth of our proposed rule.
Comment #2.a: Earthjustice
challenged EPA’s conclusion that the
NOX emission limit of 115 ppm at 3%
O2 for biomass-fired units in Rule 4352
is more stringent than the level
provided in EPA’s 1994 ACT, given that
the 1994 ACT provides achievable NOX
levels ranging from 23 to 155 ppm at 3%
O2 for wood-fired boilers with fluidized
bed combustors. Additionally,
Earthjustice asserted that this range of
NOX emission levels undermines EPA’s
conclusion that the 40 ppm limit in
other districts’ rules is not feasible.
Response #2.a: We acknowledge that
our previous statement that Rule 4352’s
requirements for biomass-fired units are
more stringent than the levels in the
1994 ACT was not entirely accurate. In
this action, we are clarifying that the
NOX emission limit in Rule 4352 for
biomass-fired boilers (115 ppm at 3%
O2) falls in the mid-range of achievable
emission levels provided in the 1994
ACT for this source category (24 ppm to
187 ppm at 3% O2).1
1 The range of emission levels that Earthjustice
identifies (23 to 155 ppm at 3% O2) are presented
in the TSD for our proposed action and are
calculated based on the lb/MMBtu values shown in
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As to the commenter’s assertion that
the range of emission levels in the 1994
ACT undermines EPA’s conclusion that
a NOX limit of 40 ppm is not feasible
for biomass-fired boilers, however, we
disagree. In the TSD for our proposal,
we referenced a 40 ppm NOX emission
limit based on SJVUAPCD’s April 16,
2009 RACT SIP analysis, which
identified four other California districts’
rules that contain emission limits of 40
ppm at 3% O2 for units firing ‘‘nongaseous fuels’’: The South Coast Air
Quality Management District
(SCAQMD) Rule 1146 (as amended
September 5, 2008); Sacramento
Metropolitan Air Quality Management
District (SMAQMD) Rule 411 (as
amended August 23, 2007); Bay Area
Air Quality Management District
(BAAQMD) Regulation 9 Rule 7 (as
amended July 30, 2008) 2; and Ventura
County Air Pollution Control District
(VCAPCD) Rule 74.15 (as amended
November 8, 1994). See SJVUAPCD,
RACT Demonstration for Ozone SIP,
Chapter 4: Rule Analysis, at 4–64 to 4–
67 (April 16, 2009) (‘‘RACT SIP
analysis’’). In response to this comment,
we contacted each of these districts to
determine whether there are any
biomass-fired units subject to the NOX
emission limits in these rules. None of
these districts provided information
indicating that any biomass-fired boiler
has achieved a NOX limit of 40 ppm at
3% O2.
Specifically, we are not aware of any
biomass-fired boiler that is or has been
subject to the 40 ppm NOX emission
limit in VCAPCD Rule 74.15 or
SCAQMD Rule 1146.3 See e-mail dated
June 7, 2010, from Kerby Zozula
(VCAPCD) to Shirley Rivera (EPA
Region 9); e-mail dated August 10, 2010,
from Charles Tupac (SCAQMD) to Idalia
Perez (EPA Region 9). The BAAQMD
has issued one permit for a biomassfired unit at a facility called Standard
Structures, Inc., but we have no
Table 2–6 of the ACT. We note, however, that the
values presented in Appendix B of the ACT (24
ppm to 187 ppm at 3% O2) are more reliable
because they were compiled from numerous
sources including technical reports, EPA
documents, compliance records, and
manufacturers’ literature, while Table 2–6 is simply
a summary of Appendix B.
2 The District’s RACT SIP analysis provides an
incorrect adoption date of November 7, 2007, for
this regulation. The version of Regulation 9 Rule 7
that is currently effective in the Bay Area was last
amended on July 30, 2008. See e-mail dated August
11, 2010, from Dan Belik (BAAQMD) to Idalia Perez
(EPA Region 9).
3 Note that SCAQMD Rule 1146 applies only to
‘‘combustion equipment fired with liquid and/or
gaseous (including landfill and digester gas) and/or
solid fossil fuel. * * *’’ Rule 1146 (as amended
September 5, 2008), sections (a), (b)(4), and (b)(12)
(emphasis added). As such, this rule does not apply
to biomass-fired units.
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information indicating that this unit is
achieving emission levels as low as 40
ppm at 3% O2. See e-mail dated June 7,
2010, from Barry Young (BAAQMD) to
Shaheerah Kelly (EPA Region 9);
Facsimile Transmittal dated June 8,
2010, attaching Evaluation Report and
Engineering Evaluation for Standard
Structures, Inc., from Art Valla
(BAAQMD) to S. Kelly (EPA Region 9);
e-mail dated June 8, 2010, from Charles
McClure (BAAQMD) to Idalia Perez
(EPA Region 9). In the Sacramento
Metro area, one source has operated a
biomass-fired boiler in the past 20 years,
but that source was subject to an earlier
version of SMAQMD’s Rule 411
containing significantly higher NOX
emission limits until it ceased operating
in March 1996. See Response #2.b,
below. We have no information
indicating that a NOX emission level of
40 ppm at 3% O2 is generally achievable
for biomass-fired units, and the
commenter has not identified any such
information.
ACT documents describe available
control techniques and their cost
effectiveness but do not define
presumptive RACT levels as the CTGs
do. The 1994 ACT (at Appendix B,
pages B20–B21) identifies NOX emission
levels for biomass-fueled boilers ranging
from 24 ppm to 187 ppm at 3% O2,
based on the use of SNCR controls with
ammonia or urea injection. This wide
range of emission levels reflects the
broad technical diversity among the
types of boilers that fire biomass as fuel,
including stokers, circulating fluidized
bed boilers and bubbling fluidized bed
boilers. It also reflects the variety of
fuels that the term ‘‘biomass’’ covers,
including various kinds of plant
materials, wood materials and
agricultural wastes.
Given the broad technical diversity of
existing biomass-fired boilers and their
varying fuel compositions, the NOX
emission levels achievable for one
operation (e.g., 24 ppm) may not
necessarily be achievable for others.
Even where boiler type, control
technology, and fuel type are the same,
achievable 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 Appendix B (at page B–20),
showing achievable NOX emission
levels ranging from 25 to 160 ppm at 3%
O2 for wood-fired stoker boilers using
SNCR with ammonia injection.
Thus, the range of emission levels for
biomass-fired boilers in the 1994 ACT
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does not necessarily establish that a
NOX emission level of 40 ppm at 3% O2
is reasonably achievable for such boilers
generally. It does, however, warrant a
more detailed evaluation of the biomassfired units in the SJV area, as discussed
further below.
Comment #2.b: Earthjustice asserted
that the District’s claim that there are no
solid-fuel fired units in the Sacramento
area that currently meet the 70 ppm
limit in the SMAQMD’s Rule 411 is
‘‘misleading and irrelevant to answering
the feasibility question.’’ Earthjustice
stated that according to CARB and
SMAQMD staff, ‘‘there was, in fact, at
least one source in the Sacramento
Metropolitan air district that burned
biomass as a fuel, and that source met
the emission limit of this rule until it
decided to switch to landfill gas as a
fuel source.’’ In support of these
assertions, Earthjustice referenced a
letter to EPA dated June 29, 2007, in
which it had made these same
assertions. Earthjustice concluded that
the SMAQMD’s NOX limit of 70 ppm for
biomass-fired units in Rule 411 ‘‘has
been demonstrated as feasible,’’ and that
‘‘EPA must conduct its own review of
the feasibility of Sacramento’s limit,’’
rather than ‘‘rely[] on the District’s
misleading claims.’’
Response #2.b: First, the difference
between the limit in SMAQMD’s Rule
411 and the limit in SJVUAPCD’s Rule
4352 is not as significant as the
commenter contends. The current 70
ppm NOX emission limit in Rule 411 is
expressed in parts per million corrected
to 12% carbon dioxide (ppm at 12%
CO2), which equates to approximately
100 ppm at 3% O2. See Rule 411 (as
amended August 23, 2007), section
303.1.4 As such, the appropriate
comparison is between a limit of 100
ppm at 3% O2 (not 70 ppm at 3% O2)
in SMAQMD’s Rule 411 and a limit of
115 ppm at 3% O2 in SJVUAPCD’s Rule
4352.
Second, to the extent the commenter
intended to argue that an emission level
of 70 ppm at 3% O2 has been achieved
in the Sacramento area, this argument is
unsupported. In both the comments
submitted for this rulemaking and the
June 29, 2007 comment letter,
Earthjustice refers to, without
identifying, a source in the Sacramento
4 We have converted the emission limit into its
approximate equivalent at 3% O2 to allow for more
direct comparison to the emission limits in
SJVUAPCD Rule 4352 and the other rules we have
evaluated, which are also generally expressed in
ppm at 3% O2. Briefly, using equations available in
EPA Method 3B along with F Factors obtained from
Method 19, we calculated the O2 that should be
obtained during combustion if there is 12% CO2 in
the flue gas and corrected the NO2 concentration
obtained to 3% O2.
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Metropolitan area that at some point
burned biomass and that met the
emission limits in Rule 411 before it
decided to switch to landfill gas as a
fuel source. It appears that Earthjustice
is referring to an almond processing
facility called Blue Diamond, which we
understand was the only source in the
Sacramento Metropolitan area to have
operated a biomass-fired boiler in the
past 20 years. See e-mail dated May 13,
2010, from Bruce Nixon (SMAQMD) to
Idalia Perez (EPA Region 9).
According to SMAQMD staff, the Blue
Diamond facility ceased operations in
March 1996. See e-mail dated February
8, 2010, from Bruce Nixon (SMAQMD)
to Idalia Perez (EPA Region 9). Prior to
this time, the facility was subject to Rule
411 as adopted on February 2, 1995,
which contained a limit for NOX
emissions from biomass-fired boilers of
110 ppm at 12% CO2, or approximately
156 ppm at 3% O2.5 See Section 303.1,
Rule 411 (as adopted February 2, 1995).
Notably, this limit was significantly
higher than the NOX limit for biomassfired boilers in SJVUAPCD’s current
Rule 4352 (115 ppm at 3% O2).
Assuming Blue Diamond’s biomassfired boiler was in compliance with the
applicable limit in the 1995 version of
Rule 411, i.e., approximately 156 ppm at
3% O2, this does not demonstrate that
a NOX emission limit of 70 ppm at 3%
O2 is achievable.6
Comment #2.c: Earthjustice asserted
that ‘‘the evidence EPA has put in the
record suggests that much lower limits
for biomass-fired units are not only
reasonably available but, in fact, are
already being achieved by just about
every facility in the Valley.’’ Earthjustice
provided an excerpt from a document
EPA had identified in the TSD and
asserted that according to this
document, which contained information
about solid fuel-fired units and
associated permit limits in the SJV area,
‘‘[a]ll but one biomass-fired unit is
already meeting the more stringent
SMAQMD limit of 70 ppm at 12% CO2
(∼100 ppm at 3% O2) and most are
permitted well below this limit * * *.’’
Earthjustice also stated that the
permitted levels do not necessarily
reflect the level of emissions from these
facilities, and that EPA should consider
source test data for these facilities ‘‘to
aid in the determination of what is
reasonably achievable.’’
Response #2.c: The commenter
correctly notes that biomass-fired
boilers in the SJV area are achieving
NOX emission levels below the levels
required by Rule 4352. In fact, based on
60625
information we have gathered in
response to these comments, it appears
that all of the existing biomass-fired
boilers in the SJV area that are subject
to Rule 4352 are achieving emission
levels significantly below 115 ppm at
3% O2. In the absence of information
indicating that these lower emission
levels are not reasonably achievable in
the SJV area, we conclude that the
District has not adequately
demonstrated that the NOX limit in Rule
4352 (115 ppm at 3% O2) represents
RACT.
Ten biomass-fired boilers in the SJV
area are currently subject to the NOX
emission limit in Rule 4352. We have
reviewed source test data for four of
these units and found that each unit is
achieving actual NOX emission levels
between 44 and 79 ppm at 3% O2. We
also evaluated source test data for two
biomass-fired units in Placer County
and one unit in Yolo County, California,
which indicate actual NOX emission
levels between 45 and 103 ppm at 3%
O2. See Table 1. These source test
results indicate that biomass-fired units
both within the SJV area and elsewhere
in California are currently achieving
NOX emission levels significantly below
115 ppm at 3% O2.
TABLE 1—NOX SOURCE TEST DATA FOR SELECTED BOILERS FIRING BIOMASS IN CA
Facility
Air
district
Madera Power, LLC ...................................
Covanta Delano, Inc ..................................
SJVUAPCD .........................
SJVUAPCD .........................
2009
2009
44.3 ppm at 3% O2.
Unit 1—0.07 lbs/MMBtu (∼54 ppm at 3% O2)
Sierra Power Corporation ..........................
Sierra Pacific Industries, Lincoln ................
SJVUAPCD .........................
Placer County APCD
(PCAPCD).
PCAPCD .............................
Yolo-Solano APCD ..............
2009
2009
Unit 2—0.063 lbs/MMBtu (∼49 ppm at 3% O2).
78.7 ppm at 3% O2.
51.2 ppm at 12% CO2 (∼103 ppm at 3% O2).
2009
2010
37.6 ppm at 12% CO2 (∼76 ppm at 3% O2)
45.34 ppm at 3% O2.
Rio Bravo Rocklin ......................................
Woodland Biomass Power, LTD ................
The remaining six biomass-fired units
in the SJV area are subject to NOX
Test
year
Emission
permit limits ranging from 62 to 83 ppm
at 3% O2. See Table 2.
TABLE 2—NOX PERMIT LIMITS FOR BIOMASS FACILITIES IN SJVUAPCD
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Permit No.
Size of unit
C–825 .........................................................
C–1820 .......................................................
N–1026 .......................................................
N–4607 .......................................................
S–285 .........................................................
C–6923 .......................................................
317 MMBtu/hr ...........................................
352 MMBtu/hr ...........................................
259 MMBtu/hr ...........................................
185 MMBtu/hr ...........................................
11.5 MW ...................................................
185 MMBtu/hr ...........................................
5 See fn. 4, supra, for an explanation of the
conversion methodology from ppm at 12% CO2 to
ppm at 3% O2.
6 The 1995 version of SMAQMD Rule 411 also
contained a lower limit of 70 ppm at 12% CO2
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NOX Limit
27.8
0.08
27.2
0.08
0.09
0.08
lb/hr (∼83 ppm at 3% O2).
lb/MMBTU (∼62 ppm at 3% O2).
lb/hr (∼83 ppm at 3% O2).
lb/MMBtu (∼83 ppm at 3% O2).
lb/MMBtu (∼70 ppm at 3% O2).
lb/MMBtu (∼62 ppm at 3% O2).
(∼100 ppm at 3% O2) which took effect May 31,
1997. See Section 306.1, Rule 411 (as adopted
February 2, 1995). On October 27, 2005, SMAQMD
revised Rule 411 by eliminating the NOX emission
limit of 110 ppm at 12% CO2 (∼156 ppm at 3% O2)
but retaining the NOX emission limit of 70 ppm at
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12% CO2 (∼100 ppm at 3% O2). At that time,
however, no facility in the SMAQMD area operated
a biomass-fired boiler subject to this limit. See email dated May 13, 2010, from Bruce Nixon
(SMAQMD) to Idalia Perez (EPA Region 9).
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We note that each of the biomass-fired
units located in the SJV area that is
subject to Rule 4352 is also subject to a
NOX emission limit representing the
Best Available Control Technology
(BACT) 7 in its District-issued permit,
and that the BACT standard often
requires a more stringent control level
than RACT. BACT requirements are
established prior to construction on an
emissions-unit by emissions-unit basis
through the District’s permitting
process. See SJVUAPCD Rule 2201 (as
amended December 18, 2008), sections
2.0 and 4.1. RACT, on the other hand,
applies to existing sources and is
defined as the lowest emission
limitation that a particular source is
capable of meeting ‘‘by the application
of control technology that is reasonably
available considering technological and
economic feasibility.’’ 44 FR 53762
(September 17, 1979). EPA historically
has recommended source-category-wide
presumptive RACT limits based on
capabilities that are general to an
industry, although RACT decisions may
also be made on a case-by-case basis.
See 57 FR 55620 at 55624 (November
25, 1992) (‘‘NOx Supplement to General
Preamble’’). Similarly, a RACT
prohibitory rule may establish emission
limits based on capabilities that are
general to the covered source category,
rather than based on source-specific
analyses.
Given the stringency and sourcespecific nature of the BACT
requirement, a BACT limit established
in a pre-construction permit does not
necessarily represent RACT for the
source category in general. This does
not mean, however, that the two
standards may never result in similar
emission levels based on the same or
similar controls. In some cases, RACT
may even result in more stringent
control levels than a source-specific
control standard like BACT or the
Lowest Achievable Emission Rate
(LAER). See Memorandum dated March
30, 1994, from Tom Helms, Chief,
Ozone/Carbon Monoxide Programs
Branch, to Region V Air Enforcement
Branch, ‘‘Nitrogen Oxides (NOx)
Questions from Ohio EPA’’;
Memorandum dated December 1, 1988,
from Gerald Emison, Director, Office of
Air Quality Planning and Standards, to
William Spratlin, Director, Air and
Toxics Division, Region VII, ‘‘RACT
Requirements in Ozone Nonattainment
7 SJVUAPCD Rule 2201 (New and Modified
Stationary Source Review Rule) defines BACT, in
relevant part, as ‘‘the most stringent emission
limitation or control technique * * * achieved in
practice for such category and class of source
* * *.’’ SJVUAPCD Rule 2201 (as amended
December 18, 2008), section 3.9.
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Areas’’ (noting that LAER is determined
at the time of permit issuance).
Fundamentally, each of these standards
requires a specific evaluation of the
types of controls that are available to the
source—or, in the case of a prohibitory
rule, to the covered sources in the
relevant area—taking into account,
where appropriate, technological and
economic feasibility.
In this case, every existing biomassfired boiler in the SJV area that is
subject to this rule is already achieving
lower NOX levels based on BACT
controls. Absent information indicating
that these controls may not be
technologically or economically feasible
for sources in the area, we have no basis
for concluding that these emissions
levels are not also reasonably available
and appropriate as RACT in the SJV
area.
Comment #2.d: Earthjustice asserted
that, in addition to identifying the
control technology that can achieve a
RACT level of control, EPA must
provide an ‘‘analysis that identifies the
appropriately stringent emission limit
within the range of control achievable
by this technology.’’
Response #2.d: We agree that a RACT
analysis generally should identify not
only reasonably available control
technologies but also appropriately
stringent emission limitations based on
these controls. We are disapproving all
of the NOX emission limits in Rule 4352
because the District has not adequately
demonstrated that these limits satisfy
RACT.
Comment #3: Earthjustice asserted
that EPA should evaluate the source test
data available to it in evaluating Rule
4352, rather than ‘‘relying strictly on
outdated technology reviews and
ignoring the fact that SNCR and other
similar technologies have radically
improved over the last fifteen
years* * *.’’ Earthjustice provided a list
of California biomass facilities at https://
www.calbiomass.org/county.htm and
stated that this could be a good starting
point for EPA’s investigation. Finally,
Earthjustice reiterated its assertions that
‘‘[t]he 70 ppm limit for biomass-fired
units in the Sacramento rule has been
proven, not just by the source that used
to operate in Sacramento, but also by
the many biomass-burning facilities in
the Valley that are already meeting that
standard,’’ and that EPA should
disapprove all of the limits in Rule 4352
as RACT.
Response #3: Although we do not
agree with the commenter’s assertion
that a NOX emission level of 70 ppm at
3% O2 has been achieved by a biomassfired unit in the Sacramento area, our
review of source test data and permits
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for biomass-fired units in the SJV area
indicate that emission levels between 44
and 83 ppm at 3% O2 are currently
being achieved. See Responses #2.b. and
#2.c above. We are disapproving all of
the NOX limits in Rule 4352, including
the limit for biomass-fired units,
because the District has not
demonstrated that these limits satisfy
RACT.
Comment #4: Earthjustice requested
confirmation that any alternate sourcespecific RACT emission limit requested
by the owner or operator of a source
under section 5.4 of Rule 4352 will be
approved by EPA only after notice and
comment rulemaking.
Response #4: We understand that
section 5.4 requires the District to
provide an opportunity for public
comment on any alternate sourcespecific RACT limit that it seeks to
approve through issuance of a Permit to
Operate under Rule 2520 (as amended
June 21, 2001), subject to EPA review,
as explained further below. Before we
approve any alternate limit under this
provision, EPA intends to ensure that
the District has satisfied the procedural
requirements of Rule 2520 and that the
Permit to Operate ensures compliance
with applicable CAA requirements,
including RACT, consistent with the
requirements of CAA title V.
Specifically, section 5.4 of Rule 4352
states that, for a unit operating at or
below 50 percent of the rated heat input
(i.e., the heat input capacity specified on
the nameplate of the unit), ‘‘the APCO,
ARB, and EPA may approve an
increased emission limit if the owner/
operator submits an application for a
Permit to Operate, which provides a
justification for the requested limit.’’
Upon approval by the APCO, ARB, and
EPA, the source owner/operator may
comply with this higher limit in lieu of
the applicable limits in Table 1 of the
rule.
Importantly, the rule allows the
District, ARB, and EPA to approve an
alternate limit only after the owner/
operator submits an application for a
Permit to Operate (PTO) that provides a
justification for the requested limit. Any
source in the SJV area that is subject to
Rule 4352 based on its potential to emit
at least 10 tons per year (tpy) of NOX is
also subject to the District’s EPAapproved title V permit program
because it is a ‘‘major source.’’ See
SJVUAPCD Rule 2520, ‘‘Federally
Mandated Operating Permits’’ (as
amended June 21, 2001), sections 2.3
and 3.19 (applying program to any
‘‘major source’’ as defined in SJVUAPCD
Rule 2201); SJVUAPCD Rule 2201, ‘‘New
and Modified Stationary Source Review
Rule’’ (as amended December 18, 2008),
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section 3.23 (defining ‘‘major source’’ to
include any source that has the
potential to emit at least 20,000 pounds
per year (10 tpy) of NOX). Thus, any
source owner/operator seeking to obtain
an alternate limit under Rule 4352 must
submit an application under Rule 2520
either for an initial PTO (if it is a new
source) or for a ‘‘significant permit
modification’’ to its existing PTO. See
Rule 2520, sections 5.3.1, 3.29, and
3.20.3. Both initial PTOs and significant
modifications to existing PTOs are
subject to a 30-day public comment
period and a 45-day EPA review period,
during which EPA may object to the
permit if it does not meet applicable
CAA requirements. See Rule 2520,
sections 11.3 and 11.7. Furthermore, if
EPA does not object in writing to the
District’s preliminary decision during
the 45-day review period, any person
may petition EPA to review the permit.
See Rule 2520, section 11.3.7.
These procedures ensure that the
public will have an opportunity not
only to comment on any alternate limit
proposed by the District under section
5.4 of Rule 4352, but also to submit a
title V petition to EPA where EPA does
not object to a proposed permit
containing such an alternate limit. Prior
to approving any alternate limit
requested under section 5.4 of Rule
4352, EPA intends to ensure that the
District has satisfied these procedural
requirements under Rule 2520 and that
the PTO, including the alternate limit,
satisfies CAA RACT requirements.
Comment #5: SJVUAPCD agreed with
EPA’s proposal to approve the NOX
limit in Rule 4352 for biomass-fired
units and stated that all solid fuel-fired
units in the area are equipped with
SNCR or SCR controls, which are more
effective than SNCR.
Response #5: As explained above,
based on the comments we received, we
have determined that the District has
not adequately demonstrated that the
NOX limit in Rule 4352 for biomassfired units satisfies RACT. See
Responses #2.c and 2.d.
Comment #6: SJVUAPCD disagreed
with EPA’s proposal to disapprove the
limit of 115 ppm at 3% O2 in Rule 4352
for solid fuels other than municipal
solid waste and biomass (i.e., coal,
petroleum coke, and/or tire-derived
fuels). The District provided several
arguments in support of its objection to
EPA’s proposal, each of which we
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address in separate comment summaries
below.
Response #6: For the reasons
discussed below, we have concluded
that the District has not adequately
demonstrated that the existing limit in
Rule 4352 for units firing solid fuels
other than municipal solid waste and
biomass (i.e., coal, petroleum coke, and/
or tire-derived fuels) (115 ppm at 3%
O2) satisfies RACT.
Comment #6.a: The District stated
that six facilities in the SJV area operate
seven boilers that are permitted to fire
coal, petroleum coke, and/or tirederived fuels, and that all of these
boilers have installed SNCR controls,
which represent BACT for this source
category.
Response #6.a: See Responses #2.c
above and 8.d below.
Comment #6.b: The District asserted
that EPA’s reliance on the emission
levels for coal-fired units in the 1994
ACT (29–65 ppm at 3% O2 or 0.04 to
0.09 lb/MMBtu) as part of its RACT
evaluation was not appropriate because
these emission levels apply only to
fluidized bed combustor (FBC) units
fired exclusively on coal. SJVUAPCD
asserted that coal has less fuel-bound
nitrogen compared to petroleum coke
and, therefore, results in less NOX
formation during combustion even with
the same emission control technology.
Response #6.b: Although we agree
with the commenter that coal has less
fuel-bound nitrogen than petroleum
coke, this does not provide a basis for
approving the current limit in Rule 4352
as RACT. Likewise, an argument that
the emission levels for coal-fired units
provided in the 1994 ACT (29–65 ppm
at 3% O2 or 0.04 to 0.09 lb/MMBtu) do
not reflect reasonably available controls
for boilers firing combinations of coal,
petroleum coke, and tire-derived fuels,
also does not demonstrate that the limit
in Rule 4352 for these units (115 ppm
at 3% O2) satisfies RACT.
In determining the level of control
that is reasonably available to sources in
the SJV area, the District must consider
new information that has become
available, including information about
control levels currently achieved by
similar sources. We note that the range
provided in the 1994 ACT reflects
control technologies from over a decade
ago, and that RACT may change over
time as new technology becomes
available or the cost of existing
technologies decreases. As discussed in
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60627
the TSD for our proposed rule, it
appears that boilers burning coal,
petroleum coke, and/or tire-derived
fuels in the SJV area are generally
achieving NOX emission levels
significantly below 115 ppm at 3% O2,
and the 1994 ACT indicates that coalfired boilers with SNCR and ammonia
injection generally can achieve NOX
emission levels below 115 ppm at 3%
O2. See TSD at 6; 1994 ACT at B–19. We
also note that use of cleaner-burning
fuels, work practice standards, or other
operation and maintenance
requirements may be considered as part
of a RACT analysis. See Memorandum
dated July 30, 1993, from Michael H.
Shapiro, Acting Assistant Administrator
for Air and Radiation, to Air Division
Directors, Regions I through X, ‘‘Fuel
Switching to Meet the Reasonably
Available Control Technology (RACT)
Requirements for Nitrogen Oxides
(NOX)’’; Memorandum dated November
7, 1996, from Sally Shaver, Director, Air
Quality Strategies & Standards Division,
to Air Division Directors, Regions I
through X, ‘‘Approval Options for
Generic RACT Rules Submitted to Meet
the non-CTG VOC RACT Requirement
and Certain NOX RACT Requirements.’’
The District has provided no
technological or economic information
to support a conclusion that these lower
emission levels are not reasonably
achievable in the SJV area.
Comment #6.c: SJVUAPCD asserted
that it had reviewed EPA’s RACT/
BACT/LAER Clearinghouse (RBLC) and
had not identified any boilers in the
nation that fire a blend of coal/coke/tirederived fuel and that meet the emission
range in the 1994 ACT. The District
asserted that EPA should not have
referenced this emission range as part of
its RACT evaluation, and that the
current limit in Rule 4352 should be
considered RACT for boilers firing coal,
petroleum coke, and tire-derived fuels.
Response #6.c: We disagree. As
shown in Table 3 below, the RBLC
identifies several boiler units firing
combinations of coal, petroleum coke,
and/or tire-derived fuels that achieve
emission levels in the range provided in
the 1994 ACT (29–65 ppm at 3% O2 or
0.04–0.09 lb/MMBtu). The District has
provided no technological or economic
information to support a conclusion that
these lower emission levels are not
reasonably achievable in the SJV area.
See Response #6.b.
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TABLE 3—RACT/BACT/LAER CLEARINGHOUSE NOX EMISSION LEVELS FOR BOILERS FIRING PETROLEUM COKE, COAL,
AND/OR TIRE-DERIVED FUELS
RLBC ID
Year
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LA–0202 ............
LA–0223 ............
MI–0258 ............
MS–0075 ...........
WI–0122 ............
2006
2008
2001
2003
2001
Fuel
Control Technology
Pet Coke/Coal ....................................
Pet Coke .............................................
Coal/Tire/Wood ...................................
Wood/Tires .........................................
Pet Coke .............................................
SNCR ................................................................................
SNCR ................................................................................
SCR ...................................................................................
LNB, overfire air, good combustion practices ..................
SNCR ................................................................................
Comment #7: SJVUAPCD asserted that
‘‘EPA has consistently interpreted the
Clean Air Act provisions to require only
those feasible measures necessary for
expeditious attainment,’’ and that ‘‘if a
feasible measure alone or in
combination with other measures,
cannot expedite attainment by at least
one year then it is not considered to be
reasonably available.’’ The District
asserted that no additional emission
reduction would be achieved by
reducing the limits in Rule 4352 to the
NOX limits in the sources’ permits
‘‘because the reduction from affected
boilers has already occurred.’’ Therefore,
the District argued, ‘‘such action is not
necessary for the District’s efforts for
expeditious attainment of the ozone and
PM2.5 standards.’’
Response #7: We disagree. Although
EPA has long interpreted the RACT
requirement in section 172(c)(1) of the
Act, known as ‘‘subpart 1 RACT,’’ as
requiring only those control measures
that will contribute to timely attainment
and meet reasonable further progress
(RFP) requirements (see 40 CFR
51.912(c) and 70 FR 71612 at 71653
(November 29, 2005)), this is not true for
the more specific RACT requirements of
CAA section 182(b)(2), known as
‘‘subpart 2 RACT.’’ Section 182 of the
Act requires, for any ozone
nonattainment area classified as
moderate or above, a SIP revision to
require RACT for all major stationary
sources of NOX that are located in the
area, among other sources. CAA
182(b)(2)(C), 182(f); 40 CFR 51.912(a).
These control measures are mandated
whether or not they advance attainment
or contribute to RFP. Because the SJV
area is designated and classified as an
extreme ozone nonattainment area (40
CFR 81.305),8 the SIP for the area must
meet subpart 2 RACT requirements for
all major NOX sources.
In addition, it is not clear that no
additional emission reduction would be
8 Effective June 4, 2010, the SJV area was
reclassified from ‘‘serious’’ to ‘‘extreme’’
nonattainment for the 8-hour ozone NAAQS. See 75
FR 24409 (May 5, 2010). The SJV area also remains
classified as ‘‘extreme’’ nonattainment for the 1-hour
ozone NAAQS. 40 CFR 81.305.
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achieved by reducing the limits in Rule
4352 for units burning coal, petroleum
coke, and/or tire-derived fuels. As
explained above in Responses #6.b and
#6.c, both the 1994 ACT and EPA’s
RBLC provide NOX emission levels
ranging from 29 to 65 ppm at 3% O2
(0.04–0.09 lb/MMBtu) for units burning
coal, petroleum coke, and/or tirederived fuels. Information that the
District submitted to us indicates that
the permit limits for units burning coal,
petroleum coke, and/or tire-derived
fuels in the SJV area range between 28
and 146.7 ppm at 3% O2. See
Attachment #6 to TSD. Several of these
permit limits exceed the NOX emission
levels provided in the 1994 ACT and the
RBLC for comparable units, one of these
(146.7 ppm at 3% O2) by a substantial
margin. Absent technical or economic
information indicating that these units
cannot reasonably achieve the emission
levels identified in the 1994 ACT and
the RBLC, we conclude that the District
has not adequately demonstrated that
the NOX limit in Rule 4352 (115 ppm at
3% O2) represents RACT.
Moreover, the permit limits that the
District references are not approved into
the SIP. We have no basis for evaluating
permit limits not submitted for SIP
approval to support a RACT
determination under section 182(b)(2) of
the CAA. See Response #8.d below.
Comment #8: SJVUAPCD disagreed
with EPA’s proposal to disapprove the
limit of 200 ppm at 12% CO2 in Rule
4352 for units firing municipal solid
waste (MSW). The District provided
several arguments in support of its
objection to EPA’s proposal, each of
which we address in separate comment
summaries below.
Response #8: For the reasons
discussed below, we have concluded
that the District has not adequately
demonstrated that the existing limit in
Rule 4352 for units firing MSW (200
ppm at 12% CO2) satisfies RACT.
Comment #8.a: SJVUAPCD stated that
there is one facility in the District that
operates two boilers firing MSW, and
that both of these boilers have SNCR
controls, which represent BACT. The
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Limit
(lb/MMBtu)
0.07
0.07
0.06
0.0310
0.07
District asserted that BACT is more
stringent than RACT.
Response #8.a: See Responses #2.c
above and 8.d below.
Comment #8.b: SJVUAPCD asserted
that the emission levels for MSW-fired
units in the 1994 ACT (52–232 ppm at
3% O2), which EPA had referenced in
the TSD for the proposed rule, are based
on ‘‘short term test data’’ which are not
necessarily representative of typical
day-to-day operations.
Response #8.b: The comment implies
that the emission levels for MSW-fired
units in the 1994 ACT are not
appropriate for consideration as RACT
because they are based on emissions
data that may not represent typical
operations. This argument is
unsupported. ACT documents describe
available control techniques and their
cost effectiveness, although they do not
define presumptive RACT, and it is
EPA’s long-standing position that States
may consider information available in
ACTs to identify available control
options as part of a RACT analysis. See,
e.g., 70 FR 71612 at 71654–55
(November 29, 2005) (preamble to final
Phase II ozone implementation rule).
The emission levels in the 1994 ACT are
based on numerous sources of
information in addition to compliance
records, including technical reports,
EPA documents, and manufacturers’
literature. See footnote 1 above and
1994 ACT at B–1. The District’s
comment does not support an argument
that the emission levels in the 1994 ACT
are not appropriate for consideration in
a RACT analysis.
The information provided in the 1994
ACT is, however, over a decade old and
may not provide an accurate picture of
current control options. It is possible
that the controls identified in the 1994
ACT are now more cost-effective or that
new control options have since become
available. The District is required to
consider not only the information in the
1994 ACT but also any new information
that has become available in
determining the control obligation and
emissions limitation that is consistent
with RACT. 70 FR 71612 at 71655.
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Comment #8.c: SJVUAPCD asserted
that the MSW-fired boilers in the SJV
area ‘‘operate an SNCR system whereby
the amount of ammonia injected into
the flue gas is closely controlled to
prevent excessive ammonia slip,’’ and
that any increase in ammonia injection
above certain established levels for
purposes of achieving additional NOX
reductions would potentially increase
PM10 emissions above allowable permit
limits.
Response #8.c: SJVUAPCD has not
provided information to substantiate
this assertion. Recent source test data
for the Covanta Stanislaus facility,
which operates the only two permitted
MSW-fired units in the SJV area, shows
average total particulate emissions of
7.58 × 10¥3 gr/DSCF for Unit 1 and 7.08
× 10¥3 gr/DSCF for Unit 2. See letter
dated August 20, 2009, from Richard L.
Wright, Air Quality Inspector,
SJUAPCD, to Terry Coble, Covanta
Stanislaus, Inc., enclosing ‘‘Summary of
Source Test Results,’’ Tables 2.1 and 2.3.
These emission levels are well below
the facility’s permit limit for total
particulate emissions from each unit,
which is 0.0275 gr/DSCF. Id.
Additionally, the same source test data
indicates average ammonia
concentrations in the flue gas of 1.54
ppm for Unit 1 and 3.47 ppm for Unit
2, both of which are well below the
ammonia limit of 50 ppm for each unit.
Id. Thus, it appears the Covanta
Stanislaus facility could substantially
increase the amount of ammonia
injection for purposes of achieving
additional NOX reductions without
violating permit requirements. The
District’s argument is unclear and, in
any case, does not support a conclusion
that the NOX limit in Rule 4352 for
MSW-fired units satisfies RACT.
Comment #8.d: SJVUAPCD asserted
that although the rule limit for MSWfired boilers is 200 ppm at 12% CO2, the
existing permit limit of 165 ppm at 12%
CO2 ‘‘is within the range of limit[s]
recommended in the ACT for this boiler
type, and therefore the units meet
RACT.’’
Response #8.d: It appears the District
intended to argue that EPA should
evaluate the permit limits for MSWfired boilers (165 ppm at 12% CO2),
rather than the limit in Rule 4352 (200
ppm at 12% CO2), for RACT purposes.
This would be appropriate if SJVUAPCD
were to adopt and submit the relevant
permit limits for approval into the
SJVUAPCD portion of the California
SIP. In this action, however, we are
evaluating Rule 4352 for approval into
the SIP, not the permit limits that the
District references. We have no basis for
evaluating permit limits not submitted
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for SIP approval to support a RACT
determination under section 182(b)(2) of
the CAA.
As discussed in the TSD for our
proposed action, the NOX emission limit
in Rule 4352 for MSW-fired units is 200
ppm at 12% CO2, which equates to
roughly 266 ppm at 3% O2. The 1994
ACT provides NOX emission levels for
MSW-fired units ranging between 44
and 210 ppm at 3% O2,9 based on the
use of SNCR with ammonia or urea
injection. See 1994 ACT at Appendix B,
pg. B–21. The District has provided no
technological or economic information
to support a conclusion that these lower
emission levels are not reasonably
achievable in the SJV area.
Comment #8.e: SJVUAPCD asserted
that EPA’s RBLC does not indicate any
BACT emission level for boilers firing
MSW fuels. The District stated that the
RBLC does identify a source called
Mahoning Renewable Energy, which
operates two boilers that burn refusederived fuel (RDF) and are equipped
with Regenerative Selective Catalytic
Reduction (RSCR). Citing EPA’s 1994
ACT, the District asserted that ‘‘unlike
MSW and industrial solid waste fuels,
which are burned in the same form as
they are received at the boiler site, RDF
is fuel processed from general solid
waste’’ and is generated by sorting and
processing such solid waste. SJVUAPCD
concluded by asserting that because the
Mahoning facility’s boilers ‘‘use RSCR
and are fired on RDF, RSCR cannot be
considered RACT for boilers fired on
MSW fuel.’’
Response #8.e: The District’s assertion
that the RBLC does not contain BACT
emission levels for MSW fuel-fired
boilers is not correct (although we note
that these entries are difficult to locate
as they are not categorized under fuel
combustion (process type 10), as are
boilers burning other fuels). The RBLC
includes MSW fuel-fired boiler units
under the process type 21.400, Waste
Combustion Processes. For example, the
Lee County Waste-To-Energy Facility in
Florida (RBLC ID FL–0258) operates two
mass-burn municipal waste combustion
units that are equipped with SNCR and
subject to an emission limit of 150 ppm
at 7% O2 (approximately 143 ppm at
12% CO2). Another facility identified in
the RBLC is the Resource Recovery
Facility in Virginia (RBLC ID VA–0277),
which operates two MSW-fired units
subject to an emission limit of 160 ppm
9 The emission levels that the District identifies
(52 to 232 ppm at 3% O2) are presented in the TSD
for our proposed action and are calculated based on
the lb/MMBtu values shown in Table 2–6 of the
ACT. We note that the values presented in
Appendix B of the Act (44 to 210 ppm at 3% O2)
are more reliable. See fn. 1 above.
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60629
at 7% O2 (approximately 152 ppm at
12% CO2).10
Additionally, we have examined
source test data for other MSW-fired
units to determine what emission limits
have been achieved in practice. The
Montenay Pacific Power Corporation
has a facility in Long Beach, California
with three MSW fuel-fired units, each of
which appears to have NOX emission
levels between 64 and 104 ppm at 7%
O2 (approximately 61–99 ppm at 12%
CO2). Eco/Pittsfield, LLC in Pittsfield,
Massachusetts operates three MSW
combustors that appear to have average
NOX emissions of 70.4 ppm at 7% O2
(approximately 67 ppm at 12% CO2).
These emission levels are significantly
lower than 200 ppm at 12% CO2.
It appears the District believes that
important distinctions between the use
of RDF and MSW as fuel justify the NOX
emission limit in Rule 4352 as RACT,
but this argument is not supported. The
District has provided no technical or
economic information to support an
argument that the control levels
currently achieved by MSW fuel-fired
units elsewhere are not reasonably
available in the SJV area.
Comment #8.f: SJVUAPCD stated that
the permits for boilers firing MSW have
stringent limits for numerous hazardous
air pollutants, because the facility is
subject to the Federal NESHAP for
municipal solid waste combustors. The
District asserted that ‘‘[t]here is no more
emission reduction that would result
with the current SNCR system, even if
the rule limit is lowered to the
permitted level since the emission has
already been reduced because of more
stringent operating permit emission
limits.’’
Response #8.f: First, to the extent the
District intended to argue that NESHAP
requirements provide a basis for
approving the NOX limits in 4352 as
RACT, this argument is unsupported.
Federal NESHAPs regulate hazardous
air pollutants under section 112 of the
CAA and do not necessarily establish
RACT for NOX control under section
182 of the Act. The District has
provided no support for an assertion
that NESHAP controls satisfy RACT
requirements in this case.
Second, the District appears to
assume that lowering the NOX emission
10 We have converted each of the emission limits
we identified in the RBLC into their approximate
equivalent at 12% CO2 to allow for more direct
comparison to the emission limit in SJVUAPCD
Rule 4352, which is also expressed in ppm at 12%
CO2. Briefly, using equations available in EPA
Method 3B along with F Factors obtained from
Method 19, we calculated the O2 that should be
obtained during combustion if there is 12% CO2 in
the flue gas and assumed this O2 in correcting to
7% O2.
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limits for MSW-fired units in Rule 4352
to permit levels will satisfy RACT. This
is not correct. Although permit limits
can in some cases indicate a level of
emissions control that is reasonably
available, source-specific permit limits
do not in themselves establish RACT.
See Response #2.c above.
Finally, the District appears to assert
that the permits for MSW-fired units in
the SJV area contain emission limits
more stringent than the limit in Rule
4352. This also does not appear to be
correct. According to the list of
permitted solid fuel-fired boilers that
the District provided to us and that we
referenced as Attachment #6 to the TSD,
the two MSW-fired boilers in the SJV
area (at the Covanta Stanislaus facility)
are subject to District-issued permits,
both of which establish a NOX limit of
200 ppm at 12% CO2. This permit limit
is identical to the NOX emission limit in
Rule 4352 for MSW-fired units. The
source test data that we obtained for the
Covanta Stanislaus facility indicate that
each of these two MSW-fired units is
subject to both a limit of 200 ppm at
12% CO2 and a limit of 175 ppm at 12%
CO2, but it is not clear how and when
these different permit limits apply. See
letter dated August 20, 2009, from
Richard L. Wright, Air Quality
Inspector, SJUAPCD, to Terry Coble,
Covanta Stanislaus, Inc., enclosing
‘‘Summary of Source Test Results,’’
Tables 2.1 and 2.3. In any case, the
District has provided no support for its
assertion that reducing the limit in Rule
4352 would result in no emissions
reductions because of ‘‘more stringent
operating permit emission limits.’’ See
also Response 8.d.
Comment #9: SJVUAPCD stated that
the SJV area needs emission reductions
as quickly as feasible and is ‘‘hesitant to
divert resources to conduct work that is
not demonstrated to have significant
potential for additional reductions or
enforceability.’’ SJVUAPCD stated that
its focus on early and voluntary
reductions from Fast Track measures,
incentive programs, and the Healthy Air
Living program demonstrates the
District’s earnest desire to expedite air
quality improvement and that it is
conducting a study to determine the
feasibility of retrofitting solid fuel-fired
boilers with SCR, in addition to SNCR,
to achieve significant NOX reductions.
The District urged that its efforts not be
diverted without clear benefits.
Response #9: As discussed above in
Response #7, section 182 of the CAA
requires, for any ozone nonattainment
area classified as moderate or above, a
SIP revision to require RACT for all
major stationary sources of NOX that are
located in the area, among other
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sources. CAA 182(b)(2)(C), 182(f); 40
CFR 51.912(a). Because the SJV area is
designated and classified as an extreme
ozone nonattainment area (40 CFR
81.305), the SIP for the area must meet
subpart 2 RACT requirements for all
major NOX sources.
We recognize the District’s substantial
efforts to expedite air quality
improvement in the Valley, and we also
recognize that it is not clear that
revising the NOX emission limits in this
rule will result in significant emissions
reductions in the SJV area. Nonetheless,
we are obligated to review Rule 4352 for
compliance with the CAA, which
requires, among other things, that the
SJVUAPCD portion of the California SIP
provide for the implementation of RACT
at a minimum. We note that the
District’s reevaluation of the NOX
emission limits in Rule 4352 may reveal
additional emission reductions not yet
considered and encourage the District to
begin this process as expeditiously as
practicable, consistent with CAA
requirements.
III. EPA Action
Under CAA sections 110(k)(3) and
301(a) and for the reasons set forth
above and in our December 9, 2009
proposed rule, we are finalizing a
limited approval and limited
disapproval of amended District Rule
4352, as submitted on October 5, 2006.
We are finalizing a limited approval of
the submitted rule because we continue
to believe that the rule improves the SIP
and is largely consistent with relevant
CAA requirements. This action
incorporates amended Rule 4352,
including those provisions identified as
deficient, into the District portion of the
Federally-enforceable California SIP.
The amended rule approved herein
supersedes the version of Rule 4352 that
we approved in February 1999 into the
applicable SIP.
We are finalizing a limited
disapproval of the submitted rule
because the District has not adequately
demonstrated that the NOX limits in the
rule for MSW-fired units, biomass-fired
units, and units burning other solid
fuels (e.g., coal, petroleum coke, and
tire-derived fuels) satisfy RACT as
required by the CAA. Our reasons for
disapproving the NOX limits for MSWfired units and units burning other solid
fuels (e.g., coal, petroleum coke, and
tire-derived fuels) are explained in the
proposed rule and further in our
responses to comments above. With
respect to the NOX emission limit for
biomass-fired units, we are not
finalizing our proposal to approve this
limit and are instead disapproving it
because the District has not adequately
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demonstrated that this emission limit
satisfies RACT, as explained in our
responses to comments above. The final
limited disapproval triggers a sanctions
clock and EPA’s obligation to
promulgate a Federal implementation
plan (FIP). Sanctions will be imposed
unless EPA approves subsequent SIP
revisions that correct the rule
deficiencies within 18 months of the
effective date of this action. These
sanctions would be imposed under
section 179 of the Act according to 40
CFR 52.31. In addition, EPA must
promulgate a FIP under section 110(c)
unless we approve subsequent SIP
revisions that correct the rule
deficiencies within 24 months of the
effective date of this action. Note that
the submitted rule has been adopted by
the SJVUAPCD, and EPA’s final limited
disapproval does not prevent the local
agency from enforcing it.
IV. Statutory and Executive Order
Reviews
A. Executive Order 12866, Regulatory
Planning and Review
The Office of Management and Budget
(OMB) has exempted this regulatory
action from Executive Order 12866,
entitled ‘‘Regulatory Planning and
Review.’’
B. Paperwork Reduction Act
This action does not impose an
information collection burden under the
provisions of the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. Burden is
defined at 5 CFR 1320.3(b).
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA)
generally requires an agency to conduct
a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements unless the
agency certifies that the rule will not
have a significant economic impact on
a substantial number of small entities.
Small entities include small businesses,
small not-for-profit enterprises, and
small governmental jurisdictions.
This rule will not have a significant
impact on a substantial number of small
entities because SIP approvals and
limited approvals/limited disapprovals
under section 110 and subchapter I, part
D of the Clean Air Act do not create any
new requirements but simply approve
requirements that the State is already
imposing. Therefore, because this
limited approval/limited disapproval
action does not create any new
requirements, I certify that this action
will not have a significant economic
impact on a substantial number of small
entities.
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Moreover, due to the nature of the
Federal-State relationship under the
Clean Air Act, preparation of flexibility
analysis would constitute Federal
inquiry into the economic
reasonableness of State action. The
Clean Air Act forbids EPA to base its
actions concerning SIPs on such
grounds. Union Electric Co., v. U.S.
EPA, 427 U.S. 246, 255–66 (1976); 42
U.S.C. 7410(a)(2).
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D. Unfunded Mandates Reform Act
Under sections 202 of the Unfunded
Mandates Reform Act of 1995
(‘‘Unfunded Mandates Act’’), signed into
law on March 22, 1995, EPA must
prepare a budgetary impact statement to
accompany any proposed or final rule
that includes a Federal mandate that
may result in estimated costs to State,
local, or tribal governments in the
aggregate; or to the private sector, of
$100 million or more. Under section
205, EPA must select the most costeffective and least burdensome
alternative that achieves the objectives
of the rule and is consistent with
statutory requirements. Section 203
requires EPA to establish a plan for
informing and advising any small
governments that may be significantly
or uniquely impacted by the rule.
EPA has determined that the limited
approval/limited disapproval action
promulgated does not include a Federal
mandate that may result in estimated
costs of $100 million or more to either
State, local, or tribal governments in the
aggregate, or to the private sector. This
Federal action approves pre-existing
requirements under State or local law,
and imposes no new requirements.
Accordingly, no additional costs to
State, local, or tribal governments, or to
the private sector, result from this
action.
E. Executive Order 13132, Federalism
Federalism (64 FR 43255, August 10,
1999) revokes and replaces Executive
Orders 12612 (Federalism) and 12875
(Enhancing the Intergovernmental
Partnership). Executive Order 13132
requires EPA to develop an accountable
process to ensure ‘‘meaningful and
timely input by State and local officials
in the development of regulatory
policies that have federalism
implications.’’ ‘‘Policies that have
federalism implications’’ is defined in
the Executive Order to include
regulations that have ‘‘substantial direct
effects on the States, on the relationship
between the national government and
the States, or on the distribution of
power and responsibilities among the
various levels of government.’’ Under
Executive Order 13132, EPA may not
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issue a regulation that has federalism
implications, that imposes substantial
direct compliance costs, and that is not
required by statute, unless the Federal
government provides the funds
necessary to pay the direct compliance
costs incurred by State and local
governments, or EPA consults with
State and local officials early in the
process of developing the proposed
regulation. EPA also may not issue a
regulation that has federalism
implications and that preempts State
law unless the Agency consults with
State and local officials early in the
process of developing the proposed
regulation.
This rule will not have substantial
direct effects on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132, because it
merely approves a State rule
implementing a Federal standard, and
does not alter the relationship or the
distribution of power and
responsibilities established in the Clean
Air Act. Thus, the requirements of
section 6 of the Executive Order do not
apply to this rule.
F. Executive Order 13175, Coordination
With Indian Tribal Governments
Executive Order 13175, entitled
‘‘Consultation and Coordination with
Indian Tribal Governments’’ (65 FR
67249, November 9, 2000), requires EPA
to develop an accountable process to
ensure ‘‘meaningful and timely input by
tribal officials in the development of
regulatory policies that have tribal
implications.’’ This final rule does not
have tribal implications, as specified in
Executive Order 13175. It will not have
substantial direct effects on tribal
governments, on the relationship
between the Federal government and
Indian tribes, or on the distribution of
power and responsibilities between the
Federal government and Indian tribes.
Thus, Executive Order 13175 does not
apply to this rule.
G. Executive Order 13045, Protection of
Children From Environmental Health
Risks and Safety Risks
EPA interprets Executive Order 13045
(62 FR 19885, April 23, 1997) as
applying only to those regulatory
actions that concern health or safety
risks, such that the analysis required
under section 5–501 of the Executive
Order has the potential to influence the
regulation. This rule is not subject to
Executive Order 13045, because it
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Fmt 4700
Sfmt 4700
60631
approves a State rule implementing a
Federal standard.
H. Executive Order 13211, Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This rule is not subject to Executive
Order 13211, ‘‘Actions Concerning
Regulations That Significantly Affect
Energy Supply, Distribution, or Use’’ (66
FR 28355, May 22, 2001) because it is
not a significant regulatory action under
Executive Order 12866.
I. National Technology Transfer and
Advancement Act
Section 12 of the National Technology
Transfer and Advancement Act
(NTTAA) of 1995 requires Federal
agencies to evaluate existing technical
standards when developing a new
regulation. To comply with NTTAA,
EPA must consider and use ‘‘voluntary
consensus standards’’ (VCS) if available
and applicable when developing
programs and policies unless doing so
would be inconsistent with applicable
law or otherwise impractical.
The EPA believes that VCS are
inapplicable to this action. Today’s
action does not require the public to
perform activities conducive to the use
of VCS.
J. Congressional Review Act
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 rule 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). This rule
will be effective on November 1, 2010.
K. Petitions for Judicial Review
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 November 30,
2010. Filing a petition for
reconsideration by the Administrator of
this final rule does not affect the finality
of this rule for the purposes of judicial
review nor does it extend the time
within which a petition for judicial
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Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations
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, Reporting and
recordkeeping requirements.
Dated: August 26, 2010.
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 paragraph (c)(347)(i)(A)(2) to
read as follows:
■
§ 52.220
Identification of plan.
*
*
*
*
*
(c) * * *
(347) * * *
(i) * * *
(A) * * *
(2) Rule 4352, ‘‘Solid Fuel Fired
Boilers, Steam Generators and Process
Heaters,’’ amended on May 18, 2006.
*
*
*
*
*
[FR Doc. 2010–24686 Filed 9–30–10; 8:45 am]
BILLING CODE 6560–50–P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 261
[EPA–R06–RCRA–2010–0066; SW FRL–
9208–7]
Hazardous Waste Management
System; Identification and Listing of
Hazardous Waste; Direct Final Rule
Environmental Protection
Agency (EPA).
ACTION: Direct final rule.
mstockstill on DSKH9S0YB1PROD with RULES
AGENCY:
EPA is proposing to grant a
petition submitted by ExxonMobil
Refining and Supply Company—
Beaumont Refinery (Beaumont Refinery)
to exclude (or delist) a certain solid
waste generated by its Beaumont, Texas,
facility from the lists of hazardous
wastes. EPA used the Delisting Risk
SUMMARY:
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16:31 Sep 30, 2010
Jkt 223001
Assessment Software (DRAS) Version
3.0 in the evaluation of the impact of the
petitioned waste on human health and
the environment.
DATES: This rule is effective on
November 30, 2010. Comments must be
received by November 1, 2010. Your
requests for a hearing must reach EPA
by October 18, 2010. The request must
contain the information described in
§ 260.20(d).
Submit your comments,
identified by Docket ID No. EPA–R06–
RCRA–2010–0066 by one of the
following methods:
1. Federal eRulemaking Portal:
https://www.regulations.gov: Follow the
on-line instructions for submitting
comments.
2. E-mail: peace.michelle@epa.gov.
3. Mail: Michelle Peace,
Environmental Protection Agency,
Multimedia Planning and Permitting
Division, RCRA Branch, Mail Code:
6PD–C, 1445 Ross Avenue, Dallas, TX
75202.
4. Hand Delivery or Courier. Deliver
your comments to: Michelle Peace,
Environmental Protection Agency,
Multimedia Planning and Permitting
Division, RCRA Branch, Mail Code:
6PD–C, 1445 Ross Avenue, Dallas, TX
75202.
Requests for a hearing should be
made to: Ben Banipal, Section Chief of
the Corrective Action and Waste
Minimization Section, Multimedia
Planning and Permitting Division (6PD–
C), Environmental Protection Agency
Region 6, 1445 Ross Avenue, Dallas,
Texas 75202.
Instructions: Direct your comments to
Docket ID No. EPA–R06–RCRA–2010–
0066. EPA’s policy is that all comments
received will be included in the public
docket without change and may be
made available online at https://
www.regulations.gov, including any
personal information provided, unless
the comment includes information
claimed to be Confidential Business
Information (CBI) or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through https://
www.regulations.gov or e-mail. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means EPA will not know your identity
or contact information unless you
provide it in the body of your comment.
If you send an e-mail comment directly
to EPA without going through https://
www.regulations.gov, your e-mail
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
ADDRESSES:
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made available on the Internet. If you
submit an electronic comment, EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
special characters, any form of
encryption, and be free of any defects or
viruses.
Docket: All documents in the
electronic docket are listed in the
https://www.regulations.gov index.
Although listed in the index, some
information is not publicly available,
e.g., CBI or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, will be publicly
available only in hard copy. Publicly
available docket materials are available
either electronically in https://
www.regulations.gov or in hard copy at
the Environmental Protection Agency,
RCRA Branch, 1445 Ross Avenue,
Dallas, TX 75202. The hard copy RCRA
regulatory docket for this proposed rule,
EPA–R06–RCRA–2010–0066, is
available for viewing from 8 a.m. to 5
p.m., Monday through Friday, excluding
Federal holidays. The public may copy
material from any regulatory docket at
no cost for the first 100 pages and at a
cost of $0.15 per page for additional
copies. EPA requests that you contact
the person listed in the FOR FURTHER
INFORMATION CONTACT section to
schedule your inspection. The
interested persons wanting to examine
these documents should make an
appointment with the office at least 24
hours in advance.
For
further technical information
concerning this document or for
appointments to view the docket or the
Beaumont Refinery petition, contact
Michelle Peace, Environmental
Protection Agency, Multimedia
Planning and Permitting Division,
RCRA Branch, Mail Code: 6PD–C, 1445
Ross Avenue, Dallas, TX 75202, by
calling (214) 665–7430 or by e-mail at
peace.michelle@epa.gov.
FOR FURTHER INFORMATION CONTACT:
Beaumont
Refinery submitted a petition under 40
CFR 260.20 and 260.22(a). Section
260.20 allows any person to petition the
Administrator to modify or revoke any
provision of parts 260 through 266, 268
and 273. Section 260.22(a) specifically
provides generators the opportunity to
petition the Administrator to exclude a
SUPPLEMENTARY INFORMATION:
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]]>Agencies
[Federal Register Volume 75, Number 190 (Friday, October 1, 2010)]
[Rules and Regulations]
[Pages 60623-60632]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-24686]
[[Page 60623]]
=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R09-OAR-2009-0711; FRL-9207-7]
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 finalizing a limited approval and limited disapproval
of 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 December 9,
2009 and concerns oxides of nitrogen (NOX) emissions from
solid fuel fired boilers, steam generators and process heaters. Under
authority of the Clean Air Act as amended in 1990 (CAA or the Act),
this action simultaneously approves a local rule that regulates these
emission sources and directs California to correct rule deficiencies.
DATES: Effective Date: This rule is effective on November 1, 2010.
ADDRESSES: EPA has established docket number EPA-R09-OAR-2009-0711 for
this action. The index to the docket is available electronically at
https://www.regulations.gov and in hard copy at EPA Region IX, 75
Hawthorne Street, San Francisco, California. While all documents in the
docket are listed in the index, some information may be publicly
available only at the hard copy location (e.g., copyrighted material),
and some may not be publicly available in either location (e.g., 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.
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 12/09/09 (74 FR 65042), EPA proposed a limited approval and
limited disapproval of the following rule that the SJVUAPCD submitted
for incorporation into the California SIP.
----------------------------------------------------------------------------------------------------------------
Local agency Rule No. Rule title Adopted Submitted
----------------------------------------------------------------------------------------------------------------
SJVUAPCD............................ 4352 Solid Fuel Fired 05/18/06 10/05/06
Boilers, Steam
Generators and Process
Heaters.
----------------------------------------------------------------------------------------------------------------
We proposed a limited approval because we determined that this rule
improves the SIP and is largely consistent with the relevant CAA
requirements. We simultaneously proposed a limited disapproval because
some rule provisions do not satisfy the requirements of section 110 and
part D of the Act. Specifically:
Section 5.1 of the Rule establishes the emission limits.
We proposed to find that, with the exception of the NOX
emission limit for biomass fuel-fired units, SJVUAPCD has not
adequately demonstrated that the NOX emission limits (i.e.,
NOX limits for units burning municipal solid waste or other
solid fuels, such as coal) satisfy Reasonably Available Control
Technology (RACT) requirements. As explained further in the TSD for the
proposed action, EPA's 1994 Alternative Control Techniques Document for
NOX emissions from Industrial/Commercial/Institutional
Boilers (1994 ACT) contains lower emission ranges for similar boilers.
Source-specific information from the SJVUAPCD also indicates that
emission limits lower than those in Rule 4352 are reasonably
achievable.
We are now disapproving all of the NOX emission limits
in Rule 4352, including the limit for biomass fuel-fired units, because
the District has not adequately demonstrated that these limits satisfy
RACT. Our proposed action and our response to comments below contain
more information on the basis for this rulemaking and our evaluation of
the submittal.
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 parties.
1. Sarah Jackson, Earthjustice; letter and e-mail dated and
received January 8, 2010.
2. Seyed Sadredin, SJVUAPCD; letter dated January 8, 2010 and
received January 11, 2010.
The comments and our responses are summarized below.
Comment #1: Earthjustice supported EPA's proposed disapproval of
the NOX emission limits in Rule 4352 for municipal solid
waste-burning and other solid fuel-burning units and agreed that the
District had failed to demonstrate that these limits satisfy CAA RACT
requirements.
Response #1: No response needed.
Comment #2: Earthjustice disagreed with EPA's proposal to approve
the NOX emission limit in Rule 4352 for biomass-fired units
as RACT. Earthjustice provided several arguments in support of its
objection to EPA's proposal, each of which we address in separate
comment summaries below.
Response #2: Although we do not agree with all of the arguments
provided in support of this comment, we have changed our position based
on this comment and agree that the District has failed to provide
adequate support for its conclusion that the NOX emission
limit in Rule 4352 for biomass-fired units satisfies RACT. We believe
our conclusion on this issue is a logical outgrowth of our proposed
rule.
Comment #2.a: Earthjustice challenged EPA's conclusion that the
NOX emission limit of 115 ppm at 3% O2 for
biomass-fired units in Rule 4352 is more stringent than the level
provided in EPA's 1994 ACT, given that the 1994 ACT provides achievable
NOX levels ranging from 23 to 155 ppm at 3% O2
for wood-fired boilers with fluidized bed combustors. Additionally,
Earthjustice asserted that this range of NOX emission levels
undermines EPA's conclusion that the 40 ppm limit in other districts'
rules is not feasible.
Response #2.a: We acknowledge that our previous statement that Rule
4352's requirements for biomass-fired units are more stringent than the
levels in the 1994 ACT was not entirely accurate. In this action, we
are clarifying that the NOX emission limit in Rule 4352 for
biomass-fired boilers (115 ppm at 3% O2) falls in the mid-
range of achievable emission levels provided in the 1994 ACT for this
source category (24 ppm to 187 ppm at 3% O2).\1\
---------------------------------------------------------------------------
\1\ The range of emission levels that Earthjustice identifies
(23 to 155 ppm at 3% O2) are presented in the TSD for our
proposed action and are calculated based on the lb/MMBtu values
shown in Table 2-6 of the ACT. We note, however, that the values
presented in Appendix B of the ACT (24 ppm to 187 ppm at 3%
O2) are more reliable because they were compiled from
numerous sources including technical reports, EPA documents,
compliance records, and manufacturers' literature, while Table 2-6
is simply a summary of Appendix B.
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[[Page 60624]]
As to the commenter's assertion that the range of emission levels
in the 1994 ACT undermines EPA's conclusion that a NOX limit
of 40 ppm is not feasible for biomass-fired boilers, however, we
disagree. In the TSD for our proposal, we referenced a 40 ppm
NOX emission limit based on SJVUAPCD's April 16, 2009 RACT
SIP analysis, which identified four other California districts' rules
that contain emission limits of 40 ppm at 3% O2 for units
firing ``non-gaseous fuels'': The South Coast Air Quality Management
District (SCAQMD) Rule 1146 (as amended September 5, 2008); Sacramento
Metropolitan Air Quality Management District (SMAQMD) Rule 411 (as
amended August 23, 2007); Bay Area Air Quality Management District
(BAAQMD) Regulation 9 Rule 7 (as amended July 30, 2008) \2\; and
Ventura County Air Pollution Control District (VCAPCD) Rule 74.15 (as
amended November 8, 1994). See SJVUAPCD, RACT Demonstration for Ozone
SIP, Chapter 4: Rule Analysis, at 4-64 to 4-67 (April 16, 2009) (``RACT
SIP analysis''). In response to this comment, we contacted each of
these districts to determine whether there are any biomass-fired units
subject to the NOX emission limits in these rules. None of
these districts provided information indicating that any biomass-fired
boiler has achieved a NOX limit of 40 ppm at 3%
O2.
---------------------------------------------------------------------------
\2\ The District's RACT SIP analysis provides an incorrect
adoption date of November 7, 2007, for this regulation. The version
of Regulation 9 Rule 7 that is currently effective in the Bay Area
was last amended on July 30, 2008. See e-mail dated August 11, 2010,
from Dan Belik (BAAQMD) to Idalia Perez (EPA Region 9).
---------------------------------------------------------------------------
Specifically, we are not aware of any biomass-fired boiler that is
or has been subject to the 40 ppm NOX emission limit in
VCAPCD Rule 74.15 or SCAQMD Rule 1146.\3\ See e-mail dated June 7,
2010, from Kerby Zozula (VCAPCD) to Shirley Rivera (EPA Region 9); e-
mail dated August 10, 2010, from Charles Tupac (SCAQMD) to Idalia Perez
(EPA Region 9). The BAAQMD has issued one permit for a biomass-fired
unit at a facility called Standard Structures, Inc., but we have no
information indicating that this unit is achieving emission levels as
low as 40 ppm at 3% O2. See e-mail dated June 7, 2010, from
Barry Young (BAAQMD) to Shaheerah Kelly (EPA Region 9); Facsimile
Transmittal dated June 8, 2010, attaching Evaluation Report and
Engineering Evaluation for Standard Structures, Inc., from Art Valla
(BAAQMD) to S. Kelly (EPA Region 9); e-mail dated June 8, 2010, from
Charles McClure (BAAQMD) to Idalia Perez (EPA Region 9). In the
Sacramento Metro area, one source has operated a biomass-fired boiler
in the past 20 years, but that source was subject to an earlier version
of SMAQMD's Rule 411 containing significantly higher NOX
emission limits until it ceased operating in March 1996. See Response
2.b, below. We have no information indicating that a
NOX emission level of 40 ppm at 3% O2 is
generally achievable for biomass-fired units, and the commenter has not
identified any such information.
---------------------------------------------------------------------------
\3\ Note that SCAQMD Rule 1146 applies only to ``combustion
equipment fired with liquid and/or gaseous (including landfill and
digester gas) and/or solid fossil fuel. * * *'' Rule 1146 (as
amended September 5, 2008), sections (a), (b)(4), and (b)(12)
(emphasis added). As such, this rule does not apply to biomass-fired
units.
---------------------------------------------------------------------------
ACT documents describe available control techniques and their cost
effectiveness but do not define presumptive RACT levels as the CTGs do.
The 1994 ACT (at Appendix B, pages B20-B21) identifies NOX
emission levels for biomass-fueled boilers ranging from 24 ppm to 187
ppm at 3% O2, based on the use of SNCR controls with ammonia
or urea injection. This wide range of emission levels reflects the
broad technical diversity among the types of boilers that fire biomass
as fuel, including stokers, circulating fluidized bed boilers and
bubbling fluidized bed boilers. It also reflects the variety of fuels
that the term ``biomass'' covers, including various kinds of plant
materials, wood materials and agricultural wastes.
Given the broad technical diversity of existing biomass-fired
boilers and their varying fuel compositions, the NOX
emission levels achievable for one operation (e.g., 24 ppm) may not
necessarily be achievable for others. Even where boiler type, control
technology, and fuel type are the same, achievable 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 Appendix B (at page B-20), showing achievable
NOX emission levels ranging from 25 to 160 ppm at 3%
O2 for wood-fired stoker boilers using SNCR with ammonia
injection.
Thus, the range of emission levels for biomass-fired boilers in the
1994 ACT does not necessarily establish that a NOX emission
level of 40 ppm at 3% O2 is reasonably achievable for such
boilers generally. It does, however, warrant a more detailed evaluation
of the biomass-fired units in the SJV area, as discussed further below.
Comment #2.b: Earthjustice asserted that the District's claim that
there are no solid-fuel fired units in the Sacramento area that
currently meet the 70 ppm limit in the SMAQMD's Rule 411 is
``misleading and irrelevant to answering the feasibility question.''
Earthjustice stated that according to CARB and SMAQMD staff, ``there
was, in fact, at least one source in the Sacramento Metropolitan air
district that burned biomass as a fuel, and that source met the
emission limit of this rule until it decided to switch to landfill gas
as a fuel source.'' In support of these assertions, Earthjustice
referenced a letter to EPA dated June 29, 2007, in which it had made
these same assertions. Earthjustice concluded that the SMAQMD's
NOX limit of 70 ppm for biomass-fired units in Rule 411
``has been demonstrated as feasible,'' and that ``EPA must conduct its
own review of the feasibility of Sacramento's limit,'' rather than
``rely[] on the District's misleading claims.''
Response #2.b: First, the difference between the limit in SMAQMD's
Rule 411 and the limit in SJVUAPCD's Rule 4352 is not as significant as
the commenter contends. The current 70 ppm NOX emission
limit in Rule 411 is expressed in parts per million corrected to 12%
carbon dioxide (ppm at 12% CO2), which equates to
approximately 100 ppm at 3% O2. See Rule 411 (as amended
August 23, 2007), section 303.1.\4\ As such, the appropriate comparison
is between a limit of 100 ppm at 3% O2 (not 70 ppm at 3%
O2) in SMAQMD's Rule 411 and a limit of 115 ppm at 3%
O2 in SJVUAPCD's Rule 4352.
---------------------------------------------------------------------------
\4\ We have converted the emission limit into its approximate
equivalent at 3% O2 to allow for more direct comparison
to the emission limits in SJVUAPCD Rule 4352 and the other rules we
have evaluated, which are also generally expressed in ppm at 3%
O2. Briefly, using equations available in EPA Method 3B
along with F Factors obtained from Method 19, we calculated the
O2 that should be obtained during combustion if there is
12% CO2 in the flue gas and corrected the NO2
concentration obtained to 3% O2.
---------------------------------------------------------------------------
Second, to the extent the commenter intended to argue that an
emission level of 70 ppm at 3% O2 has been achieved in the
Sacramento area, this argument is unsupported. In both the comments
submitted for this rulemaking and the June 29, 2007 comment letter,
Earthjustice refers to, without identifying, a source in the Sacramento
[[Page 60625]]
Metropolitan area that at some point burned biomass and that met the
emission limits in Rule 411 before it decided to switch to landfill gas
as a fuel source. It appears that Earthjustice is referring to an
almond processing facility called Blue Diamond, which we understand was
the only source in the Sacramento Metropolitan area to have operated a
biomass-fired boiler in the past 20 years. See e-mail dated May 13,
2010, from Bruce Nixon (SMAQMD) to Idalia Perez (EPA Region 9).
According to SMAQMD staff, the Blue Diamond facility ceased
operations in March 1996. See e-mail dated February 8, 2010, from Bruce
Nixon (SMAQMD) to Idalia Perez (EPA Region 9). Prior to this time, the
facility was subject to Rule 411 as adopted on February 2, 1995, which
contained a limit for NOX emissions from biomass-fired
boilers of 110 ppm at 12% CO2, or approximately 156 ppm at
3% O2.\5\ See Section 303.1, Rule 411 (as adopted February
2, 1995). Notably, this limit was significantly higher than the
NOX limit for biomass-fired boilers in SJVUAPCD's current
Rule 4352 (115 ppm at 3% O2). Assuming Blue Diamond's
biomass-fired boiler was in compliance with the applicable limit in the
1995 version of Rule 411, i.e., approximately 156 ppm at 3%
O2, this does not demonstrate that a NOX emission
limit of 70 ppm at 3% O2 is achievable.\6\
---------------------------------------------------------------------------
\5\ See fn. 4, supra, for an explanation of the conversion
methodology from ppm at 12% CO2 to ppm at 3%
O2.
\6\ The 1995 version of SMAQMD Rule 411 also contained a lower
limit of 70 ppm at 12% CO2 (~100 ppm at 3% O2)
which took effect May 31, 1997. See Section 306.1, Rule 411 (as
adopted February 2, 1995). On October 27, 2005, SMAQMD revised Rule
411 by eliminating the NOX emission limit of 110 ppm at
12% CO2 (~156 ppm at 3% O2) but retaining the
NOX emission limit of 70 ppm at 12% CO2 (~100
ppm at 3% O2). At that time, however, no facility in the
SMAQMD area operated a biomass-fired boiler subject to this limit.
See e-mail dated May 13, 2010, from Bruce Nixon (SMAQMD) to Idalia
Perez (EPA Region 9).
---------------------------------------------------------------------------
Comment #2.c: Earthjustice asserted that ``the evidence EPA has put
in the record suggests that much lower limits for biomass-fired units
are not only reasonably available but, in fact, are already being
achieved by just about every facility in the Valley.'' Earthjustice
provided an excerpt from a document EPA had identified in the TSD and
asserted that according to this document, which contained information
about solid fuel-fired units and associated permit limits in the SJV
area, ``[a]ll but one biomass-fired unit is already meeting the more
stringent SMAQMD limit of 70 ppm at 12% CO2 (~100 ppm at 3%
O2) and most are permitted well below this limit * * *.''
Earthjustice also stated that the permitted levels do not necessarily
reflect the level of emissions from these facilities, and that EPA
should consider source test data for these facilities ``to aid in the
determination of what is reasonably achievable.''
Response #2.c: The commenter correctly notes that biomass-fired
boilers in the SJV area are achieving NOX emission levels
below the levels required by Rule 4352. In fact, based on information
we have gathered in response to these comments, it appears that all of
the existing biomass-fired boilers in the SJV area that are subject to
Rule 4352 are achieving emission levels significantly below 115 ppm at
3% O2. In the absence of information indicating that these
lower emission levels are not reasonably achievable in the SJV area, we
conclude that the District has not adequately demonstrated that the
NOX limit in Rule 4352 (115 ppm at 3% O2)
represents RACT.
Ten biomass-fired boilers in the SJV area are currently subject to
the NOX emission limit in Rule 4352. We have reviewed source
test data for four of these units and found that each unit is achieving
actual NOX emission levels between 44 and 79 ppm at 3%
O2. We also evaluated source test data for two biomass-fired
units in Placer County and one unit in Yolo County, California, which
indicate actual NOX emission levels between 45 and 103 ppm
at 3% O2. See Table 1. These source test results indicate
that biomass-fired units both within the SJV area and elsewhere in
California are currently achieving NOX emission levels
significantly below 115 ppm at 3% O2.
Table 1--NOX Source Test Data for Selected Boilers Firing Biomass in CA
----------------------------------------------------------------------------------------------------------------
Test
Facility Air district year Emission
----------------------------------------------------------------------------------------------------------------
Madera Power, LLC....................... SJVUAPCD.................. 2009 44.3 ppm at 3% O2.
Covanta Delano, Inc..................... SJVUAPCD.................. 2009 Unit 1--0.07 lbs/MMBtu (~54 ppm
at 3% O2)
...............................
......... Unit 2--0.063 lbs/MMBtu (~49
ppm at 3% O2).
Sierra Power Corporation................ SJVUAPCD.................. 2009 78.7 ppm at 3% O2.
Sierra Pacific Industries, Lincoln...... Placer County APCD 2009 51.2 ppm at 12% CO2 (~103 ppm
(PCAPCD). at 3% O2).
Rio Bravo Rocklin....................... PCAPCD.................... 2009 37.6 ppm at 12% CO2 (~76 ppm at
3% O2)
Woodland Biomass Power, LTD............. Yolo-Solano APCD.......... 2010 45.34 ppm at 3% O2.
----------------------------------------------------------------------------------------------------------------
The remaining six biomass-fired units in the SJV area are subject
to NOX permit limits ranging from 62 to 83 ppm at 3%
O2. See Table 2.
Table 2--NOX Permit Limits for Biomass Facilities in SJVUAPCD
------------------------------------------------------------------------
Permit No. Size of unit NOX Limit
------------------------------------------------------------------------
C-825......................... 317 MMBtu/hr..... 27.8 lb/hr (~83 ppm
at 3% O2).
C-1820........................ 352 MMBtu/hr..... 0.08 lb/MMBTU (~62
ppm at 3% O2).
N-1026........................ 259 MMBtu/hr..... 27.2 lb/hr (~83 ppm
at 3% O2).
N-4607........................ 185 MMBtu/hr..... 0.08 lb/MMBtu (~83
ppm at 3% O2).
S-285......................... 11.5 MW.......... 0.09 lb/MMBtu (~70
ppm at 3% O2).
C-6923........................ 185 MMBtu/hr..... 0.08 lb/MMBtu (~62
ppm at 3% O2).
------------------------------------------------------------------------
[[Page 60626]]
We note that each of the biomass-fired units located in the SJV
area that is subject to Rule 4352 is also subject to a NOX
emission limit representing the Best Available Control Technology
(BACT) \7\ in its District-issued permit, and that the BACT standard
often requires a more stringent control level than RACT. BACT
requirements are established prior to construction on an emissions-unit
by emissions-unit basis through the District's permitting process. See
SJVUAPCD Rule 2201 (as amended December 18, 2008), sections 2.0 and
4.1. RACT, on the other hand, applies to existing sources and is
defined as the lowest emission limitation that a particular source is
capable of meeting ``by the application of control technology that is
reasonably available considering technological and economic
feasibility.'' 44 FR 53762 (September 17, 1979). EPA historically has
recommended source-category-wide presumptive RACT limits based on
capabilities that are general to an industry, although RACT decisions
may also be made on a case-by-case basis. See 57 FR 55620 at 55624
(November 25, 1992) (``NOx Supplement to General Preamble'').
Similarly, a RACT prohibitory rule may establish emission limits based
on capabilities that are general to the covered source category, rather
than based on source-specific analyses.
---------------------------------------------------------------------------
\7\ SJVUAPCD Rule 2201 (New and Modified Stationary Source
Review Rule) defines BACT, in relevant part, as ``the most stringent
emission limitation or control technique * * * achieved in practice
for such category and class of source * * *.'' SJVUAPCD Rule 2201
(as amended December 18, 2008), section 3.9.
---------------------------------------------------------------------------
Given the stringency and source-specific nature of the BACT
requirement, a BACT limit established in a pre-construction permit does
not necessarily represent RACT for the source category in general. This
does not mean, however, that the two standards may never result in
similar emission levels based on the same or similar controls. In some
cases, RACT may even result in more stringent control levels than a
source-specific control standard like BACT or the Lowest Achievable
Emission Rate (LAER). See Memorandum dated March 30, 1994, from Tom
Helms, Chief, Ozone/Carbon Monoxide Programs Branch, to Region V Air
Enforcement Branch, ``Nitrogen Oxides (NOx) Questions from Ohio EPA'';
Memorandum dated December 1, 1988, from Gerald Emison, Director, Office
of Air Quality Planning and Standards, to William Spratlin, Director,
Air and Toxics Division, Region VII, ``RACT Requirements in Ozone
Nonattainment Areas'' (noting that LAER is determined at the time of
permit issuance). Fundamentally, each of these standards requires a
specific evaluation of the types of controls that are available to the
source--or, in the case of a prohibitory rule, to the covered sources
in the relevant area--taking into account, where appropriate,
technological and economic feasibility.
In this case, every existing biomass-fired boiler in the SJV area
that is subject to this rule is already achieving lower NOX
levels based on BACT controls. Absent information indicating that these
controls may not be technologically or economically feasible for
sources in the area, we have no basis for concluding that these
emissions levels are not also reasonably available and appropriate as
RACT in the SJV area.
Comment #2.d: Earthjustice asserted that, in addition to
identifying the control technology that can achieve a RACT level of
control, EPA must provide an ``analysis that identifies the
appropriately stringent emission limit within the range of control
achievable by this technology.''
Response #2.d: We agree that a RACT analysis generally should
identify not only reasonably available control technologies but also
appropriately stringent emission limitations based on these controls.
We are disapproving all of the NOX emission limits in Rule
4352 because the District has not adequately demonstrated that these
limits satisfy RACT.
Comment #3: Earthjustice asserted that EPA should evaluate the
source test data available to it in evaluating Rule 4352, rather than
``relying strictly on outdated technology reviews and ignoring the fact
that SNCR and other similar technologies have radically improved over
the last fifteen years* * *.'' Earthjustice provided a list of
California biomass facilities at https://www.calbiomass.org/county.htm
and stated that this could be a good starting point for EPA's
investigation. Finally, Earthjustice reiterated its assertions that
``[t]he 70 ppm limit for biomass-fired units in the Sacramento rule has
been proven, not just by the source that used to operate in Sacramento,
but also by the many biomass-burning facilities in the Valley that are
already meeting that standard,'' and that EPA should disapprove all of
the limits in Rule 4352 as RACT.
Response #3: Although we do not agree with the commenter's
assertion that a NOX emission level of 70 ppm at 3%
O2 has been achieved by a biomass-fired unit in the
Sacramento area, our review of source test data and permits for
biomass-fired units in the SJV area indicate that emission levels
between 44 and 83 ppm at 3% O2 are currently being achieved.
See Responses 2.b. and 2.c above. We are disapproving
all of the NOX limits in Rule 4352, including the limit for
biomass-fired units, because the District has not demonstrated that
these limits satisfy RACT.
Comment #4: Earthjustice requested confirmation that any alternate
source-specific RACT emission limit requested by the owner or operator
of a source under section 5.4 of Rule 4352 will be approved by EPA only
after notice and comment rulemaking.
Response #4: We understand that section 5.4 requires the District
to provide an opportunity for public comment on any alternate source-
specific RACT limit that it seeks to approve through issuance of a
Permit to Operate under Rule 2520 (as amended June 21, 2001), subject
to EPA review, as explained further below. Before we approve any
alternate limit under this provision, EPA intends to ensure that the
District has satisfied the procedural requirements of Rule 2520 and
that the Permit to Operate ensures compliance with applicable CAA
requirements, including RACT, consistent with the requirements of CAA
title V.
Specifically, section 5.4 of Rule 4352 states that, for a unit
operating at or below 50 percent of the rated heat input (i.e., the
heat input capacity specified on the nameplate of the unit), ``the
APCO, ARB, and EPA may approve an increased emission limit if the
owner/operator submits an application for a Permit to Operate, which
provides a justification for the requested limit.'' Upon approval by
the APCO, ARB, and EPA, the source owner/operator may comply with this
higher limit in lieu of the applicable limits in Table 1 of the rule.
Importantly, the rule allows the District, ARB, and EPA to approve
an alternate limit only after the owner/operator submits an application
for a Permit to Operate (PTO) that provides a justification for the
requested limit. Any source in the SJV area that is subject to Rule
4352 based on its potential to emit at least 10 tons per year (tpy) of
NOX is also subject to the District's EPA-approved title V
permit program because it is a ``major source.'' See SJVUAPCD Rule
2520, ``Federally Mandated Operating Permits'' (as amended June 21,
2001), sections 2.3 and 3.19 (applying program to any ``major source''
as defined in SJVUAPCD Rule 2201); SJVUAPCD Rule 2201, ``New and
Modified Stationary Source Review Rule'' (as amended December 18,
2008),
[[Page 60627]]
section 3.23 (defining ``major source'' to include any source that has
the potential to emit at least 20,000 pounds per year (10 tpy) of
NOX). Thus, any source owner/operator seeking to obtain an
alternate limit under Rule 4352 must submit an application under Rule
2520 either for an initial PTO (if it is a new source) or for a
``significant permit modification'' to its existing PTO. See Rule 2520,
sections 5.3.1, 3.29, and 3.20.3. Both initial PTOs and significant
modifications to existing PTOs are subject to a 30-day public comment
period and a 45-day EPA review period, during which EPA may object to
the permit if it does not meet applicable CAA requirements. See Rule
2520, sections 11.3 and 11.7. Furthermore, if EPA does not object in
writing to the District's preliminary decision during the 45-day review
period, any person may petition EPA to review the permit. See Rule
2520, section 11.3.7.
These procedures ensure that the public will have an opportunity
not only to comment on any alternate limit proposed by the District
under section 5.4 of Rule 4352, but also to submit a title V petition
to EPA where EPA does not object to a proposed permit containing such
an alternate limit. Prior to approving any alternate limit requested
under section 5.4 of Rule 4352, EPA intends to ensure that the District
has satisfied these procedural requirements under Rule 2520 and that
the PTO, including the alternate limit, satisfies CAA RACT
requirements.
Comment #5: SJVUAPCD agreed with EPA's proposal to approve the
NOX limit in Rule 4352 for biomass-fired units and stated
that all solid fuel-fired units in the area are equipped with SNCR or
SCR controls, which are more effective than SNCR.
Response #5: As explained above, based on the comments we received,
we have determined that the District has not adequately demonstrated
that the NOX limit in Rule 4352 for biomass-fired units
satisfies RACT. See Responses 2.c and 2.d.
Comment #6: SJVUAPCD disagreed with EPA's proposal to disapprove
the limit of 115 ppm at 3% O2 in Rule 4352 for solid fuels
other than municipal solid waste and biomass (i.e., coal, petroleum
coke, and/or tire-derived fuels). The District provided several
arguments in support of its objection to EPA's proposal, each of which
we address in separate comment summaries below.
Response #6: For the reasons discussed below, we have concluded
that the District has not adequately demonstrated that the existing
limit in Rule 4352 for units firing solid fuels other than municipal
solid waste and biomass (i.e., coal, petroleum coke, and/or tire-
derived fuels) (115 ppm at 3% O2) satisfies RACT.
Comment #6.a: The District stated that six facilities in the SJV
area operate seven boilers that are permitted to fire coal, petroleum
coke, and/or tire-derived fuels, and that all of these boilers have
installed SNCR controls, which represent BACT for this source category.
Response #6.a: See Responses 2.c above and 8.d below.
Comment #6.b: The District asserted that EPA's reliance on the
emission levels for coal-fired units in the 1994 ACT (29-65 ppm at 3%
O2 or 0.04 to 0.09 lb/MMBtu) as part of its RACT evaluation
was not appropriate because these emission levels apply only to
fluidized bed combustor (FBC) units fired exclusively on coal. SJVUAPCD
asserted that coal has less fuel-bound nitrogen compared to petroleum
coke and, therefore, results in less NOX formation during
combustion even with the same emission control technology.
Response #6.b: Although we agree with the commenter that coal has
less fuel-bound nitrogen than petroleum coke, this does not provide a
basis for approving the current limit in Rule 4352 as RACT. Likewise,
an argument that the emission levels for coal-fired units provided in
the 1994 ACT (29-65 ppm at 3% O2 or 0.04 to 0.09 lb/MMBtu)
do not reflect reasonably available controls for boilers firing
combinations of coal, petroleum coke, and tire-derived fuels, also does
not demonstrate that the limit in Rule 4352 for these units (115 ppm at
3% O2) satisfies RACT.
In determining the level of control that is reasonably available to
sources in the SJV area, the District must consider new information
that has become available, including information about control levels
currently achieved by similar sources. We note that the range provided
in the 1994 ACT reflects control technologies from over a decade ago,
and that RACT may change over time as new technology becomes available
or the cost of existing technologies decreases. As discussed in the TSD
for our proposed rule, it appears that boilers burning coal, petroleum
coke, and/or tire-derived fuels in the SJV area are generally achieving
NOX emission levels significantly below 115 ppm at 3%
O2, and the 1994 ACT indicates that coal-fired boilers with
SNCR and ammonia injection generally can achieve NOX
emission levels below 115 ppm at 3% O2. See TSD at 6; 1994
ACT at B-19. We also note that use of cleaner-burning fuels, work
practice standards, or other operation and maintenance requirements may
be considered as part of a RACT analysis. See Memorandum dated July 30,
1993, from Michael H. Shapiro, Acting Assistant Administrator for Air
and Radiation, to Air Division Directors, Regions I through X, ``Fuel
Switching to Meet the Reasonably Available Control Technology (RACT)
Requirements for Nitrogen Oxides (NOX)''; Memorandum dated
November 7, 1996, from Sally Shaver, Director, Air Quality Strategies &
Standards Division, to Air Division Directors, Regions I through X,
``Approval Options for Generic RACT Rules Submitted to Meet the non-CTG
VOC RACT Requirement and Certain NOX RACT Requirements.''
The District has provided no technological or economic information to
support a conclusion that these lower emission levels are not
reasonably achievable in the SJV area.
Comment #6.c: SJVUAPCD asserted that it had reviewed EPA's RACT/
BACT/LAER Clearinghouse (RBLC) and had not identified any boilers in
the nation that fire a blend of coal/coke/tire-derived fuel and that
meet the emission range in the 1994 ACT. The District asserted that EPA
should not have referenced this emission range as part of its RACT
evaluation, and that the current limit in Rule 4352 should be
considered RACT for boilers firing coal, petroleum coke, and tire-
derived fuels.
Response #6.c: We disagree. As shown in Table 3 below, the RBLC
identifies several boiler units firing combinations of coal, petroleum
coke, and/or tire-derived fuels that achieve emission levels in the
range provided in the 1994 ACT (29-65 ppm at 3% O2 or 0.04-
0.09 lb/MMBtu). The District has provided no technological or economic
information to support a conclusion that these lower emission levels
are not reasonably achievable in the SJV area. See Response
6.b.
[[Page 60628]]
Table 3--RACT/BACT/LAER Clearinghouse NOX Emission Levels for Boilers Firing Petroleum Coke, Coal, and/or Tire-
Derived Fuels
----------------------------------------------------------------------------------------------------------------
Limit (lb/
RLBC ID Year Fuel Control Technology MMBtu)
----------------------------------------------------------------------------------------------------------------
LA-0202........................ 2006 Pet Coke/Coal............. SNCR...................... 0.07
LA-0223........................ 2008 Pet Coke.................. SNCR...................... 0.07
MI-0258........................ 2001 Coal/Tire/Wood............ SCR....................... 0.06
MS-0075........................ 2003 Wood/Tires................ LNB, overfire air, good 0.0310
combustion practices.
WI-0122........................ 2001 Pet Coke.................. SNCR...................... 0.07
----------------------------------------------------------------------------------------------------------------
Comment #7: SJVUAPCD asserted that ``EPA has consistently
interpreted the Clean Air Act provisions to require only those feasible
measures necessary for expeditious attainment,'' and that ``if a
feasible measure alone or in combination with other measures, cannot
expedite attainment by at least one year then it is not considered to
be reasonably available.'' The District asserted that no additional
emission reduction would be achieved by reducing the limits in Rule
4352 to the NOX limits in the sources' permits ``because the
reduction from affected boilers has already occurred.'' Therefore, the
District argued, ``such action is not necessary for the District's
efforts for expeditious attainment of the ozone and PM2.5 standards.''
Response #7: We disagree. Although EPA has long interpreted the
RACT requirement in section 172(c)(1) of the Act, known as ``subpart 1
RACT,'' as requiring only those control measures that will contribute
to timely attainment and meet reasonable further progress (RFP)
requirements (see 40 CFR 51.912(c) and 70 FR 71612 at 71653 (November
29, 2005)), this is not true for the more specific RACT requirements of
CAA section 182(b)(2), known as ``subpart 2 RACT.'' Section 182 of the
Act requires, for any ozone nonattainment area classified as moderate
or above, a SIP revision to require RACT for all major stationary
sources of NOX that are located in the area, among other
sources. CAA 182(b)(2)(C), 182(f); 40 CFR 51.912(a). These control
measures are mandated whether or not they advance attainment or
contribute to RFP. Because the SJV area is designated and classified as
an extreme ozone nonattainment area (40 CFR 81.305),\8\ the SIP for the
area must meet subpart 2 RACT requirements for all major NOX
sources.
---------------------------------------------------------------------------
\8\ Effective June 4, 2010, the SJV area was reclassified from
``serious'' to ``extreme'' nonattainment for the 8-hour ozone NAAQS.
See 75 FR 24409 (May 5, 2010). The SJV area also remains classified
as ``extreme'' nonattainment for the 1-hour ozone NAAQS. 40 CFR
81.305.
---------------------------------------------------------------------------
In addition, it is not clear that no additional emission reduction
would be achieved by reducing the limits in Rule 4352 for units burning
coal, petroleum coke, and/or tire-derived fuels. As explained above in
Responses 6.b and 6.c, both the 1994 ACT and EPA's
RBLC provide NOX emission levels ranging from 29 to 65 ppm
at 3% O2 (0.04-0.09 lb/MMBtu) for units burning coal,
petroleum coke, and/or tire-derived fuels. Information that the
District submitted to us indicates that the permit limits for units
burning coal, petroleum coke, and/or tire-derived fuels in the SJV area
range between 28 and 146.7 ppm at 3% O2. See Attachment
6 to TSD. Several of these permit limits exceed the
NOX emission levels provided in the 1994 ACT and the RBLC
for comparable units, one of these (146.7 ppm at 3% O2) by a
substantial margin. Absent technical or economic information indicating
that these units cannot reasonably achieve the emission levels
identified in the 1994 ACT and the RBLC, we conclude that the District
has not adequately demonstrated that the NOX limit in Rule
4352 (115 ppm at 3% O2) represents RACT.
Moreover, the permit limits that the District references are not
approved into the SIP. We have no basis for evaluating permit limits
not submitted for SIP approval to support a RACT determination under
section 182(b)(2) of the CAA. See Response 8.d below.
Comment #8: SJVUAPCD disagreed with EPA's proposal to disapprove
the limit of 200 ppm at 12% CO2 in Rule 4352 for units
firing municipal solid waste (MSW). The District provided several
arguments in support of its objection to EPA's proposal, each of which
we address in separate comment summaries below.
Response #8: For the reasons discussed below, we have concluded
that the District has not adequately demonstrated that the existing
limit in Rule 4352 for units firing MSW (200 ppm at 12% CO2)
satisfies RACT.
Comment #8.a: SJVUAPCD stated that there is one facility in the
District that operates two boilers firing MSW, and that both of these
boilers have SNCR controls, which represent BACT. The District asserted
that BACT is more stringent than RACT.
Response #8.a: See Responses 2.c above and 8.d below.
Comment #8.b: SJVUAPCD asserted that the emission levels for MSW-
fired units in the 1994 ACT (52-232 ppm at 3% O2), which EPA
had referenced in the TSD for the proposed rule, are based on ``short
term test data'' which are not necessarily representative of typical
day-to-day operations.
Response #8.b: The comment implies that the emission levels for
MSW-fired units in the 1994 ACT are not appropriate for consideration
as RACT because they are based on emissions data that may not represent
typical operations. This argument is unsupported. ACT documents
describe available control techniques and their cost effectiveness,
although they do not define presumptive RACT, and it is EPA's long-
standing position that States may consider information available in
ACTs to identify available control options as part of a RACT analysis.
See, e.g., 70 FR 71612 at 71654-55 (November 29, 2005) (preamble to
final Phase II ozone implementation rule). The emission levels in the
1994 ACT are based on numerous sources of information in addition to
compliance records, including technical reports, EPA documents, and
manufacturers' literature. See footnote 1 above and 1994 ACT at B-1.
The District's comment does not support an argument that the emission
levels in the 1994 ACT are not appropriate for consideration in a RACT
analysis.
The information provided in the 1994 ACT is, however, over a decade
old and may not provide an accurate picture of current control options.
It is possible that the controls identified in the 1994 ACT are now
more cost-effective or that new control options have since become
available. The District is required to consider not only the
information in the 1994 ACT but also any new information that has
become available in determining the control obligation and emissions
limitation that is consistent with RACT. 70 FR 71612 at 71655.
[[Page 60629]]
Comment #8.c: SJVUAPCD asserted that the MSW-fired boilers in the
SJV area ``operate an SNCR system whereby the amount of ammonia
injected into the flue gas is closely controlled to prevent excessive
ammonia slip,'' and that any increase in ammonia injection above
certain established levels for purposes of achieving additional
NOX reductions would potentially increase PM10
emissions above allowable permit limits.
Response #8.c: SJVUAPCD has not provided information to
substantiate this assertion. Recent source test data for the Covanta
Stanislaus facility, which operates the only two permitted MSW-fired
units in the SJV area, shows average total particulate emissions of
7.58 x 10-3 gr/DSCF for Unit 1 and 7.08 x 10-3
gr/DSCF for Unit 2. See letter dated August 20, 2009, from Richard L.
Wright, Air Quality Inspector, SJUAPCD, to Terry Coble, Covanta
Stanislaus, Inc., enclosing ``Summary of Source Test Results,'' Tables
2.1 and 2.3. These emission levels are well below the facility's permit
limit for total particulate emissions from each unit, which is 0.0275
gr/DSCF. Id. Additionally, the same source test data indicates average
ammonia concentrations in the flue gas of 1.54 ppm for Unit 1 and 3.47
ppm for Unit 2, both of which are well below the ammonia limit of 50
ppm for each unit. Id. Thus, it appears the Covanta Stanislaus facility
could substantially increase the amount of ammonia injection for
purposes of achieving additional NOX reductions without
violating permit requirements. The District's argument is unclear and,
in any case, does not support a conclusion that the NOX
limit in Rule 4352 for MSW-fired units satisfies RACT.
Comment #8.d: SJVUAPCD asserted that although the rule limit for
MSW-fired boilers is 200 ppm at 12% CO2, the existing permit
limit of 165 ppm at 12% CO2 ``is within the range of
limit[s] recommended in the ACT for this boiler type, and therefore the
units meet RACT.''
Response #8.d: It appears the District intended to argue that EPA
should evaluate the permit limits for MSW-fired boilers (165 ppm at 12%
CO2), rather than the limit in Rule 4352 (200 ppm at 12%
CO2), for RACT purposes. This would be appropriate if
SJVUAPCD were to adopt and submit the relevant permit limits for
approval into the SJVUAPCD portion of the California SIP. In this
action, however, we are evaluating Rule 4352 for approval into the SIP,
not the permit limits that the District references. We have no basis
for evaluating permit limits not submitted for SIP approval to support
a RACT determination under section 182(b)(2) of the CAA.
As discussed in the TSD for our proposed action, the NOX
emission limit in Rule 4352 for MSW-fired units is 200 ppm at 12%
CO2, which equates to roughly 266 ppm at 3% O2.
The 1994 ACT provides NOX emission levels for MSW-fired
units ranging between 44 and 210 ppm at 3% O2,\9\ based on
the use of SNCR with ammonia or urea injection. See 1994 ACT at
Appendix B, pg. B-21. The District has provided no technological or
economic information to support a conclusion that these lower emission
levels are not reasonably achievable in the SJV area.
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\9\ The emission levels that the District identifies (52 to 232
ppm at 3% O2) are presented in the TSD for our proposed
action and are calculated based on the lb/MMBtu values shown in
Table 2-6 of the ACT. We note that the values presented in Appendix
B of the Act (44 to 210 ppm at 3% O2) are more reliable.
See fn. 1 above.
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Comment #8.e: SJVUAPCD asserted that EPA's RBLC does not indicate
any BACT emission level for boilers firing MSW fuels. The District
stated that the RBLC does identify a source called Mahoning Renewable
Energy, which operates two boilers that burn refuse-derived fuel (RDF)
and are equipped with Regenerative Selective Catalytic Reduction
(RSCR). Citing EPA's 1994 ACT, the District asserted that ``unlike MSW
and industrial solid waste fuels, which are burned in the same form as
they are received at the boiler site, RDF is fuel processed from
general solid waste'' and is generated by sorting and processing such
solid waste. SJVUAPCD concluded by asserting that because the Mahoning
facility's boilers ``use RSCR and are fired on RDF, RSCR cannot be
considered RACT for boilers fired on MSW fuel.''
Response #8.e: The District's assertion that the RBLC does not
contain BACT emission levels for MSW fuel-fired boilers is not correct
(although we note that these entries are difficult to locate as they
are not categorized under fuel combustion (process type 10), as are
boilers burning other fuels). The RBLC includes MSW fuel-fired boiler
units under the process type 21.400, Waste Combustion Processes. For
example, the Lee County Waste-To-Energy Facility in Florida (RBLC ID
FL-0258) operates two mass-burn municipal waste combustion units that
are equipped with SNCR and subject to an emission limit of 150 ppm at
7% O2 (approximately 143 ppm at 12% CO2). Another
facility identified in the RBLC is the Resource Recovery Facility in
Virginia (RBLC ID VA-0277), which operates two MSW-fired units subject
to an emission limit of 160 ppm at 7% O2 (approximately 152
ppm at 12% CO2).\10\
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\10\ We have converted each of the emission limits we identified
in the RBLC into their approximate equivalent at 12% CO2
to allow for more direct comparison to the emission limit in
SJVUAPCD Rule 4352, which is also expressed in ppm at 12%
CO2. Briefly, using equations available in EPA Method 3B
along with F Factors obtained from Method 19, we calculated the
O2 that should be obtained during combustion if there is
12% CO2 in the flue gas and assumed this O2 in
correcting to 7% O2.
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Additionally, we have examined source test data for other MSW-fired
units to determine what emission limits have been achieved in practice.
The Montenay Pacific Power Corporation has a facility in Long Beach,
California with three MSW fuel-fired units, each of which appears to
have NOX emission levels between 64 and 104 ppm at 7%
O2 (approximately 61-99 ppm at 12% CO2). Eco/
Pittsfield, LLC in Pittsfield, Massachusetts operates three MSW
combustors that appear to have average NOX emissions of 70.4
ppm at 7% O2 (approximately 67 ppm at 12% CO2).
These emission levels are significantly lower than 200 ppm at 12%
CO2.
It appears the District believes that important distinctions
between the use of RDF and MSW as fuel justify the NOX
emission limit in Rule 4352 as RACT, but this argument is not
supported. The District has provided no technical or economic
information to support an argument that the control levels currently
achieved by MSW fuel-fired units elsewhere are not reasonably available
in the SJV area.
Comment #8.f: SJVUAPCD stated that the permits for boilers firing
MSW have stringent limits for numerous hazardous air pollutants,
because the facility is subject to the Federal NESHAP for municipal
solid waste combustors. The District asserted that ``[t]here is no more
emission reduction that would result with the current SNCR system, even
if the rule limit is lowered to the permitted level since the emission
has already been reduced because of more stringent operating permit
emission limits.''
Response #8.f: First, to the extent the District intended to argue
that NESHAP requirements provide a basis for approving the
NOX limits in 4352 as RACT, this argument is unsupported.
Federal NESHAPs regulate hazardous air pollutants under section 112 of
the CAA and do not necessarily establish RACT for NOX
control under section 182 of the Act. The District has provided no
support for an assertion that NESHAP controls satisfy RACT requirements
in this case.
Second, the District appears to assume that lowering the
NOX emission
[[Page 60630]]
limits for MSW-fired units in Rule 4352 to permit levels will satisfy
RACT. This is not correct. Although permit limits can in some cases
indicate a level of emissions control that is reasonably available,
source-specific permit limits do not in themselves establish RACT. See
Response 2.c above.
Finally, the District appears to assert that the permits for MSW-
fired units in the SJV area contain emission limits more stringent than
the limit in Rule 4352. This also does not appear to be correct.
According to the list of permitted solid fuel-fired boilers that the
District provided to us and that we referenced as Attachment 6
to the TSD, the two MSW-fired boilers in the SJV area (at the Covanta
Stanislaus facility) are subject to District-issued permits, both of
which establish a NOX limit of 200 ppm at 12%
CO2. This permit limit is identical to the NOX
emission limit in Rule 4352 for MSW-fired units. The source test data
that we obtained for the Covanta Stanislaus facility indicate that each
of these two MSW-fired units is subject to both a limit of 200 ppm at
12% CO2 and a limit of 175 ppm at 12% CO2, but it
is not clear how and when these different permit limits apply. See
letter dated August 20, 2009, from Richard L. Wright, Air Quality
Inspector, SJUAPCD, to Terry Coble, Covanta Stanislaus, Inc., enclosing
``Summary of Source Test Results,'' Tables 2.1 and 2.3. In any case,
the District has provided no support for its assertion that reducing
the limit in Rule 4352 would result in no emissions reductions because
of ``more stringent operating permit emission limits.'' See also
Response 8.d.
Comment #9: SJVUAPCD stated that the SJV area needs emission
reductions as quickly as feasible and is ``hesitant to divert resources
to conduct work that is not demonstrated to have significant potential
for additional reductions or enforceability.'' SJVUAPCD stated that its
focus on early and voluntary reductions from Fast Track measures,
incentive programs, and the Healthy Air Living program demonstrates the
District's earnest desire to expedite air quality improvement and that
it is conducting a study to determine the feasibility of retrofitting
solid fuel-fired boilers with SCR, in addition to SNCR, to achieve
significant NOX reductions. The District urged that its
efforts not be diverted without clear benefits.
Response #9: As discussed above in Response 7, section 182
of the CAA requires, for any ozone nonattainment area classified as
moderate or above, a SIP revision to require RACT for all major
stationary sources of NOX that are located in the area,
among other sources. CAA 182(b)(2)(C), 182(f); 40 CFR 51.912(a).
Because the SJV area is designated and classified as an extreme ozone
nonattainment area (40 CFR 81.305), the SIP for the area must meet
subpart 2 RACT requirements for all major NOX sources.
We recognize the District's substantial efforts to expedite air
quality improvement in the Valley, and we also recognize that it is not
clear that revising the NOX emission limits in this rule
will result in significant emissions reductions in the SJV area.
Nonetheless, we are obligated to review Rule 4352 for compliance with
the CAA, which requires, among other things, that the SJVUAPCD portion
of the California SIP provide for the implementation of RACT at a
minimum. We note that the District's reevaluation of the NOX
emission limits in Rule 4352 may reveal additional emission reductions
not yet considered and encourage the District to begin this process as
expeditiously as practicable, consistent with CAA requirements.
III. EPA Action
Under CAA sections 110(k)(3) and 301(a) and for the reasons set
forth above and in our December 9, 2009 proposed rule, we are
finalizing a limited approval and limited disapproval of amended
District Rule 4352, as submitted on October 5, 2006. We are finalizing
a limited approval of the submitted rule because we continue to believe
that the rule improves the SIP and is largely consistent with relevant
CAA requirements. This action incorporates amended Rule 4352, including
those provisions identified as deficient, into the District portion of
the Federally-enforceable California SIP. The amended rule approved
herein supersedes the version of Rule 4352 that we approved in February
1999 into the applicable SIP.
We are finalizing a limited disapproval of the submitted rule
because the District has not adequately demonstrated that the
NOX limits in the rule for MSW-fired units, biomass-fired
units, and units burning other solid fuels (e.g., coal, petroleum coke,
and tire-derived fuels) satisfy RACT as required by the CAA. Our
reasons for disapproving the NOX limits for MSW-fired units
and units burning other solid fuels (e.g., coal, petroleum coke, and
tire-derived fuels) are explained in the proposed rule and further in
our responses to comments above. With respect to the NOX
emission limit for biomass-fired units, we are not finalizing our
proposal to approve this limit and are instead disapproving it because
the District has not adequately demonstrated that this emission limit
satisfies RACT, as explained in our responses to comments above. The
final limited disapproval triggers a sanctions clock and EPA's
obligation to promulgate a Federal implementation plan (FIP). Sanctions
will be imposed unless EPA approves subsequent SIP revisions that
correct the rule deficiencies within 18 months of the effective date of
this action. These sanctions would be imposed under section 179 of the
Act according to 40 CFR 52.31. In addition, EPA must promulgate a FIP
under section 110(c) unless we approve subsequent SIP revisions that
correct the rule deficiencies within 24 months of the effective date of
this action. Note that the submitted rule has been adopted by the
SJVUAPCD, and EPA's final limited disapproval does not prevent the
local agency from enforcing it.
IV. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review
The Office of Management and Budget (OMB) has exempted this
regulatory action from Executive Order 12866, entitled ``Regulatory
Planning and Review.''
B. Paperwork Reduction Act
This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Burden is defined at 5 CFR 1320.3(b).
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to conduct a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements unless the agency certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. Small entities include small
businesses, small not-for-profit enterprises, and small governmental
jurisdictions.
This rule will not have a significant impact on a substantial
number of small entities because SIP approvals and limited approvals/
limited disapprovals under section 110 and subchapter I, part D of the
Clean Air Act do not create any new requirements but simply approve
requirements that the State is already imposing. Therefore, because
this limited approval/limited disapproval action does not create any
new requirements, I certify that this action will not have a
significant economic impact on a substantial number of small entities.
[[Page 60631]]
Moreover, due to the nature of the Federal-State relationship under
the Clean Air Act, preparation of flexibility analysis would constitute
Federal inquiry into the economic reasonableness of State action. The
Clean Air Act forbids EPA to base its actions concerning SIPs on such
grounds. Union Electric Co., v. U.S. EPA, 427 U.S. 246, 255-66 (1976);
42 U.S.C. 7410(a)(2).
D. Unfunded Mandates Reform Act
Under sections 202 of the Unfunded Mandates Reform Act of 1995
(``Unfunded Mandates Act''), signed into law on March 22, 1995, EPA
must prepare a budgetary impact statement to accompany any proposed or
final rule that includes a Federal mandate that may result in estimated
costs to State, local, or tribal governments in the aggregate; or to
the private sector, of $100 million or more. Under section 205, EPA
must select the most cost-effective and least burdensome alternative
that achieves the objectives of the rule and is consistent with
statutory requirements. Section 203 requires EPA to establish a plan
for informing and advising any small governments that
