## SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Appendix C: EPA Documents December 15, 2011

C – 1 Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 

# APPENDIX C

Federal Register Notice

And EPA Technical Support Document (TSD)

December 15, 2011

## SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

APPENDIX C: EPA Documents December 15, 2011

Final Staff Report with Appendices for Revised Proposed Amendments to Rule 4352 

## C - 2 This page intentionally blank.

### 60623 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations

1 The range of emission levels that Earthjustice identifies (23 to 155 ppm at 3% O 2 ) are presented in the TSD for our proposed action and are
calculated based on the lb/MMBtu values shown in

Continued **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 (NO X ) 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 http:// 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 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 NO X emission limit for biomass fuel-fired units, SJVUAPCD has not adequately demonstrated that the NO X emission limits ( i.e., NO X 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 NO X 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
NO X 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 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 NO X 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 NO Xemission 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 comment and agree that the District has failed to provide adequate support for its conclusion that the NO X 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
NO X emission limit of 115 ppm at 3%
O 2 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 NO X levels ranging from 23 to 155 ppm at 3%
O 2 for wood-fired boilers with fluidized bed combustors. Additionally, Earthjustice asserted that this range of
NO X 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
NO X emission limit in Rule 4352 for biomass-fired boilers (115 ppm at 3%
O 2 ) 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% O 2 ). 1


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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% O 2 ) 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. 4 We have converted the emission limit into its approximate equivalent at 3% O 2 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% O 2 . Briefly, using equations available in EPA Method 3B along with F Factors obtained from Method 19, we calculated the O 2 that should be obtained during combustion if there is 12% CO 2 in the flue gas and corrected the NO 2 concentration obtained to 3% O 2
. As to the commenter’s assertion that the range of emission levels in the 1994 ACT undermines EPA’s conclusion that
a NO X 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 NO X 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% O 2 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 NO X emission limits in these rules. None of these districts provided information indicating that any biomass-fired boiler has achieved a NO X limit of 40 ppm at 3% O 2.

Specifically, we are not aware of any biomass-fired boiler that is or has been subject to the 40 ppm NO X 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 BAAQMDhas issued one permit for a biomassfired 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% O 2
. 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 NO X emission limits until it ceased operating in March 1996. See Response #2.b, below. We have no information indicating that a NO X emission level of 40 ppm at 3% O 2 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 NO X emission levels for biomass-fueled boilers ranging from 24 ppm to 187 ppm at 3% O 2 , 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 NO X 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 NO X emission levels ranging from 25 to 160 ppm at 3%
O 2 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
NO X emission level of 40 ppm at 3% O 2 is reasonably achievable for such boilers generally. It does, however, warrant amore 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 NO X 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 NO X emission limit in Rule 411 is expressed in parts per million corrected to 12% carbon dioxide (ppm at 12%
CO 2 ), which equates to approximately 100 ppm at 3% O 2
. 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% O 2 (not 70 ppm at 3% O 2 ) in SMAQMD’s Rule 411 and a limit of 115 ppm at 3% O 2 in SJVUAPCD’s Rule

4352.

Second, to the extent the commenter intended to argue that an emission level of 70 ppm at 3% O 2 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


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5 See fn. 4, supra, for an explanation of the conversion methodology from ppm at 12% CO 2 to ppm at 3% O 2
.

6 The 1995 version of SMAQMD Rule 411 also contained a lower limit of 70 ppm at 12% CO 2 (

∼ 100 ppm at 3% O 2 ) 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 NO X emission limit of 110 ppm at 12% CO 2 (

∼ 156 ppm at 3% O 2 ) but retaining the NO X emission limit of 70 ppm at 12% CO 2 (

∼ 100 ppm at 3% O 2 ). At that time, however, no facility in the SMAQMD area operateda biomass-fired boiler subject to this limit. See email dated May 13, 2010, from Bruce Nixon (SMAQMD) to Idalia Perez (EPA Region 9). 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 NO X emissions from biomass-fired boilers of 110 ppm at 12% CO 2, or approximately 156 ppm at 3% O 2
. 5 See Section 303.1, Rule 411 (as adopted February 2, 1995). Notably, this limit was significantly higher than the NO X limit for biomassfired boilers in SJVUAPCD’s current Rule 4352 (115 ppm at 3% O 2 ).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% O 2 , this does not demonstrate that
a NO X emission limit of 70 ppm at 3%
O 2 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% CO 2 (

∼ 100 ppm at 3% O 2 ) 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
NO X 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% O 2 . 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 NO X limit in Rule 4352 (115 ppm at 3% O 2 ) represents
RACT.

Ten biomass-fired boilers in the SJV area are currently subject to the NO X emission limit in Rule 4352. We have reviewed source test data for four of these units and found that each unit is achieving actual NO X emission levels between 44 and 79 ppm at 3% O 2 . We also evaluated source test data for two biomass-fired units in Placer County and one unit in Yolo County, California, which indicate actual NO X emission levels between 45 and 103 ppm at 3%
O 2
. See Table 1. These source test results indicate that biomass-fired units both within the SJV area and elsewhere in California are currently achieving
NO X emission levels significantly below 115 ppm at 3% O 2.



### T ABLE 

### 1—NO X 

### S OURCE 

### T EST 

### D ATA FOR 

### S ELECTED 

### B OILERS 

### F IRING 

### B IOMASS IN 

### CA

Facility Air district Test
year Emission

Madera Power, LLC ................................... SJVUAPCD ......................... 2009 44.3 ppm at 3% O 2

. Covanta Delano, Inc .................................. SJVUAPCD ......................... 2009 Unit 1—0.07 lbs/MMBtu (

∼ 54 ppm at 3% O 2 )

Unit 2—0.063 lbs/MMBtu (

∼ 49 ppm at 3% O 2 ). Sierra Power Corporation .......................... SJVUAPCD ......................... 2009 78.7 ppm at 3% O 2

. Sierra Pacific Industries, Lincoln ................ Placer County APCD (PCAPCD). 2009 51.2 ppm at 12% CO 2 (

∼ 103 ppm at 3% O 2 ).

Rio Bravo Rocklin ...................................... PCAPCD ............................. 2009 37.6 ppm at 12% CO 2 (

∼ 76 ppm at 3% O 2 ) Woodland Biomass Power, LTD ................ Yolo-Solano APCD .............. 2010 45.34 ppm at 3% O 2

.

The remaining six biomass-fired units in the SJV area are subject to NO X permit limits ranging from 62 to 83 ppm at 3% O 2 . See Table 2.



### T ABLE 

### 2—NO X 

### P ERMIT 

### L IMITS FOR 

### B IOMASS 

### F ACILITIES IN 

### SJVUAPCD

Permit No. Size of unit NO X Limit

C–825 ......................................................... 317 MMBtu/hr ........................................... 27.8 lb/hr (

∼ 83 ppm at 3% O 2 ). C–1820 ....................................................... 352 MMBtu/hr ........................................... 0.08 lb/MMBTU (

∼ 62 ppm at 3% O 2 ).
N–1026 ....................................................... 259 MMBtu/hr ........................................... 27.2 lb/hr (

∼ 83 ppm at 3% O 2 ). N–4607 ....................................................... 185 MMBtu/hr ........................................... 0.08 lb/MMBtu (

∼ 83 ppm at 3% O 2 ). S–285 ......................................................... 11.5 MW ................................................... 0.09 lb/MMBtu (

∼ 70 ppm at 3% O 2 ). C–6923 ....................................................... 185 MMBtu/hr ........................................... 0.08 lb/MMBtu (

∼ 62 ppm at 3% O 2 ).


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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.

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
NO X 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 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 NO X 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 NO X 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 http:// 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 NO X emission level of 70 ppm at 3% O 2 has been achieved by a biomassfired 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% O 2 are currently being achieved. See Responses #2.b. and #2.c above. We are disapproving all of the NO X 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 requestedconfirmation 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 publiccomment 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 NO X isalso 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 NO X ). 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 NO X 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
NO X 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% O 2 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%
O 2 ) satisfies RACT.

Comment #6.a: The District stated that six facilities in the SJV area operate seven boilers that are permitted to firecoal, 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% O 2 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 NO X 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% O 2 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% O 2 ) 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 NO X emission levels significantly below 115 ppm at 3% O 2 ,and the 1994 ACT indicates that coalfired boilers with SNCR and ammonia injection generally can achieve NO X emission levels below 115 ppm at 3%
O 2
. 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 (NO X ) ’’ ; 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 NO X 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 thenation 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% O 2 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.


### 60628 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations

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.



### T ABLE 

### 3—RACT/BACT/LAER C LEARINGHOUSE 

### NO X 

### E MISSION 

### L EVELS FOR 

### B OILERS 

### F IRING 

### P ETROLEUM 

### C OKE 

### , C OAL



### , AND 

### / OR 

### T IRE 

### -D ERIVED 

### F UELS

RLBC ID Year Fuel Control Technology Limit (lb/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 combustion practices ......... ......... 0 .0310 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
NO X 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 NO X 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 NO X sources.

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 NO X emission levels ranging from 29 to 65 ppm at 3% O 2 (0.04–0.09 lb/MMBtu) for units burningcoal, 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% O 2
. See Attachment #6 to TSD. Several of these permit limits exceed the NO X emission levels provided in the 1994 ACT and the RBLC for comparable units, one of these (146.7 ppm at 3% O 2 ) 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 NO X limit in Rule 4352 (115 ppm at 3% O 2 ) 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% CO 2 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% CO 2 ) 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% O 2 ), 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.


### 60629 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations

9 The emission levels that the District identifies (52 to 232 ppm at 3% O 2 ) 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% O 2 )
are more reliable. See fn. 1 above. 10 We have converted each of the emission limits we identified in the RBLC into their approximate equivalent at 12% CO 2 to allow for more direct comparison to the emission limit in SJVUAPCD Rule 4352, which is also expressed in ppm at 12%
CO 2 . Briefly, using equations available in EPA Method 3B along with F Factors obtained from Method 19, we calculated the O 2 that should be obtained during combustion if there is 12% CO 2 in the flue gas and assumed this O 2 in correcting to 7% O 2
. 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 NO X reductions would potentially increase
PM 10 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 NO X reductions without violating permit requirements. The District’s argument is unclear and, in any case, does not support a conclusion that the NO X limit in Rule 4352 for MSW-fired units satisfies RACT.

Comment #8.d: SJVUAPCD assertedthat although the rule limit for MSWfired boilers is 200 ppm at 12% CO 2 , the existing permit limit of 165 ppm at 12%
CO 2 ‘‘ 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 shouldevaluate the permit limits for MSWfired boilers (165 ppm at 12% CO 2 ), rather than the limit in Rule 4352 (200 ppm at 12% CO 2 ), 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 NO X emission limit in Rule 4352 for MSW-fired units is 200 ppm at 12% CO 2 , which equates to roughly 266 ppm at 3% O 2. The 1994 ACT provides NO X emission levels for MSW-fired units ranging between 44 and 210 ppm at 3% O 2, 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, whichoperates 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% O 2 (approximately 143 ppm at 12% CO 2 ). 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% O 2 (approximately 152 ppm at 12% CO 2 ). 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 NO X emission levels between 64 and 104 ppm at 7%
O 2 (approximately 61–99 ppm at 12%
CO 2 ). Eco/Pittsfield, LLC in Pittsfield, Massachusetts operates three MSW combustors that appear to have average
NO X emissions of 70.4 ppm at 7% O 2 (approximately 67 ppm at 12% CO 2 ). These emission levels are significantly lower than 200 ppm at 12% CO 2.

It appears the District believes that important distinctions between the use of RDF and MSW as fuel justify the NO X 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 NO X 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 NO X 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 NO X emission


### 60630 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations

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 NO X limit of 200 ppm at 12% CO 2 . This permit limit is identical to the NO X 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% CO 2 and a limit of 175 ppm at 12%
CO 2 , 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 NO X 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 NO X 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 NO X 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 NO X 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 NO X 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 NO X 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 NO X 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 NO X 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.


### 60631 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations

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 section205, 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 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 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


### 60632 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**

**AGENCY :**  Environmental Protection Agency (EPA).

**ACTION :**  Direct final rule.

**SUMMARY :**  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 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).

**ADDRESSES :**  Submit your comments, identified by Docket ID No. EPA–R06– RCRA–2010–0066 by one of the following methods:

1. Federal eRulemaking Portal: http://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 http:// www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http:// www.regulations.gov or e-mail. The http://www.regulations.gov Web site is

an ‘‘ anonymous access ’’ system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through http:// 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 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 http://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 http:// 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 INFORMATION CONTACT :**  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.

**SUPPLEMENTARY INFORMATION :**  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


## United States Environmental Protection Agency, Region 9

Air Division

Technical Support Document

for

EPA’s Notice of Proposed Rulemaking

for the

California State Implementation Plan

San Joaquin Valley Unified Air Pollution Control District’s

Rule 4352, Solid Fuel Fired Boilers, Steam Generators and Process Heaters

Prepared by: Idalia Perez

October 2009

## - 2

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## San Joaquin Valley Unified Air Pollution Control District (SJVAPCD)

Submitted Rule SJVAPCD Rule 4352, Solid Fuel Fired Boilers, Steam Generators and Process Heaters

• Adopted: May 18, 2006

• Submitted: October 5, 2006

• Determined complete: October 24, 2006 EPA published a proposal and direct final approval of this rule on May 30, 2007 (72 FR 29886). We received adverse comments and consequently withdrew the direct final approval (72 FR 41450).

Previous Rule Submittals There are no outstanding submittals of Rule 4352.

SIP-Approved Rule

• Adopted: October 19, 1995

• Approved by EPA: February 11, 1999 (64 FR 6803)

Rule Summary Rule 4352 limits NOx and CO emissions from solid fuel fired boilers, steam generators and process heaters. The facilities in SJVAPCD that are subject to Rule 4352 burn a variety of fuels including biomass, agricultural waste, wood waste, coal, tire derived fuel, petroleum coke and municipal solid waste (MSW). The submitted rule revisions include:

• More stringent applicability threshold: the revised rule applies to solid fuel-fired boilers, steam generators, or process heaters located at sources that have potential NOx or VOC emissions of at least 10 tons per year (tpy), which is lower than the applicability threshold of 50 tpy in the SIP rule.

• More stringent NOx emission limits for units firing biomass and other non-MWS solid fuels, in Section 5.1.

• Alternative requirements for start-up and shutdown operations in Section 5.3.

• New provisions authorizing the APCO, ARB, and EPA to approve an owner/operator’s request (accompanied by appropriate justification) for an increased emission limit for a unit operated at less than 50 percent of rated heat input, in Section 5.4.

• Various minor clarifications.

Sources and Rule Requirements The following are the uncontrolled NOx emissions from this source category, according to the 1994 ACT for ICI boilers (see Guidance Document #5, Table 2-2): Fuel Boiler Type Uncontrolled NOx (lb/MMBtu) Approximate

ppm at 3% O 2 

## Coal Fluidized bed combustor (FBC) 0.14 – 0.60 109 – 466

Wood > 70 MMBtu/hr 0.17 – 0.30 124 – 218

MSW Mass burn 0.40 300

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## The following are the levels to which NOx emissions may be controlled for units with Selective Non-Catalytic Reduction (SNCR with ammonia injection), according to the 1994 ACT for ICI boilers (see Guidance Document #5, Tables 2-6): Fuel Boiler Type Controlled NOx (lb/MMBtu) Approximate

ppm at 3% O 2 

## Coal FBC 0.04 – 0.09 29 – 65

Wood FBC 0.03 – 0.20 23 – 155

MSW Stoker and mass burn 0.07 – 0.31 52 – 232

Effective January 1, 2007, Rule 4352 limits NOx emissions from MSW-fired units to 200 ppm at
12% CO 2 

## (about 266 ppm at 3% O 2 

## ) and NOx emissions from units fired by all other solid fuels, including biomass, to 115 ppm at 3% O 2 

## . Both the SIP rule and the revised rule require that the NOx emission limits be averaged over 24 hours.

SJVAPCD provided EPA with a list of permitted units subject to Rule 4352 (Attachment #6). This list identifies one facility subject to the emission limits for MSW in Rule 4352, and 13 facilities burning coal, coke, biomass or other fuels that are subject to the emission limits for all other solid fuels. This list also indicates that all of these units have installed and are operating SNCR equipment.

Effect on Emissions SJVAPCD’s staff report (Attachment #3) does not claim emission reductions from implementation of these rule revisions, as all units subject to Rule 4352 already comply with the NOx emission limits that became effective locally on January 1, 2007.

Rule Evaluation Criteria Generally, SIP rules must be enforceable (see §110(a) of the Clean Air Act, hereafter CAA); must require Reasonably Available Control Technology (RACT) for major sources of NOx in nonattainment areas (see CAA §182(b)(2) and (f)); must not interfere with applicable requirements, including requirements concerning attainment (see CAA §110(l)); and must not relax existing requirements in effect prior to enactment of the 1990 CAA amendments (see §193).

SJVAPCD regulates an extreme nonattainment area for the 1-hour ozone standard and a serious nonattainment area for the 8-hour ozone standard (40 CFR 81), so submitted Rule 4352 must fulfill RACT requirements. Rule 4352 must also require the use of advanced control technologies to control NOx emissions from this source category (see CAA §182(e)(3)).

Guidance and policy documents that we used to define enforceability and RACT requirements include the following:

1. Issues Relating to VOC Regulation, Cutpoints, Deficiencies, and Deviations (the "Blue Book"), US EPA, OAQPS (May 25, 1988).

2. Guidance Document for Correcting Common VOC and Other Rule Deficiencies , EPA Region IX (August 21, 2001, the “Little Bluebook”).

## - 4

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## 3. State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990, 57 FR 13498 (April 16, 1992); 57 FR 18070 (April 28, 1992).

4. State Implementation Plans; Nitrogen Oxides Supplement to the General Preamble; Clean Air Act Amendments of 1990 Implementation of Title I; Proposed Rule, 57 FR 55620, November 25, 1992 (the NOx Supplement).

5. Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technology for Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters , CARB (July 18, 1991). http://www.arb.ca.gov/ractbarc/boilers.pdf

6. Alternative Control Techniques Document-- NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers

, US EPA 453/R-94-022 (March 1994). http://www.epa.gov/ttn/catc/dir1/icboiler.pdf

7. Alternative Control Techniques Document-- NOx Emissions from Utility Boilers , US EPA 453/R-94-023 (March 1994). http://www.epa.gov/ttn/catc/dir1/utboiler.pdf

SJVAPCD is currently designated attainment for PM 10 

## (40 CFR 81.305). Accordingly, SJVAPCD is not subject to the requirement to implement BACM for PM 10 

## and PM 10 

## precursors in CAA § 189(b) and (e). Therefore, we are not evaluating Rule 4352 for compliance with BACM requirements.

Discussion of Enforceability and Relaxation Criteria We believe the submitted rule revisions adequately fulfill most of the relevant criteria identified above. Specifically:

• Recordkeeping and other compliance provisions in the rule ensure that the requirements are adequately enforceable.

• The change in the applicability threshold from 50 tpy to 10 tpy significantly expands the rule’s applicability.

• Inclusion of more stringent NOx emission limits make the submitted rule more stringent than the version previously approved into the SIP, so the submitted rule does not relax the SIP and complies with CAA §110(l) and §193.

Discussion of Advanced Control Technology Section 182(e)(3) of the Act requires that SIPs for extreme ozone nonattainment areas contain provisions requiring that each new, modified, and existing electric utility and industrial and commercial boiler that emits more than 25 tpy of NOx either: (1) burn as its primary fuel a clean fuel (natural gas, methanol, or ethanol, or a comparably low polluting fuel), or (2) use advanced control technology (such as catalytic control technology or other comparably effective control methods) to reduce NOx emissions. We believe the term "catalytic control technology" was intended generally to refer to selective catalytic reduction (SCR).

Rule 4352 applies to commercial and industrial boilers (in addition to other types of emission units) at facilities that potentially emit 10 tpy or more of NOx, which includes all boilers that emit more than 25 tpy of NOx. All of the NOx emission limits in the revised rule effectively require operation of Selective Noncatalytic Reduction (SNCR) control systems. We believe SNCR is "comparably effective" to SCR for the affected sources as discussed below, and thus

## - 5

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## fulfills Section 182(e)(3) requirements for these affected sources. SNCR also appears to achieve NOx emission reductions comparable to combustion of clean fuels at these types of
boilers.

According to information in the RACT/BACT/LAER Clearinghouse, recent Prevention of Significant Deterioration (PSD) permits contain emission limits for coal-fired boilers ranging from 0.067 lbs/MMBtu (for large coal-fired boilers with SCR and low-NOx burner technology) to 0.1 lbs/MMBtu (for medium-sized coal-fired boilers with SNCR). These limits reflect Best Available Control Technology (BACT) determinations under the PSD program. According to the 1994 ACT for ICI boilers (see Guidance Document #5, Tables 2-6), wood-fired watertube
boilers with SCR can achieve NOx emissions of 0.22 lb/MMBtu. The 1994 ACT does not contain emission levels for wood-fired FBC boilers with SCR but states that this type of unit with SNCR can achieve NOx emission limits ranging from 0.03 to 0.20 lb/MMBtu.

Our review of these emission ranges indicates that although emission rates can vary according to fuel type and boiler size, generally SNCR controls are comparably effective to SCR for boilers firing wood (biomass), MSW, and many other types of solid fuels. As a general matter, SNCR is also comparably effective to SCR control for circulating fluidized bed coal-fired boilers of less than 50 MW electric generation capacity. For coal-fired boilers, we have focused our review on circulating fluidized bed boilers of less than 50 MW generation capacity because all existing coal-fired boilers in SJV are of this type and below this size. The emission levels achieved by SNCR control systems are also generally comparable to the uncontrolled NOx emissions from boilers firing clean fuels such as natural gas, which may range from 0.07 to 0.45 lb/MMBtu (see Guidance Document #5, Table 2-2). SNCR control systems consistently achieve up to 80% NOx emission reductions and are compatible with almost all solid fuel-fired boiler operations, while other controls may in some cases be sensitive to catalyst poisoning and other technical constraints. As to boilers that emit above 25 tpy of NOx, we note as a practical matter that only existing boilers in SJV are likely to be constrained by the NOx emission limits in Rule 4352, as all new boilers that potentially emit above 25 tpy and all major modifications at existing boilers will also be subject to the more stringent control technology requirements of the Nonattainment New Source Review (NNSR) or PSD permit programs. The requirements of Rule 4352 are generally applicable to this source category and do not supplant any more stringent control requirements that apply on a case-by-case basis under the NNSR or PSD permit programs.

Discussion of RACT Criteria On April 16, 2009, SJVAPCD adopted its “2009 RACT SIP” to demonstrate that RACT is implemented for all appropriate activities (see Attachment #5 for relevant pages). In summary, SJVAPCD found that Rule 4352 met or exceeded the analogous NSPS, and found no applicable CTG, NESHAP or MACT standards. The document also compared Rule 4352 to analogous rules in other large California nonattainment areas including South Coast, Bay Area, Sacramento and Ventura. These rules contain a 40 ppm limit for non-gaseous fuels. Sacramento Rule 411 includes a 70 ppm limit at 12% CO 2 

## (about 100 ppm at 3% O 2 

## ) for biomass fuels. SJVAPCD states that these limits are more stringent than Rule 4352, but have not been demonstrated for
solid fuel-fired units because there are no boilers in the Sacramento area that fire solid fuels.

## - 6

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## Furthermore, SJVAPCD states that the 40 ppm limit for non-gaseous fuels in ARB’s RACT/BARCT guidelines was never intended for application to solid fuel-fired units.

We concur with SJVAPCD’s conclusion that Rule 4352 implements RACT for units fired with biomass fuels for reasons including:

• The relevant Rule 4352 requirements are more stringent than both 1994 ACT documents listed above. ACT documents provide technical information on available controls and are often used to help define RACT.

• No facilities in Sacramento currently operate boilers that meet the 70 ppm limit for biomass-fired units in Rule 411, so this limit has not been shown to be technologically feasible. (Email from Jorge de Guzman at Sacramento Metropolitan AQMD to Roger Kohn at EPA on September 10, 2009).

• We have no information indicating that the 40 ppm limit for non-gaseous fuels in other districts’ rules has been demonstrated to be generally technologically feasible for biomass

fuel-fired units.

• According to Attachment #6, all permitted units subject to Rule 4352 are equipped with SNCR. We believe SNCR technology generally achieves a RACT level of control for this source category as it is effective at reducing NOx emission and is, to our knowledge, the only technique that is currently widely available for this source category.

We do not believe, however, that SJVAPCD has adequately demonstrated that the Rule 4352 NOx emission limits for units fired with MSW (approximately 266 ppm at 3% O 2 

## ) and for units fired with coal/coke and other solid fuels (i.e., solid fuels other than MSW and biomass) (115 ppm at 3% O 2 

## ) achieves a RACT level of control for these source categories, for reasons including:

• The 1994 ACT for ICI boilers (Guidance Document #5) indicates that lower NOx emissions should be reasonably achievable with SNCR controls that existing units subject to Rule 4352 currently have installed.

• SJVACPD does not provide sufficient information to demonstrate that the emission ranges present in the 1994 ACT for ICI boilers are not reasonably achievable or other information to demonstrate that Rule 4352 satisfies RACT requirements.

• Source test data for the one existing MSW facility in the San Joaquin Valley suggests that emission limits lower than required by Rule 4352 are reasonably achievable (see Attachment #7). In 1994, units 1 and 2 tested at an average of 139 ppm and 129 ppm at
12% CO 2 

## . In 2009, they tested at an average of 146 ppm and 143 ppm at 12% CO 2 

## . It is not clear why a limit close to those ranges, consistent with the 1994 ACT is not appropriate for RACT.

• Emission limits for permitted coal-burning facilities in Attachment #6 suggest that limits lower than contained Rule 4352 are reasonably achievable. Specifically, Attachment #6 identifies only one existing facility with a permit emission limit above 0.1 lb/MMBtu (approximately 75 ppm at 3% O 2 

## ).

• For coal fired units, the ACT also states that units with ammonia injection should be able to achieve lower emissions than the 115 ppm at 3% O 2



## .

• While we believe that SNCR may represent RACT for these sources, and the NOx limits in the existing rule effectively require SNCR, we nonetheless believe it is appropriate to

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## require more stringent emission limits in Rule 4352 to ensure that facilities maintain good operating and maintenance practices consistent with CAA RACT requirements.

Rule Deficiency

• SJVAPCD has not demonstrated that the emission limits for units firing MSW fuels or other non-biomass solid fuels implement RACT. The NOx emission limits for these source categories in Rule 4352 should be lowered to ensure implementation of RACT. Alternatively, SJVAPCD may submit additional information to demonstrate that lower emission limits are not reasonably achievable.

Suggested Rule Improvement EPA recommends that the SJVAPCD make the following improvements in the next revision of
Rule 4352:

1. The term flame stabilization period in Section 2.0 should be clearly defined in the Rule.

2. Section 5.4.2 should indicate that source test information at the reduced load should be included in a request for increased emission limits for units operating at less than 50% of the rated heat input.

3. The term normal operations in Section 6.3.2 should be clearly defined in the Rule or the Rule should state that it must be defined in the permit to operate.

4. The Rule does not specify required controls for direct PM2.5 emissions. These should be added in subsequent revisions of the Rule.

Recommendation EPA staff recommends limited approval and limited disapproval of SJVAPCD’s submitted rule 4352 for incorporation into the San Joaquin Valley portion of the California SIP.

Attachments

1. Submitted Rule 4352 (Clean Copy, Adopted May 18, 2006)

2. Submitted Rule 4352 (Strikeout Copy, Adopted May 18, 2006)

3. Staff Report (Adopted May 18, 2006)

4. SIP-approved version of Rule 4352 (Adopted October 19, 1995)

5. SJVAPCD RACT Demonstration for Ozone SIP, pages 4-61 – 4-68 (Adopted April 16, 2009)

6. List of Solid Fired units in SJVAPCD

7. Source Test Report summaries for MSW facility

## SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DI STRICT

Appendix C: EPA Documents December 15, 2011

C - 20 Final Staff Report with Appendices for Revised Proposed Amendments t o Rule 4352 

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