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

1The 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 

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 (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 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 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 

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 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 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

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60624 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations 

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. 

2The 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). 

3Note 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. 

4We 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. 

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 

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 

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 

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Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations 60625 

5See fn. 4, supra, for an explanation of the 

conversion methodology from ppm at 12% CO2 to 

ppm at 3% O2. 

6The 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 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 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 

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 

Test 

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 

(PCAPCD).

2009 51.2 ppm at 12% CO2 (∼103 ppm 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). 

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60626 Federal Register / Vol. 75, No. 190 / Friday, October 1, 2010 / Rules and Regulations 

7SJVUAPCD 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 

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 

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 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 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 

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

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 

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

8Effective 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. 

TABLE 3—RACT/BACT/LAER CLEARINGHOUSE NOX EMISSION LEVELS FOR BOILERS FIRING PETROLEUM COKE, COAL, 

AND/OR TIRE-DERIVED FUELS

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 

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 

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 

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

9The 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. 

10We 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. 

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 

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 

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 

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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 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 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 

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

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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 

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