66548 Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have Federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the CAA; and 

• Does not provide EPA with the 

discretionary authority to address, as 

appropriate, disproportionate human 

health or environmental effects, using 

practicable and legally permissible 

methods, under Executive Order 12898 

(59 FR 7629, February 16, 1994). 

In addition, this rule does not have 

tribal implications as specified by 

Executive Order 13175 (65 FR 67249, 

November 9, 2000), because the SIP is 

not approved to apply in Indian country 

located in the state, and EPA notes that 

it will not impose substantial direct 

costs on tribal governments or preempt 

tribal law. 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

Under section 307(b)(1) of the CAA, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by January 7, 2013. Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this action for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. (See section 

307(b)(2).) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Particulate matter, Reporting 

and recordkeeping requirements. 

Dated: October 19, 2012. 

Susan Hedman, 

Regional Administrator, Region 5. 

40 CFR part 52 is amended as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

■ 2. In § 52.1170 the table in paragraph 

(e) is amended by adding a new entry 

for ‘‘1997 Annual Fine Particulate 

Matter 2005 Base Year Emissions 

Inventory’’ at the end of the table to read 

as follows: 

§ 52.1170 Identification of plan. 

* * * * * 

(e) * * * 

EPA-APPROVED MICHIGAN NONREGULATORY AND QUASI–REGULATORY PROVISIONS

Name of nonregulatory SIP provision Applicable geographic 

or nonattainment area 

State submittal date EPA approval date Comments 

*******

1997 Annual Fine Particulate Matter 2005 Base 

Year Emissions Inventory.

Detroit-Ann Arbor area 

(Livingston, Macomb, 

Monroe, Oakland, St. 

Clair, Washtenaw, 

and Wayne Counties).

6/13/08 11/6/12 [INSERT CITATION OF PUBLICATION].

[FR Doc. 2012–26962 Filed 11–5–12; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R09–OAR–2012–0266; FRL–9736–9] 

Revisions to the California State 

Implementation Plan, San Joaquin 

Valley Unified Air Pollution Control 

District 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is approving revisions to 

the San Joaquin Valley Unified Air 

Pollution Control District (SJVUAPCD) 

portion of the California State 

Implementation Plan (SIP). This action 

was proposed in the Federal Register on 

April 26, 2012 and concerns oxides of 

nitrogen (NOX) from solid fuel fired 

boilers. We are approving a local rule 

that regulates these emission sources 

under the Clean Air Act (CAA or the 

Act). 

DATES: This rule will be effective on 

December 6, 2012. 

ADDRESSES: EPA has established docket 

number EPA–R09–OAR–2012–0266 for 

this action. Generally, documents in the 

docket for this action are available 

electronically at http:// 

www.regulations.gov or in hard copy at 

EPA Region IX, 75 Hawthorne Street, 

San Francisco, California. While all 

documents in the docket are listed at 

http://www.regulations.gov, some 

information may be publicly available 

only at the hard copy location (e.g., 

copyrighted material, large maps, multivolume reports), and some may not be 

available in either location (e.g., 

confidential business information 

(CBI)). To inspect the hard copy 

materials, please schedule an 

appointment during normal business 

hours with the contact listed in the FOR

FURTHER INFORMATION CONTACT section. 

FOR FURTHER INFORMATION CONTACT: 

Idalia Pe ́rez, EPA Region IX, (415) 972– 

3248, perez.idalia@epa.gov. 


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Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 66549 

1See U.S. EPA Region 9, ‘‘Technical Support 

Document for EPA’s Notice of Proposed 

Rulemaking for the California State Implementation 

Plan, San Joaquin Valley Unified Air Pollution 

Control District’s Rule 4352, Solid Fuel Fired 

Boilers, Steam Generators and Process Heaters,’’ 

April 2012 (TSD). 2See Air Pollution Control Operating Permit, 

Permit Activity No. BOP090001, Covanta Essex Co. 

(Essex PTO) at pg. 57 of 95. 

3See Air Pollution Control Operating Permit, 

Permit Activity No. BOP090002, Covanta Warren 

Energy Resource Co. LP (Warren PTO) at pp. 57 and 

60 of 101. 

SUPPLEMENTARY INFORMATION: 

Throughout this document, ‘‘we,’’ ‘‘us’’ 

and ‘‘our’’ refer to EPA. 

Table of Contents 

I. Proposed Action 

II. Public Comments and EPA Responses 

III. EPA Action 

IV. Statutory and Executive Order Reviews 

I. Proposed Action 

On April 26, 2012 (77 FR 24883), EPA 

proposed to approve the following rule 

into the California SIP. 

Local agency Rule 

No. Rule title Adopted Submitted 

SJVUAPCD ................................... 4352 Solid Fuel Fired Boilers, Steam Generators and Process Heaters .... 12/15/11 02/23/12 

We proposed to approve this rule 

based on our conclusion that it complies 

with the relevant CAA requirements. 

Our proposed rule and Technical 

Support Document (TSD) 1 contain 

moreinformation onthe rule and our 

evaluation. 

II. Public Comments and EPA 

Responses 

EPA’s proposed action provided a 30- 

day public comment period. During this 

period, we received comments from the 

following party. 

1. Adenike Adeyeye, Earthjustice; 

letter dated and received May 29, 2012. 

The comments and our responses are 

summarized below. 

Comment #1: Earthjustice stated that 

these revisions are an improvement over 

prior versions of this rule. 

Response #1: No response needed. 

Comment #2: Earthjustice disagreed 

with EPA’s proposal to approve the NOX

emission limit in Rule 4352 for 

municipal solid waste (MSW) fired 

units as RACT. Earthjustice provided 

several arguments in support of its 

objection to EPA’s proposal, each of 

which we address following separate 

comment summaries below. 

Comment #2.a: Earthjustice stated 

that the New Jersey Department of 

Environmental Protection (NJDEP) has 

set NOX emissions limits for MSW-fired 

boilers at 150 ppmv at 7% O2

(approximately 142 ppmv at 12% CO2). 

Quoting from a SIP submission from 

NJDEP, Earthjustice asserted that NJDEP 

established this limit based on ‘‘the 

capability of existing selective noncatalytic reduction (SNCR) emission 

controls to reduce emissions more than 

are now being achieved.’’ The 

commenter stated that the District’s 

unsupported assertion that it is 

impossible to meet a limit lower than 

165 ppmv at 12% CO2 is simply false. 

Response #2.a: We disagree with the 

commenter’s suggestion that the NOX

emissions limits established in NJDEP’s 

rule generally represent NOX RACT for 

existing MSW-fired boilers equipped 

with SNCR controls. As the commenter 

correctly notes, under Title 7, Chapter 

27, Subchapter 19, Section 12 of the 

New Jersey Administrative Code 

(N.J.A.C. 7:27–19.12), NJDEP limits NOX

emissions from MSW combustors to 150 

ppm at 7% O2 averaged over 24 hours 

(approximately 142 ppm at 12% CO2). 

In lieu of complying with this emissions 

limit, however, the rule allows an owner 

or operator of an MSW incinerator to 

comply with an alternative emission 

limit or a ‘‘facility-specific NOX control 

plan’’ upon receipt of written approval 

from NJDEP, pursuant to section 13 of 

the rule (N.J.A.C. 7:27–19.13). See 

N.J.A.C. 7:27–19.12(b). Section 13 

identifies, among other things, the types 

of information that an owner or operator 

must submit to NJDEP as part of a 

request for such an alternative emission 

limit or facility-specific NOX control 

plan, including a list of all NOX control 

technologies available for use with the 

equipment or source operation, an 

analysis of the technological feasibility 

and costs of installing and operating 

each such control technology, and 

estimates of the NOX emissions 

reductions attainable through the use of 

each control technology which is 

technologically feasible. See N.J.A.C. 

7:27–19.13(d). The rule authorizes 

NJDEP to approve a request for an 

alternative emission limit or facilityspecific NOX control plan only if, among 

other things, the request identifies all 

available NOX control options and 

demonstrates that any control options 

that the owner/operator has rejected are 

ineffective or unsuitable for the 

particular equipment or would involve 

disproportionately high costs, in 

comparison to the associated NOX

reductions or costs borne by other like 

facilities. See N.J.A.C. 7:27–19.13(g)(3). 

According to NJDEP, three of the five 

MSW incinerators subject to N.J.A.C. 

7:27–19.12 appear to have obtained 

alternative emission limits pursuant to 

Section 13 of the rule and are not 

currently subject to the 24-hour NOX

limit of 150 ppm at 7% O2. See email 

dated July 24, 2012, from Michael Klein 

(NJDEP) to Stanley Tong (EPA Region 

9). Table 1 below shows the current 

NOX limits in the operating permits for 

each of these five MSW incinerators 

under NJDEP jurisdiction. 

TABLE 1 

Facility Emission limit 

(ppm at 7% O2) 

Emission limit 

(approximate 

ppm at 12% 

CO2) 

Averaging 

time 

(hours) 

Essex 2 ..................................................................................................................................... 300 

155 

285 

147 

1 

24 

Warren 3 ................................................................................................................................... 300 

205 

285 

195 

3 

24 


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66550 Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 

4See Air Pollution Control Operating Permit, 

Permit Activity No. BOP080001, Covanta Union 

(Union PTO) at pp. 56 and 57 of 90. 

5See Air Pollution Control Operating Permit, 

Permit Activity No. BOP090002, Wheelabrator 

Gloucester Company (Gloucester PTO) at pp. 38 and 

68 of 106. 

6See Air Pollution Control Operating Permit, 

Permit Activity No. BOP080002, Camden Cnty 

Energy Recovery Assoc LP (Camden PTO) at pp. 34 

and 66 of 99. 

TABLE 1—Continued 

Facility Emission limit 

(ppm at 7% O2) 

Emission limit 

(approximate 

ppm at 12% 

CO2) 

Averaging 

time 

(hours) 

Union 4 ..................................................................................................................................... 225 

180 

214 

171 

3 

24 

Gloucester 5 ............................................................................................................................. 350 

150 

333 

143 

3 

24 

Camden 6 ................................................................................................................................. 300 

150 

285 

143 

3 

24 

Of the three New Jersey facilities that 

have obtained permit limits exceeding 

the 24-hour NOX limit of 150 ppm (at 

7% O2) in NJDEP’s rule (Essex, Warren, 

and Union), two facilities (Warren and 

Union) have permit limits that also 

exceed the 24-hour NOX limit of 165 

ppm (at 12% CO2) in SJVUAPCD’s Rule 

4352. See Table 1. The remaining two 

facilities, which are subject to the 150 

ppm limit in NJDEP’s rule (Gloucester 

and Camden), are both equipped with 

SNCR using urea injection as a NOX

control technique. See Gloucester PTO 

at pp. 45–46 of 106; Camden PTO at pg. 

183 (of electronic file). Both of these 

facilities became subject to the 24-hour 

NOX limit of 150 ppm (at 7% O2) in 

N.J.A.C. 7:27–19.12 effective May 1, 

2011. See Gloucester PTO at pp. 38 of 

106; Camden PTO at pg. 34 of 99. 

Notably, for the Camden facility, the 150 

ppm limit applied ‘‘on and after May 1, 

2011, if compliance is achieved by 

installing a new NOX air pollution 

control system on an existing MSW 

incinerator or by physically modifying 

an existing MSW incinerator.’’ Camden 

PTO at pg. 34 of 99. The Gloucester and 

Camden facilities are the only MSW 

incinerators we know of that are subject 

to the 24-hour NOX limit of 150 ppm (at 

7% O2) in N.J.A.C. 7:27–19.12. 

Only one existing facility in the SJV 

(Covanta Stanislaus, Inc.) currently 

operates MSW-fired boilers subject to 

SJVUAPCD’s Rule 4352. The two MSWfired boilers at the Covanta Stanislaus 

facility are equipped with SCNR using 

ammonia injection systems, instead of 

urea injection systems, for NOX control. 

See Facility-wide Permit to Operate for 

Covanta Stanislaus, Inc., San Joaquin 

Valley Air Pollution Control District, 

Permit Unit: N–2073–1–10 (expiration 

date 10/31/2016), ‘‘Equipment 

Description’’ (Stanislaus PTO). 

Although ammonia and urea injection 

both serve as reducing agents for NOX

emissions in combination with SNCR 

control systems, these control methods 

require operation at different 

temperature windows and generally are 

not interchangeable without facility 

retrofits. See Alternative Control 

Techniques Document—NOX Emissions 

from Industrial/Commercial/ 

Institutional (ICI) Boilers, U.S. EPA 453/ 

R–94–022 (March 1994) (1994 ACT) at 

sections 5.5.1.1 (‘‘Ammonia-based 

SNCR’’) and 5.5.1.2 (‘‘Urea-based 

SNCR’’). For example, the optimum 

reaction temperature range for the 

reduction of NOX by ammonia is 870° to 

1,100 °C, while the optimum range for 

the reduction of NOX by urea is 900° to 

1,150 °C, and ammonia can be injected 

both in aqueous solution or anhydrous 

form while urea may only be injected in 

aqueous form. Id. These technological 

distinctions between ammonia-based 

SNCR and urea-based SNCR highlight 

uncertainties about whether the controls 

implemented by the Gloucester and 

Camden incinerators in New Jersey (i.e., 

urea-based SNCR) are 

technologicallyand economically 

feasiblefor implementation at the one 

existing MSW-fueled facility in SJV. 

Additionally, according to 

information submitted by SJVUAPCD at 

EPA’s request, four of the five MSW 

incinerators subject to the NJDEP rule 

have equipment that differs significantly 

from the equipment at the Covanta 

Stanislaus facility in SJV. See emails 

dated September 4, 2012 and September 

11, 2012, from Nichole Corless 

(SJVUAPCD) to Idalia Perez (EPA 

Region 9), with attachments. 

Specifically, SJVUAPCD states that the 

Covanta Stanislaus facility is configured 

with stoker grates whereas the New 

Jersey MSW incinerators have 

reciprocating, horizontal, and roller 

grates, which enable them to meet a 

slightly lower NOX limit. Id. These 

technological distinctions raise 

additional questions about whether the 

controls implemented by the New Jersey 

facilities are feasible for implementation 

in SJV. Moreover, the fact that both the 

Gloucester and Camden incinerators in 

New Jersey became subject to the 150 

ppm limit in N.J.A.C. 7:27–19.12 only as 

of May 1, 2011, and in Camden’s case 

only if the facility made physical 

modifications to, or installed new air 

pollution control equipment on, the 

existing MSW incinerator, further 

highlights uncertainties about whether 

the chosen control methods at these two 

facilities are ‘‘reasonably available’’ for 

implementation at existing MSW-fired 

boilers in SJV. 

Finally, information submitted by the 

SJVUAPCD indicates that retrofits to 

existing SNCR systems to achieve 

additional NOX reductions are not costeffective in light of the relatively 

insignificant difference between the 

NOX limit in NJDEP’s rule (150 ppm at 

7% O2, or approximately 142 ppm at 

12% CO2, 24-hour average) and the limit 

in SJVUAPCD’s Rule 4352 (165 ppm at 

12% CO2, 24-hour average). 

Specifically, with respect to staged 

combustion retrofits to an ammoniabased SNCR control system, SJVUAPCD 

submitted information indicating that 

the cost per ton of reductions in NOX

emissions from 165 to 142 ppm at 12% 

CO2 would be $27,650/ton. See email 

dated September 4, 2012, from Nichole 

Corless (SJVUAPCD) to Idalia Perez 

(EPA Region 9), with attachment. 

Further taking into account certain 

operational conditions at the Covanta 

Stanislaus facility which indicate that 

the limit in NJDEP’s rule (150 ppm at 

7% O2) would equate to approximately 

148 ppm (rather than 142 ppm) at 12% 

CO2, the cost per ton of NOX emission 

reductions from 165 ppm to 148 ppm at 

12% CO2 would be $37,404/ton. See id. 

These costs exceed the levels generally 


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Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 66551 

7The commenter states that ‘‘the District’s 

unsupported assertion that it is impossible to meet 

a limit lower than 165 ppmv at 12% CO2 is simply 

false,’’ but this assertion mischaracterizes the 

District’s position, as test data for Covanta 

Stanislaus submitted by the District clearly show 

average NOX emission levels below the 165 ppm 

limit in Rule 4352. See TSD at 6. An emission limit 

of 165 ppm at 12% CO2 ensures that the source is 

obligated to continually operate its emission control 

system while leaving the facility a small 

compliance buffer to account for occasional shortterm variabilities inherent in its process. Id. 

considered to be ‘‘reasonable’’ within 

the meaning of RACT. 

In sum, the information before us 

raises significant questions about the 

technical and economic feasibility of 

achieving a 24-hour NOX emission limit 

of 150 ppm at 7% O2 (approximately 

142 ppm at 12% CO2) at existing MSWfired boilers equipped with ammoniabased SNCR in the SJV, and the 

commenter has provided little 

information to substantiate its claim in 

this regard. Absent specific information 

to support a conclusion that further 

NOX controls are ‘‘reasonably available’’ 

for implementation at existing MSWfired boilers in the SJV, we find that the 

24-hour NOX emission limit of 165 ppm 

at 12% CO2 in SJVUAPCD’s Rule 4352 

represents current RACT for these 

units.7

Comment #2.b: Earthjustice asserted 

that the District has not adequately 

analyzed and considered the feasibility 

of either injecting more ammonia or 

adding more nozzles to existing SNCR 

controls to meet a lower NOX emissions 

limit. The commenter stated that 

according to the NJDEP State 

Implementation Plan (SIP) Revision for 

the Attainment and Maintenance of the 

Fine Particulate Matter (PM2.5) National 

Ambient Air Quality Standard (NJDEP 

2009 PM2.5 SIP) submitted to EPA in 

2009, 11 regulated units at 4 facilities in 

New Jersey would meet the lower NOX

emissions limit in N.J.A.C. 7:27–19.12 

by injecting more ammonia or adding 

more nozzles to existing SNCR controls. 

The commenter stated that ‘‘technical 

analysis of these demonstrated options 

must be conducted before EPA can 

accept ammonia slip as an excuse for 

rejecting tighter SNCR limits.’’ 

Response #2.b: We have generally 

evaluated the technical feasibility of 

injecting more ammonia or adding 

nozzles to existing SNCR controls but 

do not have sufficient information to 

conclude that these control methods 

represent RACT for existing MSW-fired 

boilers in SJV at this time. According to 

information submitted by SJVUAPCD at 

our request, the orientation of the 

nozzles in the combustion gas stream 

has a much greater impact on the 

resulting NOX emissions than the 

number of nozzles in the system, and 

the Covanta Stanislaus facility’s nozzles 

have already been optimized based on 

the ‘‘temperature window where SNCR 

works to reduce NOX effectively.’’ See 

email dated September 4, 2012, from 

Nichole Corless (SJVUAPCD) to Idalia 

Perez (EPA Region 9), with attachments. 

SJVUAPCD also stated that the amount 

of ammonia injected into the flue gas at 

Covanta Stanislaus is closely controlled 

to maximize NOX reductions and to 

prevent excessive ammonia slip, and 

that increases in ammonia injection 

would ‘‘result in negligible NOX

reductions and would exit the system 

and cause a detached plume,’’ causing 

violations of permit conditions 

regarding visible emissions, ammonia 

slip, and condensable particulate 

matter. Id. (citing continuous emissions 

monitoring data submitted by Covanta 

Stanislaus to support these 

conclusions). 

EPA’s Alternative Control Techniques 

document for NOX emissions from 

Industrial/Commercial/Institutional 

Boilers (1994 ACT) supports the general 

conclusion that simply injecting more 

ammonia or adding nozzles will not 

necessarily reduce NOX emissions in an 

ammonia-based SNCR system. The 1994 

ATC describes the process in an 

ammonia-based SNCR system as 

follows: 

In this process, aqueous or anhydrous 

ammonia is vaporized and injected into the 

flue gas through wall-mounted nozzles at a 

location selected for optimum reaction 

temperature and residence time. The 

optimum reaction temperature range for this 

process is 870 to 1,100 °C (1,600 to 2,000 °F). 

* * * At temperatures above 1,100 °C (2,000 

°F), ammonia injection becomes 

counterproductive, resulting in additional 

NO formation. Below 870 °C (1,600 °F), the 

reaction rate drops and undesired amounts of 

ammonia are carried out in the flue gas. 

Unreacted ammonia is commonly referred to 

as ammonia slip, breakthrough, or carryover. 

The amount of ammonia slip also depends in 

part on the amount of ammonia injected. 

Although the chemical reaction requires one 

mole of NH3 for each mole of NO, the NH3/ 

NOX ratio used is usually greater than 1 to 

avoid an undesired reaction which results in 

formation of NO. * * * Achievable NOX

reductions for an individual boiler depend 

on the flue gas temperature, the residence 

time at that temperature, the initial NOX

concentration, the NH3/NOX ratio, the excess 

oxygen level, and the degree of ammonia/flue 

gas mixing. Also, stratification of both 

temperature and NOX in the flue gas can 

affect the performance of the SNCR control. 

The optimum placement of SNCR injectors 

requires a detailed mapping of the 

temperature profile in the convective passes 

of the boiler, because of the narrow 

temperature window. 1994 ACT at Section 

5.5.1.1. 

Thus, even assuming it is 

technologically feasible to inject more 

ammonia and/or to install additional 

ammonia injection nozzles, it is not 

clear that these methods would further 

reduce NOX emissions in an ammoniabased SNCR system, and technical 

information indicates that such methods 

could instead lead to increased 

ammonia slip if not carefully adjusted to 

account for the specific temperature 

profile, NH3/NOX ratio, oxygen levels, 

degree of ammonia/flue gas mixing, and 

other factors specific to the particular 

boiler and control system. 

As the commenter correctly notes, 

Appendix C of the NJDEP 2009 PM2.5

SIP states that ‘‘the NJDEP anticipates 

that the facilities will decrease their 

emissions due to optimizing their 

existing NOX control systems (i.e., either 

injecting more ammonia or adding more 

nozzles).’’ See NJDEP 2009 PM2.5 SIP, 

App. C., at 5. This statement alone, 

however, does not establish that the 

NOX emission limit in N.J.A.C. 7:27– 

19.12 (150 ppm at 3% O2) represents 

RACT for existing MSW-fueled boilers. 

As discussed above in Response 2.a, 

four of the five MSW incinerators 

subject to the NJDEP rule have 

equipment configurations that appear to 

differ significantly from the Covanta 

Stanislaus facility, and NJDEP has 

approved alternate, higher NOX limits 

for three of the five subject sources 

based on the agency’s assessment of 

source-specific technological and/or 

economic factors. Other than 

referencing statements of general intent 

in a New Jersey SIP submission, the 

commenter provides no technological or 

economic information to support its 

assertion that existing MSW-fired 

boilers, either generally or in SJV 

specifically, are capable of meeting a 24- 

hour NOX emission limit of 150 ppm at 

3% O2 (142 ppm of at 12% CO2) by the 

application of control technology that is 

reasonably available considering 

technological and economic feasibility. 

Comment #2.c: Earthjustice asserted 

that the New Jersey rule, along with data 

presented in EPA’s TSD for the 

proposed rule, ‘‘highlights the need for 

further analysis of potential NOX

controls by the District.’’ Earthjustice 

stated that information available in 

EPA’s 1994 ACT, which shows NOX

emissions from MSW-fired boilers with 

SNCR controls ranging from 35 to 167 

ppmv at 12% CO2, calls into question 

the 165 to 210 ppmv at 12% CO2 range 

provided in the District’s 2011 Staff 

Report and places the District’s NOX

emissions limit of 165 ppmv at 12% 

CO2 at the highest end of the range. 

Earthjustice also asserted that ‘‘[g]iven 

that the Valley is in nonattainment of 


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66552 Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 

8See, e.g., SIP-approved NOX emission reduction 

commitments in 40 CFR 52.220(c)(356)(ii)(B)(2) and 

52.220(c)(356)(ii)(B)(4), and 52.220(c)(397)(ii)(B)(2). 

the PM2.5 NAAQS and is in extreme 

nonattainment of the 1-hour and 8-hour 

ozone NAAQS, EPA must require the 

District to conduct further analysis and 

ensure that MSW-fired boilers meet the 

lowest emission limit that can be 

achieved through the application of 

RACT.’’ 

Response #2.c: First, with respect to 

the commenter’s assertions about the 

NJDEP rule (N.J.A.C. 7:27–19.12), we 

addressed these comments above in 

Response #2.a. Second, with respect to 

the commenter’s assertion about data 

presented in EPA’s TSD, although we 

agree with the commenter’s observation 

that the NOX emission limit in Rule 

4352 (165 ppmv at 12% CO2) is at the 

highest end of the range of NOX levels 

identified in EPA’s 1994 ACT for MSWfired boilers operating SNCR controls 

with ammonia or urea injection, we 

disagree with the assertion that this 

necessarily compels further evaluation 

of the NOX limit in Rule 4352. 

Municipal solid waste varies widely 

in composition—often including 

durable goods, non-durable goods, 

demolition and construction wastes, 

containers and packaging, food wastes 

and yard trimmings, and/or 

miscellaneous inorganic wastes—and 

the exact makeup of MSW at a 

particular facility may vary both 

seasonally and geographically. See 1994 

ACT at Section 3.4.3. Variability in 

MSW can affect emissions both due to 

differences in the availability of fuelbound nitrogen as well as differences in 

the heat content of the fuel, which can 

affect its combustion characteristics. 

Given the broad technical diversity of 

existing MSW-fired boilers and their 

varying fuel compositions, the NOX

emission level that one MSW-fired unit 

achieves by the application of 

reasonably available controls may not 

necessarily be achievable for others 

using similar controls. Even where 

boiler type, control technology, and fuel 

type are the same, emission levels may 

differ significantly from boiler to boiler 

depending on a number of site-specific 

factors, including furnace dimensions 

and operating characteristics, design 

and condition of burner controls, design 

and condition of stream control systems, 

and fan capacity. See, for example, 1994 

ACT at Appendix B (page B–21), 

showing achievable NOX emission 

levels ranging from 44 to 210 ppm at 3% 

O2 for MSW boilers equipped with 

SNCR. 

ACT documents describe available 

control techniques and their cost 

effectiveness but do not define 

presumptive RACT levels as EPA’s 

Control Techniques Guidelines (CTGs) 

do. The wide range of emission levels 

provided in the 1994 ACT for MSWfired boilers equipped with SNCR and 

using ammonia or urea injection as a 

control technique (35 to 167 ppmv at 

12% CO2) reflects the significant 

variation in emission levels that may 

result from site-specific technological 

considerations and fuel compositions at 

different MSW-fired units. Notably, the 

NOX emission ranges provided in 

Appendix B of the 1994 ACT do not 

identify applicable averaging periods 

and therefore may not be directly 

comparable to the 24-hour NOX

emission limit in Rule 4352. See 1994 

ACT at Appendix B. 

EPA has evaluated the control 

techniques and applicable permit 

conditions for the two MSW 

incinerators in New Jersey that are 

currently subject to the 24-hour NOX

emission limit of 150 ppm (at 3% O2) 

in N.J.A.C. 7:27–19.12 (Gloucester and 

Camden) and concluded that technical 

distinctions between these facilities and 

the Covanta Stanislaus facility in SJV 

raise significant questions about the 

technological and economic feasibility 

of those same emission control methods 

at existing MSW-fired boilers in the SJV. 

See Response #2.a. We do not currently 

have information sufficient to support a 

conclusion that existing MSW-fired 

boilers using ammonia-based SNCR 

systems, either generally or specifically 

in the SJV, are capable of meeting a 24- 

hour NOX emission limit of 150 ppm at 

3% O2 (142 ppm of at 12% CO2) by the 

application of control technology that is 

reasonably available considering 

technological and economic feasibility. 

Finally, with respect to the 

commenter’s statement about the SJV 

area’s air quality designations for the 

PM2.5 and ozone National Ambient Air 

Quality Standards (NAAQS), we note 

that attainment status designations are 

not relevant to our evaluation of Rule 

4352 for compliance with the 

technology-based RACT control 

requirement in CAA section 182(b)(2). 

The RACT requirement in CAA section 

182 is a control mandate that applies 

independent of the emission reductions 

needed for attainment of the NAAQS. 

See, e.g., EPA’s Proposed Rule to 

Implement the 8-Hour Ozone [NAAQS], 

68 FR 32802, 32837 (June 2, 2003) 

(explaining that ‘‘[u]nder subpart 2, 

RACT requirements for ozone 

nonattainment areas apply independent 

of the emissions reductions needed to 

attain the standard’’). We note, however, 

that the general requirement in CAA 

section 172(c)(1) to adopt all 

‘‘reasonably available control measures’’ 

(RACM) continues to apply in the SJV 

area for purposes of attaining the ozone 

and PM2.5 NAAQS (see, e.g., 40 CFR 

51.912(d) and 51.1010). Given the 

severity of the ozone and PM2.5

pollution problems in the SJV and the 

NOX and PM2.5 emission reduction 

commitments contained in the SIPapproved plans for attainment of the 

1997 PM2.5 and 1997 8-hour ozone 

standards in the SJV,8 we encourage the 

District to further evaluate potential 

NOX and PM control options at its 

earliest opportunity to determine 

whether additional controls for existing 

MSW-fired boilers may be reasonably 

available for implementation in the 

Valley. 

Comment #3: Earthjustice asserted 

that EPA should urge the District to 

reevaluate the startup and shutdown 

provisions in Rule 4352 as the rule 

allows units to emit excess emissions 

for far longer than necessary. In support 

of this assertion, the commenter referred 

to rules adopted by the Placer County 

Air Pollution Control District 

(PCAPCD), Yolo Solano Air Quality 

Management District (YSAQMD) and 

Sacramento Metropolitan Air Quality 

Management District (SMAQMD), each 

of which contain shorter time periods 

for startup and shutdown operations. 

Citing a 1999 EPA policy document 

providing that startup and shutdown 

periods should be limited ‘‘to the 

maximum degree practicable,’’ the 

commenter asserted that the District had 

neglected to evaluate the possibility of 

requiring shorter startup and shutdown 

times under Rule 4352 for solid fuelfired boilers. 

Response #3: We disagree with the 

commenter’s assertion that the startup 

and shutdown provisions in Rule 4352 

are deficient. EPA policy for SIPs 

regarding excess emissions during 

malfunctions, startup, shutdown, and 

maintenance provides that for some 

source categories, ‘‘given the types of 

control technologies available, there 

may exist short periods of emissions 

during startup and shutdowns when, 

despite best efforts regarding planning, 

design, and operating procedures, the 

otherwise applicable emission 

limitation cannot be met.’’ Thus, with 

limited exceptions, it may be 

appropriate in consultation with EPA to 

create ‘‘narrowly-tailored SIP revisions’’ 

that take these technological limitations 

into account and state that the otherwise 

applicable emissions limitations do not 

apply during these periods. See 

Memorandum dated September 20, 

1999, from Steven A. Herman, Assistant 

Administrator for Enforcement and 

Compliance Assurance and Robert 


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Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 66553 

9The YSAQMD rule states that ‘‘the frequency 

and duration of startup and shutdown periods and 

their associated emissions shall be minimized as 

much as technologically feasible.’’ YSAQMD Rule 

2.43 at section 302.3. The PCAPCD rule includes 

alternative pound per hour emission limits for NOX

and CO during startup and shutdown periods. See 

PCAPCD Rule 233 at section 302.2. 

Perciasepe, Assistant Administrator for 

Air and Radiation, to Regional 

Administrators, Regions I–X, ‘‘State 

Implementation Plans: Policy Regarding 

Excess Emissions During Malfunctions, 

Startup, and Shutdown’’ (1999 SSM 

Policy) at Attachment, pp. 4–5. 

According to the 1999 SSM Policy, SIP 

provisions addressing these 

circumstances should, among other 

things, be limited to specific, narrowlydefined source categories. Id. 

Additionally, use of the control 

technology for the source category 

should be technically infeasible during 

startup or shutdown periods; the 

frequency and duration of operation in 

startup or shutdown mode should be 

minimized to the maximum extent 

practicable; and all possible steps 

should be taken to minimize the impact 

of emissions during startup and 

shutdown on ambient air quality. Id. 

Rule 4352 generally applies to any 

boiler, steam generator or process heater 

fired on ‘‘solid fuel’’ that is operated at 

a stationary source with a potential to 

emit at least 10 tons per year of NOX or 

VOC. See Rule 4352 at sections 2.0, 

3.18, and 4.0. Section 5.3 of the rule 

states that the applicable emission 

limits established for this defined 

source category ‘‘shall not apply during 

start-up or shutdown provided an 

operator complies with the 

requirements specified below.’’ The rule 

then limits the duration of each start-up 

to 96 hours, except that if curing of the 

refractory is required after a 

modification to the unit is made, the 

duration of start-up is limited to 192 

hours, with exceptions only as approved 

by the District, CARB, and EPA. See 

Rule 4352 at section 5.3.2. The rule also 

limits the duration of each shutdown to 

12 hours, with exceptions only as 

approved by the District, CARB, and 

EPA. Id. at section 5.3.1. Significantly, 

Rule 4352 requires, in all cases, that 

‘‘the emission control system shall be in 

operation and emissions shall be 

minimized insofar as technologically 

feasible during start-up or shutdown.’’ 

Id. at section 5.3.3. These provisions for 

start-up and shutdown apply to all solid 

fuel-fired boilers subject to Rule 4352, 

including biomass-fired and MSW-fired 

boilers. 

Earthjustice refers to rules adopted by 

the PCAPCD, YSAQMD and SMAQMD 

to support its assertion that the District 

should consider establishing shorter 

exemption periods for startup and 

shutdowns, but these other California 

rules apply to source categories that 

differ from the source category subject 

to Rule 4352. Both YSAQMD Rule 2.43 

and PCAPCD Rule 233, which apply to 

boilers fueled entirely or primarily with 

biomass, limit normal startups and all 

shutdowns to 24 hours and curing 

startups to 96 hours. See YSAQMD Rule 

2.43 at sections 102 and 302, and 

PCAPCD Rule 233 at sections 101, 206, 

214 and 215. Thus, although both the 

YSAQMD rule and PCAPCD rule limit 

the allowed duration of startup and 

shutdown to periods that are shorter 

than the limits in Rule 4352, both rules 

apply only to a subset of the boilers 

subject to Rule 4352. Biomass-fired 

boilers may not require start-up or 

shutdown periods as long in duration as 

those needed by the range of solid fuelfired boilers subject to SJVUAPCD’s 

Rule 4352, which combust more 

complex and heterogeneous fuel mixes, 

including biomass, MSW, coal, and 

other solid fuels. Notably, neither the 

YSAQMD rule nor the PCAPCD rule 

explicitly requires continued operation 

of emission control systems to the 

extent feasible during start-up and 

shutdown periods, as does Rule 4352.9

SMAQMD Rule 411, which applies to 

units fueled with gaseous and nongaseous fuels, limits startup to a 

maximum of two hours after a period in 

which the gas flow is shut off for a 

continuous period of 30 minutes or 

longer and limits shutdown to two 

hours. See SMAQMD Rule 411 at 

sections 102, 220–222. We are not 

aware, however, of any solid fuel fired 

boilers operating in the Sacramento 

metro area subject to Rule 411. Thus, 

SMAQMD Rule 411 does not appear to 

establish that shorter limits on startup 

and shutdown periods are 

technologically feasible for solid fuelfired boilers. 

In sum, the start-up and shutdown 

provisions in SJVUAPCD’s Rule 4352 

are narrowly-tailored to address the 

technological limitations of emissions 

controls at solid fuel-fired boilers and 

require, unlike the other California 

district rules cited by the commenter, 

that source owners/operators continue 

to operate emission control systems and 

to minimize emissions to the extent 

technologically feasible, even during 

start-up or shutdown periods. We 

conclude that these provisions in Rule 

4352 are consistent with EPA’s 1999 

SSM policy and appropriate for SIP 

approval for this particular source 

category. We agree with the commenter, 

however, that the District should 

reevaluate these provisions at its earliest 

opportunity to determine whether 

shorter limits on the duration of startup 

and shutdown periods may be feasible 

for certain types of solid fuel-fired 

boilers covered by the rule, and to 

consider establishing limits on the 

frequency of such events, to ensure that 

emissions during start-up and shutdown 

events are minimized to the maximum 

extent practicable. We also encourage 

the District to carefully review the 

CEMS data required by section 5.4 of 

Rule 4352 (monitoring provisions), in 

particular NOX emissions data during 

start-up and shutdown periods, to 

ensure that owners/operators of solid 

fuel-fired boilers are in fact operating 

emission control systems and 

minimizing emissions insofar as 

technologically feasible during start-up 

or shutdown as required by Rule 4352, 

section 5.3.3. 

III. EPA Action 

For the reasons provided in our 

proposed rule and above, and pursuant 

to section 110(k)(3) of the Act, EPA is 

fully approving Rule 4352 into the San 

Joaquin Valley portion of the California 

SIP. This final approval of Rule 4352 

satisfies California’s obligation to 

implement RACT under CAA section 

182(b)(2) for solid fuel-fired boilers in 

the SJV for the 1-hour ozone and 1997 

8-hour ozone NAAQS and thereby 

terminates all CAA sanctions clocks and 

Federal Implementation Plan (FIP) 

clocks associated with this source 

category. See 75 FR 60623 (October 1, 

2010) (final limited approval and 

disapproval of Rule 4352); 77 FR 1417 

(January 10, 2012) (final partial approval 

and disapproval of SJV RACT SIP); and 

77 FR 24857 (April 26, 2012) (interim 

final determination to stay and defer 

sanctions). 

IV. Statutory and Executive Order 

Reviews 

Under the Clean Air Act, the 

Administrator is required to approve a 

SIP submission that complies with the 

provisions of the Act and applicable 

Federal regulations. 42 U.S.C. 7410(k); 

40 CFR 52.02(a). Thus, in reviewing SIP 

submissions, EPA’s role is to approve 

State choices, provided that they meet 

the criteria of the Clean Air Act. 

Accordingly, this action merely 

approves State law as meeting Federal 

requirements and does not impose 

additional requirements beyond those 

imposed by State law. For that reason, 

this action: 

• Is not a ‘‘significant regulatory 

action’’ subject to review by the Office 

of Management and Budget under 

Executive Order 12866 (58 FR 51735, 

October 4, 1993); 


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66554 Federal Register / Vol. 77, No. 215 / Tuesday, November 6, 2012 / Rules and Regulations 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have Federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the Clean Air Act; 

and 

• Does not provide EPA with the 

discretionary authority to address 

disproportionate human health or 

environmental effects with practical, 

appropriate, and legally permissible 

methods under Executive Order 12898 

(59 FR 7629, February 16, 1994). 

In addition, this rule does not have 

tribal implications as specified by 

Executive Order 13175 (65 FR 67249, 

November 9, 2000), because the SIP is 

not approved to apply in Indian country 

located in the State, and EPA notes that 

it will not impose substantial direct 

costs on tribal governments or preempt 

tribal law. 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by January 7, 2013. 

Filing a petition for reconsideration by 

the Administrator of this final rule does 

not affect the finality of this action for 

the purposes of judicial review nor does 

it extend the time within which a 

petition for judicial review may be filed, 

and shall not postpone the effectiveness 

of such rule or action. This action may 

not be challenged later in proceedings to 

enforce its requirements (see section 

307(b)(2)). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen dioxide, Ozone, Particulate 

matter, Reporting and recordkeeping 

requirements. 

Dated: September 13, 2012. 

Jared Blumenfeld, 

Regional Administrator, Region IX. 

Part 52, Chapter I, Title 40 of the Code 

of Federal Regulations is amended as 

follows: 

PART 52—[AMENDED] 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart F—California 

■ 2. Section 52.220 is amended by 

adding paragraphs (c)(411) (i)(B)(4) to 

read as follows: 

§ 52.220 Identification of plan. 

* * * * * 

(c) * * * 

(411) * * * 

(i) * * * 

(B) * * * 

(4) Rule 4352, ‘‘Solid Fuel Fired 

Boilers, Steam Generators and Process 

Heaters,’’ amended on December 15, 

2011. 

* * * * * 

[FR Doc. 2012–26779 Filed 11–5–12; 8:45 am] 

BILLING CODE 6560–50–P 

GENERAL SERVICES 

ADMINISTRATION 

41 CFR Part 303–70 

[FTR Amendment 2012–07; FTR Case 2011– 

308; Docket Number 2011–0022, Sequence 

1] 

RIN 3090–AJ21 

Federal Travel Regulation (FTR); 

Payment of Expenses Connected With 

the Death of Certain Employees 

AGENCY: Office of Government-wide 

Policy, General Services Administration 

(GSA). 

ACTION: Final rule. 

SUMMARY: GSA has adopted as final, an 

interim rule amending the Federal 

Travel Regulation (FTR) to establish 

policy for the transportation of the 

immediate family, household goods, 

personal effects, and one privately 

owned vehicle of a covered employee 

whose death occurred as a result of 

personal injury sustained while in the 

performance of the employee’s duty as 

defined by the agency. 

DATES: Effective date: November 6, 

2012. 

Applicability date: This final rule 

applies to travel relating to employees 

who died on or after June 9, 2010. 

FOR FURTHER INFORMATION CONTACT: The 

Regulatory Secretariat (MVCB), 1275 

First Street NE. Washington, DC 20417, 

(202) 501–4755, for information 

pertaining to status or publication 

schedules. For clarification of content, 

contact Rick Miller, Office of 

Government-wide Policy, Travel and 

Relocation Policy Division, at (202) 

501–3822 or email at 

rodney.miller@gsa.gov. Please cite FTR 

Amendment 2012–07, FTR Case 2011– 

308. 

SUPPLEMENTARY INFORMATION: 

A. Background 

Pursuant to 5 U.S.C. 5707, the 

Administrator of General Services is 

authorized to prescribe necessary 

regulations to implement laws regarding 

Federal employees who travel in the 

performance of official business away 

from their official stations. Similarly, 5 

U.S.C. 5738 mandates that the 

Administrator of General Services 

prescribe regulations relating to official 

relocation. In addition, the Presidential 

Memorandum, ‘‘Delegation Under 

Section 2(a) of the Special Agent 

Samuel Hicks Families of Fallen Heroes 

Act,’’ dated September 12, 2011, 

published in the Federal Register on 

September 15, 2011 (76 FR 57621), 

delegates to the Administrator of 


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