# BRACEWELL

B.GILILIANI Texas Lisa M. Jaeger New York Senior Counsel Washington, DC Connecticut 202.828.5844 Office

~ l t Seattle 800.404.3970 Fax Dubai

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^C7 London Lisa.Jaeger@bgllp.com

Bracewell & Giuliani LLP 2000 K Street NW Suite 500 Washington, DC

20006-1872

July 1, 2014

Honorable Gina C. McCarthy Administrator iJnited States Environmental Protection Agency 1200 Pennsylvania Ave. NW Washington, DC 20460

RE: Revision of Petition for Reconsideration of the final Major Source Boiler MACT rule

Dear Administrator McCarthy:

The Council of Industrial Boiler Owners (CIBO), American Municipal Power, Inc. (AMP), and the American Chemistry Council (ACC) (Petitioners) hereby amend their Petition for Reconsideration now pending before EPA, as described below.

On April 1, 2013, CIBO, AMP and ACC jointly submitted a Petition for Reconsideration on the EPA final rule entitled National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters Final Rule: Notice of Final Action on Reconsideration, 78 Fed. Reg. 7,138 (January 31, 2013). EPA-HQOAR-2002-0058-3887. On August 5, 2013, EPA sent a letter to Petitioners and other industry groups indicating that EPA would begin a reconsideration process, specifying issues for which EPA intended to grant reconsideration, and reserving the right to grant reconsideration of other issues not already specified. On August 6, 2013, EPA also notified the court in the case US Sugar Corp v. EPA, No. 1 I-1108 (D.C. Cir) of its intention to grant reconsideration of certain issues in the rulemaking. As of June 30, 2014, EPA has not publicly indicated a final list of issues it intends to reconsider nor has it published any proposed reconsideration rule.

Petitioners hereby amend their Petition by withdrawing only Section IV, captioned "CO LIMIT FOR COAL-FIRED BOILERS." A11 other aspects of the Petition remain as submitted on April 1, 2013. Attached is a Revised Petition for Reconsideration reflecting this amendment. We request that EPA update the rulemaking record to reflect this change.

With permission of and on behalf of:

Robert D. Bessette President, Council of Industrial Boiler Owners555 11 `h Street, N. W., Suite 1000

Washington, D.C. 20004 (202) 637-2200

Douglas A. McWilliams
SQUIRE PATTON BOGGS (I1S) LLP 4900 Key Tower 127 Public Square Cleveland, OH 44114 (216) 479-8332 (Telephone) (216) 479-8776 (Facsimile) Counsel

, for Ainerican Municipal Power, Inc.

Leslie A. Hulse Assistant General Counsel 700 2"' St, NE Washington, D.C. 20002 (202) 249-6131 Counsel for American Chemistry Council

/s/ Lisa Marie Jaeger Lisa Marie Jaeger BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5844 (Telephone)

Cc: Janet McCabe, Elizabeth Shaw, Bob Wayland Enclosures

### REVISED PETITION FOR RECONSIDERATION OF THE COUNCIL OF INDUSTRIAL BOILER OWNERS, AMERICAN MUNICIPAL POWER, INC., and THE AMERICAN CHEMISTRY COUNCIL on

National Emission Standards for Hazardous Air Pollutants for

Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters Final Rule; Notice of Final Action on Reconsideration 78 Fed. Reg. 7,138 (January 31, 2013)

With permission of and on behalf of:

Robert D. Bessette President, Council of Industrial Boiler Owners 555 1 1 `f ' Street, N.W., Suite 1000 Washington, D.C. 20004 (202) 637-2200

Douglas A. McWilliams
SQUIRE PATTON BOGGs (US) LLP 4900 Key Tower 127 Public Sguare Cleveiand, OH 44114 (216) 479-8332 (Telephone) (216) 479-8776 (Facsinlile) Counsel for American Municipal Power, Inc.

Leslie A. Hulse Assistant General Counsel 700 2"' St, NE Washington, D.C. 20002 (202) 249-6131 Counsel for American Chemistry Council

/sl Lisa Marie Jaeger Lisa Marie Jaeger BRACEWELL & GIULIANI LLP 2000 K Street, N.W., Suite 500 Washington, D.C. 20006-1872 (202) 828-5844 (Telephone) Counsel for Council of'lndustrial I3oiler • (hvnersPursuant to § 307(d)(7)(B) of the Clean Air Act, 42 U.S.C. § 7607(d)(7)(B) and for the reasons

set forth below, the Council of Industrial Boiler Owners (CIBO), American Municipal Power, Inc. (AMP) and the American Chemistry Council (ACC) petition the Administrator of the United States Environmental Protection Agency (EPA) to reconsider specificprovisions in its Final Reconsideration Rule, National Emission Standards for I-Iazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT Rule), 78 FR 7138 (Jan. 31, 2013).

INTRODUCTION

CIBO is a broad-based association of industrial boiler owners, architect-engineers, related equipment manufacturers, and University affiliates with members representing 20 major industrial sectors. CIBO members have facilities in every region of the country and a representative distribution of almost every type of boiler and fuel combination currently in operation. CIBO was formed in 1978 to promote the exchange of information within the industry and between industry and government relating to energy and environmental equipment, technology, operations, policies, law and regulations affecting industrial boilers. Since its formation, CIBO has been active in the development of technically sound, reasonable, cost-effective energy and environmental regulations for industrial boilers. CIBO supports regulatory programs that provide industry with enough flexibility to modemize -- effectively and without penalty - the nation's aging energy infrastructure, as modernization is the key to cost-effective environmental protection.

AMP is a nonprofit corporation that provides services on a cooperative, nonprofit basis for its member cornmunities operating municipal electric systems. AMP serves 128 member municipal electric communities in six states, as well as the Delaware Municipal Electric Corporation. Combined, these publicly owned utilities serve approximately 625,000 customers. AMP members aftected by this Boiler MACT Rule operate small utility boilers of 25 megawatts or less.

ACC represents the leading companies engaged in the business of chemistry. ACC members apply the science of chemistry to make innovative products and services that make people's lives better, healthier and safer. ACC is committed to improved environmental, health and safety performance through Responsible Care k , common sense advocacy designed to address major public policy issues, and health and environmental research and product testing. The business of chemistry is a$770 billion enterprise and a key element of the nation's economy. ACC member companies own and operate boilers and process heaters subject to this rule.

On December 23, 2011, EPA proposed the reconsideration rule, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. 76 FR 80598 (Proposed Reconsideration Rule). On January 31, 2013, EPA published the Final Reconsideration Boiler MACT Rule. 78 FR 7138 (Final Reconsideration Rule or January 2013 Rule).

Reconsideration of the January 2013 Rule is warranted because the grounds for the issues identified below, which are "of central relevance to the outcome of the rule," arose after the public comment period or could not be raised due to impracticability. 42 U.S.C. § 7607(d)(7)(B). Considering this, the Clean Air Act (CAA) requires that EPA "shall convene a proceeding for

-2-reconsideration of the rule and provide the same procedural rights as would have been afforded

had the information been available at the time the rule was proposed." Id.

We respectfully request that EPA grant reconsideration of the following issues.

1. STARTUP: REQUIREMENT FOR CLEAN FUEL & DEFINITION OF "STARTUP"

The Final Reconsideration Rule announeed two new requirements of startup periods that are not logical outgrowths of the Proposed Reconsideration Rule. EPA failed to provide notice and an opportunity to comment on these new regulatory provisions. The issues are of central relevance to the rule, as they impose requirements on regulated sources that are inconsistent with basic boiler operations and with which some sources are unable to comply.

A. Clean fuel requirement

The Final Reconsideration Rule requires sources to start up on "clean fuel." Item 5, Table 3; 78 FR 7199. The definition of "clean fuel" includes several fuels but not coal or biomass or other solid fuels that many sources use during boiler startup. Id. In the December 23, 2011 Proposed Reconsideration Ru1e, the only mention of startup fuels was a solicitation of comment on

'

. whether other work practices should be required during startup and shutdown, including requirements to operate using specific fuels to reduce emissions during such periods." 76 FR 80615. This general reference and the regulatory language found in Item 5, Table 3 of the Proposed Reconsideration failed to give adequate notice of the extensive and specific changes that EPA made to Item 5, Table 3 in the final rule; these changes critically alter the effect of the rule on sources.

In response to EPA's general solicitation for comments on whether sources should be required to use specific fuels during periods of startup and shutdown, ACC submitted the following general
comment:

Not a1l facilities are permitted for or have access to suffieient natural gas or other loweremitting fuels to be able to use it as their startup fuel, and not all units are capable of burning natural gas or distillate oil. Specifying the use of natural gas or distillate fuel oil would also result in increased capital and operating costs for many facilities; these fuels are in many cases more expensive than a unit's primary operating fuel and would require different infrastructure to accommodate, if they can even be made available.

ACC Comments on Proposed Reconsideration Rule, EPA-HQ-OAR-2002-0058-3510 at 54.

The clean fuel requirement in the Final Reconsideration Rule mandates that only specified "clean fuels" be in use for "startup" and "startup" ends when heat or steam is supplied for any purpose.These requirements present significant problems for certain boilers. For example, a typical coalfired unit may use "clean fuel" initially to ignite some coal and then slowly the remaining coal is ignited and builds enough heat for the boiler to be fully operational. During this period, the unit

-3-does produce some steam for use onsite, but its startup period is still ongoing as the coal is fired

and continues to build heat and pressure inside the unit. Startup does not tidily end when coal firing begins. Startup is not a point in time, but a"period" of time during which the unit transitions from offline to fully operational and able to provide the defined electricity or steam demands. At the very least, EPA needs to recognize and clarify that a transition to base fuels that are not defined as "clean fuels", e.g., coal or biomass, is an integral and essential step in the `'startup" process and must be allowed regardless of whether any steam or heat is generated.

Affected sources have not had the opportunity to comment on the infeasibility of the specific clean fuel requirement and definition in the final rule. Moreover, because EPA included the `'clean fuel'" requirement for the first time in the tinal rule, regulated sources could not have submitted detailed comments on the costs and other impacts of EPA limiting the types of fuel allowed during startup. Certainly EPA failed to consider these costs and impacts in its promulgation of this requirement.

B. Definition of startup period

The definition of startup period was amended in the Final Reconsideration Rule, and now defines startup as ending "when any of the steam or heat from the boiler or process heater is supplied for heating and/or producing electricity, or for any other purpose." 78 FR 7191. This definition does not account for a wide range of boilers that operationally are still in startup mode even after some steam or heat is supplied to the plant. Identifying when startup ends is of central relevance to the rule, because that point dictates what other rule requirements apply and therefore whether sources are able to comply with the ru1e. Defining the end of startup based on the production of any steam or heat for any purpose is not a logical outgrowth of the proposal, which focused on percent boiler/process heater load. Moreover, sources could not have anticipated that EPA would finalize a new definition that does not reflect the realities of boiler operations and essentially ends startup at zero percent load. 

### See Environrnental Integrity Project v EPA, 425 F. 3d 992, 996 (D.C. Cir. 2005) ("we have refused to allow agencies to use the rulemaking process to pull a surprise switcheroo on regulated entities"); 

### International Union, United Mine Workers of Arnerica v. Mine Safety and Health Admin., 407 F 3d 1250, 1261 (D.C. Cir. 2005) (changing a rule from including a minimum to including a maximum is not a logical outgrowth); 

### Fertilizer Institute v EPA, 935 F. 2d 1303 (D.C. Cir. 1991) (rule is not a logical outgrowth where agency solicits comments on one approach but develops a different approach at final rule stage).

Clearly defining the end of startup is critical for compliance because it defines when sources must engage emission controls and comply with numeric emission standards rather than work practice standards. The Final Reconsideration definition of startup forces sources into the impossible circumstance of not being able to comply with other rule requirements. Moreover, this definition does not accurately account for what constitutes "startup" for all boilers, which varies widely. For example, some boilers begin to supply steam or heat for some purposes onsite before they have achieved necessary temperature or load to engage emission controls. According to the final rule, a boiler supplying even a small amount of steam would no longer be in startup and would be required at that point in time to engage emission controls. However, according to equipment specifications and established safe boiler operations, a boiler operator should 

### not engage emission controls until specific parameters are met.

-4-In the Proposed Reconsideration Rule, EPA defined startup as ending when "the unit first

achieves 25 percent load (i.e., a cold start)." 76 FR 80654. EPA explained that the proposed detinition was intended to ensure that units cannot cycle in and out of startup or shutdown" and to provide "clarity regarding which periods of operation are subject to the work practice standards rather than numeric emission limits and the associated requirements." Id. at 80615. In comments on the proposed rule, CIBO explained that boilers have widely ranging operational characteristics, due to their varied fuel types, furnace and boiler designs (combustion methods), and operating methodologies, including varied minimum stable operating loads. CIBO provided multiple examples of different startup methodologies among boilers. CIBO Comments on Proposed Reconsideration Rule, EPA-HQ-OAR-2002-0058-3534 at 24.

To address these wide variations among boilers, CIBO urged EPA to revise the startup definition to allow faciiities to determine the minimum stable operating load on a unit-specific basis and include the minimum stable operating load and the proper procedures to follow during startup and shutdown in a site-specific plan. Id. Establishment of the minimum stable operating load on a site-specific basis is analogous to setting other boiler and control device operating parameter limits on a site-specific basis, which EPA has done in this rule.

Similar comments were submitted by ACC. ACC informed EPA that some units have a minimum stable operating load that is higher than 25 percent. For example, stable operation for a stoker boiler may not be reached until 60 percent load. ACC advocated that EPA should revise the startup definition to allow facilities to determine the minimum stable operating load on a unit-specifie basis and include the minimum stable operating load that defines startup and shutdown and the proper procedures to follow during startup and shutdown in a site-specific plan. ACC Comments at 53.

In the Final Reconsideration Rule, EPA acknowledged the problems with its proposed rule and eliminated 25% load as the basis for defining the end of the startup period. However, EPA did not adopt a definition that permits site-specific considerations. Instead, EPA selected as the basis for defining startup, another variable boiler feature, while still not accounting for the broad range of boiler and fuel types, operational methodologies and facility demands placed on boilers. EPA exchanged an overly narrow startup definition for an overly broad definition that is unworkable.

The clean fuels requirement and definition of startup do not rationally correspond to the fuels used during startup and the actual procedures and periods of startup at a large percentage of boilers eovered by this ru1e. Petitioners request that EPA reconsider those aspects of the rule andpropose a definition that allows sources to identify startup periods on a site-specific and unitspecific basis. Only with this degree of flexibility will the rule adequately account for the multiple design and operational variables of the diverse boiler and process heater population regulated by this rule in a way that allows safe and effective operation with assurance of compliance with the standard.

In addition, the Table 3, item 5 requirement for engaging applicable control devices does not accommodate potential safety problems relative to ESP operation. Comments and recommended manufacturer operating proeedures provided to EPA during the Reconsideration comment period explained the potential hazards associated with ESP energization when unburned fuel may be

-5-present with oxygen levels high enough that the mixture can be in the flammable range. EPA

needs to reconsider this safety issue and revise the Table 3 requirements to include ESP energization with the other controls that are to be started as expeditiously as possible rather than when solid fuel firing is first started.

II. PM CPMS

The Final Reconsideration Rule requires sources using CPMS, the compliance alternative to PM CEMS, to "install, certify, maintain, and operate" the PM CPMS. Section 63.7525(b) (Final Reconsideration); 78 FR 7172. The requirement to certify is inconsistent with EPA statements in the Proposed Reconsideration Rule acknowledging the burden of certification of PM monitoring systems. The issue is of central relevance to the rule because it identifies specifie compliance obligations of sources regulated by the rule.

The 2010 Proposed rule required a PM CEMS for PM compliance, including requirements to certify to PS 11. 75 FR 32055( June 4, 2010). CIBO commented on the certification requirements in the 2010 Proposal, that the "installation and annual certification expenses for thePM CEMS are extreme and unreasonable." CIBO Comments on 2010 Proposed Rule, EPA-HQOAR-2006-0790-1783 at 72. When used on certain boiler and fuel types, CEMS do not reliably measure emissions, making it infeasible for the sources to certify the device and data. The CPMS alternative compliance methodology requires that sources install the same technoiogy as required for PM CEMS. The critical difference is that for CPMS eompliance, the CEMS device is used to demonstrate not continuous emission monitoring, but continuous compliance with operating parameters, obviating the need for sources to certify the emissions measurements taken by the device. Thus, although sources using the CPMS alternative must still bear the expense to install, maintain and operate the CEMS technology, they avoid the risk of faulty readings from the monitor and having to recalibrate, retest and recertify the results. Handling inaccurate monitor readings is very disruptive and costly to a plant, requiring process interruptions, system shutdowns and restarts, personnel redirected from production to handle testing and monitoring problems, and duplication of costly testing.

The Proposed Reconsideration Rule proposed to require certification of PM CPMS (76 FR 80637), but EPA requested comments on PM CPMS, noting that it "reduces the burden of certification of the monitor, which can be a substantial annual cost." 76 FR 80610. As EPA explained in the Proposed Reconsideration ru1e:

"[S]everal parties expressed concern over the state of readiness of current PM CEMS technology, certification methodology and the technical effort and eost required for the recertification necessary to handle changing fuel and control operating eonditions. In our reevaluation of this technology we find that PM monitoring technology would best be employed as parametric monitors (PM CPMS) and used to determine compliance with operating limits rather than emissions limits. This approach reduces the burden of certification of the monitor, which can be a substantial annual cost, and maintains our goals of seeking continuous data monitoring of the source particulate mass emission rate as a 30-day rolling average. We seek comment on the use of these monitors as described in the rule." ld.

^'l• '^Although EPA stated in the Proposed Reconsideration Rule that it did not intend to impose "the

burden of certification of the monitor," the Fina1 Reconsideration Rule does just that: Section 63.7525(b) and other sections require sources complying with PM CPMS standards to "certify" their CPMS. 78 FR 7172. EPA revised Section 7540(a)(9) in the final rule to remove the requirement to certify the monitoring device pursuant to an EPA approved performance specification. ' Petitioners fully support that change. However, EPA retained the certification requirement itself, while providing no guidance or definition on what would constitute "certification."

In EPA's Response to Comments, the following response sheds some light on EPA's intention not to require sources to certify their CPMS using PS 11:

"[t]he final rule requires the source to develop a site specific monitoring plan (SSMP) for a11 continuous monitoring systems, including a PM CPMS. In the case of a PM CPMS, the monitor is used as a parametric monitor and not an emissions monitor and the source is allowed to determine the performance acceptance criteria and performance evaluation procedures that are appropriate for their specific stack conditions and process operations. Then the source conducts the performance evaluation as per the site specific monitoring plan. The SSMP does not require that PS 11 be used for the performance evaluation. Other methods to evaluate the performance of CPMS are available. For example, audit materials, vendor laboratory testing, etc. could be reasonable methods. Operation, maintenance, and QA/QC procedures are also developed specifically for each site. A11 of these requirements may be less rigorous than those for PM CEMS and are custom designed to be appropriate and practical for the site's own conditions." EPA Summary of Responses to Public Comments, EPA-HQ-OAR-2002-0058-3849 at 768.

In the recent Portland Cement NESHAP rulemaking, EPA considered the same concerns raised by regulated sources regarding the technological unreliability of the PM CEMS technology and unjustifiably high cost especially in light of those failings. Reflecting those concerns at the proposal stage of the rule, EPA proposed a CPMS tailored to the circumstances, with no certification: "this proposed rule would require the installation and operation of a PM CPMS for parametric monitoring associated with the proposed PM standard. The source owner would not have to meet PS 11 requirements but would have to prepare and submit for approval, if requested by a permitting authority, a site-specific monitoring plan to apply sound practices for installing, calibrating and operating the PM CPMS." 77 FR 42376 (July 18, 2012). In the final Portland Cement rule, EPA acknowledged the difficulty of certifying PM CEMS. EPA noted that "there needs to be some assurance of the reliability of that methodology to certify with PS 11 at low

' The new definition of 7540(a)(9) reads: "The owner or operator of a boiler or process heater using a PM CPMS or

a PM CEMS to meet requirements of this subpart shall install, certify, operate, and maintain the PM CPMS or PM CEMS in accordance with your site-specific monitoring plan as required in § 63.7505(d)." 78 FR 7180. While this provision links the certification requirement to the site-specific monitoring plan, it still does not give guidance on the content or form of that certification.

-7-levels (as required by this final rule)" and "[t]hat information does not presently exist." 78 FR

10017 (Feb. 12, 2013).

EPA addressed those concerns raised by commenters by revising the rule requirement so that sources opting to comply with the rule using CPMS are not required to meet all of the requirements of PM CEMS:

You will use a PM CPMS to establish a site-specific operating limit corresponding to the results of the performance test demonstrating compliance with the PM limit. You will conduct your performance test using Method 5 or Method 51 at appendix A— 3 to part 60 of this chapter. You will use the PM CPMS to demonstrate continuous compliance with this operating limit. You must repeat the performance test annually and reassess and adjust the site-specific operating limit in accordance with the results of the performance
test. . .

40 CFR § 63.1350(b)(1)(i) (Final Portland Cement Reconsideration); 78 FR 10049.

Regarding the Final Reconsideration Rule for boilers, it appears that EPA did not intend for the word "certify" to mean what is traditionally understood by "certify", however keeping that word in the regulatory language is creating confusion and concerns in the regulated community. For all of the reasons above, Petitioners urge EPA to reconsider and revise the regulatory text to reflect the approach taken in the final Portland Cement rule with no requirement to certify.

III. 30-DAY AVERAGING PERIOD FOR OPERATING LOAD REQUIREMENT

In the Proposed Reconsideration Rule, EPA did not include a 30-day rolling average period for the operating load requirement. CIBO and several other commenters noted that the rule as written would imply that the 110 percent load limitation during a performance test is instantaneous. 

### See EPA Summary of Responses to Public Comment at 820. CIBO Comments on Proposed Reconsideration, EPA-HQ-OAR-2002-0058-3534 at 57.

EPA agreed with the commenters, noting that EPA

agree[s] that an averaging period should be added to the operating load requirement because the requirement, as currently written, implies that the 110 percent load limitation is instantaneous. For the same reasons provided for the other operating parameters, Table 8, item I 1(b) has been revised to allow a 30-day averaging period for operating loads so short term high load periods, to meet operational demands, that are more than 10 percent above the tested load do not result in deviations. This change is also consistent with Table 7 of the Boiler Area Source Rule (subpart JJJJJJ) rule in which the load monitoring requirement does have a 30-day averaging period specified.

EPA Summary of Responses to Public Comment at 819.

As EPA noted, EPA correctly added the 30-day rolling average period for operating load requirement in the Area Source rule. 

### See Table 7, Item 9; 78 FR 7521 ("Maintaining the 30-day

-8-rolling average at or below the operating limit established during the performance test according

to § 63.11212(c) and Tab1e 6 to this subpart.") By contrast, EPA did not add the 30-day rolling average to the major source rule operating load requirement. See Table 8, Item 10; 78 FR 7205. EPA did, however, add the 30-day average to other requirements. See Table 8 items 2, 4, 5, 6, 7, 9, 1 l; 78 FR 7204-7205.

EPA clearly intended to include a 30-day rolling average for operating load in the major source rule, just as it did for the area source rule. However, that intention did not translate to the regulatory text. Petitioners ask that EPA correct that oversight by granting reconsideration of the issue, issuing a technical correction to the rule, or taking some other administrative corrective

measure.

IV. DEFINITION OF GAS 1 AND GAS 2

In the Final January 2013 Rule, there is no allowance for liquid fuel firing in Gas 1 or Gas 2 units except under the gas curtailment or interruption provisions, whereas other subcategories aliow use liquid fuels for <] 0% annual heat input basis. See e.g. 78 FR 7193 ("Unit designed to burn solid fuel subcategory means any boiler or process heater that burns only solid fuels or at least 10 percent solid fuel on an annual heat input basis in combination with liquid fuels or gaseous fuels").

In the Proposed Reconsideration Rule at § 63.7575, EPA defined a"unit designed to burn Gas 1"

as:

any boiler or process heater that burns only natural gas, refinery gas, and/or other gas 1 fuels; with the exception of liquid fuels burned for periodic testing not to exceed a combined total of 48 hours during any calendar year, or during periods of gas curtailment and gas supply emergencies.

§ 63.7575 (Proposed Reeonsideration Rule), 76 FR 80655.

EPA proposed to define a"unit designed to burn gas 2(other)" as:

any boiler or process heater that is not in the unit designed to burn gas 1 subcategory and burns any gaseous fuels wither alone or in combination with less than 10 percent coal/solid fossil fuel, less than 10 percent biomass/bio based solid fuel, and less than 10 percent liquid fuels on an annual heat input basis.

Id.

EPA proposed to define a``unit designed to burn liquid" as:

any boiler or process heater that burns any liquid fuel, but less than 10 percent coal/solid fossil fuel and less than 10 percent biomass/bio-based solid fuel on an annual heat input basis, either alone or in combination with gaseous fuels. Gaseous fuel boilers and process heaters that burn liquid fuel for periodic testing of liquid fuel, maintenance, or operator

seatraining, not to exceed a combined total of 48 hours during any calendar year or during

periods of maintenance, operator training, or testing of liquid fuel, not to exceed a combined total of 48 hours during any calendar year are not included in this definition. Gaseous fuel boilers and process heaters that burn liquid fuel during periods of gas curtailment or gas supply emergencies of any duration are also not included in this definition.



### Id.

In its comments on these proposed definitions, ACC stated that EPA has consistently used 10% as a threshold for movement from one subcategory to another. For example, the most stringent — coal — includes units that burn at least 10% coal. The next — biomass — includes units that burn at least 10% biomass and less than 10% coal. The first sentence of the oii (liquid) subcategory includes any liquid fuel, but less than 10 % solid fuei. Therefore, it logically follows that a plain reading of the Gas 1 subcategory would be that a unit that burns at least 90% gas and less than 10% of any other fuel should be defined as a Gas 1 unit.

At a minimum, EPA should make the Gas 1 subcategory definition consistent with the area source definition, which places no restriction on liquid (e.g., oil) firing during startup. A new gas-fired boiler that is designed to burn liquid fuel as backup must be allowed to burn oil for more than 48 hours per year in order to ensure that the oil burners are properly tuned during initial startup.

ACC proposed the following definition for the Gas 1 subcategory:

"tlnit designed to burn gas 1 subcategory includes any boiler or process heater that burns at least 90 percent natairal gas, refinery gas, and/or other gas 1 fuels on a heat input basis on an annucrl average and less than 10 percent of any solid or liquid fuel.

ACC advocated that this definitional change would simplify the process of determining whether a unit qualifies for the gas 1 subcategory and would eliminate the need to determine whether periods during which liquid fuel is fired eonstitute natural gas curtailment, gas supply emergency, or periodic testing. It would also accommodate the need to be able to burn oil during initial startup in order to test and tune the oil burners on a new unit or an existing unit where new burners have been installed. EPA already acknowledged in §63.75 1 0(a)(2)(i) that units burning a supplemental fuel for startup, shutdown, and transient flame stability purposes are single fuel units, and the supplemental fuel is not subject to fuel analysis requirements.

ACC further stated that this change would be consistent with how EPA has proposed to define the gas 2 subcategory, which allows for the unit to burn other fuels as long as they are less than 10 percent on an annual heat input basis.

In the Final Reconsideration Rule, EPA did not consider, let alone adopt ACC's recommendations. EPA does not explain why its definition of gas 1 units must remain inconsistent with the 10 percent approach taken in the other definitions. Even more surprising, EPA changed the definition for a unit designed to burn gas 2 went from a proposed allowance of

-10-Iess than 10 percent liquid fuel to 

### a 

### prohibition on the use of liquid fuel, except in very narrow

circumstances. § 63.7575 (Final Reconsideration);78 FR 7192. This final definition is not a logical outgrowth of the Proposed Reconsideration Rule. Moreover, it conflicts with the requirements for the use of "clean fuels" during startup, which are defined to include distillate and ULSD oil, liquid fuels. Table 3(Final Reconsideration); 78 FR 7199. EPA should correct this inconsistency and allow Gas 1 and Gas 2 units the operational flexibility to use limited amounts of fuel oil. EPA should grant reconsideration on these two definitions and explain its position so that the regulated community has an opportunity to evaluate the merits of EPA's rationale and respond with meaningful comments.

CONCLUSION

For all of the foregoing reasons Petitioners respectfully request that EPA reconsider these issues and provide additional administrative process to provide regulated sources an opportunity to review and comment on revised regulatory treatment.

-11-Honorable Gina C. McCarthy Administrator US Environmental Protection Agency 1200 Pennsylvania Ave. N W Washington, DC 20460