Representing the Interests of America’s Industrial Energy Users since 1978

May 20, 2011

The Honorable Lisa P. Jackson, Administrator U.S. Environmental Protection Agency Ariel Rios Building 1200 Pennsylvania Avenue, N.W.

Mail Code: 1101A Washington, DC 20460

RE: Petition for Reconsideration of the National Em ission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commer cial, and Institutional Boilers, 76 Fed. Reg. 15,554 (Mar. 21, 2011) (Docket No. EPA-HQ-OAR-2006-0790)

Dear Administrator Jackson:

INTRODUCTION

Pursuant 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 Owner s (CIBO) petitions the Administrator of the United States Environmental Protection Agency (EPA) to rec onsider specific provisions in its final rule,

National Emission Standards for Hazardous Air Pollu tants for Area Sources: Industrial, Commercial, and Institutional Boilers (Area Source Rule), 76 Fe d. Reg. 15,554 (Mar. 21, 2011).

CIBO is a broad-based association of industrial boi ler owners, architect-engineers, related equipment manufacturers, and university affiliates with members representing 20 major

industrial sectors. CIBO members have facilities i n 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 relati ng to energy and environmental equipment, technology, operations, policies, law and regulatio ns affecting industrial boilers. Since its formation, CIBO has been active in the development of technically sound, reasonable, costeffective energy and environmental regulations for industrial boilers. CIBO supports regulatory programs that provide industry with enough flexibil ity to modernize – effectively and without-2-

penalty – the nation's aging energy infrastructure, as modernization is the key to cost-effective environmental protection.

On June 4, 2010, EPA proposed the National Emission Standards for Hazardous Air Pollutants for

Area Sources: Industrial, Commercial, and Instituti onal Boilers (75 Fed. Reg. 31,898). On August 23, 2010, the comment period closed. On March 21, 2011 , EPA published the final Area Source Rule. 76 Fed. Reg. 15,554.

Reconsideration of the rule is warranted because th e grounds for the issues identified below, which ar e "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 r econsideration of the rule and provide the same procedural rights as would have been afforded had t he information been available at the time the rule was proposed.” Id. Furthermore, during the recons ideration of the rule, EPA may stay the

effectiveness of the rule. Id.

CIBO respectfully requests that EPA grant reconside ration of the following issues.

I. O2 MONITORING REQUIREMENTS.

A. Petitioners Were Not Given the Opportunity to Comme nt on the New O2 Monitoring Requirement Contained in the Final Area Source Rule.

The final Area Source Rule creates new O2 monitorin g requirements that were not included in the proposed rule, depriving sources of notice and an opportunity to comment. EPA should

therefore reconsider this issue

The final Area Source Rule imposes a CO emission li mit on coal fired subcategories with compliance proven by a triennial Method 10 CO emiss ion test, in combination with an O2 operating limit proven with an O2 CEMS. 76 Fed. Reg . 15,594. While CIBO agrees that CO CEMS should not be required for units under Subpart DDDDD or Subpart JJJJJJ, the O2 monitoring requirements as finalized are not approp riate or workable in some cases and additional flexibility is required.

In the proposed Area Source rule, EPA established C O emissions limits for several subcategories of sources, with compliance demonstrated as a 3-run average for units less than 100MMBtu/hr and on a daily average basis using a CO CEMS for un its 100MMBtu/hr or greater. Although CO CEMS monitoring was required at all times, CO data was only used when operating at 50 percent of rated capacity or greater.

In the final rule Area Source Rule, EPA eliminated some of the CO emission limits, removed the CO CEMS requirement. Instead, EPA is requiring tri ennial Method 10 CO performance testing to demonstrate compliance by those units with CO em ission limits and the use of an O2 CEMS-3-

to demonstrate compliance on a 12-hour block averag e basis with the minimum O2 operating limit established during performance testing. 76 Fe d. Reg. 15,595-596.

EPA is requiring that the oxygen level shall be mon itored at the outlet of the boilers. Each monitor must be installed, operated, and maintained according to the applicable procedures under Performance Specification 3 at 40 CFR part 60, app endix B, and according to the site-specific monitoring plan developed according to paragraph (c ) of this section. 76 Fed. Reg. 15,595. The rule further requires monitoring of oxygen content in the combustion exhaust and the maintenance of the 12 hour average at or above the operating limit established during most recent performance test. 76 Fed. Reg. 15,605.

While CIBO agrees that CO CEMS are not an appropria te mandatory monitoring requirement for

a CO limit based on stack test data obtained at ful l load conditions, monitoring O2 levels in the stack or ductwork leading to the stack to ensure co ntinuous compliance is not appropriate for all units. Many existing boilers already utilize flue gas oxygen analyzers for indication, alarm, and

O2 trim control, where the fuel/air ratio is automa tically controlled for optimum combustion conditions. The sensing location for existing O2 m onitors is typically in the optimum location to sense flue gas composition as reliably as possible, because sensing of oxygen in these cases maintains proper excess air levels and helps preven t unsafe operating conditions. For many types of combustion units, that location is near th e boiler or process heater furnace outlet in a position upstream of any potential air inleakage po ints to avoid erroneous excess air indications. This location is also upstream of air preheaters wh ere utilized, thus avoiding the erroneous (high O2) indications due to inherent leakage across reg enerative air preheater seals or potential tube leakage in recuperative air preheaters.

For those units equipped with existing O2 sensors a nd O2 trim control systems, flue gas composition at those locations would already be use d for combustion tuning and control characterization. Therefore, if O2 monitoring was desired for continuous compliance under the Area Source Rule, sensing O2 at that current locati on would be logical and proper from a technical perspective. However, O2 analyzers utili zed for these existing purposes are not compliant CEMS meeting PS-3 requirements relative t o positioning or other QA/QC requirements. They are, however, calibrated and ma intained to provide reliable and safe service for combustion unit operation.

Conversely, if O2 was sensed prior to the stack or in the stack, that would be downstream of potential air inleakage points and air preheater le akage points, thus leading to variations in readings that can impact operation and long term co mpliance. It must be recognized that where

CO or NOx CEMS are utilized in the stack with O2 or CO2 correction, that O2 or CO2 reading purposely corrects for variations in excess air fro m the furnace as well as any air inleakage or internal air heater leakage, so the impact is not o f consequence from a combustion safety or direct compliance perspective. However, if it is r equired to actually monitor and maintain O2 level, then the most appropriate location for sensi ng that O2 level is upstream of any potential leakage points. By definition, those locations wil l not meet PS-3 requirements due to their close coupled nature and use of single or multiple point sensors that are most appropriate for the application.-4-

The most cost effective approach for utilization of O2 CEMS would be to allow the option of continued use of existing O2 analyzers and use of n ew O2 analyzers of appropriate design for the application to be located in optimum positions for the particular unit involved. Requiring periodic sensor calibration would be a way to ensur e accurate O2 monitoring. If new O2 sensors are required in all cases in the breeching or stack to meet PS-3 requirements, it would be an unjustified additional capital and ongoing O&M expe nse that will not provide any constructive compliance information. There are some units where locating O2 sensors in the breeching or stack is appropriate, so options should be provided to allow optimum monitoring.

As previously noted, the O2 monitoring requirement is new in the final Area Source Rule and petitioners were not given an opportunity to commen t on its use. Considering this, EPA should reconsider this new requirement.

B. EPA's CO Emission Limits Were Established Incorrect ly.

Some existing area source boilers are already requi red to use CO CEMS. In those cases, even with the final rule as written, instantaneous CO sp ikes could be considered credible evidence leading to deviations if those readings under any o perating conditions exceed the CO limits that were established using reference method test data a t maximum unit operating load. It is well known that CO emissions vary widely over normal loa d conditions.

However, in addition to units required to use CO CE MS, there may also be units that would prefer to install CO CEMS, so that an alternative C O limit based on use of CEMS is needed. It would be much more appropriate and cost effective f or regulated facilities and regulatory authorities if EPA would provide alternative CO lim its and their basis for facilities to utilize CO CEMS instead of O2 CEMS, rather than requiring indi vidual facilities to petition for alternative monitoring practices.

In order to allow for use of CO CEMS with O2 correc tion, EPA needs to establish CO emission limits on an appropriate basis using emission data on the same basis, i.e CEMS data. Since the final rule provides work practices for startup/shut down periods, an appropriate basis for a CO limit using a CO CEMS would be a 30-day rolling ave rage based on actual CO readings over the appropriate operating range.

CIBO notes that there are other issues related to t he O2 provisions of the final Area Source Rule. Specifically, O2 compliance basis for O2 CEMS is gi ven as 30 day rolling average. This appears to be an error since it is a12-hour block average t hat is required in the rule. See Table 7, 76 Fed. Reg. 15,596. However, the word “block” is missing in Table 7 item 7 for O2 and item 6c for ESP secondary amperage and voltage. Id. These two should be clarified to be block averages if

that is EPA’s intent.-5-

II. ENERGY ASSESSMENT

A. EPA Unreasonably Failed to Treat Certain CBI Simila rly Under the Major and

Area Source Rules.

In several documents referenced below, EPA stated i ts intent to recognize in the final Area Source Rule the sensitivity of confidential busines s information (CBI) contained in energy assessments. Despite this fact, it appears that EP A did not fully incorporate its intentions with regard to the treatment of CBI in the final Area So urce Rule. Considering this, EPA should reconsider the text § 63.11241(c) and clarify that energy assessment reports are not required to be submitted to the Agency.

In the proposed Area Source Rule, proposed § 63.112 15(b) required that:

[i]f you own or operate an existing affected boile r with a heat input capacity of 10 million Btu per hour or greater, you must submit the energy assessment report, along with a signed certification that the assessme nt is an accurate depiction of your facility.

In the final Area Source Rule, § 63.11214(c) requir es that:

[i]f you own or operate an existing affected boiler with a heat input capacity of 10 million Btu per hour or greater, you must submit a signed certification in the Notification of Compliance Status report that an en ergy assessment of the boiler and its energy use systems was completed and submit , upon request, the energy assessment report. 76 Fed. Reg. 15,594.

It appears that in the final Area Source Rule, EPA requires submission of the energy assessment report only upon request. This approach is contrar y to the approach taken in the final Boiler Rule, where § 63.7530(e) provides:

[y]ou must include with the Notification of Complia nce Status a signed certification that the energy assessment was comple ted according to Table 3 to this subpart and is an accurate depiction of your f acility. 76 Fed. Reg. 15,675.

Considering the express text of the final regulatio ns, submission of energy assessment reports is not required under the final Boiler rule. CBI is e qually an issue for companies operating area source boilers as it is for major source boilers an d process heaters. As such, a similar approach in both rules is justified. EPA has provided no ju stification for requiring submission of the energy assessment reports for area sources while no t requiring their submission for major sources. From a review of its response to comments it appears it was EPA’s intention to treat energy assessment reports for area sources similarl y to their treatment for major sources. Specifically, in the RTC, Vol.2, p.461, EPA states:-6-

In the final rule, the energy assessment is not req uired to be submitted to EPA or the permitting agency. The final rule requires that the permitting agency be notified that the energy assessment has been conduc ted according to the requirement in the final rule. The facility is requ ired to keep records that the work practices and management practices were complied wi th.

It appears that EPA did not fully incorporate its i ntentions with regard to the treatment of CBI in the final Area Source Rule. Considering this, CIBO recommends that EPA reconsider revising the text of § 63.11241(c) to read as follows:

"If you own or operate an existing affected boiler with a heat input capacity of 10 million Btu per hour or greater, you must submit a signed c ertification in the Notification of Compliance Status report that an energy assessment of the boiler and its energy use systems was completed according to Table 2 of this subpart and is an accu rate depiction of your facility and submit, upon r equest, the energy assessment report

.

B. EPA Should Clarify the Scope of the Energy Assessme nt.

EPA appears to have intended that the scope of the energy assessments be limited to those components associated with the energy output from b oilers that are regulated by the rule. Despite many indications that this was EPA's intent , the actual text of the final Area Source Rule appears to include a broad scope of what is include d in the energy assessment. Considering this, EPA should reconsider these provisions and clarify its intent with regard to the scope of the

energy assessment.

In the proposed Area Source Rule, EPA defined "Ener gy Assessment" as follows:

Energy assessment

means an in-depth assessment of a facility to iden tify immediate and long-term opportunities to save energ y, focusing on the steam and process heating systems which involves a thorough e xamination of potential savings from energy efficiency improvements, waste minimization and pollution prevention, and productivity. 75 Fed. Reg. 31,931.

As indicated in the energy assessment definition, t he focus was on the steam and process heating systems (though process heaters were not within the scope of the rule).

In the final Area Source Rule preamble, EPA include s a discussion of the energy assessment:

...we have carefully limited the requirement to perfo rm an energy assessment to specific portions of the source that directly affec t emissions from the affected

boiler , as indicated by the revised definition of an ener gy assessment in section 63.11237 of subpart JJJJJJ. The emissions that are being controlled come from

the affected source. For coal-fired units, the process changes resulting from a change in an energy using system will reduce the vo lume of emissions at the-7-

affected source. For biomass-fired and oil fired area sources, better management practices at energy using systems will r educe the emissions of HAP from the affected source by reducing fuel consu mption and the HAP released through combustion of fuel. In either case , the requirement controls

the emissions of the affected source. 76 Fed. Reg. 15,568 (emphasis added).

EPA discusses further that the purpose of an energy assessment is to "to reduce the facility energy demand which would result in reduced fuel us e." 76 Fed. Reg. 15,573. EPA stated that it is not the Agency's intent to "to require an energy assessment for the entire facility; the energy assessment is only applied to existing boilers and their energy use systems located at area sources...." Id. Furthermore, EPA provides in the fi nal Area Source Rule that it added the "energy use systems" definition for the purpose of clarifying that:

the components for each boiler system and energy us e system which must be considered during the energy assessment, including elements such as combustion management, thermal energy recovery, energy resourc e selection, and the steam end-use management of each affected boiler. These r evisions clarify that an energy assessment is only required for those portio ns of the facility using the energy generated from the affected boiler system. I d.

Considering this rather lengthy discussion, it is o bvious that it was EPA’s intention to limit the scope of the energy assessments to that which was a ssociated with the energy output from boilers regulated by the rule.

Nonetheless, EPA defines “Energy use system” to in clude "energy use which in many cases is only associated with electricity use, i.e., compres sed air systems, machine drive (motors, pumps, fans), process cooling, facility HVAC, building env elop(e), and lighting). 76 Fed. Reg. 15,600. In other provisions of the Final Area Source Rule, EPA provides that where this electricity is purchased from others (such as an electric utility) , it has no impact on the combustion unit fuel use or associated emissions regulated by this rule, and thus is outside the intended scope of the assessment (see above). Energy assessment under Su bcategory 4, item (7) includes cost of specific improvements, benefits, and time frame for recouping investments. 76 Fed. Reg. 15,602. This is an expansion from the proposed rule that wi ll require significant time and effort for some level of design and estimating to determine vs. tim e limits earlier in the rule. Considering these

issues, clarification needs to be made to the rule to exclude those energy uses that are not

associated with combustion sources on the site.

Furthermore, it is noted that Table 2, Subcategory 4, item (3) is worded differently than in the DDDD- “Inventory of major systems consuming energy from affected boiler(s),” so that the inventory is limited to boiler energy output. But item (2) of that section requires an evaluation of specifications of energy using systems . 76 Fed. Reg. 15,602. Therefore, there are inconsistencies within various provisions of JJJJJ. Because the Energy use system definition was changed in the final rule relative to the proposed rule, EPA should reconsider these issues.-8-

EPA needs to clarify that the scope of the energy a ssessments is to be limited to those facilities and equipment associated with the energy output fro m the boilers regulated under Subpart JJJJJJ. In those cases where cogeneration is incorporated i nto the facility utilizing steam output from the regulated boilers and the cogenerated electrical ou tput is utilized on site, then incorporation of those electricity using facilities and equipment is legitimately included within the scope of the

energy assessment.

C. EPA Should Clarify that the "Stated Maximum Times" Are Mere Estimates That the Agency Cannot Rely on for Enforcement Purposes.

EPA includes in the final Area Source Rule a defini tion for the "stated maximum time" to conduct an energy assessment. None of the maximum times were included in the proposed rule. Considering this, CIBO members had no opportunity t o comment and EPA should therefore

reconsider these issues.

In the final Area Source Rule, EPA provides that th e "stated maximum time" for conducting an energy assessment, i.e., one day maximum for <0.3TB tu/yr heat input and 3 days maximum for 0.3 to 1 TBtu/yr heat input. 76 Fed. Reg. 15,600. This phrasing could imply that a deviation and a potential violation could occur if the energy ass essment effort exceeded those time limits. EPA should reconsider and clarify that these times are actually "expected" maximum times for conducting the assessments. EPA should recognize t hat actual times can exceed those figures depending on site specific conditions. This clear statement is critical so that deviations or enforcement is not applicable to the elapsed times expended on energy assessments.

D. EPA Lacks Authority to Mandate the Energy Assessmen t

An energy assessment does not purport to limit emis sions, nor impose more stringent standards than the MACT floor and is therefore not a beyond-t he-floor standard consistent with the text of the Clean Air Act. Furthermore, even if efficiency measures identified in the energy assessment are actually implemented, the reduced demand for th e output of a regulated source is not an "emission control" technology to limit emissions fr om the regulated source. §112(c)(2); 42 U.S.C. § 7412(d)(3).

III. Emission Testing Requirements Should Be Changed to Be Consistent With the 5-year Title V Permit Review Cycle.

A significant amount of testing will be required by sources to determine the compliance status with respect to the rule and to evaluate and select available control strategies. Capital projects to install necessary control equipment cannot proceed until the testing and evaluation is complete. Due to the high number of sources affected by the r ule that have the same concerns, it is likely that availability of stack testing personnel and la boratory facilities to conduct tests will be limited, adding to the time required to complete th is essential first step. As outlined below, annual compliance testing requiring multiple test r uns for purposes of compliance will further-9-

reduce the availability of testing and laboratory r esources. During the reconsideration process, EPA should revise the emission testing requirements so that frequency of testing is not more then every 5 years.

EPA acknowledges that the cost of testing small boi lers and process heaters is prohibitive. While the cost of emissions testing larger units is less prohibitive, EPA must consider these costs when establishing the frequency of testing.

The benefits of testing more frequently than every 5 years do not justify the costs. HAP emissions change only when operating parameters cha nge (e.g., firing rate, maximum contaminant input limits for chloride and mercury, type of fuel, combustion efficiency, oxygen content, etc.) or when design changes occur. Absen t these changes to an affected source, operating parameters established by implementation of Area Source Rule are more than sufficient to ensure that emissions will not signif icantly change over time. Furthermore, the Area Source Rule provisions require owners and operators to install continuous emission monitors to measure real-time emissions (oxygen and PM), measur e and monitor prescriptive operating limits, as well as monitor, measure, and keep recor ds of each type of fuel on a continuous basis to verify compliance with limits established during the compliance test. The Area Source Rule regulations also stipulate that sources must perfor m testing under a representative operating load and require sources to maintain within 110% of the average operating load observed during testing. Based on these stringent monitoring requi rements, the operating parameters established during testing are sufficient for a source to demon strate compliance for a 5-year period. Modifications will be tested under the provisions f or new and modified sources, and do not need to be considered in ongoing test requirements.

Other regulations support a 5-year testing cycle. For example, 40 CFR §75 requires low mass

emissions units to establish NOx emissions curves b ased on testing conducted every 5 years. Several states require that testing be conducted up on each 5-year Title V permit renewal. All affected major sources subject to Boiler MACT are r equired to have Title V Permits.

IV. EMISSIONS AVERAGING

A. EPA Should Include Emissions Averaging for Area Sou rces.

EPA included emissions averaging as a compliance op tion in the final Boiler Rule, and this should be a compliance option for area sources as w ell. EPA has previously noted that the Small

Business Administration Panel "recommended that EPA carefully weigh the potential burden of compliance requirements and consider for small enti ties options such as, emission averaging within facility. . . " 75 Fed. Reg. 31,919. Althoug h EPA asserts that it "proposed provisions

consistent with each of the Panel's recommendations regarding area source facilities," EPA did

not include in the final Area Source Rule an emissi on averaging compliance alternative for area sources. EPA has further acknowledged that "emissi ons averaging represents an equivalent, more flexible and less costly alternative to contro lling certain emission points to MACT levels" and its application "would not lessen the stringenc y of the MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators." 75 Fed. Reg. 32,034.-10-

During the reconsideration process, EPA should adop t this flexible compliance alternative for

area sources.

B. EPA Should Not Include a 10% Discount Factor.

In the final Boiler Rule, EPA includes a restrictio n on emissions averaging that requires facilities using that option to meet a standard that is 10% st ricter than the otherwise applicable limits. 76 Fed. Reg. 15,670. EPA should not include this 10% p enalty for using emissions averaging because it is arbitrary, unnecessary for environmen tal protection and reduces the flexibility that averaging provides.

Given the accuracy of heat input weighted emission calculations, there is no uncertainty that the average emission rates will be any less stringent t han when not using averaging. Because EPA has already determined that the standards in the ru le achieve the maximum emission reduction achievable for health and environmental protection, to require an additional 10% reduction of emissions has no basis in the environmental underpi nnings of the rule. Because emissions averaging is a compliance alternative, the 10% disc ount factor would constitute a beyond-the floor requirement. Although the 10% discount may be perceived as a fair trade-off for the flexibility of emissions averaging, it still lacks a legal basis and creates a disincentive for source s to use this compliance method. Where, as here, prop osed emission limits are very tight, sources

will not be able to ensure an additional 10% reduct ion in emissions below the limits and imposing this penalty effectively would deprive man y sources of the availability of the emissions averaging compliance alternative.

V. ISSUES NEEDING CLARIFICATION

A. EPA Should Revise the Definition of "Natural Gas Cu rtailment."

The overall construct of the final rule definition of “Period of natural gas curtailment or supply interruption” presents problems that could be resolved through t echnical clarification or through further rulemaking action.

NG curtailment is defined in the Area Source Rule:

Period of natural gas curtailment or supply interru ption means a period of time during which the supply of natural gas to an affect ed facility is halted for reasons beyond the control of the facility. The act of ente ring into a contractual agreement with a supplier of natural gas established for curt ailment purposes does not

constitute a reason that is under the control of a facility for the purposes of this definition. An increase in the cost or unit price o f natural gas does not constitute a period of natural gas curtailment or supply interru ption. 76 Fed. Reg 15,601.

This definition is apparently written to protect th ose firms whose supply is downstream of a Local Distribution Company. Users downstream of a LDC can indeed have their supply halted

when the needs of users exceed the LDC’s available supply. In such a scenario, residential users-11-

(& hospitals, etc) would be given priority and an i ndustrial firm would be shut off. This definition is a good and constructive thing for suc h users.

However, the current definition does not address th e range of gas supply arrangements and would likely create confusion and eliminate routine cost-effective use of gas purchase contract arrangements. Such impacts would extend beyond EPA authority and delve into state and FERC regulatory authority. The range of gas supply arra ngements can include purchase from a Local Distribution Company (LDC) under state jurisdiction or interstate gas purchase under FERC jurisdiction. Purchased transportation can be firm (a consumer contracts for a specific amount of transport capacity) or interruptible (a consumer ca n be interrupted by the transporting entity at the transporting entity’s will), or a combination o f firm and interruptible. Because a site must pay a cost for firm transportation whether the gas is actually purchased or not, many large natural gas consumers utilize contracts that incorporate a combination of firm and interruptible supply contracts to optimize transportation costs in light of variation in natural gas demand.

Normally, with purchase of firm transportation, the risk of curtailment limits a firm’s delivery amount to the firm transport capacity purchased (or the firm’s daily nomination, whichever is less). Curtailment typically occurs when demand is unusually high, e.g., with very cold weather. Firm transport customers are normally only subject to curtailment to less than their firm capacity when the transporter suffers a force majeure situat ion (e.g., a compressor station failure, pipe failure), or the supply is significantly disrupted (e.g. a major hurricane in the Gulf of Mexico).

In the case of interstate gas contracts, there are provisions that would hypothetically allow a consumer to buy natural gas in excess of their cont ractual firm transportation amount during a curtailment. However, penalties in tariff agreemen ts, regulated by FERC, are draconian and

intended to make the a violation of curtailment so painful as to effectively prohibit a consumer from attempting to defy the curtailment order (e.g. one interstate pipeline tariff cites a $15 per dth penalty on top of Henry Hub prices, effectively quadrupling the cost of natural gas). In contrast, for firms purchasing gas from a local dis tribution company, there is little or no ability to buy in defiance of a curtailment order, and custome rs are required to honor the curtailment order. If they do not, the customer is subject to huge pen alties for amounts taken above the contract quantity.

For interruptible service, or for that portion of a supply contract that is interruptible, both

interstate and local distribution would be “halted” or “restricted” under Operational Flow Order (OFO) conditions (or pre-OFO conditions). Because many large consumers of natural gas utilize contracts that combine firm and interruptible trans portation, an OFO represents an unpredictable constraint on a firm’s ability to operate their pla nt at optimal levels. Those firms whose natural gas supply contracts consist entirely of firm deliv ery, this would an infrequent event.

Considering these issues with the current definitio n, CIBO recommends that EPA address the following during the administrative reconsideration process:-12- • EPA should not restrict the ability of natural gas consumers to obtain the most appropriate available gas purchasing contract arrangement for their

purposes.

• EPA should allow use of backup liquid fuel firing u nder those situations where the supply of natural gas is restricted to th e boiler/process heater operator under any purchase contract arrangement to the extent that either a very high cost or a penalty would be involved for continued natural gas use at pre-restriction levels. Note that gas suppl iers do not have automatic shutoff capability, but rather they rely on custome rs taking appropriate action to reduce gas use when needed.

• The intention of the new sentence added to the defi nition of “period of natural gas curtailment or supply interruption” in the final rule per the comment and the EPA response to that comment noted above appears to be to clarify that the act of establishing a natura l gas purchase contract itself is not the action being used to trigger the curtailment or interruption, but that only the action of the supplying entity to restrict gas consumption under any available contract arrangement is the tri ggering event relative to gas supply to the facility.

• However, the following EPA statement in the preambl e creates confusion:

“... the definition of ‘‘Period of natural gas curtailm ent’’ was revised to clarify that contractual agreements for curtailed g as usage or fluctuations in price do not constitute periods of gas curtailme nt under the scope of this regulation.” This could be interpreted to mean tha t if an entity contracted for interruptible gas, that the use of backup liqui d fuel during periods of supplier curtailment would actually not be allowed under this rule. It is hard to believe that EPA would intentionally use th is hammer to push boiler and process heater operators to higher price d contracts for firm gas, when such action would directly impede gas supplier s from being able to provide adequate gas supplies to other “critical” c ustomers (e.g. residential consumers). CIBO assumes this was not EPA’s intent , but rather EPA was trying to address “hedging” or other market tra nsactions not associated with supply limitations. In any case, E PA must provide further clarification so that owners/operators are not disa dvantaged in the natural gas market simply by trying to maintain high facili ty uptime with use of backup fuels.

Furthermore, EPA did not address the issue of on-si te natural gas system emergencies that might occur and restrict the ability to burn natural gas in boilers and process heaters. Similar to natural gas supplier emergency conditions such as equipment or piping failures, similar failures can occur within the affected facility fenceline. If a nd when such failures occur, it is necessary for operators to cease firing of natural gas in certain affected units to maintain safety of personnel and effect repairs. Where backup fuel is available , use of that fuel could allow facilities to remain in operation and prevent facility shutdowns, severe equipment problems and unsafe conditions due to loss of steam or process heat. E PA should allow use of backup liquid fuel-13-

under similar conditions as supply curtailments or interruptions for emergencies within the plant site that necessitate ceasing use of natural gas on specific affected units.

EPA should modify the wording of the final rule to clarify that nothing in the final rule impacts the ability of natural gas consumers to utilize any available natural gas purchase contract arrangement and that the curtailment or supply inte rruption provision applies similarly to any purchase contract arrangement. The definition shou ld be modified to indicate that the period of natural gas curtailment or supply interruption mean s a period of time during which the supply of natural gas to an affected facility is halted, rest ricted, or penalized for reasons beyond the control of the facility. The last sentence should be delet ed or modified to indicate that an increase in the cost or unit price of natural gas due to normal mar ket fluctuations not during periods of supplier delivery restriction does not constitute a period o f natural gas curtailment. EPA should clarify that financial penalties for exceeding curtailment events (such as “Operational Flow Orders”, etc.) described in tariff agreements regulated by F ERC are considered to be supply interruptions beyond the control of a facility. EPA should also clarify that on-site natural gas system emergencies or equipment failures can be similarly treated as periods of supply interruption.

VI. TECHNICAL CORRECTIONS

A. EPA Should Clarify Subpart DDDDD, Table 7 - Demonst rating Continuous Compliance.

Subpart DDDDD, Table 7, Item 1.c. includes the word “block” in stating the following requirement: “Maintaining opacity to less than or e qual to 10 percent (daily block average).” 76 Fed. Reg. 15,605. It appears that other similar re quirements do not include the word “block” in the compliance requirement statement. Considering this, EPA should revise the following items in Table 7 as noted below for clarity and to reduce potential confusion:

3.c. “Maintaining the 12-hour block average pressure drop...”

4.c. “Maintaining the 12-hour block average sorbent or carbon injection rate...”

5.c. “Maintaining the 12-hour block average secondary amperage and voltage, or total power input...”

7.b. “Maintaining the 12-hour block average oxygen content...”

B. EPA Should Clarify the Requirements of Section 63. 11220.

It appears that there are conflicting requirements in § 63.11220. 76 Fed. Reg. 15,594. Specifically, paragraph (a) requires triennial perf ormance tests; however, paragraphs (b) and (c) incorporate the wording from Subpart DDDDD relative to 3 consecutive years’ results <=75% of emission the limit in order to go to triennial test ing. Considering this, EPA should delete §§ 63.11220(b) and 63.11220(c) to eliminate incorre ct and conflicting statements.-14-

C. EPA Should Clarify that the Area Source Rule Does N ot Apply To Process Heaters.

As indicated in § 63.11193, the final Area Source R ule is only applicable to boilers, not process heaters. 76 Fed. Reg. 15,591. Despite this fact, E PA references process heaters in paragraphs (2) and (3) of the definition of " Energy assessment. " 76 Fed. Reg. 15,600. EPA should revise both of those paragraphs to delete the term "process heater. " This will help to avoid confusion and maintain consistency with rule applicability.

CONCLUSION

For all of the foregoing reasons CIBO respectfully requests that EPA grant the Petition for

Reconsideration.

If you have any questions concerning our comments o r require clarification, please contact me at 703.250.9042. Thank you for your consideration.

Sincerely yours,

/s/ Robert D. Bessette

Robert D. Bessette

President