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 Emission Standards for Hazardous 

Air Pollutants for Area Sources: Industrial, Commercial, 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 Owners (CIBO) petitions the Administrator of the United 

States Environmental Protection Agency (EPA) to reconsider specific provisions in its final rule, 

National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, 

and Institutional Boilers (Area Source Rule), 76 Fed. Reg. 15,554 (Mar. 21, 2011). 

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, costeffective energy and environmental regulations for industrial boilers. CIBO supports regulatory 

programs that provide industry with enough flexibility to modernize – effectively and without 
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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 Institutional 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 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 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. Furthermore, during the reconsideration of the rule, EPA may stay the 

effectiveness of the rule. Id. 

CIBO respectfully requests that EPA grant reconsideration of the following issues. 

I. O2 MONITORING REQUIREMENTS. 

A. Petitioners Were Not Given the Opportunity to Comment on the New O2 

Monitoring Requirement Contained in the Final Area Source Rule. 

The final Area Source Rule creates new O2 monitoring 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 limit on coal fired subcategories with 

compliance proven by a triennial Method 10 CO emission 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 appropriate or workable in some cases and 

additional flexibility is required. 

In the proposed Area Source rule, EPA established CO 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 units 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 triennial Method 10 CO performance testing 

to demonstrate compliance by those units with CO emission limits and the use of an O2 CEMS 
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to demonstrate compliance on a 12-hour block average basis with the minimum O2 operating 

limit established during performance testing. 76 Fed. Reg. 15,595-596. 

EPA is requiring that the oxygen level shall be monitored 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, appendix 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 appropriate mandatory monitoring requirement for 

a CO limit based on stack test data obtained at full load conditions, monitoring O2 levels in the 

stack or ductwork leading to the stack to ensure continuous 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 automatically controlled for optimum combustion 

conditions. The sensing location for existing O2 monitors 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 prevent unsafe operating conditions. For many 

types of combustion units, that location is near the boiler or process heater furnace outlet in a 

position upstream of any potential air inleakage points to avoid erroneous excess air indications. 

This location is also upstream of air preheaters where utilized, thus avoiding the erroneous (high 

O2) indications due to inherent leakage across regenerative air preheater seals or potential tube 

leakage in recuperative air preheaters. 

For those units equipped with existing O2 sensors and O2 trim control systems, flue gas 

composition at those locations would already be used 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 location would be logical and proper from a 

technical perspective. However, O2 analyzers utilized for these existing purposes are not 

compliant CEMS meeting PS-3 requirements relative to positioning or other QA/QC 

requirements. They are, however, calibrated and maintained 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 leakage points, thus leading to variations in 

readings that can impact operation and long term compliance. 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 from the furnace as well as any air inleakage or 

internal air heater leakage, so the impact is not of consequence from a combustion safety or 

direct compliance perspective. However, if it is required to actually monitor and maintain O2 

level, then the most appropriate location for sensing that O2 level is upstream of any potential 

leakage points. By definition, those locations will 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. 
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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 new 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 ensure 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 expense 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 comment on its use. Considering this, EPA should 

reconsider this new requirement. 

B. EPA's CO Emission Limits Were Established Incorrectly. 

Some existing area source boilers are already required to use CO CEMS. In those cases, even 

with the final rule as written, instantaneous CO spikes could be considered credible evidence 

leading to deviations if those readings under any operating conditions exceed the CO limits that 

were established using reference method test data at maximum unit operating load. It is well 

known that CO emissions vary widely over normal load conditions. 

However, in addition to units required to use CO CEMS, there may also be units that would 

prefer to install CO CEMS, so that an alternative CO limit based on use of CEMS is needed. It 

would be much more appropriate and cost effective for regulated facilities and regulatory 

authorities if EPA would provide alternative CO limits and their basis for facilities to utilize CO 

CEMS instead of O2 CEMS, rather than requiring individual facilities to petition for alternative 

monitoring practices. 

In order to allow for use of CO CEMS with O2 correction, 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/shutdown periods, an appropriate basis for a CO 

limit using a CO CEMS would be a 30-day rolling average based on actual CO readings over the 

appropriate operating range. 

CIBO notes that there are other issues related to the O2 provisions of the final Area Source Rule. 

Specifically, O2 compliance basis for O2 CEMS is given as 30 day rolling average. This appears 

to be an error since it is a12-hour block average that 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. 
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II. ENERGY ASSESSMENT 

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

Area Source Rules. 

In several documents referenced below, EPA stated its intent to recognize in the final Area 

Source Rule the sensitivity of confidential business information (CBI) contained in energy 

assessments. Despite this fact, it appears that EPA did not fully incorporate its intentions with 

regard to the treatment of CBI in the final Area Source 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 § 63.11215(b) required 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 the energy assessment report, 

along with a signed certification that the assessment is an accurate depiction of 

your facility. 

In the final Area Source Rule, § 63.11214(c) requires 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 energy 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 contrary to the approach taken in the final Boiler 

Rule, where § 63.7530(e) provides: 

[y]ou must include with the Notification of Compliance Status a signed 

certification that the energy assessment was completed according to Table 3 to 

this subpart and is an accurate depiction of your facility. 76 Fed. Reg. 15,675. 

Considering the express text of the final regulations, submission of energy assessment reports is 

not required under the final Boiler rule. CBI is equally an issue for companies operating area 

source boilers as it is for major source boilers and process heaters. As such, a similar approach 

in both rules is justified. EPA has provided no justification for requiring submission of the 

energy assessment reports for area sources while not 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 similarly to their treatment for major sources. 

Specifically, in the RTC, Vol.2, p.461, EPA states:

 
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In the final rule, the energy assessment is not required 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 conducted according to the 

requirement in the final rule. The facility is required to keep records that the work 

practices and management practices were complied with. 

It appears that EPA did not fully incorporate its intentions 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 certification 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 accurate 

depiction of your facility and submit, upon request, the energy assessment report. 

B. EPA Should Clarify the Scope of the Energy Assessment. 

EPA appears to have intended that the scope of the energy assessments be limited to those 

components associated with the energy output from boilers 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 included 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 "Energy Assessment" as follows: 

Energy assessment means an in-depth assessment of a facility to identify 

immediate and long-term opportunities to save energy, focusing on the steam and 

process heating systems which involves a thorough examination 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, the 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 includes a discussion of the energy assessment: 

...we have carefully limited the requirement to perform an energy assessment to 

specific portions of the source that directly affect emissions from the affected 

boiler, as indicated by the revised definition of an energy 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 volume of emissions at the 
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affected source. For biomass-fired and oil fired area sources, better 

management practices at energy using systems will reduce the emissions of 

HAP from the affected source by reducing fuel consumption 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 use." 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 final 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 use system which must be 

considered during the energy assessment, including elements such as combustion 

management, thermal energy recovery, energy resource selection, and the steam 

end-use management of each affected boiler. These revisions clarify that an 

energy assessment is only required for those portions of the facility using the 

energy generated from the affected boiler system. Id. 

Considering this rather lengthy discussion, it is obvious that it was EPA’s intention to limit the 

scope of the energy assessments to that which was associated with the energy output from boilers 

regulated by the rule. 

Nonetheless, EPA defines “Energy use system” to include "energy use which in many cases is 

only associated with electricity use, i.e., compressed air systems, machine drive (motors, pumps, 

fans), process cooling, facility HVAC, building envelop(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 Subcategory 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 will require significant time and effort for some 

level of design and estimating to determine vs. time 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. 
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EPA needs to clarify that the scope of the energy assessments is to be limited to those facilities 

and equipment associated with the energy output from the boilers regulated under Subpart JJJJJJ. 

In those cases where cogeneration is incorporated into the facility utilizing steam output from the 

regulated boilers and the cogenerated electrical output 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 definition 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 to comment and EPA should therefore 

reconsider these issues. 

In the final Area Source Rule, EPA provides that the "stated maximum time" for conducting an 

energy assessment, i.e., one day maximum for <0.3TBtu/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 assessment 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 that 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 Assessment 

An energy assessment does not purport to limit emissions, nor impose more stringent standards 

than the MACT floor and is therefore not a beyond-the-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 the output of a regulated source is not an 

"emission control" technology to limit emissions from 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 rule that have the same concerns, it is likely 

that availability of stack testing personnel and laboratory facilities to conduct tests will be 

limited, adding to the time required to complete this essential first step. As outlined below, 

annual compliance testing requiring multiple test runs for purposes of compliance will further 
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reduce the availability of testing and laboratory resources. 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 boilers 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 change (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. Absent 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 significantly 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), measure and monitor prescriptive operating 

limits, as well as monitor, measure, and keep records 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 perform 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 requirements, the operating parameters established 

during testing are sufficient for a source to demonstrate compliance for a 5-year period. 

Modifications will be tested under the provisions for 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 based on testing conducted every 5 years. 

Several states require that testing be conducted upon each 5-year Title V permit renewal. All 

affected major sources subject to Boiler MACT are required to have Title V Permits. 

IV.EMISSIONS AVERAGING 

A. EPA Should Include Emissions Averaging for Area Sources. 

EPA included emissions averaging as a compliance option in the final Boiler Rule, and this 

should be a compliance option for area sources as well. 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 entities options such as, emission averaging 

within facility. . . " 75 Fed. Reg. 31,919. Although 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 emission averaging compliance alternative for area 

sources. EPA has further acknowledged that "emissions averaging represents an equivalent, 

more flexible and less costly alternative to controlling certain emission points to MACT levels" 

and its application "would not lessen the stringency of the MACT floor limits and would provide 

flexibility in compliance, cost and energy savings to owners and operators." 75 Fed. Reg. 32,034. 
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During the reconsideration process, EPA should adopt this flexible compliance alternative for 

area sources. 

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

In the final Boiler Rule, EPA includes a restriction on emissions averaging that requires facilities 

using that option to meet a standard that is 10% stricter than the otherwise applicable limits. 76 

Fed. Reg. 15,670. EPA should not include this 10% penalty for using emissions averaging 

because it is arbitrary, unnecessary for environmental 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 than when not using averaging. Because EPA 

has already determined that the standards in the rule 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 underpinnings of the rule. Because emissions 

averaging is a compliance alternative, the 10% discount 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 sources 

to use this compliance method. Where, as here, proposed emission limits are very tight, sources 

will not be able to ensure an additional 10% reduction in emissions below the limits and 

imposing this penalty effectively would deprive many sources of the availability of the emissions 

averaging compliance alternative. 

V. ISSUES NEEDING CLARIFICATION 

A. EPA Should Revise the Definition of "Natural Gas Curtailment."

The overall construct of the final rule definition of “Period of natural gas curtailment or supply 

interruption” presents problems that could be resolved through technical clarification or through 

further rulemaking action. 

NG curtailment is defined in the Area Source Rule: 

Period of natural gas curtailment or supply interruption means a period of time 

during which the supply of natural gas to an affected facility is halted for reasons 

beyond the control of the facility. The act of entering into a contractual agreement 

with a supplier of natural gas established for curtailment 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 of natural gas does not constitute a 

period of natural gas curtailment or supply interruption. 76 Fed. Reg 15,601. 

This definition is apparently written to protect those 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 
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(& hospitals, etc) would be given priority and an industrial firm would be shut off. This 

definition is a good and constructive thing for such users. 

 

However, the current definition does not address the 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 arrangements 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 can be interrupted by the transporting entity at 

the transporting entity’s will), or a combination of 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 situation (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 contractual firm transportation amount during a 

curtailment. However, penalties in tariff agreements, 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 distribution company, there is little or no ability to

buy in defiance of a curtailment order, and customers are required to honor the curtailment order. 

If they do not, the customer is subject to huge penalties 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 transportation, an OFO represents an unpredictable 

constraint on a firm’s ability to operate their plant at optimal levels. Those firms whose natural 

gas supply contracts consist entirely of firm delivery, this would an infrequent event. 

Considering these issues with the current definition, CIBO recommends that EPA address the 

following during the administrative reconsideration process: 
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• 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 under those situations 

where the supply of natural gas is restricted to the 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 suppliers do not have automatic 

shutoff capability, but rather they rely on customers taking appropriate 

action to reduce gas use when needed. 

• The intention of the new sentence added to the definition 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 natural 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 triggering event relative to 

gas supply to the facility. 

• However, the following EPA statement in the preamble creates confusion: 

“... the definition of ‘‘Period of natural gas curtailment’’ was revised to 

clarify that contractual agreements for curtailed gas usage or fluctuations 

in price do not constitute periods of gas curtailment under the scope of this 

regulation.” This could be interpreted to mean that if an entity contracted 

for interruptible gas, that the use of backup liquid fuel during periods of 

supplier curtailment would actually not be allowed under this rule. It is 

hard to believe that EPA would intentionally use this hammer to push 

boiler and process heater operators to higher priced contracts for firm gas, 

when such action would directly impede gas suppliers from being able to 

provide adequate gas supplies to other “critical” customers (e.g. residential 

consumers). CIBO assumes this was not EPA’s intent, but rather EPA 

was trying to address “hedging” or other market transactions not 

associated with supply limitations. In any case, EPA must provide further 

clarification so that owners/operators are not disadvantaged in the natural 

gas market simply by trying to maintain high facility uptime with use of 

backup fuels. 

Furthermore, EPA did not address the issue of on-site 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 and 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. EPA should allow use of backup liquid fuel 
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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 interruption provision applies similarly to any 

purchase contract arrangement. The definition should be modified to indicate that the period of 

natural gas curtailment or supply interruption means a period of time during which the supply of 

natural gas to an affected facility is halted, restricted, or penalized for reasons beyond the control

of the facility. The last sentence should be deleted or modified to indicate that an increase in the 

cost or unit price of natural gas due to normal market fluctuations not during periods of supplier 

delivery restriction does not constitute a period of 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 FERC 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 - Demonstrating Continuous 

Compliance. 

Subpart DDDDD, Table 7, Item 1.c. includes the word “block” in stating the following 

requirement: “Maintaining opacity to less than or equal to 10 percent (daily block average).” 76 

Fed. Reg. 15,605. It appears that other similar requirements 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 performance 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 testing. Considering this, EPA should delete 

§§ 63.11220(b) and 63.11220(c) to eliminate incorrect and conflicting statements. 
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C. EPA Should Clarify that the Area Source Rule Does Not Apply To Process Heaters. 

As indicated in § 63.11193, the final Area Source Rule is only applicable to boilers, not process 

heaters. 76 Fed. Reg. 15,591. Despite this fact, EPA 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 or require clarification, please contact me at 

703.250.9042. Thank you for your consideration. 

Sincerely yours, 

/s/ Robert D. Bessette

Robert D. Bessette 

President