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December 28, 2009 

Lisa P. Jackson 

Office of the Administrator 

Environmental Protection Agency 

Room 3000, Ariel Rios Building 

1200 Pennsylvania Ave NW, 

Washington, DC 20004 

CC: 

Carole Cook 

Climate Change Division 

Environmental Protection Agency 

Office of Atmospheric Programs (MC-6207J) 

1200 Pennsylvania Ave NW 

Washington, DC 20460 

Richard Ossias 

Associate General Counsel for the Air and Radiation Law Office 

Office of General Counsel (Mail Code 2344A) 

Environmental Protection Agency 

1200 Pennsylvania Ave NW 

Washington, DC 20004 

THE AMERICAN PETROLEUM INSTITUTE AND THE NATIONAL PETROCHEMICAL AND REFINERS 

ASSOCIATION’S PETITION FOR RECONSIDERATION, REQUEST FOR STAY, AND 

REQUEST FOR ADDITIONAL RELIEF REGARDING

THE FINAL RULE FOR MANDATORY REPORTING OF GREENHOUSE GASES

Docket No. EPA-HQ-OAR-2008-0508 

 

I. INTRODUCTION 

The American Petroleum Institute (“API”) has approximately 400 member 

companies that are involved in all aspects of the oil and gas industry. Similarly, the National 

Petrochemical and Refiners Association (“NPRA”) represents nearly 500 members, including 

virtually all U.S. refineries and petrochemical manufacturers. Accordingly, API and NPRA 

(collectively, “Petitioners”) represent a highly important segment of the industry stakeholders 

who will become subject to the requirements of the recently promulgated Rule for Mandatory 

Reporting of Greenhouse Gases. 74 Fed. Reg. 56,260 (Oct. 30, 2009) (the “MRR”). Petitioners 

and their members are proud of their contributions to greenhouse gas (“GHG”) estimation and 

reporting methods. In fact, API’s guidelines are used worldwide for developing corporate GHG 

emission inventories in all segments of the oil and gas industry. Accordingly, Petitioners and 

their members appreciate the need for a consistent approach to GHG emissions reporting, and 
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Petitioners support the development of a single, harmonized national GHG emissions reporting 

program. 

The MRR has broad implications for all sectors of the economy, and Petitioners’ 

members will be affected by the rule both as operators of regulated facilities, and as suppliers of 

the fuels that are essential to our national economy. Petitioners and their members are confident 

that the important objectives of the MRR can be fully realized while at the same time providing 

for the lead time and flexibility necessary to achieve compliance without unreasonably disrupting 

regulated industry. It is vitally important to our economy that Petitioners’ members meet the 

initial requirements of the MRR without a resulting disruption to our energy infrastructure or a 

larger impact to our economy. For that reason, Petitioners and their members are particularly 

concerned about several elements of the final MRR that unreasonably limit compliance 

flexibility or require further clarification. Following promulgation of a rule with the MRR’s 

scope, importance, and novelty, EPA should spare no opportunity to improve the rule. 

Petitioners and their members appreciate EPA’s efforts to date to address 

stakeholder concerns related to MRR compliance obligations. However, the MRR is one of the 

most complex rulemakings EPA has ever undertaken, with very tight timeframes for compliance, 

and a number of significant issues remain unresolved. As a result, Petitioners and their members 

request EPA’s reconsideration of several aspects of the final MRR pursuant to Section 

307(d)(7)(B) of the Clean Air Act (“CAA” or “the Act”), with a corresponding stay of the 

effectiveness of relevant provisions as appropriate. Specific issues for EPA’s reconsideration are 

described in detail below, but Petitioners’ requests generally relate to: (1) the MRR’s April 1, 

2010 deadline to discontinue “best available monitoring methods”; (2) new calibration 

requirements in the final rule since proposal; and (3) new emission factors and high heat values 

for refinery “still gas” added since proposal. Reconsideration of these important issues is 

necessary to avoid rule-related disruptions at the nation’s most complex petroleum refining and 

chemical manufacturing facilities. Reconsideration of the relatively narrow field of issues listed 

below can be accomplished without compromising the purposes of the MRR. 

In addition to their formal petition for reconsideration and associated request for 

stay of certain provisions, Petitioners are requesting that EPA address a number of other critical 

issues listed below, in order to provide much needed clarity with regard to MRR compliance 

obligations. The issues presented in Section III below focus primarily on needed clarifications 

relating to operational issues and minor changes to the rule to improve its workability. In 

addition, a number of requests for technical corrections are included. EPA’s attention to these 

additional issues in the reconsideration process, in a targeted rule revision, or through the 

issuance of guidance would greatly add to the effectiveness of the MRR. 

II. REQUESTS FOR RECONSIDERATION AND REQUESTS FOR STAY 

A. EPA Reconsideration and Stay Under Section 307(d)(7)(B) 

Section 307(d)(7)(B) of the Act provides for EPA reconsideration of a CAA rule 

upon objection by a petitioner. See 42 U.S.C. § 7607(d)(7)(B). Reconsideration is appropriate 

when the objection raised by the petitioner was impracticable to raise during the public comment 

period or the grounds for the objection arise after the public comment period, if the objections 
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are of central relevance to the outcome of the rule. See id. EPA is authorized to stay the 

effectiveness of rules promulgated under the CAA for up to three months during reconsideration. 

See id. 

The reconsideration provision of Section 307(d)(B) is applicable to the MRR 

rulemaking, because the Administrator expressly determined that the MRR rulemaking is subject 

to the procedural provisions of CAA § 307(d). See 74 Fed. Reg. at 56,260. See also 74 Fed. 

Reg. at 56,262 (describing availability of reconsideration of MRR rule). Provisions in the final 

MRR that are the subject of reconsideration requests below were not specifically addressed by 

EPA in its MRR rulemaking proposal, published at 74 Fed. Reg. 16,448 (Apr. 10, 2009). 

Because these provisions were not addressed in the proposal, Petitioners were not afforded the 

opportunity to comment on those elements of the rule. It was therefore impracticable to raise 

objections to these provisions during the public comment period, and reconsideration is 

appropriate with an accompanying stay. See 42 U.S.C. § 7607(d)(7)(B). 

Each objection is discussed below. 

B. Specific Objections and Requests for Reconsideration 

1. Petitioners Request Reconsideration of the MRR’s April 1, 2010 Deadline to 

Discontinue the Use of Best Available Monitoring Methods, with a 

Corresponding Stay During Reconsideration 

As Petitioners have stated throughout EPA’s rulemaking process in consideration 

of the MRR, an implementation schedule that requires regulated entities to begin monitoring 

their source-specific GHG emissions on a highly accelerated basis, without the benefit of Best 

Available Monitoring Methods (“BAMM”), would present serious obstacles to compliance for 

Petitioners’ member companies. While the Agency’s interest in gaining monitored data as soon 

a possible is understandable, the compliance challenges presented by such an implementation 

schedule are not mere inconveniences. The short implementation schedule in the final rule 

allows for the use of BAMM only through March 31, 2010, threatens Petitioners’ member 

companies’ ability to achieve timely compliance, and will place unnecessary pressure on their 

ability to maintain safe and continuous operations necessary to supply the nation’s critical energy 

needs. 

Importantly, the MRR’s compressed implementation schedule is also without 

legislative support. EPA cites the Consolidated Appropriations Act of 2008 (“Appropriations 

Act”) as Congressional direction for the promulgation of the MRR. See 74 Fed. Reg. at 56,264 

(citing Consolidated Appropriations Act, 2008, P.L. 100-161, 121 Stat. 1844, 2128 (2008)). 

While the Appropriations Act called for publication of a draft reporting rule nine months after its 

December 26, 2007 enactment and called for promulgation of a final reporting rule 18 months 

after enactment, nothing in the Appropriations Act required that EPA begin implementation by 

any particular date. EPA missed both of the deadlines that were contained in the Appropriations 

Act.1

 It cannot compensate for those delays by unreasonably compressing the implementation 

schedule of the MRR. Cf. Nat’l Ass’n of Independent Television Producers & Distributors v. 

 

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 See 74 Fed. Reg. at 56,274 (acknowledging that “[g]iven the delay in promulgating the rule, there is less time 

between signature of the rule and a January 1, 2010 start date.”) 
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FCC, 502 F.2d 249 (2d Cir. 1974) (holding that agency failed to allow adequate time to prepare 

for amendment to rule that became effective where television networks had only eight months 

notice of informal report). 

EPA’s preamble discussion shows that the compliance challenges associated with 

an early MRR compliance date were a consideration in the rulemaking, and EPA made clear that 

the final rule’s April 1, 2010 deadline to discontinue the use of BAMM is intended to balance the 

competing objectives of rapid implementation and feasibility in implementation. See 74 Fed. 

Reg. at 56,274. However, the implementation schedule in the final rule is unworkable, 

particularly because the final rule provides only a very limited 30-day opportunity for members 

of the regulated community to seek relief through a request for extension of BAMM. In the 

MRR proposal, EPA proposed a compliance date of January 1, 2010, and EPA sought comment 

on alternative compliance schedules that would have allowed for a full year of BAMM or 

delayed the implementation of the rule until 2011. See 74 Fed. Reg. at 16,471. EPA did not seek 

comment on the implementation schedule that it ultimately finalized, nor did it seek comment on 

the final rule’s mechanism for seeking a BAMM extension. See id. Because the April 1, 2010 

BAMM discontinuation date and the final rule’s limited 30-day opportunity to request an 

extension were not offered for comment as potential scheduling options, reconsideration of those 

options is appropriate today. 

Section 98.3(d)(2) provides that “[t]he owner or operator may submit a request 

to the Administrator to use one or more best available monitoring methods beyond March 31, 

2010.” The rule goes on to note that “the extension request must be submitted to EPA no later 

than 30 days after the effective date of the GHG reporting rule.”

The overall schedule provided by EPA to begin monitoring is too short. The rule 

requires data collection to start on January 1, 2010 and requests for extension on the “use of best 

available monitoring methods” must be submitted within 30 days of the effective date of the rule. 

For the following reasons, and given the sheer size and complexity of the rule, there is not 

enough time for operators to sufficiently understand their compliance obligations related to 

monitoring requirements, data availability, and instrumentation. 

First, the safe installation of required metering equipment requires detailed 

engineering and planning. Because Petitioners’ member companies cannot put employees or the 

public in harm’s way, more time is needed to achieve compliance. Accordingly, EPA should 

provide sufficient time for designing and safely engineering instrumentation installations or 

upgrades. Second, Section 98.3(d)(2)(ii) focuses exclusively on procurement and installation of 

equipment. Although these are important considerations, the rule fails to recognize that 

engineering resources, planning, and a large number of labor hours are needed to integrate 

internal systems and train staff. As a result, equipment procurement and installations should not 

be the only reason for granting an extension. Design, detailed engineering, personnel training 

and systems integration should also be considered. Third, in continuously operated plants there 

is typically no scheduled shutdown for an entire facility. Moreover, unit maintenance and 

turnarounds are not an annual occurrence for all units. EPA has properly recognized this 

important operational reality in the context of instrument calibration; it should also provide 

approval criteria for extending the use of “best available monitoring methods” beyond December 

31, 2010 for equipment installation and upgrades. 
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Finally, the short time to request an extension is unreasonable. Because the time 

available to determine whether a request is necessary is insufficient, EPA will likely be presented 

with thousands of extension requests, many of which could have been avoided if reporters had a 

reasonable amount of time to determine compliance obligations. Accordingly, the schedule 

should provide sufficient time for reporters to properly review their compliance obligations prior 

to submitting an extension request, and thereafter provide sufficient time for EPA to consider 

and act on each request. Such an approach would be similar to the first year of mandatory 

reporting under California’s AB32 GHG reporting regulation and would eliminate the need for a 

burdensome extension process, thereby allowing reporters to focus on the work necessary to 

ensure compliance with the rule. 

For all of the reasons set forth above, Petitioners request that EPA reconsider the 

“[s]pecial provisions for reporting year 2010” of Section 98.3(d). Upon reconsideration, 

Petitioners request that EPA take the following specific actions: 

1. Stay the effectiveness of the monitoring requirements in the MRR to 

allow the use of “best available monitoring methods” through 

December 31, 2010 for all reporters. 

2. Allow the use of “best available monitoring methods” beyond 

December 31, 2010 for equipment installations and/or upgrades by 

adding an extension similar to the calibration requirement extension in 

Section 98.3(i)(6). 

3. In addition to equipment procurement and installation, clarify that 

design, detailed engineering, personnel training and systems 

integration can also support granting an extension. 

4. Consider any extension request granted, where the submitting reporter 

does not receive a response within 30 days. 

2. Petitioners Request Reconsideration of New Calibration Requirements in 40 

C.F.R. § 98.3(i) and a Corresponding Stay During Reconsideration 

New calibration accuracy requirements contained in Section 98.3(i) of the final 

MRR were not included in the proposal As a result, Petitioners were not afforded the 

opportunity to comment on those elements of the rule, and it was therefore impracticable to raise 

objections to these provisions during the public comment period. Reconsideration of Section 

98.3(i) is therefore appropriate with an accompanying stay. See 42 U.S.C. § 7607(d)(7)(B). 

While equipment and instrument calibration needs cannot be overlooked in developing a robust 

and valuable reporting rule, the calibration requirements in the final rule lack sufficient 

flexibility to properly accommodate the wide variety of devices and processes that will be 

subject to their demands. Accordingly, Petitioners request reconsideration Section 98.3(i), and 

Petitioners request that the effectiveness of Section 98.3(i) be stayed during reconsideration. 

Below, Petitioners offer specific substantive requests for EPA’s reconsideration in 

four areas related to the calibration requirements of Section 98.3(i): (1) calibration accuracy 
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requirements; (2) calibration and equipment installation timing; (3) the use of calibration 

accuracy for data verification; and (4) acceptable calibration standards. 

a. Calibration Accuracy Requirements 

Section 98.3(i)(1) of the final rule provides that “flow meters and other devices 

(e.g., belt scales) that measure data used to calculate GHG emissions shall be calibrated prior to 

April 1, 2010 using the procedures specified in this paragraph and each relevant subpart of this 

part. All measurement devices must be calibrated according to the manufacturer’s recommended 

procedures, an appropriate industry consensus standard, or a method specified in a relevant 

subpart of this part. All measurement devices shall be calibrated to an accuracy of 5 percent.” 

Section 98.3(i)(2) specifies that the accuracy of flow meter calibration should be less than 5%, 

when using Eq. A-2. Additionally, Section 98.3(i)(3) addresses accuracy requirements for in-situ

calibration of pressure and temperature transmitters for orifice, nozzle, and Venturi flow meters. 

Specifically, it mandates an accuracy of less than 2% for each measurement point, or less than 

5% for the sum of the three transmitters combined. 

Finally, the definition of “Accuracy” in Section 98.6 provides that “[a]ccuracy of 

a measurement at a specified level...means that the mean of repeat measurements made by a 

device or technique are within 95 percent of the range bounded by the true value plus or minus 

the specified level.”

It is not clear what the initial 5% calibration accuracy entails, and, specifically, 

when the EPA-specified calibration error equation (Eq. A-2) should be used. Typically, when a 

measurement device is initially calibrated, it is set to operate within the error range for the 

specific measurement technology based on the applicable operating standard. Section 98.3(i)(2), 

however, is not clear whether the +/- 5% accuracy requirement applies to the meter prior to or 

after calibration. Moreover, it is not clear whether the 5% calibration accuracy requirement 

applies to all devices used for measuring any parameter, including those used for a Tier 1 and/or 

Tier 2 method under Subpart C, or whether the 5% accuracy requirements apply to on-line 

analyzers (e.g., GCs). Finally, it is not clear whether the 5% accuracy requirements apply to 

existing company procedures and records when “best available monitoring methods’ are used. 

For orifices, nozzles and Venturi flow meters, an overall 5% error must not be 

derived by simple addition of the individual error percentages for each of the calibration 

measurements. Using proper statistical error propagation methods, the aggregated accuracy 

should be based on the square root of the sum of squares. 

Accordingly, Petitioners request that EPA take the following specific actions 

upon reconsideration of Section 98.3(i): 

1. Amend the initial calibration requirements to allow “accuracy of initial 

calibration” to be determined within the error range for the specific 

measurement technology based on the applicable operating standard. 

2. Allow flow meters to be calibrated on-site by trained personnel using 

consensus industry standards. 
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3. Correct the method specified for error summation and use a valid 

statistical error aggregation method. 

b. Calibration and Equipment Installation Timing 

As discussed above, the final rule provides that “flow meters and other devices 

(e.g., belt scales) that measure data used to calculate GHG emissions shall be calibrated prior to 

April 1, 2010.” In addition, in Section 98.3(i)(6) EPA recognizes that for continuously operating 

process units, some calibrations are not possible on-line without disrupting the process. 

Specifically, the rule provides as follows: 

For units and processes that operate continuously with infrequent 

outages, it may not be possible to meet the April 1, 2010 deadline 

for the initial calibration of a flow meter or other measurement 

device without removing the device from service and shipping it to 

a remote location, thereby disrupting normal process operation. In 

such cases, the owner or operator may postpone the initial 

calibration until the next scheduled maintenance outage, and may 

similarly postpone the subsequent recalibrations. Such 

postponements shall be documented in the monitoring plan that is 

required under §98.3(g)(5).

Petitioners are concerned that the limited time available under the final rule to 

calibrate the large amount of equipment could pose a safety hazard, especially because certain 

calibrations and associated maintenance operations may have to be completed during the heart of 

winter in order to meet the March 31st deadline. As a result, the compliance deadlines must be 

extended. For complex facilities, or those that are geographically dispersed, three months is 

insufficient to allow for initial calibration, especially at large, complex facilities. 

Section 98.3(i)(3) allows reporters to meet the calibration requirements for orifice, 

nozzle, and Venturi flow meters by performing in-situ calibration of the differential pressure, 

total pressure, and temperature transmitters. Reporters may need to upgrade the flow meters or 

install pressure and temperature compensation equipment to comply with Section 98.3(i)(3). If a 

shutdown is required to upgrade or install the compensation equipment, it is not clear if the 

compensation equipment must be upgraded or installed by April 1, 2010 (or December 31, 2010 

with an approved extension request) or whether it can be upgraded or installed during the next 

scheduled maintenance outage as provided by Section 98.3(i)(6). 

Consistent with EPA’s decision to allow the delay of initial calibrations for 

continuously operated process units, EPA should authorize the use of “best available 

measurement data,” based on existing company instrumentation and operating practices, until 

new or upgraded equipment can be installed and calibrated. Finally, EPA appears to believe that 

the disruption of normal process operations that allows reporters to delay calibrations for 

continuously operating process units with infrequent planned outages is justified because of the 

need to remove the device from service and ship it to a remote location. However, disruption of 

normal process operations is caused if an outage is required to conduct the calibration, and is not 

dependent upon whether the equipment is shipped to a remote location. 
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Accordingly, for all of the reasons discussed above, Petitioners request that EPA 

take the following specific actions upon reconsideration of Section 98.3(i): 

1. Extend the time for initial calibration of accessible equipment until the 

end of 2010. 

2. Allow the use of “best available measurement data” for continuously 

operated process units until the next scheduled maintenance outage. 

3. Amend Section 98.3(i)(6) by deleting the phrase “and shipping it to a 

remote location.”

c. Use of Calibration Accuracy for Data Verification 

Section 98.3(f) of the final rule includes a general verification clause. However, 

the final rule does not list specific validation criteria or include a timeline for EPA verification. 

For flow meters used to obtain data for calculating GHG emissions, Section 

98.3(i)(2) requires reporters to “...perform all calibrations at measurement points that are 

representative of normal operation of the meter... The calibration error at each measurement 

point shall not exceed 5.0 percent of the reference value.” Section 98.3(f)(6) references “[t]he 

results of all required certification and quality assurance tests of continuous monitoring systems, 

fuel flow meters, and other instrumentation used to provide data for the GHGs reported under 

this part.” 

These requirements make clear that flow meter calibration is a work practice and 

not a monitoring practice. Namely compliance is achieved by performing these calibrations and 

adjusting instruments to the 5% accuracy, pursuant to the schedule provided in the rule and 

documented in the monitoring plan.

Accordingly, Petitioners request that EPA take the following specific actions 

upon reconsideration of Section 98.3(i): 

1. Confirm that the required work practice is performing calibrations and 

adjusting meters where drift occurs. 

2. Confirm that the follow-up calibration accuracy results are not a basis 

for invalidating data in the future.

d. Acceptable Calibration Standards 

The rule provides that companies may use industry consensus standards to meet 

calibration and measurement requirements. Section 98.3 provides that “[a]ll measurement 

devices must be calibrated according to the manufacturer’s recommended procedures, an 

appropriate industry consensus standard, or a method specified in a relevant subpart of this 

part.” 
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In Section 98.7, EPA sets forth a list of standards that are incorporated by 

reference into the rule. API has provided EPA a list of industry standards and EPA has included 

some of those standards in the rule. However, the list of industry standards included in the rule 

is neither comprehensive nor complete. 

The final rule should include a reference to the applicable API standards as noted 

on the list provided to EPA as part of API’s comments package. In addition, Subpart C, General 

Stationary Fuel Combustion Sources, should include a reference to ASME Performance Test 

Codes (ASME PTC) in the list of applicable standards for stationary fuel combustion sources. 

EPA should leverage industry consensus standards development and revision processes to 

achieve EPA’s stated objective of receiving quality data and avoiding the burden of updating and 

maintaining lists of standards that are neither comprehensive nor the most current. 

Accordingly, Petitioners request that EPA take the following specific actions 

upon reconsideration of Section 98.3(i): 

1. Allow companies to document in their monitoring plan which version 

of the standards they are using. 

2. Offer the list of standards provided in the individual subparts as 

examples of industry consensus standards that do not preclude use of 

any other industry consensus standards accepted for similar 

applications. 

3. Petitioners Request Reconsideration of New “Still Gas” Emission Factor and 

High-Heat Value 

The addition of an emission factor and high heat value (“HHV”) for refinery “still 

gas” is also appropriate for reconsideration, because the emission factor and HHV ultimately 

designated for still gas were not included in the proposal. It was therefore impracticable to 

object to, or otherwise comment on, these values during the public comment period and 

reconsideration is appropriate. See 42 U.S.C. § 7607(d)(7)(B). Petitioners recognize that EPA 

added the still gas emission factor and HHV in an effort to mitigate the compliance burden. See

74 Fed. Reg. at 56,326. However, the still gas values ultimately promulgated into the final rule 

are flawed. As a result, Petitioners request reconsideration of the still gas emissions factor and 

HHV in Subpart Y, Table C-1 of the MRR and related emissions calculation methodologies 

specified in Subpart Y of the MRR. In addition, Petitioners seek the specific relief listed below. 

In the preamble to the final rule, EPA discusses the addition of an emission factor 

for “still gas” to Table C-1, allowing refineries that combust refinery fuel gas (still gas) and meet 

either Tier 1 or Tier 2 applicability to use the default CO2 emission factor. 

For calculating CO2 emissions, Section 98.252(a) directs reporters to, “[c]alculate 

and report these emissions under subpart C of this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C, except for CO2 emissions from combustion 

of refinery fuel gas. For CO2 emissions from combustion of fuel gas, use either equation C-5 in 

subpart C of this part or the Tier 4 methodology in subpart C of this part.” 
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Additionally, in the recently released Subpart Y Fact Sheet, a footnote indicates 

that “[f]or CO2 emissions from the combustion of fuel gas, the Tier 3 (equation C-5) or Tier 4 

methodology must be used, as stated in the rule. Rule text supersedes preamble text where 

inconsistencies occur.” 

For calculating CH4 emissions, the default ‘still gas’ heating value in Table C-1 is 

provided in units of MMBtu/gal. This is an error since the metric implies that methane is a 

liquid when it is a gas in refinery processes. The rule goes on to invoke Equation C–8 for 

estimating CH4 and N2O emissions for any fuels for which Tier 1 or Tier 3 methods are used for 

CO2, and also mandates the use of the default HHV values from Table C-1. In contrast, Equation 

C-9a permits the use of actual site HHV when using the Tier 2 method. This approach, and the 

erroneous HHV value, makes it impossible for refineries that use either Tier 1 or Tier 3 to use 

the default values in Table C-1. 

Accordingly, for calculating CO2 emissions only by the use of Equation C-5 (Tier 

3 method in Subpart C or Tier 4 method), the rule precludes smaller refinery combustion units (< 

250 MMBtu/hr) that are combusting refinery fuel gas (still gas) from using either Tier 1 or Tier 2 

methods with the default CO2 emission factor. However, this result is completely inconsistent 

with EPA’s stated intent, in the preamble, to provide burden relief by adding factors for Still Gas 

in Table C-1. 

As EPA noted in a November 5, 2009 meeting with API, EPA believes a majority 

of petroleum refiners have common fuel gas systems that feed combustion devices throughout 

the refinery and that the alternative provided in Subpart C for common pipe configurations will 

significantly reduce the monitoring required for combustion devices. However, a refinery fuel 

gas “system” can vary from no common system to multiple fuel gas systems, to one fuel gas 

system. One or two fuel gas systems at a refinery is not as common as EPA appears to believe. 

For example, one refiner reports less than 50% of its refineries have a common fuel gas system. 

The requirement to use the Tier 3 methodology for all combustion devices at refineries that burn 

fuel gas can result in hundreds of monitoring devices being subject to the rule because a heater or 

boiler can have multiple fuel usage flow meters. 

In addition, the Still Gas HHV value presented in Table C-1 is incorrect. 

According to Petitioners’ review, it is based on EIA documentation for emissions of GHG in the 

U.S. (DOE/EIA-0638 (2006), October 2008). Table 6-8 of the EIA report provides the HHVs of 

the individual samples that are the basis for the default factor. Petitioners’ analysis – averaging 

the individual HHV values – resulted in a value of 1076 Btu/scf. This value should replace the 

current HHV value in Table C-1. Moreover, the applicable definitions in Section 98.6 are 

inconsistent. On the one hand, fuel gas is defined as “gas generated at a petroleum refinery, 

petrochemical plant, or similar industrial process unit, and that is combusted separately or in 

any combination with any type of gas.” On the other hand, still gas is defined as “any form or 

mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. 

The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and 

propylene.” These definitions are inconsistent and create confusion across related rule 

requirements. This confusion is further compounded by the inclusive definition of “natural gas,” 

which provides that “[f]or the purposes of this subpart, the definition of natural gas includes 

similarly constituted fuels such as field production gas, process gas, and fuel gas.” 
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Accordingly, for all of the reasons set forth above, Petitioners request 

reconsideration of the still gas emissions factor and HHV in Table C-1 of the MRR and related 

emissions calculation methodologies specified in Subpart Y of the MRR. Upon reconsideration, 

Petitioners request that EPA take the following specific actions: 

1. Allow refineries access to all the calculation methods (tiers) outlined 

in Subpart C, as applicable. 

2. Allow the use of Tier 1 and Tier 2 methodology with applicable 

default emission factors to reduce the reporting burden for small 

stationary combustion units, including ‘pilots’ on heaters and flares. 

3. Correct Table C-1 to substitute the current default ‘Still Gas’ HHV 

value, which is provided in the wrong units, with 1076 Btu/scf.

4. Allow the use of site-specific HHV values for calculating CH4 and 

N2O for all tiers of CO2 calculations. 

III. REQUEST FOR ADDITIONAL RELIEF UPON RECONSIDERATION 

Given the scope, importance, and novelty of the MRR, a number of additional 

issues warrant EPA’s further consideration in addition to those presented above for Section 

307(d)(7)(B) reconsideration. Petitioners have addressed these important issues below with 

accompanying specific requests for clarification or suggested rule revisions. Petitioners urge 

EPA to act on the requests listed below through issuance of guidance, during reconsideration as 

requested above, or through a new rulemaking to complete necessary revisions. 

A. Confidential Business Information (CBI) 

In the preamble to the final MRR, EPA responds to numerous industry comments 

on issues related to confidential business information (CBI). Specifically, the preamble provides 

that “EPA recognizes the importance of this issue to both reporters and the public. EPA’s public 

information regulations contain a definition of “emissions data” at 40 C.F.R. 2.301, and EPA 

has discussed in an earlier Federal Register notice what data elements constitute emissions data 

that cannot be withheld as CBI (56 FR 7042–7043, February 21, 1991).” 74 Fed. Reg. at 

56,287. 

In order to prevent the need for a case-by-case basis determination of CBI, EPA 

has indicated that it intends to undertake an effort similar to what was done in 1991 for the data 

elements collected in this rule, through a notice and comment process to define what data 

elements are “emissions data” and therefore not subject to CBI protections. See id.

Petitioners welcome a transparent multi-stakeholder process focused on defining 

data elements that constitute emissions data and those elements that should be considered 

confidential and competitive in nature. However, we are concerned that there may not be 

sufficient time for EPA to conduct such a rulemaking prior to the first reporting deadline of 

March 31, 2011. As a result, EPA should provide more detail about the expected rulemaking, 
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including a firm timeline for promulgation. In addition, EPA should provide an alternative 

compliance obligation in the event the rule is not promulgated in a timely manner. 

For all of the reasons set forth above, Petitioners request that EPA take the 

following specific actions: 

1. Provide more detail, in writing, regarding the expected rulemaking to 

address CBI issues, including a clear timeline through promulgation. 

2. Allow records to be maintained on site and made available for 

inspection in the event the expected rulemaking is not concluded in a 

timely manner. 

B. Subpart C – Use of Any Calculation Tier for Combustion-Only Reporters 

Under Section 98.3(d)(3), a facility that is only required to report for stationary 

combustion devices can choose any tier level calculation method for all of 2010, regardless of 

the size of combustion devices. As a result, because Tiers 1 and 2 allow fuel volume to be based 

on “company records” (enabling calculation based on parameters), oil and natural gas production 

operations not covered by Subpart NN or any other subpart can effectively use “best available 

measurement data” for all of 2010. Beyond 2010, facilities subject only to combustion emission 

reporting under subpart C are required to submit a complete report based on the requirements of 

the appropriate method tiers. 

Accordingly, Petitioners request that EPA take the following specific actions: 

1. Amend the instructions for “combustion only” reporters to confirm 

that facilities that are subject to “stationary combustion only” reporting 

can use “best available measurement data” for all of 2010. 

2. Amend the instructions for “combustion only” reporters to provide that 

facilities that are subject to “stationary combustion only” reporting are 

not expected to submit an extension request, or to perform initial 

calibrations of any measurement instruments prior to April 1, 2010. 

C. Subpart Y – Refinery Fuel Gas Sampling Frequency and Method 

Section 98.34(b)(3)(E) provides as follows: “For gaseous fuels other than natural 

gas and biogas (e.g., refinery gas), daily sampling and analysis to determine the carbon content 

and molecular weight of the fuel is required if the necessary equipment is in place to make these 

measurements. Otherwise, weekly sampling and analysis shall be performed.” 

In addition, Section 98.34(b)(3)(E) provides that “[w]here the Tier 3 Calculation 

Methodology is used, reporters are required to determine the carbon content of natural gas, 

biogas, liquid fuels, and solids fuels monthly and of other gaseous fuels such as refinery gas and 

process gas on a daily basis.” However, this is not consistent with the preamble, which provides 

that“[t]he minimum monitoring frequency for refinery fuel gas carbon content and molecular 
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weight was changed to weekly from daily in 40 C.F.R. part 98, subpart C for reporters that do 

not have continuous monitoring equipment.” 74 Fed. Reg. at 56,324. 

It is unclear from the rule what equipment EPA believes is necessary to require 

daily sampling and analysis. 

Accordingly, Petitioners request that EPA take the following specific actions: 

1. Define “necessary equipment” to include only continuous on-line 

analyzers, not hand-drawn samples that are analyzed in a laboratory. 

2. Revise the rule to provide that where gas stream heating values and 

composition fluctuate with operational changes, the sampling 

frequency selected can be consistent with the variability of the stream. 

3. Allow the use of “engineering analysis” in lieu of sampling for streams 

where there are safety concerns such as high temperature and pressure, 

corrosivity, or personnel exposure. 

4. Change the sampling frequency requirements in subparts C and Y to 

allow weekly sampling frequency instead of the daily sampling 

frequency. 

5. Allow refineries to use calculated weekly average carbon content and 

molecular weight based on continuously sampling GCs where 

available. 

D. Subpart Y – Calculation Methods for Insignificant Sources 

The preamble to the final rule, provides that “reporters must report only the 

emissions from sources for which calculation methods are provided in the rule. Calculation 

methods are generally not included for smaller sources of emissions (e.g., coal piles on 

industrial sites).” 74 Fed. Reg. at 56,279. 

In addition, the Technical Support Document for Petroleum Refining (September 

2008, page 21) provides as follows: “There are a variety of GHG emission sources at the 

refinery, which include: asphalt blowing, delayed coking unit depressurization and coke cutting, 

coke calcining, blowdown systems, process vents, process equipment leaks, storage tanks, 

loading operations, wastewater treatment, and waste disposal. To fully account for the refinery’s 

GHG emissions, the emissions from these sources should be reported; however, the emissions 

from these sources are expected to be only about 1 percent of the refinery’s total GHG 

emission.”

The calculation methods provided in the rule for some insignificant sources in 

petroleum refineries are highly inaccurate. Importantly, as noted above, the Petroleum Refining 

TSD makes clear that emissions such as methane from storage tanks, methane from equipment 

leaks, methane and nitrous oxide from catalytic crackers and delayed cokers, methane from 

uncontrolled refinery blowdown systems and some similar sources, are truly insignificant. 
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Despite these clear reasons in support of lessening the reporting burden associated with these 

emissions, the rule requires quantification of such emissions. 

Accordingly, Petitioners request that EPA take the following specific actions: 

1. Stay the effectiveness of the requirement for reporting from 

insignificant sources. 

2. Remove the requirement for reporting from insignificant sources. 

3. Alternatively, if EPA does not remove the requirement for reporting 

from insignificant sources, allow the use of alternative, less detailed 

emission factors or estimation methods developed by trade 

organizations and others, provided the source of the method is 

properly documented. 

E. Various Subparts - The Use of GCs to Measure HHV/CC Varies by Subpart 

Subpart C allows the use of chromatographic analysis as long as the GC is 

operated, maintained and calibrated according to manufacturers’ instructions: "Use any 

applicable methods from the following list to determine the carbon content and molecular weight 

(for gaseous fuel) of the fuel. Alternatively, the results of chromatographic analysis of the fuel 

may be used, provided that the gas chromatograph is operated, maintained, and calibrated 

according to the manufacturer’s instructions." 

Subpart P specifies that an EPA-specified test method must be used to measure 

carbon content / MW of feedstocks. The test methods list includes the following 

chromatography-specific methods: ASTM D1945-03; ASTM D1946-90; UOP 539-97; and GPA 

2261-00. However, nowhere in Subpart P is there any language that allows the use of GCs as 

long as they are “operated, maintained and calibrated according to the manufacturer’s 

instructions.” Rather, the rule mandates the use of an EPA-specified GC method. 

Subpart X / Y Flare Carbon Content or HHV sampling requires that an EPAspecified test method be used to measure HHV / carbon content / MW of feedstocks. The list of 

acceptable test methods is the same as Subpart P above. 

The requirements for gas chromatography should be consistent across all 

Subparts. Accordingly, in order to enable reporters to develop a consistent approach to their 

sampling and analysis obligations, EPA should extend the requirements for the use of GCs under 

Subparts C to Subparts P, X and Y. 

Accordingly, Petitioners request that EPA take the following specific action: 

Insert the following language in each subpart: “Alternatively, the results of chromatographic 

analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, 

and calibrated according to the manufacturer’s instructions.”
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F. Subpart C – Natural Gas Emission Factor 

The definition of Natural Gas in section 98.6 provides as follows: 

“Natural gas may be field quality (which varies widely) or pipeline 

quality. For the purposes of this subpart, the definition of natural 

gas includes similarly constituted fuels such as field production 

gas, process gas, and fuel gas.” 

Section 98.33(b)(1) describes the use of the different GHG calculation methods, 

noting that “[t]he Tier 1 Calculation Methodology: (i) May be used for any fuel listed in Table 

C-1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 

mmBtu/hr or less.” Similarly, Section 98.33(b)(2) provides that “Tier 2 Calculation 

Methodology [m]ay be used for the combustion of any type of fuel in a unit with a maximum 

rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of 

this subpart.” 

Table C-1 of Subpart C lists Natural Gas as “pipeline (weighted U.S. average).” 

At the October 21, 2009 Natural Gas Star meeting in San Antonio, Texas an EPA representative 

stated that the emission factor provided in Table C-1 was intended to apply to a wide spectrum of 

natural gas type fuels, pursuant to the definition in Section 98.6. 

Accordingly, Petitioners request that EPA take the following specific action: 

Amend Table C-1 to list “Natural Gas” rather than “Pipeline”’ to ensure that the default CO2 

emission factor listed in Table C-1 applies to appropriate natural gas, consistent with the 

definition of “natural gas” in Section 98.6 of the final rule. 

G. Subpart A –Annual Report Due Date 

Section 98.3(b) of the final rule requires reporters to submit annual GHG 

emission reports no later than March 31 of each calendar year for GHG emissions in the previous 

calendar year. As previously discussed in API’s comments on the proposed rule, this schedule is 

too compressed and unduly burdensome. 

The rationale provided in the preamble to the final rule for maintaining March 31st

as the annual due date for reporting is very general and the examples provided are not applicable. 

For example, the EU-ETS is not a good comparison because that program only requires CO2

emissions reporting from a limited subset of large facilities in a few sectors. In addition, the 

examples provided in the preamble related to NSPS and NESHAPs are limited to reporting 

excess emissions and monitoring systems performance. The short time provided to compile, 

review, check and certify will impose an excessive burden on reporters and could lead to 

inadvertent errors due to the sheer volume of information requested and the fact that key inputs 

for necessary calculations may not be immediately available after the end of the year. 

Accordingly, Petitioners request that EPA take the following specific action: 

Establish an annual reporting deadline of no earlier than June 30 of each calendar year for the 

previous year. 
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H. Subpart A - Written GHG Monitoring Plan 

Under Section 98.3(g)(5), EPA requires companies to have a GHG Monitoring 

Plan available for inspection if requested during an EPA audit. 

EPA representatives have stated in several Webinars that the monitoring plan is a 

recordkeeping requirement and not a monitoring or reporting requirement. In response to 

comments, EPA has noted that it expects companies would have their monitoring plan ready 

before April 1, 2010. However, it is not clear how this would be reconciled with a request for 

extension and the associated use of available company records for the remainder of 2010. 

Accordingly, Petitioners request that EPA take the following specific actions: 

1. Confirm in writing that the requirement to maintain a monitoring plan 

is a recordkeeping requirement and not a monitoring or reporting 

requirement. 

2. Confirm in writing the date the monitoring plan is required to be 

completed when an extension for the use of BAMM is not issued, and 

the date the plan is required to be completed when an extension of 

BAMM is issued. 

I. Subpart A – Definition of Bulk Natural Gas Liquid or NGL 

The definition of “bulk natural gas liquid or NGL” in Section 98.6 “refers to 

mixtures of hydrocarbons that have been separated from natural gas as liquids through the 

process of absorption, condensation, adsorption, or other methods at lease separators and field 

facilities.” However, these processes are not simple separation processes, but rather, NGL 

extraction processes that are typically performed at “gas plants” and not at “lease separators and 

field facilities.” 

60 C.F.R. Subpart KKK defines “Natural gas processing plant” as “any 

processing site engaged in the extraction of natural gas liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas products, or both.” This definition was changed from the 

proposed version to substitute “extraction” for “separation” because EPA intended to exclude 

facilities that removed liquid from field gas by means other than forced processes, such as 

gravity or natural condensation. 

Accordingly, Petitioners request that EPA take the following specific action: 

Strike the phrase “or other methods at lease separators and field facilities” from the definition of 

bulk natural gas liquid or NGL. 

J. Subpart A – Definition of Petroleum Coke 

The definition for “petroleum coke” in Section 98.6 includes “catalyst coke.” 

Petroleum coke and catalyst coke, however, differ in their typical carbon fraction and use. 

Petroleum coke is a marketable commodity, while catalyst coke is typically regenerated in situ
-17-

and the heat released is used as process heat input. EPA should recognize the distinct and 

different nature of catalyst coke versus petroleum coke. 

Accordingly, Petitioners request that EPA take the following specific actions: 

1. Change the definition of “petroleum coke” to remove the inclusion of 

catalyst coke. 

2. Provide a separate definition for “catalyst coke,” as well as applicable 

emission factors for calculating GHG emissions from the in situ 

regeneration of catalyst coke. 

K. Subpart A – Definition of Standard Conditions 

The proposed rule defined “standard conditions” in accordance with the prevalent 

industry definition of 60F and 14.7 psia (consistent with all US consensus standards). In 

comments on the proposed rule, API noted a discrepancy between the stated standard conditions 

and the “molar volume conversion” factor provided in the equations for calculating emissions 

from gaseous fuels. 

However, instead of providing several “molar volume conversion” factors that 

could be used by reporters under different temperature and pressure conditions, the final rule 

defines “standard conditions” at 68F and 14.7 psia, placing an unnecessary burden on reporters, 

and introducing confusion that could lead to erroneous emission calculations. 

Petitioners request that EPA take the following specific action: Adopt the 

approach recommended in the API compendium (and adopted by CARB in California’s GHG 

rule) where a short list of “molar volume conversion” factors are provided for different 

temperature and pressure conditions and instruct reporters to use the appropriate one for their 

measurement method for quantifying GHG emissions. 

L. Subpart C - Treatment of Fuel Mixtures 

Under the final rule, there are no default emission factors for fuel mixtures. As a 

result, Tier 1 and 2 methods cannot be used to estimate combustion emissions from fuel 

mixtures. However, because CO2 emissions are based on the carbon content of fuel, multiplying 

the volume of each pre-mixed fuel by its respective fuel-based emission factor results in an 

accurate estimate of CO2 for the fuel mixture. 

Accordingly, Petitioners request that EPA take the following specific action: 

Revise the fuel estimation requirements in Subpart C to allow an alternative (based on default 

emission factors) to the use of carbon content measurements or CEMS for smaller sources for 

which Tier 1 and 2 methods are applicable. 

M. Subpart C - Use of Different Methods (Tiers) for a Single Combustion Device 

Section 98.36(b) allows combustion units to “...report the following information 

for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in § 
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98.33(a) to calculate CO2 emissions...” with subsections (4) (5) and (6) stating that applicable 

calculations should be performed for each type of fuel combusted. Additionally, subsection (6) 

provides: “For a unit that uses Tiers 1, 2, and 3; the CO2...” 

The stated approach of different calculation method tiers can be used for both 

sequential intervals during the reporting year where different fuels are combusted in a single 

device, and/or for concurrent use in the case of fuel mixtures. 

Accordingly, Petitioners request that EPA take the following specific action: 

Revise the rule to specifically state that the use of multiple tiers for simultaneous combustion of 

multiple fuels in different streams is allowed. 

IV. CONCLUSION 

For the reasons cited above, Petitioners urge EPA to reconsider those elements of 

the MRR that are listed in Section II, above. As appropriate, EPA is urged to stay the 

effectiveness of those provisions of the MRR that are subject to reconsideration. Further, 

Petitioners request that EPA make the needed clarifications and revisions to the MRR as 

identified in Section III, above. 

Dated: December 28, 2009 

 

 Matthew G. Paulson 

Baker Botts 

1500 San Jacinto Center 

98 San Jacinto Blvd. 

Austin, TX 78701-4039 

Telephone: (512) 322-2582 

Roger R. Martella Jr. 

Sidley Austin LLP 

1501 K Street, N.W. 

Washington, D.C. 20005 

Telephone: (202) 736-8000 

Attorneys For Petitioners