-1- 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

T HE A MERICAN P ETROLEUM I NSTITUTE AND THE N ATIONAL P ETROCHEMICAL AND R EFINERS A SSOCIATION ’ S P ETITION FOR R ECONSIDERATION , R EQUEST FOR S TAY , AND R EQUEST FOR A DDITIONAL R ELIEF R EGARDING

T HE F INAL R ULE FOR M ANDATORY R EPORTING OF G REENHOUSE G ASES 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”) re present a highly importa nt 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 “M RR”). Petitioners and their members are proud of their contribu tions 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 consis tent approach to GHG emissions reporting, and-2- Petitioners support the development of a singl e, 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 operat ors of regulated faciliti es, 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 vita lly 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 reaso n, 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 sp are no opportunity to improve the rule.

Petitioners and their members appreciat e 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 undertake n, 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 as pects of the final MRR pursuant to Section 307(d)(7)(B) of the Clean Air Act (“CAA” or “t he Act”), with a corresponding stay of the effectiveness of relevant provisions as appropriate. Sp ecific 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 availabl e monitoring methods”; (2) new calibration requirements in the final rule si nce proposal; and (3) new emission factors and high heat values for refinery “still gas” added since proposal. Reconsideration of thes e 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 comp romising the purposes of the MRR.

In addition to their formal petition for r econsideration and associated request for stay of certain provisions, Petitioners are request ing that EPA address a nu mber of other critical issues listed below, in order to provide much needed clarity with regard to MRR compliance obligations. The issues presented in Section II I 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 corr ections are included. EPA’s attention to these additional issues in the recons ideration process, in a target ed rule revision, or through the issuance of guidance would greatly add to the effectiveness of the MRR.

II. REQUESTS FOR RECONSIDERATIO N 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). R econsideration 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 afte r the public comment pe riod, if the objections-3- are of central relevance to the outcome of the rule. See id . EPA is authorized to stay the effectiveness of rules promulgate d under the CAA for up to three months during reconsideration. See id.

The reconsideration provision of Secti on 307(d)(B) is appli cable 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 reconsider ation of MRR rule). Provisions in the final MRR that are the subject of reconsideration re quests below were not sp ecifically addressed by EPA in its MRR rulemaking proposal, pub lished 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 ru le. It was therefore impracticable to raise objections to these provisions during the pub lic 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 Apr il 1, 2010 Deadline to Discontinue the Use of Best Ava ilable 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 re quires regulated entities to begin monitoring their source-specific GHG emissions on a highly acc elerated 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 m onitored data as soon a possible is understandable, th e compliance challenges presen ted by such an implementation schedule are not mere inconveniences. The shor t implementation schedule in the final rule allows for the use of BAMM only through Ma rch 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 implem entation schedule is also without legislative support. EPA cites the Consolidat ed Appropriations Act of 2008 (“Appropriations Act”) as Congressional direction fo r 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 promul gation 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 dead lines 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 Tele vision Producers & Distributors v.

1 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.”)-4- FCC , 502 F.2d 249 (2d Cir. 1974) (holdi ng that agency failed to allo w adequate time to prepare for amendment to rule that became effective wh ere television networks had only eight months notice of informal report).

EPA’s preamble discussion shows that th e compliance challenges associated with an early MRR compliance date were a considera tion in the rulemaking, and EPA made clear that the final rule’s April 1, 2010 deadline to discon tinue the use of BAMM is intended to balance the competing objectives of rapid implementa tion and feasibility in implementation. See 74 Fed. Reg. at 56,274. However, the implementation sc hedule 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 thr ough 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 woul d 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 sche dule 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 opportuni ty to request an extension were not offered for comment as poten tial scheduling options, r econsideration 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 begi n 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 comple xity of the rule, there is not enough time for operators to sufficiently underst and their compliance ob ligations related to monitoring requirements, data ava ilability, and instrumentation.

First, the safe installation of require d 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 instrument ation installations or upgrades. Second, Section 98.3(d)(2)(ii) focuses ex clusively on procurement and installation of equipment. Although these are important consid erations, the rule fa ils to recognize that engineering resources, planning, and a large nu mber 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. Th ird, in continuously operated plants there is typically no scheduled shutdown for an entir e facility. Moreover, unit maintenance and turnarounds are not an annual occurrence for a ll units. EPA has prope rly recognized this important operational reality in the context of instrument cal ibration; it should also provide approval criteria for extending the use of “bes t available monitoring methods” beyond December 31, 2010 for equipment installation and upgrades.-5- 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 wh ich could have been avoi ded if reporters had a reasonable amount of time to determine complia nce obligations. Accordingly, the schedule should provide sufficient time for reporters to prop erly review their comp liance obligations prior to submitting an extension request, and thereafter provide sufficient time for EPA to consider and act on each request. Such an approach woul d be similar to the first year of mandatory reporting under California’s AB32 GHG reporting re gulation and would elim inate the need for a burdensome extension process, thereby allowing re porters to focus on the work necessary to ensure compliance with the rule.

For all of the reasons set forth above, Petit ioners request that EPA reconsider the “[s]pecial provisions for reporting year 2010 ” of Section 98.3(d). Upon reconsideration, Petitioners request that EPA ta ke the following specific actions:

1. Stay the effectiveness of the monitoring requirements in the MRR to allow the use of “best availabl e 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 procur ement 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 Correspondi ng 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, Petiti oners were not afforded the opportunity to comment on those elements of the ru le, and it was therefore impracticable to raise objections to these provisions during the public comment period. Recons ideration of Section 98.3(i) is therefore a ppropriate with an accompanying stay. See 42 U.S.C. § 7607(d)(7)(B). While equipment and instrument calibration ne eds 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 vari ety of devices and processes that will be subject to their demands. Acco rdingly, Petitioners request rec onsideration Section 98.3(i), and Petitioners request that the eff ectiveness of Section 98.3(i) be st ayed during reconsideration.

Below, Petitioners offer specific substantive requests for EPA’s reconsideration in four areas related to the calibration requireme nts of Section 98.3(i): (1) calibration accuracy-6- requirements; (2) calibration and equipment in stallation 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 th is paragraph and each relevant subpart of this part. All measurement devices must be calibra ted according to the manufacturer’s recommended procedures, an appropriate industry consensus standar d, or a method spec ified in a relevant subpart of this part. All measurement devices sha ll be calibrated to an accuracy of 5 percent. ” Section 98.3(i)(2) specifies that the accuracy of flow meter calib ration 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 th an 2% for each measurem ent 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% calib ration accuracy entail s, and, specifically, when the EPA-specified calibration error equati on (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 a pplicable operating standard. Section 98.3(i)(2), however, is not clear whether the +/- 5% accuracy requ irement applies to the meter prior to or after calibration. Moreover, it is not clear whether th e 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 th e 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 fl ow 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 ro ot 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 th e applicable operating standard.

2. Allow flow meters to be calibra ted on-site by trained personnel using consensus industry standards.-7- 3. Correct the method specified fo r error summation and use a valid statistical error aggregation method.

b. Calibration and Equipment Installation Timing

As discussed above, the fi nal 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 reco gnizes that for continuously operating process units, some calibrations are not possibl e on-line without disrupting the process. Specifically, the rule provides as follows:

For units and processes t hat 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 sche duled maintenance outage, and may similarly postpone the subs equent 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 pos e 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 31 st 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 initi al calibration, especi ally at large, co mplex facilities.

Section 98.3(i)(3) allows repor ters 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 equipm ent to comply with Sec tion 98.3(i)(3). If a shutdown is required to upgrade or install the compensation equipm ent, 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 in stalled 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 shoul d 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 cal ibrated. 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 c onduct the calibration, and is not dependent upon whether the equipment is shipped to a remote location.-8- Accordingly, for all of the reasons discu ssed above, Petitioners request that EPA take the following specific actions u pon 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 availabl e 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 veri fication clause. However, the final rule does not list speci fic 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 a ssurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation us ed 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 th ese calibrations and adjusting instruments to the 5% accuracy, pursu ant 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 pr actice is performing calibrations and adjusting meters where drift occurs.

2. Confirm that the follow-up calibra tion accuracy results are not a basis for invalidating data in the future.

d. Acceptable Calibration Standards

The rule provides that companies may us e industry consensus standards to meet calibration and measurement require ments. Section 98.3 provides that “[a]ll measurement devices must be calibrated according to the manufacturer’s recommended procedures, an appropriate industry consensus sta ndard, or a method specified in a relevant subpart of this part.”-9- 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 comm ents package. In addition, Subpart C, General Stationary Fuel Combustion Sources, should in clude a reference to ASME Performance Test Codes (ASME PTC) in the list of applicable sta ndards for stationary fuel combustion sources. EPA should leverage industry consensus standa rds development and revision processes to achieve EPA’s stated objective of receiving quality data and avoi ding 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 prov ided in the individual subparts as examples of industry consensus standa rds 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 im practicable to object to, or otherwise comment on, these va lues 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, Petitione rs request reconsidera tion of the still gas emissions factor and HHV in Subpart Y, Table C-1 of the MRR a nd related emissions calculation methodologies specified in Subpart Y of the MRR. In addition, Petitioners seek th e 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, allowi ng refineries that combust refinery fuel gas (still gas) and meet either Tier 1 or Tier 2 applicability to use the default CO 2 emission factor.

For calculating CO 2 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 CO 2 emissions from combustion of refinery fuel gas. For CO 2 emissions from combus tion of fuel gas, use e ither equation C-5 in subpart C of this part or the Tier 4 me thodology in subpart C of this part.”-10- Additionally, in the recently released Subpa rt Y Fact Sheet, a footnote indicates that “[f]or CO 2 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 CH 4 emissions, the default ‘still gas’ heating value in Table C-1 is provided in units of MMBtu/gal. This is an e rror 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 CH 4 and N 2 O emissions for any fuels for which Tier 1 or Tier 3 methods are used for CO 2 , and also mandates the use of the default HHV va lues from Table C-1. In contrast, Equation C-9a permits the use of actual site HHV when us ing the Tier 2 method. This approach, and the erroneous HHV value, makes it impossible for refineri es that use either Tier 1 or Tier 3 to use the default values in Table C-1.

Accordingly, for calculating CO 2 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 (s till gas) from using either Tier 1 or Tier 2 methods with the default CO 2 emission factor. However, this result is completely inconsistent with EPA’s stated intent, in the preamble, to pr ovide burden relief by addi ng factors for Still Gas in Table C-1.

As EPA noted in a November 5, 2009 mee ting 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 pres ented 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. Petitione rs’ 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, th e applicable definitions in Section 98.6 are inconsistent. On the one ha nd, fuel gas is defined as “gas generated at a petroleum refinery, petrochemical plant, or similar i ndustrial process unit, and that is combusted separately or in any combination with any type of gas.” On the other hand, sti ll gas is defined as “ any form or mixture of gases produced in refineries by di stillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, et hylene, normal butane, butylene, propane, and propylene.” These definitions are inconsistent and create confusion across related rule requirements. This confusion is further compou nded by the inclusive definition of “natural gas,” which provides that “[f]or the purposes of th is subpart, the definition of natural gas includes similarly constituted fuels such as field production gas, process gas, and fuel gas.”-11- 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 th e MRR. Upon reconsideration, Petitioners request that EPA ta ke the following specific actions:

1. Allow refineries access to all th e calculation methods (tiers) outlined in Subpart C, as applicable.

2. Allow the use of Tier 1 and Ti er 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-speci fic HHV values for calculating CH 4 and N 2 O for all tiers of CO 2 calculations.

III. REQUEST FOR ADDITIONAL RELI EF 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 i ssuance of guidance, du ring 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 informa tion (CBI). Specificall y, the preamble provides that “EPA recognizes the importance of this issu e 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 noti ce 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 wh at was done in 1991 for the data elements collected in this ru le, through a notice and comment pr ocess to define what data elements are “emissions data” and theref ore 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. Howeve r, we are concerned that there may not be sufficient time for EPA to conduct such a rule making prior to the firs t reporting deadline of March 31, 2011. As a result, EPA should provide more detail about the expected rulemaking,-12- including a firm timeline for promulgation. In addition, EPA should pr ovide 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 re quest that EPA take the following specific actions:

1. Provide more detail, in writing, re garding the expected rulemaking to address CBI issues, including a cl ear 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 calc ulation method for all of 2010, regardless of the size of combustion devices. As a result, beca use Tiers 1 and 2 allow fuel volume to be based on “company records” (enabling calculation base d on parameters), oil an d natural gas production operations not covered by Subpart NN or any other subpart can e ffectively use “best available measurement data” for all of 2010. Beyond 2010, facilities subject only to combustion emission reporting under subpart C are requ ired to submit a complete report based on the requirements of the appropriate method tiers.

Accordingly, Petitioners request that EPA take th e following specific actions:

1. Amend the instructions for “comb ustion only” reporte rs to confirm that facilities that ar e subject to “stationary combustion only” reporting can use “best available meas urement data” for all of 2010.

2. Amend the instructions for “combus tion 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 equi pment is in place to make these measurements. Otherwise, weekly samp ling 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 fuel s 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 refiner y fuel gas carbon content and molecular-13- weight was changed to weekly fr om daily in 40 C.F.R. part 98, subpart C for reporters that do not have continuous mo nitoring 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 re quest 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 opera tional changes, the sampling frequency selected can be consistent with the variability of the stream.

3. Allow the use of “engi neering 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 calculate d weekly average carbon content and molecular weight based on co ntinuously 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 whic h calculation methods are provided in the rule. Calculation methods are generally not included for smalle r sources of emissions (e.g., coal piles on industrial sites).” 74 Fed. Reg. at 56,279.

In addition, the Technical Support Docume nt 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, delaye d coking unit depressurization and coke cutting, coke calcining, blowdown systems, process vents, process equi pment leaks, storage tanks, loading operations, wastewater treatment, and waste disposal. To fully account for the refinery’s GHG emissions, the emissions from these source s should be reported; however, the emissions from these sources are expected to be only about 1 percent of th e refinery’s total GHG emission.”

The calculation methods provided in the ru le for some insignificant sources in petroleum refineries are highly inaccurate. Im portantly, as noted above , the Petroleum Refining TSD makes clear that emissions such as methan e from storage tanks, methane from equipment leaks, methane and nitrous oxide from catalyt ic crackers and delayed cokers, methane from uncontrolled refinery blowdown systems and some similar sources, are truly insignificant.-14- Despite these clear reasons in s upport of lessening the reporting burden associated with these emissions, the rule requires quantif ication of such emissions.

Accordingly, Petitioners re quest 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 requi rement for reporting from insignificant sources, allow the use of alternative, less detailed emission factors or estimatio n methods developed by trade organizations and others, provide d 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 accord ing to manufacturers’ instructions: "Use any applicable methods from the following list to de termine the carbon content and molecular weight (for gaseous fuel) of the fuel. Alternatively, th e results of chromatographi c analysis of the fuel may be used, provided that the gas chroma tograph is operated, maintained, and calibrated according to the manufacturer’s instructions."

Subpart P specifies that an EPA-specified te st method must be used to measure carbon content / MW of feedstocks. The te st methods list in cludes 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 a ny language that allows the use of GCs as long as they are “operated, maintained and calibrate d 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 sa mpling 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 chromatogra phy 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 ex tend 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 langua ge in each subpart: “ Alternatively, the resu lts of chromatographic analysis of the fuel may be used, provided t hat the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions .”-15- 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 constitute d fuels such as field production gas, process gas, and fuel gas.”

Section 98.33(b)(1) describe s the use of the differen t GHG calculation methods, noting that “[t]he Tier 1 Calculation Methodology: (i) Ma y 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 mmBt u/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 pr ovided 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 th an “Pipeline”’ to ensure that the default CO2 emission factor listed in Table C-1 applies to appropriate natu ral 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 re quires reporters to submit annual GHG emission reports no later than March 31 of each ca lendar 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 31 st as the annual due date for reporting is very genera l and the examples provide d are not applicable. For example, the EU-ETS is not a good comparison because that program only requires CO 2 emissions reporting from a limited subset of large facilities in a few sect ors. In addition, the examples provided in the preamble related to NSPS and NESHAPs are limited to reporting excess emissions and monitoring systems perfor mance. The short time provided to compile, review, check and certify will impose an exce ssive burden on reporters and could lead to inadvertent errors due to the sheer volume of in formation requested and the fact that key inputs for necessary calculations may not be immediat ely available after the end of the year.

Accordingly, Petitioners request that EPA take the following specific action: Establish an annual reporting deadline of no earli er than June 30 of each calendar year for the previous year.-16- 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 severa l Webinars that the monitoring plan is a recordkeeping requirement and not a monitoring or reporting requiremen t. In response to comments, EPA has noted that it expects comp anies would have their monitoring plan ready before April 1, 2010. However, it is not clear ho w this would be reconc iled with a request for extension and the associated use of availabl e company records for the remainder of 2010.

Accordingly, Petitioners re quest that EPA take the following specific actions:

1. Confirm in writing that the requir ement to maintain a monitoring plan is a recordkeeping requirement a nd not a monitoring or reporting requirement.

2. Confirm in writing the date the m onitoring 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 liq uid or NGL” in Sec tion 98.6 “refers to mixtures of hydrocarbons that have been sepa rated from natural gas as liquids through the process of absorption, condensati on, 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 “Natur al gas processing plant” as “any processing site engaged in the extraction of natu ral gas liquids from fiel d gas, fractionation of mixed natural gas liquids to natu ral gas products, or bot h.” This definition was changed from the proposed version to substitute “extraction” for “separation” because EPA intended to exclude facilities that removed liquid fr om 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 separa tors 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, diffe r 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 he at input. EPA should r ecognize the distinct and different nature of catalyst coke versus petroleum coke.

Accordingly, Petitioners re quest 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 condi tions” 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 discre pancy between the stated standard conditions and the “molar volume conversion” factor provid ed in the equations for calculating emissions from gaseous fuels.

However, instead of providing several “m olar volume conversion” factors that could be used by reporters under different temper ature and pressure conditions, the final rule defines “standard conditions” at 68F and 14.7 ps ia, placing an unnecessary burden on reporters, and introducing confusion that could lead to erroneous emission calculations.

Petitioners request that EPA take th e 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 c onversion” 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 ar e 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 CO 2 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 CO 2 for the fuel mixture.

Accordingly, Petitioners request that EPA take the following specific action: Revise the fuel estimation requirements in Subp art 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 (Ti ers) for a Single Combustion Device

Section 98.36(b) allows combustion units to “...report the following information for stationary combustion units th at use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in §-18- 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 di fferent calculation method tie rs can be used for both sequential intervals during the reporting year wh ere different fuels are combusted in a single device, and/or for concurrent us e 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, Pe titioners 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 provision s of the MRR that are subject to reconsideration. Further, Petitioners request that EPA make the needed clarifications and revi sions 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