# MEMORANDUM

FROM: Lisa Hanle, U.S. EP A, Climate Change Division

TO: Docket EPA-HQ-OAR-2008-0508, Mandato ry Reporting of Greenhouse Gases.

DATE: July 1, 2010

SUBJECT: Summary of ques tions raised on subparts A, C, D, X, Y, AA, NN, OO, and PP of

the final Mandatory Greenhouse Gas Repor ting Rule (40 CFR Part 98) after

promulgation that are being addressed in the proposed Revision of Certain

Provisions to the Mandatory Re porting of Greenhouse Gases Rule.

1.0 INTRODUCTION

On October 30, 2009, EPA published the final rule titled: Mandatory Greenhouse Gas

Reporting (74 FR 56259), 40 CFR part 98, under the authority of Sections 114 and 208 of the

Clean Air Act. Part 98 requires reporting of greenhouse gas (GHG) emissions and other related

information from certain sectors of the econom y. Part 98 requires the monitoring of GHGs

beginning with the 2010 calendar year, with re ports submitted annually by a March 31 deadline

in each following year. Part 98 does not require control of GHGs; rather it only requires that

sources above certain threshold levels monitor and report emi ssions and other related data.

Since promulgation of part 98, the Administ rator has identified a number of technical

issues that need to be corrected and specific prov isions that need to be clarified. EPA published

a notice proposing amendments to many subparts of Part 98 on June 15, 2010 (75 FR 33950).

However, this first notice did not cover all of the issues that have been identified, and many

issues were more complicated and requi red additional time to address.

EPA is now proposing a second set of amendmen ts to specific provisions in Part 98 to

correct these additional technical and editorial errors that have been identified since

promulgation and to clarify or propose updates to cer tain provisions that ha ve been the subject of

questions from reporting entities. Except for certain amendments to subparts A (General

Provisions), P (Hydrogen Production) and V (N itric Acid Production) of Part 98, these

amendments are for different subparts than were addressed by the June 15, 2010, proposed

amendments.

The purpose of this memorandum is to describe the extent of EPA’s outreach efforts for

Part 98 and to summarize the questions that have been raised during EPA’s outreach activities

that are being addressed by some of the proposed amendments.

2.0 SUMMARY OF EPA OUTREACH ACTIVITIES

EPA has conducted an extensive outreach program for the Greenhouse Gas Reporting

Program (GHGRP), including meetings with trad e associations and individual businesses, on-

# line web-based seminars (webinars), and traini ng sessions for EPA Regi onal Offices. The

following table lists those meetings and webinars that EPA has c onducted to date, along with the

month and year of the activity. Where available, the approximate attendance for the meeting or

webinar is included in parentheses.

POST-SIGNATURE MEETI NGS AND WEBINARS

Month and Year of Inform ation Meeting or Webinar

Organization or Location (estimat ed attendance, if available)

Sept 2009

EPA Regional Offices Briefing (100)

Agriculture community teleconference (100)

State and Local Agencies teleconference (100)

Clean Energy Group Meeting (about 40)

State of Washington (2)

Business Council (73)

Call with Massachusetts on data system (2)

Overview webinar (293)

US Climate Action Partnership (20)

Overview webinar (284)

National Cooperative Refinery Associa tion, and Van Arsdall & Associates

Oct 2009

Oil and Gas Compact (30)

Detailed webinar (326)

Portland Cement Assoc. (20)

CENSARA(50)

Overview webinar (217)

Applicability Tool Demonstration (84)

National Lime Assoc. (3)

Detailed webinar (252)

EEI (80)

NACAA (75)

Nitric Acid and Ammonia Assoc.(30)

TFI, AISI, SMA

Overview webinar (176)

Detailed webinar (208)

Air Program Managers and staff (25)

Detailed webinar (206)

Aluminum Industry

Steel Manufacturers Assoc.

Natural Gas Star

Overview webinar (133)

Carolina Air Pollution Control Assoc. (400)

Applicability Tool Demonstration (238)

Waste Management and Equipment Companies (25)

Ohio Manure Storage

Overview webinar (251)

Corporate Climate Regulation, Chicago, IL

# POST-SIGNATURE MEETI NGS AND WEBINARS

Month and Year of Inform ation Meeting or Webinar

Organization or Location (estimat ed attendance, if available)

Midwest Transportation & Air Quality Conference

Detailed webinar (333)

TCR/CAA (90)

Environmental Groups (10)

API

NOV 2009

Misc. Meetings with Industries (Refiner ies, Pulp and Paper, Cement) (100)

Northeast Gas Assoc.

Ecology and Environment, Inc. (2)

Detailed webinar (253)

TCR

Tribal Air Coordinators (50)

GHG data exchange discussion with New Mexico (8)

API (20)

ABA (100)

Training for three regional cap and trade programs – DC (70)

State-EPA Dialogue - DC (80)

Treated Wood Council (60)

Detailed webinar (172)

MAPI (Manufacturing Alliance) (15)

Environmental Services Corporation (150)

Western Climate Initiative partner meeting – Santa Fe (50)

Detailed webinar (171)

Regional Climate sub-leads (40)

Air Products (5)

Waste Management and others (10)

Detailed webinar (96)

DEC 2009

AWMA-EPA- RTP (100)

Envirosys (4)

Detailed webinar (50)

ACC (5)

National Grid

Detailed webinar (91)

Utilitpoint and Allegro (115)

CARB

NPRA and API

Golder and Associates

Andarko (10)

Kinder Morgan

EEI

SWANA- LFGTE

Thermo Fisher Scientific

EPA Region 4 Training (100)

# POST-SIGNATURE MEETI NGS AND WEBINARS

Month and Year of Inform ation Meeting or Webinar

Organization or Location (estimat ed attendance, if available)

Waste Management and others (8)

Air Products (5)

The Fertilizer Institute

ADM (8)

JAN 2010

Detailed webinar (83)

Air Products

National Emissions Inventory (30)

OECA- Regional offices (30)

National Grid

Alliance of Automobile Manufacturers (9)

Detailed webinar (100)

NRPA (300)

Feb 2010

Dedicated webinar for American Colleges and Universities (220)

EPA Regional Inventory, Enforcement (23)

University Challenge

State webinar (200)

Webinar (182)

Iowa Landfill operators (125), Asphalt Paving Associati on of Iowa (70), and the Iowa Chapter of AMWA

(60).

Mar 2010

Inst. Of Clean Air Companies (23)

SWANA (200)

EPA AFS Compliance Meeting

Second Nature (Colleges/Universities) Panel (20)

ECOS (50)

PCA

Training- EPA Regions 5 and 7 (180)

Iowa Landfills (50)

April 2010

Arkansas Environmental Federation, Little Rock (160)

NACAA Emissions and Modeling Committee (30)

Webinar (75)

Central TX AWMA (50)

Chicago Exchange Meeting

Exchange Network National Meeting (50)

EPA Air Division Directors (20)

National Assoc. of Clean Water Agencies

Pepsico-Frito Lay (150)

Pacific NW Legislative Energy Horizon Inst./AGA (35)

May 2010

LA, Boise, Portland Training (150, 100, 70, respectively)

ESC Users Group (150)

NCASI

# POST-SIGNATURE MEETI NGS AND WEBINARS

Month and Year of Inform ation Meeting or Webinar

Organization or Location (estimat ed attendance, if available)

EPRI CEMUG (150)



# 3.0 SUMMARY OF QUESTIONS BEIN G ADDRESSED BY PROPOSED

AMENDMENTS

EPA has maintained a web-based helpline that allows individuals to submit questions

about the GHGRP, as well as on any proposed rule s published since the fina l rule. So far, EPA

has resolved approximately 1,900 inqui ries on the final rule. Most of those inquiries have been

resolved by providing further guid ance to reporting entities through a web-based list of answers

to frequently asked questions. However, for ma ny questions, they are be ing resolved through the

proposed amendments to the final rule.

EPA has also held meetings with many trade associations for industries affected by the

GHGRP, and many questions were presented by those trade associ ations that are also being

resolved through the proposed am endments to the final rule.

The following table summarizes the questions that have been rais ed on various subparts

of the GHGRP which are being addressed by the proposed amendments. Not all of the

amendments correspond to questions that were raised by reporters. The need for some

corrections and other amendments were identified as a result of internal EPA review of the

GHGRP, and may not be reflec ted in the following table.Summary of Questions And Issues From TheEPA Helpline And Trade AssociationsBeing Resolved By The Proposed Revision of Certain Provisions of the Mandatory Reporting of Greenhouse Gases RuleCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)Subpart A – General Provisions98.2 and TableA-1Part 98 has Table A-1 for Global Warming Potentials. How does a facility report if the gasthey use does not have a global warming potential, for example C5F8 and specificfluorinated heat-transfer fluids?At least 2Hotline98.3(c) BiogenicEmissionsAre electric generating units that are subjectto Subpart D-Electricity Generation requiredto separately report their biogenic CO2emissions?At least 3Hotline/TradeAssociation98.3(f)typographic errorI have found a couple typos in Part 98. In 98.3(f), where it refers to (c)(8), it should say(c)(9)At least 1Hotline98.3(g)(4)Record-keepingfor Missing DataEventsIn the final Part 98, EPA added in §98.3(g)a requirement to record: For each missing dataevent, ... a record of the duration of the event, actions taken to restore malfunctioningmonitoring equipment, the cause of the event, and the actions taken to prevent or minimizeoccurrence in the future.Although Part 75 requires recording of the cause of missing data periods and the correctiveactions taken (see 40 C.ER. § 75.57(h)), this can be satisfied by a simple notation in themaintenance log required under Part 75, Appendix B, § 1.1.3 (maintenance records). Thereis no requirement in Part 75 to separately record the "duration of the event" or the "actionstaken to prevent or minimize occurrence in the future." Requiring sources using CEMS,particularly those already complying withPart 75 recordkeeping, to develop theseadditional records would be overlyburdensome and of little usefulness.The majority of missing data periods associated with CEMS are due to routine activities orcalibration failures, for which there is no clearmeasure to preventfuture occurrence.Moreover, because these events are of short duration and Part 75 already requires theflagging of each missing data period in the electronic report, a new requirement to recordthe "duration" of missing data events alsois unnecessary and potentially burdensome. EPAshould reconsider these additional requirements,particularly with respect to units subjectto Part 75 recordkeeping, and Part 98 should rely on Part 75 recordkeeping as sufficient tosatisfy Part 98 recordkeeping for CO2and heat input.At least 1TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(h)Correction andResubmission ofAnnual ReportsWe have a number of concerns regarding the provision for resubmission of GHG reports.First, because the annual reports includemuch more information than calculated GHGemissions data, and must be submitted in the as yet unspecified "format specified by theAdministrator," (see, e.g., Final §§ 98.5 and 98.36), the types of "errors" that could triggera requirement for resubmission under thisrule are almost limitless and go well beyonderrors in "calculation" of data. Although EPA presumably could develop some significancecriteria for errors, and limit the resubmissionrequirement to errors identified in formalrequests for submission (as opposed to those identified in the sort of automated feedbackreports used under the Acid Rain Program (ARP) reporting requirements), Part 98 appearsto require resubmission for virtually any error identified by the source owner/operatorwithout exception. Part 98 also could trigger a requirement for resubmission years after theoriginal submission was made.Second, depending upon the mechanism EPA uses to define and identify "errors," Part 98could trigger a requirement for resubmission even when the report is accurate. Forexample, in some cases, identified "errors" could be caused not by inaccurate informationor data, but by errors or bugs in EPA's(or the source's) software, differences ininterpretation of Part 98, or implementationof other screening mechanisms that may nottake into account source specific configurations or issues. Based on experience withreporting under the ARP, these issues are most likely to arise in the first year ofimplementation of any new or revised electronic format or software, and could arisefrequently if EPA relies on electronic auditing tools similar to those employed under 40C.F.R. Part 75 to identify "errors." Reportersshould not be required to re-submit and recertify the accuracy of a report, unless the source owner/operator concurs that the originalreport was erroneous.Third, the requirement to resubmit a report"within 45 days" may not provide sufficienttime to determine whether the identified "error" isin fact an error, or to determine the bestway to correct an error. Such an inflexible deadline is not appropriate in the context of suchan open-ended requirement.At least 1TradeAssociation98.3(i)CalibrationRequirementsWe operate vortex and magnetictube fuel flow meters for which there are no fieldcalibration procedures identified by the manufacturers. How do we comply with the initialand ongoing calibration requirements for these types of meters?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(i)CalibrationRequirementsDid EPA intend that fuel flow meters used to collect company records under Tiers 1 or 2be required to adhere to the initial calibration and ±5 percent accuracy requirements of§98.(i)? Company records are allowed to be used to determine the amount of fuelcombusted in general stationary combustion sources under Tiers 1 and 2 of Subpart C.Sources will likely use data from existing fuel flow meters on Tier 1 or 2 sources as thecompany records required for emission calculations. Subpart C does not prescribe specificaccuracy requirements for company records; it only stipulates that the company recordsshall include an explanation of how they are used to determine fuel consumption whenTiers 1 or 2 are used [see §98.34(f)(1)]. This is in contrast to the Tier 3 direct fuel flowmeasurement requirements in which EPA clearly mandates that the fuel flow metersrequired under Tier 3 be calibrated according to§98.3(i) [see §98.33(a)(3)(ii) and (iii)].However, in reviewing §98.3(i), it appears toapply to all "flow meters and other devices(e.g. belt scales) that measure data used to calculate GHG emissions" and requires that "allmeasurement devices shall be calibrated to an accuracy of 5 percent."At least 5Hotline98.3(i)CalibrationRequirementsSection 98.3(i)(1) requires flow meters andother devices (e.g., belt scales) that measuredata used to calculate GHG emissions tobe calibrated prior to April 1, 2010 usingprocedures specified in Part 98. The paragraph goes on to state that all measurementdevices must be calibrated according to themanufacturer's recommended procedures, anappropriate industry-consensus standard, or a method specified in a relevant subpart of thispart. The paragraph also requires all measurement devices must be calibrated to anaccuracy of 5%. Has EPA already established some Q&A surrounding the "calibration"topic?A common accounting practice with weight measurements at cement plants is to reconciledata from continuous direct weight measurement devices with inventory accounting data(material receipts, shipments, etc.). For purposes of meeting the 5% accuracy requirement,would EPA allow a calibration procedure basedon weight measurement with calibratedscales, and periodic reconciliation basedupon inventory and accounting records?"At least 1TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(i)CalibrationRequirements1. It is not clear what the initial 5% calibration accuracy entails, and, specifically, when theEPA-specified calibration error equation (Eq. A-2) should be used. Typically when ameasurement device is calibrated initially, it is setto operate within the error range for theapplicable measurement technology and operating standard. In 98.3(i)(2), it is not clearwhether the +/- 5% accuracy requirement appliesto the meter prior to or after calibration.2. Is the 5% calibration accuracy requirementapplicable to all devices used for measuringany parameter – even those used for a Tier 1 and/or Tier 2 method under subpart C? Doesthe 5% accuracy requirement apply to on-line analyzers (e.g., GCs)? Would it apply toexisting company procedures and records whenthe ‘best available monitoring method’clause is enabled?At least 1TradeAssociation98.3(i)CalibrationRequirementsTiers 1 and 2 do not specifically require directmeasurement of fuel consumption. Part 98allows for the use of "company records" (asdefined in §98.6) in lieu of flow meters.However, if the "company records" are based on data from flow meters, do such flowmeters still need to meet the calibration/accuracy requirements in §98.3(i)?At least 2TradeAssociation98.3(i)CalibrationRequirementsAre facilities using Tier 1 or Tier 2 calculation methods only required to follow the initialcalibration requirements contained in 40 CFR 98.3, and are not subject to any recurringcalibration requirements? Part 98 does not include any language that requires those usingTier 1 or Tier 2 calculation methods to perform recalibrations.At least 10Hotline98.3(i)CalibrationRequirementsAn ethanol production facility has sold CO2in the past, but has not done so at all in 2009.The facility does not know if they will sell CO2in the future. However, if they begin sellingethanol sometime in 2010, how soon must the ethanol plant install a flow meter for thisCO2stream or must they install the flow meternow, before March 31st, 2010, even if theydo not sell any CO2in 2010?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(i)CalibrationRequirementsPart 98 states: "If a portion of the fuel measured at the common pipe is diverted to achemical or industrial process where it is used but not combusted, you may subtract thediverted fuel from the fuel measured atthe common pipe prior to performing the GHGemissions calculations, provided that the amountof fuel diverted is also measured with acalibrated flow meter per §98.3(i)." Section 98.3(i) includes the +/- 5% accuracyrequirement. It is possible to have an overall measurement accuracy of +/- 5% withoutrequiring that all flow meters in a common pipe meet +/- 5%. For example, a commonpipe supplies fuel gas that is used as fuelto a combustion unit that has a maximum ratedheat input > 250 MMBTU and supplies fuel gasused as a feedstock to a process unit. Thefuel gas is measured at the common pipe witha meter that has an accuracy of +/- 1% andthe flow of fuel gas used as a feedstock ismeasured at the process unit with a meter thathas an accuracy of +/- 10%. 90% of the fuel supplied by the common pipe is used as fuelin the large combustion unit. If a sum ofsquares weighted uncertainty calculation isperformed on the flow meters, the overall measurement uncertainty of fuel supplied to thecombustion unit may still be within the +/- 5%accuracy requirement. Allowing the use ofa weighted measurement uncertainty calculation to determine overall measurementuncertainty for common pipe situations willallow reporters the flexibility to reportaccurate emissions without requiring a large number of new or upgraded flow meters to beinstalled.At least 1Hotline98.3(i)CalibrationRequirementsAre orifice, venturi, and nozzle flow metersrequired to have temperature, and totalpressure transmitters located on the flow meters?At least 1Hotline98.3(i)CalibrationRequirementsDoes Part 98 require gas billing meters to be calibrated?At least 10Hotline98.3(i)CalibrationRequirementsEPA should take the following specific actions with respect to Section 98.3(i):1. Amend the initial calibration requirements toallow “accuracy of initial calibration” to bedetermined within the error range for thespecific measurement technology based on theapplicable operating standard.2. Allow flow meters to be calibrated on-siteby trained personnel using consensus industrystandards.At least 1TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(j) BAMMA refinery has already submittedand received from EPA a BAMM extension requestapproval through 2010 for refinery fuel gasmeters and other meters associated withSubpart Y. Recently the refinery realized that calibrating the pressure transmitter used tocompensate the air flow to the FCC would require bypassing the surge protection for theblower. This could result in damage to the air blower since it would have no surgeprotection during the time of calibration ofthe instrument. Therefore because of thisequipment safety issue, the refinery prefersto wait to calibrate the pressure instrumentuntil a scheduled downtime for the FCC.Would EPA confirm that even beyond 2010, a calibration is not required until a scheduledshutdown, since 98.3 (i)(6) allows for delay in cases where calibration would disruptnormal process operation?.At least 1Hotline98.3(j) BAMM40 CFR 98.3(i)(6) allows the delay of calibration of measurement devices if the devicerequires that a continuously operating unit orprocess must be shutdown and the devicesent off-site for calibration. If a piece of monitoring equipment is required to be installedto comply with the GHG reporting rule and the installation requires a unit shutdown, canthe facility delay the installation of monitoring equipment until the next scheduledshutdown?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(j) BAMMThere is a concern that the limited amount of time available to calibrate the large numberof equipment, as required under this rule, could pose a safety hazard. This would beespecially pronounced if calibrations and maintenance have to be completed during theheart of winter, in order to meet the March 31st deadline. For complex facilities, or thosethat are geographically dispersed, the 3 months period (till March 31st) allowed for initialcalibration is insufficient. It will be extremely difficult to identify all the equipment whosedata would be used to calculate and report emissions. Making sure that all of this requiredequipment is calibrated will necessitate manyadditional resources, including skilled labor,which would impose an undueburden on reporters.In accordance with the provision of postponing initial calibrationsfor continuouslyoperated process units, would EPA authorize theuse of ‘best available measurement data’using existing company instrumentation and operating practices until new or upgradedequipment could be installed and calibrated?At least 1TradeAssociation98.3(j) BAMMCould EPA modify the “[s]pecial provisions for reporting year 2010” of section 98.3(d),specifically allow the use of “best available monitoring methods” beyond December 31,2010 for equipment installations and/or upgrades by adding an extension similar to thecalibration requirement extension in Section 98.3(i)(6).At least 1TradeAssociation98.3(j) BAMMSection 98.3(i)(1) ofthe final rule provides that “flowmeters and other devices (e.g., beltscales) that measure data used to calculateGHG emissions shall be calibrated to anaccuracy of 5 percent.”Section 98.3(i)(2) specifies that the accuracy of flow meter calibration should be less than5%, when using Eq. A-2. Additionally, Section 98.3(i)(3) addresses accuracy requirementsfor in-situ calibration of pressure and temperature transmitters for orifice, nozzle, andVenturi flow meters. Specifically, it mandates an accuracy of less than 2% for eachmeasurement point, or less than 5% for the sum of the three transmitters combined.At least 1TradeAssociationSubpart A – General Provisions and Subpart C – General Stationary Fuel Combustion SourcesCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.3(c) BiogenicEmissionsIf ARP units are in fact subject to the reporting requirements in 98.36(b), and assumingthey are considered to follow tier 4 becausethey use CEMS, then98.36(b)(7) appears toindicate that separate reporting of biogenic CO2is required. However, there are at leasttwo instances in EPA's response to commentsin which EPA states that they are notrequiring ARP units to separately report CO2emissions from biomass, but have provided amethod for those that choose to do so. So is separate reporting of biogenic CO2required?At least 3Hotline/TradeAssociation98.6 Definition of"Distillate fueloil"Subpart C §98.33(b)(2)(ii) states: "Tier 2 Calculation Methodology may be used in a unitwith a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustionof pipeline quality natural gas or distillate fuel oil". Therefore, for a combustion enginewith a maximum rated heat input capacity greater than 250 mmBtu/hr that only burnspipeline quality Jet-A fuel oil, is itacceptable to use Tier 2 to calculate CO2emissions?At least 1Hotline98.6 Definition of"fossil-fuel" andclassification ofmunicipal solidwaste (MSW)and tiresReclassifying MSW or tires as "fossil fuel-derived fuels" and including consumer plasticsand other petroleum-derived MSW materialscould have the potential to undermine theexemption of "solid waste incinerator units" from CAIR and the Acid Rain Program. EPAshould correct them by restoring both the proposed definition of "fossil fuel" and the moreappropriate subheading "alternative fuels" to encompass MSW and tires. Such a technicalcorrection would have no impact on the reported GHG emissions from MWCs in light ofthe requirement that MWCs must apportion total CO2emissions into biogenic and nonbiogenic fractions based on ASTM D-6866 analysis. The same quantities of biogenic andnon-biogenic C02emissions will be reported regardlessof how the fuels are labeled.At least 1TradeAssociation98.6 Definition of"Municipal solidwaste or MSW"Is there some Q&A clarification on the definition of MSW? For example, does the MSWdefinition included wood, paper, etc. separated from municipal solid waste prior tolandfilling? Would commercial or industrial cardboard/paper scrap be considered MSW, orcould it be considered as one of the "biomass fuels - solid" in Table C-1 of Subpart C?At least 2Hotline andTradeAssociation98.6 Definition of"Primary Fuel"If a combustion unit regularly fires two or more fuel types (i.e., they are not fired as“backup” fuels”), how are the primary fuels and secondary fuels determined? Are all fuelsfired on a routine basis considered “primary” and only those as backup considered‘secondary”? Or are primary, secondary, tertiary, etc., fuels determined on annual heatinput?At least 2HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.6 Definition of"Waste Oil"We have a burner fueled by used oil in our mechanic shop. Under which C-1 fuel doesused oil fall? If it is not listed in C-1, howdo we calculate CO2? Do we have to samplequarterly for HHV?At least 2Hotline98.6 Definition of"Waste Oil"For a space heater (<250mmbtu/hr) that burns waste motor oil, would a Tier 1 calculationusing the HHV of Residual fuel oil #6 from Table C-1 be acceptable? If not, what wouldbe the applicable tier and approach?At least 2Hotline98.6 Definition ofNatural GasThe definitions in 98.6 define “Fuel gasmeans gas generated at a petroleum refinery,petrochemical plant, or similar industrial process unit, and that is combusted separately orin any combination with any type of gas”, which is followed by a similar but not identicaldefinition of, “Still gas means any form or mixture of gases produced in refineries bydistillation, cracking, reforming, and other processes. The principal constituents aremethane, ethane, ethylene, normal butane, butylene, propane, and propylene.”This inconsistency in definitions is compounded when the definition of “natural gas”includes the statement: “For the purposes of this subpart, the definition of natural gasincludes similarly constituted fuels such as field production gas, process gas, and fuel gas”.At least 1TradeAssociation98.6 Definition ofNatural GasAre emissions from combustion of field gas reportable under Subpart C?Field gas refers to natural gas prior toprocessing to remove impurities and producepipeline quality gas. In oil and gas productionfacilities, field gas may be used in variouscombustion units, which are rarely if ever greater than 250 mmBtu/hr.The MRR definition of "natural gas" includes field gas, at least for the purposes of SubpartA: "...Natural gas may be field quality (which varies widely) or pipeline quality. For thepurposes of this subpart, the definition of natural gas includes similarly constituted fuelssuch as field production gas, process gas, and fuel gas."However, Table C-1 in Subpart C does not include field gas; the only type of natural gasfor which HHV and CO2emission factor values are given is "Pipeline (Weighted U.S.Average)". Therefore it would appear that field gas combustions are not reportable underSubpart C, except in the highly unlikely event that a combustion unit is greater than 250mmBtu/hr heat input (see highlighted path on attached flowchart). Is this correct?At least 2HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.6 Definitionsof "Agriculturalbyproducts,""Solidbyproducts," and"Woodresiduals."In reading through the O2CEMS option in §98.33(a)(4)(iv) it states that you must onlyburn fuel on Table 1 of 40 CFR 75 Appendix F 3.3.5. At one of our facilities we combusta mixture of coal, petroleum coke, tire-derived fuel, and “agricultural derived biomass”(nut shells, peach pits, wood pruning, etc).Table 1 lists coal, petroleum coke, tire derivedfuels, and also lists “wood (bark and wood residue)”. Would agricultural derived biomassas listed above be considered wood residue?At least 1TradeAssociationSubpart A – General Provisions and Subpart NN – Suppliers of Natural Gas and Natural Gas Liquids98.2(a)(4)Threshold fornatural gas localdistributioncompaniesSection 98.2(a)(4) provides that all naturalgas LDCs, as GHG suppliers, are required tocomply with the requirements of Part 98. The requirements are to report annually and tocomply with related record-keeping, qualitycontrol and other mandates. The determinationto apply all of the requirements of Part 98 to all LDCs should be reversed for each of thereasons discussed below.1. First, the absence of an exemption for small LDCs is inconsistent with one of threeprincipal goals for Part 98, which is to "balance the rule coverage to maximize the amountof emissions reported, while excluding small entities."2. Second, the failure to provide an exemption for small LDCs is fundamentallyinconsistent with a central provision ofPart 98, which established a general minimumGHG threshold of 25,000 metric tons of C02ein order to exempt entities that would notmaterially contribute to GHG emissions.3. Third, the failure to provide an exemption for LDCs affects this source category ofGHG disproportionately and puts an unfair burdenon LDCs that is not separately justifiedby the facts.4. Fourth, the apparent rationale for not exempting small LDCs from the Rule is withoutmerit. In the Proposed Rule, the EPA set forth statistics that clearly established thatapplication of the minimum threshold toLDCs would eliminate less than 1% of GHGemissions from the Rule's coverage. The agencythen found that the Rule would not requireany LDC to collect information in additionto the information already collected and,therefore, concluded that no LDC should be exempted from the Rule.At least 1TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)5. Fifth, Part 98 includes a provision that will exempt any GHG source if it reports annualGHG emissions of less than 15,000 metric tonsC02e for three consecutive years or 25,000metric tons C02e for five consecutive years.Based on analysis of EIA Form 176 data for2006, 75% of the 986 municipal LDCs - or 742LDCs would be exempt within three years,and an additional 70 small LDCs would be exempt from the Rule within five years.98.2(a)(4)Threshold fornatural gas localdistributioncompaniesOur city owns and operates distribution pipelines that deliver natural gas to end users in thecity. The point of measurement for natural gassupply is the city gate meter and the citydoes not make its own measurement. Every citygas customer has a gas meter installed,owned, and maintained by the city. The city receives significantly lower than 460,000million standard cubic feet of natural gas at the city gate. Thus, the city has no large enduser. Does the city need to calibrate gas meters installed at various customer locations?At least 4Hotline98.6 Definition of"bulk natural gasliquid or NGL"The definition of “bulk natural gas liquid orNGL” in Section 98.6 “refers to mixtures ofhydrocarbons that have been separated fromnatural gas as liquids through the process ofabsorption, condensation, adsorption, or other methods at lease separators and fieldfacilities.” However, these processes are not simple separation processes, but rather, NGLextraction processes that are typically performed at “gas plants” and not at “leaseseparators and field facilities.” 60 C.F.R. Subpart KKK defines “Natural gas processingplant” as “any processing site engaged in the extraction of natural gas liquids from fieldgas, fractionation of mixed natural gas liquids to natural gas products, or both.” Thisdefinition was changed from the proposedversion to substitute “extraction” for“separation” because EPA intended to excludefacilities that removed liquid from field gasby means other than forced processes, such as gravity or natural condensation.Accordingly, EPA should strike the phrase “orother methods at lease separators and fieldfacilities” from the definition of bulk natural gas liquid or NGL.At least 1TradeAssociation98.6 Definition ofMscfIn Subpart NN, Section 98.406(b)(7) LDC's are required to report the annual volume inMscf of natural gas delivered to each meterregistering supply equal to or greater than460,000 Mcsf during the calendar year. In Subpart A "Mscf" is defined as "millionstandard cubic feet". I just want to verify that the requirement in Section 98.406(b)(7) onlyapplies to meters where 460 BILLION standard cubic feet is delivered in a calendar year.This seems very high.At least 4HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)Subpart C – General StationaryFuel Combustion Sources98.30(d) ExcludeGHG emissionsfrom pilots fromreportingLiquefied petroleum gas (LPG) is fired in someboilers at a facility in very small quantitiesexclusively for igniting the fuel oil burners. LPG is not fired at any other time, and annualheat input from LPG fuel therefore amountsto a minuscule fraction (less than one onehundredth of one percent) of annual heat input to the boilers. GHG emissions from firingthe LPG during oil burner ignition accounts for less than one one-hundredth of one percentof total annual GHG emissions from fossil fuels, and on the order of less than 0.003percent of total annual GHG emissions from all fuels (including biomass) at this facility. Itwould therefore seem appropriate to be ableto exclude the insignificant emissions fromthis startup/ignition fuel from the annual GHG emissions calculations.At least 3Hotline98.33(a)(1) AddEq C-1a for usewhen natural gasconsumption isexpressed intherms.Do "therms purchased" on a natural gas invoice constitute HHV data and thereby triggerTier 2 reporting? If so, how can a company that purchases natural gas be sure that theirvendor is measuring and reporting HHV per the requirements of Part 98?At least 3Hotline98.33(a)(1) AddEq C-1a for usewhen natural gasconsumption isexpressed intherms.A fuel invoice is based on quantity consumed and therms. Because therms can beconverted to MMBTUs and a monthly average HHV can be determined by dividing thesenumbers, are we required to use the Tier 2methodology and does the natural gas need tobe tested semi-annually per 98.34?At least 3Hotline98.33(a)(1) TableC-1.The “petroleum coke” listed in the Table C-1 of subpart C seems to be for a liquid fuelsince the units for HHV are mmBtu/gallon. Weare not aware that a petroleum coke is onthe market that is in liquid phase.At least 10TradeAssociation98.33(a)(1) TableC-1.We recommend that EPA propose to re-organize Table C-1 by removing the category of"fossil-fuel derived fuels (solid)" and replacing it with a category of "other fuels (solid)."At least 10TradeAssociation98.33(a)(1) TableC-1.Replace the HHV (which is based on the units for a liquid fuel) and CO2emission factorfor “Still Gas” in Table C-1 of subpartC with a HHV (for a gaseous fuel) and CO2emission factor for "Fuel gas."At least 10TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(a)(1) TableC-1.Amend Table C-1 of subpart c to remove "Pipeline" from the designation for “NaturalGas” to ensure that the default CO2emission factor listed in Table C-1 applies toappropriate natural gas, consistent with the definition of “natural gas” in Section 98.6 ofpart 98.At least 10TradeAssociation98.33(a)(1) TableC-1.For a space heater (<250mmbtu/hr) that burns waste motor oil, could a source use Tier 1and the HHV and emission factor for "Residual fuel oil #6" from Table C-1 of subpart C tocalculate CO2emissions? If not, what would be the applicable tier and approach?At least 10Hotline98.33(a)(1) TableC-1.Pursuant to 40 CFR 98.33(b)(2)(iii), the Tier2 calculation methodology may be used forcalculating CO2emissions from combustion of MSW, as Tier4 is not required. Pursuant to40 CFR 98.33(a)(2)(i), units combusting MSW and producing steam are instructed to useEquation C-2c for calculating annual CO2mass emissions. Equation C-2c containsvariable EF, where EF = fuel-specific default CO2emission factor, from Table C-1 ofSubpart C. Table C-1 does list a default CO2emission factor for Municipal Solid Waste.However, footnote 1 for Table C-1 indicates thatthe values/factors listed in Table C-1 forMunicipal Solid Waste are allowed only for unitsthat do not generate steam and use Tier1. Therefore, it appears Subpart C, as currently written, provides no way for MSW unitsthat produce steam to use Tier 2 to calculate annual CO2mass emissions.At least 10Hotline98.33(a)(1) TableC-1.An ethanol production facility has combustion units that would be subject to the generalstationary fuel combustion source category(subpart C) reporting requirements. Allcombustion units are <250 mmBtu/hr, and the facility has no CEMS that satisfy the Tier 4requirements. Some process vapors containing ethanol are used as combustion air for anatural gas-fired process boiler. The ethanolin the vapors is combusted in the boiler.There is no method for determining the ethanolcontent in the vapor stream fed to theboiler. Although ethanol is listed in Table C-1,it is listed with the qualifier "(100%)" andas a liquid fuel. Because the ethanol concentration in the combustion air is unknown andthe C-1 listing for ethanol specifies 100% ethanol, is the source required to report CO2emissions from combustion of the ethanol vapors?At least 10HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(a)(2)(ii)HHV weightingunder Tier 2.Reporting forunits sharing acommon fuelpipe.Part 75 requires HHV sampling at least monthly in many cases, and many smaller fuelcombustion sources at a facility subject to Subpart D in part 98 share a fuel source with aunit also subject to Part 75, Appendix D. Examples of combustion units sharing fuelsupplies with Part 75, Appendix D sources, are comfort heating, hot water heating, andother combustion units. These units might otherwise qualify for Tier 1 monitoring, exceptthat HHV data are available for these units that share a fuel source with a unit subject toPart 75. Are these smaller units also required to calculate a weighted average annual HHVunder Tier 2 using equation C-2b, even for homogeneous fuels like natural gas or No.2 fueloil? Requiring this calculation under Tier 2, and estimating the monthly fuel use for suchinsignificant activities would provide little benefit to the program. Moreover, becausemonthly fuel use is being determined solelyby "company records of annual fuel use" anyadditional accuracy associated with calculating the average HHV is likely to be lost in thecalculation.At least 1TradeAssociation98.33(a)(3)(iv)Conditionallyallow the use ofmass-based gasflow meters.Many facilities use mass or volumetric flow meters to measure gaseous streams. Pleaseconfirm whether it is acceptable to use a mass flow meter to determine the volumetric flowrate of gaseous streams under Subpart C of part 98.At least 1Hotline98.33(a)(4)Address theemissions froman exhaust streamdiverted from aCEMS monitoredstack.A plant has a mill that use 6 to 8 percent ofthe exhaust volume from a kiln and then emitsthis kiln exhaust flow through a separate millstack. The kiln stack will need to use a CO2CEMS, because it already has a CEMS installed to show compliances with state emissionlimits. However, the mill stack is not subject to any emission limit that would require aCEMS and does not have one installed. In 2011, can we estimate the mill stack flow rate asa percent of the total kiln gas flow rate (byengineering estimation or stack tests) and thenestimate the CO2emissions from the mill stack based on this percent and the measured CO2in the kiln stack?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(a)(4) and(a)(5) CEMSMany sources are subject only to a NOx trading program (NOx SIP Call or NOx-CAIRprogram) that requires reporting only during the ozone season (May 1 through September30). These sources use either a CO2(or O2) continuous monitor and a stack volumetricflow monitor, or a CO2(or O2) continuous monitor along with Part 75 Appendix D fuelflow methodology. These instruments are quality assured only during the ozone season.How should such sources calculate and report?Section 98.33(b)(4) seems to dictate the useof Tier 4, but the CO2emissions measurements will not cover the entire year. Section98.33(a)(5) discusses units that are not subjectto the Acid Rain Program but use monitorsunder Part 75, which seems to apply to the sources in question, but the various subsectionsdon't apply, as all scenarios assume that the source reports heat input year-roundAt least 2Hotline98.33(a)(4) and(a)(5) CEMSFor CAIR-affected units that monitor SO2and NOx emissions and Heat Input using theprovisions of Part 75 Appendix D & E, but are not required to report CO2mass emissions,may Part 75 Appendix G be used for CO2reporting under Part 98?At least 1TradeAssociation98.33(a)(4) Stackgas moisturecontentUnder Part 98, we have to either measure moisture in the stack for mass flow correction(which we don't do), or use the default moisturecorrection factors. For the Bituminous coalwe use the default correction is 6%, but the average is about 5% stack moisture whenmeasured during the RATA. We use the average of those 3 runs for the moisturecorrections until the next RATA. Instead ofusing multiple correction factors for differentpollutants, can EPA approve the use of thesame moisture numbers that are generatedduring the RATA? Because this is a Federalrule do we have to get permission fromsomeone at EPA? If so, who would that be?At least 1Hotline98.33(a)(4)(iii)Allow the use ofsite-specificmoistureconstants.If the CO2CEMS provides a reading on a dry basis, it is necessary to have a moisturecontent to calculate the mass rate emission(Equations C-6 and C-7)? If there is not amoisture sensor for the exhaust, Part 98 says use the default fuel moisture values per75.11(b)(2) in part 75. These are not appropriatedefaults for a cement plant. Cement plantmoistures are higher than the default valuesdue to other materials. Can we use themoisture measured during the CEMS RATA as a default for the year?At least 2TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(a)(5)Alternativemethods forcertain unitssubject to Part 75of chapter 40.Can electric generating units that have fuelflow meters and currently calculate their CO2emissions using 40 CFR part 75 appendix G(which is reported to the State) report CO2emissions using the alternative method for unitswith continuous monitoring systems, insection 98.33(a)(5), even if they are not subjectto the Acid Rain Program and do not reportdata to EPA ?At least 3Hotline98.33(a)(5)Alternativemethods forcertain unitssubject to Part 75of chapter 40.Subpart C does not clearly state that we can choose from Part 75, Part 60 or an applicablestate program to administer the CEMs for compliance with Part 98. For instance, Part98.34(c) gives us the option to use any of the 3 programs, however 98.35(a) says we arerequired to use Part 75 substitutions (...stationary combustion units subject to therequirements of this part that monitor and report emissions and heat input data inaccordance with 40 CFR part 75, the missing data substitution procedures in 40 CFR part75 shall be followed...). Additionally, 98.36(d) Units subject to 40 CFR part 75 does notapply because these units do report CO2mass emissions year-round according to Part 75.At least 3Hotline98.33(a)(5)(iv)Clarify forbiomasscombustion inunits with CEMIf a CEMS is used on a unit combusting both fossil fuel and biomass, subpart C requiresthat volumes of CO2be calculated for total CO2and fossil fuel CO2using equations C-12and C-13, where equation C-13 uses Fc-factors in scf of CO2/mmBtu from 40 CFR Part 75Appendix F. We must also calculate the process CO2; however, that procedure usingequation H-2 calculates a mass of CO2. Since the CEMS provides a mass of CO2, andequation H-2 provides a mass of CO2, can we calculate a mass of fossil fuel CO2using theemission factors in Table C-1 or a site-specific CO2emission factor in kg CO2/mmBtu? Ifwe can do it using mass calculations would we be exempt from reporting CO2volumes asrequired in 98.36(e)(2)(ix)?At least 2TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(b)(3)(iii)Clarify commonpipe reportingunder Tier 3We have multiple boilers in our steam generation unit, each of which has a heat inputcapacity greater than 250 mmBtu/hr. We used two fuels last year that accounted for lessthan 10% of the total heat input in the steam generation unit as a whole (not consideringthat the steam generation unit consists of multiple boilers that each had their own uniquepercentage for each type of fuel). One of those fuels accounted for 9% of the heat input. Isit correct that that we do not have to calculate and report CO2emissions from that fuel? Ifnext year our operations change and that fuel accounts for 11% of the total heat input;would that fuel have to be reported next yeareven if it is not included in this year’semissions report? Should we be prepared toreport CO2e emissions from any fuel type inany particular year that it accounts for more than 10% of the heat input, but at the sametime not have to report for years that are under 10%?At least 2Hotline98.33(b)(3)(iii)Clarify the use ofTier 3A boiler less than 250 mmBtu/hr burns coal, woodwaste, and other process rejects frompaper recycling/manufacturing. The unit alsouses limestone injection. Since the processwaste fuels are inconsistent and blended prior to burning, it is difficult to measure theamount of each fuel with acceptable accuracy. One option is to install as CO2CEMS andreport total emissions from the boiler using Tier 4. However, we would end up reportingemissions from fuels not listed in Table C-1. Because these waste fuel streams are lessthan 10% of the heat input, can we calculate emissions from coal, woodwaste, andlimestone using Tier 1, even if these methodsuse inventory tracking such as pile inventoryand company-established factors (i.e. % of wood chips purchased)?At least 3HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(b)(4)Clarify commonstack reportingunder Tier 440 CFR 98.36(c)(2) states that units exhausting through a common stack where CEMS areused to monitor CO2emissions at the common stack according to the Tier 4 Calculationmethodology may report the combined emissions from the units sharing the common stackor duct, in lieu of separately reporting theGHG emissions from individual units.What if I have an auxiliary boiler exhausting through a common stack with coal firedboilers using a CEMS and reporting under "Alternative methods for units with continuousmonitoring system" in 40 CFR 98.33(a)(5)(iii)? I'm not using the Tier 4 calculationmethodology for the auxiliary boiler, but the auxiliary boiler is still exhausting through acommon stack where CEMS are used. Am I still able to report under the common stackconfiguration?If the next year the coal fired boilers begin reporting under the Acid Rain Program andSubpart D, the same question applies: AmI still able to report under the common stackconfiguration? If not, will I need to subtract the auxiliary boiler GHG emissions out of theCEMS emissions totals and report them separately? That would be less accurate.At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(b)(4)Increase Tier 4threshold forMSWcombustion.The 250 tons MSW/day maximum rated input capacity as a criterion for use of Tier 4 isinequitable relative to the 250 mmBtu/hr maximum rated heat input capacity threshold thatapplies to other stationary combustion sources. An oil fired unit rated at 250 mmBtu/hrcould emit 18,275 kg C02/hr, whereas an MWCrated at just over 250 tons MSW/daywould emit only 3,331 kg C02/hr.EPA has argued that 250 tons MSW/day is asize determination for considering a largesource in other EPA programs, and reflects consistency with other EPA programs,particularly where the challenge of monitoring is substantially different, as it is for MSWversus more homogenous fossil fuels. However, EPA has not explained how the 250 tonsMSW/day threshold is relevantto monitoring of GHG emissions.EPA should establish either a "Tier 2-like" methodology or increase the threshold for Tier4 for MSW combustion to be equivalent tothe actual non-biogenic CO2 emissions equal tothe 250 mmBtu/hr threshold for fossil fuel-fired units. This would be consistent withnumerous programs and principles that EPA endorses.At least 1TradeAssociation98.33(b)(5)Clarify thestarting dates forthe use of Tier 4According to Part 98:40 CFR 98.33(b)(5) The Tier 4 Calculation Methodology shall be used beginning on:(i) January 1, 2010, for a unit that is required to report CO2mass emissions beginning onthat date, if all of the monitors needed to measure CO2mass emissions have been installedand certified by that date.(ii) January 1, 2011, for a unit that is required to report CO2mass emissions beginning onJanuary 1, 2010, if all of the monitors needed to measure CO2mass emissions have notbeen installed and certified by January 1, 2010.In this case, you may use Tier 2 or Tier 3to report GHG emissions for 2010.Is it correct to use Tier 4 for any portion of 2010 after an O2CEMS is certified? Forexample, an O2meter is certified on Feb 3, 2010. In the mean time the plant started the yearwith Tier 2 or 3 and then elects to begin (with a log note in the monitoring plan) usingCEMS data for GHG reporting on March 1, 2010.Does this also apply to installationsrequiring use of Tier 4?At least 5HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(c) CH4 andN2Ocalculations.Should 40 CFR 98.33(c) be amended so thatCH4 and N2O emissions are calculated usingEq C-9a, instead of Eq C-8, if Tier 3 is being used to calculate CO2emissions? Theequations are the same, but the definition ofHHV in Eq. C-8 refers to HHV values inTable C-1, and in C-9a it refers to measured HHV values.At least 1Hotline98.33(c) CH4 andN2Ocalculations.For calculating CH4 emissions, the default ‘still gas’ heating value in Table C-1 isprovided in units of MMBtu/gal. This is an error since these units imply that methane is aliquid when it is actually a gas in refineryprocesses. Part 98 goes on to specify EquationC–8 for estimating CH4 and N2O emissions for any fuels for which Tier 1 or Tier 3methods are used for CO2, and also mandates the use of the default HHV values fromTable C-1. In contrast, Equation C-9a permits the use of actual site HHV when using theTier 2 method. This approach, and the erroneous HHV value, makes it impossible forrefineries that use either Tier 1 or Tier3 to use the default values in Table C-1.At least 1TradeAssociation98.33(c) CH4 andN2Ocalculations.Although Part 98 limits reporting of CH4 and N20 to fuels combusted during "normaloperation," Part 98 does not define "normaloperation." In response to comments, EPAstated that "reporting of CH4 and N20 emissions is not required for fuels that are usedexclusively for unit startup or ignition." See,e.g., RTC, Volume 15 at 293-294, 328, 387,442, 448-449, 473, and 480. This statement suggests that EPA may not consider startup tobe "normal operation," but EPA does not say that or refer to a specific rule. Moreover, it isnot clear what other operating conditions orfuels EPA may have intended to exclude byreference to "normal operation."EPA should reconsider these new provisions in light of the provisions in Part 75 addressingcombustion of multiple fuels and explain in Part 98 how sources are to treat startup fuel,and other operating conditions thatEPA may not consider "normal."At least 2TradeAssociation98.33(c) Removeduplicate table C2 for CH4 andN2O.Table C-2 has been printed twice in the final rule. Is this just an editorial error or was athird table accidentally left out?At least 2Hotline98.33(d) ClarifyCO2emissionsfrom sorbent.Does Subpart C, 98.33(d)(1) reporting of CO2from sorbent, apply to cement kilns usingdry lime injection to control SO2in stack gas?At least 1TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.33(d) ClarifyCO2emissionsfrom sorbent.If a unit uses magnesium hydroxide for acid gas control (no CO2emissions should begenerated from this sorbent), can the unit use an O2monitor in lieu of a CO2monitorconcentration measurement? (I.e. the Mg(OH)2is not considered a source of process orsorbent CO2emissions.)At least 1Hotline98.33(e) Clarifythe calculation ofemissions frombiomasscombustion whencombined withother fuels.Did EPA intend for all biomass fuels to be subject to the 98.33(e) limitation, regardless ofwhether the unit fires biomass exclusively ora combination of fossil and biomass fuels(such that all biofuels not listed in Table C-1 would be exempt from CO2calculationrequirements, unless a CEMS is used)?At least 3Hotline98.33(e) Clarifybiogenic CO2emissions frombiomasscombustion40 CFR 98.33(e) discusses CO2emissions from the combustion of biomass, and states "Usethe procedures of this paragraph (e) to estimate biogenic CO2emissions from units thatcombust a combination of biomass and fossil fuels. Reporting of CO2emissions fromcombustion of biomass is required only for those biomass fuels listed in Table C-1 of thissection, unless emissions are measured using CEMS." Table C-1 does not list MunicipalSolid Waste as a biomass fuel, instead listing it as"Fossil fuel-derived fuel (solid)." Inaddition, if a unit does not measure CO2emissions using CEMS, based on the citedlanguage from 98.33(e), the unit is not required to calculate biogenic CO2emissions fromthe combustion of MSW.At least 3Hotline98.33(e) Optionalreporting ofbiogenic CO2Although EPA states in response to comments that Subpart D units that "choose" to reportbiogenic CO2separately may calculate biogenic CO2under § 98.33(e), RTC, Volume 16 at21, that option is not clearly reflected in §98.33(e), which makes no reference to Subpart Dunits? Moreover, §98.3(c) provides no option for not separately reporting biogenic CO2.At least 2TradeAssociation98.34 Allow theuse of consensusstandard methodsWe request that EPA confirm that the methods specified for analyzing GCV (or HHV)under Part 75, Appendix D, are not different methods than those specified in §98.34(a)(6),simply because they refer to a different approval year.At least 2TradeAssociationCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.34 Allow theuse of consensusstandard methodsSubpart C, 98.34(a)(6) lists eight approved methods for fuel sampling and analysis todetermine HHV for Tier 2 calculations. One of the methods listed is ASTM D240-02(Reapproved 2007), Standard Test Method forHeat of Combustion of Liquid HydrocarbonFuels by Bomb Calorimeter. We currentlyuse ASTM D240, but always use the mostrecent revision of any standard. ASTM D240was revised on September 21, 2009 to ASTMD240-09. It is still required to use the older version of the standard, or is it assumed thatwhen a standard is revised, the most recentversion supersedes the one written in Part 98?At least 2Hotline98.34 Allow theuse of consensusstandard methodsA facility burns coal. With each shipment received the coal company sends an analysisreport. The source planned to use Tier 2 for stationary combustion unit reporting sinceHHV information is received with each shipment.An analysis recently received for coalthat will be burned in 2010 referencesmethod ASTM D5865-04, not ASTM D5865-07a, asspecified in part 98 for HHV. Therefore, does the source have the option to use Tier 1,since the source does not have information on HHV using the same method versionspecified in Part 98?At least 2Hotline98.34(a)(2)Clarify thesamplingfrequency forcoal and fuel oilThe HHV and carbon content sampling and reporting in Part 98 are different from the fuelsampling requirements in Part 75, AppendixD. Part 98 may require additional (andsometimes duplicative) fuel sampling procedures for any Subpart C unit that shares a fuelsupply with a unit that is monitoring and reporting under part 75, Appendix D. Forexample, Subpart C does not appear to authorize sampling from a fuel line or tankfollowing the addition of a new shipment offuel, whereas this is allowed in Part 75,Appendix D. As a result, the owner/operator of a Subpart C source that shares a fuel supplywith a Part 75 source that has opted to usetank sampling would be required to obtain anduse fuel analysis records for each shipment, in addition to sampling under Part 75,Appendix D, when that shipment is added to the tank.At least 1TradeAssociation98.34(a)(2)Clarify thesamplingfrequency forcoal and fuel oilA facility is required to use Tier 3 to calculate GHG emissions from its coal-fired boiler.They receive coal delivery via railcar (1-2 times a week) and trucks (~2 trucks per day orevery other day). The coal comes from the samemine. Per 98.34(b)(3)(ii)(B), "For coaland fuel oil, analysis of at least one representative sample from each fuel lot is required.For the purposes of this section, a fuel lot isdefined as a shipment or delivery of a singlefuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.)." Does thismean that coal sampling has to be performedevery day/every other day from the trucks?At least 5HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.34(a)(2)Clarify thesamplingfrequency forcoal and fuel oilDoes the EPA have any additional informationon the meaning of "fuel lot" as used inSection 98.34(b)(3)(ii)(B)? (I can't find any onthe web.) Must the fuel sample come fromeach and every "delivery" that comes to the reporting facility? If so, this could involveliterally dozens of annual samplings, if fuel isdelivered by tanker trucks, which may arrivemultiple times per month.Conversely, could the analysis be of a sample from one of many rail cars in the same train,even if those cars didn't have a common source -- i.e., the fuel in them came from multiplerefineries, one of which ends up being the fuelthat is actually "delivered" to the reportingentity?At least 5Hotline98.34(a)(3),(b)(1)(vi), and(b)(3)(v) forblended fuelcombustionUnder 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 CO2emissions are based on the carbon content of fuel, multiplying thevolume of each pre-mixed fuel by its respective fuel-based emission factor results in anaccurate estimate of CO2for the fuel mixture.At least 1TradeAssociation98.34(a)(3),(b)(1)(vi), and(b)(3)(v) forblended fuelcombustionWhere the heat input capacity of a combustion unit is less than 250 mm Btu/hr inputcapacity and the unit is not subject to Tier 3 or 4 per Subpart Y of part 98, and where theremight be more than one fuel type fed to the same combustion unit, can the Tier 2 methodbe used to calculate emissions by usingmeasured HHV values of input streams or ameasured HHV of the mixed stream?At least 3Hotline98.34(a)(3),(b)(1)(vi), and(b)(3)(v) forblended fuelcombustionA source burns a mixed fuel stream that consists of ethylene process off-gas, other processoff-gas, and natural gas. The fuel is a mixedstream and is subject to Tier 3 requirementsfor CO2emissions. Calculations of CH4 and N2O appear to only be required for the fuelsthat are listed in Table C-2 of Part 98. Natural gas is listed in Table C-2, but the fuelmixture that is actually burned is not. Is the mixed fuel exempt from the requirement tocalculate CH4 and N20 emissions at this timebecause emission factors don't exist? Or, dowe need to estimate the fraction of the mixedfuel that is natural gas and then calculateCH4 and N2O emissions from the natural gas contribution to the overall mixture?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.34(b) ClarifyTier 3 samplingfrequency forgaseous fuels.As currently written, steelmaking units thatcombust blast furnace gas and/or coke ovengas are subject to two competing requirements. First, §98.34(b)(3)(ii)(C) requiressampling “once per calendar quarter” “for fossilfuel-derived gaseous fuels.” Since blastfurnace gas and coke oven gas are both expressly identified in Table C-1 as “Fossil Fuelderived Fuels (Gaseous)”, they are subject to this requirement. Second, §98.34(b)(3)(ii)(E)requires either daily or weekly sampling for “gaseous fuels other than natural gas andbiogas,” which (perhaps inadvertently) also appears to include fossil fuel-derived gaseousfuels like blast furnace gas and coke oven gas.EPA should clarify that Tier 3 blast furnace gas and coke oven gas sampling frequency isgoverned solely by §98.34(b)(3)(ii)(C) since these gases are expressly listed as “fossil fuelderived gaseous fuels” in Table C-1. To accomplish that result, EPA should provide thefollowing technical clarification to §98.34(b)(3)(ii)(E):(E) For gaseous fuels other than natural gas,fossil fuel-derived gaseous fuels listed inTable C-1 and biogas (e.g., refinery gas), daily sampling and analysis to determine thecarbon content and molecular weight of the fuelis required if the necessary equipment is inplace to make these measurements. Otherwise, weekly sampling and analysis shall beperformed.Quarterly sampling is appropriate to determine and report CO2emissions from coke ovengas and blast furnace gas combustion given the relatively narrow and defined ranges ofvariation expected. Confirming a quarterly approach is also consistent with EPA’s relateddecision to reduce the reporting burden by allowing Tier 1 or Tier 2 treatment via thecreation of default emissions factor for blast furnace gas and coke oven gas.At least 2HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.34(b)(3)(ii)(E)Clarify samplingfrequency forgaseous fuel.Regarding refinery fuel gas sampling frequency and method. 98.34(b)(3)(ii)(E) addressesfuel sampling and states “For gaseous fuels other than natural gas and biogas (e.g., refinerygas), daily sampling and analysis to determine the carbon content and molecular weight ofthe fuel is required if the necessary equipment is in place to make these measurements.Otherwise, weekly sampling and analysisshall be performed”. What constitutes“necessary equipment” that would mandate “daily sampling and analysis”? Does thismean a continuous on-line gas chromatographor does it also include hand drawn samplesanalyzed in a lab? Section 98.34(b)(3)(ii)(E)is not in agreement with the preamble for thefinal part 98 which states “The minimum monitoring frequency for refinery fuel gas carboncontent and molecular weight was changedto weekly from daily in 40 CFR part 98,subpart C, for reporters that do not have continuous monitoring equipment”. Please clarifyrefinery fuel gas monitoring frequency requirements.At least 1Hotline98.34(c) formoisture monitorcertificationCement production facilities often have CEMS that are subject to State and Part 60regulations. Facilities have or will be installing CO2CEMS on their kiln stacks in order toreport under Part 98. One facility's CEMS has a moisture monitor (O2wet and O2drysystem) and reports emissions on a dry basis.If all other CEMS (flow and CO2) at thisfacility can be certified under State or Part 60 guidelines for Part 98, does the certificationof the moisture system (O2wet and O2dry) need to be certified under Part 75 regulations,which would require the facility to order different O2calibration gases in order to meetwith Linearity requirements of Part 75? Also, can this facility certify each individual CEMunder different guidelines, or does one specific regulation (Part 60 or Part 75) apply to allCEMS utilized in the reporting of emissions under Part 98?At least 2HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.36(c)(3) forcommon pipereporting optionUnder the recordkeeping portion of subpart A ofpart 98, you must retain a list (record) ofall units, operations, processes, and activities for which GHG emission were calculated, inaddition to those records prescribed in eachapplicable subpart of part 98.Scenario: A facility is subject to part 98 but only as a stationary fuel combustion sourcesubject to subpart C. The facility uses natural gas and has one natural gas line entering thefacility that is used to fuel four separateboilers. The facility will be depending on utilitybills for the total quantity of natural gas used during 2010, from which it can then calculateCO2-e emissions, CO2emissions, N2O emissions, and CH4 emissions.Based upon the language noted from subpart A, does the facility need to maintain a list ofall the individual combustion units (in this case, the boilers) for which GHG emissionswere calculated? This does not seem necessary because GHG emissions were notcalculated at the unit level; the facility wasreally only calculating one emissions numberbased upon natural gas intake through one pipe.Though this particular example seems simple, there could be other cases where fuel couldbe coming in through one pipe but could beused in many different units. This couldrequire an exhaustive inventory-taking process of hundreds of small combustion units suchas lab Bunsen burners, cafeteria equipment,and other small operations and processes, butthe facility is still only calculating the emissionsbased upon the quantity of fuel taken in atthat one source, based on utility bills, and not calculating the emissions on a unit level.Please provide clarification as to whether records must be kept on unit level, when GHGemissions are being calculated based upon a single fuel intake line, and fuel intake iscalculated based on fuel vendor invoices/bills, orvendors external meter readings, insteadof based on flowmeters or any individual fuelmeasurements on an individual unit, process,or activity level.At least 10HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.36(c)(3) forcommon pipereporting optionPart 98 allows for the common reporting and monitoring of fuel for equipment: "When twoor more liquid-fired or gaseous-fired stationary combustion units at a facility combust thesame type of fuel and the fuel is fed to the individual units through a common supply lineor pipe, you may report the combined emissions from the units...provided that the totalamount of fuel combusted by the units is accurately measured at the common pipe orsupply line using a fuel flow meter that iscalibrated in accordance with § 98.34(a)"However, 98.34(a) does not have calibration requirements for fuel flow meters. 98.34(a)provides requirements for the monitoring ofthe HHV of the fuel. 98.34(b) provides thecalibration and maintenance requirements for fuel flow meters. Can the common supplypipe provisions still be utilized as long asthe flow meters meet the requirements of98.34(b)? Is this issue being addressed?At least 3Hotline98.36(c)(3) forcommon pipereporting optionIf a facility wishes to use the "Common Pipe" reporting alternative, but some of the fuelmonitored by a common flow meter may be occasionally flared, is it acceptable to includethe flared gas in the total fuel consumption?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.36(c)(4) forcombinations oflarge and smallcombustion unitsSources that are subject to Part 98 due to combusting more than the trigger threshold ofnatural gas (determined using a common billingmeter) may have some large quantity usersand small quantity users. The sources we are looking at are institutional(schools/universities) and industrial (manufacturing). These sources will be required todevelop an inventory of the equipment that burns the fuel as part of their Monitoring Plan.What level of detail is required for the inventory with respect to small quantity equipmentuses (e.g. stoves, ovens, space heaters, processheaters, Bunsen burners, etc.)? The EPA'sFAQ web-site indicates there is NO de minimis level to exempt reporting for sources. Dothe smaller sources need to be included on the equipment inventory found in theMonitoring Plan? Is it acceptable to list outthe details on the large quantity sources (e.g.boilers) and then generalize the smaller sources?For example, universities and manufacturing operations have onsite labs for students orprocess operations to use. These labs do not meet the definition of R&D so they are notexempt from reporting. These facilities can havea multitude of small quantity sources suchas space/door heaters, Bunsen burners, muffle ovens, process ovens, etc., that use naturalgas. The natural gas use cannot be separatedout, as a common meter is used. How shouldthis type of equipment be addressed in the equipment inventory? Is it acceptable togeneralize "various natural gas combustion equipment with a heat input capacity less thanXX BTU/hr"? Is it acceptable to use the CO2emission factor found in Part 98 for allgeneral pipeline quality natural gas combustion atthe site regardless of equipment size?Also, universities and other institutions have residential housing units that are part of theircampus. These units can use gas for heating orcooking. They are part of the institution'scampus so are not considered residential and must be included in the report. Usage comesfrom a common meter. Is it OK to report "a variety of kitchen stoves/ovens less than XXBTU/hr heat input" in the inventory?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.36(e)(2)(iii)HHV valuesobtained fromfuel suppliers.A facility has combustion units that burn natural gas that are greater than 250 MMBtu/hr,so it must use Tier 2 and measure the HHV for a fuel. All the units are supplied to thefacility by the same natural gas line. On the monthly gas bills, the gas supplier provides aHHV for the gas for that month. This HHV isan average value for multiple stationsmonitored each month around the city. The station nearest the facility is only sampledevery 3-4 months. The gas supplier does not provide the information specified in Part 98for HHV measured values, such as the test method used and the date of the test. Can thefacility use the HHV provided each month to calculate the emissions following the Tier 2requirements and not maintain the other information about the tests, or does the facilityneed to obtain from the supplier the testmethod used, date of the test, etc.?At least 2HotlineSubpart D – Electricity Generation98.46 DataReportingShould section 98.46 , "Data Reporting Requirements" under Subpart D, reference section98.36(d) instead of section 98.36(b)? Section 98.36(b) applies to units that use the fourtiers, which is not applicable to units that are subject to Subpart D. Section 98.36(d) appliesto units that are subject to 40 CFR part 75, which would apply to units that are subject toSubpart D.At least 3Hotline/UARGSubpart X – Petrochemical Production98.243(d) Adddefault HHV inTable C-1 andallow the use ofsite specific HHV40 CFR 98.243(d) requires that 98.33(c) be used to calculate CH4 and N2O fromcombustion of fuel that contains ethylene process off-gas using the factors in Table C-2.98.33(c) requires that the default HHV in Table C-1 or monitored HHV be used. Sincethere is not a default HHV for ethylene process off-gas in Table C-1, must facilitiescomplying with Subpart X via the ethylene combustion methodology determine a sitespecific HHV for ethylene process off-gas?If so, what calibration and missing dataprocedures apply?At least 1Hotline98.243(d) Addthe methodologyfor smallethylene off-gasstreamsCan Part 98 include an alternative to installing fuel flow meters for calculating CO2emissions, etc., for very low flow natural gasusers, such as catalytic thermal oxidizers thathandle vents from storage tanks?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.244(b)(4)Amend carboncontentdeterminationmethodspecificationsSubpart C allows the use of a calibrated gas chromatograph for the determination of HHV(40 CFR 98.34(a)(6), Tier 2) and for molecular weight and carbon content (40 CFR98.34(b)(5), Tier 3). Why does the mass balance method under Subpart X (40 CFR98.243(c)(3)) require that only specific methods as specified at 40 CFR 98.244(b)(4) beused for the determination of carbon content of feedstocks and products? Why doesSubpart X not allow the use of a calibratedgas chromatograph for the determination ofcarbon content from petrochemical feedstocks and products?At least 3Hotline98.244(b)(4)Amend carboncontentdeterminationmethodspecificationsThe test methods outlined in 40 CFR 98.244(b)(4)(i) through 98.244(b)(4)(x) were notspecifically developed for the analysis of carbon content in carbon black. Of all themethods noted in the regulation, method ASTM 5291 would be the closest to beingappropriate for carbon black. However, this method was designed for carbon content in the75% - 87% range, while the carbon content ofcarbon black is in excess of 97%. In orderto use this method for the intended purpose, slight modifications will have to be made toASTM 5291 to accommodate the higher carbon content to ensure the needed accuracy.Please note that modifications to this method have been accepted under other GHGregulatory systems, such as the European Union Emission Trading Scheme. The carbonblack industry proposes to implement these modifications to the ASTM test method tomeet the requirements of Part 98. We suggest that the agency revise Part 98 to clarify thatit has the authority to approve methods and modifications to methods that would be betteror more appropriate than those specified in 40 CFR 98.244(b).At least 3Hotline98.244(b)(4)Amend carboncontentdeterminationmethodspecificationsThe following test method should be incorporated by reference at 40 CFR 98.7(e) and 40CFR 98.244(b)(4): ASTM D2593-93 (Reapproved 2009) Standard Test Method forButadiene Purity and Hydrocarbon Impurities by Gas ChromatographyAt least 3HotlineSubpart X – Petrochemical Production and Subpart Y – Petroleum RefineriesCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.243 and98.253 -alternativestandardconditionsThe proposed Part 98 defined “standard conditions” in accordancewith the prevalentindustry definition of 60F and 14.7 psia (consistent with allUS consensus standards). Incomments on the proposed Part 98, we noteda discrepancy between the stated standardconditions and the “molar volume conversion”factor provided in the equations forcalculating emissions from gaseous fuels. However, instead of providing several “molarvolume conversion” factors that could be usedby reporters under different temperature andpressure conditions, the final Part 98 defines“standard conditions” at 68F and 14.7 psia,placing an unnecessary burden on reporters to convert to emissions at 60F and 14.7 psia,and introducing confusion that could leadto erroneous emission calculations.EPA should adopt the approach where a shortlist of “molar volume conversion” factorsare provided for different temperature and pressure conditions and instruct reporters to usethe appropriate one for their measurement method for quantifying GHG emissions.At least 1TradeAssociationSubpart Y – Petroleum Refineries98.252(a) Addthe methodologyfor combustion offuel gas in smallunitsBy invoking the use of Equation C-5 (Tier 3method in subpart C) or Tier 4 method, Part98 precludes smaller refinery combustion units (< 250 MMBtu/hr) that are combustingrefinery fuel gas (still gas) from using either Tier 1 or Tier 2 methods with the default CO2emission factor. Due to the inconsistency between subparts Y and C on this topic, EPAshould correct the text in 98.252(a) to reflect its intent - as provided in the preamble - andallow refineries access to allthe calculation methods (tiers) as outlined in subpart C, asapplicable.At least 5Hotline andEPAcorrespondencewith tradeassociations98.252(a) Addthe methodologyfor combustion offuel gas in smallunitsEPA should explicitly allow the use of Tier 1 and Tier 2 methodology with applicabledefault emission factors to reduce the reporting burden for small stationary combustionunits, including ‘pilots’ on heaters and flares.This would prevent the need to install flowmeters on all “pilots” which will be quite costly and absolutely unnecessary consideringthe insignificance of their emissions.At least 5Hotline andEPAcorrespondencewith tradeassociations98.252(a) Addthe methodologyfor combustion offuel gas in smallunitsCan Part 98 include an alternative to installing fuel flow meters for calculating CO2emissions, etc., for very low flow natural gasusers, such as catalytic thermal oxidizers thathandle vents from storage tanks?At least 5Hotline andEPAcorrespondencewith tradeassociationsCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.252(a) Addthe methodologyfor combustion offuel gas in smallunitsIf a source has storage tank vents routed to on-site incinerators for vapor destruction, couldPart 98 have an alternative to installing fuelflow on the storage tank vents for calculatingCO2emissions, etc.?At least 5Hotline andEPAcorrespondencewith tradeassociations98.252(a) Allowuse of same Tierfrom subpart Cfor CH4 and N2Oas for CO2.Due to the inconsistency between subpartsY and C on this topic, EPA should amend98.252(a) to allow refineries to use all thecalculation methods (tiers) as outlined in subpartC, that are applicable for calculating CO2, CH4, and N2O emissions.At least 1Hotline98.252(a) Clarifythe requiredemissionsmethods forflares98.253(a) & (b) contradict themselves and 98.252(a). Section 98.252(a) says to use SubpartC to calculate flare emissions, then 98.253(a) excludes 98.252(a), but then 98.253(b)includes flares and there is a section in subpart Y for doing flare calculations. Should flareemissions be calculated following subpart Y or C?At least 5Hotline98.253(e) AmendCBQdefinition inEquation Y-11Equation Y-11 calls for the number of regeneration cycles and the coke burn off perregeneration cycle, for calculating CO2emissions from the catalytic reforming unit catalystregenerator. However, some units are not operated with regeneration cycles. Can sourcesalter this equation to more accurately calculate emissions based on actual operations?At least 1HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.253(i)(1)CalibrationRequirementsIn regards to Equation Y-18 Subpart Y section98.253(i)(1): The variable Pcv is defined asthe "gauge pressure of the coking vessel whenopened to the atmosphere prior to cokecutting or, if the alternative method providedin paragraph (i)(2) of this section is used,gauge pressure of the coking vessel when depressurization gases are first routed to theatmosphere (pounds per squareinch gauge, psig)." If a pressuregauge is used to determinePcv, does the gauge have to be calibrated? Section 98.254 (Monitoring and QA/QCrequirements) does not discuss calibration/recalibration requirements for pressure gauges,but Subpart A Section 98.3(i)(A) states that, "...devices (e.g., belt scales) that measure dataused to calculate GHG emissions shall be calibrated prior to April 1, 2010..." Therefore,Subpart A appears to require that, because the pressure gauge is a device measuring dataused to calculate GHG emissions, it must be calibrated. However, no methods areprovided for calibration and no recalibration requirements are discussed in Subpart Y.Please clarify whether a pressure gauge must be calibrated.At least 1Hotline98.253(n) Clarifythe requirementsfor loadingoperationsWhat test method is USEPA recommending or requiring for analysis of vapor-phasemethane composition as specified in 98.253(n)? None is mentioned in 98.253(n), and noneof the methods in 40 CFR 98.7, listing the standardized methods adopted by reference, arespecific to identification of vapor-phrase methane composition.At least 1EPA's e-mailsays it's fromRT.98.254(b) Clarifythe calibrationrequirementsWhen Part 98 says facilities must re-calibrateflow meters either "biennially or at theminimum frequency specified by the manufacturer" (e.g., §98.254(b)), does that mean ...(1) If the manufacturer specifies a re-calibration frequency of once every 6 months, thenthe facility must re-calibrate every six months, instead of biennially?(2) If the manufacturer specifies a re-calibration frequency of once every 3 years, then theycan recalibrate once every three years? Or do they have to re-calibrate after 2 yearsbecause Part 98 meant to say biennially was the minimum frequency allowed?Part 98 does not specify the minimum requirements for recalibration, so is it safe to assumethat a source can do it every 3 years, if that is specified by the manufacturer, and still be incompliance? Are they still in compliance if the recommended frequency from themanufacturer is every 10 years?At least 1HotlineSubpart AA – Pulp and Paper ManufacturingCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.273 and 98.33Used oilcombustionPursuant to 98.273(a)(1), CO2emissions resulting from the fossil fuels burned in recoveryfurnaces and lime kilns are to be determinedusing “direct measurement of fossil fuelsconsumed and default emissions factors according to the Tier 1 methodology for stationarycombustion sources in 98.33(a)(1).”98.273(c)(1) and (c)(2) require that defaultemission factors from Table AA-2 be used inthe GHG calculations for lime kilns. Used oilis considered a listed fuel (“other oil”) inTable C-1 of Subpart C based on the FAQ’s posted on U.S. EPA’s web site. However,used oil is not listed in Table AA-2. What GHG emission factors should be utilized forused oil burned in lime kilns?At least 2Hotline andTradeAssociation98.273 andCalibration98.3(i)Pursuant to 98.273(a)(1), CO2emissions resulting from the fossil fuels burned in recoveryfurnaces and lime kilns are to be determinedusing “direct measurement of fossil fuelsconsumed and default emissions factors according to the Tier 1 methodology for stationarycombustion sources in 98.33(a)(1).”Given that Tier 1 is to be used to calculate CO2emissions from recovery furnaces/limekilns and that no calibrations are required for Tier 1, can you confirm that the fuel flowmeters used to measure the amount of fossilfuel going to recovery furnaces and lime kilnsdo not have to meet the calibration requirements in 98.3?At least 2Hotline98.273 and98.33(b)(2) Tier1 vs. Tier 2Pursuant to 98.273(a)(1), CO2emissions resulting from the fossil fuels burned in recoveryfurnaces and lime kilns are to be determinedusing “direct measurement of fossil fuelsconsumed and default emissions factors according to the Tier 1 methodology for stationarycombustion sources in 98.33(a)(1).”If a mill obtains the HHV or carbon content of the fossil fuels burned in its recoveryfurnaces or lime kilns in accordance with the minimum frequency specified under Tier 2 orTier 3 of Subpart C, can it use the Tier 2 or Tier 3 methodology to determine the CO2emissions from its recovery furnaces instead of the Tier 1 methodology? If so, can a milluse the annual average HHV from the sampling and analysis instead of the default HHV inthe GHG emission calculations if it obtains the HHV of the fossil fuels in accordance withthe minimum frequency specified in Part 98?At least 2HotlineSubpart OO – Suppliers of Industrial Greenhouse GasesCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.410 Subpart Lversus SubpartOO reportingrequirementsSubpart OO may conflict with the reservedSubpart L applicability provisions. EPAshould clearly state that Subpart OO does not apply to production, only to HFCs packagedfor market.At least 1TradeAssociation98.410 Subpart Lversus SubpartOO reportingrequirementsEPA should delete §§98.416(a)(8)and (a)(9). These elements are associated with SubpartO or reserved Subpart L. These production-related provisions are unrelated to HFCs incommerce.At least 1TradeAssociation98.414Clarification oftermsEPA needs to clarify the definition of destruction and emission.At least 1TradeAssociationSubpart PP - Suppliers of Carbon Dioxide98.423(a)(1),(a)(2), and (b)Definition of"purification,processing orcompressing"The carbon dioxide (CO2) supplier source category under Subpart PP of the GHG MRRconsists of facilities with production process units that capture a CO2stream for purposesof supplying CO2for commercial applications. Capturerefers to the initial separation andremoval of CO2from a manufacturing process or any other process (40 CFR 98.420(a)(1)).Subpart PP requires that the amount of CO2captured, prior to any subsequent purification,processing, or compressing, be monitored using a mass or volumetric flow meter (40 CFR98.423(a)). EPA should clarify the description given in Subpart PP for the location of aflow meter prior to any subsequent purification, processing, or compressing.Some plants that produce ammonia also produce carbon dioxide only as a byproduct of theprocess. The disposition of the CO2extracted from the synthesisgas is incidental to theammonia plant operations, and the design of the ammonia plant is not to capture CO2forthe purposes of supplying CO2for commercial applications.As the initial gas stream containing ammonia and CO2is a two-phase flow, an acceptabletechnology for accurately monitoring the two-phase flow is not available. Thus, a CO2flowmeasurement may not be technically feasible or accurate at the location required by aliteral interpretation of thisregulation. In addition, CO2later captured from this streamcould be used on-site for noncommercialapplications, commercial applications, andAt least 3HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)vented. 40 CFR 98.420(b)(5) specifically exempts "on-site use of CO2captured on site"from reporting. Therefore, a literal interpretationof Part 98 could require the installation ofa monitoring system that drastically over-estimates the amount of CO2supplied and doesnot satisfy the intent of Part 98 (to report the amount of CO2supplied for commercialapplications).Thus the question is, would initial cooling ofa gas stream containing ammonia and CO2,for the purpose of condensing and removing water, be considered "purification" under Part98, even if a portion of the CO2captured further downstream is for on-site noncommercialuse? Or does the statement "prior to purification, processing or compressing" apply only tosteps involved for the purpose of supplying CO2for commercial sale? Clarification of theflow meter's location is critical to a facility with applications for CO2that are bothnoncommercial and commercial. Thus, clarification is needed for the meaning of"purification, processing or compressing" under this rule.Some facilities further process the CO2gas (cooling, drying, and compression) to improvequality of the gas for commercial sale.Prior to the noncommercial and commercialapplications, and even at this time, CO2is routinely vented rather than entered into one ofthese applications.In order to accurately report the amount of CO2supplied for commercial applications, werecommend the amount of CO2supplied for commercial applications be measured usingtruck and rail weigh scales to determine the mass of CO2sold (i.e. weighing the truck orrail car in which CO2is shipped off-site before and after loading). Truck and weigh scalesare often calibrated and annually certifiedfor accuracy. In addition, measuring the CO2using weigh scales is consistent with how the mass of CO2imported or exported ismeasured under 40 CFR 98.423(b).Citation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.423(a)(1),(a)(2), and (b)Definition of"purification,processing orcompressing"EPA should clarify the applicability of Part 98 as it relates to CO2producers. Would a CO2production plant that takes a CO2-rich waste stream from a different plant, then purifiesand compresses the CO2, which is then sold, need to report their GHG emissions accordingto Part 98? Per 40 CFR Part 98, SubpartA, section 98.2(a)(4)(v)(A) indicates that carbondioxide suppliers including all producers of CO2are required to report their GHGemissions. In addition, Subpart PP, section 98.420(a)(1) defines suppliers of CO2as"Facilities with production process units that capture a CO2stream for purposes ofsupplying CO2for commercial applications... Capture refers to the initial separation andremoval of CO2from a manufacturing process or any other process". However, section98.420(b) indicates that Part 98 does not cover purification, compression, or processing ofCO2. Would a facility that does both initial separation of CO2and purification of CO2needto report its emissions?At least 3Hotline98.423(b) CO2supplied incontainersI am working with an ethanol facility that will fall under the applicability of Subpart PP"Suppliers of Carbon Dioxide". They ship CO2off site in containers (dry ice and liquidCO2in trucks). They use a scale and weigh bills to track CO2production and shipments.They do not transfer CO2gas offsite nor do they export CO2in containers.As an alternative to installing expensive CO2mass flow meters, can facility measure theannual CO2mass using the existing scale and weigh bill approach for their shipments (asallowed under (a)(3) for importersand exporters), or must they install flow meters?If a facility is already weighing the CO2in containers (even if they are not exporting)shouldn't the scale weigh bill approach be allowed?At least 2HotlineCitation andTechnical IssueSummary of Question Submitted to EPAType andapproximatenumber ofsubmittalsReference(Helpline orTradeAssociationmaterials)98.424(a)(5) -Default value forCO2densitySeveral sources are concerned with a particular requirement of Subpart PP – Suppliers ofCarbon Dioxide. Most of these sources operate volumetric flow meters and are required touse equation PP-2 of Subpart PP to calculate quarterly the mass of CO2in their CO2stream.Equation PP-2 requires the measurement of the density of the CO2stream on a quarterlybasis. In Section 98.424 of Part 98 (Monitoring and QA/QC requirements of Subpart PP)several ambiguous methods to complete thedensity measurements are listed such as “Youshall use an appropriate standard methodpublished by a consensus-based standardsorganization to measure density if such method exists.” The other option is “Where noappropriate standard method developed by consensus-based standards organizations exist,you shall follow industry standard practices.”The sources note that the measurement of density of a CO2stream is estimated to cost asmuch as $15,000 per year based on 3rd party bids. Does the EPA have furtherrecommendations, additional informationon acceptable methods, or feedback on howothers are measuring the density of their CO2streams? As an example, it is possible tomeasure the density of the CO2stream by monitoring the temperature and pressure of thestream. The temperature and pressure wouldbe used as inputs to the ideal gas law(PV=nRT) allowing a calculation of the density of the CO2stream to be made. Can EPAprovide feedback on the acceptability of this method or others that are available?At least 1Hotline98.424(b)(2)referencecorrectionIn regards to Subpart PP - Suppliers of CO2,EPA has referenced examples of acceptablemethods for determining the composition of the CO2stream. One of the acceptablemethods noted includes "U.S. Food and Drug Administration food-grade specifications forCO2(see 21 CFR 184.1250)..." This specific citation refers to "Cellulase enzymepreparation derived from Trichoderma longibrachiatum," and makes no mention of CO2.CO2is referenced under 21 CFR 184.1240 as a compound that is generally recognized assafe (GRAS); however, this citation (184.1240) does not provide any analytical methodsfor determining the CO2gas composition. Please provide clarification on the specificmethods EPA is referencing when it refers to "see 21 CFR 184.1250."At least 1Hotline