MEMORANDUM 

FROM: Lisa Hanle, U.S. EPA, Climate Change Division 

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

DATE: July 1, 2010 

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

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

promulgation that are being addressed in the proposed Revision of Certain 

Provisions to the Mandatory Reporting 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 economy. Part 98 requires the monitoring of GHGs 

beginning with the 2010 calendar year, with reports 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 emissions and other related data. 

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

issues that need to be corrected and specific provisions 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 required additional time to address. 

EPA is now proposing a second set of amendments 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 certain provisions that have been the subject of 

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

Provisions), P (Hydrogen Production) and V (Nitric 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 trade associations and individual businesses, on-
line web-based seminars (webinars), and training sessions for EPA Regional Offices. The 

following table lists those meetings and webinars that EPA has conducted 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 MEETINGS AND WEBINARS 

Month and Year of Information Meeting or Webinar 

Organization or Location (estimated 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 Association, 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 MEETINGS AND WEBINARS 

Month and Year of Information Meeting or Webinar 

Organization or Location (estimated attendance, if available) 

Midwest Transportation & Air Quality Conference 

Detailed webinar (333) 

TCR/CAA (90) 

Environmental Groups (10) 

API 

NOV 2009 

Misc. Meetings with Industries (Refineries, 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 MEETINGS AND WEBINARS 

Month and Year of Information Meeting or Webinar 

Organization or Location (estimated 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 Association 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 MEETINGS AND WEBINARS 

Month and Year of Information Meeting or Webinar 

Organization or Location (estimated attendance, if available) 

EPRI CEMUG (150) 

3.0 SUMMARY OF QUESTIONS BEING 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 rules published since the final rule. So far, EPA 

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

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

to frequently asked questions. However, for many questions, they are being 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 associations that are also being 

resolved through the proposed amendments to the final rule. 

The following table summarizes the questions that have been raised 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 reflected in the following table. 
Summary of Questions And Issues From The EPA Helpline And Trade Associations 

Being Resolved By The Proposed Revision of Certain Provisions of the Mandatory Reporting of Green

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Subpart A – General Provisions

98.2 and Table A-1 

Part 98 has Table A-1 for Global Warming Potentials. How does a facility report if the gas they use does not have a global warming potential, for example C5F8 and specific fluorinated heat-transfer fluids? 

At least 2 

98.3(c) Biogenic Emissions 

Are electric generating units that are subject to Subpart D-Electricity Generation required to separately report their biogenic CO2 emissions? 

At least 3 

98.3(f) typographic error 

I 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 1 

98.3(g)(4) Record-keeping for Missing Data Events 

In the final Part 98, EPA added in §98.3(g) a requirement to record: For each missing data event, ... a record of the duration of the event, actions taken to restore malfunctioning monitoring equipment, the cause of the event, and the actions taken to prevent or minimize occurrence in the future. Although Part 75 requires recording of the cause of missing data periods and the corrective actions taken (see 40 C.ER. § 75.57(h)), this can be satisfied by a simple notation in the maintenance log required under Part 75, Appendix B, § 1.1.3 (maintenance records). There is no requirement in Part 75 to separately record the "duration of the event" or the "actions taken to prevent or minimize occurrence in the future." Requiring sources using CEMS, particularly those already complying with Part 75 recordkeeping, to develop these additional records would be overly burdensome and of little usefulness. The majority of missing data periods associated with CEMS are due to routine activities or calibration failures, for which there is no clear measure to prevent future occurrence. Moreover, because these events are of short duration and Part 75 already requires the flagging of each missing data period in the electronic report, a new requirement to record the "duration" of missing data events also is unnecessary and potentially burdensome. EPA should reconsider these additional requirements, particularly with respect to units subject to Part 75 recordkeeping, and Part 98 should rely on Part 75 recordkeeping as sufficient to satisfy Part 98 recordkeeping for CO2 and heat input. 

At least 1 
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98.3(h) Correction and Resubmission of Annual Reports 

We have a number of concerns regarding the provision for resubmission of GHG reports. First, because the annual reports include much more information than calculated GHG emissions data, and must be submitted in the as yet unspecified "format specified by the Administrator," (see, e.g., Final §§ 98.5 and 98.36), the types of "errors" that could trigger a requirement for resubmission under this rule are almost limitless and go well beyond errors in "calculation" of data. Although EPA presumably could develop some significance criteria for errors, and limit the resubmission requirement to errors identified in formal requests for submission (as opposed to those identified in the sort of automated feedback reports used under the Acid Rain Program (ARP) reporting requirements), Part 98 appears to require resubmission for virtually any error identified by the source owner/operator without exception. Part 98 also could trigger a requirement for resubmission years after the original submission was made. Second, depending upon the mechanism EPA uses to define and identify "errors," Part 98 could trigger a requirement for resubmission even when the report is accurate. For example, in some cases, identified "errors" could be caused not by inaccurate information or data, but by errors or bugs in EPA's (or the source's) software, differences in interpretation of Part 98, or implementation of other screening mechanisms that may not take into account source specific configurations or issues. Based on experience with reporting under the ARP, these issues are most likely to arise in the first year of implementation of any new or revised electronic format or software, and could arise frequently if EPA relies on electronic auditing tools similar to those employed under 40 C.F.R. Part 75 to identify "errors." Reporters should not be required to re-submit and recertify the accuracy of a report, unless the source owner/operator concurs that the original report was erroneous. Third, the requirement to resubmit a report "within 45 days" may not provide sufficient time to determine whether the identified "error" is in fact an error, or to determine the best way to correct an error. Such an inflexible deadline is not appropriate in the context of such an open-ended requirement. 

At least 1 

98.3(i) Calibration Requirements 

We operate vortex and magnetic tube fuel flow meters for which there are no field 

calibration procedures identified by the manufacturers. How do we comply with the initial 

and ongoing calibration requirements for these types of meters? 

At least 1 
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98.3(i) Calibration Requirements 

Did EPA intend that fuel flow meters used to collect company records under Tiers 1 or 2 be 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 fuel combusted 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 the company records required for emission calculations. Subpart C does not prescribe specific accuracy requirements for company records; it only stipulates that the company records shall include an explanation of how they are used to determine fuel consumption when Tiers 1 or 2 are used [see §98.34(f)(1)]. This is in contrast to the Tier 3 direct fuel flow measurement requirements in which EPA clearly mandates that the fuel flow meters required 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 to apply to all "flow meters and other devices (e.g. belt scales) that measure data used to calculate GHG emissions" and requires that "all measurement devices shall be calibrated to an accuracy of 5 percent." 

At least 5 

98.3(i) Calibration Requirements 

Section 98.3(i)(1) requires flow meters and other devices (e.g., belt scales) that measure data used to calculate GHG emissions to be calibrated prior to April 1, 2010 using procedures specified in Part 98. The paragraph goes on to state that all measurement devices must be calibrated according to the manufacturer's recommended procedures, an appropriate industry-consensus standard, or a method specified in a relevant subpart of this part. The paragraph also requires all measurement devices must be calibrated to an accuracy 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 reconcile data 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 based on weight measurement with calibrated scales, and periodic reconciliation based upon inventory and accounting records?" 

At least 1 
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98.3(i) Calibration Requirements 

1. It is not clear what the initial 5% calibration accuracy entails, and, specifically, when the EPA-specified calibration error equation (Eq. A-2) should be used. Typically when a measurement device is calibrated initially, it is set to operate within the error range for the applicable measurement technology and operating standard. In 98.3(i)(2), it is not clear whether the +/- 5% accuracy requirement applies to the meter prior to or after calibration. 2. Is the 5% calibration accuracy requirement applicable to all devices used for measuring any parameter – even those used for a Tier 1 and/or Tier 2 method under subpart C? Does the 5% accuracy requirement apply to on-line analyzers (e.g., GCs)? Would it apply to existing company procedures and records when the ‘best available monitoring method’ clause is enabled? 

At least 1 

98.3(i) Calibration Requirements 

Tiers 1 and 2 do not specifically require direct measurement of fuel consumption. Part 98 allows for the use of "company records" (as defined in §98.6) in lieu of flow meters. However, if the "company records" are based on data from flow meters, do such flow meters still need to meet the calibration/accuracy requirements in §98.3(i)? 

At least 2 

98.3(i) Calibration Requirements 

Are facilities using Tier 1 or Tier 2 calculation methods only required to follow the initial calibration requirements contained in 40 CFR 98.3, and are not subject to any recurring calibration requirements? Part 98 does not include any language that requires those using Tier 1 or Tier 2 calculation methods to perform recalibrations. 

At least 10 

98.3(i) Calibration Requirements 

An ethanol production facility has sold CO2 in the past, but has not done so at all in 2009. 

The facility does not know if they will sell CO2 in the future. However, if they begin selling 

ethanol sometime in 2010, how soon must the ethanol plant install a flow meter for this CO2 stream or must they install the flow meter now, before March 31st, 2010, even if they 

do not sell any CO2 in 2010? 

At least 1 
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98.3(i) Calibration Requirements 

Part 98 states: "If a portion of the fuel measured at the common pipe is diverted to a chemical or industrial process where it is used but not combusted, you may subtract the diverted fuel from the fuel measured at the common pipe prior to performing the GHG 

emissions calculations, provided that the amount of fuel diverted is also measured with a 

calibrated flow meter per §98.3(i)." Section 98.3(i) includes the +/- 5% accuracy requirement. It is possible to have an overall measurement accuracy of +/- 5% without requiring that all flow meters in a common pipe meet +/- 5%. For example, a common pipe supplies fuel gas that is used as fuel to a combustion unit that has a maximum rated heat input > 250 MMBTU and supplies fuel gas used as a feedstock to a process unit. The fuel gas is measured at the common pipe with a meter that has an accuracy of +/- 1% and the flow of fuel gas used as a feedstock is measured at the process unit with a meter that has an accuracy of +/- 10%. 90% of the fuel supplied by the common pipe is used as fuel in the large combustion unit. If a sum of squares weighted uncertainty calculation is performed on the flow meters, the overall measurement uncertainty of fuel supplied to the combustion unit may still be within the +/- 5% accuracy requirement. Allowing the use of a weighted measurement uncertainty calculation to determine overall measurement uncertainty for common pipe situations will allow reporters the flexibility to report accurate emissions without requiring a large number of new or upgraded flow meters to be installed. 

At least 1 

98.3(i) Calibration Requirements 

Are orifice, venturi, and nozzle flow meters required to have temperature, and total pressure transmitters located on the flow meters? 

At least 1 

98.3(i) Calibration Requirements 

Does Part 98 require gas billing meters to be calibrated? At least 10 

98.3(i) Calibration Requirements 

EPA should take the following specific actions with respect to Section 98.3(i): 1. Amend the initial calibration requirements to allow “accuracy of initial calibration” to be determined within the error range for the specific measurement technology based on the applicable operating standard. 2. Allow flow meters to be calibrated on-site by trained personnel using consensus industry standards. 

At least 1 
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98.3(j) BAMM A refinery has already submitted and received from EPA a BAMM extension request 

approval through 2010 for refinery fuel gas meters and other meters associated with Subpart Y. Recently the refinery realized that calibrating the pressure transmitter used to compensate the air flow to the FCC would require bypassing the surge protection for the blower. This could result in damage to the air blower since it would have no surge protection during the time of calibration of the instrument. Therefore because of this equipment safety issue, the refinery prefers to wait to calibrate the pressure instrument until a scheduled downtime for the FCC. Would EPA confirm that even beyond 2010, a calibration is not required until a scheduled shutdown, since 98.3 (i)(6) allows for delay in cases where calibration would disrupt normal process operation?. 

At least 1 

98.3(j) BAMM 40 CFR 98.3(i)(6) allows the delay of calibration of measurement devices if the device 

requires that a continuously operating unit or process must be shutdown and the device sent off-site for calibration. If a piece of monitoring equipment is required to be installed to comply with the GHG reporting rule and the installation requires a unit shutdown, can the facility delay the installation of monitoring equipment until the next scheduled shutdown? 

At least 1 
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98.3(j) BAMM There is a concern that the limited amount of time available to calibrate the large number 

of equipment, as required under this rule, could pose a safety hazard. This would be especially pronounced if calibrations and maintenance have to be completed during the heart of winter, in order to meet the March 31st deadline. For complex facilities, or those that are geographically dispersed, the 3 months period (till March 31st) allowed for initial calibration is insufficient. It will be extremely difficult to identify all the equipment whose data would be used to calculate and report emissions. Making sure that all of this required equipment is calibrated will necessitate many additional resources, including skilled labor, which would impose an undue burden on reporters. In accordance with the provision of postponing initial calibrations for continuously operated process units, would EPA authorize the use of ‘best available measurement data’ using existing company instrumentation and operating practices until new or upgraded equipment could be installed and calibrated? 

At least 1 

98.3(j) BAMM Could 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 the calibration requirement extension in Section 98.3(i)(6). 

At least 1 

98.3(j) BAMM Section 98.3(i)(1) of the final rule provides that “flow meters and other devices (e.g., belt 

scales) that measure data used to calculate GHG emissions shall be calibrated to an accuracy of 5 percent.” Section 98.3(i)(2) specifies that the accuracy of flow meter calibration should be less than 5%, when using Eq. A-2. Additionally, Section 98.3(i)(3) addresses accuracy requirements for in-situ calibration of pressure and temperature transmitters for orifice, nozzle, and Venturi flow meters. Specifically, it mandates an accuracy of less than 2% for each measurement point, or less than 5% for the sum of the three transmitters combined. 

At least 1 

Subpart A – General Provisions and Subpart C – General Stationary Fuel Combustion Sou
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98.3(c) Biogenic Emissions 

If ARP units are in fact subject to the reporting requirements in 98.36(b), and assuming they are considered to follow tier 4 because they use CEMS, then 98.36(b)(7) appears to 

indicate that separate reporting of biogenic CO2 is required. However, there are at least 

two instances in EPA's response to comments in which EPA states that they are not requiring ARP units to separately report CO2 emissions from biomass, but have provided a 

method for those that choose to do so. So is separate reporting of biogenic CO2 required? 

At least 3 

98.6 Definition of "Distillate fuel oil" 

Subpart C §98.33(b)(2)(ii) states: "Tier 2 Calculation Methodology may be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of pipeline quality natural gas or distillate fuel oil". Therefore, for a combustion engine with a maximum rated heat input capacity greater than 250 mmBtu/hr that only burns pipeline quality Jet-A fuel oil, is it acceptable to use Tier 2 to calculate CO2 emissions? 

At least 1 

98.6 Definition of "fossil-fuel" and classification of municipal solid waste (MSW) and tires 

Reclassifying MSW or tires as "fossil fuel-derived fuels" and including consumer plastics and other petroleum-derived MSW materials could have the potential to undermine the exemption of "solid waste incinerator units" from CAIR and the Acid Rain Program. EPA should correct them by restoring both the proposed definition of "fossil fuel" and the more appropriate subheading "alternative fuels" to encompass MSW and tires. Such a technical correction would have no impact on the reported GHG emissions from MWCs in light of the requirement that MWCs must apportion total CO2 emissions into biogenic and nonbiogenic fractions based on ASTM D-6866 analysis. The same quantities of biogenic and 

non-biogenic C02 emissions will be reported regardless of how the fuels are labeled. 

At least 1 

98.6 Definition of "Municipal solid waste or MSW" 

Is there some Q&A clarification on the definition of MSW? For example, does the MSW definition included wood, paper, etc. separated from municipal solid waste prior to landfilling? Would commercial or industrial cardboard/paper scrap be considered MSW, or could it be considered as one of the "biomass fuels - solid" in Table C-1 of Subpart C? 

At least 2 

98.6 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 fuels fired on a routine basis considered “primary” and only those as backup considered ‘secondary”? Or are primary, secondary, tertiary, etc., fuels determined on annual heat input? 

At least 2 
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98.6 Definition of "Waste Oil" 

We have a burner fueled by used oil in our mechanic shop. Under which C-1 fuel does used oil fall? If it is not listed in C-1, how do we calculate CO2? Do we have to sample quarterly for HHV? 

At least 2 

98.6 Definition of "Waste Oil" 

For a space heater (<250mmbtu/hr) that burns waste motor oil, would a Tier 1 calculation using the HHV of Residual fuel oil #6 from Table C-1 be acceptable? If not, what would be the applicable tier and approach? 

At least 2 

98.6 Definition of Natural Gas 

 The definitions in 98.6 define “Fuel gas means gas generated at a petroleum refinery, petrochemical plant, or similar industrial process unit, and that is combusted separately or in any combination with any type of gas”, which is followed by a similar but not identical definition of, “Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene.”  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 gas includes similarly constituted fuels such as field production gas, process gas, and fuel gas”. 

At least 1 

98.6 Definition of Natural Gas 

Are emissions from combustion of field gas reportable under Subpart C? Field gas refers to natural gas prior to processing to remove impurities and produce pipeline quality gas. In oil and gas production facilities, field gas may be used in various combustion 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 Subpart A: "...Natural gas may be field quality (which varies widely) or pipeline quality. For the purposes of this subpart, the definition of natural gas includes similarly constituted fuels such as field production gas, process gas, and fuel gas." However, Table C-1 in Subpart C does not include field gas; the only type of natural gas for which HHV and CO2 emission factor values are given is "Pipeline (Weighted U.S. 

Average)". Therefore it would appear that field gas combustions are not reportable under Subpart C, except in the highly unlikely event that a combustion unit is greater than 250 mmBtu/hr heat input (see highlighted path on attached flowchart). Is this correct? 

At least 2 
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98.6 Definitions of "Agricultural byproducts," "Solid byproducts," and "Wood residuals." 

In reading through the O2 CEMS option in §98.33(a)(4)(iv) it states that you must only 

burn fuel on Table 1 of 40 CFR 75 Appendix F 3.3.5. At one of our facilities we combust a 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 derived fuels, and also lists “wood (bark and wood residue)”. Would agricultural derived biomass as listed above be considered wood residue? 

At least 1 

Subpart A – General Provisions and Subpart NN – Suppliers of Natural Gas and Natural Gas L

98.2(a)(4) Threshold for natural gas local distribution companies 

Section 98.2(a)(4) provides that all natural gas LDCs, as GHG suppliers, are required to comply with the requirements of Part 98. The requirements are to report annually and to comply with related record-keeping, quality control and other mandates. The determination 

to apply all of the requirements of Part 98 to all LDCs should be reversed for each of the reasons discussed below. 1. First, the absence of an exemption for small LDCs is inconsistent with one of three principal goals for Part 98, which is to "balance the rule coverage to maximize the amount of emissions reported, while excluding small entities." 2. Second, the failure to provide an exemption for small LDCs is fundamentally inconsistent with a central provision of Part 98, which established a general minimum 

GHG threshold of 25,000 metric tons of C02e in order to exempt entities that would not materially contribute to GHG emissions. 3. Third, the failure to provide an exemption for LDCs affects this source category of GHG disproportionately and puts an unfair burden on LDCs that is not separately justified by the facts. 4. Fourth, the apparent rationale for not exempting small LDCs from the Rule is without merit. In the Proposed Rule, the EPA set forth statistics that clearly established that application of the minimum threshold to LDCs would eliminate less than 1% of GHG emissions from the Rule's coverage. The agency then found that the Rule would not require any LDC to collect information in addition to the information already collected and, therefore, concluded that no LDC should be exempted from the Rule. 

At least 1 
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5. Fifth, Part 98 includes a provision that will exempt any GHG source if it reports annual GHG emissions of less than 15,000 metric tons C02e for three consecutive years or 25,000 metric tons C02e for five consecutive years. Based on analysis of EIA Form 176 data for 2006, 75% of the 986 municipal LDCs - or 742 LDCs 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 for natural gas local distribution companies 

Our city owns and operates distribution pipelines that deliver natural gas to end users in the city. The point of measurement for natural gas supply is the city gate meter and the city does not make its own measurement. Every city gas customer has a gas meter installed, owned, and maintained by the city. The city receives significantly lower than 460,000 million 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 4 

98.6 Definition of "bulk natural gas liquid or NGL" 

The definition of “bulk natural gas liquid or NGL” in Section 98.6 “refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods at lease separators and field facilities.” However, these processes are not simple separation processes, but rather, NGL extraction processes that are typically performed at “gas plants” and not at “lease separators and field facilities.” 60 C.F.R. Subpart KKK defines “Natural gas processing plant” as “any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both.” This definition was changed from the proposed version to substitute “extraction” for “separation” because EPA intended to exclude facilities that removed liquid from field gas by means other than forced processes, such as gravity or natural condensation. Accordingly, EPA should strike the phrase “or other methods at lease separators and field facilities” from the definition of bulk natural gas liquid or NGL. 

At least 1 

98.6 Definition of Mscf 

In Subpart NN, Section 98.406(b)(7) LDC's are required to report the annual volume in Mscf of natural gas delivered to each meter registering supply equal to or greater than 460,000 Mcsf during the calendar year. In Subpart A "Mscf" is defined as "million standard cubic feet". I just want to verify that the requirement in Section 98.406(b)(7) only applies to meters where 460 BILLION standard cubic feet is delivered in a calendar year. This seems very high. 

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Subpart C – General Stationary Fuel Combustion Sources

98.30(d) Exclude GHG emissions from pilots from reporting 

Liquefied petroleum gas (LPG) is fired in some boilers at a facility in very small quantities exclusively for igniting the fuel oil burners. LPG is not fired at any other time, and annual heat input from LPG fuel therefore amounts to a minuscule fraction (less than one onehundredth of one percent) of annual heat input to the boilers. GHG emissions from firing the LPG during oil burner ignition accounts for less than one one-hundredth of one percent of total annual GHG emissions from fossil fuels, and on the order of less than 0.003 percent of total annual GHG emissions from all fuels (including biomass) at this facility. It would therefore seem appropriate to be able to exclude the insignificant emissions from this startup/ignition fuel from the annual GHG emissions calculations. 

At least 3 

98.33(a)(1) Add Eq C-1a for use when natural gas consumption is expressed in therms. 

Do "therms purchased" on a natural gas invoice constitute HHV data and thereby trigger Tier 2 reporting? If so, how can a company that purchases natural gas be sure that their vendor is measuring and reporting HHV per the requirements of Part 98? 

At least 3 

98.33(a)(1) Add Eq C-1a for use when natural gas consumption is expressed in therms. 

A fuel invoice is based on quantity consumed and therms. Because therms can be converted to MMBTUs and a monthly average HHV can be determined by dividing these numbers, are we required to use the Tier 2 methodology and does the natural gas need to be tested semi-annually per 98.34? 

At least 3 

98.33(a)(1) Table C-1. 

The “petroleum coke” listed in the Table C-1 of subpart C seems to be for a liquid fuel since the units for HHV are mmBtu/gallon. We are not aware that a petroleum coke is on the market that is in liquid phase. 

At least 10 

98.33(a)(1) Table C-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 10 

98.33(a)(1) Table C-1. 

Replace the HHV (which is based on the units for a liquid fuel) and CO2 emission factor 

for “Still Gas” in Table C-1 of subpart C with a HHV (for a gaseous fuel) and CO2 

emission factor for "Fuel gas." 

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98.33(a)(1) Table C-1. 

Amend Table C-1 of subpart c to remove "Pipeline" from the designation for “Natural Gas” to ensure that the default CO2 emission factor listed in Table C-1 applies to 

appropriate natural gas, consistent with the definition of “natural gas” in Section 98.6 of part 98. 

At least 10 

98.33(a)(1) Table C-1. 

For a space heater (<250mmbtu/hr) that burns waste motor oil, could a source use Tier 1 and the HHV and emission factor for "Residual fuel oil #6" from Table C-1 of subpart C to calculate CO2 emissions? If not, what would be the applicable tier and approach? 

At least 10 

98.33(a)(1) Table C-1. 

Pursuant to 40 CFR 98.33(b)(2)(iii), the Tier 2 calculation methodology may be used for calculating CO2 emissions from combustion of MSW, as Tier 4 is not required. Pursuant to 

40 CFR 98.33(a)(2)(i), units combusting MSW and producing steam are instructed to use Equation C-2c for calculating annual CO2 mass emissions. Equation C-2c contains 

variable EF, where EF = fuel-specific default CO2 emission factor, from Table C-1 of 

Subpart C. Table C-1 does list a default CO2 emission factor for Municipal Solid Waste. 

However, footnote 1 for Table C-1 indicates that the values/factors listed in Table C-1 for Municipal Solid Waste are allowed only for units that do not generate steam and use Tier 1. Therefore, it appears Subpart C, as currently written, provides no way for MSW units that produce steam to use Tier 2 to calculate annual CO2 mass emissions. 

At least 10 

98.33(a)(1) Table C-1. 

An ethanol production facility has combustion units that would be subject to the general stationary fuel combustion source category (subpart C) reporting requirements. All combustion units are <250 mmBtu/hr, and the facility has no CEMS that satisfy the Tier 4 requirements. Some process vapors containing ethanol are used as combustion air for a natural gas-fired process boiler. The ethanol in the vapors is combusted in the boiler. There is no method for determining the ethanol content in the vapor stream fed to the boiler. Although ethanol is listed in Table C-1, it is listed with the qualifier "(100%)" and as a liquid fuel. Because the ethanol concentration in the combustion air is unknown and 

the C-1 listing for ethanol specifies 100% ethanol, is the source required to report CO2 

emissions from combustion of the ethanol vapors? 

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98.33(a)(2)(ii) HHV weighting under Tier 2. Reporting for units sharing a common fuel pipe. 

Part 75 requires HHV sampling at least monthly in many cases, and many smaller fuel combustion sources at a facility subject to Subpart D in part 98 share a fuel source with a unit also subject to Part 75, Appendix D. Examples of combustion units sharing fuel supplies with Part 75, Appendix D sources, are comfort heating, hot water heating, and other combustion units. These units might otherwise qualify for Tier 1 monitoring, except that HHV data are available for these units that share a fuel source with a unit subject to Part 75. Are these smaller units also required to calculate a weighted average annual HHV under Tier 2 using equation C-2b, even for homogeneous fuels like natural gas or No.2 fuel oil? Requiring this calculation under Tier 2, and estimating the monthly fuel use for such insignificant activities would provide little benefit to the program. Moreover, because monthly fuel use is being determined solely by "company records of annual fuel use" any additional accuracy associated with calculating the average HHV is likely to be lost in the calculation. 

At least 1 

98.33(a)(3)(iv) Conditionally allow the use of mass-based gas flow meters. 

Many facilities use mass or volumetric flow meters to measure gaseous streams. Please confirm whether it is acceptable to use a mass flow meter to determine the volumetric flow rate of gaseous streams under Subpart C of part 98. 

At least 1 

98.33(a)(4) Address the emissions from an exhaust stream diverted from a CEMS monitored stack. 

A plant has a mill that use 6 to 8 percent of the exhaust volume from a kiln and then emits this kiln exhaust flow through a separate mill stack. The kiln stack will need to use a CO2 

CEMS, because it already has a CEMS installed to show compliances with state emission limits. However, the mill stack is not subject to any emission limit that would require a CEMS and does not have one installed. In 2011, can we estimate the mill stack flow rate as a percent of the total kiln gas flow rate (by engineering estimation or stack tests) and then estimate the CO2 emissions from the mill stack based on this percent and the measured CO2 in the kiln stack? 

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98.33(a)(4) and (a)(5) CEMS 

Many sources are subject only to a NOx trading program (NOx SIP Call or NOx-CAIR program) that requires reporting only during the ozone season (May 1 through September 30). These sources use either a CO2 (or O2) continuous monitor and a stack volumetric 

flow monitor, or a CO2 (or O2) continuous monitor along with Part 75 Appendix D fuel 

flow 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 use of Tier 4, but the CO2 emissions measurements will not cover the entire year. Section 

98.33(a)(5) discusses units that are not subject to the Acid Rain Program but use monitors under Part 75, which seems to apply to the sources in question, but the various subsections don't apply, as all scenarios assume that the source reports heat input year-round 

At least 2 

98.33(a)(4) and (a)(5) CEMS 

For CAIR-affected units that monitor SO2 and NOx emissions and Heat Input using the 

provisions of Part 75 Appendix D & E, but are not required to report CO2 mass emissions, 

may Part 75 Appendix G be used for CO2 reporting under Part 98? 

At least 1 

98.33(a)(4) Stack gas moisture content 

Under Part 98, we have to either measure moisture in the stack for mass flow correction (which we don't do), or use the default moisture correction factors. For the Bituminous coal we use the default correction is 6%, but the average is about 5% stack moisture when measured during the RATA. We use the average of those 3 runs for the moisture corrections until the next RATA. Instead of using multiple correction factors for different pollutants, can EPA approve the use of the same moisture numbers that are generated during the RATA? Because this is a Federal rule do we have to get permission from someone at EPA? If so, who would that be? 

At least 1 

98.33(a)(4)(iii) Allow the use of site-specific moisture constants. 

If the CO2 CEMS provides a reading on a dry basis, it is necessary to have a moisture 

content to calculate the mass rate emission (Equations C-6 and C-7)? If there is not a moisture sensor for the exhaust, Part 98 says use the default fuel moisture values per 75.11(b)(2) in part 75. These are not appropriate defaults for a cement plant. Cement plant moistures are higher than the default values due to other materials. Can we use the moisture measured during the CEMS RATA as a default for the year? 

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98.33(a)(5) Alternative methods for certain units subject to Part 75 of chapter 40. 

Can electric generating units that have fuel flow meters and currently calculate their CO2 

emissions using 40 CFR part 75 appendix G (which is reported to the State) report CO2 emissions using the alternative method for units with continuous monitoring systems, in section 98.33(a)(5), even if they are not subject to the Acid Rain Program and do not report data to EPA ? 

At least 3 

98.33(a)(5) Alternative methods for certain units subject to Part 75 of chapter 40. 

Subpart C does not clearly state that we can choose from Part 75, Part 60 or an applicable state program to administer the CEMs for compliance with Part 98. For instance, Part 98.34(c) gives us the option to use any of the 3 programs, however 98.35(a) says we are required to use Part 75 substitutions (...stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data in accordance with 40 CFR part 75, the missing data substitution procedures in 40 CFR part 75 shall be followed...). Additionally, 98.36(d) Units subject to 40 CFR part 75 does not apply because these units do report CO2 mass emissions year-round according to Part 75. 

At least 3 

98.33(a)(5)(iv) Clarify for biomass combustion in units with CEM 

If a CEMS is used on a unit combusting both fossil fuel and biomass, subpart C requires that volumes of CO2 be calculated for total CO2 and fossil fuel CO2 using equations C-12 

and C-13, where equation C-13 uses Fc-factors in scf of CO2/mmBtu from 40 CFR Part 75 Appendix F. We must also calculate the process CO2; however, that procedure using equation H-2 calculates a mass of CO2. Since the CEMS provides a mass of CO2, and equation H-2 provides a mass of CO2, can we calculate a mass of fossil fuel CO2 using the 

emission factors in Table C-1 or a site-specific CO2 emission factor in kg CO2/mmBtu? If 

we can do it using mass calculations would we be exempt from reporting CO2 volumes as 

required in 98.36(e)(2)(ix)? 

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98.33(b)(3)(iii) Clarify common pipe reporting under Tier 3 

We have multiple boilers in our steam generation unit, each of which has a heat input capacity greater than 250 mmBtu/hr. We used two fuels last year that accounted for less than 10% of the total heat input in the steam generation unit as a whole (not considering that the steam generation unit consists of multiple boilers that each had their own unique percentage for each type of fuel). One of those fuels accounted for 9% of the heat input. Is it correct that that we do not have to calculate and report CO2 emissions from that fuel? If 

next year our operations change and that fuel accounts for 11% of the total heat input; would that fuel have to be reported next year even if it is not included in this year’s emissions report? Should we be prepared to report CO2e emissions from any fuel type in any particular year that it accounts for more than 10% of the heat input, but at the same time not have to report for years that are under 10%? 

At least 2 

98.33(b)(3)(iii) Clarify the use of Tier 3 

A boiler less than 250 mmBtu/hr burns coal, woodwaste, and other process rejects from paper recycling/manufacturing. The unit also uses limestone injection. Since the process waste fuels are inconsistent and blended prior to burning, it is difficult to measure the amount of each fuel with acceptable accuracy. One option is to install as CO2 CEMS and 

report total emissions from the boiler using Tier 4. However, we would end up reporting emissions from fuels not listed in Table C-1. Because these waste fuel streams are less than 10% of the heat input, can we calculate emissions from coal, woodwaste, and limestone using Tier 1, even if these methods use inventory tracking such as pile inventory and company-established factors (i.e. % of wood chips purchased)? 

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98.33(b)(4) Clarify common stack reporting under Tier 4 

40 CFR 98.36(c)(2) states that units exhausting through a common stack where CEMS are used to monitor CO2 emissions at the common stack according to the Tier 4 Calculation 

methodology may report the combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG emissions from individual units. What if I have an auxiliary boiler exhausting through a common stack with coal fired boilers using a CEMS and reporting under "Alternative methods for units with continuous monitoring system" in 40 CFR 98.33(a)(5)(iii)? I'm not using the Tier 4 calculation methodology for the auxiliary boiler, but the auxiliary boiler is still exhausting through a common stack where CEMS are used. Am I still able to report under the common stack configuration? If the next year the coal fired boilers begin reporting under the Acid Rain Program and Subpart D, the same question applies: Am I still able to report under the common stack configuration? If not, will I need to subtract the auxiliary boiler GHG emissions out of the CEMS emissions totals and report them separately? That would be less accurate. 

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98.33(b)(4) Increase Tier 4 threshold for MSW combustion. 

The 250 tons MSW/day maximum rated input capacity as a criterion for use of Tier 4 is inequitable relative to the 250 mmBtu/hr maximum rated heat input capacity threshold that applies to other stationary combustion sources. An oil fired unit rated at 250 mmBtu/hr could emit 18,275 kg C02/hr, whereas an MWC rated at just over 250 tons MSW/day would emit only 3,331 kg C02/hr. EPA has argued that 250 tons MSW/day is a size determination for considering a large source in other EPA programs, and reflects consistency with other EPA programs, particularly where the challenge of monitoring is substantially different, as it is for MSW versus more homogenous fossil fuels. However, EPA has not explained how the 250 tons MSW/day threshold is relevant to monitoring of GHG emissions. EPA should establish either a "Tier 2-like" methodology or increase the threshold for Tier 4 for MSW combustion to be equivalent to the actual non-biogenic CO2 emissions equal to the 250 mmBtu/hr threshold for fossil fuel-fired units. This would be consistent with numerous programs and principles that EPA endorses. 

At least 1 

98.33(b)(5) Clarify the starting dates for the use of Tier 4 

According 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 CO2 mass emissions beginning on 

that date, if all of the monitors needed to measure CO2 mass emissions have been installed 

and certified by that date. (ii) January 1, 2011, for a unit that is required to report CO2 mass emissions beginning on 

January 1, 2010, if all of the monitors needed to measure CO2 mass emissions have not 

been installed and certified by January 1, 2010. In this case, you may use Tier 2 or Tier 3 to report GHG emissions for 2010. Is it correct to use Tier 4 for any portion of 2010 after an O2 CEMS is certified? For 

example, an O2 meter is certified on Feb 3, 2010. In the mean time the plant started the year 

with Tier 2 or 3 and then elects to begin (with a log note in the monitoring plan) using CEMS data for GHG reporting on March 1, 2010. Does this also apply to installations requiring use of Tier 4? 

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98.33(c) CH4 and N2O calculations. 

Should 40 CFR 98.33(c) be amended so that CH4 and N2O emissions are calculated using Eq C-9a, instead of Eq C-8, if Tier 3 is being used to calculate CO2 emissions? The 

equations are the same, but the definition of HHV in Eq. C-8 refers to HHV values in Table C-1, and in C-9a it refers to measured HHV values. 

At least 1 

98.33(c) CH4 and N2O calculations. 

For calculating CH4 emissions, the default ‘still gas’ heating value in Table C-1 is provided in units of MMBtu/gal. This is an error since these units imply that methane is a liquid when it is actually a gas in refinery processes. Part 98 goes on to specify Equation C–8 for estimating CH4 and N2O emissions for any fuels for which Tier 1 or Tier 3 methods are used for CO2, and also mandates the use of the default HHV values from Table C-1. In contrast, Equation C-9a permits the use of actual site HHV when using the Tier 2 method. This approach, and the erroneous HHV value, makes it impossible for 

refineries that use either Tier 1 or Tier 3 to use the default values in Table C-1. 

At least 1 

98.33(c) CH4 and N2O calculations. 

Although Part 98 limits reporting of CH4 and N20 to fuels combusted during "normal operation," Part 98 does not define "normal operation." In response to comments, EPA stated that "reporting of CH4 and N20 emissions is not required for fuels that are used exclusively 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 to be "normal operation," but EPA does not say that or refer to a specific rule. Moreover, it is not clear what other operating conditions or fuels EPA may have intended to exclude by reference to "normal operation." EPA should reconsider these new provisions in light of the provisions in Part 75 addressing combustion of multiple fuels and explain in Part 98 how sources are to treat startup fuel, and other operating conditions that EPA may not consider "normal." 

At least 2 

98.33(c) Remove duplicate table C2 for CH4 and N2O. 

Table C-2 has been printed twice in the final rule. Is this just an editorial error or was a third table accidentally left out? 

At least 2 

98.33(d) Clarify CO2 emissions 

from sorbent. 

Does Subpart C, 98.33(d)(1) reporting of CO2 from sorbent, apply to cement kilns using 

dry lime injection to control SO2 in stack gas? 

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98.33(d) Clarify CO2 emissions 

from sorbent. 

If a unit uses magnesium hydroxide for acid gas control (no CO2 emissions should be 

generated from this sorbent), can the unit use an O2 monitor in lieu of a CO2 monitor 

concentration measurement? (I.e. the Mg(OH)2 is not considered a source of process or 

sorbent CO2 emissions.) 

At least 1 

98.33(e) Clarify the calculation of emissions from biomass combustion when combined with other fuels. 

Did EPA intend for all biomass fuels to be subject to the 98.33(e) limitation, regardless of whether the unit fires biomass exclusively or a combination of fossil and biomass fuels (such that all biofuels not listed in Table C-1 would be exempt from CO2 calculation 

requirements, unless a CEMS is used)? 

At least 3 

98.33(e) Clarify biogenic CO2 emissions from biomass combustion 

40 CFR 98.33(e) discusses CO2 emissions from the combustion of biomass, and states "Use 

the procedures of this paragraph (e) to estimate biogenic CO2 emissions from units that 

combust a combination of biomass and fossil fuels. Reporting of CO2 emissions from 

combustion of biomass is required only for those biomass fuels listed in Table C-1 of this section, unless emissions are measured using CEMS." Table C-1 does not list Municipal Solid Waste as a biomass fuel, instead listing it as "Fossil fuel-derived fuel (solid)." In addition, if a unit does not measure CO2 emissions using CEMS, based on the cited 

language from 98.33(e), the unit is not required to calculate biogenic CO2 emissions from 

the combustion of MSW. 

At least 3 

98.33(e) Optional reporting of biogenic CO2 

Although EPA states in response to comments that Subpart D units that "choose" to report biogenic CO2 separately may calculate biogenic CO2 under § 98.33(e), RTC, Volume 16 at 

21, that option is not clearly reflected in §98.33(e), which makes no reference to Subpart D units? Moreover, §98.3(c) provides no option for not separately reporting biogenic CO2. 

At least 2 

98.34 Allow the use of consensus standard methods 

We 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. 

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98.34 Allow the use of consensus standard methods 

Subpart C, 98.34(a)(6) lists eight approved methods for fuel sampling and analysis to determine HHV for Tier 2 calculations. One of the methods listed is ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter. We currently use ASTM D240, but always use the most recent revision of any standard. ASTM D240 was revised on September 21, 2009 to ASTM D240-09. It is still required to use the older version of the standard, or is it assumed that when a standard is revised, the most recent version supersedes the one written in Part 98? 

At least 2 

98.34 Allow the use of consensus standard methods 

A facility burns coal. With each shipment received the coal company sends an analysis report. The source planned to use Tier 2 for stationary combustion unit reporting since HHV information is received with each shipment. An analysis recently received for coal that will be burned in 2010 references method ASTM D5865-04, not ASTM D5865-07a, as 

specified 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 version specified in Part 98? 

At least 2 

98.34(a)(2) Clarify the sampling frequency for coal and fuel oil 

The HHV and carbon content sampling and reporting in Part 98 are different from the fuel sampling requirements in Part 75, Appendix D. Part 98 may require additional (and sometimes duplicative) fuel sampling procedures for any Subpart C unit that shares a fuel supply with a unit that is monitoring and reporting under part 75, Appendix D. For example, Subpart C does not appear to authorize sampling from a fuel line or tank following the addition of a new shipment of fuel, whereas this is allowed in Part 75, Appendix D. As a result, the owner/operator of a Subpart C source that shares a fuel supply with a Part 75 source that has opted to use tank sampling would be required to obtain and use 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 1 

98.34(a)(2) Clarify the sampling frequency for coal and fuel oil 

A 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 or every other day). The coal comes from the same mine. Per 98.34(b)(3)(ii)(B), "For coal and fuel oil, analysis of at least one representative sample from each fuel lot is required. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.)." Does this mean that coal sampling has to be performed every day/every other day from the trucks? 

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98.34(a)(2) Clarify the sampling frequency for coal and fuel oil 

Does the EPA have any additional information on the meaning of "fuel lot" as used in Section 98.34(b)(3)(ii)(B)? (I can't find any on the web.) Must the fuel sample come from each and every "delivery" that comes to the reporting facility? If so, this could involve literally dozens of annual samplings, if fuel is delivered by tanker trucks, which may arrive multiple 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 multiple refineries, one of which ends up being the fuel that is actually "delivered" to the reporting entity? 

At least 5 

98.34(a)(3), (b)(1)(vi), and (b)(3)(v) for blended fuel combustion 

Under the final rule, there are no default emission factors for fuel mixtures. As a result, Tier 1 and 2 methods cannot be used to estimate combustion emissions from fuel mixtures. However, because CO2 emissions are based on the carbon content of fuel, multiplying the 

volume of each pre-mixed fuel by its respective fuel-based emission factor results in an accurate estimate of CO2 for the fuel mixture. 

At least 1 

98.34(a)(3), (b)(1)(vi), and (b)(3)(v) for blended fuel combustion 

Where the heat input capacity of a combustion unit is less than 250 mm Btu/hr input capacity and the unit is not subject to Tier 3 or 4 per Subpart Y of part 98, and where there might be more than one fuel type fed to the same combustion unit, can the Tier 2 method be used to calculate emissions by using measured HHV values of input streams or a measured HHV of the mixed stream? 

At least 3 

98.34(a)(3), (b)(1)(vi), and (b)(3)(v) for blended fuel combustion 

A source burns a mixed fuel stream that consists of ethylene process off-gas, other process off-gas, and natural gas. The fuel is a mixed stream and is subject to Tier 3 requirements for CO2 emissions. Calculations of CH4 and N2O appear to only be required for the fuels 

that are listed in Table C-2 of Part 98. Natural gas is listed in Table C-2, but the fuel mixture that is actually burned is not. Is the mixed fuel exempt from the requirement to calculate CH4 and N20 emissions at this time because emission factors don't exist? Or, do we need to estimate the fraction of the mixed fuel that is natural gas and then calculate CH4 and N2O emissions from the natural gas contribution to the overall mixture? 

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98.34(b) Clarify Tier 3 sampling frequency for gaseous fuels. 

As currently written, steelmaking units that combust blast furnace gas and/or coke oven gas are subject to two competing requirements. First, §98.34(b)(3)(ii)(C) requires sampling “once per calendar quarter” “for fossil fuel-derived gaseous fuels.” Since blast furnace 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 and biogas,” which (perhaps inadvertently) also appears to include fossil fuel-derived gaseous fuels like blast furnace gas and coke oven gas. EPA should clarify that Tier 3 blast furnace gas and coke oven gas sampling frequency is governed 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 the following technical clarification to §98.34(b)(3)(ii)(E): (E) For gaseous fuels other than natural gas, fossil fuel-derived gaseous fuels listed in Table C-1 and biogas (e.g., refinery gas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if the necessary equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed. Quarterly sampling is appropriate to determine and report CO2 emissions from coke oven 

gas and blast furnace gas combustion given the relatively narrow and defined ranges of variation expected. Confirming a quarterly approach is also consistent with EPA’s related decision to reduce the reporting burden by allowing Tier 1 or Tier 2 treatment via the creation of default emissions factor for blast furnace gas and coke oven gas. 

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98.34(b)(3)(ii)(E) Clarify sampling frequency for gaseous fuel. 

Regarding refinery fuel gas sampling frequency and method. 98.34(b)(3)(ii)(E) addresses fuel sampling and states “For gaseous fuels other than natural gas and biogas (e.g., refinery gas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if the necessary equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed”. What constitutes “necessary equipment” that would mandate “daily sampling and analysis”? Does this mean a continuous on-line gas chromatograph or does it also include hand drawn samples analyzed in a lab? Section 98.34(b)(3)(ii)(E) is not in agreement with the preamble for the final part 98 which states “The minimum monitoring frequency for refinery fuel gas carbon content and molecular weight was changed to weekly from daily in 40 CFR part 98, subpart C, for reporters that do not have continuous monitoring equipment”. Please clarify refinery fuel gas monitoring frequency requirements. 

At least 1 

98.34(c) for moisture monitor certification 

Cement production facilities often have CEMS that are subject to State and Part 60 regulations. Facilities have or will be installing CO2 CEMS on their kiln stacks in order to 

report under Part 98. One facility's CEMS has a moisture monitor (O2 wet and O2 dry 

system) and reports emissions on a dry basis. If all other CEMS (flow and CO2) at this facility can be certified under State or Part 60 guidelines for Part 98, does the certification of the moisture system (O2 wet and O2 dry) need to be certified under Part 75 regulations, 

which would require the facility to order different O2 calibration gases in order to meet 

with Linearity requirements of Part 75? Also, can this facility certify each individual CEM under different guidelines, or does one specific regulation (Part 60 or Part 75) apply to all CEMS utilized in the reporting of emissions under Part 98? 

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98.36(c)(3) for common pipe reporting option 

Under the recordkeeping portion of subpart A of part 98, you must retain a list (record) of all units, operations, processes, and activities for which GHG emission were calculated, in addition to those records prescribed in each applicable subpart of part 98. Scenario: A facility is subject to part 98 but only as a stationary fuel combustion source subject to subpart C. The facility uses natural gas and has one natural gas line entering the facility that is used to fuel four separate boilers. The facility will be depending on utility bills for the total quantity of natural gas used during 2010, from which it can then calculate CO2-e emissions, CO2 emissions, N2O emissions, and CH4 emissions. 

Based upon the language noted from subpart A, does the facility need to maintain a list of all the individual combustion units (in this case, the boilers) for which GHG emissions were calculated? This does not seem necessary because GHG emissions were not calculated at the unit level; the facility was really only calculating one emissions number based upon natural gas intake through one pipe. Though this particular example seems simple, there could be other cases where fuel could be coming in through one pipe but could be used in many different units. This could require an exhaustive inventory-taking process of hundreds of small combustion units such as lab Bunsen burners, cafeteria equipment, and other small operations and processes, but the facility is still only calculating the emissions based upon the quantity of fuel taken in at that 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 GHG emissions are being calculated based upon a single fuel intake line, and fuel intake is calculated based on fuel vendor invoices/bills, or vendors external meter readings, instead of based on flowmeters or any individual fuel measurements on an individual unit, process, or activity level. 

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98.36(c)(3) for common pipe reporting option 

Part 98 allows for the common reporting and monitoring of fuel for equipment: "When two or more liquid-fired or gaseous-fired stationary combustion units at a facility combust the same type of fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions from the units...provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter that is calibrated 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 of the HHV of the fuel. 98.34(b) provides the calibration and maintenance requirements for fuel flow meters. Can the common supply pipe provisions still be utilized as long as the flow meters meet the requirements of 98.34(b)? Is this issue being addressed? 

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98.36(c)(3) for common pipe reporting option 

If a facility wishes to use the "Common Pipe" reporting alternative, but some of the fuel monitored by a common flow meter may be occasionally flared, is it acceptable to include the flared gas in the total fuel consumption? 

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98.36(c)(4) for combinations of large and small combustion units 

Sources that are subject to Part 98 due to combusting more than the trigger threshold of natural gas (determined using a common billing meter) may have some large quantity users and small quantity users. The sources we are looking at are institutional (schools/universities) and industrial (manufacturing). These sources will be required to develop 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 equipment uses (e.g. stoves, ovens, space heaters, process heaters, Bunsen burners, etc.)? The EPA's FAQ web-site indicates there is NO de minimis level to exempt reporting for sources. Do the smaller sources need to be included on the equipment inventory found in the Monitoring Plan? Is it acceptable to list out the 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 or process operations to use. These labs do not meet the definition of R&D so they are not exempt from reporting. These facilities can have a multitude of small quantity sources such as space/door heaters, Bunsen burners, muffle ovens, process ovens, etc., that use natural gas. The natural gas use cannot be separated out, as a common meter is used. How should this type of equipment be addressed in the equipment inventory? Is it acceptable to generalize "various natural gas combustion equipment with a heat input capacity less than XX BTU/hr"? Is it acceptable to use the CO2 emission factor found in Part 98 for all 

general pipeline quality natural gas combustion at the site regardless of equipment size? Also, universities and other institutions have residential housing units that are part of their campus. These units can use gas for heating or cooking. They are part of the institution's campus so are not considered residential and must be included in the report. Usage comes from a common meter. Is it OK to report "a variety of kitchen stoves/ovens less than XX BTU/hr heat input" in the inventory? 

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98.36(e)(2)(iii) HHV values obtained from fuel 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 the facility by the same natural gas line. On the monthly gas bills, the gas supplier provides a HHV for the gas for that month. This HHV is an average value for multiple stations monitored each month around the city. The station nearest the facility is only sampled every 3-4 months. The gas supplier does not provide the information specified in Part 98 for HHV measured values, such as the test method used and the date of the test. Can the facility use the HHV provided each month to calculate the emissions following the Tier 2 requirements and not maintain the other information about the tests, or does the facility need to obtain from the supplier the test method used, date of the test, etc.? 

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Subpart D – Electricity Generation

98.46 Data Reporting 

Should section 98.46 , "Data Reporting Requirements" under Subpart D, reference section 98.36(d) instead of section 98.36(b)? Section 98.36(b) applies to units that use the four tiers, which is not applicable to units that are subject to Subpart D. Section 98.36(d) applies to units that are subject to 40 CFR part 75, which would apply to units that are subject to Subpart D. 

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Subpart X – Petrochemical Production

98.243(d) Add default HHV in Table C-1 and allow the use of site specific HHV 

40 CFR 98.243(d) requires that 98.33(c) be used to calculate CH4 and N2O from combustion 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. Since there is not a default HHV for ethylene process off-gas in Table C-1, must facilities complying with Subpart X via the ethylene combustion methodology determine a sitespecific HHV for ethylene process off-gas? If so, what calibration and missing data procedures apply? 

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98.243(d) Add the methodology for small ethylene off-gas streams 

Can Part 98 include an alternative to installing fuel flow meters for calculating CO2 

emissions, etc., for very low flow natural gas users, such as catalytic thermal oxidizers that handle vents from storage tanks? 

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98.244(b)(4) Amend carbon content determination method specifications 

Subpart 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 CFR 98.34(b)(5), Tier 3). Why does the mass balance method under Subpart X (40 CFR 98.243(c)(3)) require that only specific methods as specified at 40 CFR 98.244(b)(4) be used for the determination of carbon content of feedstocks and products? Why does Subpart X not allow the use of a calibrated gas chromatograph for the determination of carbon content from petrochemical feedstocks and products? 

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98.244(b)(4) Amend carbon content determination method specifications 

The test methods outlined in 40 CFR 98.244(b)(4)(i) through 98.244(b)(4)(x) were not specifically developed for the analysis of carbon content in carbon black. Of all the methods noted in the regulation, method ASTM 5291 would be the closest to being appropriate for carbon black. However, this method was designed for carbon content in the 75% - 87% range, while the carbon content of carbon black is in excess of 97%. In order to use this method for the intended purpose, slight modifications will have to be made to ASTM 5291 to accommodate the higher carbon content to ensure the needed accuracy. Please note that modifications to this method have been accepted under other GHG regulatory systems, such as the European Union Emission Trading Scheme. The carbon black industry proposes to implement these modifications to the ASTM test method to meet the requirements of Part 98. We suggest that the agency revise Part 98 to clarify that it has the authority to approve methods and modifications to methods that would be better or more appropriate than those specified in 40 CFR 98.244(b). 

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98.244(b)(4) Amend carbon content determination method specifications 

The following test method should be incorporated by reference at 40 CFR 98.7(e) and 40 CFR 98.244(b)(4): ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography 

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Subpart X – Petrochemical Production and Subpart Y – Petroleum Refineries
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98.243 and 98.253 - alternative standard conditions 

The proposed Part 98 defined “standard conditions” in accordance with the prevalent 

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

comments on the proposed Part 98, we noted a discrepancy between the stated standard conditions and the “molar volume conversion” factor provided in the equations for calculating emissions from gaseous fuels. However, instead of providing several “molar volume conversion” factors that could be used by reporters under different temperature and pressure conditions, the final 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 lead to erroneous emission calculations. EPA should adopt the approach where a short list of “molar volume conversion” factors are provided for different temperature and pressure conditions and instruct reporters to use the appropriate one for their measurement method for quantifying GHG emissions. 

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Subpart Y – Petroleum Refineries

98.252(a) Add the methodology for combustion of fuel gas in small units 

 By invoking the use of Equation C-5 (Tier 3 method in subpart C) or Tier 4 method, Part 98 precludes smaller refinery combustion units (< 250 MMBtu/hr) that are combusting refinery fuel gas (still gas) from using either Tier 1 or Tier 2 methods with the default CO2 

emission factor. Due to the inconsistency between subparts Y and C on this topic, EPA should correct the text in 98.252(a) to reflect its intent - as provided in the preamble - and allow refineries access to all the calculation methods (tiers) as outlined in subpart C, as applicable. 

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98.252(a) Add the methodology for combustion of fuel gas in small units 

EPA should explicitly allow the use of Tier 1 and Tier 2 methodology with applicable default emission factors to reduce the reporting burden for small stationary combustion units, including ‘pilots’ on heaters and flares. This would prevent the need to install flow meters on all “pilots” which will be quite costly and absolutely unnecessary considering the insignificance of their emissions. 

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98.252(a) Add the methodology for combustion of fuel gas in small units 

Can Part 98 include an alternative to installing fuel flow meters for calculating CO2 

emissions, etc., for very low flow natural gas users, such as catalytic thermal oxidizers that handle vents from storage tanks? 

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98.252(a) Add the methodology for combustion of fuel gas in small units 

If a source has storage tank vents routed to on-site incinerators for vapor destruction, could Part 98 have an alternative to installing fuel flow on the storage tank vents for calculating CO2 emissions, etc.? 

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98.252(a) Allow use of same Tier from subpart C for CH4 and N2O as for CO2. 

Due to the inconsistency between subparts Y and C on this topic, EPA should amend 98.252(a) to allow refineries to use all the calculation methods (tiers) as outlined in subpart C, that are applicable for calculating CO2, CH4, and N2O emissions. 

At least 1 

98.252(a) Clarify the required emissions methods for flares 

98.253(a) & (b) contradict themselves and 98.252(a). Section 98.252(a) says to use Subpart C 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 flare emissions be calculated following subpart Y or C? 

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98.253(e) Amend CBQ definition in 

Equation Y-11 

Equation Y-11 calls for the number of regeneration cycles and the coke burn off per regeneration cycle, for calculating CO2 emissions from the catalytic reforming unit catalyst 

regenerator. However, some units are not operated with regeneration cycles. Can sources alter this equation to more accurately calculate emissions based on actual operations? 

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98.253(i)(1) Calibration Requirements 

In regards to Equation Y-18 Subpart Y section 98.253(i)(1): The variable Pcv is defined as the "gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the alternative method provided in paragraph (i)(2) of this section is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere (pounds per square inch gauge, psig)." If a pressure gauge is used to determine 

Pcv, does the gauge have to be calibrated? Section 98.254 (Monitoring and QA/QC requirements) 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 data used 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 data used to calculate GHG emissions, it must be calibrated. However, no methods are provided for calibration and no recalibration requirements are discussed in Subpart Y. Please clarify whether a pressure gauge must be calibrated. 

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98.253(n) Clarify the requirements for loading operations 

What test method is USEPA recommending or requiring for analysis of vapor-phase methane composition as specified in 98.253(n)? None is mentioned in 98.253(n), and none of the methods in 40 CFR 98.7, listing the standardized methods adopted by reference, are specific to identification of vapor-phrase methane composition. 

At least 1 

98.254(b) Clarify the calibration requirements 

When Part 98 says facilities must re-calibrate flow meters either "biennially or at the minimum 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, then the 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 they can recalibrate once every three years? Or do they have to re-calibrate after 2 years because 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 assume that a source can do it every 3 years, if that is specified by the manufacturer, and still be in compliance? Are they still in compliance if the recommended frequency from the 

manufacturer is every 10 years? 

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Subpart AA – Pulp and Paper Manufacturing
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98.273 and 98.33 Used oil combustion 

 Pursuant to 98.273(a)(1), CO2 emissions resulting from the fossil fuels burned in recovery 

furnaces and lime kilns are to be determined using “direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in 98.33(a)(1).” 98.273(c)(1) and (c)(2) require that default emission factors from Table AA-2 be used in the GHG calculations for lime kilns. Used oil is considered a listed fuel (“other oil”) in Table 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 for used oil burned in lime kilns? 

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98.273 and Calibration 98.3(i) 

Pursuant to 98.273(a)(1), CO2 emissions resulting from the fossil fuels burned in recovery 

furnaces and lime kilns are to be determined using “direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in 98.33(a)(1).” Given that Tier 1 is to be used to calculate CO2 emissions from recovery furnaces/lime 

kilns and that no calibrations are required for Tier 1, can you confirm that the fuel flow meters used to measure the amount of fossil fuel going to recovery furnaces and lime kilns do not have to meet the calibration requirements in 98.3? 

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98.273 and 98.33(b)(2) Tier 1 vs. Tier 2 

Pursuant to 98.273(a)(1), CO2 emissions resulting from the fossil fuels burned in recovery 

furnaces and lime kilns are to be determined using “direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in 98.33(a)(1).” If a mill obtains the HHV or carbon content of the fossil fuels burned in its recovery furnaces or lime kilns in accordance with the minimum frequency specified under Tier 2 or Tier 3 of Subpart C, can it use the Tier 2 or Tier 3 methodology to determine the CO2 

emissions from its recovery furnaces instead of the Tier 1 methodology? If so, can a mill use the annual average HHV from the sampling and analysis instead of the default HHV in the GHG emission calculations if it obtains the HHV of the fossil fuels in accordance with 

the minimum frequency specified in Part 98? 

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Subpart OO – Suppliers of Industrial Greenhouse Gases
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98.410 Subpart L versus Subpart OO reporting requirements 

Subpart OO may conflict with the reserved Subpart L applicability provisions. EPA should clearly state that Subpart OO does not apply to production, only to HFCs packaged for market. 

At least 1 

98.410 Subpart L versus Subpart OO reporting requirements 

EPA should delete §§98.416(a)(8) and (a)(9). These elements are associated with Subpart O or reserved Subpart L. These production-related provisions are unrelated to HFCs in commerce. 

At least 1 

98.414 Clarification of terms 

EPA needs to clarify the definition of destruction and emission. At least 1 

Subpart PP - Suppliers of Carbon Dioxide

98.423(a)(1), (a)(2), and (b) Definition of "purification, processing or compressing" 

The carbon dioxide (CO2) supplier source category under Subpart PP of the GHG MRR consists of facilities with production process units that capture a CO2 stream for purposes 

of supplying CO2 for commercial applications. Capture refers to the initial separation and 

removal of CO2 from a manufacturing process or any other process (40 CFR 98.420(a)(1)). 

Subpart PP requires that the amount of CO2 captured, prior to any subsequent purification, 

processing, or compressing, be monitored using a mass or volumetric flow meter (40 CFR 98.423(a)). EPA should clarify the description given in Subpart PP for the location of a flow meter prior to any subsequent purification, processing, or compressing. Some plants that produce ammonia also produce carbon dioxide only as a byproduct of the process. The disposition of the CO2 extracted from the synthesis gas is incidental to the 

ammonia plant operations, and the design of the ammonia plant is not to capture CO2 for 

the purposes of supplying CO2 for commercial applications. 

As the initial gas stream containing ammonia and CO2 is a two-phase flow, an acceptable 

technology for accurately monitoring the two-phase flow is not available. Thus, a CO2 flow 

measurement may not be technically feasible or accurate at the location required by a literal interpretation of this regulation. In addition, CO2 later captured from this stream 

could be used on-site for noncommercial applications, commercial applications, and 

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vented. 40 CFR 98.420(b)(5) specifically exempts "on-site use of CO2 captured on site" 

from reporting. Therefore, a literal interpretation of Part 98 could require the installation of a monitoring system that drastically over-estimates the amount of CO2 supplied and does 

not satisfy the intent of Part 98 (to report the amount of CO2 supplied for commercial 

applications). Thus the question is, would initial cooling of a gas stream containing ammonia and CO2, for the purpose of condensing and removing water, be considered "purification" under Part 98, even if a portion of the CO2 captured further downstream is for on-site noncommercial 

use? Or does the statement "prior to purification, processing or compressing" apply only to steps involved for the purpose of supplying CO2 for commercial sale? Clarification of the 

flow meter's location is critical to a facility with applications for CO2 that are both 

noncommercial and commercial. Thus, clarification is needed for the meaning of "purification, processing or compressing" under this rule. Some facilities further process the CO2 gas (cooling, drying, and compression) to improve 

quality of the gas for commercial sale. Prior to the noncommercial and commercial applications, and even at this time, CO2 is routinely vented rather than entered into one of 

these applications. In order to accurately report the amount of CO2 supplied for commercial applications, we 

recommend the amount of CO2 supplied for commercial applications be measured using 

truck and rail weigh scales to determine the mass of CO2 sold (i.e. weighing the truck or 

rail car in which CO2 is shipped off-site before and after loading). Truck and weigh scales 

are often calibrated and annually certified for accuracy. In addition, measuring the CO2 

using weigh scales is consistent with how the mass of CO2 imported or exported is 

measured under 40 CFR 98.423(b). 
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98.423(a)(1), (a)(2), and (b) Definition of "purification, processing or compressing" 

EPA should clarify the applicability of Part 98 as it relates to CO2 producers. Would a CO2 

production plant that takes a CO2-rich waste stream from a different plant, then purifies and compresses the CO2, which is then sold, need to report their GHG emissions according to Part 98? Per 40 CFR Part 98, Subpart A, section 98.2(a)(4)(v)(A) indicates that carbon dioxide suppliers including all producers of CO2 are required to report their GHG 

emissions. In addition, Subpart PP, section 98.420(a)(1) defines suppliers of CO2 as 

"Facilities with production process units that capture a CO2 stream for purposes of 

supplying CO2 for commercial applications... Capture refers to the initial separation and 

removal of CO2 from a manufacturing process or any other process". However, section 

98.420(b) indicates that Part 98 does not cover purification, compression, or processing of CO2. Would a facility that does both initial separation of CO2 and purification of CO2 need 

to report its emissions? 

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98.423(b) CO2 supplied in containers 

I am working with an ethanol facility that will fall under the applicability of Subpart PP "Suppliers of Carbon Dioxide". They ship CO2 off site in containers (dry ice and liquid 

CO2 in trucks). They use a scale and weigh bills to track CO2 production and shipments. 

They do not transfer CO2 gas offsite nor do they export CO2 in containers. 

As an alternative to installing expensive CO2 mass flow meters, can facility measure the 

annual CO2 mass using the existing scale and weigh bill approach for their shipments (as 

allowed under (a)(3) for importers and exporters), or must they install flow meters? If a facility is already weighing the CO2 in containers (even if they are not exporting) 

shouldn't the scale weigh bill approach be allowed? 

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98.424(a)(5) - Default value for CO2 density 

Several sources are concerned with a particular requirement of Subpart PP – Suppliers of Carbon Dioxide. Most of these sources operate volumetric flow meters and are required to 

use equation PP-2 of Subpart PP to calculate quarterly the mass of CO2 in their CO2 stream. 

Equation PP-2 requires the measurement of the density of the CO2 stream on a quarterly 

basis. In Section 98.424 of Part 98 (Monitoring and QA/QC requirements of Subpart PP) several ambiguous methods to complete the density measurements are listed such as “You shall use an appropriate standard method published by a consensus-based standards organization to measure density if such method exists.” The other option is “Where no appropriate 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 CO2 stream is estimated to cost as 

much as $15,000 per year based on 3rd party bids. Does the EPA have further recommendations, additional information on acceptable methods, or feedback on how others are measuring the density of their CO2 streams? As an example, it is possible to 

measure the density of the CO2 stream by monitoring the temperature and pressure of the 

stream. The temperature and pressure would be used as inputs to the ideal gas law (PV=nRT) allowing a calculation of the density of the CO2 stream to be made. Can EPA 

provide feedback on the acceptability of this method or others that are available? 

At least 1 

98.424(b)(2) reference correction 

In regards to Subpart PP - Suppliers of CO2, EPA has referenced examples of acceptable methods for determining the composition of the CO2 stream. One of the acceptable 

methods noted includes "U.S. Food and Drug Administration food-grade specifications for CO2 (see 21 CFR 184.1250)..." This specific citation refers to "Cellulase enzyme 

preparation derived from Trichoderma longibrachiatum," and makes no mention of CO2. CO2 is referenced under 21 CFR 184.1240 as a compound that is generally recognized as 

safe (GRAS); however, this citation (184.1240) does not provide any analytical methods for determining the CO2 gas composition. Please provide clarification on the specific 

methods EPA is referencing when it refers to "see 21 CFR 184.1250." 

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