1 

Mandatory Greenhouse Gas 

Reporting Rule: EPA's Response 

to Public Comments 

Revision of Certain Provisions of the 

Mandatory Reporting of Greenhouse 

Gases Rule 
2 

November 2010 

Revision of Certain Provisions of the 

Mandatory Reporting of Greenhouse Gases 

Rule 

U. S. Environmental Protection Agency 

Office of Atmospheric Programs 

Climate Change Division 

Washington, D.C. 
iii 

FOREWORD 

This document provides EPA’s responses to public comments on EPA’s Proposed Revision of 

Certain Provisions of the Mandatory Reporting of Greenhouse Gases Rule. EPA published a 

Notice of Proposed Rulemaking in the Federal Register on August 11, 2010 (75 FR 48744). 

EPA received comments on this proposed rule via one or more of the following methods: 

regulations.gov, e-mail, fax, mail or courier. Copies of all comments submitted are available at 

the EPA Docket Center Public Reading Room. Comment letters are also available electronically 

through http://www.regulations.gov by searching Docket ID EPA-HQ-OAR-2008-0508. 

This Response to Comments document provides the verbatim text of comments extracted from the 

original comment letter. For each comment, the name and affiliation of the commenter, the document 

control number (DCN) assigned to the comment letter, and the number of the comment excerpt is 

provided. 

EPA’s responses to comments are generally provided immediately following each comment excerpt. 

However, in instances where several commenters raised similar or related issues, EPA has grouped 

these comments together and provided a single response after the first comment excerpt in the group 

and referenced this response in the other comment excerpts. In some cases, EPA provided responses 

to specific comments or groups of similar comments in the preamble to the final rulemaking. Rather 

than repeating those responses in this document, EPA has referenced the preamble. 

While every effort was made to include the significant comments related to the selection of source 

categories to report and the level of reporting in this volume, some comments inevitably overlap 

multiple subject areas. For comments that overlapped two or more subject areas, EPA assigned the 

comment to a single subject category based on an assessment of the principle subject of the 

comment. For this reason, EPA encourages the public to read all sections of this document with 

subject areas that may be relevant to the reader’s subpart(s) of interest. 

The primary contact regarding questions or comments on this document is: 

Carole Cook (202) 343-9263 

U.S. Environmental Protection Agency 

Office of Atmospheric Programs 

Climate Change Division 

Mail Code 6207-J 

1200 Pennsylvania Avenue, NW 

Washington, D.C. 20460 

ghgreportingrule@epa.gov
iv 
v 

TABLE OF CONTENTS 

Section Page

1. HOW THESE AMENDMENTS APPLY TO 2011 GHG EMISSION REPORTS...........1

2. SUBPART A – GENERAL PROVISIONS ........................................................................8

Applicability threshold for natural gas LDCs......................................................................8 

Content of annual report- separate biogenic CO2 emissions reporting ...............................11 

Content of annual report- other amendments ....................................................................41 

Recordkeeping .................................................................................................................41 

Revisions to the annual GHG report .................................................................................47 

Calibration and accuracy requirements.............................................................................56 

Measurement device installation.......................................................................................74 

Definition of agricultural byproducts................................................................................82 

Definition of municipal solid waste (MSW)......................................................................83 

Definition of natural gas...................................................................................................90 

Definition of waste oil......................................................................................................91 

Definition of wood residuals.............................................................................................93 

Other definitions...............................................................................................................95 

Standardized methods incorporated by reference ............................................................ 101 

Other Subpart A comments............................................................................................. 103 

3. SUBPART C – GENERAL STATIONARY FUEL COMBUSTION............................ 108

Definition of source category.......................................................................................... 108 

Tier 1 Calculation Methodology..................................................................................... 109 

Tier 2 Calculation Methodology..................................................................................... 113 

Tier 4 Calculation Methodology..................................................................................... 122 

Tier 1 Applicability ........................................................................................................ 128 

Tier 2 Applicability ........................................................................................................ 129 

Tier 3 Applicability ........................................................................................................ 130 

Tier 4 Applicability ........................................................................................................ 132 

CH4 and N2O emissions.................................................................................................. 138 

Biogenic CO2 emissions................................................................................................. 140 

Monitoring and QA/QC requirements............................................................................. 152 

4. SUBPART D - ELECTRICITY GENERATION .......................................................... 194

5. SUBPART F - ALUMINUM PRODUCTION ............................................................... 195

Other Subpart F Comments............................................................................................ 195 

6. SUBPART G - AMMONIA MANUFACTURING ........................................................ 195

Purge Gas/Recycle Stream ............................................................................................. 195 

Proposed Deletion of Synthetic Fertilizer Reporting ....................................................... 196 

Other Subpart G Comments............................................................................................ 200 

7. SUBPART P - HYDROGEN PRODUCTION ............................................................... 201

Oil and Gas Flow Meter Calibration ............................................................................... 201 

Other Subpart P Comments............................................................................................ 202 
TABLE OF CONTENTS 

Section Page

vi 

8. SUBPART V - NITRIC ACID PRODUCTION............................................................. 203

9. SUBPART X: PETROCHEMICAL PRODUCTION................................................... 203

GHGS to Report............................................................................................................. 203 

Calculating CH4 and N2O emissions for Ethylene Only Options..................................... 205 

Equation X-1.................................................................................................................. 205 

Monitoring and QA/QC Requirements ........................................................................... 208 

Data Reporting Requirements......................................................................................... 215 

Other Subpart X Comments............................................................................................ 216 

10. SUBPART Y- PETROLEUM REFINERIES ................................................................ 218

GHGs to report............................................................................................................... 218 

Reporting Emissions From Flares................................................................................... 220 

Sulfur Recovery: Sour Gas Sent Offsite.......................................................................... 221 

CO2 Emissions From Asphalt Blowing........................................................................... 222 

Other Equations.............................................................................................................. 223 

Calculating GHG Emissions........................................................................................... 225 

Monitoring and QA/QC Requirements ........................................................................... 227 

Other Subpart Y Comments............................................................................................ 230 

11. SUBPART AA - PULP AND PAPER MANUFACTURING......................................... 235

12. SUBPART NN - SUPPLIERS OF NATURAL GAS AND NATURAL GAS LIQUIDS235

13. SUBPART OO - SUPPLIERS OF INDUSTRIAL GREENHOUSE GASES ............... 235

Monitoring and QA/QC Requirements ........................................................................... 235 

Definitions ..................................................................................................................... 238 

Other Subpart OO Comments......................................................................................... 238 

14. SUBPART PP - SUPPLIERS OF CARBON DIOXIDE................................................ 240

Calculating CO2 Supply.................................................................................................. 240 

Equation PP-1 ................................................................................................................ 240 

Equation PP-2 ................................................................................................................ 240 

Other Subpart PP Comments.......................................................................................... 245 

15. COMMENTS ON ADMINISTRATIVE PROCEDURES (E.G., COMMENT PERIOD)246

16. COMMENTS ON LEGAL AUTHORITY FOR THE AMENDMENTS ..................... 247

17. GENERAL SUPPORT AND OPPOSITION FOR THE AMENDMENTS.................. 248

General Support for the Amendments............................................................................. 248 

General Opposition To The Amendments....................................................................... 250 

18. COMMENTS ON PART 98 ISSUES THAT WERE COVERED BY THE FIRST PART 

98 CORRECTIONS NOTICE........................................................................................ 252

19. GENERAL OUT OF SCOPE COMMENTS ................................................................. 254
1 

1. HOW THESE AMENDMENTS APPLY TO 2011 GHG EMISSION 

REPORTS 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 7 

Comment: EPA required that sources have GHG Monitoring Plans in place by March 31, 2010. 

Many of these revisions will need to be incorporated into the existing plans, including: (1) 

Documenting the method(s) used to determine the HHV for Tier 2 fuels; (2) Documenting the 

method(s) used to calibrate Tier 3 fuel flow meters; (3) Documenting the method(s) used to 

determine the carbon content and molecular weight of Tier 3 gas fuels; and, (4) Preparing a 

monitoring plan for a new Tier 1 fuel due to the addition of “Fuel Gas” to Table C-1. EPA 

should provide additional time, until at least March 31, 2011, for the owner/operators to revise 

the GHG Monitoring Plan upon the finalization of these proposed MRR revisions. 

Response: It is not necessary to impose a specific deadline, for example March 31, 2011, to 

revise the GHG Monitoring Plan to reflect the amendments to the GHG Reporting Rule because 

40 CFR 98.3(g)(5)(iii) of the 2009 final rule already has a requirement to revise the GHG 

Monitoring Plan, as needed, to reflect changes in production processes, monitoring 

instrumentation, and quality assurance procedures, among other process changes. We do not see 

any unique circumstances that would necessitate applying a specific date by which these 

amendments need to be reflected in the monitoring plan. We would refer to the 2009 final 

preamble (74 FR 56281), which states, “Reporters need their monitoring plan to be up to date in 

order to ensure that facility or supplier personnel follow the right monitoring and QA procedures 

and that the reporter meets the requirements of the reporting rule. Likewise, EPA needs to be 

able to view an up-to-date monitoring plan during facility audits.”

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 1 

Comment: EPA seeks comment on the conclusion that it is appropriate to implement these 

amendments and incorporate the requirements in the data reported to EPA by March 31, 2011. 

Further, EPA seeks comment on whether there are specific subparts of Part 98 for which this 

timeline may not be feasible or appropriate due to the nature of the proposed changes or the way 

in which data have been collected thus far in 2010. 
2 

Given the nature of these amendments and objections [August 19, 2010 letter from the Clean Air 

Task Force, Natural Resources Defense Council, and Sierra Club.] raised to some of the 

amendments that result from the proposed GHGRP settlement agreements from 75 FR 42085 

(July 20, 2010), companies do not know what the final amendments will contain, and thus can 

not take action to implement the provisions until the final rule is published. 

Companies impacted by the GHGRP are currently nine months into the reporting period, with 

reporting required by March 31, 2011. Companies have been preparing for reporting under the 

GHGRP since the initial rule was proposed in April 2009. Currently GPA member companies 

are working toward meeting the original GHGRP requirements, while simultaneously attempting 

to understand the requirements for Confidential Business Information, EPA’s reporting tool 

schema, and preparing for requirements proposed under Subpart W. It may not be feasible to 

incorporate revisions that impact emission calculations or reporting requirements this late in the 

reporting year. As discussed below, the proposed amendments to the natural gas definition could 

require data collection or equipment installation retroactive to January 1, 2010. In addition, 

reconfiguring and retesting software or other calculation tools takes time. 

For the 2010 reporting year, GPA requests that EPA provide companies with the option of 

reporting based on the requirements from the October 30, 2009 version of the rule or based on 

the amended requirements when they are published as final. 

Response: EPA disagrees with the commenter and is requiring the final amendments to be 

reflected in the first reports submitted to EPA by March 31, 2010. We appreciate the commenter 

providing a specific example of where the proposed amendments would not be feasible to 

implement for these first reports. Specifically, with respect to the concern about the definition of 

natural gas, we have finalized a definition that does not include specific specifications for Btu 

value and methane content for natural gas. As pointed about by several commenters, these 

change in definition could have resulted in some units being subject to a higher calculation tier 

under subpart C (e.g., Tier 3 versus Tier 2) than they originally expected in early 2010. Please 

see Section II.F of the Preamble for EPA’s rationale for the final definition of natural gas. As 

described in Section I.D of the preamble to the final rule amendments we have concluded that 

the amendments as finalized can be implemented for the 2010 reporting year. 

We recognize that EPA has published several proposed rulemakings, as well as some final 

rulemakings related to the GHG Reporting Program in 2010. EPA does not agree that the 

rulemaking and other activities undertaken by EPA and mentioned by the commenter should 

impact the ability of the commenter to incorporate the amendments into the first reports on 

March 31, 2011. As described in Section I.E of the preamble, in general, the specific 

amendments finalized should ease burden and in many cases, the requirement of the 2009 final 

rule is retained as an option. The other rulemaking activities mentioned by the commenter are 

independent from this final rule and do not have a substantive impact on the emissions 

calculation requirements for the subparts included in this rulemaking. Therefore we have 

determined that the fact that there are multiple rulemakings does not provide a sufficient 

rationale for delaying this rulemaking or allowing reporters the option of following the 2009 

final rule, or the rule as amended here, in the first annual report. 
3 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 1 

Comment: Because the agency has opened this “final” rule to further revision on multiple 

occasions, including the CBI issue, PCA recommends acceptance of the first reports through 

June 30, 2011. 

Among other provisions, EPA is requesting comment on proposed amendments to Subpart A and 

Subpart C of the MRR. Whereas Subpart A addresses reporting of biogenic emissions, Subpart C 

focuses on stationary fuel combustion and will be relevant to all cement manufacturers preparing 

reports for 2010 emissions. As a general matter, EPA states that the proposed amendments to 

Subpart C would not require monitoring or information collection above what is already required 

by Part 98. Therefore, EPA expects that sources will be able to use the same information that 

they have been collecting under Part 98 to calculate and report GHG emissions for 2010. As 

stated in PCA comments on the June 15 proposal, modification of Subpart C focusing on 

stationary fuel combustion will have a major impact on the cement industry. 

Response: EPA disagrees with the commenter and is requiring the final amendments to be 

reflected in the first reports submitted to EPA by March 31, 2010. The proposed rulemaking was 

not soliciting comment on the other activities related to the Greenhouse Gas Reporting Program 

(GHGRP), including the proposed rulemaking “Confidentiality Determination for the Mandatory 

Greenhouse Gas Reporting Rule and Proposed Rule Amendment Specifying Procedures for 

Handling Part 98 Data,” mentioned by the commenter. PCA does not provide specific comments 

on why they cannot implement the proposed amendments in the August 11, 2010 proposal, 

rather, in general, they merely allege that modifications to subpart C will have a major impact on 

the cement industry. Please see response to comment EPA-HQ-OAR-2008-0508-2402.1, 

excerpt 1 and Section I.D of the preamble to the final rule amendments for the response to this 

comment. 

Commenter Name: Brian Gasiorowski 

Commenter Affiliation: Lafarge North America 

Document Control Number: EPA-HQ-OAR-2008-0508-2401.1 

Comment Excerpt Number: 5 

Comment: Due Date for Initial Annual GHG Emission Report. EPA requested comment on its 

conclusion that all of the technical amendments and corrections can be implemented and 

incorporated into the initial GHG emissions reports by the due date of March 31, 2011. 

Specifically, EPA asked for comments on whether this timeline is feasible or appropriate, 

considering the nature of the proposed changes and the way in which data have been collected 

thus far in 2010. 
4 

Lafarge believes the deadline for the initial annual report should be extended to June 30, 2011. 

It’s important to note that the extra time will be needed since facilities have been collecting data 

and performing calculations on a monthly basis throughout 2010. This has been a particularly 

labor- and data-intensive program for the many cement plants, particularly those that will not 

begin using CO2 CEMs until either late in 2010, or by January 1, 2011. While it’s recognized the 

proposed rule changes are intended to simplify, the fact remains that it will take a great deal of 

extra work to reconcile any differences between the data collection and calculation approach 

actually used in 2010 (up to this point) with the changes that are ultimately finalized by EPA. 

This extra work will be necessary in order to ensure both data accuracy and full compliance with 

the proposed amendments which EPA is intending to make retroactively effective for all of 2010. 

Arising from the technical amendments and corrections, there will be extensive internal QA/QC 

required to validate whether proper changes have been made to spreadsheets and data elements 

used for emissions calculations at each plant. This labor-intensive effort justifies and extensive of 

the deadline for submitting the initial annual GHG reports to June 30, 2011. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2399.1, excerpt 1. We 

recognize that there will be some additional costs associated with reviewing the regulation and 

determining how it applies to your facility. For a discussion of the estimated burden associated 

with today’s final rule, please refer to the economics discussion in “Final Part 98 Economics 

Memo for Revisions Rulemaking” that has been placed in docket EPA-HQ-OAR-2008-0508 for 

the final rule. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 5 

Comment: The proposed addition of "Fuel Gas" to Table C-1 of the Reporting Rule has 

additional impacts on the implementation of this rule that EPA should account for as detailed 

below. 

Fuels used in combustion units with a heat input < 250 MMBtu/hr were previously not subject to 

the reporting rule if the fuel was not listed in Table C-1. The proposed rule will result in 

numerous fuel streams now becoming subject to the requirements as Tier 1 fuels. As a result of 

this proposal, the owner/operator will be required to re-assess all previously exempt streams, 

develop monitoring plan documents, and train additional site personnel on these requirements of 

the reporting rule. Therefore, additional time will be needed to implement these changes. 

EPA should provide owner/operators the option to use the new reporting provisions in the report 

due March 31, 2011, but not mandate the use of the new requirements until the Year 2011 report 

which is due by March 31, 2012. 

Response: We appreciate the commenter providing a specific example of where the proposed 

amendments would not be feasible to implement for these first reports. However, with respect to 
5 

the concern about the addition of fuel gas to Table C-1, EPA did not intend for this amendment 

to require additional fuels to be covered under the GHGRP. In the final rule, EPA has modified 

the definition of “fuel gas” to limit the applicability of this term, thereby removing the reason for 

the extension requested by the commenter. Please see response to comment, EPA-HQ-OAR2008-0508-2366.1, excerpt 4 for the rationale for this amendment in the final. As described in 

Section I.D of the preamble to the final rule amendments we have concluded that the 

amendments can be implemented for the 2010 reporting year. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 6 

Comment: EPA Should Provide Additional Time for Owner/Operators to Update GHG 

Monitoring Plans. 

Throughout the proposed rule, EPA proposes several items that clarify what information should 

be included in the GHG Monitoring Plan. Source owners were required to have GHG Monitoring 

Plans in place by March 31, 2010, thus these changes will require review and editing of these 

plans in order to add the additional items. In addition, some sources may need GHG Monitoring 

Plans developed for the first time due to the addition of "Fuel Gas" to Table C-1. Therefore, EPA 

should provide additional time, until at least March 31, 2011, for the source owners to update the 

content of the GHG monitoring plans or prepare new plans. 

Some examples of additional monitoring plan requirements are: 

• Documenting the method(s) used to determine the HHV for Tier 2 fuels. 

• Documenting the method(s) used to calibrate Tier 3 fuel flow meters, 

• Documenting the method(s) used to determine the carbon content and molecular weight 

of Tier 3 gas fuels. 

• Preparing a monitoring plan for a new Tier 1 fuel due to the addition of "Fuel Gas" to 

Table C-1. 

Taken collectively, source owners will need additional time to update existing monitoring plans 

and to create new monitoring plans. 

Response: The requirements from the 2009 final rule in §98.3(g)(5)(i) have always required the 

GHG Monitoring Plan to contain an explanation of the processes and methods used to collect the 

necessary data for the GHG calculations. Although this final rulemaking is more explicit in 

certain cases, pointing out that a method should be documented in the monitoring plan this is 

simply a clarification and not a new requirement. Regarding the concern about fuel gas, EPA 

has modified the definition of “fuel gas” in the final rule to limit the applicability of this term. 

Please see response to comment EPA-HQ-OAR-2008-0508-2366.1, excerpt 4 for a discussion of 

this amendment. 
6 

Please see response to comment EPA-HQ-OAR-2008-0508-2368.1, excerpt 7, regarding the 

comment about updating the GHG Monitoring Plan. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 13 

Comment: Application of Revised Rules to 2011 Reports. 

UARG agrees that reporters should be allowed to use the revised rules in their 2011 reports of 

2010 emissions. Requiring facilities to report under the existing rules when EPA has determined 

that those rule are overly burdensome or unclear is not reasonable. However, UARG is 

concerned that there may be instances where the revised rules could be construed as limiting (not 

expanding) the options for calculating emissions. For example, consistent with the UARG 

settlement, EPA proposes to revise § 98.33(a)(2)(ii) to require calculation of weighted HHV 

“only for individual Tier 2 units with a maximum rated heat input capacity greater than or equal 

to 100 mmBtu/hr, and for groups of units that contain at least one unit of that size.” (75 FR 

48756.) For smaller units, the annual arithmetic average HHV would be used instead. See supra 

at section V. Because the rule currently provides no exception to the HHV weighting 

requirement for small units, facilities with combustion sources affected by that provision have 

been retaining the information necessary to determine monthly fuel use and apply the HHV 

weighing required in the rule in the event EPA does not revise the rule. Because the work has 

already been done, those facilities should not be prevented from reporting data using those 

procedures in 2010. Although UARG has not identified any other examples, others might exist. 

To avoid unintended results, UARG requests that EPA not prohibit use of any current provision 

for 2010 emissions reporting, unless EPA can identify a significant discrepancy between the 

existing provision and the reporting requirements in the final rule. 

Response: EPA disagrees with the commenter and is requiring the final amendments to be 

reflected in the first reports submitted to EPA by March 31, 2010. We appreciate the commenter 

providing a specific example of where the proposed amendments would not be feasible to 

implement for these first reports. Specifically, with respect to the concern about the calculation 

of HHV for Tier 2 units with a maximum rated heat input capacity less than 100 mmBtu/hr. 

EPA has finalized the rule to allow these units to use either a weighted HHV calculation or the 

annual arithmetic average, thereby retaining as an option the requirement from the 2009 final 

rule. Please see response to comment, EPA-HQ-OAR-2008-0508-2371.1, excerpt 6 for the 

rationale for this amendment in the final. As described in Section I.D of the preamble to the final 

rule amendments we have concluded that the amendments can be implemented for the 2010 

reporting year. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 
7 

Comment Excerpt Number: 15 

Comment: Per comments submitted with respect to EPA’s proposed amendments published on 

June 15, PCA recommends extension of due dates for the initial reports to June 30, 2011 for the 

2010 GHG data only. Subsequent reports would be due on March 31 of each calendar year, 

beginning in 2011. Modification of Subpart C for stationary combustion will have significant 

impacts on the cement industry, influencing the ability to file accurate reports. The extra time 

will be needed since plants have been collecting data and performing calculation on a monthly 

basis throughout 2010. This has been particularly labor-intensive especially for plants that will 

not begin using CO2 CEMS until either late in 2010, or by January 1, 2011. The proposed rule 

changes may be intended to simplify, but the fact is it will take a great deal of extra work to 

rectify any differences between the data collection and calculation approach actually used in 

2010 with changes finalized by EPA. This extra work will be necessary in order to ensure 

compliance with the proposed amendments which EPA is intending to make retroactively 

effective for all of 2010. There will be extensive internal QA/QC required to validate whether 

correct changes have been made to spreadsheets and data elements used for each emission source 

at each plant. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2399.1, excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 16 

Comment: API believes any revision that requires new measurement or recordkeeping will have 

difficulty meeting the March 31, 2011 reporting deadline if data collection, sampling, or record 

requirements are retroactive to January 1, 2010. Examples include, fuel gas streams combusted at 

petrochemical facilities that were previously exempt from Tier 3 requirements, small metered 

off-gas or vent gas streams at refineries that were previously exempt from Tier 3 requirements, 

and exhaust flow gas meters required under 98.254(f) to comply with Refinery MACT 

requirements. 

Response: EPA disagrees with the commenter and is requiring the final amendments to be 

reflected in the first reports submitted to EPA by March 31, 2010. We appreciate the commenter 

providing specific examples of where the proposed amendments would not be feasible to 

implement for these first reports. Specifically, with respect to the concern about the fuel gas 

streams, we have modified the definition of fuel gas in this final rule with a goal to not subject 

additional fuels to reporting that would not have otherwise been required to be reported 

according to the 2009 final rule. For a further discussion of the rationale for the change in the 

definition of fuel gas, please refer to section II.G of the preamble. 

Regarding the concern that there are fuel gas streams that “were previously exempt” from 

reporting but now would have to be measured, EPA disagrees with the commenter’s concerns. 

The proposed amendments on August 11, 2010 specifically proposed relief in 98.243(d) 
8 

“Optional combustion methodology for ethylene production processes”. The 2009 final rule was 

clear that these streams must be measured using Tier 3 or Tier 4. The final amendments, as 

proposed, allow use of Tier 1 or Tier 2 under certain conditions. The proposed rule did not 

impose Tier 3 on new streams, therefore we have determined that the request to extend 

implementation for measuring these streams is not warranted. 

Finally, with respect to the concern about requiring exhaust flow gas meters required under 

98.254(f) to comply with Refinery MACT requirements, we agree with the commenter that it is 

inappropriate to add these requirements to process vent flow meters at this juncture, thus this 

concern does not justify an extension. For a further discussion of the rationale for these final rule 

requirements, please refer to section II.N of the preamble to the final rule. 

Based on the discussion above, we have concluded that there is no need to postpone 

implementation of these amendments and, as described in Section I.D of the preamble to the 

final rule amendments we have concluded that the amendments can be implemented for the 2010 

reporting year. 

2. SUBPART A – GENERAL PROVISIONS 

Applicability threshold for natural gas LDCs 

Commenter Name: Bert Kalisch 

Commenter Affiliation: American Public Gas Association (APGA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2355 

Comment Excerpt Number: 1 

Comment: APGA supports applying the 25,000 metric ton threshold to local gas distribution 

systems. APGA supports the 25,000 metric ton CO2 equivalent threshold, because application of 

the threshold would appropriately eliminate unduly burdensome requirements. We believe that 

changes proposed in this proposed rule by EPA adequately address APGA’s concerns. APGA 

also agrees with EPA’s decision to express the reporting limit in cubic feet rather than metric 

tons of CO2; it will be much easier for LDCs to determine if they are over the reporting 

threshold. Owners and operators of LDCs know how much natural gas they deliver to their 

customers and it would, therefore, be easier for facilities to determine if they are subject to the 

rule than if the threshold were specified in metric tons of CO2. 

Response: We thank the commenter for the input. We have finalized the proposed 

requirements to amend the threshold for local distribution companies to 460,000 thousand 

standard cubic feet or more of natural gas delivered per year. This level is approximately 

equivalent to 25,000 mtCO2e per year. Please see Section II.P in the preamble to the final rule 
9 

amendments, as well as Section II.P of the proposal preamble (75 FR 48776) for additional 

information. 

Commenter Name: Bert Kalisch 

Commenter Affiliation: American Public Gas Association (APGA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2355 

Comment Excerpt Number: 2 

Comment: REQUESTED CLARIFICATION. APGA supports the fundamental approach of the 

proposed rule. However, APGA believes that the EPA should provide the following clarification: 

The reporting threshold for local gas distributors in amended Section 98.2(a) (4)(iii)(B) is 

expressed in cubic feet of natural gas, but in several other sections of the rule thresholds continue 

to be expressed only in metric tons CO2 equivalent. Specifically, Sections 98.2(i)(1) and (2) 

allow entities to stop reporting if emissions are less than 25,000 metric tons for 5 consecutive 

years or less than 15,000 metric tons for 3 consecutive years. 25,000 metric tons is 

approximately 460 million cubic feet of natural gas and 15,000 metric tons is approximately 276 

million cubic feet of natural gas. APGA urges EPA to clarify that the threshold for natural gas 

distributors (460,000 thousand cubic feet per year) is equivalent to the threshold of 25,000 metric 

tons CO2 wherever that metric ton threshold appears in the rule. In particular, EPA should clarify 

that the conditions for ceasing reporting to EPA listed in Sections 98.2(i)(1) apply to LDCs if an 

LDC supplies less than 460 million cubic feet of gas for 5 consecutive years and that Section 

98.2(i)(2) applies if an LDC delivers less than 276 million cubic feet or gas for 3 consecutive 

years. APGA believes this is consistent with the intent of these two sections. 

Response: See section II.P in the preamble to the final rule amendments for the response to this 

comment. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2394.1 

Comment Excerpt Number: 1 

Comment: The American Gas Association (AGA) supports applying the 25,000 metric ton 

threshold to local gas distribution systems. AGA supports EPA’s proposal to exempt small 

natural gas local distribution companies (LDCs) that deliver less than 460,000 thousand standard 

cubic feet of natural gas per year from the reporting and other requirements under Subpart NN of 

the MRR. In addition, AGA supports comments filed in this docket by the American Public Gas 

Association (APGA) requesting EPA to clarify that the reporting threshold for natural gas LDCs 

(460,000 thousand standard cubic feet per year) is equivalent to the threshold of 25,000 metric 

tons CO2 wherever that metric ton threshold appears in the rule. We agree with APGA that EPA 

should clarify that the conditions for being allowed to cease reporting to EPA listed in Section 

98.2(i)(1) should apply to an LDC if it supplies less than 460,000 thousand standard cubic feet 

per year for 5 consecutive years and that section 98.2(i)(2) applies if an LDC delivers less than 

276,000 thousand cubic feet of natural gas for 3 consecutive years. It makes no sense to impose 
10 

the numerous reporting and recordkeeping burdens of Subpart NN on these small LDCs, when 

they represent less than 1 percent of the reported GHG emissions associated with LDC supply – 

a much lower percent than the 10 to 15 percent of GHG emissions that are excluded in other 

sectors by the comparable 25,000 ton per year (tpy) carbon dioxide equivalent (CO2e) threshold 

used in other Subparts of the MRR. See 75 Fed. Reg. at 48776. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2355.1, excerpt 2. 

Commenter Name: Ann W. McIver 

Commenter Affiliation: Citizens Energy Group 

Document Control Number: EPA-HQ-OAR-2008-0508-2387.1 

Comment Excerpt Number: 1 

Comment: Citizens supports the proposed changes in applicability at 40 CFR 98.2(a) to exempt 

natural gas LDCs that distribute less than 460,000 mscf to customers per year from the annual 

GHG reporting requirements. This exemption will remove an administrative burden from these 

small natural gas LDCs. 

Response: EPA thanks the commenter for the input. We have finalized the proposed 

requirements to amend the threshold for local distribution companies to 460,000 thousand 

standard cubic feet or more of natural gas per delivered per year. Please see Section II.P, in the 

preamble to the final rule amendments as well as Section II. P of the proposal preamble (75 FR 

48776) for additional information. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 12 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 12 

These two commenters submitted identical comments on this subject. 

Comment: EPA proposes to exempt local natural gas distribution companies (“LDCs”) 

delivering 460,000 thousand cubic feet or less per year from all reporting requirements. See 75 

Fed. Reg. at 48,777. EPA had previously included all LDCs in the rule, and “did not receive any 

comments opposed to the ‘all in’ designation,” while it did receive two supportive comments. Id. 

Because LDC owners and operators “know how much natural gas they deliver,” reporting is not 

particularly burdensome. Id. We are therefore skeptical of EPA’s decision to exempt these 

sources now. 
11 

EPA concludes that exempting smaller LDCs would diminish “emissions coverage [by] . .. less 

than 1 percent.” Id. EPA should clarify whether this is a loss of 1 percent in this specific category 

or across the entire rule. If it is the latter, we strongly oppose the exemption, as 1% of national 

emissions is quite significant. Either way, we ask that EPA provide lost coverage estimates in 

both tons and percentages, as this makes it easier to assess. If the loss is large, EPA should 

reconsider the exemption, as reporters face a low burden here, and did not oppose their inclusion 

during the public comment period. 

Response: No rule change has been made as a result of this comment. Please see section II.P of 

the proposal preamble (40 CFR 48744) for a discussion regarding EPA’s rationale for amending 

the threshold for LDCs. We considered the burden associated with reporting, the quantities of 

greenhouse gases that will be reported by these smaller LDCs, as well as the fact that after five 

years all of these LDCs would no longer be required to report per the off-ramp clause in 98.2(i) 

(many would no longer be required to report after three years per this provision). 

In exhibit 7 of the technical supporting document for suppliers of natural gas and natural gas 

liquids from January 28, 2009, EPA displays the emissions coverage that would be attained at 

various reporting thresholds for local natural gas distribution companies. According to that 

estimate, having a reporting threshold of 25,000 mtCO2e (approximately equivalent to 460,000 

mscf of natural gas) for LDCs would still cover 99.28% of emissions associated with all natural 

gas delivered by LDCs. The lost coverage of 0.72% from LDCs equates to approximately 

4,500,000 mtCO2e, which is less than 0.1% of total emissions in the United States per year. 

EPA has concluded that this loss in emissions coverage is small enough to justify the change in 

reporting threshold. 

Content of annual report- separate biogenic CO2 emissions reporting 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 8 

Comment: EPA has proposed changes to Section 98.3(c)(4) Content of the annual report, with 

the stated intent of clarifying that units subject to subpart D or other Part 75 units are not 

required to separately report their biogenic CO2 emissions, but may do so optionally. However, 

the proposed amendments to Section 98.3(c)(4) go far beyond the Agency’s stated intent and will 

adversely affect the quality and transparency of reporting for many more types of facilities. 

The proposed revisions to 40 CFR 98.3(c)(4)(i) would require all reporters to report annual, 

aggregated, facility-wide anthropogenic and biogenic emissions. However, this does not appear 

to be the actual intent of the revision, as the preamble to the proposed changes at section II. C. 

states: 
12 

We intended for the reporting of biogenic CO2 emissions to be optional for units subject 

to subpart D. However, the current rule does not consistently affirm this. To address these 

concerns, we are proposing to amend the data elements in subparts A and C that currently 

require separate accounting and reporting of biogenic CO2 emissions so that it would be 

optional for Part 75 units.” 

The revisions as proposed will result in less clear and complete emissions reporting information 

for the public, EPA and state regulators as there will be no delineation of the biogenic emissions 

versus anthropogenic emissions of a facility. WM has many facilities reporting under subpart HH 

and subpart C. For these facilities fully half to all of the total GHG emissions are biogenic. We 

do not feel it is appropriate to force us to aggregate these emissions with our anthropogenic GHG 

emissions. 

Emissions reporting will be more accurate, more transparent and complete if our biogenic and 

anthropogenic emissions are separately reported as now required in the Final Rule. This is 

particularly important as EPA has just requested comments on the treatment of biogenic 

emissions in implementing the Tailoring Rule. Distinct reporting of anthropogenic versus 

biogenic emissions will be necessary to support EPA’s ultimate decision. 

We recommend that EPA amend 40 CFR 98.3(c)(4)(i) as follows so as to maintain the delineated 

anthropogenic and biogenic emissions reporting while allowing subpart D reporters and Part 75 

methodology users to optionally report biogenic CO2 emissions: 

Annual emissions (excluding biogenic CO2) aggregated for all GHG from all applicable source 

categories in subparts C through JJ of this part and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart, with the exception of sources subject to subpart D or sources 

using Part 75 methodologies to calculate CO2 mass emissions, which are not required to exclude 

biogenic emissions from the annual emissions. EPA’s proposed changes to 40 CFR 98.3(c) (ii) 

and (c) (4) (iii) (A) to clarify that subpart D reporters or units using Part 75 methodologies to 

calculate CO2 mass emissions need only report biogenic CO2 optionally can remain the same as 

proposed. 

Further, WM recommends that the Agency commit to making optionally reported biogenic CO2

emissions information readily and transparently available to the public and to state regulators. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

The recommendation to make biogenic CO2 emissions readily available is beyond the scope of 

the amendments proposed on August 11, 2010. On July 7, 2010 we published a proposed 

regulation in the Federal Register with our proposed determination regarding the confidential 

nature for each data element under the Greenhouse Gas Reporting Program. The comment 

period closed on September 7, 2010. We are still reviewing comments submitted on that 

proposal. 
13 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 1 

Comment: The Mandatory Reporting of Greenhouse Gases final rule (hereinafter "final rule") 

does not provide clear guidance on biogenic reporting requirements for Subpart D, nor for units 

using other Part 75 methodologies to report emissions. The proposed rule clarifies that separate 

reporting of biogenic emissions for these units is optional. Xcel Energy supports this clarification 

because it is consistent with existing 40 CFR Part 75 practices, which allow aggregated reporting 

of non-biogenic and biogenic emissions. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 1 

Comment: Biogenic CO2 reporting should not be revised as EPA proposed –but EPA can ease 

separate reporting of biogenic and fossil fuel emissions for CEMS users. Proposed revisions in 

several provisions of Subpart A and Subpart C would allow 40 CFR Part 75 methods users to 

report biogenic CO2 separately on a voluntary basis, and, unlike the current final regulation, all 

GHG emissions reporters would be directed to first report their total GHG emissions including 

biogenic CO2. For example, see proposed rule language at §98.3(c)(4)(i), which substitutes 

“including” for “excluding” with respect to reporting biogenic CO2 emissions. This has the effect 

of lumping biogenic CO2 emissions with fossil GHG emissions instead of the totally separate 

reporting of those emissions promulgated in the final rule. After reporting co-mingled fossil and 

biogenic GHG emissions, only the reporters not using Part 75 methods would still be required to 

report biogenic CO2 as a separate line item. 

These proposed changes are the result of a proposed settlement agreement between EPA and 

UARG and are principally aimed at electric utility generating units subject to 40 CFR §98 

Subpart D, that is, sources that are subject to the Acid Rain Program and are using continuous 

emissions monitoring systems (CEMS) to measure the total CO2 existing their exhaust stacks. 

See footnote 1. However, the proposed subsequent proposed revisions to the GHG MRR upon 

which we are commenting raise this reporting issue in the context of trying to resolve UARG 

members’ concerns regarding the substantial and burdensome fossil fuel analyses and additional 

work beyond what Part 75 already requires. The additional work occurs since CO2 CEMS 

measurements alone do not differentiate among the sources of the CO2. Specifically, the existing 

requirement to determine and report separately a small fraction of CO2 that is biogenic in origin 

amidst the predominant use of fossil fuel at an electric utility plant using CO2 CEMS and 

reporting using Part 75 methods appears unreasonable. However, instead of making the separate 

reporting of biogenic CO2 more manageable for UARG members, EPA provides a proposed 
14 

solution --an exemption from reporting biogenic CO2 and a change in the reporting focus-- that 

we believe is problematic. [Footnote: We provide six examples of problems arising in our 

comments on the settlement agreement. See Exhibit 1 in DCN: EPA-HQ-OAR-2008-0508-

2375.1.] 

As we noted in our comments on the proposed settlement agreement, we believe as a first 

principle that separate reporting of biogenic CO2 should be mandatory for all source categories 

subject to EPA’s GHG MRR. It should not be optional, as suggested in the proposed settlement 

agreement with UARG and as configured in the proposed revisions in Subpart A and Subpart C. 

We believe separate reporting of biogenic CO2 is important because it is consistent with the 

approach taken in the IPCC and national and regional U.S. GHG inventory frameworks, and it 

correctly supports the concept that biogenic CO2 emissions in the U.S. are carbon neutral. This is 

because CO2 is captured from the atmosphere in the photosynthetic process, therefore the 

biogenic CO2 released to the atmosphere during biomass combustion is a net neutral and the CO2

does not contribute to the overall global GHG inventory. Also, the separate reporting of biogenic 

CO2 is appropriate for transparency and inventory balancing purposes since biogenic CO2 is 

accounted for in the land use portions of the EPA National Inventory. These concepts are 

explained in great detail in Weyerhaeuser’s comments [Footnote: Weyerhaeuser’s comments on 

the “Call for Information” are assigned Docket ID No. EPA-HQ-OAR-2010-0560-0563.1.] filed 

recently in response to EPA’s PSD Tailoring Rule “Call for Information.” 

We have already addressed this issue in detail in our comments on the settlement agreement and 

have proposed a reasonable solution therein to ease the UARG members’ burden while retaining 

the completely separate reporting of biogenic CO2 emissions already promulgated in the final 

GHG MRR. Because of that we will cut our comments short here and adopt those previous 

comments into this rulemaking as Exhibit 1. We urge EPA to adopt the alternative solution 

proposed in those earlier comments and preserve the appropriate reporting framework for 

biogenic CO2 emissions that is embodied in the final GHG MRR issued October 30, 2009. While 

we believe our proposed alternative solution is reasonable and workable for all parties, we are 

open to other approaches that achieve the same necessary endpoints: the separate reporting of 

biogenic CO2 (i.e., not comingled with fossil GHG emissions reporting totals) and mandatory 

reporting of biogenic CO2 emissions for all subject to the GHG MRR. We stand ready to work 

with EPA, UARG and other parties to resolve this question. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Caitlin Post 

Commenter Affiliation: Southern Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2377.1 

Comment Excerpt Number: 1 

Comment: EPA is proposing to make the separate reporting of biogenic emissions for units 

subject to subpart D optional. Southern Company understands that this option is beneficial for 

units that are burning small amounts of biomass and do not want the burden of separating out 
15 

these emissions since they are not currently required to do so per the requirements of Part 75. By 

incorporating this option into the rule, EPA had to change the requirement to report annual 

carbon dioxide (CO2) emissions from each source category in subparts C through JJ of this part 

to include biogenic CO2 emissions. Southern Company realizes this change is necessary to 

integrate this option into the rule. However, the Company suggests EPA allow optional reporting 

of annual CO2 emissions excluding biogenic CO2 emissions in addition to the annual CO2

emissions including biogenic CO2 emissions. 

It is appropriate to allow units the option to report annual CO2 emissions excluding biomass 

because the combustion of biomass causes no net increase in CO2 on a lifecycle basis. CO2

emissions from biomass combustion, in contrast to CO2 emissions from fossil fuels which 

represent a one-way process (release of geologic carbon that has been out of the atmosphere for 

millions of years), are part of a two-way process – termed the biogenic carbon cycle. Plants 

absorb CO2 as they grow and release it as they decay or are burned. This cycle releases no new 

CO2 into the atmosphere, which is why this cycle is termed “carbon neutral.” Significantly, in 

many cases, the combustion of certain biomass fuels avoids methane emissions from biomass 

decay, generating a net effect that is better than carbon neutral. Ultimately, CO2 emissions from 

biomass are different from CO2 emissions from fossil fuels. 

EPA already treats biogenic CO2 emissions differently than other CO2 emissions in the MRR by 

excluding biogenic CO2 emissions in determining if a facility meets the applicability threshold. 

Also, EPA references this difference in its final Prevention of Significant Deterioration and Title 

V Greenhouse Gas Tailoring Rule (Tailoring Rule). EPA states in the Tailoring Rule that: “We 

[EPA] are mindful of the role that biomass or biogenic fuels and feedstocks could play in 

reducing anthropogenic GHG emissions, and we do not dispute the commenters’ observations 

that many state, federal, and international rules and policies treat biogenic and fossil sources of 

CO2 emissions differently.” Since releasing the Tailoring Rule, EPA, according to Executive 

Order 13514, collaborated with the Department of Energy, the Department of Defense, the 

General Services Administration, the Department of the Interior, the Department of Commerce 

and other agencies to develop draft Federal Greenhouse Gas Reporting and Accounting 

Guidance. This guidance exempts biogenic CO2 emissions from Federal agency greenhouse gas 

reduction targets. 

All units except those subject to subpart D must still report their biogenic CO2 emissions 

separately. Therefore, it would not be burdensome to allow units the option to also report their 

annual CO2 emissions excluding biomass. Units subject to subpart D that choose to not report 

their biogenic CO2 emissions separately should not be required to report their annual CO2

emissions excluding biomass. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Edward W. Repa 

Commenter Affiliation: National Solid Wastes Management Association (NSWMA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2379.1 
16 

Comment Excerpt Number: 1 

Comment: Section 98.3(c)(4)(ii) states: “Annual emissions of biogenic CO2 aggregated for all 

applicable source categories in subparts C through JJ of this part in metric tons. Units that use the 

methodologies in part 75 of this chapter to calculate CO2 mass emissions are not required to 

separately report biogenic CO2 emissions, but may do so as an option.” Similar language is also 

contained in section 98.3(c)(4)(iii)A). EPA states in the preamble that the rationale for proposing 

this change is “to provide clarity and remove any potential inconsistencies” [C. Subpart A. 

(General Provisions): Reporting of Biogenic Emissions]. However, NSWMA believes the 

proposed changes are less clear and will only cause more inconsistencies because data users 

(e.g., federal and state regulators, the public) [who] will not be able to tell the difference between 

biogenic and anthropogenic emissions from a source. 

NSWMA’s landfill members manage MSW that is comprised of more than 60 percent biomass, 

including paper and paperboard (31%), yard trimmings (13.2%), food scraps (12.7%), and wood 

(6.6%) (EPA 2009) [Footnote: 1 Beck, R.W. 2001. Size of the United States Solid Waste 

Industry. Environmental Research and Education Foundation. Alexandria, VA. 30 pp.]. This 

biomass is unique because it does not compete with other land uses for biomass production (e.g., 

good farmland is not being taken out of service). NSWMA believes that the mandatory reporting 

rule for GHG produced from biomass should not be accounted for in the same manner as 

anthropogenic GHG (e.g., fossil fuel use), which will allow emissions reporting to be accurate, 

transparent, comparative, and complete. In addition, the comment period on EPA’s Call for 

Information on Greenhouse Gas Emissions Associated With Bioenergy and Other Biogenic 

Sources (75 FR 41173) was just completed on September 13, 2010 and will determine how 

biogenic sources are treated under the EPA’s final rule Prevention of Significant Deterioration 

(PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). NSWMA suggests that EPA 

amend the language such that reporters submit separate biogenic and non-biogenic CO2

aggregated for all GHG emissions from all applicable sources unless the source can justify in its 

report to EPA that this method is not possible. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Rhea Hale 

Commenter Affiliation: American Forest & Paper Association (AF&PA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2382.1 

Comment Excerpt Number: 1 

Comment: The American Forest & Paper Association (AF&PA) objects to EPA’s proposal to 

combine reporting of biogenic and fossil fuel emissions. Rather, AF&PA offers an alternative 

proposal that would maintain the current requirement for separate reporting, thus insuring proper 

differentiation of fossil and biogenic emissions and accuracy of totals, while effectively 

eliminating the burden of separate reporting for subpart D sources utilizing Part 75 CO2 CEMS. 
17 

Biogenic and fossil-based emissions are fundamentally different and should not be combined in 

one total. Climate change experts, including the IPCC and EPA, have always differentiated 

biomass-derived carbon from fossil-fuel derived carbon based on biomass’s role in the global 

carbon cycle. Biomass-derived carbon is part of a relatively rapid natural cycle that, when in 

balance, neither adds nor subtracts carbon to/from the atmosphere, whereas fossil fuel-derived 

carbon is not part of such a rapid cycle and does add to the concentrations of GHG in the 

atmosphere. The carbon dioxide (CO2) removed from the atmosphere during photosynthesis is 

converted into organic carbon and stored in biomass, such as trees and crops. When harvested 

and combusted, the carbon in the biomass is released as CO2, thus completing the carbon cycle. 

The carbon in biomass will return to the atmosphere regardless of whether it is burned for energy 

or allowed to biodegrade. When we burn biomass for energy, we are simply inserting a step in 

the cycle that allows us to recover usable energy that can displace fossil fuels. 

The carbon (CO2) neutrality of biomass is universally accepted in greenhouse gas reduction 

programs as reflected in measurement protocols, legislative proposals, implemented regulations, 

voluntary programs, and in overall global strategies for greenhouse gas (GHG) reduction. EPA’s 

proposed requirement for sources to combine fossil and biogenic emissions together in one total 

ignores the natural biomass carbon cycle, will overstate net CO2 entering the atmosphere, runs 

counter to IPCC accounting protocols and will confuse established climate and renewable energy 

policy in this country. 

EPA’s proposal carries with it, whether intended or not, a distinct policy change implication with 

respect to biomass fuel. EPA’s proposed approach cannot support future regulatory programs 

and will result in erroneous CO2 totals for both fossil and biogenic emissions. The 1990 Clean 

Air Act Amendments require utility sources to monitor and report CO2 emissions. In the past, 

EPA has not required Part 75 CEMs users to differentiate their fossil and biogenic carbon 

dioxide emissions. However, beginning in January 2011, EPA will begin regulating greenhouse 

gases beyond monitoring requirements for the first time. Therefore it will be necessary to 

maintain separate totals for fossil fuel-based emissions, which are measured at the point of 

combustion and biogenic emissions, which are measured most accurately as carbon stock 

changes on the land. Biogenic emissions at the point of combustion are often reported for 

informational purposes but do not represent a comprehensive accounting of biogenic emissions. 

In addition, the Mandatory GHG Reporting Rule was authorized by Congress to support future 

climate change legislation. All proposed climate change legislation to date has emphatically 

excluded biogenic emissions from proposed caps, facility thresholds and reduction requirements. 

To support future legislative proposals it is imperative that separate totals are complete and 

accurate. By making separate reporting optional for Part 75 sources, EPA will be unable to 

determine an accurate accounting of fossil-based emissions or biogenic emissions as many 

sources will choose not to separate out emissions simply to reduce reporting burden, thus 

overstating the fossil total and understating the biogenic total. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 
18 

Commenter Name: Angela D. Marconi 

Commenter Affiliation: Delaware Solid Waste Authority (DSWA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2392.1 

Comment Excerpt Number: 1 

Comment: Part 98.3(c)(4) contains revisions to the content of the annual report. These revisions 

apply to how biogenic emissions are to be reported. They include a requirement to report the 

total of biogenic and anthropogenic emissions together as well as reporting of biogenic emissions 

separately. Additionally, the reporters for subpart D are allowed the option of not reporting 

biogenic emissions separately. From examining the information sheet and section II.C of the 

preamble it appears that the revision does not accomplish what EPA intended it to. It appears that 

EPA’s intent was to give reporters under subpart D the option of not separating their biogenic 

and anthropogenic emissions. DSWA request that EPA further revise this part to clarify its 

intent. DSWA is concerned that if left unchanged, the reporting of anthropogenic and biogenic 

emissions together will cause confusion for both reporters and the public and will make the 

information contained in the reports less transparent. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: John H. Skinner 

Commenter Affiliation: Solid Waste Association of North America (SWANA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2397.1 

Comment Excerpt Number: 5 

Comment: The Solid Waste Association of North America (SWANA) is concerned that this 

proposal would require aggregate reporting of carbon dioxide emissions. SWANA supports the 

separate reporting of biogenic and anthropogenic emissions, as was required in the final rule. 

This is particularly important as EPA has just requested comments on the treatment of biogenic 

emissions in implementing the Tailoring Rule. Distinct reporting of anthropogenic versus 

biogenic emissions will be necessary to support EPA’s ultimate decision. A majority of the 

emissions from waste-to-energy operations are biogenic in nature and for more accurate 

reporting we believe it is necessary to report them separately. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 6 

Comment: The proposed changes to biogenic emissions reporting are inconsistent with stated 

agency intent and will result in less transparent and complete reporting of GHG emissions. EPA 

has proposed changes to Section 98.3(c)(4) Content of the annual report, with the stated intent of 
19 

clarifying that units subject to subpart D or other Part 75 units are not required to separately 

report their biogenic CO2 emissions, but may do so optionally. However, the proposed 

amendments to Section 98.3(c)(4) go far beyond the Agency’s stated intent and will adversely 

affect the quality and transparency of reporting for many more types of facilities. 

The proposed revisions to 40 CFR 98.3(c)(4)(i) would require all reporters to report annual, 

aggregated, facility-wide anthropogenic and biogenic emissions. However, this does not appear 

to be the actual intent of the revision, as the preamble to the proposed changes at section II. C. 

states: “We intended for the reporting of biogenic CO2 emissions to be optional for units subject 

to subpart D. However, the current rule does not consistently affirm this. To address these 

concerns, we are proposing to amend the data elements in subparts A and C that currently require 

separate accounting and reporting of biogenic CO2 emissions so that it would be optional for Part 

75 units.” 

The revisions as proposed will result in less clear and complete emissions reporting information 

for the public, EPA, and state regulators as there will be no delineation of the biogenic emissions 

versus anthropogenic emissions of a facility. The large majority of GHG emissions from wasteto-energy facilities are biogenic, and it is inappropriate to force these facilities to aggregate these 

emissions with anthropogenic GHG emissions. Emissions reporting will be more accurate, more 

transparent and complete if our biogenic and anthropogenic emissions are separately reported as 

now required in the Final Rule. This is particularly important as EPA has just requested 

comments on the treatment of biogenic emissions in implementing the Tailoring Rule. Distinct 

reporting of anthropogenic versus biogenic emissions will be necessary to support EPA’s 

ultimate decision. 

We recommend that EPA amend 40 CFR 98.3(c)(4)(i) as follows (see the changes in square 

brackets) so as to maintain the delineated anthropogenic and biogenic emissions reporting while 

allowing subpart D reporters and Part 75 methodology users to optionally report biogenic CO2

emissions: (i) Annual emissions ([excluding] biogenic CO2) aggregated for all GHG from all 

applicable source categories in subparts C through JJ of this part and expressed in metric tons of 

CO2e calculated using Equation A-1 of this subpart, [with the exception of sources subject to 

subpart D or sources using Part 75 methodologies to calculate CO2 mass emissions.] EPA’s 

proposed changes to 40 CFR 98.3(c)(ii) and (c)(4)(iii)(A) to clarify that subpart D reporters or 

units using Part 75 methodologies to calculate CO2 mass emissions need only report biogenic 

CO2 optionally can remain the same as proposed. Further, the Energy Recovery Council (ERC) 

recommends that the Agency commit to making optionally reported biogenic CO2 emissions 

information readily and transparently available to the public and to state regulators. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 8 
20 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.1 

Comment Excerpt Number: 1 

These two commenters submitted identical comments on this subject. 

Comment: We strongly oppose EPA’s proposal to exempt subpart D and other source categories 

that comply with the monitoring and reporting requirements of the Acid Rain Program (“ARP”) 

from the requirement to report separately their biogenic CO2 emissions. These facilities would 

include a large number of electricity generation facilities [See, e.g., 74 Fed. Reg. 56,260, 56,290 

& 56,294 (Oct. 30, 2009)]. As discussed below, there is absolutely no valid justification – legal, 

scientific, or otherwise – for this exclusion. 

Not surprisingly, EPA does not attempt to proffer one. Rather, EPA only states that it “intended” 

that subpart D source categories would continue to monitor and report as required by the ARP. 

Moreover – and most importantly – this exemption would severely undermine EPA’s execution 

of the sweeping congressional mandate that it require reporting from “all sectors of the 

economy.” See Appropriations Act of 2009, Pub. L. No. 110-329, 122 Stat. 3574-3716 (March 

11, 2009), the purpose of which is to establish a comprehensive inventory of the sources of GHG 

emissions to inform the development of climate change policies. 

As an initial matter, and as was noted in comments submitted by environmental organizations on 

proposed settlement agreements with respect to the MMR Rule, the monitoring and reporting 

requirements of the ARP do not and should not constrain EPA’s reporting requirements in the 

GHG context. Congress’s mandate to EPA is clear: to establish an economy-wide inventory of 

GHG emissions to inform climate policy. In contrast, the ARP was designed to prevent acid rain 

and not climate change. Therefore, very different considerations – including the GHG 

implications of different types of fuels – should govern EPA’s development of the 

congressionally mandated economy-wide GHG inventory. [Footnote: As was stated in comments 

on the proposed settlement agreements, it is not at all clear to us that the amount of biogenic CO2

emissions can be back-calculated from data made publicly available under the ARP or what the 

burden would be on the public and policymakers to perform such a back-calculation, if it is in 

fact possible. Ex. 1 at 12-13. 

Further review of the requirements of the ARP for this rulemaking has confirmed this. In fact, 

Appendix G of the ARP specifically states that when a unit combusts both fossil fuel and nonfossil fuels, the reporter should either use a CO2 CEMS or apply to the Administration for 

approval of a unit specific method to determine CO2 emissions. 40 C.F.R. Appx. G § 2. Nor is it 

clear to us that this information can be back-calculated based on the data reporting provisions of 

the MMR Rule, see 40 C.F.R. § 98.36(d), or pursuant to EPA’s proposed definition of “emission 

data,” 75 Fed. Reg. 39,094, 39,100-01. 

However, even if this information can be back-calculated, the public interest overwhelmingly 

supports making this data available in the most transparent manner, particularly when such 
21 

calculations may be made in a straightforward manner by the polluter. Should EPA, however, 

finalize its proposal – which we would strongly oppose – EPA in the final rulemaking should 

clearly explain exactly how such back-calculations could be performed. In the past, EPA has 

correctly recognized that establishment of an accurate and comprehensive inventory, including 

the types of fuels used at facilities and related emissions, is fundamental to the development of 

effective climate change policies. The Agency has stressed that “[a]ccurate and timely 

information on GHG emissions is essential for informing many future climate change policy 

decisions” and that facility specific data is particularly important for understanding factors that 

influence GHG emissions rates and identifying actions and facilities that could reduce emissions 

[See 74 Fed. Reg. at 56,265]. Further, EPA has stated that “[b]esides total facility emissions, it 

benefits policy makers to understand: (1) The specific source of emissions and the amounts 

emitted by each unit/process to effectively interpret the data and (2) the effect of different 

processes, fuels, and feedstocks on emissions.” We agree. However, EPA’s proposal to exclude 

subpart D source categories from separately reporting biogenic CO2 emissions would do serious 

damage to EPA’s efforts to gain a better understanding of the sources of GHG emissions and 

ways in which emissions of these harmful air pollutants can be reduced. 

Ample evidence demonstrates that biomass is not inherently “carbon neutral” and that uses of 

some types of biomass, as compared to fossil fuels, may actually lead to a net increase in GHG 

emissions. [See, e.g., Comments of the Clean Air Task Force, Conservation Law Foundation, 

Natural Resources Council of Maine, Natural Resources Defense Council, Sierra Club and 

Southern Environmental Law Center on Call for Information: Information on Greenhouse Gas 

Emissions Associated with Bioenergy and Other Biogenic Sources (75 Fed. Reg. 41,173 (July 

15, 2010), 27, available at http://www.regulations.gov/search/Regs/home.html#home (Docket 

ID. No. EPA-HQ-OAR-2010-0560) (Ex. 4). The substance of those comments is fully 

incorporated into these comments on the proposed changes to the MMR Rule.] 

For too long, however, federal and state policies seeking to reduce GHG emissions have not fully 

taken into account these scientific findings [See, e.g., Environmental Working Group, Clearcut 

Disaster: Carbon Loophole Threatens U.S. Forests (June 2010)]. EPA’s proposal is particularly 

problematic given that subpart D source categories are the exact facilities that are likely to use an 

increasing amount of biomass in the coming years. 

For instance, one report from the Environmental Working Group, which was co-authored by Dr. 

Mary Booth, has concluded that in the United States, 118 new biomass power plant and co-firing 

proposals that would use wood as a fuel are currently at various stages of the permitting process. 

Dr. Booth concluded that reaching a goal of generating 25% of electricity from renewable 

sources by 2025 “will require the equivalent of cutting between 18 and 30 million acres over the 

next 15 years” and “[b]y 2030, the equivalent of up to 50 million acres could be clear-cut[.]”. As 

that report points out, 30 million acres is an area larger than the state of Pennsylvania. 

As was detailed in comments by environmental organizations and others on EPA’s Tailoring 

Rule Call for Information, land clearing and indirect land use changes that could result from 

irresponsible biomass policies may result in significant GHG emissions. Certain types of 

biomass feedstocks may not involve significant land clearing (such as certain forestry and timber 

residues). However, at least for the foreseeable future, the predominant biomass feedstock that 
22 

will be used for energy production will likely be whole trees. Therefore, renewable energy and 

climate change policies that incentivize the use of biomass without an accurate assessment of the 

GHG emissions associated with specific types of biomass fuels could have unintended 

consequences that dramatically undermine efforts to combat climate change, and have other 

detrimental environmental impacts. 

For these reasons, EPA should require that all facilities separately report their biogenic CO2

emissions so that the public may understand how much and by what sectors biomass is being 

used, whether the amount of biomass used as fuel source is increasing, and – in some cases – the 

type of biomass being used. There is therefore no scientific or policy-related rationale for this 

exemption. Moreover, scientific considerations – which must serve as the foundation for any 

climate change policy to be effective – demonstrate that understanding the emissions associated 

with biomass fuel is critical. 

Finally, the burden required of industry to meet this requirement is small. EPA is exempting only 

those facilities that are already required to or that already do report their CO2 emissions under the 

ARP. Therefore, as compared to other source categories, the relative burden imposed on subpart 

D source categories by the MMR Rule is minimal – and certainly does not outweigh the public 

interest in access to this information. Further, EPA in section 98.33(e) provides a methodology 

whereby facilities monitoring CO2 using CEMS may calculate in a straightforward manner the 

amount of their biogenic CO2 emissions. In addition, we see no reason – and, unsurprisingly 

EPA fails to provide one – to exempt subpart D source categories from the burden of separately 

reporting biogenic CO2 emissions, while imposing this burden on other source categories. 

In sum, there is no absolutely no valid justification for EPA’s proposal to exempt subpart D 

source categories from the requirement that biogenic CO2 be reported separately. In fact, all 

considerations of policy and science inevitably lead to the conclusion that to develop effective 

climate change policies, EPA, the public, and policymakers should be aware of the extent to 

which – and if possible, the type of – biomass feedstocks that are being used as a fuel source. 

We recognize that section 114 of the Clean Air Act provides EPA flexibility in establishing a 

monitoring and reporting program for GHGs. Nonetheless, EPA’s proposal to exclude only 

subpart D facilities is not supported by any relevant consideration (and unsurprisingly, EPA fails 

to provide any justification for the exclusion) and would undermine gaining valuable information 

regarding, and as such is arbitrary and an abuse of discretion [See Am. Farm Bureau Federation 

v. EPA, 559 F.3d 512, 520-524 (D.C. Cir. 2009)]. 

Response: EPA does not agree with the comment that EPA would be in violation of the law if it 

did not require separate reporting of biogenic emissions from Part 75 units; commenters’ 

arguments to this end are conclusory. For instance, commenters do not explain how cited 

statutory language regarding coverage of “all sectors of the economy” is dispositive of the type 

of information that EPA must obtain from a source category covered by the rule. Moreover, as 

EPA recently explained in another GHG reporting rule package, the appropriations language 

grants EPA much discretion in formulating the reporting rule. 75 FR 39736, 39752 (July 12, 

2010). Nonetheless, EPA has decided to require reporting of biogenic CO2 emissions from Part 

75 units starting with the 2011 reporting year. 
23 

Please see Section II.C in the preamble to the final rule amendments for additional responses to 

this comment. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.2 

Comment Excerpt Number: 1 

Comment: As a first principle, we believe reporting of biogenic CO2 should be mandatory for 

all source categories subject to EPA’s GHG MRR. It should not be optional, as suggested in the 

proposed Settlement Agreement with UARG (see details in Attachment A to that proposed 

settlement agreement). We believe separate reporting of biogenic CO2 is important because it is 

consistent with the approach taken in the IPCC and national and regional U.S. GHG inventory 

frameworks, and it correctly supports the concept that regulating biogenic CO2 in the U.S. --

whether all or some of the biogenic CO2 as EPA currently is evaluating [Footnote: See EPA’s 

"Call for information" related to biomass published July 16,2010 (75 FR 41173), as follow-up to 

the PSD Tailoring rule.] -- in the global warming context is unnecessary. It is unnecessary, as 

EPA knows, because with respect to CO2 captured from the atmosphere in the photosynthetic 

process, the flux of biogenic CO2 released to the atmosphere during biomass combustion is a net 

neutral and the CO2 does not contribute to the overall global GHG inventory. Also, in 

Weyerhaeuser’s view the separate reporting of biogenic CO2 as supporting information is 

appropriate for transparency and inventory balancing purposes since biogenic CO2 is accounted 

for in the land use portions of the EPA National Inventory. 

Not surprisingly, EPA sets out its own reasons for deciding to retain separate reporting of 

biogenic CO2 for all facilities in its response to comments on the proposed Mandatory Reporting 

Rule. Specifically, in response to Weyerhaeuser and others’ comments that supported the 

separate reporting of biogenic CO2 from other greenhouse gas emissions, EPA says: " ...Upon 

review of the comments, we determined to retain the proposed approach in the final rule. 

Facilities are not required to count emissions associated with biomass combustion when 

determining whether they meet or exceed the threshold for reporting, but if the threshold is 

exceeded they are required to separately report emissions associated with the biomass 

combustion at the facility. This approach is consistent with IPCC Guidelines for National 

Greenhouse Gas Inventories, which require the separate reporting of CO2 emissions from 

biomass combustion and also the approach taken in the U.S. Inventory of Greenhouse Gas 

Emissions and Sinks. Separate reporting of emissions from biomass combustion is also 

consistent with some State and regional GHG programs, such as California’s mandatory GHG 

reporting program, the Western Climate Initiative, and The Climate Registry, all of which 

require reporting of biogenic emissions from stationary fuel combustion sources. The final rule 

does not eliminate the requirement to report emissions from the combustion of biomass fuels 

because they can be used as alternatives to fossil fuels. While this reporting requirement does not 

imply whether emissions from combustion of biomass will or will not be regulated in the future, 

the data collected will improve EPA’s understanding of the extent of biomass combustion and 
24 

the sectors of the economy where biomass fuels are used. It will also allow EPA to improve 

methods for quantifying emissions through testing of biomass fuels." 

We agree with this response-to-comment by EPA, and believed the matter settled. However, the 

proposed Settlement Agreement re-raises the issue in the context of trying to resolve concerns 

regarding the substantial and burdensome fossil fuel analyses and additional work beyond what 

Part 75 already requires. Specifically, the existing requirement to determine and report separately 

a small fraction of CO2 that is biogenic in origin amidst the predominant u<>e of fossil fuel at an 

electric utility plant using CO2 CEMS and reporting using Part 75 methods appears 

unreasonable. However, instead of making the separate reporting of biogenic CO2 more 

manageable for UARG members, EPA provides a proposed settlement solution --an exemption 

from reporting biogenic CO2 and a change in the reporting focus-that we believe is problematic. 

The following describes the basis for this comment. The purpose of the Settlement Agreement is, 

in part, to relieve facilities using Part 75 CO2 CEMS methods from having to report biogenic 

CO2 emissions separate from their fossil fuel emissions. The changes are meant to apply to 

electric utilities subject to GHG reporting under EPA’s GHG Mandatory Reporting Rule at 40 

CFR 98 Subpart D (although as discussed later, the proposed rule language appears to exempt 

any user of Part 75 methods). The specific changes outlined in Attachment A to the Settlement 

Agreement aim to resolve UARG’s challenge to EPA’s requirements in Subpart A (General 

Provisions) at 40 CFR 98.3(c)(4) requiring separate reporting of biogenic CO2 emissions from all 

other GHG emissions (whether from fossil fuels or biogenic fuels). Currently, the final 

regulations issued in 2009 completely separate the reporting of biogenic CO2 quantities from all 

other GHG emissions, a practice that is in concert with international and other national and 

regional protocols and inventories for reporting "Scope I" GHG emissions, as described earlier. 

Although electric utility combustion units subject to Subpart D are expressly exempted from 

Subpart C of the MRR (see 40 CFR 98.30(b)(5», the calculations and other methods for 

determining what portion of the CEMS total monitored CO2 emissions that are biogenic CO2 are 

provided in Subpart C at40 CFR 98.33(e)(2). Subpart D units are also referred to Subpart C for 

methane (CH4) and nitrous oxide (N2O) calculations for any fuel used including biomass (see 

Subpart D 40 CFR 98.43(b), which refers to Subpart C at 40 CFR 98.33(c». In 98.33(e)(2), 

reporters actually are instructed first to determine the portion of the total CEMS monitored 

emissions that are of fossil fuel origin; those fossil fuel CO2 emissions subsequently are 

subtracted from the CO2 CEMS monitor total to obtain and report the separate biogenic CO2

emissions estimate. This calculation requirement is embodied in equations C-13 and C-14 and 

the various subparagraphs of 40 CFR 98.J3(e)(2). The Settlement’s proposed solution would 

allow Part 75 methods users to report biogenic CO2 separately on a voluntary basis, and, unlike 

the current regulation, all reporters would now first report total GHG emissions including 

biogenic CO2. Then, only the reporters not using Part 75 methods would still be required to 

report biogenic CO2 as a separate line item. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

. 

Commenter Name: Kevin P. Bundy 
25 

Commenter Affiliation: Center for Biological Diversity 

Document Control Number: EPA-HQ-OAR-2008-0508-2385.1 

Comment Excerpt Number: 1 

Comment: Greenhouse gas emissions from biomass combustion and other “biogenic” sources 

contribute to global warming and climate change. As set forth in detail in the Center for 

Biological Diversity’s (Center) recent comments regarding EPA’s Call for Information on 

treatment of biogenic emissions under the Clean Air Act’s PSD and Title V programs, biomass 

facilities may have a range of climate footprints depending on fuel sources, combustion methods, 

and associated land use impacts, but there is no scientific or legal support for treating emissions 

from these facilities as if they are not “pollutants” or as if they have no effect on the climate. 

[Footnote: See the comments provided by commenter in DCN: EPA-HQ-OAR-2010-0560-0157 

and the associated exhibits in DCN: EPA-HQ-OAR-2010-0560-0158, -0159, -0160, and -0161] 

Given the importance of accurately measuring and effectively regulating biogenic greenhouse 

gas emissions, the Center strongly opposes EPA’s proposal to exempt certain electrical 

generating units from the requirement to monitor and separately report such emissions. We have 

reviewed the letter submitted today by Clean Air Task Force and other environmental 

organizations regarding the Proposed Rule, and we share their concerns. EPA should not exempt 

sources of biogenic greenhouse gas emissions from monitoring and reporting requirements. It 

makes no sense even to consider such an exemption while the agency is still working to 

determine how best to regulate biogenic emissions under the PSD and Title V programs. Rather, 

EPA should ensure that monitoring and reporting methodologies accurately account for biogenic 

greenhouse gas emissions, and should use that data to inform policy and regulatory development. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.2 

Comment Excerpt Number: 2 

Comment: As proponents of acknowledging biogenic CO2 as a separately inventoried emission 

in keeping with international and other national protocols and precedent, we prefer to not change 

the reporting paradigm in the way EPA proposes. EPA’s proposal carries with it, whether 

intended or not, a distinct policy change implication with respect to separate reporting of 

biomass emissions under greenhouse gas inventories and climate regulations. It also has the 

potential to cause a substantial under-representation of biogenic CO2 emissions in the separate 

biogenic CO2 line item while likewise making accurate estimates of the total fossil fuel 

emissions inventory incalculable. Fossil emissions would be incalculable since the total GHG 

emissions will contain an unknown quantity of biogenic CO2 un-reported because of the 

voluntary nature for some in the separate biogenic CO2 emissions reporting step. 
26 

The following outline some examples of the problems: (1) All electrical generating companies 

already report individual fuel usages; therefore, calculating and reporting biogenic CO2 could be 

very straightforward. All electrical generating companies report fuel usage (by fuel type) to the 

U.S. Energy Information Administration (EIA). Therefore, calculating the biogenic CO2 could 

simply be a matter of using this fuel information and the default biogenic CO2 emission factors 

provided in the MRR. (2) Some Part 75 sources will over-report their total GHG emissions. For 

example, there are many pulp mills, primarily located in the East, that are subject to or use Part 

75 methods. These pulp mills typically produce between 70% to 80% of their total energy from 

biomass fuels (e.g. spent pulping liquor, wood, bark and other wood residuals). Therefore, the 

total CO2 (including the biomass CO2) can be approximately four times larger than the fossil fuel 

CO2 emissions alone. As a consequence, if these sources decide not to report biogenic C02 

separately the total reported GHG emissions would gravely misrepresent the GHG emission 

impact from these facilities. These facilities would be allowed the option even though they are 

not classified as electric generating utilities subject to MRR Subpart D because in the proposed 

Settlement Agreement at two places in Attachment A the modified rule language reads: "Units 

that use the methodologies in part 75 of this chapter to calculate CO2 mass emissions are not 

required to separately report biogenic CO2 emissions, but may do so as an option." (3) There are 

electric generating utilities subject to the Acid Rain Program and using a CO2 CEMS subject to 

Part 75, thus making them subject to MRR Subpart D, that primarily burn biomass but would 

have the option to not separately report their biogenic CO2 emissions. These large biogenic CO2

emissions would be under-reported on the separate biogenic CO2 inventory but imply much large 

total fossil and other GHG emissions in the proposed new primary inventory category that 

includes biogenic CO2 emissions. (4) Reporting the biogenic CO2 with the direct (Scope 1) GHG 

emissions is in conflict with the WRI GHG Protocol. The Protocol states that "Direct CO2

emissions from the combustion of biomass shall not be included in Scope I but reported 

separately". The WRI Protocol is an internationally accepted GHG accounting protocol, used by 

many organizations, companies and others to consistently account and report GHG emissions. 

Therefore, combining the biogenic CO2 with the Scope I GHG emissions is inconsistent with the 

WRI Protocol, and will cause unnecessary discrepancies between the different GHG reporting 

programs. (5) The number of affected facilities is much larger than perceived. The perception is 

the vast majority of sources subject to 40 CFR Part 75 are electrical generating units (EGU). 

However, as previously mentioned there are many other Part 75 facilities, including pulp mills. 

Many pulp mills burn coal not only because of its relatively lower cost, but also because of 

operational necessity. Coal is a source of dry fuel when burning other wetter biomass materials, 

e.g. wet tree bark (hogged fuel). Therefore, many other Part 75 sources besides EGUs will be 

affected by this proposed change. (6) Including biogenic CO2 with the anthropogenic GHG is in 

conflict with EPA’s Green Power Partnership (GPP). 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

In addition, with respect to the commenter’s assertion that EGUs already report individual fuel 

usage (by fuel type) to the U.S. Energy Information Administration (EIA) we would just point 

out that EPA contacted EIA in the development of the final rule to see if all biomass combusted 

is, in fact, reported to EIA under Form EIA-923. We learned that this is not always the case; 

biomass combusted for test burns, for example, is not necessarily reported to EIA. Nevertheless, 
27 

we agree with the commenter’s overall argument that there is not a significant burden associated 

with quantifying this fuel consumption. Today’s final rule provides two simplified procedures 

for quantifying biogenic CO2 emissions at these part 75 units. Specifically, all facilities, except 

those combusting MSW and tires, can use the simplified Tier 1 approach, which is based on 

company records on the quantity of fuel combusted. Further, today’s final rule provides an 

additional method (40 CFR 98.33(e)(6) that allows a reporter to calculate biogenic CO2

emissions based on the heat input data available in the annual electronic reports submitted under 

40 CFR part 75, along with other best available information. For a discussion of the estimated 

burden associated with today’s final rule, please refer to the economics discussion in “Final Part 

98 Economics Memo for Revisions Rulemaking” that has been placed in docket EPA-HQ-OAR2008-0508 for the final rule. 

Finally, in developing today’s final rule we also reviewed carefully fuel consumption at part 75 

units, including the number of units and facilities that would be affected by mandatory reporting 

of biogenic emissions, and the types and relative amount of biogenic fuel (e.g., whether it is the 

primary fuel or a secondary fuel) that they are combusting. For this discussion, please refer to the 

“Background Technical Support Document for the Revisions of Certain Provisions of the 

Mandatory Reporting of Greenhouse Gases Rule” that has been placed in docket EPA-HQ-OAR2008-0508 for the final rule 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 2 

Comment: As promulgated, § 98.36(d) exempts units that report CO2 mass emissions and/or 

heat input year-round under Part 75 (including Subpart D units) from the requirement to monitor 

and report CO2 by fuel type (including the requirement to monitor and report biogenic CO2 from 

combustion of biomass separately from other CO2 emissions). Although EPA described the rule 

in its response to comments as providing Subpart D units the choice of monitoring and reporting 

biogenic CO2 separately (EPA Response to Public Comments, Volume 16 at 21), that option is 

not reflected in § 98.36(d) or in § 98.33(e), which sets out the monitoring provisions for 

calculating biogenic CO2 from Subpart C units with CEMS but makes no reference to Subpart D 

units. [Because Subpart C does not apply to electricity generating units that are subject to 

Subpart D, only those provisions of Subpart C that are specifically referenced in Subpart D apply 

to Subpart D sources. 40 C.F.R. § 98.30(a)(5).] Section 98.3(c) also includes a requirement 

(which was not proposed ) for facility level reporting of CO2 emissions from the combustion of 

biomass fuel, and of CO2 excluding biogenic CO2, that inexplicably fails to address how owners 

and operators of units that are not required to monitor biogenic CO2 separately can certify their 

facility level reports. 40 C.F.R. § 98.3(c)(4). 

In its Reconsideration Petition, UARG described these inconsistencies and asked EPA to 

convene a proceeding to solicit comment on these provisions as applied to Subpart D units. 

UARG noted that units that combust only de minimis amounts of biomass may object to use of 

the monitoring procedure specified for Subpart C units. UARG’s concerns arise in part from the 
28 

fact that the Subpart C procedure requires year-round, and otherwise completely unnecessary, 

sampling and analysis of fossil fuel combusted in order to calculate CO2 emissions from nonfossil fuel. As a result, sources would be required to conduct fuel sampling and analysis of fossil 

fuel at units already continuously measuring CO2 at the stack simply to keep open the option of 

combusting even a tiny amount of biomass during the year (e.g., perform a test burn). 

To address the rule inconsistencies, EPA proposes to revise § 98.33(e) to make clear that Part 75 

sources may calculate biogenic emissions separately under Subpart C and to revise § 98.36(d) 

(and a number of related provisions) to allow (but not require) the reporting of those emissions 

on a unit-specific basis. Because facilities that do not monitor biogenic CO2 separately cannot 

report CO2 separately, or certify a report as excluding biogenic CO2 from the reported emission 

value when those emissions have not been excluded, EPA also proposes to revise § 98.3(c) to 

require reporting of total CO2 (i.e., CO2 including biogenic CO2) in lieu of reporting CO2

excluding CO2. This reporting is consistent with the requirement in Subpart D that units report 

CO2 emissions based on their Part 75 reports, which do not distinguish between biogenic and 

non-biogenic CO2. [See, e.g., Proposed 40 C.F.R. § 98.33(a)(5)(ii)(D), § 98.36(d)(l)(ii) and (ix), 

§ 98.36(d)(2)(ii)(F) and (I), and § 98.36(d)(2)(iii)(F) and (I). 3 Electricity generating units 

subject to Part 75 have been reporting total annual CO2 mass emissions to EPA for more than 10 

years, and some for as many as 15 years.] It also is consistent with other existing or proposed 

provisions that do not require calculation and reporting of CO2 from biomass combustion. See, 

e.g., 40 C.F.R. § 98.33(e) (excluding fuels not listed in Table C-1). 

Although not required under UARG’s settlement agreement, EPA proposes another change 

relevant to UARG’s concerns with the existing rules. Specifically, EPA proposes to remove the 

existing restriction in § 98.33(e)(1) on use of Tier 1 to calculate and report CO2 from the 

combustion of biomass at units that use CEMS to monitor CO2 (including Part 75 units). EPA 

correctly determined that there is “no technical basis” for this restriction in the current rules. 75 

Fed. Reg. at 48,759. As a result, under EPA’s proposal, both Subpart D units and Tier 4 units 

monitoring CO2 with CEMS no longer are limited to fuel sampling and analysis of fossil fuel in 

order to combust biomass. This is a significant improvement in the rules and UARG strongly 

supports it. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2375.2, excerpt 2, for the 

response to this comment. 

Commenter Name: David P. Tenny 

Commenter Affiliation: National Alliance of Forest Owners (NAFO) 

Document Control Number: EPA-HQ-OAR-2008-0508-2373.1 

Comment Excerpt Number: 2 

Comment: NAFO opposes the proposed rule’s change of the existing reporting program to 

require inclusion of biogenic CO2 when reporting aggregate annual emissions and to 

categorically exempt units using the part 75 methodologies from the requirement to separately 

report biomass emissions. It would be inconsistent with and a reversal of established government 

precedent and policy for the Reporting Rule to treat biomass emissions identical to other 
29 

emissions. As such, it is critical that any amendments preserve the existing Reporting Rule’s 

separate reporting of fossil and biomass combustion. While NAFO supports a regulatory regime 

that facilitates the use of biomass, the proposed changes to the regulations are far broader than 

necessary to achieve this goal. 

Response: Please see Section II.C in the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 3 

Comment: UARG also requests that the Agency consider allowing Part 75 sources that are 

applying fuel-specific F-factors to calculate heat input under Part 75 to calculate and report CO2

from combustion of biomass using the same options provided for calculation and reporting of 

methane (CH4) and nitrous oxide (N2O) in the proposed rule. Although not all biomass fuels are 

required to be accounted for separately in heat input calculations under Part 75, many units likely 

are applying a pro-rated F-factor based on an estimated percent of each fuel (biomass and fossil) 

when combusting fuel mixtures that contain biomass. As a result, a source that has apportioned 

its Part 75 annual heat input to multiple fuels that include biomass could calculate emissions of 

CO2 from biomass combustion (i.e., biogenic CO2) using the same procedure it uses to calculate 

emissions of CH4 and N2O under proposed § 98.33(c)(4)(ii)(D). 

Response: EPA thanks the commenter for the input. Today’s final rule provides two simplified 

procedures for quantifying biogenic CO2 emissions at these part 75 units. Specifically, all 

facilities, except those combusting MSW and tires, can use the simplified Tier 1 approach, which 

is based on company records on the quantity of fuel combusted. Further, today’s final rule 

provides an additional method (40 CFR 98.33(e)(6)) that allows biogenic CO2 emissions to be 

calculated based on the heat input data available in the annual electronic reports submitted under 

40 CFR part 75, along with other best available information. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 3a 

Comment: Although UARG believes EPA’s proposed revisions are reasonable and well 

supported, UARG understand that other industries not involved in the settlement may not support 

the proposed requirement that all facilities report total CO2, or agree that all units reporting under 

Part 75 necessarily should be provided the option of not reporting biogenic CO2 separately. 

Specifically, the National Alliance of Forest Owners (NAFO) and the American Forest & Paper 

Association (AF&PA) articulated concerns in comments on UARG’s settlement that the 
30 

Agency’s revision of the facility level reporting requirement to eliminate the reporting of total 

non-biogenic CO2 (i.e., CO2 excluding biogenic CO2) for all units was not consistent with other 

GHG programs, or with those groups’ views regarding the distinctly different nature of biogenic 

and fossil-based CO2. EPA-HQ-OGC-2010-0575-0009 and 0013. The groups also questioned 

whether Part 75 units that are combusting primarily biomass ought to be allowed the option of 

reporting only total CO2. 

UARG shares NAFO’s and AF&PA’s view regarding the nature of biogenic CO2, see, e.g., 

Response of the Utility Air Regulatory Group to the Call for Information on Greenhouse Gas 

Emissions Associated with Bioenergy and Other Biogenic Sources, EPA-HQ-OAR-2010- 0560-

0271. UARG also agrees that units combusting significant amounts of biomass are unlikely to 

opt out of reporting biogenic CO2, and that preservation of an option for facilities with Subpart D 

units combusting small amounts of biomass to report total CO2 from their Part 75 reports does 

not itself require a change in the reporting requirement for other facilities. In short, while UARG 

does not believe that EPA’s proposal in any way signals a change in the Agency’s recognition of 

the distinction between biogenic and non-biogenic CO2, or impedes the separate treatment of 

biogenic CO2 in future regulatory programs, UARG recognizes that there may approaches to unit 

level and facility level reporting of CO2 other than the current proposal that address its concerns. 

For example, EPA could limit the option for reporting total CO2 to those facilities that are not 

required to report biogenic CO2 separately, rather than requiring all sources to report total CO2. 

EPA also could establish a de minimis threshold (e.g., five percent of total annual heat input) for 

the separate reporting of biogenic CO2 Part 75 sources. UARG looks forward to discussing these 

alternative approaches with EPA. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: David P. Tenny 

Commenter Affiliation: National Alliance of Forest Owners (NAFO) 

Document Control Number: EPA-HQ-OAR-2008-0508-2373.1 

Comment Excerpt Number: 3 

Comment: EPA and other domestic and international organizations historically have recognized 

and affirmed carbon neutrality in reporting and other contexts. Biomass CO2 neutrality has been 

the foundation of American policy. As the EPA has concluded, there is “[s]cientific consensus . . 

. that the CO2 emitted from burning biomass will not increase total atmospheric CO2 if this 

consumption is done on a sustainable basis.” [Environmental Protection Agency Combined Heat 

and Power Partnership, Biomass Combined Heat and Power Catalog of Technologies, 96 (Sept. 

2007), available at www.epa.gov/chp/documents/biomass_chp_catalog.pdf. ] 

Consistent with this conclusion, in its most recent GHG inventory, EPA did not include 

emissions from the combustion of wood biomass in its national emissions totals because it 

“assumed that the carbon . . . released during the consumption of biomass is recycled as U.S. 

forests and crops regenerate, causing no net addition of CO2 to the atmosphere.” [EPA, Inventory 
31 

of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 at 3-10 (April 15, 2010), available at 

http://www.epa.gov/climatechange/emissions/downloads10/US-GHG-Inventory2010_Report.pdf.] Similarly, the Department of Energy’s (DOE’s) Voluntary Reporting of 

Greenhouse Gases Program, authorized by Section 1605(b) of the Energy Policy Act of 1992, 

provides for exclusion of combustion of biomass fuels. [See DOE, Technical Guidelines: 

Voluntary Reporting of Greenhouse Gases (1605(b)) Program (January 2007) at 77 (“Reporters 

that operate vehicles using pure biofuels within their entity should not add the carbon dioxide 

emissions from those fuels to their inventory of mobile source emissions because such emissions 

are considered biogenic and the recycling of the carbon is not credited elsewhere.”). ] 

The international GHG accounting methods developed by the United Nation’s Intergovernmental 

Panel on Climate Change also recognize that biogenic carbon is part of the natural carbon 

balance and will not add to atmospheric concentrations of carbon dioxide. Similarly, the 

European Union directive on carbon trading specifies that biomass is considered to be carbon 

neutral. Therefore, a strong consensus exists that treating combustion of biomass as carbon 

neutral is scientifically sound. NAFO’s recommendations below on the proposed rule are 

consistent with and supported by this longstanding government policy. 

B. The combustion of forest biomass is carbon neutral. The proper EPA policies recognizing 

carbon neutrality are based on near-universal recognition that greenhouse gases emitted in 

combustion of fuels derived from biomass should be excluded from greenhouse gas regulations 

because production and combustion of such fuels does not increase atmospheric carbon dioxide 

levels. As EPA is aware, growing plants absorb significant amounts of carbon dioxide from the 

atmosphere. Forests, in particular, sequester massive amounts of carbon dioxide. The process of 

sequestration and storage is a natural by-product of tree growth. Through the process of 

photosynthesis, trees take up carbon dioxide from the air and in the presence of light, water, and 

nutrients, release oxygen and manufacture carbohydrates that are used for metabolism and 

growth of above and below ground organs. All plant materials are ultimately derived from this 

carbon dioxide, which is drawn from the atmosphere. When plant biomass materials, such as 

biofuels made from forest biomass, are burned, the carbon dioxide emitted contains the same 

carbon that was sequestered by the plant feedstocks. Thus, the combustion of biofuels does not 

result in net carbon dioxide emissions. All carbon dioxide emitted is a product of carbon dioxide 

absorbed, making the carbon dioxide released back to the atmosphere a net zero with respect to 

the natural carbon cycle. In this manner, biofuels from forest biomass are fundamentally 

different from conventional fuels. Once coal, natural gas, or oil is extracted and combusted, it 

cannot be replaced. In contrast, the sustainable forest management practiced by the United States 

forest products industry ensures that there is no temporal imbalance between biogenic CO2

emissions and CO2 sequestration and thus no effect on the atmospheric GHG inventory. Indeed, 

as EPA is aware, carbon stocks in United States forests have been, and continue to, increase. 

Thus, the forest bioenergy industry is truly carbon dioxide neutral. 

Response: Please see Section II.C in the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: David P. Tenny 
32 

Commenter Affiliation: National Alliance of Forest Owners (NAFO) 

Document Control Number: EPA-HQ-OAR-2008-0508-2373.1 

Comment Excerpt Number: 4 

Comment: Under the proposed rule, EPA would amend 40 C.F.R. § 98.3(c)(4)(i)-(iv) to require 

the applicable source categories to annually report “[a]nnual emissions (including biogenic CO2) 

aggregated for all GHG . . . .” See 75 Fed. Reg. at 48782. This amendment thus comingles both 

conventional and biogenic CO2 emissions and is a direct reversal of the existing regulatory 

requirement, which requires separate reporting of conventional and biogenic CO2. Not only 

would the proposed rule direct entities to include biomass emissions when reporting their 

aggregate annual emissions, the regulation would state that “[u]nits that use the methodologies in 

part 75 of this chapter to calculate CO2 mass emissions are not required to separately report 

biogenic CO2 emissions, but may do so as an option.” Id. Other proposed changes—to Sections 

98.33(a)(5), 98.33(e), 98.36(d)(1)(ii) and (ix), 98.36(d)(2)(ii), and 98.36(d)(2)(iii)—would 

similarly adjust the requirements for units using part 75 methodologies so that separately 

reporting annual CO2 emissions from the combustion of biomass would be optional. See id. at 

48790, 48792, 48797, 48798. 

The regulations should not mandate the combined reporting of biogenic and conventional 

emissions. Such a requirement is flatly inconsistent with established government policies, 

regulations, and recognition of carbon neutrality of biomass emissions. Specifically, NAFO 

objects to the proposed rule’s requirement that biogenic CO2 be included without segregation, as 

directed by the proposed amendment to 40 C.F.R. § 98.3(c)(4)(i). Doing so would not only be 

inconsistent with carbon neutrality principles, it would make it impossible for EPA to make 

accurate estimates of aggregate fossil fuel emissions as the reported annual emissions would 

include an unknown quantity of biogenic emissions. Moreover, by making it optional for all 

reporters using part 75 methodologies to separately report biogenic emissions, the proposed rule 

would likely result in a substantial underreporting of biomass combustion. 

EPA should preserve the distinction between conventional and biomass combustion. To the 

extent situations arise making it difficult for the separate reporting of biomass emissions by some 

units under existing calculation methodologies, EPA should add flexibility to the calculation 

process to reduce the reporting burden to manageable levels rather than eliminate all reporting 

obligations. Exceptions from biomass reporting should only be considered as a last resort, if at 

all. In the event EPA elects to exempt certain units from the requirement to separately report 

biomass emissions, it should be set out as an exception to the overall Reporting Rule 

requirements. In addition, the exception should be drawn narrowly so that it only applies to units 

that have demonstrated there is a legitimate need. Some of the proposed amendments would 

affect not only units reporting under subpart D of the Reporting Rules (e.g. electric generating 

units) but also units in other direct emitter source categories. See e.g. proposed 40 C.F.R. § 

98.3(c)(4)(ii) (making separate reporting of biogenic emissions optional for all “[u]nits that use 

the methodologies in part 75”). As such, EPA’s proposed changes to the Reporting Rule will 

have ramifications that affect not only electric generating units, but numerous other categories of 

sources. NAFO believes such a far-reaching rule change is inappropriate as these other source 

categories have not been a part of the development of the proposed settlement that is the impetus 
33 

for the proposed rule changes and certainly have not demonstrated a need to be exempt from the 

established policy of separately reporting biogenic and fossil fuel emissions. 

NAFO thus urges EPA to avoid any exemption from biomass reporting by adjusting the 

calculation methodologies. However, if EPA rejects this solution, it should narrowly tailor any 

final rule to address only provisions affecting the specific settling parties, and only to the extent 

they have demonstrated a legitimate need for special treatment under the Reporting Rule. NAFO 

also recommends that EPA further clarify that any adjustments to the regulations do not reflect 

any change in government policy regarding the treatment of biogenic emissions. In other words, 

NAFO requests that EPA confirm that the proposed rule does not change the well established 

significant distinctions that repeatedly have been recognized between biogenic and non-biogenic 

emissions, and that the only reason certain units may be allowed (as a last resort) to include 

biogenic emissions in their annual reporting of emissions is that they have demonstrated it is 

necessary to eliminate significant administrative and financial burden. Above all, EPA must 

ensure that any changes to the Reporting Rule are consistent with the government’s longstanding 

policy that there are significant distinctions between biomass and fossil fuel emissions and that 

biomass emissions are not counted when estimating CO2 emissions. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2375.2, excerpt 2, for the 

response to this comment. 

Commenter Name: David P. Tenny 

Commenter Affiliation: National Alliance of Forest Owners (NAFO) 

Document Control Number: EPA-HQ-OAR-2008-0508-2373.1 

Comment Excerpt Number: 5 

Comment: NAFO urges EPA to confirm that the proposed rule would not change, in any way, 

the fact that the Reporting Rule does not include biogenic CO2 in its reporting thresholds. 

Indeed, the proposed changes to the regulations (discussed above) relate only to the Reporting 

Rule’s requirements for annual reports. Biogenic emissions would still not be considered when 

entities conduct a threshold analysis to determine if the Reporting Rule’s requirements are 

triggered in the first place. 

Response: These rule amendments do not change how biogenic CO2 emissions are considered in 

a facility’s threshold analysis. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 6 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 
34 

Comment Excerpt Number: 5 

[These two commenters submitted identical comments on this subject.] 

Comment: Failure to Require Reporting from Biogenic Fuels. A key component in developing 

effective climate change policies and regulations is the creation of an accurate, science-based 

accounting system and inventory of biomass-related emissions that accounts for and enforces the 

complete spectrum of GHG emissions from biomass. To this end, we strongly oppose the 

proposed amendments to the GHG Monitoring and Reporting Rule regarding biogenic emissions 

contained in the proposed settlement between EPA and UARG. First, we explain why the final 

reporting rule requires biogenic CO2 emissions to be reported separately, including by source 

categories covered by subpart D. Second, we explain why, if implemented, EPA’s proposed 

changes could significantly limit the information provided to the public and policy makers about 

the amount of biogenic CO2 emissions from these facilities. An accurate, economy-wide 

inventory of biogenic CO2 emissions is important because the evidence to date conclusively 

demonstrates that biomass is not inherently carbon neutral. In fact, recent studies indicate that in 

some instances replacing fossil fuels with certain types of biomass could result in net increases 

of GHG emissions. An accurate accounting system and inventory can only be developed based 

on robust and transparent reporting requirements for biogenic GHG emissions. 

The express language of the final reporting rule requires separate reporting of biogenic CO2

emissions for subpart D and other source categories. The terms in EPA’s proposed settlement 

with UARG would amend the final reporting rule to exempt facilities that report CO2 emissions 

pursuant to the requirements of the ARP, see 40 C.F.R. § 75.1 et seq., from separately reporting 

their biogenic CO2 emissions. This exemption would apply to certain types of electricity 

generation units (“EGUs”). See 40 C.F.R. § 98.2(a)(1)(i); see also 40 C.F.R. § 72.6. [Footnote: 

Certain other facilities that are not required to comply with the ARP but nonetheless do so would 

also be exempt from separately reporting their biogenic CO2 emissions. See 75 Fed. Reg. at 

48,790 (proposed 40 C.F.R. §98.33(a)(5)(iv)). For the sake of simplicity, throughout these 

comments these source categories and subpart D source categories are collectively referred to as 

“subpart D source categories.”] 

In the Proposed Rulemaking on Amendments, EPA states that “[w]e intended for the reporting of 

biogenic CO2 emissions to be optional for units subject to subpart D.” 75 Fed. Reg. at 48,751. To 

that effect, EPA states that subsequent to the issuance of the final reporting rule “EPA . . . has 

provided guidance that separate reporting of biogenic emissions for units subject to subpart D is 

optional.” Id. Again, as an initial matter, the ARP program does not and should not constrain 

EPA in the GHG context, as that program was not designed to inform climate change policies or 

to control the emissions of GHGs to combat climate change. 

The plain language of the final reporting rule, which clearly requires that subpart D units 

separately report their biogenic CO2 emissions, renders EPA’s subsequently stated intentions on 

the subject irrelevant. 40 C.F.R. § 98.3 sets forth the “general monitoring, reporting, and 

verification requirements” of the rule. See 40 C.F.R. § 98.3 (section title) . That section describes 

the contents of the annual report to be submitted by reporting facilities. 40 C.F.R. § 98.3(c). For 
35 

all facilities required to report direct emissions, with certain exceptions not relevant here, Section 

98.3(c) requires that “facilities [] report annual CO2, CH4, [and] N2O . . . as follows”: 

(i) Annual emissions (excluding biogenic CO2) aggregated for all GHG from all applicable 

source categories in subparts C through JJ of this part and expressed in metric tons of CO2e 

calculated using Equation A–1 of this subpart. 

(ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories in subparts 

C through JJ of this part. 

(iii) Annual emissions from each applicable source category in subparts C through JJ of this part, 

expressed in metric tons of each GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of 

this section. 

(A) Biogenic CO2. 

(B) CO2 (excluding biogenic CO2). 

(C) CH4. 

(D) N2O. 

40 C.F.R. § 98.3(c)(4)(i)-(iii). 

There is no exemption for subpart D source categories that comply with the requirements of the 

ARP. 

As we understand it, EPA’s argument essentially rests on its claim that, because subpart D does 

not explicitly provide for separate reporting of biogenic CO2 emissions, such reporting could be 

read as “optional” under the final rule. See 75 Fed. Reg. at 48,751. This position, however, is 

further belied by the required contents of the annual report per the provisions of the final 

reporting rule. 

In addition to the above listed requirements in Section 98.3(c), that section also requires that a 

facility report “[e]missions and other data for individual units, processes, activities, and 

operations as specified in the ‘Data reporting requirements’ section of each applicable subpart of 

this part.” 40 C.F.R. § 98.3(c)(4)(iv). The only logical reading of this separate requirement is that 

compliance with the monitoring and reporting requirements of each specific subpart governing 

covered facilities is in addition to these general reporting requirements. EPA’s reading therefore 

would render this separate requirement superfluous. C.f. TRW Inc. v. Andrews, 534 U.S. 19, 31 

(2001) (“It is a cardinal principle of statutory construction that a statute ought, upon the whole, to 

be so construed that, if it can be prevented, no clause, sentence, or word shall be superfluous, 

void, or insignificant.”) (citations and internal quotations omitted). Therefore, per the express 

language of the final rule, it is irrelevant that subpart D does not mandate separate reporting of 

biogenic CO2 emissions. EPA in the Proposed Rulemaking on Amendments concedes that the 

plain language of the finalized reporting rule requires separate reporting of biogenic CO2

emissions from source categories covered by subpart D: 

Section 98.3(c)(4) . . . requires sources to report facility-wide GHG emissions, excluding 

biogenic CO2, and to report CO2 emissions for each for each category excluding [sic] biogenic 

CO2 emissions. To meet these reporting requirements, facilities with subpart D and/or other Part 

75 Units would have to separately account for the biogenic CO2 emissions (if any) from those 

units. 75 Fed. Reg. at 48,751 (emphasis added). Therefore, EPA itself acknowledges that the 
36 

provisions of the final rule requiring separate reporting of biogenic CO2 emissions are 

“requirements” applicable to source categories covered by subpart D or that otherwise comply 

with the requirements of the ARP. 

Further, it is irrelevant that, since the promulgation of the final reporting rule, EPA has issued 

Guidance [Footnote: Based on recent communications with EPA, we believe that this guidance 

refers to a response to a question sent via the “hotline” established for the final reporting rule. 

We believe that this “hotline” is the “Rule Help Center” webpage at 

http://www.epa.gov/climatechange/emissions/ghgrule_contactus.htm. It is our understanding that 

responses to questions sent via this webpage are provided only to the sender of the question and 

not available for retrieval otherwise. We also note that we were unable to find similar statements 

by EPA through its electronic “Frequently Asked Questions” system by performing separate 

searches for the “biogenic,” “biomass,” and "Acid Rain Program." 

http://www.epa.gov/climatechange/emissions/ghg_faq.html. Given the difficulty we encountered 

in identifying and obtaining this guidance and the importance of transparency with respect to the 

GHG reporting requirements, we urge EPA to make all guidance relating to the final reporting 

rule readily accessible at http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.] 

indicating that separate reporting of biogenic CO2 emissions for subpart D source categories is 

optional. See id. The United States Court of Appeals for the D.C. Circuit has made it clear that 

“[o]nce an agency gives its regulation an interpretation, it can only change that interpretation as 

it would formally modify the regulation itself: through the process of notice and comment 

rulemaking.” Paralyzed Veterans of America v. D.C. Arena L.P., 117 F.3d 579, 586 (D.C. Cir. 

1997). The guidance exempting subpart D source categories from separately reporting their 

biogenic CO2 emissions constitutes a “re-interpretation” of the reporting rule as finalized 

because, as explained above, it clearly contradicts the express requirements of the final reporting 

rule. As such, it is not an interpretive rule that “only reminds affected parties of existing duties,” 

Assoc. of Am. RR v. Dept. of Transp., 198 F.3d 944, 947 (D.C. Cir. 1999) (internal quotations 

and citations omitted), but rather a substantive rule re-interpreting the final reporting rule to 

exempt subpart D facilities from the existing requirements of the final reporting rule. See 

Paralyzed Veterans of America, 117 F.3d at 587-88 (stating that a substantive rule is one that has 

the force and effect of law and that intends to create new rights or duties). Therefore, EPA’s 

issuance of guidance on this subject is insufficient to modify the requirements of the final 

reporting rule. See id. at 586. [Footnote: Further, it is irrelevant that EPA in its “Response to 

Comments” stated that subpart D source categories are not required to separately report biogenic 

CO2 emissions and that the methodologies in Section 98.33(e) are optional. U.S. EPA, 

Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments, Vol. No. 16, 

Subpart D – Electricity Generation, 21 (Sep. 2009), available at 

http://www.epa.gov/climatechange/emissions/responses.html “Agency interpretations of their 

own regulations have been afforded deference by federal reviewing courts for a very long time 

and are sustained unless plainly erroneous or inconsistent with the regulation.” Paralyzed 

Veterans of America, 117 F.3d at 584 (emphasis added, internal quotations and citations 

omitted). Because the exemption proposed in the guidance directly conflicts with the express 

requirements of the final reporting rule, it should receive no deference. This is particularly true 

because, as stated before, EPA concedes that separate reporting of biogenic CO2 emissions for 

subpart D source categories is a “requirement” of the final reporting rule. 75 Fed. Reg. at 48,751. 

Moreover, given that the rule expressly requires that subpart D source categories separately 
37 

report biogenic CO2 , it is of little import that section 98.33(e) provides that those source 

categories “may use” the methodologies to calculate these emissions. 40 C.F.R. § 98.33(e)(2).] 

We emphasize that there may be additional arguments that the final reporting rule requires 

separate reporting of biogenic CO2 emissions from subpart D and other facilities complying with 

the requirements of the ARP or that the guidance EPA has issued has no substantive effect, and 

that these comments are not meant to be exhaustive on these issues. 

Response: EPA disagrees with the commenter that the 2009 final rule required separate 

reporting of biogenic CO2 emissions for subpart D units, which is why this final rule does not 

impose that requirement until reporting year 2011. The 2009 final rule clearly stated that if there 

are any inconsistencies between the general provisions in subpart A and a source category 

subpart, the source category subpart takes precedence. 40 CFR 98.1(b). Subpart D required 

reporting of CO2 reporting “as required under § 75.13... and § 75.64,” and those sections of Part 

75 do not require separate reporting of biogenic CO2 emissions. The only additional requirement 

under the GHG reporting rule regarding CO2 emissions from subpart D units was a conversion of 

short tons to metric tons. Thus, to the extent there are any inconsistencies with the general 

provisions regarding reporting of biogenic CO2 emissions and subpart D, subpart D takes 

precedence. This is consistent with statements in the 2009 proposed rule that “[f]or ARP units, 

the CO2 mass emissions data already reported to EPA under part 75 would be used in the annual 

GHG emissions reports required under this proposed rule." 75 FR at 16486. Moreover, 

contemporaneous with the final rule, in response to comments, EPA stated that 

It is EPA's intent that Acid Rain Program units will be able to continue to measure and 

report CO2 emissions as they do under the Acid Rain Program. EPA believes that this will 

reduce the reporting burden on sources, and for this reason has not required Acid Rain 

Program units to report biogenic emissions separately. However, EPA has provided a 

method for Acid Rain Program units which choose to separately quantify their biogenic 

CO2 emissions; see §98.33(e) of the final rule. 

Thus, contrary to commenters’ argument, EPA’s subsequent responses to questions on this topic 

were not a change in interpretation. 

Please see Section II.C of the preamble to the final rule amendments for additional information 

related to this comment. 

As noted by the commenter, we have developed and posted a Frequently Asked Questions 

database on the website for the Greenhouse Gas Reporting Program. This database can be found 

at http://www.epa.gov/climatechange/emissions/ghg_faq.html. Given that this is a new Program 

and EPA is receiving numerous questions, many of which have been submitted by others in the 

past, we decided to provide an FAQ database to support implementation. The website is clear, 

however that the searchable FAQ database is intended to provide general and administrative 

information about 40 CFR Part 98. The database does not provide legal advice, and responses to 

questions received by EPA do not have legally binding effect or expressly or implicitly create, 

expand, or limit any legal rights, obligations, responsibilities, expectations, or benefits in regard 
38 

to any person. Facility owners or operators and suppliers are responsible for determining how 

they would be affected by the requirements of 40 CFR Part 98. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 7 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 6 

These two commenters submitted identical comments on this subject. 

Comment: Separate reporting of biogenic CO2 emissions is necessary for the establishment of a 

transparent and complete inventory of economy-wide CO2 emissions. As explained in comments 

submitted by these organizations on the proposed mandatory monitoring and reporting rule, 

EPA’s decision to exclude biogenic CO2 emissions from the determination of whether a facility 

meets the 25,000 ton CO2 threshold was erroneous. However, we agree with EPA’s 

determination that once a facility’s emissions otherwise meet the reporting threshold, the facility 

must report its biogenic CO2 emissions and must report these separately from GHG emissions 

from the combustion of fossil fuels and other emission sources. See, e.g., 40 C.F.R. §98.2(b)(2). 

In the past, EPA has correctly stressed that “[a]ccurate and timely information on GHG 

emissions is essential for informing many future climate change policy decisions” and that 

facility specific data is particularly important for understanding factors that influence GHG 

emissions rates and identifying actions and facilities that could reduce emissions. 74 Fed. Reg. at 

56,265. Further, EPA has stated that “[b]esides total facility emissions, it benefits policy makers 

to understand: (1) The specific source of emissions and the amounts emitted by each unit/process 

to effectively interpret the data and (2) the effect of different processes, fuels, and feedstocks on 

emissions.” Id. at 56,277. We agree. The terms of the proposed settlement agreement with 

UARG, however, run contrary to the principle underlying these statements. 

Allowing subpart D source categories to comply with the reporting requirements of the ARP 

alone could deprive the public of important information on the types of fuels being used and the 

amount of biogenic CO2 emissions at these large sources. Pursuant to the finalized mandatory 

monitoring and reporting rule and EPA’s proposed definition of “emission data”, 75 Fed. Reg. 

39,094, 39,101 (July 7, 2010), the information currently required to be reported and proposed to 

be made publicly available would allow the public to easily identify the amount of biogenic CO2

emissions, 40 C.F.R. § 98.3(a)(4)(ii), and in some cases the amount and fuel type being used, see 

40 C.F.R. § 98.33(e)(1) (directing parties that do not use CEMS to monitor CO2 emissions to 

calculate biogenic CO2 emissions based on fuel type and other emissions factors). We are 

concerned that the proposed amendments, which would not require subpart D source categories 

to report separately the amount of biogenic CO2 emissions, could deprive the public of this 
39 

valuable information. It is unclear whether this information could be derived from the reporting 

requirements of the ARP, and even if it could, it is not clear how burdensome such backcalculation would be to the public and policy makers. For instance, facilities reporting under the 

ARP are required in their quarterly electronic reports to indicate the type(s) of fuel used at each 

unit, the start and end dates of combustion for each type of fuel, and “whether the fuel is 

primary, secondary, emergency or start up fuel.” See 40 C.F.R. § 75.53(g)(1)(D); see also 40 

C.F.R. § 75.64(a)(2) (requiring electronic, quarterly reporting of certain information in 40 C.F.R. 

§ 75.53). The amount of biogenic CO2 emissions cannot be calculated by the public and policy 

makers from that information alone. This is further evidenced by the fact that the quarterly 

emissions reports under the ARP do not provide information regarding the amount of biogenic 

CO2 emissions or the amount of biomass used at a given facility. [Footnote: The quarterly reports 

are available through EPA’s website, http://camddataandmaps.epa.gov/gdm/index.cfm.] It is also 

unclear to us how regulators themselves would calculate the biogenic CO2 emissions from these 

facilities from this and other information required to be reported under the ARP. 

Moreover, the burden imposed upon subpart D facilities to calculate these emissions is of little 

consequence given the importance of this information in developing an accurate GHG emissions 

inventory to serve as a basis for effective climate change policies. Section 98.33(e) provides a 

calculation whereby facilities monitoring CO2 using CEMS may calculate in a straightforward 

manner the amount of their biogenic CO2 emissions. 40 C.F.R. § 98.33(e)(2) (74 Fed. Reg. at 

56,402). In addition, we see no reason to exempt subpart D source categories from the burden of 

separately reporting biogenic CO2 emissions, while imposing this burden on other source 

categories. 

Accurate information regarding the amount of biogenic CO2 emissions, in particular from the 

electricity sector, is of the utmost importance in developing effective climate change policies. 

The scientific evidence to date has dispelled the notion that all biomass is “inherently carbon 

neutral.” [Footnote: See, e.g., T. Searchinger et al., Fixing a Critical Climate Accounting Error, 

326 SCIENCE 527 (2009); Manomet Center for Conservation Sciences, Biomass Sustainability 

and Carbon Policy Study (June 2010) (“Manomet Study”); see also Environmental Working 

Group, Clearcut Disaster: Carbon Loophole Threatens U.S. Forests (June 2010) (“Clearcut 

Disaster”), available at http://www.ewg.org/clearcut-disaster]. This is particularly a concern 

when whole trees are used as a fuel source at utility scale electric generation facilities. For 

instance, the Manomet Study showed that in Massachusetts, replacing coal with biomass derived 

from whole trees would increase net GHG emissions through 2050 and would achieve only a 

19% reduction by 2100. That study also found that, if biomass replaces natural gas at electricity 

generation units in Massachusetts, there could be more than an 100% increase in GHG emissions 

though the year 2050.16 The study also found that by 2100, replacing natural gas with whole 

trees could cause a net increase of GHG emissions of 63%. 

Unfortunately, the scientific evidence dispelling the assumption of inherent carbon neutrality has 

not been fully taken into in account in federal and state policies that seek to reduce GHG 

emissions from the power and transportation sector. For instance, as explained above, EPA 

erroneously excluded biogenic emissions in determining whether a facility is required to report 

its GHG emissions. Until recently, in Massachusetts, woody biomass was considered to be 

carbon neutral and thus eligible to receive renewable energy credits. In response to mounting 
40 

scientific evidence that biomass is not inherently carbon neutral, the Commonwealth suspended 

the application of renewable energy credits to certain biomass facilities and commissioned the 

“Manomet Study.” In light of this study’s conclusions, the Commonwealth is in the process of 

revising its renewable energy policies with respect to biomass-fired facilities. 

As the experience in Massachusetts demonstrates, unless and until science-based policies are 

developed at the state and federal levels that fully account for the GHG emissions associated 

with biomass combustion, there is a great incentive for utility scale electricity generation 

facilities and other stationary combustion units to either switch wholesale to biomass combustion 

or to co-fire biomass and fossil fuels. For instance, one report from the Environmental Working 

Group, which was co-authored by Dr. Mary Booth, has concluded that in the United States, 118 

new biomass power plant and co-firing proposals that would use wood as a fuel are currently at 

various stages of the permitting process.18 Dr. Booth concluded that reaching a goal of 

generating 25% of electricity from renewable sources by 2025 “will require the equivalent of 

cutting between 18 and 30 million acres over the next 15 years” and “[b]y 2030, the equivalent 

of up to 50 million acres could be clear-cut[.]” As that report points out, 30 million acres is an 

area larger than the state of Pennsylvania. [Footnote: Clearcut Disaster: Carbon Loophole 

Threatens U.S. Forests (June 2010) (“Clearcut Disaster”), available at 

http://www.ewg.org/clearcut-disaster ]. Therefore, renewable energy and climate change policies 

that incentivize the use of biomass without an accurate assessment of the GHG emissions 

associated with those fuels could have unintended consequences, and have other detrimental 

environmental impacts. 

Some types of highly efficient facilities may result in GHG reductions in the nearer term when 

using biomass as compared to fossil fuels. For instance, the Manomet Study found that for oil 

thermal and combined heat and power plants, replacing fossil fuels with whole-tree biomass 

would result in 25% net reductions of GHG emissions by 2050. By 2100, replacing fossil fuels at 

these facilities with whole-tree biomass would result in net GHG emissions reductions of 42%. 

The finding of the Manomet Study that certain forms of biomass-based power generation can 

provide net GHG reductions within a useful time period as compared to fossil fuels reinforces 

the point that EPA must require EGUs to report biogenic emissions separately. Without 

empirical data on the emissions associated with biomass use at EGUs, EPA and other regulators 

will be hard-pressed to distinguish between biomass-to-power applications that increase net 

GHG emissions and those that do not. 

Given the significant scientific uncertainty about the impacts of shifting electricity generation 

from fossil fuels to biomass, the incidental burden placed on these facilities to separately report 

their biogenic CO2 emissions is of little consequence. We applaud EPA’s commitment to 

transparency with regard to the GHG emissions inventory and encourage it to publish as much 

information on its website as it is legally permitted. See 75 Fed. Reg. at 39,099. To that end, 

EPA should continue to prioritize, in conformity with its Congressional mandate, the 

development of a comprehensive GHG emissions inventory that covers “all sectors of the 

economy of the United States.” See Fiscal Year 2008 Consolidated Appropriations Act, Pub. L. 

No. 110-161, 121 Stat. 1844, 2128 (Dec. 26, 2007). It should also continue to prioritize 

providing timely and accurate information to both the public and to state and local authorities to 

aid in the development of GHG emissions reductions strategies. Amending the final reporting 
41 

rule to exempt certain facilities from having to separately report their biogenic CO2 emissions is, 

however, a step in the wrong direction and could deprive the public and state and local policy 

makers of important information regarding the use of biomass as a fuel source. To be clear, we 

are opposed to exempting these facilities from the separate reporting requirements of biogenic 

CO2 emissions under the final monitoring and reporting rule. However, should EPA should 

exempt these facilities, it should do so only upon a showing this information can and will be 

easily accessible to the public – and policy makers – pursuant to the reporting requirements of 

the ARP. 

Response: Please see Section II.C of the preamble to the final rule amendments for the response 

to this comment. Please see response to comment EPA-HQ-OAR-2008-0508-2398.1, excerpt 8, 

for the response to the comment regarding the congressional mandate. 

Content of annual report- other amendments 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 2 

Comment: Mexichem supports the EPA’s proposal to clarify that suppliers of industrial 

fluorinated GHGs only calculate and report GHG emissions in mtCO2e for those fluorinated 

GHGs that are listed in Table A-1 under 40 CFR 98.3(c)(5)(i). 

Response: We thank the commenter for the input. We have finalized the proposed 

requirement to report GHG emissions in mtCO2e for only those fluorinated GHGs that are listed 

in Table A-1 under 40 CFR 98.3(c)(5)(i). 

Recordkeeping 

Commenter Name: Tom Siegrist 

Commenter Affiliation: Koch Nitrogen Company LLC (KNC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2364.1 

Comment Excerpt Number: 1 

Comment: EPA’s proposal to modify the reporting requirements associated with missing data 

events will provide EPA with sufficient information to manage the program while simplifying 

the reporting obligations for reporters. (75 FR 48753) The current language at 40 CFR 98.3(g)(4) 

requires reporting of the cause of each missing data event, the duration of the event, the 

corrective actions taken, and the actions taken to minimize occurrence in the future. EPA has 

concluded that it does not need information regarding the duration of the event or the actions 

taken to minimize reoccurrence in order to administer the program. KNC agrees that information 

regarding the event’s cause and corrective actions taken should provide EPA with the 

information needed to evaluate the reliability of the data collection systems in place. Koch 
42 

Nitrogen Company, LLC (KNC) supports EPA’s proposal to focus its data collection efforts on 

those two areas. 

Response: We thank the commenter for the input. We have finalized the proposed amendments 

to require only the cause of the missing data event and the corrective actions taken. Please see 

Section II.E of the preamble for the final rule amendments for the response to this comment. 

Commenter Name: Brady W. Wassom 

Commenter Affiliation: Environmental Systems Corporation (ESC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2367.1 

Comment Excerpt Number: 2 

Comment: Environmental Systems Corporation (ESC) is also requesting that EPA allow the 

reporting requirements specified in 40 CFR 75 related to missing data events to satisfy the 

reporting requirements for missing data events specified in §98.3(c)(8). §98.3(c)(8) requires 

reporting of each data element for which a missing data procedure was used according to the 

procedures of an applicable subpart and the total number of hours in the year that a missing data 

procedure was used for each data element. 

In addition, §98.46 requires that the units subject to Subpart D follow the applicable missing data 

substitution procedures in 40 CFR 75 for CO2 concentration, stack gas flow rate, fuel flow rate, 

high heating value, and fuel carbon content. ESC believes that requiring the reporting of missing 

data events according to the requirements specified in §98.3(c)(8) duplicates the requirements in 

40 CFR 75 and will increase the reporting burden for our customers. For example, in the case of 

CO2 concentration, units subject to 40 CFR 75 report a method of determination code according 

to §75.57(e)(1)(viii) for CO2 concentration which specifies whether the value associated with 

CO2 concentration was a valid measurement or substitute value. Through the use of the method 

of determination codes, the source has already documented the number of missing hours in a 

reporting period and the methods used for determining each substituted value. Our hope is that 

EPA recognizes that: (1) facilities subject to the requirements of 40 CFR 75 already report 

missing data events to the EPA on a more frequent basis (quarterly) than required by 40 CFR 98, 

(2) such reporting satisfies the intent of the reporting requirements specified in §98.3(c)(8), and 

(3) EPA will add a clarifying statement to that effect in §98.3(c). 

Response: No rule change has been made as a result of this comment. It is true, as noted by the 

commenter, that some of the same information reported under 40 CFR part 75 is also required to 

be reported under the requirements of §98.3(c)(8). However, we have concluded that it is 

important for consistency and comparability across reporting facilities to have information for all 

missing data events reported under 40 CFR part 98 by all units at all facilities. 

We note that facilities reporting under 40 CFR part 98 may include units subject to 40 CFR part 

75 as well as other units. Again, for consistency across reporters under 40 CFR part 98 we have 

determined that it is necessary to have the information reported in one place. For additional 

information regarding a similar comment to the 2009 final rule, please see response to comment 

EPA-HQ-OAR-2008-0508-0165, excerpt 6 in Mandatory Greenhouse Gas Reporting Rule: EPA's 
43 

Response to Public Comments, Volume No.: 16, Subpart D—Electricity Generation available at 

http://www.epa.gov/climatechange/emissions/downloads09/documents/SubpartDCommentReponses.pdf 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 2 

Comment: The final rule requires reporters to document the cause and duration of any missing 

data event, the action taken to restore the equipment, and the actions taken to minimize future 

occurrences. Under the proposed revisions, reporters are no longer required to document the 

actions taken to prevent future reduce missing data occurrences. Xcel Energy supports this 

change as it is consistent with current Part 75 requirements. 

Response: We thank the commenter for the input. We have finalized the recordkeeping 

requirements for missing data as proposed. Please see Section II.E of the preamble for the final 

rule amendments for the response to this comment. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 2 

Comment: Reporting requirements related to missing data procedures in §98.3(c)(8): Current 

language: “Each data element for which a missing data procedure was used according to the 

procedures of an applicable subpart and the total number of hours in the year that a missing data 

procedure was used for each data element.” Suggested language with proposed new language in 

square brackets: 

“Each data element for which a missing data procedure was used according to the procedures of 

an applicable subpart and the total number of hours in the year that a missing data procedure was 

used for each data element, [for the data elements with hourly collection frequency].” 

Incorporation of the requested change will provide clarification for instances where the number 

of hours related to missing data cannot be easily determined, for example if the data collection 

frequency is monthly, semiannual, or “twice a year at least four months apart”. 

Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. EPA proposed to amend the 

recordkeeping requirements for missing data events in 40 CFR 98.3(g)(4) for the reasons 

described in Section II.E of the proposal preamble. We did not propose to amend the reporting 

requirements related to missing data events. 
44 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 6 

Comment: IV. Information to Record for Missing Data Events Section 98.3(g)(4) as 

promulgated requires, for “each missing data event,” recording 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. As UARG described in its 

Reconsideration Petition, the requirement to record the cause of missing data periods and the 

corrective actions taken can be satisfied for units using CEMS by a simple notation in the 

maintenance log already required under Part 75, Appendix B, § 1.1.3 (maintenance records). See 

40 C.F.R. § 75.57(h). However, there are no requirements in Part 75 to separately record the 

“duration of the event” or the “actions taken to prevent or minimize occurrence in the future.” 

Instead, the duration of each missing data event is reflected in the hourly records in the quarterly 

reports (which are coded to indicate whether the data are from the CEMS or a missing data 

substitution procedure) and in the percent monitor availability that is calculated and recorded 

each operating hour. Any actions actually taken to prevent future missing data also would be 

reflected in the maintenance log as corrective action or maintenance. Requiring sources using 

CEMS, particularly those already complying with Part 75 recordkeeping, to develop additional 

records would be overly burdensome and of little usefulness. The majority of missing data 

periods associated with CEMS are of short duration and are due to routine activities or 

calibration failures for which there is no clear measure to prevent future occurrence. In response 

to UARG’s concerns, EPA proposes to revise § 98.3(g)(4) to remove the requirement to record 

the “duration” of all missing data events and the actions taken “to prevent or minimize 

occurrence in the future.” 75 Fed. Reg. at 48,753. EPA also proposes to revise § 98.47 to make 

clear that the records already being retained under § 75.57(h) are sufficient to satisfy this rule. 

EPA’s proposal is reasonable and necessary, especially with respect to CEMS. Requiring sources 

to record an action taken to prevent or minimize future occurrence when no such measure is 

available is not reasonable. Nor does EPA need a rule to require sources to try to prevent missing 

data. Sources already have adequate incentives to collect data from their monitoring systems, 

particularly under Part 75 where missing data procedures become increasingly punitive as the 

length of the missing data event increases and data availability falls. 

Response: EPA thanks the commenter for the input. We have finalized the recordkeeping 

requirements for missing data, as proposed. Please see Section II.E of the preamble for the final 

rule amendments for the response to this comment. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 7 
45 

Comment: EPA has offered no compelling justification for waiving some of its 40 C.F.R. § 

98.3(g)(3) recordkeeping requirements. EPA proposes to drop recordkeeping requirements for 

the duration of missing data events and for “corrective actions taken.” 75 Fed. Reg. at 45,752-53. 

It proposes to do so because the Part 75 Acid Rain Program reporting system does not have this 

requirement and some reporters have asserted that the continuous emissions monitoring systems 

(CEMS) used in that program do not offer reporters opportunities to take “clear measures to 

avoid” missing data events. Id. These rationales do not support EPA’s action. Initially, the design 

of the Acid Rain Program (“ARP”) bears only tangentially on appropriate requirements for the 

reporting rule, which is far more comprehensive and designed to create a broader range of data. 

But, even in the context of CEMS used in that program, tracking the duration of outages, and 

requiring operators to document what action, if any, they intend to take to correct outages, is 

useful and not burdensome. It creates incentives for accurate reporting, solely at the cost of a few 

electronic files saved on a reporter’s computer. More importantly, these justifications have no 

bearing on the far broader class of measurement systems EPA proposes to use in the reporting 

rule. The vast array of scales, meters, and monitoring systems reporters may use extends far 

beyond the relatively homogeneous universe of CEMS in the ARP. Even if EPA’s rationales for 

dropping missing data recordkeeping held true for ARP CEMS, it makes no sense to rely upon 

that narrow class of instruments to justify waiving these requirements for all other instruments. 

Indeed, it is precisely this broader class of mechanical systems that is more susceptible to 

corrective action, as some of its members, such as belt scales, may fail for mechanical reasons 

that could be corrected with preventative maintenance. EPA has offered no evidence whatsoever 

that waiving requirements is appropriate for any technology other than CEMS, and so it may not 

do so. At bottom, by making missing data harder to document, and errors harder to fix, EPA is 

imperiling the reporting system. It should drop these proposed changes. 

Response: We have finalized the recordkeeping requirements for missing data, as proposed. 

Please see Section II.E of the preamble for the final rule amendments for the response to this 

comment. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 7 

Comment: In its comments on UARG’s settlement, CATF objects to this revision. CATF argues 

that recording the duration of missing data events is not burdensome because sources already 

must know the duration in order to calculate missing data substitution procedures. CATF also 

asserts that, if there is no clear action available to prevent or minimize the occurrence, the 

requirement is not burdensome because there is not much to record. EPA-HQ-OGC-2010-0575- 

0014 at 6. CATF misses the point. The mere fact that sources can record the duration of each 

event separately (and separate from another report, like the Part 75 report) is not a rationale for 

requiring that it be recorded and CATF provides no independent reason for recording this 

information. With respect to actions to prevent future missing data, if the rule requires the 

recording of some action, the fact that there is no action that can be taken does not make the 
46 

recording more reasonable, it makes it impossible. Sources should not be required to make up 

unnecessary tests and actions simply to satisfy a rule. CATF also has offered no evidence that a 

rule requiring sources to record such actions, where they do exist, would add any incentive to 

preventing missing data or that sources do not already have adequate incentives to keep their 

monitoring systems operating. EPA should reject CATF’s comments. 

Response: We have finalized the recordkeeping requirements for missing data, as proposed. We 

agree with the commenter that just because source can record the duration of each event 

separately, does not provide sufficient rationale for requiring that it be recorded. As noted in 

Section II.E of the preamble for the final rule amendments we have concluded that the 

information on missing data events reported to EPA under 40 CFR 98.3(c)(8) as well as the 

recordkeeping requirements provide sufficient information for the GHG Reporting Program We 

also agree that commenters have not provided sufficient evidence that providing the additional 

information on missing data will provide any additional incentive to improve their monitoring 

practices. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 2 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 3 

These two commenters submitted identical comments on this subject. 

Comment: Missing Data Provisions Under the proposed UARG settlement, EPA would weaken 

the rule-wide missing data recordkeeping procedure. See 40 C.F.R. § 98.3(g)(4). UARG would 

remove recordkeeping requirements for the duration of a missing data event and would also 

replace records of “the actions taken to prevent or minimize occurrence in the future” with a 

requirement that companies document “corrective actions taken to restore malfunctioning 

monitoring equipment.” See 75 Fed. Reg. at 48,752-53. We do not support these changes. EPA 

justifies these changes because the Part 75 ARP “does not require separate accounting of the 

duration of [missing data] event[s] or . . . actions taken to minimize occurrence in the future.” 75 

Fed. Reg. at 48,753. These justifications are not compelling. Initially, the ARP’s requirements do 

not constrain EPA’s obligations in the greenhouse gas context. Because missing data periods 

allow global warming pollution to go unmeasured, they should be strictly documented and EPA 

and the public must be able to verify how long they have lasted, and how they will be prevented 

in the future. As to duration in particular, EPA’s concern that this requirement is “overly 

burdensome” is not compelling. See id. Reporters, presumably, would comply with the duration 

requirement by noting how long a system failed in their general report, or adding a “duration” 

column to their reporting spreadsheets. This small additional requirement is hardly burdensome. 

Indeed, to accurately use missing data procedures, reporters must know the duration of missing 
47 

data events and so must be collecting this information regardless. EPA should not waive the 

requirement. The changes to the “minimize occurrence” requirement are even less well-justified. 

EPA posits that because missing data events “associated with the use of continuous emissions 

monitors [(‘CEMS’)] are due to routine activities or calibration failures for which there are no 

clear measures to avoid similar occurrences in the future,” it should eliminate this requirement 

entirely. 75 Fed. Reg. at 48,753. But most facilities covered by the rule are not using CEMS; 

indeed, EPA designed the rule in part to avoid requiring CEMS. So, it does not make sense to 

waive the “minimize occurrence” requirement for this large class of reporters because a subset of 

facilities do happen to use CEMS. EPA should not be sacrificing incentives to minimize missing 

data events across the rule because this may be hard to do with some CEMS systems. Indeed, 

even for CEMS-users, EPA’s justification actually cuts the other way. If, in fact, there are few 

clear actions available to minimize the failure of these systems in the future, then reporters will 

not have much to record, and so will not be burdened. On the other hand, such a requirement 

might help CEMS users discover ways to minimize new system failures – which is also a 

positive result. The bottom line is that EPA’s concerns are ill-supported. By waiving 

recordkeeping requirements on the theory that some facilities may not have many records to keep 

(but, yet, are somehow “burdened”), it weakens requirements for all facilities, including ones 

whose reporting practices would improve with rigorous recordkeeping requirements. EPA should 

not make these changes. 

Response: We have finalized the recordkeeping requirements for missing data, as proposed. 

Please see Section II.E of the preamble for the final rule amendments for the response to this 

comment. 

Revisions to the annual GHG report 

Commenter Name: Caitlin Post 

Commenter Affiliation: Southern Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2377.1 

Comment Excerpt Number: 2 

Comment: EPA is proposing to amend 40 CFR 98.3(h) to clarify what triggers an annual report 

resubmission and the process for resubmitting the report. Southern Company supports these 

clarifications. The proposal makes it clear that only a substantive error, which is defined as “an 

error that impacts the quantity of GHG emissions reported or otherwise prevents the reported 

data from being validated or verified,” would require a report resubmission. This explanation is 

necessary because it is impractical to resubmit a report for an error that is unrelated to the 

reported emissions. The proposal also allows the owner or operator to demonstrate that the report 

does not include a substantive error or that the identified error is not substantive. Southern 

Company supports this proposal because there may be instances when something is incorrectly 

identified as a substantive error. 

Response: EPA thanks the commenter for the input. The requirements regarding resubmission 

of the annual GHG report have been finalized as proposed. Please see Section II.D of the 

preamble to the final amendments for additional information. 
48 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 5 

Comment: The § 98.3(h) reporting revision proposal clarifies how EPA and reporters may 

amend previously submitted GHG reports. However, Arkema requests that EPA clarify the term 

“substantive error” at proposed 40 CFR 98.3(h). Many errors are possible that would cause a 

reporter to misstate actual emissions by less than 5%, thus not impacting actual annual GHG 

emission rates. We request that, in the final preamble, EPA clarify that any error not be 

considered substantive unless it exceeds 1% to 5% of the total annual CO2 equivalent (“CO2e”) 

emission amount reported by an individual reporting facility. EPA should also modify the 

“contains one or more substantive errors” language to allow the agency flexibility to investigate 

potential as well as documented errors. Not all data anomalies detected by EPA staff may be 

errors. Specifically, reporters under the upcoming Subpart L, Fluorinated Greenhouse Gas 

Production, will be required to report GHG leak detection and repair (“LDAR”) emissions from 

manufacturing process equipment. LDAR emission rates of individual constituents in a 

manufacturing unit vary substantially from year to year. The many GHGs in a Subpart L facility 

exhibit a wide range of Part 98 Table A-1 global warming potential (“GWP”) values. Slight 

variations in fugitive leak rates from one section of a reporting facility could cause fugitive GHG 

emission rates to vary by orders of magnitude from one year to the next. None of this expected 

process variability constitutes an error, just normal manufacturing activity. As EPA noted at 

proposed § 98.3(h)(2), some data issues may require nothing more than a clarification statement 

from a reporter. 

Response: No rule change has been made as a result of this comment. Please see Section 

II.D of the preamble for the final rule amendments for the response to the request to further 

clarify the definition of “substantive error” and why EPA has determined that it is not 

appropriate to assign a quantity of emissions (as a percentage of total emissions reported) below 

which an annual GHG report does not have to be resubmitted. We have also concluded that no 

rule change is needed to address the commenter’s concern that normal process variability might 

wrongly be considered a “substantive error”. The final rule contains a provision that, within 45 

days, the owner or operator can either resubmit the report correcting any substantive errors or 

provide information demonstrating that the previously submitted report does not contain the 

identified substantive error or that the identified error is not a substantive error. Further, this 45 

day period may be extended upon request. We have concluded that this additional timing, as 

well as the ability for the owner or operator to demonstrate that errors are not substantive 

provides the flexibility requested by the commenter. 

Commenter Name: Jamie Mann 

Commenter Affiliation: Suncor Energy USA, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2389.1 

Comment Excerpt Number: 3 
49 

Comment: EPA is proposing to amend 40 C.F.R. § 98.3(h) to clarify how a resubmission is 

triggered and the process for resubmitting annual GHG reports. First, reports would only have to 

be resubmitted when the owner or operator or the Administrator determines that a substantive 

error exists. A substantive error would be defined as one that impacts the quantity of GHG 

emissions reported or otherwise prevents the reported data from being validated or verified. This 

clarification is important because some errors are not significant (e.g., an error in the zip code) 

and do not impact emissions. Such "errors" would not obligate the owner or operator to resubmit 

the annual report. The owner or operator would be required to resubmit the report within 45 days 

of identifying the substantive error, or the Administrator notifying them of a substantive error, 

unless the owner or operator provides information demonstrating that the previously submitted 

report does not contain the identified substantive error or that the identified error is not a 

substantive error. This proposed change would provide owners or operators the opportunity to 

demonstrate that what the Administrator has deemed to be substantive errors are not, in fact, 

substantive errors. 

The concept of a "substantive error" was not included in the original August 20, 2009, final GHG 

MRR rule. This concept appears to be very close to the "material misstatement" concept in the 

California AB32 Rules, which is defined in the rule as follows [§95102(113)]: 

Material misstatement’ means one or more inaccuracies identified in the course of 

verification that result in the total reported emissions, or reported purchases, sales, 

imports or exports of electricity, being outside the 95 percent accuracy required to receive 

a positive verification opinion. 

This term can be misleading because it is not an indication of the true accuracy of the emission 

estimate, but is rather an indication of the accuracy of the facility in performing the emissions 

estimate. In the California Air Resources Board (CARB) document entitled "Mandatory 

Reporting of Greenhouse Gas Emissions: Instructional Guidance for Operators", CARB clarified 

the term "material misstatement" is as follows (page 6-2): 

To enable a positive verification opinion, a GHG emissions data report must be found by 

the verification team to be free of material misstatement and to conform to the 

requirements of the regulation. For an emissions report to be free of material 

misstatement, the verification team must find that the report contains no errors that could 

not result in facility-wide CO2e emissions being less than 95 percent accurate. This 

means that errors in emissions estimation adding up to 5 percent of the overall facility 

CO2e emissions are allowed. For an emissions report to conform to the requirements of 

the regulation means that regulation standards and methods were observed by the 

operator in report preparation. 

The 5 percent materiality threshold for verification is different than the ±5 percent 

accuracy requirement for fuel use measurement required by section 95103(a)(9). Because 

the verification process allows for the inherent uncertainty associated with allowed 

instrumentation and emission factors, these additional uncertainties are outside the 

materiality threshold. The materiality threshold requires that emission factors and 

calculation methods be applied correctly, to ensure that no significant errors have been 
50 

made in the operator’s emissions calculation. Errors may be made that result in an 

overstatement or understatement of emissions, but as long as the absolute errors result in 

a less than 5 percent error in total facility CO2e emissions, the emissions data report is 

deemed acceptable." 

EPA has provided very little specific information on how the mandatory GHG inventory data 

would be used for a cap and trade program. As a result, "substantive error" is used to establish 

when an emission inventory should be resubmitted to the agency. A "substantive error" can be 

self determined or identified by the Administrator. Therefore, Suncor Energy U.S.A., Inc. 

(Suncor) proposes that the changes underlined below be made to the proposed rule definition of 

"substantive error": 

(3) A substantive error is an error that impacts the total quantity of GHG emissions 

reported for the affected facility or otherwise prevents the reported data from being 

validated or verified. A substantive error can occur if an emission factor or calculation is 

not correctly applied. A substantive error is different than an accuracy requirement, such 

as that for fuel gas metering in this rule. 

In addition to the above clarifications, a numerical value such as the five (5) percent of total 

emissions could be presented to allow a more quantitative measurement of "substantive error." 

The numerical value may be helpful in allowing the owner or operator to demonstrate if a 

"substantive error" has occurred. 

Response: No rule change has been made as a result of this comment. Please see Section II.D 

of the preamble for the final rule amendments for why EPA has determined that it is not 

appropriate to assign a quantity of emissions (as a percentage of total emissions reported) below 

which an annual GHG report does not have to be resubmitted. We have also not made any 

changes, as recommended by the commenter, to the definition of substantive error. We do not 

agree with addition of the suggested sentence that a substantive error can occur if an emission 

factor or calculation is not correctly applied. While the statement is true, it is not complete, as 

there are many other causes of substantive errors. For example, a facility might forget to report 

on a specific unit(s) or they may have used missing data procedures for an underlying parameter, 

but later realize that reporting could have been completed with actual data and missing data 

procedures were not necessary. These two events could trigger a resubmission, but would not 

specifically be related to an emission factor or incorrect application of an equation. 

It is clear that the process for resubmission of an annual GHG report, and the identified 

substantive error that leads to such resubmission, is different than any underlying accuracy 

requirements in the rule, as the latter refers to the calibration of the specific measurement 

technologies used to calculate GHG emissions. We have concluded that the suggested change by 

the commenter is unnecessary. 

Finally, the commenter notes that EPA has provided very little specific information on how the 

mandatory GHG inventory data would be used for a cap and trade program. As noted in the 

preamble to the 2009 final rule, the data collected under this rule will provide comprehensive and 

accurate data to inform future climate change policies. Potential future CAA and other climate 
51 

policies include a wide range of possibilities. Because EPA does not know at this time the 

specific policies that may be adopted, the data reported through this rule should be of sufficient 

quality to support a range of approaches (74 FR 56369). 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 3 

Comment: Reporting requirements related to annual GHG report revisions in §98.3(h)(1): 

Current language, including changes proposed by the EPA: “(1) The owner or operator shall 

submit a revised annual GHG report within 45 days of discovering that an annual GHG report 

that the owner or operator previously submitted contains one or more substantive errors. The 

revised report must correct all substantive errors.” Proposed language with suggested changes in 

square brackets: “(1) The owner or operator shall submit a revised annual GHG report within 45 

days of discovering that an annual GHG report that the owner or operator previously submitted 

contains one or more substantive errors [that cause a 10%+ change in emissions]. The revised 

report must correct all substantive errors.” 

Response: No rule change has been made as a result of this comment. Please see Section II.D of 

the preamble for the final rule amendments for why EPA has determined that it is not appropriate 

to assign a quantity of emissions (as a percentage of total emissions reported) below which an 

annual GHG report does not have to be resubmitted. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 4 

Comment: III. Requirements for Correction and Resubmission of Annual Reports. 

As promulgated, § 98.3(h) requires owners or operators to submit a revised report “within 45 

days of discovering or being notified by EPA of errors” in an annual GHG report. The revised 

report must correct “all identified errors.” As described in its Reconsideration Petition, UARG 

has a number of concerns regarding this rule provision. 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., 40 C.F.R. §§ 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 the errors in “calculation” of data EPA suggested should be 

corrected under its 2009 proposal. As promulgated, the rule appears to require resubmission for 

virtually any error identified by the source owner or operator without exception even if 

discovered years after the original submission was made. 
52 

Second, depending upon the mechanism EPA uses to define and identify “errors,” the rule could 

trigger a requirement for resubmission even when the report is accurate. Because designated 

representatives (DRs) are required to personally certify all GHG submissions as “true, accurate, 

and complete,” see § 98.4(e), any rule that would require a DR to submit and certify a revised 

report based on the Agency’s identification of an error, when the DR continues to believe that 

the original report is accurate, is not lawful. EPA cannot require DRs to certify what they do not 

believe. 

UARG’s concerns with § 98.3(h) arise as a result of its members’ experience with Acid Rain 

Program (ARP) reporting under Part 75. In that program, disagreements between EPA and DRs 

(particularly following a new rule, rule revision, or reporting format change) about the accuracy 

of reports are not uncommon. Disagreements can arise for many reasons, including as a result of 

differences in rounding methodologies, differences in rule interpretation, EPA’s use of the 

reporting “format” to collect information not otherwise required by rule to be submitted, and 

other errors or programming “bugs” in the electronic data QA checks used by to EPA to identify 

errors. Because EPA has said it intends to use similar electronic QA checks and procedures to 

identify errors in GHG annual reports, see, e.g., 75 Fed. Reg. at 48,762, 74 Fed. Reg. at 56,278, 

UARG anticipates that similar issues may arise under the GHG reporting program. 

Third, the current 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 openended requirement. 

In short, although UARG generally does not object to a requirement to correct and resubmit 

information an owner or operator believes to be in error, as long as the corrected information is 

of enough significance to be useful to EPA, UARG does object to any rule that allows EPA to 

require correction and resubmission where the owner or operator’s DR disagrees with that 

characterization. EPA proposes to address UARG’s concerns by revising § 98.3(h) to (1) require 

resubmission only for “substantive errors,” (2) preserve DRs ability to certify reports based on 

their own factual and legal determinations by allowing them to dispute EPA’s assertion of 

reporting errors, and (3) allow additional time for resolution of questions regarding identification 

of errors. 75 Fed. Reg. at 48,752. UARG believes this proposal is not only reasonable, but 

necessary. If EPA does not revise the requirement to allow DRs to dispute EPA’s error findings, 

EPA must remove the requirement for DR certification of the GHG reports. 

Response: EPA thanks the commenter for the input. The resubmission procedures in §98.3(h) 

have been finalized, as proposed. Please see Section II.D of the preamble to the final rule 

amendments for additional information. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 5 
53 

Comment: We are similarly concerned by EPA’s decision to substantially weaken the rule’s 

missing data and error correction systems. [See 75 Fed. Reg. at 48,752-53]. For the reasons 

explained in our settlement comments, we oppose EPA’s proposals to add a complex error 

correction system, which we believe would substantially increase paperwork and slow error 

correction, rather than improving information collection systems. We also continue to oppose 

EPA’s proposal to remove recordkeeping requirements that would otherwise document the 

duration of missing data episodes and what corrective action reporters need to take to avoid such 

incidents in the future. 

Both of these changes substantially weaken the rule. First, by converting an automatic, and 

largely ministerial, error correction system into a complex, quasi-adversarial system, EPA swaps 

quick error correction -- in just 45 days -- for an ongoing debate with operators over whether an 

error is “substantive,” a question which must be resolved before a correction would be made. See 

75 Fed. Reg. at 48,752. The idea, apparently, is to avoid “burdening” reporters with the need to 

resubmit reports where they have made some relatively minor error. But EPA proposes to use an 

electronic reporting system, so resubmitting a report should pose no great burden. On the other 

hand, the system EPA proposes – with reporters and EPA debating whether an error “impacts the 

quality of GHG emissions reported or otherwise prevents the reported data from being validated 

or verified,” id., creates a real burden, as reporters will then focus on dueling with EPA, rather 

than just fixing their mistakes. 

Making matters worse, EPA proposes to allow reporters to extend their resubmission deadlines 

during such debates by at least 30 days, and likely longer (EPA sets no limit on the number or 

length of these extensions, but should do so). See id. The result will be an unwieldy system, with 

various facilities at different phases in a drawn-out error correction process. This change is a 

mistake. EPA should stick with its basic, hard deadline of 45 days for resubmission, triggered by 

any error. As EPA acknowledges, because “it is important to ensure that the most accurate data 

are available,” a deadline is needed “to ensure EPA receives timely submission of data” and that 

most reporters simply do not need any extra time. See id. If there are odd outlier circumstances 

where more time is needed, or where resubmission is an insurmountable burden, EPA should 

deal with these instances by using its enforcement discretion, not by bending its core error 

correction system out of shape to deal with them. A strong, simple, rule is far preferable here. 

Response: Please see Section II.D of the preamble for the final rule amendments for the 

response to the comment on the resubmission procedures in §98.3(h). We do not agree with the 

commenter’s views that there is no burden associated with resubmission. While it is true that an 

electronic reporting format facilitates submission there are inevitably procedures in place at the 

facility to acquire any necessary additional information and have the report reviewed and 

approved for submission. Requiring facilities and suppliers to undertake these additional 

activities, no matter how small, for non-substantive errors, does not provide any additional value 

to the GHG data collected. 

Please see Section II.E of the preamble for the final rule amendments for the response to the 

comment on missing data procedures. 
54 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 5 

Comment: In comments on UARG’s settlement, CATF objected to this revision because it does 

not allow EPA to “trump” an owner or operator’s opinion. CATF also asserts that even 

nonsubstantive errors should be corrected because resubmitting a report is “just not that 

burdensome.” EPA-HQ-OGC-2010-0575-0014 at 7-8. As explained above, EPA cannot require a 

DR to certify the accuracy of a resubmitted report the DR does not believe is accurate. Nor can 

EPA require sources to submit information that is not required to be reported under the rules, or 

in a manner that is inconsistent with the rules. EPA cannot both refuse to subject its reporting 

format and system to rulemaking, and insist that source owners and operators comply with that 

system without any opportunity to dispute its content or requirements. EPA’s proposed rule 

represents a reasonable compromise under the circumstances. 

CATF also is without any basis to opine on the burdens associated with resubmission. EPA’s 

reporting format and system are still under development and, unless EPA has shared information 

with the CATF that it has not shared with the public, CATF has no idea what resubmission will 

entail. UARG’s experience under the ARP suggests that resubmissions may not be simple. 

Depending upon how EPA designs the system, resubmission of even one piece of information 

could require resubmission (and accordingly recertification) of the entire report. If the 

resubmission takes place after a change in DRs, the new DR also would need to certify the entire 

report. Resubmission also likely would require the resources of EPA staff to open the receiving 

system for resubmission and may require replacement of all of the previously submitted 

information in EPA’s central database. These details will not be known at least until EPA reveals 

the details of its reporting system later this year, and perhaps not until EPA actually opens its 

system for submissions. Unless EPA can establish, by subjecting the details of its reporting 

system, format, and error checking software to rulemaking, that its proposed resubmission 

requirement will be completely consistent with the rules and easy to implement, EPA must limit 

its resubmission rule to those elements critical to program implementation, and provide a 

reasonable process for resolving disputes. EPA should reject CATF’s comments. 

Response: EPA thanks the commenter for the input. The resubmission procedures in§98.3(h) 

have been finalized, as proposed. Please see response to comment EPA-HQ-OAR-2008-0508-

2398.1, excerpt 5 for the response to the comment on burden. Please see Section II.D of the 

preamble to the final rule amendments for additional information. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 3 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 
55 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 4 

These two commenters submitted identical comments on this subject. 

Comment: The Error Correction System. Per the UARG settlement, EPA has proposed a 

byzantine new error correction system. See 75 Fed. Reg. at 48,752. Under the existing rule, 

operators are required to “submit a revised report within 45 days of discovering or being notified 

by EPA of errors in an annual GHG report,” correcting all errors. 40 C.F.R. § 98.3(h). This 

simple requirement ensures that EPA’s database is always up-to-date and relatively error-free. 

EPA’s new proposal would mire that system in an odd, pseudo-adversarial process, which could 

take months or longer to correct some, but not all, errors. 

As we understand the proposal, the correction system would only be triggered for “substantive 

errors” – errors which “impact[] the quantity of GHG emissions reported or otherwise prevents 

the reported data from being validated or verified.” 75 Fed. Reg. at 48,782-83. This term is very 

much open to debate, as any error will somewhat affect reporting accuracy (even misidentifying 

the source’s location will make its emissions hard to track, for instance), and EPA invites such 

disputes. It allows operators, within 45 days of being notified of a substantive error, to show that 

they did not make such an error, or that the error is not substantive. Id. at 48,783. 

The proposed rule does not give EPA a clear method to dispute these points with operators, nor 

provide that EPA’s view trumps the operator’s opinion. Nor does it allow members of the public 

to argue that an error is, in fact, substantive, and must be corrected. If EPA retains this system, it 

must correct these flaws to prevent operators from blocking error correction by denying their 

mistakes are substantive. 

That assumes, however, that operators even respond promptly; they may avoid doing so under 

the proposed rule. There, EPA is allowed to “provide reasonable extensions of the 45-day period 

for submissions of the revised report” – or “substantive error” claims – and must grant a 30 day 

extension if an operator requests one “at least two business days” before the period expires. Id. 

The Administrator may then extend the extension still further, by whatever amount “is 

reasonable.” Id. 

As a result, operators and EPA may take months, perhaps years, to correct errors, and may still 

refuse to correct some of them. This is a radical departure from the existing rule, and serves only 

to hinder what was a straight-forward and effective process. 

EPA’s justifications are not compelling. First, as EPA states in the preamble to the proposed rule, 

“the 45-day time period is a sufficient time period for the vast majority of facilities.” 75 Fed. 

Reg. at 48,752. In the very rare cases where a facility takes longer, EPA assuredly has 

enforcement discretion to allow a few delays. It has no warrant to eviscerate the process as a 

whole because of such possibilities. 

Second, there is really no good reason to adopt the “substantive error” dispute process. 

Resubmitting a report is just not that burdensome – indeed, even without any error correction 
56 

system, sources in the ARP have submitted revised data “in less than 45 days after notification or 

identification of an error.” 75 Fed. Reg. at 48,752. Resubmitting is, certainly, far less 

burdensome that arguing with EPA about whether an error is “substantive.” In any event, if EPA 

really is concerned about additional paperwork, it might allow facilities simply to submit error 

reports, correcting specific data points in their reports, rather than resubmitting all data. 

These changes, in sum, cause problems instead of solving them. They imperil data quality, 

violating EPA’s statutory mandates. EPA should abandon them. 

Response: Please see Section II.D of the preamble for the final rule amendments for the 

response to this comment. 

Calibration and accuracy requirements 

Commenter Name: Bert Kalisch 

Commenter Affiliation: American Public Gas Association (APGA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2358.1 

Comment Excerpt Number: 1 

Comment: In response to comments from APGA and others to EPA on the proposed rule, EPA 

added a new section 98.3(i)(4) to the final rule intended to exempt fuel billing meters from the 

annual calibration requirements under the rule. APGA applauds EPA’s decision since few, if 

any, utilities have the equipment and resources to annually calibrate all their customer meters. 

Furthermore, as our comments pointed out, utilities have a vested interest in maintaining the 

accuracy of these meters which are the “cash registers” of the utility business. EPA chose, 

however, not to exempt fuel billing meters that serve facilities owned by the owner of the utility. 

The new section reads as follows: 

98.3(i)(4) Fuel billing meters are exempted from the calibration requirements of this 

section, provided that the fuel supplier and any unit combusting the fuel do not have any 

common owners and are not owned by subsidiaries or affiliates of the same company. 

As this provision was not in the proposed rule, APGA did not have the opportunity to provide 

comments on it during the comment period of the April 10, 2009 notice of proposed rulemaking. 

For public gas utilities which are governmental entities owned by the communities they serve, 

which in turn are owned by the citizens of the communities, e.g. the utility’s customers, this has 

caused a great deal of confusion. It could be interpreted that public gas utilities must annually 

calibrate all customer meters, which APGA believe was not EPA’s intent. In addition it appears 

that the exemption would not apply to fuel billing meters serving government facilities such as 

city halls, courthouses, schools and other facilities because these facilities are owned by 

government entities that also own the utility. 
57 

APGA urges EPA to delete the phrase “provided that the fuel supplier and any unit combusting 

the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the 

same company.” 

EPA could also resolve the issue by clarifying that “company” as used in this section, does not 

include municipal gas distribution systems, public utility districts, county districts, or other 

public agencies that own and operate natural gas distribution facilities. Public gas utilities are not 

“companies.” 

Response: No rule change has been made as a result of this comment. This comment is out of scope to 

this rulemaking. The primary purpose of the proposed amendments to 40 CFR 98.3(i)(4) were to 

include an additional exemption from the calibration requirements of 40 CFR 98.3(i) for flow 

meters that are used exclusively to measure the flow rates of fuels used for unit startup or 

ignition. In addition, we also provided clarification that fuel billing meters are not only exempt 

from the calibration requirements but also the corresponding monitoring plan requirements. EPA 

did not propose to make any changes to the definition of company in 40 CFR 98.3(i)(4), nor did EPA 

propose to modify which fuel billing meters are exempted by 40 CFR 98.3(i)(4). However, EPA disagrees 

with the commenters assertion that Part 98 in any way implies a publicly owned and operated natural gas 

utility could be required to calibrate all customer meters. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 21 

Comment: In various parts of the rule EPA uses the terms “consensus-based standards 

organizations” and “industry consensus standard practice.” However, these are also referred to 

as “consensus standards organization” and “industry standard practice” in other parts of the rule. 

The first terms are more descriptive and should be used throughout the rule as follows: 

§98.3(i)(1) ***Rather, each of these measurement devices shall be calibrated to meet the 

accuracy requirement specified for the device in the applicable subpart of this part, or, in 

the absence of such accuracy requirement, the device must be calibrated to an accuracy 

within the appropriate error range for the specific measurement technology, based on an 

applicable operating standard, including but not limited to industry consensus standards 

and manufacturer’s specifications.*** 

§98.33(a)(3)(iv) *** You may use a method published by a consensus-based standards 

organization, if such a method exists, or you may use industry consensus standard 

practice.*** You may use a density meter calibrated according to the manufacturer’s 

instructions, a method published by a consensus-based standards organization, or an 

industry consensus standard practice.*** 

§98.34(a)(6) *** You may use a method published by a consensus-based standards 

organization, if such a method exists, or you may use industry consensus standard 

practice to determine the high heat values.*** 
58 

§98.34(b)(1)(i)(A) You may use an appropriate flow meter calibration method published 

by a consensus-based standards organization if such a method exists.*** 

§98.34(b)(4) *** You may use a method published by a consensus-based standards 

organization, if such a method exists, or you may use industry consensus standard 

practice to determine the carbon content and molecular weight (for gaseous fuels) of the 

fuel.*** 

Response: EPA agrees with the commenter in part, and has incorporated the recommended 

change to refer to “consensus-based standards organizations.” We have closely reviewed the 

suggestion to insert “consensus” after industry to refer to “industry consensus standards.” For 

some industries, there may be a difference between an “industry consensus standard” and an 

“industry standard,” the latter of which could be broader and include standards not adopted by 

consensus-based organizations. When referring to industry standard practices or methods, we 

wanted to maintain sufficient flexibility to allow appropriate practices or methods to be used, as 

appropriate, that are commonly used by a particular industry. We determined that not all of these 

practices and methods would necessarily be adopted by a “consensus” organization and did not 

want to introduce such a limitation in the final rule. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2396.1 

Comment Excerpt Number: 3 

Comment: The Proposed Rule does not apply consistent nomenclature when referring to 

methods or procedures, and this could cause confusion. For example, in addition to referencing 

“consensus methods” or “industry standard practices”, Subparts A and Subpart C also use the 

following terms: “industry consensus standard method”; “industry consensus standard practice”; 

“industry consensus standard”; “industry consensus calibration schedule”; and, “industryaccepted or industry consensus standard calibration practice”. The Interstate Natural Gas 

Association of America (INGAA) understands that rule requirements regarding “methodology” 

in Subparts A and C generally follow one of three criteria: (1) consensus method (from a 

standards organization); (2) manufacturer specification; and/or (3) industry standard practice. For 

clarity, methodologies should be consistently referred to using the same nomenclature and 

INGAA recommends these three terms. 

Response: Please see the response to comment EPA-HQ-OAR-2008-0508-2357.1, excerpt 21, 

for the response to this comment, particularly with respect to whether the term “consensus” is 

used after “industry’ to refer to “industry consensus standard practices”. In addition, we note 

that the commenter does not appear to make a distinction between industry “practices” and 

industry “standards” or “methods.” We recognize that both of these terms are used in the final 

rule. We concluded that for some industries, a “practice” might not be considered an actual 

“method.” We did not want to introduce such a limitation in the final rule by switching all uses 
59 

of the term “practice” to “method,” nor, conversely did we want to open up all uses of the term 

“method” to “practice.” 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2396.1 

Comment Excerpt Number: 4 

Comment: The Interstate Natural Gas Association of America (INGAA) strongly recommends 

accepting “industry standard practices” as an option for flow meter calibration in Subpart A and 

Subpart C, and gas analysis / heating value measurement in Subpart C. Requirements in Subpart 

A and Subpart C for flow meter calibration (or associated temperature or pressure calibration) 

include confusing text noted above (e.g., “industry consensus standard practice”). When revising 

the text, EPA should ensure that “industry standard practices” are retained as an acceptable 

approach for flow measurement and calibration – including calibration frequency. Similarly, 

references related to fuel sampling and analysis in Subpart C use inconsistent nomenclature. 

When revising for consistent nomenclature, “industry standard practice” should be included as 

an acceptable approach for natural gas sampling and analysis, including heating value analysis. 

Company procedures consistent with industry standard practice will be documented in the GHG 

monitoring plan. 

Response: Under the final rule, the General Provisions require that devices be calibrated 

according to the manufacturer’s recommended procedures, an appropriate industry consensus 

standard method or a method specified in a relevant subpart of this part (see 40 CFR 98.3(i)). 

Recalibration must be at the frequency specified in each applicable subpart of this part, or where 

none is specified, at the frequency recommended by the manufacturer or by an industry standard 

practice (see 40 CFR 98.3(i)). We agreed with the commenter and removed the term 

“consensus” after “industry” under subpart C so that flow meters must be calibrated using a 

method published by a consensus-based standards organization or an industry-accepted practice. 

Fuel sampling and analysis may be performed using manufacturer’s instructions, methods 

published by a consensus-based standards organization if such a method exists, or an industry 

standard practice. 

Please see response to comment EPA-HQ-OAR-2008-0508-2357.1, excerpt 21 for the response 

to the comment about consistent nomenclature. . 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 3 

Comment: ACC supports EPA’s changes to the MRR language regarding calibration 

requirements. 
60 

Response: EPA thanks the commenter for the input. In general, we have finalized the 

calibration requirements, as proposed. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 3 

Comment: Under the proposed rule issued August 11, 2010, fuel flow meter calibration 

requirements do not apply when the use of company records is allowed, or for units calculating 

CO2 mass emissions via Part 75. In addition, the proposed rule adds exemptions for fuel billing 

meters and for fuel flow meters when used exclusively during unit start-up or ignition. Xcel 

Energy supports these exemptions because it reduces reporting burden, while maintaining the 

integrity of the emissions report. 

Response: EPA thanks the commenter for the input. In general, we have finalized the 

calibration requirements, as proposed. We would note that we have removed the term ignition 

from the calibration exemption provision in 98.3(i). Based on comments received, the inclusion 

of the term ignition had suggested that you need to calculate emissions from all ignition fuels, 

which is inconsistent with the amendment finalized in 98.30 that reporters don’t need to report 

emissions from pilot lights. If a fuel is used for ignition, but does not meet the requirements 

necessary to be considered fuel for a pilot light, the ignition fuel may be more generally referred 

to as a startup fuel and the emissions from consumption of the fuel would still be reported, but 

the calibration exemption would still apply. Please see Section II.B of the preamble for the final 

rule amendments for the response to this comment. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 5 

Comment: §98.3(i)(4): This proposed revision provides an exemption from the calibration 

requirements for fuel meters exclusively used for startup or ignition purposes. GHG emissions 

from startup and ignition sources are extremely small compared to the normal operational fuel(s) 

emissions. This is a reasonable and insightful change that will reduce the unnecessary calibration 

burden for all sources that employ these devices. Weyerhaeuser supports this revision 

Response: EPA thanks the commenter for the input. Please see response to comment EPA-HQOAR-2008-0508-2374.1, excerpt 3 and Section II.B of the preamble for the final rule 

amendments for the response to this comment. 
61 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 20 

Comment: API supports the revision of §98.3(i)(4) – Fuel billing meters are exempt from the 

Monitoring Plan and recordkeeping provisions. Meters used exclusively to measure the flow 

rates of fuels used for unit startup or ignition are also exempt from the calibration requirements. 

Response: EPA thanks the commenter for the input. Please see response to comment EPA-HQOAR-2008-0508-2374.1, excerpt 3 and Section II.B of the preamble for the final rule 

amendments for the response to this comment. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 3 

Comment: §98.3(i): This proposed revision provides clarification regarding flow meter 

calibration and the associated accuracy requirements. This revision clarifies that calibration 

requirements do not apply when company records are used. Weyerhaeuser agrees with this 

revision because the definition of “company records”, as provided in §98.3(6), does not require 

any specific calibration methodology or meet any accuracy standard. Therefore, this revision 

provides the needed consistency with the definition. Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. In general, we have finalized the 

calibration requirements, as proposed. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 4 

Comment: §98.3(i)(1): This proposed revision allows the use of applicable operating standards 

(e.g. industry standards, manufacturer’s specifications, etc.) when calibrating measurement 

devices. This revision provides greater flexibility for sources to determine the appropriate 

calibration methodology best suited for their operation. This revision properly addresses the 

issue of establishing the percent calibration error, rather than specifying a universal value that 

would apply to all measurement devices. Weyerhaeuser supports this revision 

Response: EPA thanks the commenter for the input. The ability to use applicable operating 

standards has been finalized, as proposed. 
62 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 6 

Comment: The calibration requirements of 40 CFR 98.3(i)(2) are not applicable to the 

manufacturer’s recommended procedures for coriolis meters. Mexichem has installed coriolis 

meters in order to meet certain accuracy requirements of the rule. 40 CFR 98.3(i)(2) requires that 

the calibration error be calculated at each flow meter measurement point for flow meters other 

than orifice, nozzle, and venturi meters. Therefore, coriolis meters would be subject to this 

requirement. Micro Motion’s Recommended Calibration Practices for Coriolis meters used to 

comply with EPA 40 CFR part 98, Green House Gas regulations is to utilize an initial factory 

calibration in which the % error at each measurement point is calculated and then, for those 

meters equipped with on-board Meter Verification (MV), to perform the verification once per 

quarter. If the meter passes the MV, then it is within the manufacturer’s specification. The EPA 

should ensure §98.3(i) contains provisions for coriolis meters and the manufacturer’s 

recommended procedures for calibration. Micro Motion’s recommended procedure is located at: 

http://www.documentation.emersonprocess.com/groups/public_public_mmisami/documents/arti

cles_articlesreprints/mm028843.pdf. 

Response: The calibration requirement of 40 CFR 98.3(i)(1) specifies that flow meters must be 

calibrated according to a manufacturer’s recommended procedure, an appropriate industry 

consensus standard, or the relevant subpart in the rule. As specified in 40 CFR 98.3(i)(5), 

recalibration must be performed according to the manufacturer’s recommended schedule or the 

appropriate industry consensus calibration schedule. If an individual subpart specifies that meter 

calibrations must be performed, the procedures of that subpart must be followed. If the 

manufacturer can provide documentation showing that their calibration schedule will satisfy the 

calibration accuracy requirements of 40 CFR 98.3(i)(2) for flow meters, then the calibration 

procedures and schedule specified by the manufacturer will be valid. As such, EPA finds that no 

further amendments need to be made to accommodate the use of coriolis meters. Regardless of 

the aforementioned requirements, the monitoring plan requires a description of the procedures 

and methods that are used for quality assurance, maintenance, and repair of all continuous 

monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs 

reported under Part 98. The manufacturer’s initial calibration of a coriolis meter must meet the 

accuracy requirements of §98.3(i)(2). If it does not, a recalibration is required. Once 

compliance with the accuracy specification has been demonstrated, the manufacturer’s 

recommended recalibration frequency (i.e., recalibrate when the quarterly MV diagnostic test is 

failed) may be applied. If the commenter elects to use the manufacturer’s recommended 

calibration schedule, the monitoring plan must include a reference to the documentation that 

establishes how the manufacturer’s calibration schedule will continuously meet the applicable 

calibration accuracy requirements of Part 98. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 
63 

Comment Excerpt Number: 1 

Comment: The Clean Air Task Force, Natural Resources Defense Council, and Sierra Club 

(collectively, CATF) opposes the Settlement Agreement’s revision to the instrument calibration 

requirements of 40 C.F.R. §98.3(i) in place of an across-the-board five percent accuracy 

standard. These revisions are critical, however, because they would specifically tailor calibration 

requirements to the pertinent equipment and practices in place in the industry, and thus would 

better accommodate the complexities of the metering and instrumentation systems in a 

sophisticated refinery or petrochemical manufacturing complex. Contrary to CATF’s assertions, 

the changes would not undermine the accuracy of the data. Rather, because the revisions would 

improve the workability of the rule, they are expected to improve the accuracy of the data 

reported. 

Response: EPA thanks the commenter for the input. We have finalized the accuracy 

requirements, as proposed. Please see Section II.B of the preamble for the final rule amendments 

for the response to this comment. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 1 

Comment: I. Subpart A Calibration Requirements. As promulgated, § 98.3(i) requires (subject 

to some limited exceptions) that all flow meters and other devices that measure data used to 

calculate GHG emissions be calibrated prior to April 1, 2010 according to both the procedures 

specified in paragraph (i) and each relevant subpart of Part 98. In its Reconsideration Petition, 

UARG objected to the Agency’s failure to reflect in this provision its intent to exclude certain 

other types of data from the general calibration requirement. 

For example, the provision appears to require calibration of fuel flow meters (and other devices) 

used for “company records” under Tiers 1 and 2, and for “best available information” under 

various provisions, to meet the same accuracy specification as fuel flow meters required under 

Tier 3. Requiring calibration of fuel flow meters used to obtain data under provisions that are 

specifically designed to rely on existing data (rather than require new or revised monitoring) 

makes no sense. Recognizing this, EPA staff and contractors stated a number of times in training 

sessions on the final rule that fuel flow meters that are not otherwise required under the rule do 

not have to meet the calibration requirements of the rule. However, because that intent was not 

explicitly reflected in § 98.3(i), UARG is concerned that some could argue that the requirement 

applies despite EPA’s statements. The provisions of § 98.34(g) addressing monitoring plan 

requirements related to “company records” also could be misinterpreted to suggest that sources 

must employ new or different procedures to ensure the accuracy of devices used to create those 

records. 

Similarly, § 98.3(i) also includes no exception for sources already complying with the detailed 

calibration requirements for fuel flow meters under 40 C.F.R. Part 75 (Part 75), Appendix D § 2, 
64 

the data from which must be used to report emissions and heat input from electricity generating 

units under Subpart D. As a result, UARG is concerned that some could argue that sources 

reporting under Subpart D must comply with the requirements of both rules. 

To address these inconsistencies, EPA proposes to revise § 98.3(i) to make clear that the 

accuracy specifications in that provision do not apply to the use of “company records,” “best 

available information,” or fuel flow meters or other equipment already meeting the requirements 

of 40 C.F.R. Part 75, and to remove § 98.34(g). 75 Fed. Reg. at 48,750, 48,792. These revisions 

are not only reasonable, they are necessary to ensure that that rule is consistent with EPA’s intent 

not to impose additional monitoring in these cases. 

In comments on UARG’s settlement, the Clean Air Task Force, et al. (CATF) objects to EPA’s 

exclusion of Part 75 sources and “company records” from the calibration requirements in § 

98.3(i), arguing that the amendment would destroy the uniform accuracy requirements of the 

rule. EPA-HQ-OGC-2010-0575-0014. at 3-4. CATF misconstrues the rule. EPA never intended 

to impose these new accuracy specifications on the types of information addressed in the 

proposed revision. In the 2009 final rule, EPA determined that the burden associated with certain 

new monitoring requirements was not justified under some circumstances and adopted a tiered 

approach to monitoring. With respect to Part 75, EPA determined that the monitoring in Part 75 

was more than adequate and therefore required sources already subject to Part 75 to utilize data 

collected under that rule to report under Part 98 Subpart D. EPA’s proposed revisions to § 98.3(i) 

to exclude certain types of data simply make this poorly worded provision consistent with EPA’s 

intent and the rest of the rule. EPA should reject CATF’s comments. 

Response: EPA thanks the commenter for the input. We have finalized, as proposed, that the 

calibration accuracy requirements of 40 CFR 98.3(i) do not apply where company records are 

used. Please see Section II.B of the preamble for the final rule amendments for the response to 

this comment. 

Commenter Name: Jamie Mann 

Commenter Affiliation: Suncor Energy USA, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2389.1 

Comment Excerpt Number: 2 

Comment: EPA has proposed to amend 40 C.F.R. § 98.3(i)(3) to add five conditions (hereafter 

referred to as Conditions 1 through 5) that must be met in order for a source to use assumed 

values for temperature and/or total pressure at the flow meter location, based on measurements 

of these parameters at a remote location (or locations). Conditions 1 through 5 are stated as 

follows: 

(1) The owner or operator would have to demonstrate that the remote readings, when corrected, 

are truly representative of the actual temperature and/or total pressure at the flow meter location, 

under all expected ambient conditions. Pressure and temperature surveys could be performed to 

determine the difference between the readings obtained with the remote transmitters and the 

actual conditions at the flow meter location. 
65 

(2) All temperature and/or total pressure measurements in the demonstration must be made with 

calibrated gauges, sensors, transmitters, or other appropriate measurement devices. 

(3) The methods used for the demonstration, along with the data from the demonstration, 

supporting engineering calculations (if any), and the mathematical relationship(s) between the 

remote readings and the actual flow meter conditions derived from the demonstration data would 

have to be documented in the monitoring plan for the unit and maintained in a format suitable for 

auditing and inspection. 

(4) The temperature and/or total pressure at the flow meter must be calculated on a daily basis 

from the remotely measured values, and the measured flow rates must then be corrected to 

standard conditions. 

(5) The mathematical correlation(s) between the remote readings and actual flow meter 

conditions must be checked at least once a year, and any necessary adjustments must be made to 

the correlation(s) going forward. 

Suncor Energy U.S.A., Inc. (Suncor) proposes that EPA delete the language "under all expected 

ambient conditions" and replace that language with "under standard conditions" in the Condition 

1 requirement "to demonstrate that the remote readings are truly representative of the actual 

temperature and/or total pressure at the flow meter location under all expected ambient 

conditions." The variability of temperature and pressure throughout a refinery fuel gas system is 

dependent upon several factors, not limited to only ambient conditions, but also to the presence 

of steam tracing, piping insulation, etc. Such a change in language is consistent with the 

requirement in Condition 4 that "the temperature and/or total pressure at the flow meter must be 

calculated on a daily basis from the remotely measured values, and the measured flow rates must 

be corrected to standard conditions. Without the requested change, an owner/operator could not 

satisfy Condition 1, notwithstanding that it satisfies Condition 4. 

Additionally, Suncor proposes that EPA clarify Condition 4 for the requirement that "the 

temperature and/or total pressure at the flow meter must be calculated on a daily basis from the 

remotely measured values, and the measured flow rates must then be corrected to standard 

conditions." Due to the dynamic nature of a refinery fuel gas system and the proposed 

conditions, it appears that the proposed rule requires the development of a dynamic model to 

provide daily correction factors at all expected ambient conditions which would require 

temperature and pressure data that is currently not collected. In order to collect data needed to 

develop the correlations, Suncor would need to install temperature and pressure measuring 

devices throughout the facility or commission an extensive survey of the fuel gas system. The 

first option invalidates the need to use remote temperature and pressure data and the purpose of 

the proposed rule change. The second option requires an extensive and costly survey of the fuel 

gas system as well as annual verification of the survey. Suncor believes that the cost to install 

temperature and pressure monitoring devices at all fuel flow meters was not considered in the 

cost analysis for the rule as originally proposed or for the proposed changes. Suncor also believes 

that the burden imposed by these conditions (i.e., the ability to compensate for all ambient 

conditions on a daily basis through the use of detailed pressure and temperature surveys) is not 
66 

adequately reflected in the cost analysis for this proposed rulemaking despite the fact that it will 

require both significant initial and ongoing expenditures. Therefore, Suncor proposes that EPA 

allow owner/ operators the ability to calculate the temperature and/or total pressure at the flow 

meter using remote pressure and temperature data under standard conditions. 

Response: No rule change has been made as a result of this comment. The change recommended 

by the commenter to replace the words “under all expected ambient conditions” with “under 

standard conditions” is not appropriate because the goal of using remote temperature and 

pressure readings is to determine viable correlations between those readings and the 

actual conditions at the meter, over the range of ambient conditions typically encountered at the 

facility, and not just under standard conditions. The temperature correlation, in particular, can 

be affected by the outside air temperature. Although there may be other factors, as described by 

the commenter, that affect these correlations , we believe that data obtained through temperature 

and pressure (T and P) surveys, if documented as described above, can provide 

sufficiently reliable estimates of the temperature and pressure at the meter. 

The commenter also expresses concern about the cost associated with this approach, believing it 

would require an extensive survey of their fuel gas system and development of a "dynamic 

model" to provide daily correction factors. However, reporters are not required to conduct the 

remote surveys or to develop the correlations for temperature and pressure at the meter location. 

Use of remote transmitters is simply an option that is intended to reduce burden. It is also 

consistent with recommendations made by industry. Industry representatives have indicated that 

conditions at a flow meter can, in many cases, be reliably and accurately predicted 

from temperature and pressure readings made at locations remote from the flow meter. They 

have further suggested that temperature and pressure surveys can be performed to demonstrate 

this, and that "active compensation", which is the periodic, automated feed of the remote T and P 

measurements into the metering calculation system algorithms, is feasible (see Background 

Technical Support Document for Revisions of the Mandatory Reporting of Greenhouse Gases 

Rule in Docket HQ-OAR-2008-0508). Therefore, we have concluded that we should retain 

these optional procedures and finalize them, as proposed. If the commenter elects not to 

implement these procedures, then for each orifice, nozzle or venturi flow meter that is used to 

provide data for the GHG emissions calculations, if temperature and/or pressure transmitters are 

lacking, the necessary transmitter(s) must be installed and calibrated, in accordance with §

98.3(i)(3)(i). 

Commenter Name: Sean M. O'Keefe 

Commenter Affiliation: Alexander & Baldwin, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2380.1 

Comment Excerpt Number: 2 

Comment: EPA has also proposed to add clarifying language in section 98.3(i) (4) stating that 

flow meters used exclusively to measure flow rates of fuels "used for unit startup or ignition" are 

exempted from calibration requirements. EPA correctly notes in the preamble (page 48751) that 

"the amount of fuel used for ignition and startup generally provides a very small percentage of 
67 

the annual heat input (less than I percent in most cases)", making rigorous calibration of meters 

used exclusively for startup and ignition fuels unnecessary. 

Response: EPA thanks the commenter for the input. Please see response to comment EPA-HQOAR-2008-0508-2374.1, excerpt 3 and Section II.B of the preamble for the final rule 

amendments for the response to this comment. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 1, 2, 3, 4 

Comment: We are particularly concerned by EPA’s proposal to remove the rule-wide accuracy 

standard presently codified at 40 C.F.R. § 98.3(i). See 75 Fed. Reg. at 48,750-51. At present, that 

requirement requires that all “measurement devices . . . be calibrated to an accuracy of 5 

percent.” 40 C.F.R. § 98.3(i)(1). This sort of rule-wide accuracy requirement is necessary to 

provide cross-comparable and accurate data, as even small calibration errors can rapidly 

propagate through reporting data, producing major errors. For this reason, peer systems, 

including the European Union’s emissions reporting, requires regular “uncertainty assessments” 

and specifies accuracy requirements, including, for instance, a “maximum uncertainty” of just 

1.5% for large combustion sources. [See 2007/589/EC Commission Decision of 18 July 2007 

establishing guidelines for the monitoring and reporting of greenhouse gas emissions, Annex II 

at § 2.1.1.1, available at http://eurlex.europa.eu/LexUriServ/LexUriServ.douri=CELEX:32007D0589:EN:NOT , and attached as Ex 3]. It is therefore extremely troubling to 

see EPA abandon this requirement, and we discussed it at length in our comments on the 

settlements. 

EPA proposes to specify that the 5% accuracy requirement will apply only to flow meters, and 

only where a particular sectoral reporting regulation (e.g., for oil and gas systems, or stationary 

combustion sources), so specifies. See 75 Fed. Reg. at 48,750. This decision is unacceptable. 

Initially, EPA itself acknowledges that it has “many years of experience with fuel flow meter 

calibration” and “is confident” that a 5% accuracy threshold is “both reasonable and achievable 

for such meters.” Id. It is therefore arbitrary and capricious, in light of EPA’s reporting mandate, 

to waive this requirement for any flow meters. All such meters should be required to meet these 

minimum accuracy requirements, with no exceptions. 

EPA has proposed essentially to waive accuracy requirements altogether for all other 

measurement devices. In the existing rule, EPA applies the 5% requirement to “all measurement 

devices,” 40 C.F.R. § 98.3(i)(1) (emphasis added), including “belt scales” and other such 

mechanisms. Id. But now EPA specifies that “weighing devices” will escape this requirement 

and instead have to meet either accuracy requirements in a given subpart (where they exist), or 

nebulous “appropriate, technology-based error-limits, such as an industry consensus standards or 

manufacturer’s accuracy specifications.” 
68 

Although EPA states that these “consensus standards” will be documented in the monitoring plan 

for a given facility, the result will be a nation-wide patchwork of varying calibration 

requirements and a concomitant patchwork of data accuracy, rendering emissions comparisons 

and policy development very difficult. EPA has left itself without a clear process or standard for 

disapproving a given calibration approach, and these approaches are likely to vary widely. Nor 

will they necessarily meet the practical data quality requirements of the rule, as a given “industry 

consensus” may well have developed before the rule existed, be influenced by other factors not 

relevant to EPA’s mandates, or low-ball possible accuracy efforts to save some expenses. The 

public, too, may be unable to access some calibration “standards” if industry attempts to claim 

them as confidential, or relies upon expensive private protocols. 

The upshot is that EPA’s proposal trades a simple, rule-wide accuracy requirement for a 

confusing, facility-by-facility approach that will make data more opaque, less reliable, and less 

useful. EPA offers no rational, record-supported reason for this switch. See Motor Vehicle Mfrs. 

Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 44 (1983) (“[T]he arbitrary 

and capricious test applie[s] to rescissions of prior agency regulations.”). Indeed, we can find no 

evidence in the record that EPA has even considered how its proposals would affect the rule’s 

data quality, quantified any increase or decrease in uncertainty caused by its proposals, identified 

which “industry consensus” or other standards might be used, and in which industries, with what 

sort of accuracy and precision, or whether those standards would be public. Nor has the agency 

considered whether the resulting data from EPA’s proposals could reliably be used to develop 

policy, inform the public, and support any ultimate emissions reduction policy, including a 

carbon market, pricing system, or regulatory control technology approach. Instead, EPA appears 

simply to have ceded the floor to industry pressure. See id. at 46 (agency rescission is invalid 

where agency “apparently gave no consideration whatsoever” to important issues). We expect 

any final rule to abandon this flawed approach. 

There is one bright spot. We are pleased to see that EPA plans to specify that data following a 

“failed flow meter calibration” would be treated as invalid from the “hour of the failed 

calibration and continuing until a successful calibration is completed.” 75 Fed. Reg. at 48,750. It 

is entirely appropriate to invalidate such faulty data. EPA should apply this approach more 

broadly to any failed calibration, and, further, should make clear that failing to successfully and 

quickly calibrate measurement instruments violates the rule, opening facilities to enforcement 

action. 

Response: Please see Section II.B of the preamble for the final rule amendments for the response 

to this comment. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 1 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 
69 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 2 

These two commenters submitted identical comments on this subject. 

Comment: Calibration and Accuracy Requirements. 

To fulfill its purpose, the reporting rule must produce accurate data that can be readily compared 

across sources and industry categories. Data will not be cross-comparable – or accurate – if 

different reporters use materially different calibration methods, or calibrate to different levels of 

accuracy. Put differently, 1 ton of carbon dioxide, reported with a possibility of 5% error, is quite 

different than 1 ton of carbon dioxide reported with 10% error. We were therefore very pleased 

to see EPA include a general calibration accuracy requirement of 5 percent in the final rule, see 

40 C.F.R. § 98.3(i)(1), as well as detailed, specific calibration and measurement protocols, see 40 

C.F.R. § 98.34, and are very disturbed that EPA has proposed to remove these requirements. 

EPA’s proposed settlements with the Utility Air Resources Group (“UARG”) and the American 

Petroleum Institute (“API”) would delete portions of the general calibration requirement along 

with industry-specific measurement protocols. In its proposed rulemaking, EPA responds to a 

“great deal of concern in the regulated community,” and proposes to limit the general accuracy 

requirement solely to flowmeters in narrowly-defined contexts. See 75 Fed. Reg. at 48,569-51. 

These decisions are serious errors, and conflict with EPA’s mandate to build a comprehensive 

greenhouse gas reporting system. [Footnote: We note, however, that some of the flowmeterspecific calibration requirements that EPA proposes are helpful, such as requiring detailed 

correlation analyses for data gathered from remote locations. See 75 Fed. Reg. at 48,570-71.] 

The core problem is that uniform calibration requirements are needed to assure that data is 

accurate, and uniformly so across reporting categories. Without uniform requirements, it will be 

difficult for EPA, the public, or regulators and participants in any carbon control program, to 

assure that emissions reductions are consistent and verifiable. The reporting rule already suffers 

somewhat from this problem because it allows many sources to use emissions estimation 

approaches which are generally less accurate than direct emissions measurement. The proposed 

settlements exacerbate this flaw by waiving the Section 98.3(i) calibration requirement for many 

sources – including sources in the Acid Rain Program (“ARP”), those using company records to 

report, those without flowmeters, and, startlingly, for any source, even one with a flowmeter, if 

its industry-specific subpart does not “specif[y]” such requirements. See 75 Fed. Reg. at 48,782-

85. 

All other measurement devices are to be calibrated to accuracy requirements in industry-specific 

subparts of the rule – where such requirements exist – or “to an accuracy within the appropriate 

error range for the specific measurement technology, based on an applicable operating standard, 

including but not limited to industry standards and manufacturer’s specifications.” 75 Fed. Reg. 

at 48,783. This change, demanded by API, does serious damage. It will leave EPA and the public 

in the dark, even if EPA requires such methods to be “documented in the written Monitoring 

Plan,” id., because the change has no real substance. It is not at all clear what an “appropriate” 

error range is, nor which standards a reporter will deem “applicable.” Worse, these standards 
70 

include, but are “not limited” to industry standards and manufacturer’s specifications, meaning 

reporters could presumably come up with their own “standards.” 

The upshot is that, by radically limiting the calibration requirements, in response both to the 

proposed settlements and to general political pressure, EPA is risking the integrity of the 

reporting rule. This risk is made even more acute by the agency’s simultaneous proposal to 

delete specific monitoring and quality control protocols from the rule. 

These changes mean that not only would calibration be subject to vague industry standards, but 

underlying measurements would be as well. Under the UARG settlement, for instance, EPA 

would strike a list of approved high heat value measurement methods from 40 C.F.R § 

98.34(a)(6); the API settlement would make similar changes to 40 C.F.R. §§ 98.244 & 98.254. 

Rather than using specific measurement methods, reporters would have the option of using 

“methods published by a consensus standards organization if such a method exists” or an 

undefined “industry consensus standard practice.” See, e.g., 75 Fed. Reg. at 48,795. 

EPA does not explain how it will determine whether an “industry consensus” in fact exists, what 

it will do when different reporters identify different “industry consensus” practices, how it will 

enforce this nebulous standard, or how it will verify emissions data reported with such a wide 

range of methods. It will also make it difficult for the public to correctly interpret monitoring 

data, even though a monitoring plan should define the methods used, because methods will vary 

from source to source – and some operators may improperly try to claim some subset of their 

methods are confidential business information. At a minimum, then, EPA should define the term 

and set out hard rules for determining whether a consensus exists and whether it has been 

appropriately followed. 

But even if EPA began to specify what this new standard means, the rule’s accuracy will still 

suffer. Industry consensus methods may well produce variably accurate results, leading to 

growing uncertainty within the data. Because EPA has also largely jettisoned rule-wide accuracy 

requirements, there is nothing to constrain “industry standard” practices from producing large 

uncertainties. Industry may agree that it can only measure a given variable to 30% error, based 

on standard practice, for example. Without calibration requirements, under the proposed 

settlement EPA will apparently have to settle for this inaccurate data. 

The upshot is that, by proposing to remove both industry-specific measurement requirements and 

rule-wide accuracy measures, EPA risks losing control of the rule’s data quality. It should 

change course. 

The most sensible way to do so is to retain and strengthen the existing rule’s requirements. That 

is the course we recommend. Alternately, if EPA can substantiate that it needs to set a lower 

calibration requirement (7.5% or 10%, say) for some devices on technical impossibility grounds, 

it might do so, without departing from the general principle of rule-wide accuracy requirements. 

If EPA takes any other course, which we strongly oppose, we request that it at least (1) carefully 

define “industry consensus” methods and address the verification and enforcement issues we 

have identified and (2) conduct a thorough uncertainty analysis of its proposal, documenting the 
71 

degree of additional uncertainty, including in terms of tons of emissions potentially missed, that 

its proposals will create. 

We understand EPA’s concern, expressed at a meeting with the agency, that specifying particular 

measurement protocols makes it harder to track improving practices, as a rulemaking is required 

to alter the mandated protocols. If EPA, motivated by this reasoning, wishes to provide for more 

methodological flexibility, it should do so only if it sharply constrains the uncertainty that 

flexibility produces. EPA should do so by maintaining and strengthening the uniform calibration 

requirements. That way, even if individual reporters have some flexibility, they will have to 

demonstrate that their methods comply with general data quality standards. 

Such requirements can be successfully implemented. The European Union’s emissions reporting 

system, for instance, generally allows for methodological flexibility, but constrains all emitters 

by uncertainty tiers, requiring, for instance, that large general combustion sources report data 

“within a maximum uncertainty of ± 1.5%.” [Footnote: see 2007/589/EC Commission Decision 

of 18 July 2007 establishing guidelines for the monitoring and reporting of greenhouse gas 

emissions, Annex II at § 2.1.1.1, available at http://eurlex. europa.eu/LexUriServ/LexUriServ.douri=CELEX:32007D0589:EN:NOT .] Reporters, in turn, must conduct careful “uncertainty 

assessment[s]” where they are not following approved methods, “which shall provide written 

proof of the uncertainty level associated with the determination of activity data for each source 

stream in order to demonstrate compliance with the uncertainty thresholds.” [Footnote: See 

Commission Decision § 7] EPA could take a similar course. 

In sum, accuracy requirements are at the core of a sound reporting system. The rule as 

promulgated sensibly imposes both rule-wide requirements and industry-specific methodologies. 

By abandoning both of these principles, EPA undermines the rule. 

Response: EPA disagrees that the removal of the rule-wide 5% calibration accuracy 

requirements and the removal of specific test methods and standards in favor of the use of 

methods more broadly adopted by consensus-based standards organizations will detrimentally 

affect data quality in the GHG Reporting Program. Please see Section II.B of the preamble for 

the final rule amendments for the response to this comment regarding the removal of the 5% 

calibration accuracy requirements. We would also point the commenter to the Background 

Technical Support Document for the Revisions proposed rule (EPA-HQ-OAR-2008-0508) 

which illustrated that application of technology specific accuracy requirements will, in many 

cases, lead to a higher standard than the 5% requirement. 

With respect to the removal of specific test methods in favor of the use of manufacturers’ 

specifications or industry consensus standards, we would note that we have not removed all test 

methods. Rather, the decision was made on a subpart-specific basis. Please see section II.G of 

the preamble for our response to this comment. The commenters are also concerned that EPA 

does not explain how it will determine whether an “industry consensus” in fact exists, what it 

will do when different reporters identify different “industry consensus” practices, how it will 

enforce this standard, or how it will verify emissions data reported using different methods. We 

would note that the rule does, in fact, point to examples of specific consensus-based standards 

organizations (e.g., ASTM, ASME, AGA, API, etc.) that would be appropriate for meeting the 
72 

requirements of a consensus-based standards organization. We would expect that different 

reporters in the same industry might use test methods from different organizations and disagree 

with the commenter that this variation should be a concern. The use of different methods by 

reporters in the same industry would have been allowed under the 2009 final rule as well, as 

these different test methods were incorporated by reference in the 2009 final rule. Rather than 

being a concern, one benefit of opening up specific sections of the rule to the use of industry 

consensus standards is the ability of reporters to use the same general methods (e.g., ASTM, 

ASME, AGA, API, etc) but using more updated, improved versions of those methods. We also 

disagree that this change will have an impact on the verification process, as EPA will still be able 

to do the same type of verification regardless of the proposed revisions. 

Finally, the commenters are concerned that more uniform requirements are needed to assure 

EPA, the public and regulators of the quality of the data for achieving compliance with an 

emissions reduction program. Our decision to remove the use of specific test methods for some 

subparts or to remove the blanket accuracy requirement across the rule should not be seen as a 

signal of how any potential future emission reduction program might be structured. This is a 

reporting program, not a reductions program. The decisions made now reflect our determination 

of what is most appropriate for a GHG reporting program and like other key elements of the 

program (e.g., the use of calculation or direct measurement approaches), would be re-assessed if 

such reporting is part of any potential future emissions reduction program. See generally, Vol. 9 

Response to Comments, Legal Issues on the 2009 final MRR, pp. 14-15 (“EPA is well aware that 

it may become appropriate to revise this rule in the future to reflect subsequent activities or 

requirements.”). 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 20 

Comment: Revise §98.3(i)(1) to include product flow meters. 

§98.3(i)(1) Except as provided in paragraphs (i)(4) through (i)(6) of this section, flow meters that 

measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock or product

flow rates and provide data for the GHG emissions calibrations, shall be calibrated prior to April 

1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in 

a relevant subpart of this part.*** 

Response:. No rule change was made as a result of this comment. The commenter did not 

provide sufficient rationale as to why these “product” flow meters should specifically be 

referenced in §98.3(i). We would note that excluding specific references to these product flow 

meters from §98.3 (i) does not exempt product flow meters from calibration and accuracy 

requirements, rather it means only that reporters must follow applicable operating standards for 

calibration of these devices. The rule only specifically refers to calibration accuracy 

requirements of product flow meters in one place, §98.244(b)(2). §98.244(b)(2) does refer back 

to §98.3(i), and as such, the accuracy specifications in §98.3(i)(2) and (i)(3) would apply. 
73 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 45 

Comment: Revise §98.3(i)(4), the fuel billing meter QA/QC exemption, to include feedstock 

and product custody transfer meters. The exemption for fuel billing meters recognizes that 

meters used for financial transactions are likely to be very well maintained and operated; 

therefore, the exemption should be extended to include feedstock and product custody transfer 

meters, which generate data for financial transactions (i.e., billing). If this suggestion is 

accepted, then a provision analogous to the Tier 3 QA/QC exemption at §98.34(b)(1)(iii) should 

be placed in §98.244(b) as shown below. Regardless of whether or not this comment is accepted, 

the citation for the recordkeeping exemptions should be revised to include paragraph (g)(6). 

§98.3(i)(4) Fuel billing meters and feedstock and product custody transfer meters are 

exempted from the calibration requirements of paragraphs (g)(5)(i)(C), (g)(6) and (g)(7) 

of this section; provided that the feedstock or fuel supplier, or product purchaser, and any 

unit utilizing the feedstock, combusting the fuel, or supplying the product do not have 

any common owners and are not owned by subsidiaries or affiliates of the same 

company.*** 

§98.244(b) *** Feedstock and product custody transfer meters are exempted from the 

initial and ongoing calibration requirements of this paragraph and from the Monitoring 

Plan and recordkeeping requirements of §98.3(g)(5)(i)(C), (g)(6) and (g)(7), provided 

that the feedstock supplier or product purchaser and the unit utilizing the feedstock or 

supplying the product do not have any common owners and are not owned by 

subsidiaries or affiliates of the same company. 

Response: EPA agrees with the commenter that the exemption in §98.3(i)(4) should include 

paragraph (g)(6), and we have amended the rule to include this reference. The other suggested 

changes to §98.3(i)(4) and 98.244(b) have not been included in the final amendments because we 

have concerns that custody transfer meters for feedstock and products may not represent the 

actual amount of material used in or produced by a process. For example, a portion of the 

material that is used as a feedstock for a petrochemical process may be used in other processes, 

as fuel, or lost through equipment leaks. If this occurs, then the flow measured by the custody 

transfer meter would overstate the amount of material actually fed to the petrochemical process. 

Similarly, product flow measured by custody transfer meters, particularly if located at customer’s 

facilities, may understate the amount of product actually produced. Furthermore, if a given 

product is purchased by multiple customers, then each customer would have to have a custody 

transfer meter. Summing the results from each of these custody transfer meters would result in 

greater uncertainty in the total flow relative to using the results from one flow meter. 
74 

Measurement device installation 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2353 

Comment Excerpt Number: 2 

Comment: My only concern with this proposed rule is the way in which you will evaluate the 

petitions made by facilities that claim that they are unable to follow the scheduled shut-down of 

facilities because they are in need of more time to update and make changes to their facilities. 

This information is found in Subpart A under general provisions of best available monitoring 

methods. 

Response: Please see Section II.A of the preamble to the final rule amendments, where specific 

criteria for approval of the extension requests are described 

Commenter Name: Peter Zalzal 

Commenter Affiliation: Environmental Defense Fund (EDF) 

Document Control Number: EPA-HQ-OAR-2008-0508-2370.1 

Comment Excerpt Number: 1 

Comment: Environmental Defense Fund (EDF) supports the Agency’s efforts to develop a 

robust greenhouse gas reporting rule covering “all sectors of the economy,” consistent with 

legislative mandate. We share EPA’s concern that the final Mandatory Reporting Rule provides 

accurate, timely, facility-specific data, equipping policymakers and the public alike with the 

information necessary to respond to the challenges and opportunities associated with climate 

change. In light of these goals, we respectfully offer the below comments, which specifically 

address the Agency’s proposal to extend the use of best available monitoring methods 

(“BAMM”) for certain facilities until December 31, 2015. 

EPA is proposing to establish a new petition process, allowing for facilities reporting under 

subpart P (hydrogen production), subpart X (petrochemicals production), and subpart Y 

(petroleum refineries) to use BAMM past the current December 31, 2010 deadline. 75 Fed. Reg. 

at 48748. EPA’s proposal allows these facilities to petition for extended use of BAMM if 

“compliance with a specific provision in the regulation required measurement device installation, 

and installing the device(s) would necessitate an unscheduled process equipment or unit 

shutdown or could only be installed through a hot tap.” Id. If an affected facility does not have 

such a shutdown scheduled prior to the December 31, 2010 deadline for full compliance, the 

facility can petition for an extension, allowing it to use BAMM until December 31, 2013. Id. 

EPA has additionally proposed to allow facilities taking advantage of this initial BAMM 

extension request to file an additional, subsequent request, potentially extending the facility’s use 

of BAMM until December 31, 2015. Id. EPA’s proposal, then, opens the door for affected 

facilities to request the use of BAMM for five years beyond the Agency’s original deadline. 
75 

Consistent data are an inextricable piece of any high-quality greenhouse gas emissions inventory, 

as they allow comparisons among similarly situated facilities. EPA has recognized the critical 

importance of consistent data collection in its Mandatory Reporting Rule, noting “[t]he goal of 

this rule is to collect accurate and consistent data of sufficient quality to inform future CAA 

policy and regulatory decisions.” 74 Fed. Reg. 56260, 56279 (Oct. 30, 2009). Facilities 

calculating emissions using BAMM, however, undermine the consistency of the dataset. The 

best available monitoring methods facilities can use to determine important measurement values 

include: 

(1) Monitoring methods currently used by the facility that do not meet the specifications of a 

relevant subpart; 

(2) Supplier data; 

(3) Engineering calculations; and 

(4) Other company data. 

74 Fed. Reg. at 56274. In its final MRR, EPA determined that this sacrifice of accuracy and 

consistency was necessary to give facilities an additional year, at most, to come into full 

compliance with the Rule’s requirements. Here, EPA’s proposal to prolong full compliance with 

the MRR’s requirements for an additional five years is simply too long, especially given the 

significant greenhouse gas emissions attributable to these facilities. [Note: According to EPA’s 

MRR, hydrogen production accounts for 15 million metric tons of CO2 equivalent 

(“mmtCO2e”), petrochemical production accounts for 54.4 mmtCO2e, and petroleum refineries 

account for 204.7 mmtCO2e. 74 Fed. Reg. at 56363. EPA estimates that these facilities account 

for roughly 6 percent of economy-wide emissions. Id.] 

Given the critical nature of this data, we strongly encourage EPA not to extend the use of 

BAMM any longer than its initial re-proposed deadline of December 31, 2013. Moreover, with 

respect to the Agency’s decision to allow an extension until December 31, 2013, we respectfully 

ask that the EPA provide a more thorough analysis of challenges associated with timely 

installation of the required measurement devices, set forth manifest decision criteria for allowing 

any extensions, and establish procedures for applying these decision criteria to the particular 

facts of any BAMM request. EPA does not quantify or evaluate the key factors that inform its 

decision to extend BAMM past the current December 31, 2010 deadline. And the Agency does 

not provide for the critical fact-based determinations on the administrative record that will 

provide the basis for the Agency’s judgment. This analysis is the hallmark of reasoned decisionmaking. Conversely, the failure to provide clear decision-making criteria and to provide for factbased findings in specific instances would be quintessentially arbitrary and capricious given the 

Agency’s previously-stated expectation “that the vast majority of facilities will begin complying 

with the full monitoring requirements of the rule no later than April 1, 2010, and will not require 

or be granted an extension.” 74 Fed. Reg. at 56275. 

Response: Please see Section II.A of the preamble for the final rule amendments for a general 

response to this comment. In addition, we would note that the overall quantity of emissions that 

could be reported using best available monitoring methods for the limited extension of time is 

not as large as suggested by the commenter. Not all greenhouse gases emitted by facilities using 

the BAMM extension would be calculated and reported using a best available monitoring 
76 

methodology, rather only those specific pieces of equipment at the facility where it is 

satisfactorily demonstrated that the required monitoring equipment cannot be installed absent a 

shutdown of the unit or a hot tap. 

The commenter also appears concerned that best available monitoring methods may include 

supplier data, engineering calculations, or other company data. In general this is true. However 

we would also point out that unlike the 2010 BAMM process, as part of the approval of the 

extension request for BAMM, EPA will also approve the method proposed to calculate GHG 

emissions in the interim. Therefore, there will be a clear record of an approved approach that 

facilities must follow in calculating GHG emissions. 

 

The commenter also requests that EPA set forth criteria for allowing any extensions and 

establish procedures for applying these decision criteria to the particular facts of any BAMM 

request. As proposed, the final rule requires the owner or operator to demonstrate to the 

Administrator’s satisfaction that it is not reasonably feasible to install the measurement device 

without a process equipment or unit shutdown, or through a hot tap, and that the proposed 

method for estimating GHG emissions during the time before which the measurement device 

will be installed is appropriate. To do this, the extension request must contain very specific 

information, including, identification of the specific measurement device (and location) for 

which the request is being made, the specific rule requirements requiring the measurement 

device, reasons why the needed equipment could not be installed before April 1, 2010, or by the 

expiration date for the use of best available monitoring methods under §98.3(d), documentation 

showing that it is not practicable to isolate the process equipment or unit and install the 

measurement device without a full shutdown or a hot tap and that there was no opportunity 

during 2010 to install the device, and a description of the proposed best available monitoring 

method for estimating GHG emissions during the time prior to installation of the meter. These 

are very clear criteria against which each individual application for BAMM will be evaluated. 

Because each specific application request will be unique, EPA cannot further delineate key 

factors that would inform its review of any given request at this time. 

Finally, we disagree with the commenters’ suggestion that EPA should approve BAMM for no 

later than December 31, 2013. For reasons provided in section II.A of the preamble for the final 

rule amendments we have determined that having a two-phase approach, with the first phase 

ending in 2013 and the second phase no later than 2015, is appropriate and provides a clear and 

documented approach that ensures that EPA is still receiving data of a known and appropriate 

quality without unnecessarily forcing shutdowns for these facilities. 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 2 

Comment: ACC supports EPA’s proposal to establish a new petition process in 40 CFR 98.3(j) 

that would allow for the use of BAMM past December 31, 2010 for owners and operators 
77 

required to report under subparts P (Hydrogen Production), X (Petrochemicals Production), and 

Y (Petroleum Refineries). We agree with EPA’s rationale that a number of these facilities may 

not have a process or unit shutdown scheduled for several years, and that requiring the 

installation of a measuring device may result in an unplanned shutdown. ACC strongly 

recommends, however, that the BAMM extension should extend to any and all facilities subject 

to any subpart in the MRR that would have to undertake an unplanned shutdown to 

accommodate the installation of a required measurement device. 

Response: No rule change has been made as a result of this comment. Please see Section II.A of 

the preamble for the final rule amendments for the response to this comment. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 1 

Comment: The Proposed Language in 98.3(j) should be modified to allow all source categories 

to seek an extension for the use of best monitoring methods, and EPA should not require 

sampling and analysis of a stream that is dangerous to monitor due to the presence of toxic 

chemicals. 

The proposed changes to the rules include the addition of 98.3(j) that allows facilities with 

source categories under subpart P, subpart X, and subpart Y to receive an extension of best 

monitoring methods beyond December 31, 2010. Dow clearly understands the need for such a 

provision and supports this proposed addition, However, Dow believes this extension should 

apply to all source categories in need of such relief should they need to execute a process 

shutdown to install the necessary measurement devices. There is no logical reason for making 

this extension available to only some of the source categories when all facilities would have the 

same constraints and burdens regarding the installation of measurement devices. 

Dow has two boilers at one of its facilities that require the use of Tier 3 calculation methods. One 

of the fuel streams for these units is an off-gas process stream that provides greater than 10% of 

the annual heat input and contains significant quantities of hydrogen cyanide. This stream is 

unsafe for routine sampling required by the Tier 3 calculation methods. Contract laboratories 

contacted also expressed concern with analyzing these samples for safety reasons. A letter was 

sent to EPA on January 22, 2010 inquiring the best mechanism to address situations such as this, 

where a fuel stream is unsafe to sample. We were instructed to submit a request for an extension 

under the rules, and that EPA would further consider this situation. Dow requested and received 

an extension, but no additional guidance has been provided. Dow has since initiated a project to 

install the necessary equipment to allow the use of the Tier 4 calculation methodologies. The 

estimated cost for this project is $300,000. This is a fairly significant cost that is only needed to 

determine the emissions of 25% of the fuel use in the equipment. These boilers receive fuel 

streams from and provide steam to several manufacturing plants at the facility. Current logistics 

make it problematic to shutdown the equipment needed to install this equipment prior to the end 

of 2010. 
78 

Presently, EPA does not have any provision in the GHG reporting rule for fuel gas streams that 

are dangerous to sample due to the presence of toxic chemicals. EPA should allow use of 

company records or process knowledge to estimate fuel use and calculate GHG emissions rather 

than forcing these sources to sample these toxic streams, or install, operate and maintain CEMS 

under the Tier 4 method. Alternatively EPA could allow the use of the "fuel gas" factors that are 

proposed for additions to Table C-1. This would eliminate the need for personnel to handle these 

toxic chemicals, or in the above case, the need to install, operate and maintain CEMS under the 

Tier 4 method. 

EPA should make provisions for fuel streams containing toxic chemicals and modify the 

proposed 98.3(j) to include all source categories covered by the rule. 

Response: No rule change has been made as a result of this comment. Please see Section II.A of 

the preamble for the final rule amendments for the response to this comment. 

Commenter Name: Jamie Mann 

Commenter Affiliation: Suncor Energy USA, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2389.1 

Comment Excerpt Number: 1 

Comment: EPA has proposed that a new petition process be established under 40 C.F.R. § 

98.3(j) that would allow use of BAMM past December 31,2010 for owners and operators 

required to report under subpart P (Hydrogen Production), subpart X (Petrochemicals 

Production), or subpart Y (Petroleum Refineries). Specifically, EPA is proposing to amend 40 

C.F.R § 98.3(i)(6) to account for units and processes that operate continuously with infrequent 

outages and that cannot meet the flow meter calibration deadline without disrupting normal 

process operation. A petition for the use of BAMM beyond December 31, 2010 would require 

measurement device installation, and installing the device(s) would necessitate an unscheduled 

process equipment or unit shutdown or could only be installed through a hot tap. 

EPA has specifically requested comment on this conclusion and whether there are other facilities 

beyond those specified in subparts P, X, and Y that would require a shutdown, or a hot tap, in 

order to install the required measurement devices. 

Suncor Energy U.S.A., Inc. (Suncor) was granted approval by EPA of an extension request to 

use BAMM for temperature and pressure-compensated gas flows through December 31, 2010. In 

order to develop temperature and pressure-compensated gas flows, Suncor has elected to install a 

multi-variable monitor capable of measuring flow, temperature, and total pressure. Suncor’s 

compliance strategy was premised on the rejection by EPA of the portion of Suncor’s extension 

request that requested an extension until the next scheduled process unit turnarounds at Suncor’s 

Commerce City Refinery. Based on the changes to the GHG Mandatory Reporting Rule 

proposed by EPA, Suncor would have the flexibility originally requested in Suncor’s BAMM 

extension request, and may therefore elect to implement a different and preferred compliance 

strategy. Additionally, because the proposed changes have not been finalized, the installation by 
79 

Suncor of the multi-variable monitor under the current BAMM extension request may not meet 

the data collection requirements of the final rule. Accordingly, Suncor believes EPA should 

extend existing BAMM extension requests for temperature and pressure-compensated gas flows 

through December 31, 2011, so that sources such as Suncor may avoid having to install a 

monitor that may not comply with the final rule, resulting in additional, unnecessary economic 

burdens of having to install one or more subsequent flow meter(s). 

Furthermore, Suncor requests that EPA clarify that a petition for the use of BAMM beyond 

December 31, 2010, would be permitted for emission sources regulated under subpart C (General 

Stationary Fuel Combustion Sources) at Petroleum Refineries. Specifically, the installation of 

flow meters and transmitters in order to meet the Subpart C Tier 3 requirements for combustion 

of refinery fuel gas would require a shutdown or hot tap of a refinery fuel gas system for many 

refiners. Numerous heaters, boilers, and other combustion units at refineries will require the use 

of BAMM beyond December 31, 2010, with respect to units that have not been shutdown since 

the original rule proposal and are not scheduled to be shutdown until after December 31, 2010. 

Suncor believes that EPA’s intention was to include Stationary Combustion Sources subject to 

Subpart C at Petroleum Refineries subject to Subpart Y as sources that are able to make the 

petition for an extended BAMM period and believes this should be explicitly stated in the final 

rule. 

Response: It is not necessary for EPA to extend all existing BAMM requests through December 

31, 2011. Subpart P, X, and/or Y owners or operators that currently have approval to use 

BAMM, may request an extension under the final rule amendments, if installation of the 

measurement devices would require a process unit shutdown or hot tap. Owners or operators 

requesting to use BAMM beyond 2010 are required to electronically notify EPA by January 1, 

2011 that they intend to apply for BAMM for installation of measurement devices and certify 

that such installation will require a hot tap or unscheduled shutdown. They have until February 

15, 2011, to submit the full extension request for BAMM. Owners or operators that notify EPA 

of their plan to apply for BAMM by January 1, 2011 and subsequently submit a full extension 

request by February 15, 2011, can automatically use BAMM consistent with their request 

through June 30, 2011. The post 2010 BAMM extension requests described in §98.3(j) are for 

facilities subject to P, X and/or Y and may cover units that are subject to any subpart of the rule, 

including subpart C units. 

Regarding the temperature and pressure transmitters specifically, EPA did not propose to change 

the 2009 final rule requirements for pressure and temperature transmitters. Rather, we proposed 

an additional option to allow facilities to use remote temperature and/or pressure transmitters to 

determine conditions at the meters. Because we did not propose to change the requirements in 

the 2009 final rule there is no basis for facilities requiring additional time to install measurement 

devices consistent with those same requirements. Therefore, no rule change has been made as a 

result of this comment. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 
80 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 8 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 1 

These two commenters submitted identical comments on this subject. 

Comment: The current rules require installation of meters and other measurement devices by 

April 1, 2010, with extensions available through December 31, 2010. 40 C.F.R. 98.3(d)(1) and 

(2). As noted by EPA, “it is important to establish a date by which all equipment must be 

installed and operating in order to ensure that consistent data are collected by all reporters.” 75 

Fed. Reg. at 48748; see also 74 Fed. Reg. at 56274 (final reporting rule). We are in full 

agreement with EPA that timely installation of measurement equipment is a critical component 

of the reporting rule for ensuring accuracy and consistency. For these reasons, we oppose EPA’s 

proposal, based upon the API settlement, to provide additional extensions of up to 5 years 

beyond its original extension deadline for hydrogen and petrochemical production facilities, as 

well as petroleum refineries. 

We are cognizant of the complex nature of these facilities and the various schedules for taking 

equipment out of service. However, we also believe that the need to install measurement 

equipment for reporting rule purposes should be a significant consideration in planning 

scheduled shutdowns. The current rule provides an incentive for subpart P, X and Y facilities to 

prioritize scheduled shutdown of units requiring measurement equipment. In contrast, EPA’s 

new proposal would potentially let these sources off the hook for many years down the road. 

EPA should consider at most a single tier extension program ending in December 2013. 

In addition, the rule should make use of unplanned outages as opportunities to install the required 

equipment sooner rather than later. Many facilities will experience unplanned unit shutdowns 

before their schedule outages. EPA should require facilities to prepare device installation plans 

and acquire devices as soon as possible, such that devices can be installed during unplanned 

shutdowns where feasible. 

Furthermore, the deadlines for requesting the second tier extension come too late in the game and 

appear to create significant gaps in the program’s coverage. Currently, a source must request 

permission to use best available monitoring methods (“BAMM”) beyond March 31, 2010 by 

filing a request for extension with EPA several months in advance. 40 C.F.R. § 98.3(d)(2) 

(request for extension submitted no later than 30 days after effective date of the GHG reporting 

rule) and 74 Fed. Reg. 56,260 (GHG reporting rule effective date of December 29, 2009). By 

requiring the extension request to be submitted prior to the deadline for ending BAMM, the rule 

aims at ensuring that sources at all times are authorized to use BAMM, i.e., are not unjustifiably 

avoiding installation of measurement equipment. 
81 

The same is not true for the proposed second extension period for hydrogen and petrochemical 

facilities and refineries. The proposal similarly requires a source to submit an initial notification 

of the intent to submit an extension request for use of BAMM beyond December 31, 2010. 75 

Fed. Reg. at 48,784. This notification, however, must be submitted to EPA by no later than 

January 1, 2011 or by the end of the approved use of BAMM, whichever is earlier, with a final 

request to be filed no later than February 15, 2011. Id. at 48,785. Here the timing creates a gap 

during which some sources will be operating with only BAMM even though EPA has made no 

determination that such continued use is warranted. For example, a source that obtained an initial 

extension to use BAMM until September 30, 2010 would submit its request on October 1, then 

enjoy an additional three months before it even has to lay out its full case for an extension in 

mid-February 2011. Moreover, such a source would have until July 1, 2011 to actually install 

measurement devices – apparently even if the Administrator eventually denies the extension 

request. See id. at proposed (j)(6). 

It is not clear that such delays and additional time to make extension requests are warranted. 

Indeed, a significant underlying premise of and justification for the proposal is that companies 

have patterns of planned outages that they schedule many years in advance. The company even 

has to submit its historic shutdown information for the unit in its extension request. See id. at 

proposed (j)(4)(iv) (request must include “the date of the three most recent shutdowns for each 

relevant process equipment or unit, the frequency of shutdowns for each relevant process 

equipment or unit, and the date of the next planned process equipment or unit shutdown.”) Thus, 

the vast majority of, if not all, sources will know in well in-advance of the expiration of their first 

BAMM extensions (not to mention in advance of February 15, 2011) that they need additional 

leeway. Notably, EPA is proposing a third extension request deadline several months in advance 

of the December 31, 2013 second tier installation deadline. See id. at proposed (j)(7) (request to 

use BAMM after December 31, 2013 must be submitted by June 1, 2013). EPA should consider 

advancing the deadlines for second extension requests and/or eliminating any gaps created by the 

timing of these deadlines. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2370.1, excerpt 1 and 

Section II.A of the preamble for the final rule amendments for the response to this comment. 

EPA considered, but decided not to advance the deadlines for the notification to request BAMM 

for 2011. Facilities that would have required a shutdown to install the necessary monitoring 

equipment, but did not have a shutdown scheduled during 2010, most likely have already asked 

for BAMM through the end of 2010, if not longer. These initial BAMM requests were approved 

only through December 31, 2010. Given the timing of this rulemaking, and the need to ensure 

that facilities with BAMM would not have a period during which their BAMM approval would 

lapse, we determined that it was necessary to provide facilities the ability to notify EPA by 

January 1, 2011 and essentially grant them BAMM until July 1, 2011 (and later if approved). As 

a practical matter, this automatic BAMM through June 30, 2011 is necessary to give EPA 

sufficient time to evaluate the applications, while providing sufficient certainty for the reporters 

on their compliance obligations. If the automatic extension period is not long enough to allow 

EPA to evaluate the requests and inform a facility whether its request was approved well in 

advance of the expiration of the automatic extension, many of these facilities may feel compelled 

to undertake an unscheduled shutdown or a hot tap because they could not be assured of getting 
82 

the extension approved by EPA in time. This is the very result we are trying to avoid with the 

extended BAMM process. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 2 

Comment: The Clean Air Task Force, Natural Resources Defense Council, and Sierra Club 

(collectively, CATF) argues against the proposed extension of deadlines for installation of 

meters and other measurement devices, suggesting that such extensions may not be warranted. 

While the American Petroleum Institute (API) and NPRA understand the desire to have 

monitored data as soon a possible, the short implementation schedule in the final rule would 

present compliance challenges that go beyond mere inconveniences. As demonstrated by API 

and NPRA’s early submissions, allowing extensions under certain limited conditions would 

alleviate potential safety risks that would otherwise be necessitated by dangerous and delicate 

“hot-tapping” to install required monitoring equipment before a scheduled shut down. The 

Settlement Agreement’s revisions to 40 C.F.R. §98.3(j) would allow the owner or operator of a 

regulated facility under certain limited conditions to request EPA approval for additional time to 

continue using best available monitoring methods if an unscheduled shut down or “hot tap” 

would be necessary to install certain monitoring equipment. The risk associated with hot-tapping 

should be avoided whenever possible and the proposed Settlement Agreement would achieve 

that goal. 

Response: We have finalized the post 2010 BAMM process, as proposed. Please see Section 

II.A of the preamble for the final rule amendments for the response to this comment. 

Definition of agricultural byproducts 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 10 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.1 

Comment Excerpt Number: 2 

These two commenters submitted identical comments on this subject. 

Comment: Additional Definitions Related to Biomass. We support EPA’s clarification of the 

definitions of “agricultural byproducts,” “solid byproducts,” and “wood residuals.” As we have 

stated numerous times, an accurate GHG emissions inventory is essential. The accuracy of the 
83 

default CO2 emissions factors and high heat values (“HHV”) provided for in the regulation will 

play a large part in achieving this objective. As EPA gains experience with the implementation 

of this rule and more comprehensive information about the sources of GHG emissions, we urge 

EPA to review these existing values for accuracy and to provide more specific values for fuels 

within those categories. For instance, when and if EPA is able to do so, it should provide specific 

values for biomass feedstocks that would otherwise fall within the umbrella categories of 

“agricultural byproducts,” “solid byproducts,” and “wood residuals.” 

Response: We thank the commenter for the input. As policies and programs evolve and/or 

particular calculation or monitoring equipment improves EPA plans to evaluate whether or not to 

update the methodologies in this rule. 

Definition of municipal solid waste (MSW) 

Commenter Name: John R. "Doc" Holladay 

Commenter Affiliation: Local Government Coalition for Renewable Energy 

Document Control Number: EPA-HQ-OAR-2008-0508-2378.1 

Comment Excerpt Number: 1 and 2 

Comment: EPA’s October 2009 GHG Reporting Rule defines MSW as “solid phase household, 

commercial/retail, and/or institutional waste, such as, but not limited to, yard waste and refuse.” 

See 40 C.F.R. § 98.6 (Definitions), 74 Fed. Reg. at 56389/2 (the virgule [“/”] identifies the 

column or columns to which we are referring). EPA’s August 11 rulemaking proposal notes that 

various commenters critiqued that definition as insufficient to determine whether certain types of 

waste constitute MSW. See Mandatory Reporting of Greenhouse Gases, 75 Fed. Reg. at 

48754/2-3. On that basis, EPA proposes to amend the GHG Reporting Rule’s definition of MSW 

to parallel the definition in Subpart Ea of the NSPS for MWC facilities, supra, 40 C.F.R. § 

60.51a. Specifically, EPA proposes to define MSW as 

solid phase household, commercial/retail, and/or institutional waste. Household waste 

includes material discarded by single and multiple residential dwellings, hotels, motels, 

and other similar permanent or temporary housing establishments or facilities. 

Commercial/retail waste includes material discarded by stores, offices, restaurants, 

warehouses, non-manufacturing activities at industrial facilities, and other similar 

establishments or facilities. Institutional waste includes material discarded by schools, 

nonmedical waste discarded by hospitals, material discarded by non-manufacturing 

activities at prisons and government facilities, and material discarded by other similar 

establishments or facilities. Household, commercial/retail, and institutional waste does 

not include used oil, wood p[a]llets, construction, renovation, and demolition wastes 

(which includes, but is not limited to, railroad ties and telephone poles), clean wood, 

industrial process or manufacturing wastes, medical waste, or motor vehicles (including 

motor vehicle parts or vehicle fluff). Household, commercial/retail, and institutional 

wastes include yard waste, refuse-derived fuel, and motor vehicle maintenance materials, 

limited to vehicle batteries and tires, except where a single waste stream consisting of 

tires is combusted in a unit. 
84 

See Mandatory Reporting of Greenhouse Gases, 75 Fed. Reg. at 48785-86 (text of proposed 40 

C.F.R. § 98.6, Definitions). 

As already indicated, this new definition would exclude a number of materials such as clean 

wood and wood pallets, construction and demolition waste, used motor oil and a broad range of 

motor vehicle maintenance parts (the latter can range from windshield wiper blades to filters, 

headlamps and other lighting and electrical parts, etc.). [Footnote: Although on an average basis 

the quantities of clean wood, wood pallets, construction and demolition debris, etc., processed by 

a given municipal waste combustion facility are limited, periodically more significant quantities 

of such materials will be delivered to WTE facilities for processing.] Those materials are 

unavoidable in MSW, particularly residential waste, as EPA has long recognized. For example, 

EPA’s website notes that at least 10 percent of motorists dispose of used motor oil in their 

household waste. Similarly, EPA’s annual overview of MSW in the United States indicates that 

6.6 percent of MSW is clean wood, primarily from wood packaging, including wood pallets, and 

only a small portion of that wood waste (about 15 percent of the 6.6 percent) is recovered for 

recycling. Similarly, EPA has acknowledged that construction and demolition debris is a 

significant portion of the overall “municipal solid waste stream.” [Footnote: 4 U.S. 

Environmental Protection Agency, What’s in a Building- Composition Analysis of C&D Debris, 

http://www.epa.gov/region09/waste/solid/pdf/cd1.pdf.] 

As noted above, EPA’s August 11 proposal to amend the GHG Reporting Rule explains that the 

proposed definition of MSW mirrors the definition in the NSPS for municipal waste combustion 

units and has the same exclusions. The administrative record for the NSPS shows, however, that 

the exclusions from the NSPS definition were not made due to any assumption that clean wood, 

wood pallets, used motor oil, small quantities of used tires, etc., are absent from MSW. Rather, 

those materials were excluded from the NSPS definition because stationary sources that generate 

power (or otherwise recover energy) from homogeneous streams of such materials successfully 

sought to be excluded from the rigorous air emission limitations for municipal waste combustors 

under the NSPS (as well as the related Emission Guidelines in 40 C.F.R. § 60.50b, et seq.). 

EPA has addressed this point on several occasions in connection with the NSPS and Emission 

Guidelines and various amendments to each. For example, in amendments to the NSPS and 

Emission Guidelines proposed in 1994, EPA explained as follows: 

[W]aste-fuel power generation facilities that combust a single-item waste stream of tires, 

fuel derived solely from tires, or used oil would be subject only to an initial notification 

of construction and would not be subject to any other provisions in today’s proposal. This 

exclusion is unchanged from the NSPS promulgated on February 11, 1991. 

See Standards of Performance for New Stationary Sources: Municipal Waste Combustors, 

Proposed Rule and Notice of Public Hearing, 59 Fed. Reg. 48198, 48212/2 (Sept. 20, 1994). 

EPA elaborated on its policy position in connection with combustion of used tires, explaining 

that although “[t]ires are considered to be MSW,” “combustors that fire 100 percent tires . . . or 

tire-derived fuel with other non-MSW fuels[] are specifically excluded from the combustor 

standards.” See Standards of Performance for New Stationary Sources and Final Emission 
85 

Guidelines; Final Rules, 56 Fed. Reg. 5488, 5495/3 (Feb. 11, 1991); see also id. at 5496/1 

(“[T]ires are a national problem and since few options exist for their disposal, the Agency does 

not want to take any premature action that could discourage projects for the combustion of tires 

and, therefore, dedicated tire combustion facilities are not regulated under this NSPS for MWCs. 

However, combustors that do not fire 100 percent tires or tire-derived fuel, but co-fire tires or 

tire-derived fuel with MSW, would be covered under this NSPS if the combustor meets the other 

MWC applicability requirements of the standards.”). 

EPA further addressed this subject in connection with 1995 amendments to the NSPS and 

Emission Guidelines. In particular, EPA explained that although clean wood had previously been 

included in the definition of MSW, the agency changed course and decided that the rigorous air 

emission limits it applied to municipal waste combustion units were not necessary for singlestream combustion of clean wood. EPA addressed this point as follows: 

Under the proposed standards, clean wood was included in the definition of MSW. 

Several commenters disagreed with this decision to cover clean wood under the MWC 

standards. Under the final rule, clean wood is not considered to be MSW. . . . Clean wood 

is predominantly an agricultural, industrial, or other non-municipal solid waste; 

regulation of the combustion of these types of wastes is currently being addressed under a 

separate rulemaking. 

Standards of Performance for New Stationary Sources and Emission Guidelines for Existing 

Sources, Final Rule, 60 Fed. Reg. 65387, 65395/2 (Dec. 19, 1995). 

In short, the rulemaking record for the NSPS and Emission Guidelines for municipal waste 

combustion facilities demonstrates that the purpose of the above-described exclusions from the 

definition of MSW was to exempt certain types of combustion facilities from the NSPS and 

Emission Guidelines and not to preclude combustion of such materials by the WTE facilities that 

are the intended focus of the emission limitations and other standards that underlie the NSPS and 

Emission Guidelines. In that regard, EPA has consistently recognized that clean wood, other 

construction and demolition waste, used oil, etc., are present – and, in fact, unavoidable – in 

MSW. The latter has direct implications under the GHG Monitoring Rule, specifically, the 

substantially more costly and burdensome GHG monitoring that will be required for WTE 

facilities as a direct result of the proposed new definition of MSW. 

The Proposed MSW Definition Would Force WTE Facilities to Tier 4 Monitoring. Tier 4 is the 

most demanding monitoring protocol under the GHG Reporting Rule. To the extent Tier 4 

monitoring is required for WTE facilities, it will often require costly upgrades of existing CEMS 

to accommodate GHG monitoring. To be sure, EPA’s April 2009 proposal for the GHG 

Reporting Rule had expressly contemplated either Tier 2 or Tier 4 monitoring for WTE facilities. 

See 74 Fed. Reg. 16448, 16481, Table C-1 (April 10, 2009). However, in response to the concern 

of MWC owners-operators that the 250 TPD threshold would disproportionately burden MWC 

facilities, see 75 Fed. Reg. at 48757/1-2, EPA’s August 11 proposal to amend the GHG 

Reporting Rule would increase from 250 tons per day (“TPD”) to 600 TPD the threshold at 

which Tier 4 monitoring applies to municipal waste combustion units. Given the fact that the 

municipal waste combustion units at most WTE facilities are below the 600 TPD threshold, the 
86 

change to the 600 TPD threshold is intended to expand substantially the opportunity for WTE 

facilities to use Tier 2 monitoring. Importantly, Tier 2 monitoring does not require CEMS for 

carbon dioxide and instead calculates carbon dioxide emissions based on fuel use, higher heating 

value and fuel-specific emissions factors. See 75 Fed. Reg. at 48757/1-2. But the expanded use 

of Tier 2 monitoring that EPA intended for WTE facilities will largely be nullified by the 

proposed new definition of MSW, which would generally exclude the fuel combusted by WTE 

facilities from the GHG Reporting Rule’s definition of MSW. As a consequence, WTE facilities 

would be forced to Tier 4 monitoring (albeit with some cases where Tier 3 monitoring could 

apply). 

In that regard, WTE facilities are generally subject to the GHG reporting rule due to CO2e 

emissions above the rule’s annual threshold of 25,000 metric tons and aggregate maximum rated 

heat input capacity of 30 mmBtu/hour or more. See 40 C.F.R. § 98.2(a)(3). The unintended 

mandate for Tier 4 monitoring is evident from review of 40 C.F.R. § 98.33(b): 

Tier 1 – Tier 1 does not appear to be an option because, as relevant here, it is limited to sources 

that combust “any fuel listed in Table C-1 of this subpart,” and although MSW is listed in Table 

C-1, the fuel combusted by WTE facilities generally does not meet the GHG Reporting Rule’s 

proposed definition of MSW (for the same reason, Tier 1 is also precluded for small MSW 

combustors that do not produce steam). 

Tier 2 – Tier 2 is intended to apply broadly to WTE facilities. See 40 C.F.R. § 98.33(b)(2)(iii) 

(stating that Tier 2 applies to “MSW in a unit of any size that produces steam[] if the use of Tier 

4 is not required”). Once again, however, it appears that Tier 2 would generally not apply to 

WTE facilities because the fuel they process would generally not meet the GHG Reporting 

Rule’s proposed definition of MSW. 

Tier 3 – Similarly, Tier 3 is not an option for WTE facilities because it is primarily limited to 

facilities that combust fuels listed in Table C-1. See 40 C.F.R. § 98.33(b)(3)(i) and (ii). Although 

Tier 3 can be used in some circumstances for facilities that combust a fuel not listed in Table C1, that alternative is limited to units with maximum rated heat input capacity greater than 250 

mmBtu/hour, and the municipal waste combustion units at many WTE facilities have maximum 

rated heat input capacity below that level. 

Tier 4 – Finally, due to the unavailability of Tiers 1-3, WTE facilities will default to Tier 4, 

which is the fallback “for a unit of any size, combusting any type of fuel.” 40 C.F.R. § 

98.33(b)(4)(i). 

In sum, the definition of MSW in the proposed GHG Reporting Rule amendments is such that 

the typical fuel for essentially all municipal waste combustors and WTE facilities does not 

appear to qualify as MSW, which will force those facilities to more costly and burdensome Tier 

4 monitoring. That does not appear to have been the result intended by EPA, particularly given 

the Agency’s acknowledgement in its August 11 rulemaking proposal that expanded availability 

of Tier 2 monitoring for municipal waste combustors will provide WTE facilities with 

“comparable monitoring thresholds and conditions as other general stationary combustion units.” 

See 75 Fed. Reg. at 48757/2. Accordingly, EPA should either adhere to the definition of MSW 
87 

under the current terms of the GHG Reporting Rule or adopt a revised definition which 

recognizes that MSW, in particular residential waste and similar waste streams from commercial 

and institutional establishments, will necessarily include materials such as clean wood and wood 

pallets, construction and demolition waste, etc. 

Response: Please see Section II.F of the preamble for the final rule amendments for the response 

to this comment. We did not intend to push municipal waste combustors into use of higher tiers 

through the change in the definition of municipal solid waste. The final rule clarifies that 

“insofar as there is separate collection, processing and disposal of industrial source waste streams 

consisting of used oil, wood pallets, construction, renovation, and demolition wastes (which 

includes, but is not limited to, railroad ties and telephone poles), clean wood, plastics, industrial 

process or manufacturing wastes, medical waste, motor vehicle parts or vehicle fluff, or used 

tires that do not contain hazardous waste identified or listed under 42 U.S.C. §6921, such wastes 

are not municipal solid waste. However, such wastes qualify as municipal solid waste where 

they are collected with other municipal solid waste or are otherwise combined with other 

municipal solid waste for processing and/or disposal.” 

Commenter Name: Edward W. Repa 

Commenter Affiliation: National Solid Wastes Management Association (NSWMA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2379.1 

Comment Excerpt Number: 3 

Comment: The definition of MSW in Section 98.6 is yet again another definition supplied by 

EPA. EPA has defined MSW in its Fact and Figures Documents [Footnote: U.S. Environmental 

Protection Agency. http://www.epa.gov/osw/nonhaz/municipal/msw99.htm.] of various years as: 

“Municipal solid waste (MSW) includes wastes such as durable goods, nondurable 

goods, containers and packaging, food scraps, yard trimmings, and miscellaneous 

inorganic wastes from residential, commercial, institutional, and industrial sources. 

Examples of waste from these categories include appliances, automobile tires, 

newspapers, clothing, boxes, disposable tableware, office and classroom paper, wood 

pallets, and cafeteria wastes. MSW does not include wastes from other sources, such as 

construction and demolition debris, automobile bodies, municipal sludges, combustion 

ash, and industrial process wastes that might also be disposed in municipal waste landfills 

or incinerators” and 

“MSW—otherwise known as trash or garbage—consists of everyday items such as 

product packaging, grass clippings, furniture, clothing, bottles, food scraps, newspapers, 

appliances, and batteries. Not included are materials that also may be disposed in landfills 

but are not generally considered MSW, such as construction and demolition materials, 

municipal wastewater treatment sludges, and non-hazardous industrial wastes.” 
88 

NSWMA believes that EPA should have and use a standard definition of MSW in all documents 

and rules. NSWMA is willing to assist EPA in developing this definition to ensure consistency 

between various EPA rules and documents. 

Response: We have finalized a definition of municipal solid waste that is similar to that used in 

the subpart Ea of the NSPS regulations. Please see Section II.F of the preamble for the final rule 

amendments for the response to this comment. 

Although consistency is desirable, it is beyond the scope of the GHGRP to try and make all of 

the definitions of MSW in all EPA regulations and guidance documents the same. We proposed 

a substantive definition taken from Subpart Ea, which specifically regulates large MWC units. 

In response to comments received, the final rule clarifies when certain materials are either 

included in or excluded from the definition. The adjustments made to the definition are 

consistent with the regulatory history of Subpart Ea. 

Commenter Name: Rhea Hale 

Commenter Affiliation: American Forest & Paper Association (AF&PA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2382.1 

Comment Excerpt Number: 4 

Comment: The American Forest & Paper Association (AF&PA) requests the following edits 

(see the phrases in square brackets) to the proposed definition of municipal solid waste: 

Municipal solid waste or MSW means solid phase household, commercial/retail, and/or 

institutional waste. Household waste includes material discarded by single and multiple 

residential dwellings, hotels, motels, and other similar permanent or temporary housing 

establishments or facilities. Commercial/retail waste includes material discarded by stores, 

offices, restaurants, warehouses, nonmanufacturing activities at industrial facilities, and other 

similar establishments or facilities. Institutional waste includes material discarded by schools, 

nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at 

prisons and government facilities, and material discarded by other similar establishments or 

facilities. Household, commercial/retail, and institutional waste does not include used oil, wood 

pellets, construction, renovation, and demolition wastes (which includes, but is not limited to, 

railroad ties and telephone poles), [paper that is commonly recycled,] clean wood, industrial 

process or manufacturing wastes, medical waste, or motor vehicles (including motor vehicle 

parts or vehicle fluff). Household, commercial/retail, and institutional wastes include yard waste, 

refuse-derived fuel, and motor vehicle maintenance materials, limited to vehicle batteries and 

tires, except where a single waste stream consisting of tires is combusted in a unit. 

Response: The exclusion of “paper” was an oversight and should have been included in the 

definition. Therefore, we have incorporated the commenter's suggestion. The definition of 

MSW in the final rule specifies that when paper is separately collected, processed, and disposed 

of (such as by recycling), it is not considered to be MSW. 

Commenter Name: Ted Michaels 
89 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 7 

Comment: EPA has proposed to amend the definition of “municipal solid waste” in the MRR to 

closely match the definition in Subpart Ea of the NSPS regulations (40 CFR 60.51a). However, 

strict application of the NSPS definition of MSW in the MRR would mean that the presence of 

any exempted material could trigger Tier 4 reporting, even for units rated below 600 tons per 

day. 

The NSPS definition includes a list of excluded materials from the categories of household, 

commercial/retail, and institutional waste including used oil, wood pellets, construction, 

renovation, and demolition wastes (which includes, but is not limited to, railroad ties and 

telephone poles), clean wood, industrial process or manufacturing wastes, medical waste, or 

motor vehicles (including motor vehicle parts or vehicle fluff). These materials can be present in 

municipal solid waste streams to varying degrees. The material exclusions contained in the NSPS 

definition was intended to delineate a group of materials that would be regulated under NSPS 

source categories separate from municipal waste combustors when combusted in a single stream, 

not to imply that these materials would not be present to some extent in municipal solid waste. 

As applied in the GHG MRR, however, exclusion of these materials could lead to the unintended 

consequence of reintroducing Tier 4 reporting requirements for units below the 600 tons per day 

threshold. The proposed language of the MRR Corrections states that Tier 2 can be used for 

MSW, as long as Tier 4 is not required (units above 600 tons per day). The presence of excluded 

materials in a waste stream could cause it to be a material other than “municipal solid waste” for 

the purposes of the MRR and therefore unable to report using Tier 2, regardless of the rated 

capacity of the unit. 

We strongly recommend that the EPA return to the definition of “municipal solid waste” as 

promulgated in the MRR published in the Federal Register on October 30, 2009 or specifically 

recognize that facilities permitted as municipal waste combustors under the NSPS requirements 

of 40 CFR 60 combust “municipal solid waste.” 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2378.1, excerpt 1 and 2 

for the response to this comment. 

Commenter Name: Brian Gasiorowski 

Commenter Affiliation: Lafarge North America 

Document Control Number: EPA-HQ-OAR-2008-0508-2401.1 

Comment Excerpt Number: 3 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 9 
90 

These two commenters submitted identical comments on this subject. 

Comment: Municipal Solid Waste. We propose that EPA’s proposed municipal solid waste 

definition (EPA, August 11, 2010) be modified further by adding the phrase "recovered or 

separated plastics" as shown in bold italic type. 

Municipal solid waste or MSW means solid phase household, commercial/retail, and/or 

institutional waste. Household waste includes material discarded by single and multiple 

residential dwellings, hotels, motels, and other similar permanent or temporary housing 

establishments or facilities. Commercial/retail waste includes material discarded by 

stores, offices, restaurants, warehouses, non-manufacturing activities at industrial 

facilities, and other similar establishments or facilities. Institutional waste includes 

material discarded by schools, nonmedical waste discarded by hospitals, material 

discarded by non-manufacturing activities at prisons and government facilities, and 

material discarded by other similar establishments or facilities. Household, 

commercial/retail, and institutional waste does not include used oil, wood pellets, 

recovered or separated plastics, construction, renovation, and demolition wastes (which 

includes, but is not limited to, railroad ties and telephone poles), clean wood, industrial 

process or manufacturing wastes, medical waste, or motor vehicles (including motor 

vehicle parts or vehicle fluff). Household, commercial/retail, and institutional wastes 

include yard waste, refuse-derived fuel, and motor vehicle maintenance materials, limited 

to vehicle batteries and tires, except where a single waste stream consisting of tires is 

combusted in a unit. 

Response: Please see Section II.G of the preamble for the final rule amendments for the 

response to this comment. 

Definition of natural gas 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 5 

Comment: The amendments include a revision to the definition of natural gas to indicate that it 

is composed of at least 70% CH4 by volume or has a HHV between 910 and 1150 Btu/scf. This 

revision conflicts with the remainder of the definition, as the range of HHV values represents a 

narrow range of pipeline quality natural gas, and excludes most field quality natural gas. This 

poses significant issues when considering the use of the term natural gas in the context of 

Subpart W. This revision also negates the change to Table C-1, where “pipeline” is removed 

from the description of natural gas. API requests that EPA maintain the definition of natural gas 

from the October 30, 2009 rule, with the exception of removing the last sentence. The revised 

definition would read: 
91 

“Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon 

gases found in geologic formations beneath the earth’s surface, of which its constituents 

include, but are not limited to, methane, heavier hydrocarbons, and carbon dioxide. 

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

Response: EPA decided to remove the specifications regarding a minimum methane content 

and a range of high heating values in the definition of natural gas. Please refer to Section II.F.2 

of the preamble to the final rule amendments for the rationale for removing these specifications. 

We decided not to use the exact definition provided by the commenter because adding the term 

“which varies widely” does not increase the utility of the definition after we have removed the 

specifications for HHV range and minimum methane content. The final definition of natural gas 

is also consistent with the removal of “pipeline” in Table C-1. 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 5 

Comment: 98.6 Definition of Natural Gas. EPA is proposing to revise the definition of natural 

gas under 98.6 to indicate that it is composed of at least 70% methane (CH4) by volume or has a 

high heating value (“HHV”) between 910 and 1150 Btu/scf. This revision poses significant 

issues in meeting the reporting timeline of the GHG RP. There are many different types of 

gaseous streams combusted at facilities operated by GPA members companies. The change in the 

definition of “natural gas” forces GPA members to revisit each gas stream to determine if it fits 

within the new definition of natural gas in terms of the carbon content or heating value range, 

and if so, GPA members must determine if the change prompts modifications to the emission 

estimation methodologies required by the rule. In addition, this revision conflicts with the 

remainder of the definition, as the range of HHV values proposed represents a narrow range of 

pipeline quality natural gas, and excludes most field quality natural gas. This revision also 

negates the change to Table C-1, where “pipeline” is removed from the description of natural 

gas. GPA requests that EPA maintain the definition of natural gas from the October 30, 2009 

rule. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2383.1, excerpt 5 for the 

response to this comment. 

Definition of waste oil 

Commenter Name: Kimberly A. Hibbard 

Commenter Affiliation: S.D. Warren Company - Somerset Operations 

Document Control Number: EPA-HQ-OAR-2008-0508-2404 

Comment Excerpt Number: 1 
92 

Comment: The proposed changes to the regulation include the listing of waste oil in Table C-1 

of 40 CFR Part 98 Subpart C General Stationary Fuel Combustion Sources. Once waste oil is 

listed in Table C-1, Section 98.33(b)(3) and (4) would require a source that burns waste oil in a 

boiler with a maximum rated heat input capacity greater than 250 MMBtu/hr to calculate 

greenhouse gas emissions according to Tier 3 or Tier 4. The Somerset Mill has no issue with 

calculating the greenhouse gas emissions from waste oil. However, Section 98.34 sets forth the 

QA/QC requirements for each Tier. For the use of Tier 3, pursuant to 98.34(b)(3) a carbon 

content analysis of waste oil would be required. It is unclear by the proposed definition of waste 

oil if it would be considered "fuel oil" in 98.34(b)(3)(ii)(B) requiring an analysis per lot or "other 

liquid fuels other than fuel oil" in 98.34(b)(3)(ii)(C) requiring one analysis per calendar quarter. 

S .D. Warren adds both onsite generated and purchased waste oil directly into the mill’s No .6 

fuel oil main supply tank. The onsite generated waste oil is added in small volumes at a time 

(approximately 700 gallons or less). If waste oil is considered fuel oil, would a carbon content 

analysis be required for each small volume of onsite generated waste oil added to the No. 6 oil 

tank? Additionally, offsite waste oil is received in relatively small volumes from commercial 

retailers. The cost associated with the carbon content analysis for both onsite and offsite 

generated waste oil seems excessive given the small quantity used by the Somerset Mill and the 

relatively small impact on GHG emissions. 

Response: The term “waste oil” has been replaced with the term “used oil” in the final rule 

amendments (see Section II.F of the preamble to the final rule amendments.) Used oil consists 

primarily of used lubricating and automotive oils (e.g., used motor oil, transmission oil, 

hydraulic fluids, brake fluid, industrial engine oils, metalworking oils, process oils, industrial 

grease, etc). EPA’s long-standing position that on-specification used oil is essentially 

equivalent to virgin fuel oil. Therefore, used oil is considered to be fuel oil. 

For a unit that has a heat input capacity greater than 250 mmBtu/hr and combusts fuels in Table 

C-1 other than natural gas and distillate oil, the use of Tier 3 is triggered. For the specific case 

cited by the commenter, if the used oil and the No. 6 oil are treated as separate fuels, each one 

would have to be analyzed for carbon content at the frequency specified in §98.34(b)(3)(ii)(B), 

and the quantity of each fuel would have to be separately measured, using either calibrated flow 

meters or tank drop measurements, as applicable. However, in accordance with 

§98.34(b)(3)(ii)(F) and the term “Fuel” in Equation C-4, if the mixture (blend) of No. 6 oil and 

used oil is considered to be the “fuel type”, carbon content sampling would be required only 

once per quarter, and tank drop measurements could be used to quantify the amount of blended 

fuel combusted. 

Please see also the response to the subpart C comment EPA-HQ-OAR-2008-0508-2404, excerpt 

2, under “Tier 3 Applicability”. 

Commenter Name: Sean M. O'Keefe 

Commenter Affiliation: Alexander & Baldwin, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2380.1 

Comment Excerpt Number: 4 
93 

Comment: References to "waste oil" should be changed to "used oil". EPA has proposed to add 

a definition of "waste oil" to section 98.6 of the reporting rule and to add a higher heat value 

(HHV) and default CO2 emission factor for waste oil to Table C-I. In a separate rulemaking 

(Docket Number EPA-HQ-RCRA-2008-0329, Identification of Non-Hazardous Secondary 

Materials That Are Solid Waste; Proposed Rule), EPA is considering, among other things, 

whether used oil should be classified as a solid waste. In that rulemaking, EPA has proposed not 

to classify on-specification used oil as a solid waste but instead to consider it a "traditional fuel ". 

This conclusion is based on the EPA’s long-standing position that on-specification used oil is 

essentially equivalent to virgin fuel oil. A&B believes that use of the term "waste oil" in the 

GHG Reporting Rule suggests that EPA considers all oil meeting the proposed definition of 

"waste oil", including on-specification used oil, to be a waste, which is inconsistent with EPA’s 

position as expressed in the proposed solid waste rule. While A&B recognizes that the solid 

waste rule has been proposed under the RCRA program, we note that whether or not certain 

materials, including used oil, are classified as solid waste under this rule will determine whether 

facilities which burn these materials will be regulated as boilers or as commercial and industrial 

solid waste incinerators under the Clean Air Act. For consistency with other regulatory 

programs, therefore, A&B recommends that EPA use the term "used oil" rather than "waste oil" 

in the GHG Reporting Rule. 

Response: The term “waste oil” has been replaced with the term “used oil” in the final rule 

amendments. Please see Section II.F of the preamble to the final rule amendments and response 

to comment EPA-HQ-OAR-2008-0508-2404, excerpt 1 for additional information in response to 

this comment. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 5 

Comment: “Waste oil” is proposed to be added to the list of petroleum products in Table C-1, 

and an accompanying definition added to 40 CFR 98.6. PCA supports broader definitions. PCA 

believes these changes add flexibility. 

Response: The term “waste oil” has been replaced with the term “used oil” in the final rule 

amendments. Please see Section II.F of the preamble for the final rule amendments for the 

response to this comment. 

Definition of wood residuals 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 2 
94 

Comment: The proposed definition of Wood Residuals needs to be expanded. The final rule has 

a definition of “biomass” in Subpart A at §98.6. That definition is generally broad enough to 

accommodate valuable sources of biogenic fuels in the U.S. Because the biomass definition 

includes the phrase “... including products, by-products, residues and waste from agriculture, 

forestry and related industries,” this definition, in our understanding, includes among other 

woody biomass resources the wood residuals from downstream wood products manufacturing as 

well as wood residuals from the initial processing of timber at forest products industry mills. The 

original rule also has the terms “Wood and Wood Residuals,” along with “Agricultural 

Byproducts,” “Peat” and “Solid Byproducts” as listed, specific solid biomass fuel types in Table 

C-1 to Subpart C. Table C-1 provides “Default CO2 Emission Factors and High Heat Values for 

Various Types of Fuel,” which are used in various emissions calculations for those employing 

either the Tier 1 or Tier 2 calculation methods. However, none of these specified solid biomass 

types are defined in the original rule, though default CO2 emission factors and High Heat Values 

were provided for each. 

So now EPA is providing definitions for three of the four terms: “Wood Residuals,” 

“Agricultural Byproducts,” and “Solid Byproducts.” EPA explains in the preamble to the 

proposed rule that it is proposing to add definitions of the terms to §98.6 “...due to the large 

number of questions received requesting clarification of the definition of these terms.” Preamble 

at pg 48754. Further, EPA indicates it has drawn the proposed definitions “...based on the results 

of an Internet search and IPCC inventory guidelines.” 

For Subpart C (General Stationary Fuel Combustion Sources) sources burning biomass we are 

concerned that the newly proposed Wood Residuals definition is defined with so much 

specificity that it is unclear whether biomass residuals from downstream manufacturing, such as 

wood panel plants and engineered wood products mills are covered by the default values Table 

C-1 provides. To ensure those residuals are included we suggest the following modification 

(underlined language) to the proposed definition: 

Wood residuals means wood waste recovered from three principal sources: Municipal 

solid waste (MSW); construction and demolition debris; and primary timber processing. 

Wood residuals recovered from MSW include wooden furniture, cabinets, pallets and 

containers, scrap lumber (from sources other than construction and demolition activities), 

and urban tree and landscape residues. Wood residuals from construction and demolition 

debris originate from the construction, repair, remodeling and demolition of houses and 

non-residential structures. Wood residuals from primary timber processing include bark, 

sawmill slabs and edgings, sawdust, and peeler log cores. Other sources of wood 

residuals include, but are not limited to, railroad ties, telephone and utility poles, pier and 

dock timbers, wastewater process sludge from paper mills, trim, sander dust and sawdust 

from wood products manufacturing including resinated wood product residuals, and 

logging residues. 

Response: This change has been made to the definition. Please see Section II.F of the preamble 

for the final rule amendments for the response to this comment. 
95 

Commenter Name: Rhea Hale 

Commenter Affiliation: American Forest & Paper Association (AF&PA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2382.1 

Comment Excerpt Number: 3 

Comment: EPA requested comment on whether is it appropriate to apply emissions factors for 

wood residuals to wastewater treatment sludges from pulp and paper mills. The American Forest 

& Paper Association (AF&PA) agrees that it is appropriate for wastewater treatment sludges to 

be included in the revised definition of wood and wood residuals and to apply the same 

emissions factors for wood residuals to wastewater treatment sludges. AF&PA requests the 

following edits (see the phrases in square brackets) to the proposed definition of wood residuals: 

Wood residuals means [materials] recovered from three principal sources: municipal 

solid waste (MSW); construction and demolition debris; and primary timber processing. 

Wood residuals recovered from MSW include wooden furniture, cabinets, pallets and 

containers, scrap lumber (from sources other than construction and demolition activities), 

and urban tree and landscape residues. Wood residuals from construction and demolition 

debris originate from the construction, repair, remodeling and demolition of houses and 

non-residential structures. Wood residuals from primary timber processing include bark, 

sawmill slabs and edgings, sawdust, and peeler log cores. Other sources of wood 

residuals include, but are not limited to, railroad ties, telephone and utility poles, pier and 

dock timbers, wastewater process sludge from paper mills, [trim, sander dust and sawdust 

from wood products manufacturing including resinated wood product residuals,] and 

logging residues. 

Response: This change has been made to the definition. Please see Section II.F of the preamble 

for the final rule amendments for the response to this comment. 

Other definitions 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 1 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 1 

These two commenters submitted identical comments on this subject. 

Comment: EPA is proposing to correct the definition of “fossil fuel” and revert to the definition 

in the Proposed Rule, making the definition consistent with the definition used in the Clean Air 
96 

Act (CAA) New Source Performance Standards program. 74 Fed. Reg. 16621. We support the 

proposed correction as appropriate and necessary to ensure municipal solid waste (MSW) and 

tires are not inappropriately defined as fossil fuel. WM further supports the deletion of the 

definition of “fossil fuel-fired” that was not present in the Proposed Rule. We also note that by 

making these technical corrections and reverting to the definition of “fossil fuel” contained in the 

Proposed Rule, EPA has already afforded the public notice and ample opportunity to comment of 

the corrected definition. 

Response: Please see Section II.F of the preamble for the final rule amendments for the 

response to this comment. 

Commenter Name: John H. Skinner 

Commenter Affiliation: Solid Waste Association of North America (SWANA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2397.1 

Comment Excerpt Number: 1 

Comment: The Solid Waste Association of North America (SWANA) agrees with EPA’s 

decision to revert the definition of “fossil fuel” back to that in the proposed rule. This definition 

is consistent with the definition of fossil fuel under the Clean Air Act’s New Source Performance 

Standards. Our concern over EPA’s new definition presented in the final version of the reporting 

rule is that it would classify municipal solid waste as “fossil fuel”, and reflected a significant 

change from the proposed rule by EPA without notice or the opportunity for public comment. 

Response: We thank the commenter for the input. We have finalized the definition of fossil 

fuel as proposed. Please see Section II.F of the preamble for the final rule amendments for the 

response to this comment. 

Commenter Name: Edward W. Repa 

Commenter Affiliation: National Solid Wastes Management Association (NSWMA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2379.1 

Comment Excerpt Number: 2 

Comment: EPA is proposing that the definition of fossil fuel be returned to the initial proposed 

definition to provide clarity and make it consistent with other Clean Air Act sections. NSWMA 

agrees with this change because fossil fuel will not inappropriately include MSW and tires, 

which is the way fossil fuel was defined in the original Proposed Rule. 

Response: We thank the commenter for the input. We have finalized the definition of fossil 

fuel as proposed. Please see Section II.F of the preamble for the final rule amendments for the 

response to this comment. 

Commenter Name: Brian Gasiorowski 

Commenter Affiliation: Lafarge North America 
97 

Document Control Number: EPA-HQ-OAR-2008-0508-2401.1 

Comment Excerpt Number: 2 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 8 

These two commenters submitted identical comments on this subject. 

Comment: 1. Proposed Definition Changes Plastics. We propose the following definition for 

plastics: 

Plastics means plastic waste recovered or separated from three principal sources: 

municipal solid waste (MSW); construction and demolition debris; and waste from 

manufacturing and industrial processes. Plastics from MSW include non-recyclable or 

unwanted plastic parts, components, pieces, etc. from household, commercial or 

institutional sources - such as bottles, containers, bags, CD cases, sheeting, packaging, 

broken consumer goods, etc. Plastic from construction and demolition debris are typically 

piping, tubing, sheeting, coverings, containers, taping, etc, Plastics from manufacturing 

or industrial process include trimmings, cuttings, ends of rolls, off-spec or unsalable 

product or packaging, off-spec intermediate product or plastics residues from other 

recycling or separation processes. 

Response: No change has been made as a result of this comment. We do not feel that it is 

necessary to define the term “plastics” in the final rule amendments since it is commonly 

understood and easily recognized whether a material or fuel source is plastic or non-plastic. The 

commenter is apparently concerned that plastic waste recovered from MSW and processed 

separately might be classified as MSW. The definition of MSW in the final rule makes it clear 

that this is not the case.

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2394.1 

Comment Excerpt Number: 2 

Comment: The American Gas Association (AGA) supports EPA’s proposal to correct the 

confusing definition of “Mscf” in 40 C.F.R. 98.6 to say that the term means thousand standard 

cubic feet – which is the normal usage in the industry -- and not as incorrectly stated in the final 

rule, a million standard cubic feet. When combusted, 460,000 thousand standard cubic feet of 

natural gas could be expected to produce 25,000 tons of CO2. While it was obvious that this was 

what EPA intended, the incorrect definition left our members confused. No doubt, the agency 

intended to say 460 million standard cubic feet – which is the same amount as 460,000 thousand 

standard cubic feet. We were among those who pointed out this discrepancy, and we appreciate 

your proposed correction. However, we note that while the preamble mentions this proposed 
98 

change, there appears to be no such provision in the actual proposed amendments to section 98.6. 

See 75 Fed. Reg. at 48754 and 48785-86. The final rule should include this change. 

Response: The definition of "Mscf" was corrected in the amendments to 40 CFR part 98, subpart 

A, which were signed on October 7, 2010, and published in the Federal Register on October 28, 

2010. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 4 

Comment: §98.6 Definition of mscf: EPA states in the preamble on pages 48753 and 48754 the 

intention to revise the definition of mscf from “million standard cubic feet” to “thousand 

standard cubic feet”. API supports this clarification. However, the proposed regulatory text and 

redline version incorporating the August 11 revisions do not reflect the change. EPA should 

reflect the change in definition for mscf throughout the rule. 

Response: The definition of "Mscf" was corrected in the amendments to 40 CFR part 98, subpart 

A, which were signed on October 7, 2010, and published in the Federal Register on October 28, 

2010. 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 4 

Comment: §98.6 Definition of mscf: EPA states in the preamble on pages 48753 and 48754 the 

intention to revise the definition of mscf from “million standard cubic feet” to “thousand 

standard cubic feet”. GPA supports this clarification. However, the proposed regulatory text and 

redline version incorporating the August 11 revisions do not reflect the change. GPA requests 

that EPA reflect the change in definition for Mscf throughout the rule 

Response: The definition of "Mscf" was corrected in the amendments to 40 CFR part 98, subpart 

A, which were signed on October 7, 2010, and published in the Federal Register on October 28, 

2010. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 5 
99 

Comment Definition of Mscf. Current language: “Mscf means million standard cubic feet.” 

Proposed language with requested changes denoted by bold font: Mscf means thousand standard 

cubic feet. Justification: The proposed language corrects a technical error in the rule language. 

Response: The definition of "Mscf" was corrected in the amendments to 40 CFR part 98, subpart 

A, which were signed on October 7, 2010, and published in the Federal Register on October 28, 

2010. 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2350 

Comment Excerpt Number: 1 

Comment: There are still errors in the updated proposed rule. The definition of Mscf is still 

defined as million standard cubic feet. 

Response: The definition of "Mscf" was corrected in the amendments to 40 CFR part 98, subpart 

A, which were signed on October 7, 2010, and published in the Federal Register on October 28, 

2010. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 4 

Comment: Definition of maximum rated heat input capacity: Current language: “Maximum 

rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts 

the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as 

of the initial installation of the unit, as specified by the manufacturer.” Proposed language with 

suggested changes in square brackets: “Maximum heat input capacity" means the [maximum 

heat value an affected source can combust on a steady state basis as determined by the physical 

and operational design and characteristics of the affected source. Maximum heat input capacity is 

expressed in millions of British Thermal Units (mmBtu) per unit of time. Maximum heat input 

capacity is the product of the gross caloric value (Higher Heating Value) of the fuel (expressed in 

Btu/mass) multiplied by the maximum fuel feed rate for the combustion device (expressed in 

mass of fuel/time)].” The proposed language is consistent with EPA’s response to a specific 

question posted by El Paso and provides clarification to the determination of the maximum heat 

input capacity values. 

Response: No rule change has been made as a result of this comment. The changes to the 

definition suggested by the commenter are outside the scope of the specific amendments 

proposed for public comment in the Federal Register notice of August 11, 2010. 
100 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2396.1 

Comment Excerpt Number: 1 

Comment: In Subpart A, §98.6, the definition for “maximum rated heat input capacity” is based 

solely on manufacturer specifications. For existing equipment, this definition may be 

inappropriate or difficult to address. For example, an existing combustion device could have 

been uprated or derated subsequent to initial installation, or manufacturer information may not be 

available for some existing equipment. In instances where a derate or uprate has occurred, as is 

commonly done to gas turbine ratings to account for site-specific ambient conditions, the heat 

input capacity may be included in a permit, and that capacity may differ from the manufacturer 

specifications. To avoid unnecessary confusion and also address the situation where 

manufacturer information is not readily available, the Interstate Natural Gas Association of 

America (INGAA) recommends revising the definition as follows (new text bold and 

underlined). 

Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), 

when it combusts the maximum amount of fuel per hour that it is capable of combusting 

on a steady state basis, as of the initial installation of the unit, as specified by the 

manufacturer. If the manufacturer specification is not available or site capacity 

differs (e.g., due to site-specific conditions that result in unit uprate or derate), then 

the capacity reflected in a permit can be used. If a permitted value is not available, 

capacity defined by the operator can be used. 

Response: No rule change has been made as a result of this comment. The change to Part 98 

suggested by the commenter is outside the scope of the specific amendments proposed for public 

comment in the Federal Register notice of August 11, 2010. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 46 

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

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

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

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

from gaseous fuels. 

Recent amendments to Subparts X and Y provide two options for “molar volume conversion” 

factors that can be used by reporters for standard conditions of 60°F and 14.7 psia or 68°F and 

14.7 psia. However, the same change has not been made to Subpart C. Currently, Subpart C 

defines standard conditions of 68°F and 14.7, and the default natural gas heating value in Table 
101 

C-1 is based on 60°F and 14.7 psia. The issue is further complicated in the proposed Subpart W, 

which introduces other, different “standard conditions” for gaseous sources. This inconsistency 

is extremely confusing and could lead to erroneous emission calculations. In addition, it places 

an unnecessary burden on reporters. 

In addition, the frequently asked questions (FAQ) list on the EPA’s MRR web site was updated 

in March to state that natural gas billing records that report natural gas usage at standard 

conditions other than 68°F and 14.7 psia must be corrected to the EPA standard conditions. 

API requests that EPA take the following specific actions: 

(1) Adopt a consistent approach for standard conditions throughout the rule, where a short list of 

“molar volume conversion” factors are provided for different temperature and pressure 

conditions and instruct reporters to use the appropriate one for their measurement method for 

quantifying GHG emissions. 

(2) Amend the answer in the FAQ to use industry standard conditions of 60°F and 14.7 psia (1 

atmosphere), as specified in the proposed rule, and in accordance with all the consensus industry 

practice standards listed by EPA in the final MRR. 

Response: Please see Section II.G of the preamble for the final rule amendments for the 

response to this comment. The final rule amendments have revised the definition of standard 

conditions in §98.6 to include both 60 °F and 68 °F. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 19 

Comment: API supports the recent amendments to Subparts X and Y which provide two options 

for “molar volume conversion” factors that can be used by reporters for standard conditions of 

60°F and 14.7 psia or 68°F and 14.7 psia. This same option should be included in all subparts of 

the rule. In particular, Subparts A and C currently defines standard conditions of 68°F and 14.7, 

while the default natural gas heating value in Table C-1 is based on 60°F and 14.7 psia. 

Response: Please see Section II.F of the preamble to the final rule amendments for the response 

to this comment. 

Standardized methods incorporated by reference 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2394.1 

Comment Excerpt Number: 3 
102 

Comment: EPA is proposing to add several specific ASTM and ASME standards to those 

incorporated by reference in section 98.7 of the MRR. The American Gas Association (AGA) 

requests that EPA also add the following AGA standards to the list in section 98.7, to facilitate 

their use: 

(1) AGA Report No. 3 --- Orifice Metering of Natural Gas Part 1: General Equations & 

Uncertainty Guidelines (1990) 

(2) AGA Report No. 3 --- Orifice Metering of Natural Gas Part 2: Specification and Installation 

Requirements (2000) 

(3) AGA Report No. 3 --- Orifice Metering of Natural Gas Part 3: Natural Gas Applications 

(1992) 

(4) AGA Report No. 3 --- Orifice Metering of Natural Gas Part 4: Background, Development 

Implementation Procedure (1992) 

(5) AGA Report No. 5 --- Natural Gas Energy Measurement (2009) 

(6) AGA Report No. 7 --- Measurement of Natural Gas by Turbine Meter (2006) 

(7) AGA Report No. 8 --- Compressibility Factor of Natural Gas and Related Hydrocarbon 

Gases (1994) 

(8) AGA Report No. 9 --- Measurement of Gas by Multipath Ultrasonic Meters (2007) 

(9) AGA Report No. 11 --- Measurement of Natural Gas by Coriolis Meter (2003) 

(10) ANSI B109.1 --- Diaphragm-Type Gas Displacement Meters, Capacity Under 500 cft/hr. 

(2000) 

(11) ANSI B109.2 --- Diaphragm-Type Gas Displacement Meters, Capacity 500 cft/hr. and over 

(2000) 

We have found that when a regulation lists specific standards, it can be difficult to persuade 

consultants and others that other unlisted standards published by the same consensus standards 

body may also be used. Therefore, we request that EPA amend the list in 98.7 to include the 

above listed standards. 

Response: The final rule amendments are removing and reserving 40 CFR 98.7(b), which 

incorporated by reference the AGA reports listed by the commenter in items (1), (2), (6), and 

(11). The final rule amendments are not adding the other AGA reports or the ANSI standards 

listed by the commenter. The rationale for removing the AGA reports was explained in the 

preamble to the proposed amendments for subparts C (75 FR 48761), X (75 FR 48770), and Y 

(75 FR 48774), published on August 11, 2010. In short, the reference to these AGA methods 

was removed because the QA/QC sections of these subparts already allowed meters to be 

calibrated according to “a method published by a consensus-based standards organization.” 

Maintaining the lists of methods from the AGA was redundant with allowing the use of methods 

from an organization such as the AGA. 

Accordingly, we have not added the other AGA reports and the two ANSI methods. Rather, in 

many places throughout the document where these reports could have been considered for 

incorporation by reference, we have finalized the rule to allow the use of standards from 

consensus-based standards organizations. We then go on to clarify that consensus-based 

standards organizations include, but are not limited to ASTM, ASME, API, and AGA. Thus, 

although these methods have not been incorporated by reference in 40 CFR 98.7, as requested by 
103 

the commenter, they may still be appropriate to use in accordance with the monitoring and 

QA/QC requirements in the underlying subparts. 

Other Subpart A comments 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Numbers: 1 - 13 

[The commenter suggested several changes to the format of cross-references used in various 

sections of Subpart A.] 

§98.3(c)(6): A written explanation, as required under §98.3 paragraph (e) of this section, if you 

change emission calculation methodologies during the reporting period. 

§98.3(g)(5)(ii): The GHG Monitoring Plan may rely on references to existing corporate 

documents (e.g., standard operating procedures, quality assurance programs under appendix F to 

40 CFR part 60 of this chapter or appendix B to 40 CFR part 75 of this chapter, and other 

documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily 

recognizable. 

§98.4(a) General. *** If the facility is required under any other part of title 40 of the Code of 

Federal Regulations to submit to the Administrator any other emission report that is subject to 

any requirement in 40 CFR part 75 of this chapter, the same individual shall be the designated 

representative responsible for certifying, signing, and submitting the GHG emissions reports and 

all such other emissions reports under this part. 

40 CFR 98.6, Definitions: 

COD means the chemical oxygen demand as determined using methods specified pursuant to 40 

CFR part 136 of this chapter. 

Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the 

composition and properties of which do not meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR §80.40 of 

this chapter, but which meet summer RVP standards required under 40 CFR §80.27 of this 

chapter or as specified by the state.*** 

Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the 

composition and properties of which do not meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR §80.40 of 

this chapter or the summer RVP standards required under 40 CFR §80.27 of this chapter or as 

specified by the state.*** 
104 

Fluorinated greenhouse gas means sulfur hexafluoride (SF6), nitrogen trifluoride (NF3), and any 

fluorocarbon except for controlled substances as defined at 40 CFR part 82 of this chapter, 

subpart A and substances with vapor pressures of less than 1 mm of Hg absolute at 25 degrees 

C.*** 

Landfill means an area of land or an excavation in which wastes are placed for permanent 

disposal and that is not a land application unit, surface impoundment, injection well, or waste 

pile as those terms are defined under 40 CFR §257.2 of this chapter. 

Maximum rated input capacity means the maximum charging rate of a municipal waste 

combustor unit expressed in tons per day of municipal solid waste combusted, calculated 

according to the procedures under 40 CFR §60.58b(j) of this chapter. 

Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous 

geographical space where household waste is placed in or on land. An MSW landfill may also 

receive other types of RCRA Subtitle D wastes (40 CFR §257.2 of this chapter) such as 

commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator 

waste, and industrial solid waste. *** 

Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the 

composition and properties of which meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR §80.40 of 

this chapter and 40 CFR §80.41 of this chapter, and summer RVP standards required under 40 

CFR §80.27 of this chapter or as specified by the state. 

Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the 

composition and properties of which meet the requirements of the reformulated gasoline 

regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR §80.40 of 

this chapter and 40 CFR §80.41 of this chapter, but which do not meet summer RVP standards 

required under 40 CFR §80.27 of this chapter or as specified by the state.*** 

Table A–3 to Subpart A—Source Category List for §98.2(a)(1) 

Source Categories Applicable in 2010 and Future Years 

Electricity generation units that report CO2 mass emissions year round through 40 

CFR part 75 of this chapter (subpart D) 

Response: No rule changes have been made as a result of these comments. The changes to the 

format of the cross references suggested by the commenter are outside the scope of the specific 

amendments proposed for public comment in the Federal Register notice of August 11, 2010. 

Moreover, although we do not necessarily disagree with the changes, we also do not think they 

are necessary to improve clarity and, as such, have not made changes in the final rule. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 
105 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 14 

Comment: §98.33(e)(2) If a CO2 CEMS (or a surrogate O2 monitor) and a stack gas flow rate 

monitor are used to determine the annual CO2 mass emissions either according to 40 CFR part 75 

of this chapter, the Tier 4 Calculation Methodology, or the alternative calculation methodology 

specified in paragraph (a)(5)(iii); and if both fossil fuel and biomass (except for MSW) are 

combusted in the unit during the reporting year, you may use the following procedure to 

determine the annual biogenic CO2 mass emissions 

Response: This paragraph is being amended and the format of the cross references in the final 

rule language follows the format suggested by the commenter. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 15, 17, and 18 

The commenter suggested several revisions to §98.3(g), Recordkeeping: 

Revise §98.3(g)(2)(iii) to include recordkeeping for product analyses. 

§98.3(g)(2)(iii) The results of all required analyses for high heat value, carbon content, 

and other required fuel, or feedstock, or product parameters. 

Delete §98.3(g)(5)(iv), which is a provision that requires information to be made available to 

EPA during an audit. It is duplicative of the requirements in the introduction to paragraph (g). If 

it is not deleted, consider moving it elsewhere. It is a recordkeeping requirement, which does not 

belong in paragraph (g)(5), which is a description of the GHG Monitoring Plan contents. It could 

be moved to a new paragraph (g)(8), for instance. 

Revise §98.3(g)(6)to include all flow meters since, in addition to fuel flow meters, feedstock, 

product, and process stream meters may provide data used for GHG emission calculations. 

 

§98.3(g)(6) The results of all required certification and quality assurance tests of 

continuous monitoring systems, fuel flow meters, and other instrumentation used to 

provide data for the GHGs reported under this part. 

Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010, as we did not propose 

amendments to these paragraphs in 40 CFR 98.3(g). 
106 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 22 

Comment: There appears to be an error in the citation in the first sentence of §98.4(m)(4), and 

that “paragraph (m)(2)(iv)(A)” should be replaced with “paragraph (m)(2)(v)(A)”. 

Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010, as we did not propose 

amendments to this paragraph. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 1 

Comment: Requirements for facility address in annual report and abbreviated annual report, in 

§98.3(c)(1) and §98.3(d)(3)(i): Current language, including changes proposed by the EPA: 

“Facility name or supplier name (as appropriate), facility or supplier ID number, and physical 

street address of the facility or supplier, including the city, state, and zip code.” 

Suggested language with proposed new language in square brackets: “Facility name or supplier 

name (as appropriate), facility or supplier ID number, and physical street address of the facility 

or supplier, including the city, state, and zip code. [If a facility or supplier does not have an 

address, a description of physical location of facility or supplier must be provided.]” 

Incorporation of the suggested changes will provide clarification for facilities and suppliers that 

do not have a street address. 

Response: No rule change has been made as a result of this comment. We are not finalizing 

amendments to the 2009 final rule to require reporting of facility or supplier ID. Please see 

Section II.F of the preamble to the final rule amendments for additional information. EPA 

believes that the language in the final rule is sufficient to identify and locate reporting facilities 

and suppliers. A Frequently Asked Question (FAQ) will be available on our website shortly to 

address the few instances where a physical street address may not be available. Please refer to 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.html for more information. 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 3 
107 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 3 

The same comment was submitted by both commenters, with the only difference being the use of 

“GPA” and “API.” 

Comment: 98.3(c)(1) Facility and supplier ID number. EPA proposes to add a requirement for 

each facility or supplier to report an ID number. The preamble in Section II.F on page 48753 

states the exact mechanism for assigning the ID numbers has not yet been determined and EPA 

will provide necessary guidance later this year. Without knowing the mechanism for assigning 

the ID numbers, GPA cannot fully review and comment on this proposed revision and anticipates 

commenting on the guidance when it is issued. GPA requests that EPA provide a separate public 

comment period when the mechanism and guidance for assigning facility or supplier ID numbers 

is available. 

Response: EPA is not amending the 2009 final rule to require each facility or supplier to report 

an ID number. Please see section II.F of the preamble for the response to this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 44 

Comment: Designated Representative Section §98.4(a) requires that each facility and each 

supplier have “one and only one designated representative, who shall be responsible for 

certifying, signing, and submitting GHG emissions reports” and other submissions. It is overly 

burdensome and unnecessary to require each facility and each supplier to authorize only one 

designated representative. Because the rule broadly defines “facility” in §98.6 to include 

contiguous or adjacent properties, the rule would unreasonably require that a single person be the 

designated representative for contiguous or adjacent plants even if they have vastly different 

responsibilities. This is especially true given the requirement of §98.4(e)(1) that designated 

representatives certify, among other things, that they “have personally examined, and am 

familiar with, the statements and information submitted” to EPA. A single designated 

representative might not have the detailed expertise to evaluate data and emissions from all of 

the processes of large complex facility. For example, the refinery plant manager who is in the 

best position to certify an emissions report for a refinery plant is unlikely to have the familiarity 

or expertise to sign an emissions report for the adjacent chemical plant over which he or she has 

no authority or control. 

Recommendation: We request that EPA delete the requirement that each facility and each 

supplier have “one and only one designated representative.” We request the language in §98.4 

be amended to allow each facility and each supplier to have “one or more designated 

representatives.” Such an amendment would be consistent with EPA’s approach for Title V 
108 

reporting requirements; under that program, facilities in a Title V permit can designate a 

responsible official for each covered source (40 C.F.R. pts. 70, 71). 

Response: No rule change has been made as a result of this comment. The change to Part 98 

suggested by the commenter is outside the scope of the specific amendments proposed for public 

comment in the Federal Register notice of August 11, 2010. 

3. SUBPART C – GENERAL STATIONARY FUEL COMBUSTION 

Definition of source category 

Commenter Name: Sean M. O'Keefe 

Commenter Affiliation: Alexander & Baldwin, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2380.1 

Comment Excerpt Number: 1 

Comment: The exemption for emissions from "pilot lights" requires further clarification. EPA 

has proposed to clarify that GHG emissions from a pilot light need not be included in the 

emissions totals for a facility by adding a new section 98.30(d) which specifically states, "You 

are not required to report emissions from pilot lights". A&B supports the proposed clarification, 

which is justified because a pilot light simply initiates the combustion process in a boiler, 

turbine, or other fuel combustion device and is not used to produce electricity or steam, or to 

provide useful energy to an industrial process, or to reduce waste by removing combustible 

matter. Therefore, for the purposes of Part 98, a pilot is not considered to be a stationary fuel 

combustion source and pilot gas consumption should not be required to be included in the GHG 

emissions calculations. However, the proposed section 98.30(d) goes on to state, "A pilot light is 

a small permanent auxiliary flame that ignites the burner of a combustion device when the 

control valve opens" (emphasis added). In some boilers, propane or liquefied petroleum gas is 

used to ignite oil burners when oil firing is initiated in the boiler. The igniter fires gas in the 

burner for a pre-determined period of time and then extinguishes once combustion of oil in the 

burner has commenced. The igniter is not a "permanent auxiliary flame" because it does not 

remain lit once the burner ignition cycle has been completed. The statement that a pilot light is 

"permanent" would therefore appear to exclude such igniters from the proposed clarifying 

language, even though they serve the same purpose as a "pilot light" and clearly are also not 

stationary fuel combustion sources for the purposes of Part 98. Moreover, such igniters would 

tend to have lower GHG emissions than a pilot light because they fire only intermittently as 

needed and remain lit for only a short period of time. A&B therefore recommends that the word 

"permanent" be deleted from the proposed section 98.30(d) in order to clarify that igniters which 

provide only a temporary flame for burner ignition are also not subject to the GHG reporting 

requirement. 
109 

Response: EPA acknowledges that, in an effort to conserve fuel, pilot lights may not be 

permanently operated. Accordingly, we have removed the word "permanent" from the definition 

of pilot light in 40 CFR 98.30(d). 

Commenter Name: Sean M. O'Keefe 

Commenter Affiliation: Alexander & Baldwin, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2380.1 

Comment Excerpt Number: 3 

Comment: Based on the foregoing discussion and guidance previously provided by EPA, it is 

A&B’s understanding that reporting of GHG emissions from ignition fuels is not required 

because such fuels simply initiate the combustion process in a boiler, turbine, or other fuel 

combustion device and are not used to produce electricity or steam, or to provide useful energy 

to an industrial process, or to reduce waste by removing combustible matter. The proposed 

clarification of calibration requirements applicable to meters used exclusively for ignition fuels, 

however, would appear to suggest that reporting of emissions from these fuels is in fact required, 

since clarification of meter calibration requirements would not be required for fuels for which 

GHG emissions are not reported. A&B therefore requests that EPA explicitly state in the rule 

that reporting of GHG emissions from ignition fuels is not required. 

Response: EPA agrees with the commenter that pilot lights will effectively be burning an 

ignition fuel. The language in 40 CFR 98.3(i)(4) was not intended to imply that the fuel 

consumed in pilot lights is required to be reported. To make this clear, we have removed the 

word "ignition" from 40 CFR 98.3(i)(4). This modification is not intended to be an expansion of 

what is considered to be a pilot light. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 6 

Comment: Listing of excluded source categories §98.30(b)(4): Current language: “Flares, unless 

otherwise required by provisions of another subpart of this part to use methodologies in this 

subpart.” Proposed language: “Flares.” The current language may lead reporters to believe that 

subpart C provides methodologies to calculate emissions from flares. 

Response: We are not making the change recommended by the commenter. Although specific 

methodologies are not provided for flares in Subpart C, other subparts may direct reporters to 

calculate combustion emissions from destruction devices using the general methodologies 

provided in Subpart C. 

Tier 1 Calculation Methodology 
110 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 23 

Comment: In §98.33(a)(1), EPA added flexibility by adding Equation C-1a to the Tier 1 

calculation methodologies. Equation C-1a allows a facility to calculate CO2 emissions from 

natural gas combustion when natural gas billing records are used to quantify fuel usage and gas 

consumption is expressed in units of therms. However, sometimes billing records are expressed 

in units of energy other than therms (e.g., mmBtu), so the term “therms” should be replaced with 

the more general “units of energy”. This would require language in the introductory text to 

specify that the units of energy must be converted to therms for use in Equation C-1a. If this 

suggested change is accepted, it would necessitate analogous changes to other parts of the rule 

which are also shown below. Additional clerical corrections are also shown below. Regardless of 

whether the above suggestion is accepted, a very important omission seemed to be made in that 

there’s no analogous equation to the new Equation C-1a in §98.33(c) for calculating CH4 and 

N2O emissions. It is proposed below to add a new Equation C-8a for this purpose. 

Response: EPA acknowledges that customers may receive natural gas billing information in 

energy units other than therms. To add more flexibility, we are adding Equation C-1b to 

calculate emissions when the natural gas billing records are provided in units of mmBtu. We are 

also adding two new equations to 40 CFR 98.33(c), Equations C-8a and C-8b, for calculating 

CH4 and N2O emissions when the fuel usage information on natural gas billing records is in units 

of therms or mmBtu. The language in 40 CFR 98.33(b)(1)(v) has also been revised to include 

mmBtu in addition to therms to explicitly allow the use of the Tier 1 equation when natural gas 

billing records are received in units of therms. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 24 

Comment: Changes related to replacing the term “therms” with “units of energy”. 

§98.33(a)(1)(i) Use Equation C-1 except when natural gas billing records are used to quantify 

fuel usage and gas consumption is expressed in units of energy (e.g., mmBtu, therms).*** 

§98.33(a)(1)(ii) If natural gas consumption is obtained from billing records and fuel usage is 

expressed in units of energy (e.g., mmBtu, therms), use Equation C-1a. Fuel usage must be 

converted to therms when using Equation C-1a. 

§98.33(b)(1)(v) May be used for natural gas combustion in a unit of any size, in cases where the 

annual natural gas consumption is obtained from fuel billing records in units of energy (e.g., 

mmBtu, therms). 
111 

Changes related to addition of new Equation C-8a and clerical corrections to promote 

consistency in language throughout the rule. 

§98.33(c)(1)(i) Use Equation C-8 of this section to estimate CH4 and N2O emissions for any 

fuels for which you use the Tier 1 Equation C-1 or Tier 3 Equation C-3, C-4 or C-5 calculation 

methodologies for CO2.*** 

§98.33(c)(1)(ii) Use Equation C-8a of this section to estimate CH4 and N2O emissions for natural 

gas when you use the Tier 1 Equation C-1a calculation methodology for CO2. Use the same 

values for natural gas consumption that you use for the Tier 1 calculation. 

CH4 or N2O=1x10-3[0.1*Gas*EF] (Eq.C-8a) 

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from natural gas combustion (metric tons). 

Gas = Annual natural gas consumption from billing records (therms). 

EF = Fuel-specific default CH4 or N2O emission factor for natural gas, from Table C-2 of this 

subpart (kg CH4 or N2O per mmBtu). 

0.1 = Conversion factor from therms to mmBtu. 

1 x 10-3 = Conversion factor from kilograms to metric tons. 

§98.33(c)(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific 

results from Equations C-8, C-8a, C-9a, C-9b, or C-10 of this section (as applicable) to obtain the 

total annual CH4 and N2O emissions, in metric tons. 

§98.33(c)(6)(ii)(C) Calculate the annual CH4 and N2O emissions from component “i” using 

Equation C-8, C-8a, C-9a, or C-10 of this section, as applicable. 

§98.36(e)((2)(iv)(F) The annual average HHV, when measured HHV data, rather than a default 

HHV from Table C-1 of this subpart, are used to calculate CH4 and N2O emissions for a Tier 3 

unit, in accordance with §98.33(c)(1)(i). 

Other minor clerical changes to promote consistency in language throughout the rule: 

§98.33(c)(2) Use Equation C-9a of this section to estimate CH4 and N2O emissions for any fuel 

for which you use the Tier 2 Equation C-2a calculation methodology of this section to estimate 

CO2 emissions.*** 

§98.33(c)(3) Use Equation C-9b of this section to estimate CH4 and N2O emissions for any fuels 

for which you use the Tier 2 Equation C-2c calculation methodology of this section to calculate 

the estimate CO2 emissions. 
112 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2357.1 excerpt 23 for an 

explanation of how we have added more flexibility for using natural gas billing information. 

Regarding the other changes suggested by the commenter, only two of these have been made, 

i.e., to §§98.33(c)(5) and (c)(6)(ii)(C), to include references to new Equations C-8a and C-8b. 

The other recommended changes are outside the scope of this rulemaking and are deemed 

unnecessary. 

Commenter Name: Caitlin Post 

Commenter Affiliation: Southern Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2377.1 

Comment Excerpt Number: 4 

Comment: EPA is proposing to amend 40 CFR 98.33(e)(1) to allow the use of Tier 1 to 

calculate biogenic CO2 emissions from units that have CO2 CEMS. Southern Company supports 

this proposal; however, EPA should clarify that subpart D units that choose to separately report 

their CO2 emissions from biomass may also use Tier 1. Southern Company believes it is EPA’s 

intent to allow subpart D units to use Tier 1 to calculate their biogenic CO2 emissions, but it is 

not expressly stated. 

Response: EPA has finalized requirements for separate reporting of biogenic CO2 emissions for 

all subpart D units, as well as other units that follow the alternative methods in 40 CFR part 

98.33(a)(5) beginning in the 2011 reporting year. Separate reporting of biogenic CO2 emissions 

is optional for the 2010 reporting year. 

EPA has concluded that the proposed change to 40 CFR 98.33(e)(1) was sufficiently clear that 

Subpart D units could also use Tier 1, and we have finalized it, as proposed. In addition, in 

finalizing these requirements, EPA has provided an additional method in 40 CFR 98.33(e)(6) for 

calculating emissions from the combustion of biomass fuels. Specifically, EPA has finalized 

new equation C-15a to calculate biogenic CO2 emissions. The equation is based on the use of 

heat input data that may be available from the part 75 electronic data reports, or where this is not 

possible, from best available information. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 6 

Comment: §98.33(a)(1)(ii) and §98.33(b)(1)(v): These proposed revisions allow the use of the 

Tier 1 calculation methodology for natural gas for a unit of any size, if fuel consumption 

quantities are obtained from billing records with fuel usage expressed in “therms.” These 

revisions provide greater flexibility, without sacrificing accuracy, when calculating GHG 

emissions from natural gas. First, EPA is correct in using therms as the basic unit. Billing records 

from natural gas suppliers are typically expressed in therms and Equation C-1a reflects this 

commonly used unit of measure. Second, allowing the use of Tier 1 for natural gas for any size 
113 

unit shows a clear understanding of combustion units that fire natural gas. The combustion of 

natural gas results in very consistent combustion properties for any combustion unit regardless of 

size. Therefore, it does not matter what the size of the combustion unit is, Equation C-1a will 

accurately calculate the CO2 emissions. Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. We have finalized the proposed 

requirements. The revision was extended to cases where natural gas billing records are received 

in mmBtu. Please see the response to comment EPA-HQ-OAR-2008-0508-2357.1 excerpt 23. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 22 

Comment: API supports the revision of §98.33(a)(3)(iv) – Allows the use of fuel flow meters 

that measure mass flow rates for gaseous fuels. For liquid fuels, density can be determined using 

a method published by a consensus standards organization. For gaseous fuels, density can be 

determined by manufacturer’s instructions, a method published by a consensus standards 

organization, or an industry practice. 

Response: EPA thanks the commenter for the input. The amendments have been finalized, as 

proposed. 

Tier 2 Calculation Methodology 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 6 

Comment: EPA appropriately provides smaller Subpart C Tier 2 reporters with the flexibility to 

streamline high heating value (“HHV”) data management. The proposed language at proposed § 

98.33(a)(ii)(B) appears to mandate arithmetic averaging of HHV values collected less frequently 

than monthly or for units smaller than 100 million British Thermal Units (mmBTU) per hour 

heat capacity. Arkema has already implemented flow-weighted average reporting systems for 

Tier II reporting facilities. While we appreciate the opportunity to implement either arithmetic or 

flow-weighted HHV reporting, we request that EPA clarify that reporters may elect to use either 

averaging method. 

Response: By making the modification in 98.33(a), we concluded that we were reducing 

reporting burden. However, it was not our intent to mandate the use of the less burdensome 

calculation method. We have revised 40 CFR 98.33(a)(ii)(B) to allow the flexibility of using 
114 

either arithmetic or flow-weighted HHV reporting when HHV data are obtained less frequently 

than monthly, and for smaller units. 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 1 

Comment: Mexichem supports the EPA’s proposal to allow Tier 2 units that receive monthly (or 

more frequently) HHV data to use an arithmetic average annual HHV in the emission 

calculations instead of a fuel-weighted average HHV. We agree that the use of the arithmetic 

average rather than a fuel-weighted average will not significantly enhance data quality. 

Response: EPA thanks the commenter for the input. The final rule provides owners or operators 

the choice of using an arithmetic average or fuel-weighted average HHV. Please see response to 

comment EPA-HQ-OAR-2008-0508-2371.1, excerpt 6. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 2 

Comment: PCA members support flexibility being proposed to calculate GHG emissions. For 

example, EPA proposes to allow the use of billing records for natural gas consumption, when 

such consumption is expressed in therms. To accommodate this flexibility, EPA proposes to 

amend the equation C-1a when making those calculations. EPA proposes to add a new 

paragraph, (b)(1)(v) to 40 CFR 98.33 to reflect this. Section 98.36(e)(2)(1) would also be 

amended to allow gaseous fuel consumption to be reported in units of therms. PCA members 

support this measure. 

Response: EPA thanks the commenter for the input. Please see the response to comment EPAHQ-OAR-2008-0508-2357.1 excerpt 23. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 3 

Comment: EPA also proposes to amend 40 CFR 98.33(a)(2)(i) to require calculation of a 

weighted HHV only for individual Tier 2 units with a maximum rated heat input capacity greater 

than or equal to 100 mmBtu/hr, and for groups of units that contain at least one unit of that size. 

For Tier 2 units smaller than 100 mmBtu/hr and for aggregated groups of Tier 2 units under § 

98.36(c)(1) in which all units in the group are smaller than 100 mmBtu/hr, the annual arithmetic 
115 

average HHV, rather than the annual fuel-weighted average HHV, would be used in Equation C–

2a. 

Response: EPA thanks the commenter for the input. Note that the final rule provides owners or 

operators the choice of using an arithmetic average or fuel-weighted average HHV when HHV 

data are obtained less frequently than monthly, and for smaller units. Please see response to 

comment EPA-HQ-OAR-2008-0508-2371.1, excerpt 6. 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 6 

Comment: 98.33(a)(2)(ii)(B) – Revisions to Tier 2 Calculation Methodology 

According to the preamble on page 48765, EPA proposes to “allow” smaller Tier 2 sources 

(<100 mmBtu/hr) that receive monthly HHV data to use arithmetic annual average HHV instead 

of fuel-weighted average HHV. The proposed regulatory text change to 98.33(a)(2)(ii)(B) (page 

48788) says “If the results of fuel sampling are received less frequently than monthly, or, for a 

unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) 

regardless of the HHV sampling frequency, the annual average HHV shall be computed as the 

arithmetic average HHV for all values for the year (including valid samples and substitute data 

values under §98.35).” 

In the Preamble (pages 48755-8766), EPA notes that “requiring small, low-emitting combustion 

sources to calculate CO2 mass emissions using fuel-weighted annual average HHVs instead of 

arithmetic average values will not significantly enhance data quality.” While GPA agrees with 

this comment, the amendment does not give companies the option to alternatively calculate HHV 

based on a weighted average. 

Computing HHV on a weighted average is the natural gas industry’s standard, as that is how fuel 

billing is conducted. For some GPA members, flow rates and heat content are pulled 

electronically into systems which compute a monthly weighted average HHV. This GHG RP 

modification would force GPA members to reconfigure software systems, an activity that would 

likely pose an issue in meeting the March 2011 reporting deadline, or to calculate a separate heat 

content for GHG RP reporting purposes, thus maintaining two different calculation methods for 

the same information. 

GPA requests that EPA provide the option of calculating HHV based on either a weighted 

average or an arithmetic average. This could be accomplished by changing the “shall” to “may” 

in 98.33(a)(2)(ii)(B) to allow reporters that have already set up and implemented systems to 

calculate flow-weighted average HHV for these sources the option to continue to do so instead of 

revising their systems. 
116 

Response: The final rule provides owners or operators the choice of using an arithmetic average 

or fuel-weighted average HHV when HHV data are obtained less frequently than monthly, and 

for smaller units. See the response to comment EPA-HQ-OAR-2008-0508-2371.1 excerpt 6 for 

an explanation of averaging HHV for Tier 2 sources. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 6 

Comment: §98.33(a)(2)(i)((B) HHV annual average: 

According to the preamble on page 48765, EPA proposes to “allow” smaller Tier 2 sources 

(<100 MMBtu/hr) that receive monthly HHV data to use arithmetic annual average HHV instead 

of fuel-weighted average HHV. The proposed regulatory text change to §98.33(a)(2)(i)(B) (page 

48788) says “If the results of fuel sampling are received less frequently than monthly, or for a 

unit with a maximum rated heat input capacity less than 100 MMBtu/hr (or a group of such 

units) regardless of the HHV sampling frequency, the annual average HHV shall be computed as 

the arithmetic average HHV for all values for the year (including valid samples and substitute 

data values under §98.35).” 

The “shall” should be revised to “may” to allow reporters that have already set up and 

implemented systems to calculate flow-weighted average HHV for these sources the option to 

continue to do so instead of revising their systems. 

Response: The final rule provides owners or operators the choice of using an arithmetic average 

or fuel-weighted average HHV when HHV data are obtained less frequently than monthly, and 

for smaller units. See the response to comment EPA-HQ-OAR-2008-0508-2371.1 excerpt 6 for 

an explanation of averaging HHV for Tier 2 sources. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 7 

Comment: Methodology to determine HHV value in § 98.33(a)(ii)(A): 

Current language, including changes proposed by the EPA: 

“If the results of fuel sampling are received monthly or more frequently, then for each unit with a 

maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of 

units that includes at least one unit of that size), the annual average HHV shall be calculated 
117 

using Equation C-2b of this section. If multiple HHV determinations are made in any month, 

average the values for the month arithmetically.” 

Proposed language with requested changes in square brackets: 

“If the results of fuel sampling are received monthly or more frequently, then for each unit with a 

maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of 

units that includes at least one unit of that size), the annual average HHV shall be calculated 

using Equation C-2b of this section. If multiple HHV determinations are made in any month, 

average the values for the month arithmetically. [You may opt to use this method for units of any 

capacity if the results of fuel sampling are received monthly or more frequently.]” 

Using fuel weighted averaging for HHV results in more accurate results than using arithmetic 

averaging of HHV values. It is assumed that the objective of the change proposed by the EPA 

was to reduce the reporting burden by allowing less complex averaging methods for smaller 

units. However, many reporters, including El Paso, have already designed their reporting systems 

to use fuel weighted averaging for HHV if the HHV values are received on a monthly frequency 

regardless of the combustion unit capacity. The requirement to use arithmetic averaging will 

require changes to the already developed systems while decreasing the accuracy of calculated 

emissions. Therefore, El Paso is requesting the flexibility to use averaging methods as specified 

in the originally promulgated regulation. 

Response: The final rule provides owners or operators the choice of using an arithmetic average 

or fuel-weighted average HHV when HHV data are obtained less frequently than monthly, and 

for smaller units. See the response to comment EPA-HQ-OAR-2008-0508-2371.1 excerpt 6 for 

an explanation of averaging HHV for Tier 2 sources. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 8 

Comment: V. Use of Equation C-2b 

As promulgated, § 98.33(a)(2)(ii) requires the weighting of HHV results from fuel analysis in 

proportion to the amount of fuel burned on a monthly basis when using the Tier 2 methodology 

for any fuel supply for which results are actually obtained at least monthly. In its petition for 

reconsideration UARG objected to this provision as applied to small units or activities that may 

trigger the requirement simply because they share a fuel supply with a Part 75 unit that obtains 

these values at least monthly to satisfy Part 75. Examples of combustion activities that may share 

fuel supplies with Part 75, Appendix D sources include comfort heating, hot water heating, and 

other combustion sources that might otherwise qualify for Tier 1 monitoring. Requiring heat 

input weighting, and estimation of monthly fuel use, for such insignificant activities will provide 

little benefit to the program. Moreover, because monthly fuel use is being determined solely by 
118 

“company records of annual fuel use,” any additional accuracy associated with the HHV 

weighting process is likely to be lost in the calculation. 

In response to UARG’s concerns, EPA proposes to revised § 98.33(a)(2)(ii) to require 

calculation of weighted HHV only for individual Tier 2 units with a maximum rated heat input 

capacity greater than or equal to 100 mmBtu/hr and for groups of units that contain at least one 

unit of that size. 75 Fed. Reg. at 48,755-56. Although UARG continues to question the need for 

HHV weighting at all for homogenous fuels like natural gas and distillate oil, EPA’s proposed 

revision is a significant improvement over the current rule and should prevent application of the 

weighting procedure, and the additional unnecessary recordkeeping and reporting, to 

insignificant activities. UARG is somewhat concerned, however, that the proposed rule as 

drafted could be read to prohibit use of the HHV weighting procedure by a unit or group of units 

with heat input less than 100 mmBtu/hr. Although most small units will want to take advantage 

of the less onerous procedures, UARG can think of no reason to prohibit HHV weighting if a 

source chooses to perform the additional work and asks that EPA either reword the provision or 

confirm in the final rule that the exception is not mandatory. 

Response: The final rule provides owners or operators the choice of using an arithmetic average 

or fuel-weighted average HHV when HHV data are obtained less frequently than monthly, and 

for smaller units. See the response to comment EPA-HQ-OAR-2008-0508-2371.1 excerpt 6 for 

an explanation of averaging HHV for Tier 2 sources. 

TIER 3 CALCULATION METHODOLOGY 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 25 

Comment: Tier 3 Equations C-4 and C-5 at §98.33(a)(3) define the term “Fuel” and refer to 

using fuel flow meters calibrated “according to §98.3(i)”. A more appropriate reference would be 

“according to §98.34(b)” since §98.34(b) includes the requirements of §98.3(i) plus additional 

requirements for meters used for the Tier 3 calculation methodology. 

Response: This comment is outside the scope of the proposed rule. The suggested change is 

also deemed to be unnecessary. The calibration requirements for flow meters are found in 

§98.3(i), and all Subpart C sources must comply with the applicable provisions of §98.34. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 
119 

Comment Excerpt Number: 26 

Comment: Revise §98.33(a)(3)(iii) Equation C-5 and §98.253(b)(1)(ii)(B) Equation Y-2 to 

revise the term “MVC” to be consistent with changes proposed in other parts of the rule. 

Additionally, revise the reporting requirements at §98.36(e)(2)(iv)(B). 

Response: We have revised the nomenclature for Equations C-5 and Y-2 to allow sources to 

calculate the CO2 mass emissions using either the MVC value at 60 oF or 68 oF. See the 

discussion on standard conditions in Section II.G of the Preamble for further information for the 

changes related to subpart C and section II..N of the preamble to the final rule amendments for 

the changes related to subpart Y. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 28 

Comment: In §98.33(a)(3)(v), the reference to ASTM methods should be removed because the 

reference to specific ASTM methods in paragraph (a)(3)(iv) have been removed and replaced 

with a much broader array of methods. 

Response: We agree with the commenter. In the final rule, since the reference to a specific 

ASTM method for measuring density has been removed from §98.33(a)(3)(iv), we have also 

removed from §98.33(a)(3)(v) the cross-reference to that ASTM method. 

Commenter Name: Keith W. Holman 

Commenter Affiliation: National Lime Association (NLA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2361.1 

Comment Excerpt Number: 1 

Comment: EPA published a proposed rule on August 11, 2011 clarifying specific provisions of 

the GHGRR and making technical and editorial corrections. While the proposed rule corrects 

many of the errors in the original GHGRR rule, we note that the proposed rule does not address 

necessary changes to Equation C-5, which sets forth the Tier 3 method for calculating emissions 

from the combustion of gaseous fuel. In the original GHGRR rule, the carbon content definition 

referred to liquid fuels. While the proposed rule acknowledges this error and notes that the 

definitions of carbon content and molecular weight will be revised in Equation C-5, the 

definition of carbon content needs to include a reference to gaseous fuel and include the correct 

units (k C/kg of fuel). These changes, together with an accompanying discussion, were included 

as revisions on pages 137 and 138 of the redline version of the proposed revisions that EPA 

posted on its website. http://www.epa.gov/climatechange/emissions/downloads10/MRRRevisions_Redline.pdf. NLA will look for these changes to be included in the final GHGRR 

revisions rule. 
120 

Response: In our proposed amendments, the definition of Carbon Content (CC) in Equation C-5 

was amended to correct the units of measure. This proposed amendment was published without 

error in the August 11, 2010 Federal Register notice, and we have finalized it, without 

modification. As such, no further action is needed on this issue. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 7 

Comment: §98.33(a)(3)(iv): This proposed revision allows the density of the fuel to be 

determined by industry standards or other established references, rather than requiring laboratory 

testing of the fuels. For gaseous fuels, the density of the fuel may be determined either by a 

calibrated density meter, a published consensus standard or an industry standard practice. For 

liquid fuels, a published consensus standard, an industry standard practice or default density 

value provided in §98.33(a)(3)(v) can be used. In general, the densities of liquid and gaseous 

fuels do not vary significantly, therefore the use of published densities, industry standard values, 

or EPA provided values is appropriate. The key is to consistently use the same referenced value, 

which most facilities will tend to do once they decide on which reference best represents their 

fuel type. This revision provides greater flexibility for the facilities to select the proper 

conversion methodology, as well as eliminating the unnecessary fuel testing costs. Weyerhaeuser 

supports this revision. 

Response: EPA thanks the commenter for the input and we have finalized the amendments, as 

proposed. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 4 

Comment: EPA Should Make Further Changes to the Rule Due to the Addition of "Fuel Gas" to 

Table C-1. 

The proposed addition of "Fuel Gas" to Table C-1 of the Reporting Rule has additional impacts 

on the implementation of this rule that EPA should account for as detailed below: 

#1 - Fuels used in combustion units with a heat input > 250 MMBtu/hr are required to use Tier 3 

if the fuel combusted is listed in Table C-1 unless the fuel is natural gas or distillate. At a 

minimum, if these fuels provide less than 10% of the annual heat input, they should be excluded 

from the reporting requirements just like fuels that do not have an emission factor provided in 

Table C-1. Otherwise, even the presence of a small amount of fuel gas in a gas mixture will 
121 

trigger the Tier 3 requirements. The following regulatory text should be added to 

98.33(b)(3)(B)(iii) regarding Tier 3 requirements: 

Shall be used for a fuel listed (except for natural gas and distillate fuel oil) in Table C-1 and for a 

fuel not listed in Table C-1 of this subpart if the fuel is combusted in a unit with a maximum 

rated heat input capacity greater than 250 mmBtu/hr (or. pursuant to.98.36(c)(3)’ in a group of 

units served by a common supply pipe, having at least one unit with a maximum rated heat input 

capacity greater than 250 mmBtu/hr). provided that both of the following conditions apply: 

(A) The use of Tier 4 is not required. 

(B) The fuel provides 10 percent or more of the annual heat input to the unit or. if 98.36Cc) 

applies, to a group of units served by common pipe. 

Response: The term “still gas” was changed to “fuel gas” to be more consistent with the 

terminology commonly used by industry. We did not intend to introduce Tier 3 requirements for 

units that would not have otherwise been subject to Tier 3 prior to the proposed change. We have 

addressed this concern in the final rule by modifying the definition of “fuel gas” to include only 

fuels generated at petroleum refineries or petrochemical processes subject to subpart X of the 

rule. For additional information regarding the final amendments related to fuel gas, please refer 

to section II.G of the preamble to the final rule amendments. 

We do not agree with the commenter that for traditional fuels there should be a 10% 

cutoff point below which no GHG emissions reporting is required. The 10% rule in Tier 3 is 

only for unconventional fuels that are not listed in Table C-1. Moreover, this general suggestion 

is outside the scope of the August 11, 2010 proposal. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 39 

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

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

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

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

The Tier 3 CO2 emissions calculation methodology in Section §98.33(a)(3)(iii) for gaseous fuels 

defines carbon content and molecular weight of the fuel in terms of annual average and refers to 

section §98.33(a)(2)(ii) for the procedure on how to determine the annual average. 

Section §98.33(a)(2)(ii) states when the frequency of the sample is monthly or more frequently, 

the annual average shall be calculated using Equation C-2b which provides a weighted annual 

average based on fuel quantity. This procedure for calculating annual average when an on-line 

gas chromatograph (GC) is used to determine carbon content may be burdensome depending 
122 

upon whether or not the GC is connected to a data management system and how the data 

management system is configured. A typical on-line GC will analyze a sample about every 15 

minutes. Thus, the carbon content and molecular weight annual weighted average consists of 

35,040 calculations per year per fuel gas stream. 

The rule references §98.33(a) methodologies for carbon content and molecular weight, which 

still requires the use of all values for the year. We request that EPA allow refineries to use 

calculated weekly average carbon content and molecular weight when an on-line GC is used to 

analyze fuel gas content. 

Response: Equation C-2b uses a maximum of 12 monthly average HHVs and 12 monthly fuel 

usage values to determine a weighted average annual HHV. In the final rule, we have clarified 

the term “HHV” in the nomenclature of Equation C-2b, to indicate that each monthly average 

HHV in the equation may be a composite of many samples taken at a particular frequency. This 

same approach applies when the equation is used for weighted average carbon content (CC) or 

molecular weight (MW) determinations. The rule does not specify how the monthly average of 

HHV, CC, or MW is to be obtained. The commenter has suggested that the use of weekly 

averages should be allowed. We agree. A monthly average value determined by averaging four 

weekly averages (where each weekly average is calculated by the data management system using 

the individual 15 minute readings for that week) satisfies the rule requirement to use all available 

data in the monthly average, and is acceptable for any of these parameters. 

Tier 4 Calculation Methodology 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 5 

Comment: WM supports EPA’s proposal to clarify that reporters required to provide gas stack 

moisture content using Part 75 methodologies may use site-specific moisture values where none 

are specified in part 75. As EPA notes in the preamble, many such site-specific values have been 

approved for use by the Agency in the Acid Rain program. 

Response: EPA thanks the commenter for the input. We have finalized the amendment allowing 

site-specific moisture values to be used where none are specified in part 75. 

Commenter Name: John H. Skinner 

Commenter Affiliation: Solid Waste Association of North America (SWANA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2397.1 

Comment Excerpt Number: 3 
123 

Comment: The Solid Waste Association of North America (SWANA) agrees with EPA’s 

proposed clarification regarding the use of site-specific moisture values when none are specified 

in part 75. This approach is similar to that of EPA’s Acid Rain Program. 

Response: EPA thanks the commenter for the input. We have finalized the amendment allowing 

site-specific moisture values to be used where none are specified in part 75. See section II.G of 

the preamble to the final rule amendments for further information. 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 4 

Comment: Section 98.33(a)(4)(iii) proposes changes to the requirements for determining the 

specific default moisture values using measurements with EPA Method 4. For each site-specific 

default moisture percentage, at least nine Method 4 runs are required, and moisture data from the 

relative accuracy test audit (RATA) of a CEMS may be used for this purpose. However, 

§98.34(c)(3) provides flexibility for the owner/operator to follow the applicable procedures in 

appendix B to 40 CFR part 75, appendix F to 40 CFR 60, or an applicable state continuous 

monitoring program. This proposed rule should be consistent throughout, and therefore allow 

owner/operators the ability to utilize less than nine Method 4 runs if a state continuous 

monitoring program allows for such alternatives. The moisture content of a larger flue gas stream 

is not expected to vary significantly over the course of an emission test or RATA. ACC 

recommends that EPA should modify this requirement, and require a minimum of three Method 

4 runs in order to determine the site-specific moisture percentage. 

Response: EPA agrees with the commenter. The commenter correctly notes that situations exist 

where fewer than nine Method 4 runs need to be performed during a RATA. Various regulatory 

programs allow for a single moisture determination to represent multiple RATA runs. We have 

amended 40 CFR 98.33(a)(4)(iii) to allow for the default moisture content value to be based on 

the number of moisture runs required by the applicable RATA regulation. See section II.G of the 

preamble to the final rule amendments for further information. 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 4 

Comment: The Energy Recovery Council (ERC) supports EPA’s proposal to clarify that 

reporters required to provide gas stack moisture content using Part 75 methodologies may use 

site-specific moisture values where none are specified in part 75. As EPA notes in the preamble, 
124 

many such site-specific values have been approved for use by the Agency in the Acid Rain 

program. 

Response: EPA thanks the commenter for the input. We have finalized the amendment allowing 

site-specific moisture values to be used where none are specified in part 75. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 2 

Comment: EPA Should Modify the Requirements to Measure a Site-Specific Default Moisture 

Percentage for Tier 4 Emission Calculations. 

Section 98.33(a)(4)(iii) proposes changes to the requirements for determining the specific default 

moisture values using measurements with EPA Method 4. For each site-specific default moisture 

percentage at least nine Method 4 runs are required and moisture data from the relative accuracy 

test audit (RATA) of a CEMS may be used for this purpose. 

Section 98.34(c)(3) provides flexibility for the owner/operator to follow the applicable 

procedures in either appendix B to 40 CFR part 75, appendix F to 40 CFR 60, or an applicable 

State continuous monitoring program. Thus, this proposed rule change should also provide 

flexibility for the owner/operator to use less than nine Method 4 runs if a State continuous 

monitoring program allows for such alternatives. The moisture content of a larger flue gas stream 

is not expected to vary significantly over the course of an emission test or RATA. Therefore, 

EPA should modify this requirement to require a minimum of three Method 4 runs (instead of 

nine) in order to determine the site-specific moisture percentage. Execution of nine Method 4 

runs is overly burdensome when the results are expected to be similar between test runs. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2368.1 excerpt 4 for an 

explanation of the number of Method 4 runs required. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 6 

Comment: EPA also proposes to amend 40 CFR 98.33(a)(4)(iii) to allow the use of site-specific 

moisture constants under the Tier 4 methodology. The site-specific moisture default value(s) 

would have to represent the fuel(s) or fuel blends that are combusted in the unit during normal, 

stable operation, and would have to account for any distinct difference(s) in stack gas moisture 

content associated with different process operating conditions. For each site-specific default 
125 

moisture percentage, at least nine runs would be required using EPA Method 4—Determination 

of Moisture Content in Stack Gases (40 CFR Part 60, Appendix A–3). Moisture data from the 

relative accuracy test audit (RATA) of a CEMS could be used for this purpose. Each site-specific 

default moisture value would be calculated by taking the arithmetic average of the Method 4 

runs. Each site-specific moisture default value would be updated at least annually, and whenever 

the current value is believed to be non-representative, due to changes in unit or process 

operation. The updated moisture value would be used in the subsequent CO2 emissions 

calculations. Many cement manufacturers support this additional measure, although timing 

constraints have forced some companies to move forward with installation of moisture analyzers, 

making this proposal in some respects too late to allow flexibility with respect to compliance. 

Response: EPA thanks the commenter for the input. We have finalized the amendment allowing 

site-specific moisture values to be used where none are specified in part 75. See section II.G of 

the preamble to the final rule amendments for further information. 

Companies that have moved forward with the installation of moisture sensors are under no 

obligation to continue using them, and may, at any convenient time, determine and use sitespecific moisture default values instead. All such changes in the CO2 emissions calculation 

methodology must be documented in the monitoring plan. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 7 

Comment: Per the requirements of §98.33(a)(4)(iii): If you measure CO2 emissions for Tier 4 

methodology on a dry basis, then you must apply a moisture correction to your mass flow 

calculation using equation C-7. The same paragraph also contains changes which state: 

“you may determine an appropriate site specific default moisture value (or values), using 

measurements made with EPA Method 4—Determination Of Moisture Content In Stack Gases, 

in appendix A–3 to part 60 of this chapter. If this option is selected, the site specific moisture 

default value(s) must represent the fuel(s) or fuel blends that are combusted in the unit during 

normal, stable operation, and must account for any distinct difference(s) in the stack gas moisture 

content associated with different process operating conditions. For each site specific default 

moisture percentage, at least nine Method 4 runs are required. Moisture data from the relative 

accuracy test audit (RATA) of a CEMS may be used for this purpose. Calculate each sitespecific default moisture value by taking the arithmetic average of the Method 4 runs.” 

At the typical stack temperatures that most FCC wet gas scrubbers operate, a small change in 

temperature can mean a big change in the moisture content. The change in moisture content is 

approximately 0.5% moisture per degree Fahrenheit in the 140 degree to 160 degree range. 

Using the average of nine Method 4 runs as EPA proposes, covering different process operating 
126 

conditions, could result in significant error in the moisture content of the stack when the stack 

temperature changes by even a few degrees from the "average". 

This same process would not apply to "non-saturated" stacks like heaters as the moisture content 

is not likely to be at the saturation value for the stack temperature. 

API requests that EPA allow an option to use a calculated moisture value based on the saturation 

value for moisture at the actual temperature of the stack. This would be done using a standard 

equation for determining the moisture content, such as: 

Where: 

Tc is the temperature in degrees Celsius 

Atm P is actual atmospheric pressure for the site 

0.01450377 is a conversion factor from millibars to PSIA. 

This follows the logic set forth in Reference Method 4, which states that if the measured 

moisture content of the stack using isokinetic sampling, is greater than the calculated saturation 

value for moisture at the actual stack temperature, then you should use the calculated saturation 

value as the moisture value for the test. 

Response: The commenter is requesting a method to calculate moisture content for a saturated 

stack based on temperature measurements. EPA has determined that the rule is already 

sufficiently flexible to satisfy the commenter’s request. In 40 CFR 98.33(a)(3)(iii) the reporter is 

given the option of either using a continuous monitoring method in 40 CFR 75.11(b)(2) or to 

apply an appropriate default moisture percentage. Included in 40 CFR 75.11(b)(2) is the option 

to use a temperature sensor and a moisture look-up table (e.g., a psychrometric chart). This 

option is only allowed for a gas stream that is demonstrably saturated (e.g., following a wet 

scrubber). Since this option already exists and is allowed by 40 CFR 98.33(a)(3)(iii), EPA is not 

making any additional changes. Note that the standard equation proposed by the commenter 

may be used, provided that it gives results equivalent to those obtained from a psychrometric 

chart. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 11 

Comment: CO2 Emissions from Coal Mill Stacks 

In addition to having concerns about methods for calculating biogenic emissions and the scope of 

regulatory definitions, at least one PCA member addresses EPA’s proposal for section $98.33 
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(a)(4)(viii) that may apply to the separate coal mill stack in cement plants. In this section EPA 

state that: 

“If a portion of the flue gases generated by a unit subject to Tier 4 (e.g., a slip stream) is 

continuously diverted from the main flue gas exhaust system for the purpose of heat recovery or 

some other similar process, and then exhausts through a stack that is not equipped with the 

continuous emission monitors to measure CO2 mass emissions, provided that the CO2

concentration in the diverted stream is not altered in any way (e.g., by chemical reaction or 

dilution) before the diverted stream exits to the atmosphere, an estimate of the hourly average 

volumetric flow rate (scfh) of the diverted gas stream shall be made at the point where it exits the 

main exhaust system, by using the best available information (e.g., 143 correlations of operating 

parameters versus flow measurements made with EPA Method 2 in appendix A-2 to part 60 of 

this chapter, engineering analysis, or other methods). Each hourly average volumetric flow rate 

(scfh) measured at the main flue gas stack shall then be added to the corresponding estimate of 

the hourly average flow rate of the diverted gas stream, to determine the total hourly average 

stack gas volumetric flow rate "Q", for use in Equation C-6 of this section. The method use to 

estimate the hourly flow rate of the diverted portion of the flue gas exhaust stream shall be 

documented in the Monitoring Plan required under §98.3(g)(5). “ 

This revision addresses comments submitted by a PCA member pertaining to the separate coal 

mill stack that contains a slip stream of kiln gas. EPA’s intention is to allow using the best 

information to estimate the CO2 from the coal mill stack without installing an additional CO2

CEM system. However, the improper pre-conditions and non-practical method in the section will 

not make this purpose realized. 

A. The rule requires that “the diverted stream is not altered in any way (e.g., by chemical 

reaction or dilution)”. It is reasonable to require there is no more chemical reaction so that no 

more CO2 will be generated. However, it is impossible that the diverted stream has no any 

dilution for two reasons: 

1 There are ductworks and fan that introduces this stream to a separate stack. The system 

must have additional false air and more or less dilute the gas stream; 

2 For the “heat recovery” purpose, additional equipment with dust collector is typically 

installed in the diverted stream, such as the coal mill and dust collect in the cement plants. These 

equipment may bring more false air and dilute the stream. 

Member recommendation: simply remove the words “or dilution” in the bracket. Any such 

diverted stream must have some false air in the system. 

B. The rule requires estimating the actual flow rate in the diverted stream and then to add 

it to the main stream. Actually, it does not work because both streams have different false air due 

to different duct works, fans, heat recovery equipment and dust collectors, etc. The CO2

concentrations are diluted in a different ratio and could be significantly different in the two 

stacks. A simple addition of flow rate may cause some significant errors. Even in the gas flow of 

the diverted gas stream at the point where it exits the main exhaust system, the CO2

concentration will be different with the main stack since the false air in the main stream. 
128 

This recommendation to estimate the CO2 emission in the diverted stream has been sent to EPA 

before, and provided as following: 

* The plants will conduct an initial stack test on the coal mill stack and follow-up testing as 

needed. The CO2 emission rate (tons per hour) will be measured in the coal mill stack. During 

the coal mill stack test, the coal mill system will operate under normal conditions at a minimum 

of 90% of its rated capacity. 

* The CO2 emission from the coal mill stack will be calculated using the measured average 

tons/hr CO2 emission times the total coal mill operation hours in a year. The coal mill operation 

hours will be obtained from the company record. 

* The sum of the CO2 emissions recorded by the kiln stack CEM and the calculated emissions 

from the coal mill stack will be reported as total kiln stack CO2 emissions. 

If EPA prefers to use their approach: adding the hourly average flow rate of the diverted gas 

stream to the main stream “to determine the total hourly average stack gas volumetric flow rate 

"Q", for use in Equation C-6”, then since the CO2 concentration will be different, we suggest 

estimating the “equivalent” flow rate in the diverted stream. The ratio of the equivalent flow rate 

in the diverted stream and the actual flow rate in the main stack should be the same ratio of the 

CO2 ton/hour in the diverted stream and in the main stack determined during the stack tests. Only 

after the modification of the precondition and the estimation approach, this section can then be 

used in the diverted stream such as the coal mill stack in cement plants. 

Response: In the final rule, we have incorporated the stack testing approach suggested by the 

commenter, with a few modifications to account for any significant variability in the volumetric 

flow rate of the diverted gas stream. Please see EPA’s discussion on determining emissions from 

an exhaust stream diverted from a CEMS monitored stack in Section II.G of the preamble to the 

final rule amendments, for further information. 

Tier 1 Applicability 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 23 

Comment: API supports the revision of §98.33(b)(1)(v) – Allows the use of Tier 1 methods for 

natural gas combustion in a unit of any size in cases where the annual natural gas consumption is 

obtained from fuel billing records in units of therms. 

Response: EPA thanks the commenter for the input. We have finalized this provision to allow 

the use of Tier 1 methods for natural gas combustion in a unit of any size in cases where the 
129 

annual natural gas consumption is obtained from fuel billing records in units of therms. Please 

see section II.G of the preamble to the final rule amendments, for further information. 

Tier 2 Applicability 

Commenter Name: Mike Stroben 

Commenter Affiliation: Duke Energy 

Document Control Number: EPA-HQ-OAR-2008-0508-2354.1 

Comment Excerpt Number: 2 

Comment: EPA’s proposal to change the minimum sampling frequency for Tier 2 will have the 

unintended effect of forcing many Tier 1 fuel/units into Tier 2. 

The final Mandatory Greenhouse Gas Reporting Rule (74 FR 56260-56519 on October 30, 2009) 

made it clear that if a fuel consumed by a combustion source of less than 250 mmBtu/hr capacity 

was not sampled and analyzed at the minimum frequency specified in §98.34(a) of that rule, then 

fuel for that source could be considered Tier 1 in Subpart C (see §98.33(b)(1)(iv)) (74 FR 

56400). For example, the current rule requires a Tier 2 unit consuming fuel oil is to analyze a 

sample from every lot or delivery. If this is not occurring and the unit meets other Tier 1 criteria, 

then the unit is Tier 1 for fuel oil, and fuel oil sampling and analysis is not required. With this 

proposed rule (75 FR 48744 on August 11, 2010), EPA would change those sampling frequency 

minimums, forcing many Tier 1 units into Tier 2. While Duke Energy acknowledges that EPA’s 

motive for decreasing the required frequency of sampling by some Tier 2 sources is laudable, 

this action will force a lot of small sources into unnecessary sampling regimes. 

EPA can remedy this situation most easily by slightly altering the Tier 1 requirements of 

§98.33(b)(1). Duke Energy requests that EPA delete the requirement of §98.33(b)(1)(iv) and 

instead provide any unit that meets the requirements of §98.33(b)(1)(i-i ii ,v) the option to use 

Tier 1 criteria. 

§98.33(b)(1)(iv) [The Tier 1 calculation methodology] May not be used if you routinely perform 

fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of 

HHV sampling and analysis from the fuel supplier at the minimum frequency specified in 

§98.34(a), or at a greater frequency. In such cases, Tier 2 shall be used. 

This change would allow any small (<250 mmBtu/hr) units consuming a fuel listed in Table C-1 

to use the default HHV in Table C-1 regardless of sampling frequency and analysis methods that 

might also be occurring at the facility. Larger units and units consuming fuels not listed in Table 

C-1 would continue to use Tier 2 and Tier 3 methods. 

This relief would clear up a lot of confusion surrounding Tier 1 vs Tier 2 applicability, including 

the shifting definition of “routinely”. Also, as the fuels listed in Table C-1 are all fungible fuels 

of consistent quality, allowing small sources to use the default factors in Table C-1 will not 

affect the quality of this program. 
130 

Response: The intent of Tier 2 is to require units to report fuel analysis only if they are already 

performing sampling or receive the results of fuel sampling from the supplier at the minimum 

frequency specified in §98.34(a)(2). For fuel oil, Tier 2 is required if, for each collective fuel lot, 

at least one sample is taken and analyzed as part of the facility’s normal operating procedures. 

Since a fuel lot can be aggregated to the monthly level, Tier 2 will typically be required if a 

representative sample is analyzed at least once a month. For units smaller than 250 mmBtu that 

are subject to Tier 2 because they meet the minimum sampling frequency, no additional 

sampling requirements are being imposed. Note that at the request of other commenters, 

additional sampling options for fuel oil (e.g., sampling after each addition of oil to the tank, daily 

manual sampling, etc) have been added to the final rule. Units that use these sampling methods 

as part of their normal operation and might otherwise have qualified for Tier 1 will also be 

required to use Tier 2. 

We recognize that there may be some facilities that rightfully assumed they would use Tier 1 for 

the 2010 reporting year, based on the 2009 final rule, and retained the corresponding records. 

These same facilities might not have the information available to follow Tier 2 based on the 

revised definition of fuel lot. Where this is the case, and the appropriate records have not been 

retained by the facility for the 2010 reporting year, we interpret this to mean that the facility did 

not have the data available at the required frequency in 2010, and therefore would not be 

required to use Tier 2 for the 2010 reporting year. 

Note that although the amendments may require more sources to use Tier 2 than originally 

anticipated, no additional fuel sampling requirements are being imposed. The use of Tier 2 is 

triggered for these units only because they obtain or receive HHV data at a certain frequency, as 

part of their normal operation. 

 

 

Tier 3 Applicability 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 6 

Comment: Fuels used in combustion units with a heat input greater than 250 MMBtu/hr are 

required to use the Tier 3 calculation method if the fuel combusted is listed in Table C-1, unless 

the fuel is natural gas or distillate fuel oil. However, ACC believes that if these fuels provide less 

than 10% of the annual heat input, these fuels should be excluded from the reporting 

requirements just like fuels that do not have any emission factor provided in Table C-1. 

Otherwise, even the presence of a small amount of fuel gas in a gas mixture will trigger the Tier 

3 methodology, which requires calibrated flow meters to determine fuel quantity and periodic 

sampling and analysis to determine fuel composition. Based on the October 2009 final rule, 

petrochemical plants that burn “fuel gas” in combustion units with a heat input less than 250 
131 

MMBtu/hr or with a heat input greater than 250 MMBtu/hr where “fuel gas” provides less than 

10% of the annual heat input, were not required to calculate GHG emissions because fuel gas 

was not listed in Table C-1. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2366.1, Excerpt 4 for the 

response to this comment. 

Commenter Name: Kimberly A. Hibbard 

Commenter Affiliation: S.D. Warren Company - Somerset Operations 

Document Control Number: EPA-HQ-OAR-2008-0508-2404 

Comment Excerpt Number: 2 

Comment: S .D. Warren urges EPA to revise its proposed changes to provide that fuels listed in 

Table C-1 which provide less than 10% of the annual heat input to a boiler with a maximum 

rated heat input capacity >250 MMBtu/hr be allowed to use Tier 1 for calculating GHG 

emissions for such fuels (i.e. use of company records and default emission factors). . 

Another potential issue with the use of Tier 3 for waste oil is found in 98.43(b)(1)(vi) . Would 

the addition of waste oil into the No.6 fuel oil tank be considered as a mixture of fuels 

transported by a common pipe requiring measurement of fuels with a certified flow meter prior 

to mixing? Would the mill have to install a new storage tank and flow meter system for waste oil 

in order to meter the fuels separately prior to mixing as specified by 98.43(b)(1)(vi)? This 

requirement also seems excessive and impracticable for such a small fuel stream. 

Response: The request to use Tier 1 for Table C-1 fuels that provide less than 10% of the annual 

heat input to large (greater than 250 mmBtu/hr) combustion units is outside the scope of this 

rulemaking. EPA did not propose any changes to the requirements of the current rule regarding 

the allowable CO2 emissions calculation methodologies for Table C-1 fuels. See also the 

response to comment EPA-HQ-OAR-2008-0508-2366.1, excerpt 4. 

Regarding the addition of waste oil to a No. 6 oil storage tank, the method of quantifying the 

CO2 emissions from the mixed oil depends on the size of the unit (or units) combusting the fuel. 

The final rule provides emission factors for both “used oil” and No. 6 oil. So if the unit’s 

maximum rated heat input capacity is 250 mmBtu/hr or less and the fuels are not precisely 

measured before mixing, you could consider the mixture (blend) to be the “fuel type”, use the 

best available information to estimate the relative proportions of the two fuels in the mixture, and 

then apply the Tier 2 methodology in §98.34(a)(3)(ii) for a blend of Table C-1 fuels. If the unit 

is greater than 250 mmBtu/hr, the use of Tier 3 would be triggered. However, you could 

consider the blend to be the fuel type and apply the Tier 3 methodology in §98.34(b)(3)(v) for 

blended fuels. Note that Tier 3 allows the use of tank drop measurements as an alternative to 

installing calibrated fuel flow meters (see the definition of “Fuel” in the nomenclature of 

Equation C-4). The minimum required sampling frequency for a blend of liquid fuels is once per 

calendar quarter, under both Tier 2 and Tier 3 (see §§98.34(a)(2)(v) and (b)(3)(ii)(F)). 
132 

Commenter Name: Kimberly A. Hibbard 

Commenter Affiliation: S.D. Warren Company - Somerset Operations 

Document Control Number: EPA-HQ-OAR-2008-0508-2404 

Comment Excerpt Number: 3 

Comment: The Somerset Mill has a similar issue with the firing of No.2 Fuel oil in the No. 2. 

Power Boiler as an igniter fuel. On average No.2 fuel oil provides less than 10/6 [sic] of the 

annual heat input to the No.2 Power Boiler. Because No.2 Fuel Oil is listed in Table C-1 and is 

burned in a boiler with a maximum rated heat input capacity >250 MMBtu/hr, a fuel analysis of 

the higher heating value (HHV) for Tier 2 (98.34(a)(2)(ii)) or a fuel analysis of the carbon 

content for Tier 3 (98.34(b)(3)) of every lot or shipment is required. 

When the Somerset Mill requested the supplier of No.2 Fuel Oil to provide copies of the HHV 

for each shipment, the mill was informed that there were no suppliers or distributors currently 

testing cargos of No .2 oil throughout New England and that the comingling of No.2 oil prior to 

delivery to the ultimate user is a common practice. The testing of each No.2 fuel oil delivery to 

the mill, which is a relatively small volume compared to No.6 oil cargo testing, seems excessive 

for a fuel that provides less than 1 % of the annual heat output to the No.2 Power Boiler. Similar 

to the waste oil issue, the Somerset Mill recommends the use of Tier 1 to calculate greenhouse 

gas emissions for small quantities of igniter fuel. 

Response: The changes to Part 98 suggested by the commenter are outside the scope of the 

specific amendments proposed for public comment in the Federal Register notice of August 11, 

2010. However, note that if the No. 2 oil is combusted in a manner consistent with the definition 

of a pilot light in §98.6, then the fuel is exempted from GHG emissions reporting under 

§98.30(d). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 24 

Comment: API supports the revision of §98.34(b) and the use of the terminology – For Tier 3 

oil and gas flow meters, you may use an appropriate flow meter calibration method published by 

a consensus standards organization. 

Response: EPA thanks the commenter for the input. We have finalized this provision, as 

proposed. 

Tier 4 Applicability 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 
133 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 6 

Comment: WM supports the proposed applicability threshold for requiring use of Tier 4 

methodologies. The proposed 600 tons per day threshold will relieve smaller, primarily 

municipally-owned MSW combustor units from having to retrofit and install expensive new 

monitoring equipment that is inconsistent with the monitoring equipment required by the New 

Source Performance Standards for those units. At the same time, the 600 ton per day 

applicability threshold for MSW combustors is far more stringent than the threshold applied to 

fossil fuel-fired combustors that emit significantly larger amounts of greenhouse gases. 

Response: EPA thanks the commenter for the input. However, please note that the 600 tons per 

day (tpd) threshold is not more stringent than the threshold for fossil fuel combustors. On a heat 

input basis, 600 tpd of MSW compares quite well to the 250 mmBtu/hr threshold for fossil fuelfired units. In fact, the main reason for raising the MSW threshold to 600 tpd was to put MSW 

and fosil fuel combustors on a more equal footing (see the comment from the Solid Waste 

Association of North American (SWANA) regarding the 600 tpd threshold, in EPA-HQ-OAR2008-0508-2397.1, Excerpt 4). 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 7 

Comment: WM believes it is important to note that small MSW combustion units with 

capacities below the 600 tons per day threshold are anticipating finalization of the new 

applicability threshold by the end of 2010. Indeed, EPA specifically states in the preamble that it 

intends to finalize these proposed revisions to the rule by the end of 2010, and recommends that 

sources calculate emissions and submit reports relying on these amendments: 

EPA is planning to address the comments on these proposed amendments and publish the final 

amendments before the end of 2010. Therefore, reporters would be expected to calculate 

emissions and other relevant data for the reports that are submitted in 2011 using Part 98, as 

amended by this and the other revisions package (75 FR 33950), as finalized. 75 FR 48747. 

Should EPA fail to promulgate these amendments by the end of 2010, units with less than 600 

tons per day capacity will require a deferral of the requirement to use Tier 4 until January 1, 

2012, so that they may have sufficient time to install and certify new Part 75 equipment. 

Response: Please see EPA’s response to comment in EPA-HQ-OAR-2008-0508-2397.1 excerpt 

4 for a discussion of the timing of this rulemaking. 

Commenter Name: John H. Skinner 

Commenter Affiliation: Solid Waste Association of North America (SWANA) 
134 

Document Control Number: EPA-HQ-OAR-2008-0508-2397.1 

Comment Excerpt Number: 4 

Comment: The Solid Waste Association of North America (SWANA) appreciates EPA’s 

decision to raise the applicability threshold for Tier 4 reporting from 250 tons per day to 600 tons 

per day. A WTE plant at 250 tpd has only 18-25% of the CO2 emissions of the same sized fossilfuel fired unit. Based on a nominal heat content of 5,000 Btu / lb, the 250 tons / day threshold is 

equivalent to 104 mmBtu/hr, less than half the standard applied to other stationary combustion 

units. Conversely, a 250 mmBtu/hr threshold applied to nominal MSW would translate into a 

mass rate threshold of approximately 600 tons / day, so this new threshold is much more 

appropriate. 

Further we would like to point out that even under this new threshold a total of 27 waste-toenergy facilities, many of which are owned by local governments, would be required to use the 

more costly Tier 4 method. Since waste-to-energy facilities account for only 0.55 percent of the 

total CO2e emissions from the combustion source sector, we question whether this economic 

burden on local government is justified and believe that the threshold could be set even higher. 

Should EPA fail to promulgate these amendments by the end of 2010, units with less than 600 

tons per day capacity will require a deferral of the requirement to use Tier 4 until January 1, 

2012, so that they may have sufficient time to install and certify new Part 75 equipment. 

Response: EPA thanks the commenter for the input. We acknowledge that there are local 

government-owned waste-to-energy facilities that may still be subject to the Tier 4 requirements 

of the rule. The burden associated with this reporting was accounted for in the Regulatory 

Impact Analysis for the 2009 final rule. The purpose of amending the MSW threshold was to 

approximate the threshold for other stationary combustion units required to use Tier 4. As noted 

by the commenter, a 250 mmBtu/hr threshold applied to nominal MSW would translate into a 

mass rate threshold of approximately 600 tons / day. As such, we have concluded it is not 

appropriate to further raise the threshold above 600 tons of MSW per day. 

These amendments will become effective prior to January 1, 2011, and the amendments will 

apply for reporting year 2010. Therefore, EPA has determined that there is no need to provide 

relief for units with a capacity of less than 600 tons of MSW per day. 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 5 

Comment: The Energy Recovery Council (ERC) supports the proposed applicability threshold 

for requiring use of Tier 4 methodologies. The proposed 600 tons per day threshold will relieve 

smaller, primarily municipally-owned MSW combustor units from having to retrofit and install 

expensive new monitoring equipment that is inconsistent with the monitoring equipment 

required by the New Source Performance Standards for those units. At the same time, the 600 

ton per day applicability threshold for MSW combustors is more stringent on the basis of non-
135 

biogenic emissions per unit of heat input than the threshold applied to other combustors that fire 

100% fossil fuel. 

ERC believes it is important to note that small MSW combustion units with capacities below the 

600 tons per day threshold are anticipating finalization of the new applicability threshold by the 

end of 2010. Indeed, EPA specifically states in the preamble that it intends to finalize these 

proposed revisions to the rule by the end of 2010, and recommends that sources calculate 

emissions and submit reports relying on these amendments: 

“EPA is planning to address the comments on these proposed amendments and publish the final 

amendments before the end of 2010. Therefore, reporters would be expected to calculate 

emissions and other relevant data for the reports that are submitted in 2011 using Part 98, as 

amended by this and the other revisions package (75 FR 33950), as finalized. 75 FR 48747.” 

Should EPA fail to promulgate these amendments by the end of 2010, units with less than 600 

tons per day capacity will require a deferral of the requirement to use Tier 4 until January 1, 

2012, so that they may have sufficient time to install and certify new Part 75 equipment. 

Response: Please see EPA’s response to comment in EPA-HQ-OAR-2008-0508-2397.1 excerpt 

4 for a discussion of the timing of this rulemaking and a comparison of the 600 tpd threshold to 

the 250 mmBtu/hr threshold. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 7 

Comment: The final rule requires the use of the Tier 4 calculation methodology for a unit that 

"has a maximum rated heated capacity greater than 250 mmBTU/hr or if the unit combusts 

municipal solid waste and has a maximum rated input capacity greater than 250 tons per day of 

MSW" (40 CFR §98.33(b)(4)(ii)(A)). Calculations using the Tier 4 methodology must begin 

January 1,2011, if monitors have not been installed and certified prior to January 1, 2010 (40 

CFR §98.33(b)(5)(ii)). The proposed rule increases the maximum rated heat input capacity for 

the Tier 4 calculation methodology to 600 tons per day of MSW. 

Xcel Energy supports the proposed revision because it would eliminate the capital and O&M 

costs of continuous emissions monitoring systems (CEMS) on our six units that combust RDF. If 

the proposed rule becomes final, GHG emissions from these units will be calculated using the 

Tier 2 methodology. However, we are concerned that the timing of the proposed change will not 

be finalized soon enough for us to make a sound business decision prior to the current January 1, 

2011, regulatory deadline for installing and certifying monitors. Because there is potential for 

delay in the finalization of the new limit, Xcel Energy asks that the revisions provide a six month 

extension for CEMS installation and certification for units affected by the 600 tons per day 

threshold change. 
136 

Response: Please see EPA’s response to comment in EPA-HQ-OAR-2008-0508-2397.1 excerpt 

4 for a discussion of the timing of this rulemaking. 

Because we have finalized the amendments to allow units less than 600 tons of MSW per day to 

use the Tier 2 calculation procedures, we have concluded that additional relief is not needed for 

those units. Units greater than 600 tons of MSW per day have always been required to use the 

Tier 4 calculation procedures, and we did not propose otherwise in the August 11, 2010 proposal. 

Therefore, EPA has concluded that facilities with these larger units have known since 

promulgation of the 2009 final rule that these units must have their CEMS installed and certified 

by January 1, 2011. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 8 

Comment: 98.33(b)(4)(ii)(B): This proposed revision fundamentally changes the requirement to 

use Tier 4 for units that burn solid fossil fuel or MSW as the primary or secondary fuel. This 

revision deletes the reference to the secondary fuel. A primary fuel has been defined in the 

proposed revisions as that fuel that provides the greatest percentage of annual heat input. This 

revision is important to units that burn a significant amount of biomass fuels and a small amount 

of supplemental coal for combustion control, due to the high moisture content often contained in 

the biomass, e.g. wet wood bark. Large combination boilers that burn wood residuals and some 

coal are common in the pulp and paper industry. To require a Tier 4 CO2 CEM for this type of 

application is senseless and would result in unnecessary significant capital and facility resources 

to install and maintain a CO2 CEM and gas flow monitoring system. As this revision illustrates, 

the purpose of this requirement was to capture combustion units that primarily burn coal or 

MSW, not combustion units that primarily burn biomass and a small amounts of coal. 

Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. We have finalized this provision, as 

proposed. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 15 

Comment: Further, as stated in our comments on the proposed settlement agreements, EPA’s 

proposal to raise the reporting threshold for MSW-burning facilities to use the Tier 4 

methodology from 250 tons per day (“tpd”) to 600 tpd is troubling. In this proposed 

rulemaking, EPA argues that the 600 tpd threshold is the approximate equivalent of the 250 
137 

mmBtu/hr heat requirement for other source categories. While this may be the case, we 

nonetheless renew our request in those previous comments. 

EPA should still determine the emissions coverage it would lose from this change, as emissions 

coverage must ultimately be the metric for reporting rule decisions. We ask EPA to calculate that 

figure and report it in any final rulemaking. If EPA determines that the change will result in an 

unacceptably high emission coverage loss, it should not adopt the proposed change. [. We 

generally agree that use of Tier 4 monitoring may result in more accurate emissions information, 

but that the information that would be made publicly available pursuant to EPA’s proposed 

definition of “emission data” elements that would be required to be reported under lower tiers 

would be helpful in determining the impacts of GHG emissions with regard to different fuel 

types. However, evidence exists that use of MSW or other products that have reached the end of 

their useful lifetimes may create significant GHG emissions reductions when compared to fossil 

fuels or biomass. UN-Energy, Sustainable Bioenergy: A Framework for Decisionmakers, (Apr. 

2007) (“Sustainable Bioenergy”), available at http://esa.un.org/un---

energy/pdf/susdev.Biofuels.FAO.pdf. Despite these potential benefits, we nonetheless urge EPA 

to require the reporting of additional information that would be provided if a lower tier were 

being used, for example, amount of fuel and type and the carbon content of those fuels.] 

Response: There is no loss in emissions coverage by this change. Units previously required to 

use CEMS to measure CO2 emissions from MSW will now be required to use the Tier 2 

methodology, based on steam production and boiler efficiency. We acknowledge that the lower 

tiers may result in a small loss in the accuracy of the data for smaller MWC units, but it is not 

our intent to impose undue burden on the smaller combustion units. 

With respect to the comment that EPA should require Tier 4 units to report the same information 

that is reported by units using the lower tiers, this comment is outside the scope of the 

amendments proposed on August 11, 2010. Moreover, it is a broad concept that would require 

consideration in a more comprehensive manner across the entire rule. 

EPA has undertaken a separate rulemaking effort to solicit comment on the treatment of 

confidential information under the Greenhouse Gas Reporting Program. Please refer to Proposed 

Confidentiality Determinations for Data Required Under the Mandatory Greenhouse Gas (docket 

EPA-HQ-OAR-2009-0924). 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 11 

Comment: EPA’s proposal to raise the reporting threshold for MSW-burning facilities from 250 

tons per day of MSW to 600 tons per day of MSW is troubling. See 75 Fed. Reg. at 48,757. EPA 

argues that the 600 ton per day requirement is closer to the 250 mmbtu/hr heat input reporting 

threshold for other reporting sources. Even if this is so, EPA should still determine the emissions 
138 

coverage it would lose from this change, as emissions coverage must ultimately be the metric for 

reporting rule decisions. We ask EPA to calculate that figure and report it in any final 

rulemaking. If EPA determines that the change will result in an unacceptably high emission 

coverage loss, it should not adopt the proposed change. 

Response: Please see EPA’s response to comment in EPA-HQ-OAR-2008-0508-2398.1 excerpt 

15. 

CH4 and N2O emissions 

Commenter Name: Mike Stroben 

Commenter Affiliation: Duke Energy 

Document Control Number: EPA-HQ-OAR-2008-0508-2354.1 

Comment Excerpt Number: 1 

Comment: The Methane (CH4) and Nitrous Oxide (N2O) Calculation Simplification Available 

to Part 75 CEMs Units Should Also Be Available to Subpart C Tier 4 Units 

On page 48791 of EPA’s proposed rule, EPA proposes to simplify the record keeping necessary 

to calculate CH4 and N2O emissions in §98.33(c)(4)(ii) for units using part 75 CEMs 

calculations by adding the following paragraph: 

(B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this chapter, 

the value of (HI)A obtained from the electronic data reports under §75.64 of this chapter may be 

attributed exclusively to the fuel with the highest F-factor, when the reporting option in 3.3.6.5 

of appendix F to part 75 of this chapter is selected and implemented. 

As the calculated emissions of GH4 and N2O from these units is insignificant and well within the 

margin of error for the CEMs equipment, no matter how it is calculated, compared to the 

quantity of CO2 emitted, this is a reasonable action that Duke Energy supports. It would also be 

reasonable for EPA to provide the same simplification to Tier 4 units. Instead, EPA is proposing 

the following: 

(G) For Tier 4 units, use the best available information (e.g., fuel feed rate measurements, fuel 

heating values, engineering analysis) to estimate the value of (HI)A for each type of fuel. 

This requirement would force Tier 4 operators to track the fuel use of each combustion source 

when the CEMs are already providing sufficiently accurate emissions data. Many industrial sites 

have Tier 4 sources that fire very much like a Subpart D electric generating units. There is no 

reason why Tier 4 units should not be allowed to use the same simplifying CH4 and N2O 

provision. If Tier 4 units are not allowed to use the paragraph (B) provision they will be forced to 

track or estimate fuel use for several different fuels on a unit by unit basis with no associated 

increase in the accuracy of the CH4 or N2O emissions calculations. 
139 

Duke Energy requests that EPA make §98.33(c)(4)(ii)(B) available to Tier 4 units that implement 

a fixed f-factor in their CEMs calculations similar to the reporting option in 3.3.6.5 of appendix 

F to part 75. 

Response: The final rule does not incorporate the commenter’s suggestion. We can audit the 

electronic monitoring plans of Part 75 units to determine the type(s) of fuel combusted and the 

purpose of each fuel (e.g., primary fuel, secondary fuel, startup fuel). We can then apply a filter 

to identify multi-fuel units that report a single F-factor for all unit operating hours. This 

information can help us identify Part 75 units that may be misapplying the worst-case F-factor 

provision. We do not have similar audit capability for Tier 4 units. 

We note, however, that requiring Tier 4 units to report CH4 and N2O emissions by fuel type is 

not overly burdensome, since sources are allowed to use the best available information to 

determine fuel consumption and fuel-specific heat input. Any flow meters or other instruments 

used to determine fuel usage are not subject to the calibration requirements of 40 CFR 98.3(i) or 

the quality assurance requirements of 40 CFR 98.34. The best available information may also be 

an engineering analysis. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 29 

Comment: In §98.33(c)(2), the reference to the Tier 1 or Tier 3 calculation is incorrect and 

should be replaced by reference to the Tier 2 calculation. 

Response: A correction to the reference the commenter cites was included in the proposed rule 

and has been finalized. No further changes need to be made. 

Commenter Name: Caitlin Post 

Commenter Affiliation: Southern Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2377.1 

Comment Excerpt Number: 3 

Comment: EPA is proposing changes to 40 CFR 98.33(c)(4) to allow flexibility in determining 

the cumulative annual heat input needed to calculate CH4 and N2O using equation C-10. EPA is 

proposing to allow units subject to subpart D that measure their hourly heat input values based 

on Section 3.3.6.5 of Part 75 appendix F, which bases all hourly heat input values on the “worstcase” or highest F-factor for any fuel combusted in the unit, to use this same heat input in 

equation C-10. Southern Company supports this proposal because it is consistent with other 

information already being reported to EPA and will reduce the reporting burden for units that use 

this method. 
140 

Response: EPA thanks the commenter for the input. We have finalized the amendments, as 

proposed. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 9 

Comment: VI. Methane (CH4 ) and Nitrous Oxide (N2O) Calculations 

As promulgated, § 98.33(c) requires units that monitor and report heat input year-round basis 

under Part 75 to calculate CH4 and N2O based on the “cumulative annual heat input from [each] 

fuel, derived from the electronic data reports required under § 75.64” and fuel-specific emission 

factors for CH4 and N2O from Table C–2. As UARG explained in its Reconsideration Petition, 

this provision is based on the misconception that Part 75 units are necessarily recording and 

reporting heat input for each fuel combusted. The current rule also limits reporting to fuels 

combusted during “normal operation,” but does not define “normal operation” or explain how 

the heat input from non-normal operation would be calculated and excluded from the total annual 

heat input reported under Part 75. UARG further explained that, under Part 75, most sources that 

use oil or gas for startup, or that combust a small amount of secondary fuel with a lower F-factor 

(e.g., use oil for flame stabilization) exercise an option in Part 75 that allows the source to use 

the “worst case” F-factor to report heat input from secondary fuels (e.g., calculate heat input 

assuming only coal was combusted). A rule that requires Part 75 sources that monitor with 

CEMS to exclude startup operations from GHG reporting, or to derive fuel specific heat input 

values from the Part 75 report, would require collection and reporting of information that are 

different from what is currently reported under § 75.64. 

To address UARG’s concerns, EPA proposes to remove references to “normal operation” from § 

98.33(c)(4)(i) and (ii) and to allow additional options for Part 75 sources that are unable to 

determine the heat input contribution of a specific fuel from the Part 75 quarterly reports 

because, for example, they have exercised the “worst-case” F-factor option for reporting under 

Part 75. 75 Fed. Reg. at 48,758. All of the options provided in EPA’s proposed rule are 

reasonable and necessary to allow Part 75 sources to calculate and report CH4 and N2O using 

their Part 75 heat input data. EPA should finalize the revisions as proposed. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Biogenic CO2 emissions 

Commenter Name: Rhea Hale 

Commenter Affiliation: American Forest & Paper Association (AF&PA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2382.1 
141 

Comment Excerpt Number: 2 

Comment: The current method for calculating the biogenic share of CO2 emissions for Part 75 

sources is burdensome and should be amended. The methods defined in the final reporting rule 

require that facilities calculate the fossil portion via equation C-13 and C-14 and the various 

subparagraphs of 40 CFR 98.33(e)(2) and subtract it from the CEM total resulting in the biogenic 

share. For those facilities using a small amount of biomass, and a Part 75 monitor, the 

requirement to calculate a higher heating value via fuel sampling analysis is extremely 

burdensome and could produce inconsistencies between the fossil fuel emission calculation and 

the CEMs reading. The prescribed method is also inflexible should a facility wish to burn 

biomass at a future point in time but has not completed prior fuel sampling of its fossil fuel. 

Instead, EPA should allow Part 75 sources to calculate either their biogenic or their fossil fuel 

portions and eliminate the fuel sampling requirement, replacing it with a default higher heating 

value. These default values are provided by EPA in Table C-1 of Subpart C. EPA could set the 

threshold for this HHV default selection to when biomass comprises less than 50% of the annual 

heat input. Also note that fuels not listed in Table C-1 are exempt if they provide less than 10% 

of the total heat input. 

These changes would allow Part 75 sources that are not predominantly burning biomass to report 

biogenic CO2 separately with minimal additional effort to their Part 75 CO2 CEMS reporting 

obligations under the Mandatory Reporting Rule. This will eliminate potential discrepancies 

involved with using two different methods when fossil fuel is the predominant portion of the 

CEMS total and will provide more flexibility for reporting entities related to fuel mix. Only for 

facilities burning truly incidental amounts of biomass (e.g. less than 5% of total heat input) 

should separate reporting of biogenic emissions be optional. 

In addition, since Subpart D Part 75 method users are expected to select the biomass fuel 

calculation option when they are firing only relatively small amounts of biomass, the rule 

language could be modified to allow those Subpart D reporters to use default higher heating 

values for biomass in their Equation C-13 calculation without any appreciable loss of accuracy. 

In formal implementation-related questions posed to EPA following the finalization of the 

Reporting Rule, the American Forest & Paper Association (AF&PA) requested that facilities be 

allowed to calculate either the biogenic share of the CEMS total or the fossil portion at their 

discretion. Sean Hogan of EPA responded that EPA would consider this proposed change. See 

the following EPA responses to AF&PA questions dated February 16, 2010: 

“Question 14: EPA should allow unit that is using Tier 4 and combusts a combination of fossil 

and biomass fuels to back out the biomass for CO2 calculations. The rule states that in order to 

determine the amount of biogenic CO2 emitted from a combination combustion unit the fossil 

fuel portion of the total CO2 is calculated (Equation C-13) and subtracted from the total CO2 as 

read by the CEMS. We propose that units should have the option to calculate the biogenic CO2

using the same methodology as Equation 13. The amount of biomass fuel has to be quantified for 

CH4 and N2O calculations and a fuel specific default F-factor for Bark and Wood residue is 

available from Table 1 in section 3.3.5 of Appendix F to 40 CFR part 75. Alternatively, a facility 
142 

would have the option to determine a site-specific value as outlined under section 3.5.6 of 

Appendix F to 40 CFR part 75. 

Response: Thank you for your proposal. EPA will give this further consideration.” 

Proposed Alternative Approach: 

Sources that combust both biomass and fossil fuels and use a (Tier 4) CO2 CEM currently are 

required to calculate the fossil CO2 and determine the biomass fuel CO2 by difference (i.e. CEM 

CO2 minus fossil CO2). Under this alternate approach, sources would be allowed to choose either 

their biomass or their fossil fuel use to determine the calculated CO2 emissions using the same 

methodology as the current Equation C-13. This approach is reasonable since the amount of 

biomass fuel used has to be quantified for CH4 and N2O calculations anyway and a fuel specific 

default F-factor for Bark and Wood residue is available from Table 1 in section 3.3.5 of 

Appendix F to 40 CFR Part 75. Alternatively, a facility would have the option to determine a 

site-specific value as outlined under section 3.5.6 of Appendix F to 40 CFR Part 75. 

To allow the use of either calculating the fossil fuel CO2 or biomass CO2, a small change to the 

current Equation C-13 can be made. The current Equation C-13 is as follows: 

Vff = [Fuel*Fc*HHV] / 1,000,000 (Eq. C-13) 

Where: 

Vff = Annual volume of CO2 

Fuel = Total quantity of the fossil fuel combusted 

Fc = Fuel-specific carbon based F-factor 

HHV = High heat value of the fossil fuel 

1,000,000 = Conversion factor, Btu per mmBtu 

Equation C-13 calculates the annual CO2 volume from the fossil fuels. To allow the calculation 

of CO2 for any fuel, the reference to “fossil fuels” should be changed to “fuels combusted.” 

Therefore, Equation C-13 stays the same, but the definitions are now: 

Vfc = Annual volume of CO2 for fuels combusted 

Fuel = Total quantity of the fuels combusted 

Fc = Fuel-specific carbon based F-factor 

HHV = High heat value of the fuels combusted 

1,000,000 = Conversion factor, Btu per mmBtu 

Corresponding rule language text changes to calculate the correct CO2 fraction would need to be 

made in 40 CFR 98.33(e)(2)(iii) and (iv). For example, at 98.33(e)(2)(iii) at the two places where 

the words “fossil fuel” currently exist they could be replaced with the phrase “either fossil fuel or 

biomass.” 

Response: Please see Section II.C in the preamble to the final rule amendments, for EPA’s 

rationale regarding biogenic CO2 reporting for Part 75 units 
143 

The recommended change to the calculation methodology in §98.33(e)(2) is deemed to be 

unnecessary, in view of the fact that the final rule provides two simplified procedures for 

quantifying biogenic CO2 emissions at facilities with part 75 units. First, we have expanded the 

use of the Tier 1 methodology under §98.33(e)(1) to include units that use CEMS. Second, 

today’s rule provides a method in §98.33(e)(6) that allows biogenic CO2 emissions to be 

calculated based on the heat input data available in the annual electronic reports submitted under 

Part 75, supplemented, if necessary, with other available information. The calculation method 

proposed by the commenter is significantly more complicated than either of these two methods, 

and could only be used for the two biomass fuels listed in Table 1 of 40 CFR Part 75, Appendix 

F, section 3.3.5 (i.e., for wood residue and bark). For more information on the final methods for 

quantifying CO2 emissions from biomass combustion, please refer to section II.G of the 

preamble. 

Commenter Name: Brian Gasiorowski 

Commenter Affiliation: Lafarge North America 

Document Control Number: EPA-HQ-OAR-2008-0508-2401.1 

Comment Excerpt Number: 1 

Comment: EPA has clearly stated its desire to provide facilities with added flexibility with 

respect to mandatory requirements for separate reporting of biogenic CO2 emissions. EPA states 

on page 48759 of the preamble: 

"In general, biogenic CO2 emissions reporting would be required only for the combustion of the 

biomass fuels listed in Table C-1 and for municipal solid waste (which consists partly of biomass 

and partly of fossil fuel derivatives. ) 

We are proposing to amend 40 CFR 98.33(e) to describe three cases in which units that combust 

biomass would not need to report biogenic CO2 emissions separate from total CO2 emissions." 

We are concerned that none of the above three exclusionary cases would provide relief to a 

cement kiln operator using a CO2 CEMs to measure the total combustion and process emissions 

from a cement kiln that is using some relatively small amount of an alternative fuel that still fits 

within EPA’s proposed definition of "municipal solid waste." 

As EPA is aware the cement industry plays a significant positive role in promoting resource 

conservation and recovery through use of a broad range of byproducts as alternative fuels. These 

byproducts include materials such as woods, papers, plastics, carpets, baby diapers, animal and 

agricultural byproducts, asphalt shingles, tires, landfill gas, auto shredder fluff, and many others. 

The proposed rule language provides flexibility such that in many cases a cement kiln operator 

using CO2 CEMs to determine the total CO2 emission from the cement kiln is not obligated to 

report biogenic CO2 emissions separately. In these cases, the separate reporting of biogenic CO2

emissions would be optional. However, we are concerned that in a more limited number of cases 

a cement kiln operator using an alternative fuel meeting the definition of "MSW" under this rule 
144 

would be obligated to separately measure and report biogenic CO2 emissions even if only a very 

small amount of the "MSW" fuel were being used with relatively small biogenic emissions. 

We propose two changes to the language of the rule which would ensure that cement kiln 

operators using relatively small amounts of "MSW" are not obligated to separately report the 

small amount of biogenic emissions from combustion of the MSW. In these cases the facility 

would include the biogenic CO2 emissions with the total CO2 emissions determined by the 

CEMs. These two proposed changes are as follows: 

1. Adding a definition for "plastics" along with a minor change to the definition of MSW to 

clarify that any plastics separated from MSW are not included within the MSW definition. 

2. Adding a sub-paragraph under 98.33(e)(3) to make reporting of biogenic CO2 emissions 

optional for cases where less than 10% biomass fuel is used even if CO2 CEMs are being used. 

Response: EPA has revised the definition of municipal solid waste (MSW) in §98.6, which we 

have concluded addresses the commenter’s concern, by specifying that materials separated from 

MSW and combusted separately (such as plastics) are not classified as MSW. We have 

determined that this definition change addresses the commenter’s concern, and therefore, a 

definition of plastics does not need to be added to the rule at this time. . 

We have not incorporated the commenter’s suggestion to make biogenic CO2 reporting optional 

for sources that burn less than 10% biomass. However, recognizing that the use of ASTM 

Methods D7459-08 and D6866-08 each quarter can impose a significant cost burden on sources 

that burn small amounts of partially biogenic fuels such as MSW and tires, we have added a 

provision to the final rule that allows sources that derive 10 percent or less of their heat input 

from MSW and/or tires to calculate biogenic CO2 emissions using the Tier 1 methodology 

together with fuel-specific default biogenic percentages. See section II.G of the preamble to the 

final rule amendments for further information. 

 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.2 

Comment Excerpt Number: 3 

Comment: A Proposed Solution. In overview, sources would still report biogenic CO2

completely separate from other GHG emissions as in the current rule, but CO2 CEMS users 

would have the option as to which fuel type -fossil fuel or biomass fuel-to use to determine the 

portion of their CO2 emissions to subtract from their CEMS total to get the balance orCO2 for the 

other fuel type. Part 75 CO2 CEMS users subject to Subpart D would also be allowed to use a 

default higher heating value (HHV) for their biomass fuel when their biomass fuel use is less 

than 50% of their total heat input. These changes should allow the UARG members who are not 
145 

predominantly burning biomass to report biogenic CO2 separately with minimal additional effort 

to their Part 75 CO2 CEMS reporting obligations under the Mandatory Reporting Rule. 

Current Rule Under current rule provisions, sources that combust both biomass and fossil fuel 

and use a CO2 CEMS are required to calculate the fossil CO2 and determine the biomass fuel 

CO2 by difference (Le., CEM CO2 minus fossil CO2). 

Alternate Approach. Under this alternate approach, sources would be allowed to choose either 

their biomass or the fossil fuel use to determine the calculated CO2 emissions using the same 

methodology as the current Equation C-13. This approach is reasonable since the amount of 

biomass fuel used has to be quantified for CH4 and N20 calculations anyway and a fuel specific 

default F-factor for Bark and Wood residue is available from Table I in section 3.3.5 of 

Appendix F to 40 CFR Part 75. Alternatively, a facility would have the option to determine a 

site-specific value as outlined under section 3.5.6 of Appendix F to 40 CFR Part 75. In addition, 

since Subpart D Part 75 method users are expected to select the biomass fuel calculation option 

when they are firing only relatively small amounts of biomass, the rule language could be 

modified to allow those Subpart 0 reporters to use default higher heating values for biomass in 

their Equation C-13 calculation without any appreciable loss of accuracy. These default values 

are provided by EPA in Table C-I of Subpart C. EPA could set the threshold for this HHV 

default selection to when biomass comprises less than 50% of the annual heat input. Also note 

that fuels not listed in Table C-l are exempt if they provide less than 10% of the total heat input. 

To allow the use of either calculating the fossil fuel CO2 or biomass CO2, a small change to the 

current Equation C-13 can be made. The current Equation C-13 is as follows: 

V(ff) = [Fuel*F(c)+HHV] 10^6 (Eq. C-13) 

Where: 

V(ff)= Annual volume of CO2 

Fuel = Total quantity of the fossil fuel combusted 

Fc = Fuel-specific carbon based F-factor 

HHV = High heat value of the fossil fuel 

10^6= Conversion factor, Btu per mmBtu 

Equation C-13 calculates the annual CO2 volume from the fossil fuels. To allow the calculation 

of CO2 for any fuel. the reference to "fossil fuels" should be changed to "fuels combusted." 

Therefore, Equation C-13 stays the same, but the definitions are now: 

V(fc) = Annual volume orCO2 (Note V(fc) = volume of CO2 for fuels combusted (fc)) (Change 

V(ff) to V(fc) 

Fuel = Total quantity of the fuels combusted (Change fossil fuel to fuels) 

Fc = Fuel-specific carbon based F-factor 

HHV = High heat value of the fuels combusted (Change fossil fuel to fuels combusted) 

10^6= Conversion factor, Btu per mmBtu 

Corresponding rule language text changes to calculate the correct CO2 fraction would need to be 

made in 40 CFR 98.33(e)(2)(iii) and (iv). For example, at 98.33(e)(2)(iii) at the two places where 

the words "fossil fuel" currently exist they could be replaced with the phrase "either fossil fuel or 

biomass." 
146 

In summary, allowing the source to select the fuel type to calculate the CO2 will still achieve the 

accuracy standards in the GHG MRR while lessening the unnecessary monitoring and reporting 

burden for Subpart D sources that use CO2 CEMS and predominantly burn fossil fuels. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2382.1, Excerpt 2. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.1 

Comment Excerpt Number: 3 

Comment: We urge EPA to require that the reporter use the tier method that will provide the 

most accurate information regarding the amount and type of biomass used and its carbon content 

– presumably the Tier 3 methodology as it proposes. Importantly, for purposes of determining 

the types of biomass being combusted and the amount of emissions, under EPA’s proposed 

definition of “emission data”, EPA would make available all of the inputs required to make these 

calculations, which would include at least the fuel type and fuel amount. This would provide the 

public and policymakers with important information regarding the types and amount of biomass 

being used. Thus, in conjunction with the evolving scientific evidence, the public and 

policymakers will be able to more accurately assess the GHG impacts of biomass use. 

EPA further proposes to amend the provisions of section 98.33(e) by removing the CEMS 

restriction on the use of Tier 1 reporting to determine biogenic emissions contained in section 

98.33(e)(1). EPA rationalizes that “[t]here is no technical basis for this restriction provided that 

biomass consumption can be accurately quantified.” While that may be the case with respect to 

the rule as it exists [A fact that we do not concede], we would urge EPA to take this opportunity 

to strengthen the reporting requirements. EPA should provide that the source category must 

determine its biogenic CO2 emissions using the tier that applies to that unit. For instance, source 

categories that are required to use Tier 3 methodology to calculate their other GHG emissions 

would be required to use Tier 3 to determine their biogenic CO2 emissions. 

In general, we agree with EPA that section 98.33(e)(2) needs to be revised to more accurately 

capture the amount of CO2 emissions from biomass combustion. We also agree that use of this 

methodology from facilities whose monitoring also includes process and/or sorbent CO2

emissions and emissions from the combustion of MSW could lead to an inaccurate accounting of 

biogenic CO2 emissions. However, we again think that this is an opportunity to strengthen this 

rule. Therefore we propose that EPA amend the rule to require that a facility that is disqualified 

from using the methodology set forth in section 98.33(e)(2), as proposed, must use the Tier 3 

methodology to calculate its biogenic CO2 emissions. Again, as explained above, this would 

provide the public with useful information not only about the amount of biogenic CO2 emissions 

from source categories, but as to the type and amount of biomass used. 
147 

Response: The commenter states that Tier 3 rather than Tier 1 should be used to calculate CO2

emissions from biomass combustion, for units with CEMS that cannot use the calculation 

method in §98.33(e)(2), because Tier 3 will provide information on the type and amount of 

biomass fuel(s) combusted. In fact, Tier 1 provides the same basic information as Tier 3, 

regarding the fuel type and the amount of fuel combusted (see §§98.36(b)(4), 98.36(e)(2)(i), and 

98.36(e)(2)(iv)(A)). The difference between the two Tiers is that Tier 1 uses a default HHV and 

a default CO2 emission factor in the emissions calculations, whereas Tier 3 requires periodic 

determination of the carbon content of the fuel. Also, the Tier 3 QA/QC requirements for 

quantifying fuel consumption are generally much more rigorous than those for Tier 1. 

Although Tier 3 is likely to provide more accurate data than Tier 1, particularly for a fuel that 

has a significantly variable heating value or carbon content, we are not imposing the added 

burden of Tier 3 fuel sampling and QA/QC requirements on units with CEMS, particularly when 

the method in §98.33(e)(2) to calculate biogenic CO2 emissions cannot be used. Sources always 

have the option to use Tier 3 instead of Tier 1, if greater accuracy is desired, but the additional 

burden is not warranted at this time. Further, we would note that such a decision does not affect 

the uncertainty of the overall emissions estimate that was obtained from the CEMS, but only the 

allocation of emissions between biogenic and fossil. In view of these considerations, the 

commenter’s suggestion has not been incorporated into the final rule. 

Commenter Name: Brian Gasiorowski 

Commenter Affiliation: Lafarge North America 

Document Control Number: EPA-HQ-OAR-2008-0508-2401.1 

Comment Excerpt Number: 4 

Comment: Proposed exclusion for cases where MSW is less than 10% of Annual Heat Input 

There are cases in which a cement kiln operator may use an MSW-derived fuel in small amounts 

of just a few percent of a kiln’s annual heat input. We believe that in these cases the quarterly - 

or more frequent - stack gas sampling and testing is unwarranted relative to the small amount of 

biogenic CO2 emissions which would be required to be reported separately. We propose adding a 

sub-paragraph under 98.33(e)(3) to make reporting of biogenic CO2 emissions optional for cases 

where less than 10% biomass fuel is used even if CO2 CEMs are being used. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2401.1, Excerpt 1. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 7 

Comment: EPA states on page 48759 of the preamble: 
148 

“In general, biogenic CO2 emissions reporting would be required only for the combustion of the 

biomass fuels listed in Table C-1 and for municipal solid waste (which consists partly of biomass 

and partly of fossil fuel derivatives.) 

We are proposing to amend 40 CFR 98.33(e) to describe three cases in which units that combust 

biomass would not need to report biogenic CO2 emissions separate from total CO2 emissions.” 

We are concerned that none of the three exclusionary cases would provide relief to a cement kiln 

operator using a CO2 CEMs to measure the total combustion and process emissions from a 

cement kiln that is using some relatively small amount of an alternative fuel that still fits within 

EPA’s proposed definition of “municipal solid waste.” 

As EPA is aware, the cement industry plays a significant positive role in promoting resource 

conservation and recovery through use of a broad range of byproducts as alternative fuels. These 

byproducts include materials such as woods, papers, plastics, carpets, baby diapers, animal and 

agricultural byproducts, asphalt shingles, tires, landfill gas, auto shredder fluff, and many others. 

The proposed rule language provides flexibility such that in many cases any biogenic CO2

emissions are not obligated to be reported separately from a cement kiln operator using CO2

CEMs to determine the total CO2 emission from the cement kiln. Instead, in the cases reporting 

of biogenic CO2 emissions would be optional. However, we are concerned that is a more limited 

number of cases a cement kiln using an alternative fuel meeting the definition of “MSW” under 

this rule would be obligated to separately determine and report biogenic CO2 emissions even if 

only a very small amount of the “MSW” fuel were being used with relatively small biogenic 

emissions. 

We propose two changes to the language of the rule which would ensure that cement kiln 

operators using relatively small amounts of “MSW” are not obligated to separately report the 

small amount of biogenic emissions from combustion of the MSW. In these cases the facility 

would include the biogenic CO2 emissions with the total CO2 emissions determined by the 

CEMs. These two proposed changes are as follows: 

1. Adding a definition for “plastics” along with a minor change to the definition of MSW to 

clarify that any plastics separated from MSW are not included within the MSW definition. 

2. Adding a sub-paragraph under 98.33(e)(3) to make reporting of biogenic CO2 emissions 

optional for cases where less than 10% biomass fuel is used even if CO2 CEMs are being used. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2401.1, Excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 8 
149 

Comment: Several petroleum industry companies have requested clarifications to the estimation 

methodology for the biogenic portion of GHG emissions for small incinerator units, typically 

remotely located, such that the data collection burden and amount of emissions would be 

balanced. As the technical corrections to Subpart C, did not address this issue adequately, API 

members would like to raise this issue again and provide an example to support our suggestions. 

The oil and gas industry operates small co-fired batch incinerators located at remote facilities to 

burn on-site Municipal Solid Waste (MSW) classified trash and waste. 40 CFR 98.34(d) requires 

facilities that combust MSW to determine the biogenic portion of the CO2 emissions using 

ASTM 06866-08 (analysis) and ASTM 07459-08 (sampling) each quarter when MSW is 

combusted. 

These types of units typically co-fire natural gas and MSW the entire time they are in use and 

operate in batch mode. The Technical Revisions to Part 98 in the Federal Register on August 11, 

2010, provide clarification on the issue of exhaust gas testing for co-fired units. 40 CFR 98.34(d) 

requires determination of the biogenic portion of the CO2 emissions for units when MSW is the 

only fuel with a biogenic portion component combusted in the unit. This would be applicable to 

the typical small remote location incinerators found in the industry. 

One API member company performed sampling on an incinerator at an Alaska North Slope 

operation in June 2010. The samples were taken during co-firing of MSW and natural gas, as this 

is the only mode in which the incinerator is able to operate. The biogenic portion of the exhaust 

was 28 percent. Applying this biogenic portion to the sum of the emissions from natural gas 

(using Tier 1) and the MSW (using Tier 1) for the total 2009 fuel use (as an example calculation, 

2010 year will not vary greatly) yields the following results: [See submittal for data tables 

provided by commenter showing the portion of biogenic CO2 emissions from MSW combustion] 

Several options would be preferable to the current requirements for these small sources. In order 

of preference these are: 

(1) Make reporting of the biogenic portion of incinerator CO2 emissions optional for sources 

whose projected annual emissions from MSW are less than a certain threshold (e.g. 5,000 

tonnes). Provide a default biogenic percentage, such as 30% for the sources who choose not to 

perform the testing. 

(2) If EPA feels that testing is necessary, regardless of the magnitude of emissions from the 

source, allow sources to perform one-time testing for biogenic content and then use the data for 

current and future reporting. A periodic test (once every 5 years) to reconfirm the biogenic 

portion would be reasonable. 

The basis of this request to modify the current requirements in Part 98 is on the cost to perform 

the testing vs. the amount of biogenic emissions quantified. The cost of the June 2010 test 

highlighted above was approximately $11,000. Subsequent tests are expected to be on the order 

of $5,000-$7,000 each. Therefore, it will cost approximately $20,000-$30,000 per year per 

facility, indefinitely, to quantify approximately 400 tonnes of biogenic CO2 emissions annually 

from a single small batch, co-fired incinerator. For a regulation with an applicability threshold of 
150 

25,000 metric tons, the cost is not reasonable in relation to the mass of emissions it quantifies. 

Use of a default biogenic factor would be a far more reasonable assessment method, and any 

error introduced by use of a default would only be on the order of tens or hundreds of tonnes. 

This magnitude of error is consistent with the use of the default factors of Tiers 1 and 2, which 

are considered reasonable by EPA. Additionally, the biogenic component of emissions from 

these types of units is not expected to vary significantly. 

API requests that the requirement to determine the biogenic portion of CO2, through sampling 

and analysis, for the exhaust from these small incinerators should be optional and a simplified 

and limited protocol provided to estimate the biogenic portion of the emissions. API requests 

further technical correction to the provisions of 98.34(d) to allow those options. 

Response: Please see Section II.G of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 10 

Comment: Proposed exclusion for cases where MSW is less than 10 percent of Annual Heat 

Input. There are cases in which a cement kiln operator may use an MSW-derived fuel in small 

amounts of just a few percent of a kiln’s annual heat input. We believe that in these cases the 

quarterly – or more frequent – stack gas sampling and testing is unwarranted relative to the small 

amount of biogenic CO2 emissions which would be reported separately. We propose adding a 

sub-paragraph under 98.33(e)(3) to make reporting of biogenic CO2 emissions optional for cases 

where less than 10% biomass fuel is used even if CO2 CEMs are being used. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2401.1, Excerpt 1. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 11 

Comment: C. Amendments to Methodology for Calculating Biogenic CO2 Emissions 

EPA proposes various revisions to the 40 C.F.R. § 98.33, and in particular subsection (e) of that 

provision. As an initial matter, we oppose any proposed amendment that would exempt any 

source category from separately reporting its biogenic CO2 emissions (including those emissions 
151 

which may result from the combustion of tires and other municipal solid waste 

(“MSW”)).[Specifically we oppose proposed section 98.33(a)(5)(iv) and 98.33(e).] 

EPA proposes to amend § 98.33(e) of the rule to address reporting of biogenic CO2 emissions in 

the event that the rule does not provide an HHV or default CO2 emission factor for a specific 

type of biofuel. Facilities that use fuels for which default values are not provided may face some 

burden in calculating biogenic CO2 emissions. Nonetheless, we urge EPA to require separate 

reporting of biogenic CO2 emissions whenever possible. Therefore, EPA should not provide, as 

proposed, that use of CEMS would exempt a source from this separate reporting requirement. 

Once again, knowing the amount of biogenic CO2 emissions is important from a policy 

perspective regardless of the monitoring methodology used. Therefore, we urge EPA to require 

that the reporter use the methodological tier that will provide the most accurate information 

regarding the amount and type of biomass used and its carbon content – presumably the Tier 3 

methodology as it proposes. 

Importantly, for purposes of determining the types of biomass being combusted and the amount 

of emissions, under EPA’s proposed definition of “emission data”, EPA would make available 

all of the inputs required to make these calculations, which would include at least the fuel type 

and fuel amount. This would provide the public and policymakers with important information 

regarding the types and amount of biomass being used. Thus, in conjunction with the evolving 

scientific evidence, the public and policymakers will be able to more accurately assess the GHG 

impacts of biomass use. 

Response: The final rule allows only two exceptions to the requirement to separately report 

biogenic CO2 emissions: (1) For Part 75 units, the reporting is optional for 2010, but becomes 

mandatory for the 2011 reporting year; and (2) the reporting is optional for the combustion of 

tires. For more information on EPA’s rationale regarding biogenic CO2 emissions reporting, see 

Sections II.C.2 and II.G of the preamble to the final rule amendments. 

Please see also the response to comment EPA-HQ-OAR-2008-0508-2403.1, excerpt 3. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 12 

Comment: EPA further proposes to amend the provisions of section 98.33(e) by removing the 

CEMS restriction on the use of Tier 1 reporting to determine biogenic emissions contained in 

section 98.33(e)(1). EPA rationalizes that “[t]here is no technical basis for this restriction 

provided that biomass consumption can be accurately quantified.” While that may be the case 

with respect to the rule as it exists, [A fact that we do not concede.] we would urge EPA to take 

this opportunity to strengthen the reporting requirements. EPA should provide that the source 

category must determine its biogenic CO2 emissions using the tier that applies to that unit. For 
152 

instance, source categories that are required to use Tier 3 methodology to calculate their other 

GHG emissions would be required to use Tier 3 to determine their biogenic CO2 emissions. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2403.1, excerpt 3. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 13 

Comment: In general, we agree with EPA that section 98.33(e)(2) needs to be revised to more 

accurately capture the amount of CO2 emissions from biomass combustion. We also agree that 

use of this methodology from facilities whose monitoring also includes process and/or sorbent 

CO2 emissions and emissions from the combustion of MSW could lead to an inaccurate 

accounting of biogenic CO2 emissions. However, we again think that this is an opportunity to 

strengthen this rule. Therefore we propose that EPA amend the rule to require that a facility that 

is disqualified from using the methodology set forth in section 98.33(e)(2), as proposed, must use 

the Tier 3 methodology to calculate its biogenic CO2 emissions. Again, as explained above, this 

would provide the public with useful information not only about the amount of biogenic CO2

emissions from source categories, but as to the type and amount of biomass used.[In fact, EPA 

may want to consider requiring a source category to determine its biogenic CO2 emissions even 

if a facility uses CEMS as this would require, pursuant to EPA’s proposed definition of 

“emission data,” the amount and type of biomass that is used publicly available.] 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2403.1, Excerpt 3. 

Monitoring and QA/QC requirements 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association (GPA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2402.1 

Comment Excerpt Number: 2 

Comment: Natural Gas Standard Conditions (Preamble page 48768) 

EPA acknowledges in the Preamble (page 48768) that “the oil and gas industry and other 

hydrocarbon processing facilities commonly express gaseous volumes using 60 F as the standard 

temperature. Thus, many existing flow monitors for gaseous feedstocks and products at 

petrochemical facilities may be programmed to output volumes at standard conditions of 60 F. It 

is impractical and unnecessary to either reprogram these monitors to provide volumes corrected 

to standard conditions at 68 F or to require reporters to convert the output volumes from one set 

of standard conditions to another...” EPA proposes to amend Subparts X and Y to provide two 
153 

options for “molar volume conversion” factors that can be used by reporters for standard 

conditions of 60 F and 14.7 psia or 68 F and 14.7 psia. 

No revisions are proposed for Subpart C, which currently defines standard conditions as 68 F and 

14.7 psia, while the default natural gas heating value in Table C-1 is based on 60 F and 14.7 psia. 

The issue is further complicated in the proposed Subpart W, which introduces other, different 

“standard conditions” for gaseous sources. This inconsistency is extremely confusing and could 

lead to erroneous emission calculations. In addition, it places an unnecessary burden on 

reporters. 

GPA requests that EPA consistently provide flexibility in using standard conditions of 60 F and 

14.7 psia or 68 F and 14.7 psia in all parts of the GHG RP. 

Response: We have concluded that the commenters’ request to use standard conditions of 60 °F 

and 14.7 psia or 68 °F and 14.7 psia is reasonable, and we are revising the definition of the term 

“MVC (molar volume conversion)” in the nomenclature of Equation C-5 of subpart C. The 

revised definition of MVC allows sources to use a MVC value of either 849.5 scf/kg mole (for a 

standard temperature of 68 °F) or 836.6 scf/kg mole (for a standard temperature of 60 °F). 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 30 

Comment: Revise §98.34(a)(6) to remove the limitation of using a gas chromatograph for only 

gaseous fuels. This would make this Tier 2 fuel sampling and analysis requirement consistent 

with the Tier 3 requirement at §98.34(b)(4), which does not limit the use of a gas chromatograph 

to gaseous fuels. 

Response: We agree with the commenter and have amended 40 CFR 98.34(a)(6) so as not to 

limit the use of gas chromatographs to gaseous fuels. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 31 

Comment: The Tier 3 calculation methodology QA/QC requirements at §98.34(b)(1) state that 

the requirements only apply to oil and gas flow meters but they should apply to all fuel flow 

meters. 

§98.34(b)(1) You must calibrate each oil and gas fuel flow meter according to §98.3(i) and the 

provisions of this paragraph (b)(1). 
154 

Response: EPA is not making the recommended change. The reference to oil and gas fuel flow 

meters is sufficient to capture liquid and gaseous fuels reporting under the Tier 3 option. In 

addition, Equations C-4 and C-5 specify that fuel consumption must be provided by fuel flow 

meters calibrated according to 40 CFR 98.3(i) unless the fuel consumption is measured either by 

qualified fuel billing meters under 40 CFR 98.34(b)(3) or by oil tank drop measurements. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508 

.1 

Comment Excerpt Number: 32 

Comment: Revise §98.34(b)(1)(i)(C) to remove the term “industry-accepted” as it has the same 

meaning as the term “industry consensus standard” and is therefore redundant in the sentence. 

§98.34(b)(1)(i)(C) You may use an industry-accepted or industry consensus standard calibration 

practice. 

Response: To avoid confusion, we have revised 40 CFR 98.34(b)(1)(i)(C) to remove “industry 

consensus standard calibration” and only refer to “industry-accepted practice” Please see 

response to -: EPA-HQ-OAR-2008-0508-2396.1, excerpt 3 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 33 

Comment: Revise §98.34(b)(1)(ii) to allow a consensus-based standards organization method to 

be used for recalibrating fuel flow meters. The Tier 3 calibration procedures at 

§98.34(b)(1)(i)(A) through (C) allow the initial fuel flow meter calibration to be performed 

according to one of three procedures: a method published by a consensus-based standards 

organization, a procedure specified by the meter manufacturer, or an industry consensus standard 

calibration practice. The recalibration procedures should allow the use of the same procedures. 

§98.34(b)(1)(ii) In addition to the initial calibration required by §98.3(i), recalibrate each fuel 

flow meter (except as otherwise provided in paragraph (b)(1)(ii) of this section) either annually, 

at the minimum frequency specified by the manufacturer, at the interval specified by the 

consensus-based standards organization method, or at the interval specified by the industry 

consensus standard practice. 
155 

Response Recalibrations may be performed by using any procedure allowed for the initial 

calibration. We have amended 40 CFR 98.34(b)(1)(ii) to clarify that the frequency at which 

calibrations must be performed is according to one of the following. Recalibrations may be 

performed annually, at the minimum frequency specified by the manufacturer, or according to 

industry standard practice. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 34 

Comment: Revise §98.34(b)(1)(iii) to correct the recordkeeping citation. 

§98.34(b)(1)(iii) Fuel billing meters are exempted from the initial and ongoing calibration 

requirements of this paragraph and from the Monitoring Plan and recordkeeping requirements of 

§98.3(g)(5)(i)(C), (g)(6) and (g)(7), provided that the fuel supplier and the unit combusting the 

fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same 

company. 

Response: We We agree with the commenter. The requirement in paragraph (g)(6) for Part 98 

facilities to keep records of certification and QA test results is not appropriate for fuel billing 

meters. The QA/QC of these meters is the responsibility of the billing companies, and these 

companies are not regulated under Part 98. The final rule therefore adds paragraph (g)(6) of 

§98.3 to the list of monitoring plan record keeping requirements from which fuel billing meters 

are exempted. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 35 

Comment: It appears that 98.34(b)(4) has been revised. EPA may have inadvertently removed 

some important installation requirements for Tier 3 fuel meters in the original §98.34(b)(4) . For 

example, some of the methods previously listed contained requirements relative to the number of 

upstream and downstream distances from the nearest flow disturbance in order to assure accurate 

data. It is suggested to reinstate this paragraph but without the reference to specific methods, 

analogous changes to the fuel sampling paragraph, to provide more flexibility. This would 

require renumbering the EPA’s proposed paragraph (b)(4) to (b)(5). 

§98.34(b)(4) Install, operate, and maintain all fuel flow meters according to one of the following 

methods. You may use the manufacturer’s recommended procedures, a method published by a 

consensus-based standards organization, or industry consensus standard practice. Consensusbased standards organizations include, but are not limited to, the following: ASTM International, 

the American National Standards Institute (ANSI), the American Gas Association 
156 

Response: We do not agree with the commenter’s assessment. The final rule provides a great 

deal of flexibility in choosing an appropriate calibration method. It is true that some of the 

methods in the list that was removed from the rule do have specific installation requirements 

(e.g., AGA Report No. 3 for orifice plates). But since these installation requirements are 

method-specific, no universally applicable installation requirements were lost by removing the 

list of methods from the rule. Regardless of which calibration method is selected, if the method 

includes special installation requirements, the source will have to meet those requirements in 

addition to performing the calibration procedures. 

Commenter Name: David A. Buff 

Commenter Affiliation: Golder Associates Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2395.1 

Comment Excerpt Number: 1 

Comment: The proposed 98.34(a)(2)(ii)(B) adequately addresses situations where multiple fuel 

deliveries are obtained from one supplier during a month. However, during the course of a 

month, or even daily, a facility may receive multiple fuel shipments from different supply 

sources, even though the shipments are from the same fuel oil distributor. This revision would 

still require sampling multiple fuel oil deliveries in a given day or month if fuel oil is received 

from different supply sources. This provision should be revised to require only quarterly 

sampling for stationary combustion sources that fire a limited amount of fuel oil on an annual 

basis (i.e. <10% annual capacity factor) regardless of the number of fuel oil suppliers (or the 

number of “lots”). Language similar to that in 98.34(a)(2)(iii) would be appropriate. It would 

also be appropriate to allow a composite sample to be obtained over the quarterly period to 

reduce the analytical burden. Another option for these type sources would be to allow for the use 

of default HHV values. 

Response: For a discussion on what is considered a fuel lot, see EPA’s response to comment 

EPA-HQ-OAR-2008-0508-2381, Excerpt 1. Also see EPA’s response to comment EPA-HQOAR-2008-0508-2381, Excerpt 2 on sampling from in-service fuel oil tanks. EPA has concluded 

that our interpretation of “supply source” in Section II.G of the Preamble, combined with the rule 

provisions for sampling in-service tanks only will sufficiently reduce the burden on units 

operating with low capacity factors. Use of a default HHV is not appropriate where a unit is 

larger than 250 mmBtu/hr. 

Commenter Name: Walter Tyler 

Commenter Affiliation: INVISTA 

Document Control Number: EPA-HQ-OAR-2008-0508-2372.1 

Comment Excerpt Number: 1 
157 

Comment: EPA is proposing to revise 40 CFR 98.33(a)(2)(iii) [Footnote: It appears that the 

reference to 40 CFR 98.33(a)(2)(iii) should actually be 40 CFR 98.34(a)(2)(iii).] by replacing 

“fossil fuel-derived gaseous fuels” with “other fuels (gaseous)” and additional related changes. 

INVISTA’s facilities have multiple units that burn process waste off gases that currently are not 

identified as fuels in Subpart C. With the proposed language change to this subpart, and the other 

language changes proposed, there is significant potential for confusion about the applicability of 

Subpart C requirements to the process waste off gases burned in these types of units. 

To provide additional context, the definitions of Fuel Gas and Fuel Gas System at 40 CFR 98.6 

currently describe processes at petroleum refineries and petrochemical plants that collect gaseous 

fuels for combustion. The definition of Fuel Gas System describes gas handling (e.g., 

compression, knock-out pots, etc.) and processing (e.g., sulfur removal) that usually are 

associated with the extraction of fuel gases from production units at petroleum refineries and 

petrochemical plants. These gaseous fuels from refinery and petrochemical processes tend to be 

similar to the hydrocarbons found in natural gas. The broad-based language of “other fuels 

(gaseous)” could be interpreted to apply to process waste off-gases from any chemical 

production unit at facilities that are not petroleum refineries or petrochemical plants and that do 

not have characteristics and properties similar to natural gas. The inclusion of these chemical 

processes in this definition does not appear to meet the intent of the regulation. To avoid this 

potential unintended consequence EPA should modify the definition of “Fuel” in 40 

CFR 98.6 as follows “Fuel means solid, liquid or gaseous combustible material, but excludes 

process waste off gases from chemical production plants that are not petroleum refineries or 

petrochemical plants.” 

Response: We did not intend to impose Tier 3 requirements on units that would not have 

otherwise been subject to Tier 3 prior to the proposed change. We have addressed this concern 

in the final rule by modifying the definition of “fuel gas” to include only fuels generated at 

petroleum refineries or petrochemical processes subject to subpart X of the rule. Please see 

Section II.G of the preamble for a further discussion for a rationale for the change in definition of 

fuel gas. 

Commenter Name: Gregory J. Wooten 

Commenter Affiliation: American Electric Power (AEP) 

Document Control Number: EPA-HQ-OAR-2008-0508-2381 

Comment Excerpt Number: 1 

Comment: AEP is requesting that EPA further clarify fuel oil HHV sampling requirements. 

Under the proposed amendments, EPA is proposing to more precisely define the term “fuel lot” 

as it pertains to facilities that receive multiple deliveries of a particular fuel from the same supply 

source each month, either by truck, rail, or pipeline. The proposed amendment clarifies that a 

fuel lot consists of all of the deliveries for a given calendar month. Thus, for these facilities, the 

required HHV sampling frequency would be no greater than once per month. From the end users 

standpoint (AEP), we are interpreting the term “supply source” as it applies to distillate oil 
158 

grades to mean a single vendor. For example, AEP may place an order for No. 2 distillate fuel oil 

from a vendor who chooses to deliver the fuel oil to the AEP facility over a number of days in 

several truck loads. AEP interprets the proposed amendment to allow the facility to obtain one 

sample and analysis for HHV per month for the No. 2 distillate fuel oil from a specific vendor. If 

the facility also takes delivery of a different fuel type (e.g. No. 1 distillate fuel oil), then one 

sample per month from the vendor for that fuel type would also be obtained and analyzed. AEP 

would appreciate EPA confirming that this interpretation is acceptable and consistent with the 

amendment. 

Response: For fuel oil, as noted in Section II.G of the Preamble, the “supply source” may be a 

particular refinery, bulk terminal, or fuel oil distributor, provided the fuel properties can 

reasonably be expected to be consistent. For a specific grade number of fuel oil, EPA expects 

there to be little variation for the HHV and one sample per month for each grade of fuel 

delivered from each supply source is acceptable. The owner or operator must document in the 

monitoring plan how the monthly sampling for each fuel type in Table C-1 is performed. 

Commenter Name: David A. Buff 

Commenter Affiliation: Golder Associates Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2395.1 

Comment Excerpt Number: 2 

Comment: If a facility has already implemented a fuel sampling plan required by a Title V 

operating permit, this sampling plan should be used in lieu of the requirements of 98.34. This 

would significantly reduce the sampling and monitoring burden on a facility that may be required 

to sample, analyze, and report fuel characteristics on a different schedule than those required by 

the mandatory reporting rule. 

Response: For the purpose of obtaining consistent and verifiable data, we are not allowing 

exceptions to the fuel sampling frequencies specified in this rule. We note that the commenter 

did not provide examples of typical fuel sampling schedules that may be found in Title V 

permits. However, if the fuel sampling schedule in a Title V permit requires sampling at a 

frequency that is equal to or higher than the minimum frequency specified in Part 98, meeting 

that schedule would satisfy the requirements of the GHGRP. 

Commenter Name: Walter Tyler 

Commenter Affiliation: INVISTA 

Document Control Number: EPA-HQ-OAR-2008-0508-2372.1 

Comment Excerpt Number: 2 

Comment: The text at 40 CFR 98.34(b)(3)(ii)(E) currently reads...”For gaseous fuels other than 

natural gas and biogas (e.g., process gas),...” The use of the term “process gas” appears to 

change the meaning of the “other fuels (gaseous)” phrase. INVISTA recommends 

98.34(b)(3)(ii)(E) be modified to read...”For gaseous fuels other than natural gas and biogas 
159 

(e.g., fuel gas [not process gas]),...” 

Response: The term “other fuels (gaseous)” in Table C-1 is meant to organize fuels by category, 

only. The fuels listed in Table C-1 under “other fuels (gaseous)” are not inclusive of all gaseous 

fuels other than natural gas and biogas. If a gaseous fuel is not listed in Table C-1, it would still 

be subject to the requirements of 40 CFR 98.34(b)(3)(ii)(E) if the use of Tier 3 is required. The 

reference to “process gas” in 40 CFR 98.34(b)(3)(ii)(E) does not change the meaning of the 

categorical heading of “other fuels (gaseous).” Process gas is not included in Table C-1, but it 

may still be subject to the requirements of 40 CFR 98.34(b)(3)(ii)(E). As such, EPA is not 

making any changes in response to this comment. 

Commenter Name: Gregory J. Wooten 

Commenter Affiliation: American Electric Power (AEP) 

Document Control Number: EPA-HQ-OAR-2008-0508-2381 

Comment Excerpt Number: 2 

Comment: Regarding the proposed amendment that will allow manual oil samples to be taken 

after each addition of oil to the storage tank. AEP operates a number of distillate-oil fired 

auxiliary sources that operate infrequently and are subject to the HHV sampling requirements of 

the GHG reporting rule. As previously described, the fuel deliveries for the tanks that supply 

these sources at our facilities may arrive at the facility by truck over a number of days. It’s not 

unusual to receive delivery of several truck loads of fuel oil between periods of operation of the 

source. AEP believes that it would be appropriate to manually sample the fuel from the tank each 

day that the source is operated and that this method would be equivalent to the amendment that 

allows for sampling the tank after each addition of oil. AEP would appreciate EPA confirming 

that this interpretation is acceptable and consistent with the amendment. 

Response: EPA agrees with the commenter and believes it is only appropriate to require fuel 

sampling of each addition to the storage tank when the tank is in service. However, the August 

11. 2010 proposed rule did not provide such flexibility. As a result, we have amended 

§98.34(a)(2)(ii) to only require fuel sampling once the storage tank is placed in service and to 

only require sampling of each fuel addition as long as the tank remains in service. The final rule 

also clarifies that the daily manual sampling option requires sampling only on days when oil 

from the storage tank is combusted in the unit. Please see section II.G of the preamble to the 

final rule amendments for further information. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2396.1 

Comment Excerpt Number: 2 

Comment: The Interstate Natural Gas Association of America (INGAA) approves of several 

revisions in the Proposed Rule regarding methodologies and practices that are acceptable. For 

example, to determine heating value, §98.34(a)(6) is revised to indicate that, “You may use a 
160 

method published by a consensus standards organization if such a method exists, or you may use 

industry consensus standard practice to determine the high heat values.” This general reference 

to consensus methods is preferable to the original rule requirements, which provided a long list 

of specific allowable methods. INGAA approves of this change. In addition, the Proposed Rule 

references “industry standard practices” for procedures such as flow meter calibration, and 

INGAA agrees that industry standard practices should be acceptable for addressing reporting rule 

requirements. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 3 

Comment: EPA’s Clarifications to Tier 4 Monitoring Requirements. The Energy Recovery 

Council (ERC) supports EPA’s proposal to clarify CEMS hourly average data validation 

consistent with 40 CFR 60.13. This will ensure CO2 validation is consistent with CEMs for SO2, 

NOx and CO required for Part 60 sources such as large MWCs. We note, however, that EPA has 

proposed a recommendation for quarterly ASTM 7459-08 sampling (collect small amount 1-5 cc 

every hour for quarter). In practice this recommendation would be very difficult and costly to 

implement as is would require separate sample collection system and could not be readily 

integrated into an existing CEM system without considerable modifications to sampling 

components and software. Because of the significant impediments to implementing quarterly 

ASTM 7459-08 sampling, we strongly recommend that EPA delete this proposed 

recommendation. 

We do have a recommendation for refining the sampling requirement language to better facilitate 

the Agency’s recommendation that sampling be collected over a longer time period, EPA should 

revise the sampling requirement by striking out the word “consecutive” to: “... collect gas 

sample during normal operation for at least 24 [consecutive] hours or for as long as is deemed 

necessary to obtain a representative sample.” Eliminating the term “consecutive” would allow a 

source to spread sampling out over longer period of time consistent with EPA’s own 

recommendation. 

Response: The final rule removes the word “consecutive” from the rule text in 98.34(d). 

Therefore, collection of the quarterly gas samples over 24 cumulative hours is acceptable. We 

have also clarified that the “recommendation” to withdraw a small 1-5 cc sample during every 

operating hour is only an option. The biogenic percentage of the total CO2 emissions from MSW 

combustion varies not only with the composition of the MSW, but also with the amount of fossil 

fuel (if any) co-fired with the MSW. By installing a continuous sampling device, any changes in 

MSW properties or fuel blend ratios would be captured. 
161 

Our intent in recommending the use of a continuous sampling device was to suggest a way to 

eliminate these uncertainties in quantifying biogenic CO2 emissions from MSW. However, the 

proposed rule did not include guidelines for determining when continuous sampling is required. 

Therefore, the final rule simply states that sources are free to consider using a continuous 

sampling device in situations where the blend ratio or type of MSW combusted is not consistent 

----but this is not a requirement. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2394.1 

Comment Excerpt Number: 4 

Comment: The American Gas Association (AGA) supports the proposal to remove the lists of 

specific standards in section 98.34(a)(6), (b)(4) and (b)(5) and to replace the lists with a 

statement that reporters “may use a method published by a consensus standards organization if 

such a method exists, or you may use industry standard practices to determine” high heat values 

and carbon content of fuel. We agree this approach avoids the potential for omitting important 

standards, as occurred in section 98.7. We appreciate your inclusion of AGA in the statement 

that “Consensus-based standards organizations include, but are not limited to, the following: ... 

the American Gas Association (AGA).” 

Response: EPA thanks the commenter for the input. Generally, we have finalized the 

amendments noted by the commenter as proposed. The final rule provides contact information 

for the listed organizations. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 4 

Comment: Currently, under the final rule, sampling from each fuel lot is required for Tier 2 

units burning coal and fuel oil. The proposed rule clarifies the fuel lot definition for coal and fuel 

oil to be a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, oil 

delivery via pipeline from a tank farm, group of railroad cars, etc.). Therefore, when multiple 

deliveries of a particular type of fuel are received from the same supply source in a given 

calendar month, the deliveries for that month are considered, collectively, to comprise a fuel lot. 

This broader definition of a fuel lot reduces sampling burden for facilities with frequent fuel 

deliveries. At the most, sampling from the same supply source will be required once per month. 

Xcel Energy supports this expanded definition of a fuel lot because it reduces the sampling 

burden, but does not affect the accuracy of the emissions report. 

Response: EPA thanks the commenter for the input. For additional information on EPA’s final 

amendments clarifying the definition of “fuel lot” please refer to Section II.G of the preamble. 
162 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2396.1 

Comment Excerpt Number: 5 

Comment: For natural gas systems, frequent HHV analysis will often be available in association 

with existing gas chromatographs that monitor gas quality. For Subpart C, §98.34(a)(4) requires 

that “all valid fuel analyses” be used in GHG emission calculations. In some cases, existing 

operational practices include regular sampling (e.g., multiple sample in a day or hour) using gas 

chromatography (GC) to determine gas properties, including HHV. Thus, the rule essentially 

penalizes operators for having plentiful data by requiring implementation of new “data handling” 

procedures for HHV averaging and for addressing missing data. 

Existing GC instruments and operating procedures follow standard operating practices and the 

associated accuracy meets the accuracy objectives for GHG reporting. To avoid confusion and 

unnecessary burden regarding criteria for natural gas HHV sampling, the requirements for 

natural gas analysis should be clarified. Current practices should be accepted to avoid the need to 

develop new computer algorithms that specifically follow Subpart C calculation methodology. 

Averaging or reporting data at high frequency should not be required and Part 98 missing data 

algorithms should not be required because this added burden is not warranted. 

The Interstate Natural Gas Association of America (INGAA) recommends that operators be 

allowed to use existing averaging procedures. In addition, many sites have gas quality that does 

not vary significantly. In those cases, a single monthly natural gas analysis result provides an 

accurate means to estimate emissions and a single analysis from within the month should be 

allowed to determine HHV for natural gas. The methods and data averaging used can be 

identified in the GHG Monitoring Plan. 

To address this, §98.34(a)(4) should be revised, and INGAA recommends the following (see the 

edits in square brackets): 

“(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the 

minimum frequency specified in paragraph (a)(2) of this section, the results of all valid fuel 

analyses shall be used in the GHG emission calculations. [For natural gas-fired sources with 

multiple HHV samples and analyses within a single month, operator procedures or a single 

analysis from the month can be used to determine HHV. The procedure used to determine HHV 

shall be identified in the GHG Monitoring Plan required in §98.3(g)(5). For natural gas-fired 

sources, operator procedures can include alternative missing data procedures to those specified in 

§98.35.]” 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2383.1, Excerpt 39. 
163 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 5 

Comment: Mexichem supports the EPA’s proposal to remove the list of specific methods for 

determining HHV and carbon content and for fuel flow meter calibration, and specify instead 

that sources must either use appropriate methods from consensus standards organizations if such 

methods exist, or standard industry practice. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Caitlin Post 

Commenter Affiliation: Southern Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2377.1 

Comment Excerpt Number: 5 

Comment: EPA is proposing to clarify the frequency at which the high heating value (HHV) 

needs to be determined for various fuel types. Southern Company supports EPA’s clarification of 

CFR 98.34(a)(2)(ii) that allows multiple deliveries of a particular fuel from the same supply 

source in a calendar month to be considered a “fuel lot” and only require one representative 

sample. This clarification is appropriate because it eliminates the burden of sampling each truck 

delivery (there could be multiple deliveries a day) from the same source. 

Southern Company believes it is the intent of EPA to capture the HHV of the fuel oil that is 

actually being combusted. This intent is supported by the proposed option to sample fuel oil each 

time fuel oil is added to a unit’s storage tank instead of by fuel lot. Southern Company supports 

this option; however, this proposal does not provide needed clarification for facilities with 

multiple storage tanks. For example, a Southern Company facility has three storage tanks. 

Currently, Tank #1 is in service supplying fuel oil to the generating units. Tank #2 is designated 

as filling and is receiving shipments of fuel oil. (Tank #3 is maintained empty.) Tank #2 will not 

be placed into service until the in service tank (Tank #1) is depleted. Due to low run hours and 

the large capacity of the fuel storage tanks, the facility may not have a need to swap from Tank 

#1 to Tank #2 for a number of years. Because no fuel is moved from Tank #2 to Tank #1, the 

fuel sampling as currently required by the MRR is not capturing the HHV for the fuel oil that is 

actually being combusted. The MRR requires sampling of fuel as it is delivered or, as now 

proposed, when the fuel is added to a storage tank. These conditions require this facility to use 

the HHV of fuel that has not been combusted to calculate the greenhouse gas emissions from the 

unit for the current year (because the fuel that is being delivered and put into storage tanks is 

being added to Tank #2, not the in service Tank #1). Southern Company believes EPA does not 

intend for facilities to report emissions based on fuel that has not been used. To address this 

issue, Southern Company suggests that EPA allow facilities with multiple storage tanks to 

sample the fuel oil from the in-service tank twice a year and before a tank is placed into service. 
164 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2381, Excerpt 2, for the 

response on sampling in-service tanks only. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 5 

Comment: Under the proposed rule, as an alternative to sampling with every fuel lot, Tier 2 

units burning fuel oil can perform sampling after each addition to the storage tank using manual 

sampling methods, flow-proportional sampling, and continuous drip sampling. Xcel Energy 

supports giving reporters this alternative because it draws on current industry practices and 

reduces sampling burden at a number of our facilities. 

Response: EPA thanks the commenter for the input. For additional information on EPA’s final 

amendments clarifying the definition of “fuel lot” please refer to Section II.G of the preamble. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 8 

Comment: The proposed rule clarifies that facilities combusting MSW as either the primary or 

only fuel, paragraph (d), and facilities combusting combinations of biomass fuels, paragraph (e), 

shall perform a quarterly biomass (biogenic) CO2 analysis. Furthermore, the samples have to be 

collected for at least 24 consecutive hours. Xcel Energy believes this is excessive and that a 

shorter sample duration will give representative results. The supporting information is organized 

into three sections: facility descriptions, a discussion of MSW versus RDF, and 2010 biogenic 

CO~ sampling results. 

Response: The final rule allows sources to perform a demonstration, comparing the results of 

8-hour and 24-hour samples, to justify reducing the required minimum sampling time to 8 hours. 

Please see Section II.G of the preamble for further discussion. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 9 
165 

Comment: The Red Wing Plant is an electric power generating station located along the 

Mississippi River in Red Wing, Minnesota. The Red Wing plant is rated at 25 megawatts (MW) 

and has two boilers that burn RDF. The RDF burned at this facility is processed under contract 

with the Elk River Resource Recover Facility in Elk River, Minnesota, and the 

Ramsey/Washington Resource Recovery Facility in Newport, Minnesota. The RDF is brought 

onsite via truck and unloaded in the receiving area. From there, a single conveyor brings the fuel 

into the plant where it is then directed into either of the two traveling grate boilers. 

The Wilmarth facility is an electric power generating station located along the Minnesota 

River in Mankato, Minnesota. The Wihmarth plant is rated at 25 MW and has two boilers that 

burn RDF. The RDF burned at this facility is processed under contract with the Elk River 

Resource Recover Facility in Elk River, Minnesota, and the Ramsey/Washington Resource 

Recovery Facility in Newport, Minnesota. The RDF is brought onsite via truck and unloaded in 

the receiving area. From there, a single conveyor brings the fuel into the plant where it is then 

directed into either of the two traveling grate boilers. 

The French Island facility is an electric power generating station located along the 

Mississippi River in La Crosse, Wisconsin. During normal operation, the two boilers at the 

French Island plant burn a mixture of 50% RDF and 50% wood (ground treated railroad ties), 

each rated at 15 MW. The current air quality permit allows no more then 50% RDF in the 

mixture. MSW is brought onsite and processed to RDF before combusted in the boilers. Ground 

treated railroad ties are brought onsite via truck. The railroad ties are mixed with the RDF before 

being directed into either of the two boilers. 

MSW versus RDF: 

By definition, RDF and MSW are different. RDF is processed MSW that goes through various 

stages to remove all non-combustibles such as glass and metals, and larger objects such as 

mattresses and carpet. Please note that the processing facilities are not allowed to accept 

industrial solid wastes and hazardous materials with the MSW. Once sorted, the combustible 

waste is shredded and dried before shipping to the facilities as RDF. The composition of RDF is 

much more homogenous then unprocessed MSW and, as a result, emissions from combustion of 

RDF are much less variable than emissions from MSW. Therefore, it is reasonable to have 

different biogenic sampling requirements for RDF and MSW facilities. 

2010 biogenic CO2 sampling results: 

Starting January 1,2010, quarterly samples have been collected at each of the qualifying facilities 

listed above. For the benefit of this research, multiple units were sampled at each facility, even 

though the rule only requires sampling at one unit per facility because of the common fuel 

source. Sample times ranged from 1-hour to 24-hours. Beta Analytic Inc. out of Miami, Florida, 

performed the biogenic CO2 analysis per ASTM D6866-08 (Standard Test Methods for 

Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon 

Analysis). The test results are practically identical regardless of the collection duration time, and 

are all within ~: 3% of the mean average of 60% for the two facilities. The French Island 

facility’s biogenic CO2 content is slightly higher due to the fact they burn a 50/50 mixture of 

RDF and wood. Nonetheless, the results from a 24-hour sample are within 1% of the results seen 

from a 4-hour sample taken that same day on the same unit. 
166 

Facilities that combust RDF, or a combination of RDF and biomass (such as wood), should be 

exempt from the 24-hour minimum sample duration due to the fact that the fuel is processed and 

is less variable than MSW. For RDF and RDF combinations, we suggest a minimum sample 

duration of 8 hours, not only because it will still capture a representative sample, but also 

because sampling is labor intensive and requires an employee onsite for the entire data collection 

period. See DCN:EPA-HQ-OAR-2008-0508-2374 for a table displaying the Sample Duration of 

Biomass from the facilities stated above. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2374.1, Excerpt 8. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 9 

Comment: §98.34(a)(2)(ii): This proposed revision allows multiple fuel deliveries from the 

same supplier during the same month to be considered a fuel lot for the purposes of fuel 

sampling. This revision accounts for the fact that fuel properties from the same supplier do not 

significantly change over short periods of time, e.g. weekly or daily. This is especially true if the 

supplier is drawing the fuel from large storage tanks, e.g. fuel oil, to supply its many customers. 

This revision also acknowledges the fact that fuel properties do not typically change from the 

same supplier because fuel specifications contracts are often in place with the buyers that limit 

the variability of the fuel properties. Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. For additional information on EPA’s final 

amendments clarifying the definition of “fuel lot” please refer to Section II.G of the preamble. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 10 

Comment: §98.34(b)(1)(i): This proposed revision removes the restrictive list of approved fuel 

flow meter calibration methods, and allows the use of either an appropriate published flow meter 

calibration method by a consensus standard organization, calibration procedures specified by the 

flow meter manufacturer, or an industry-accepted or industry consensus standard calibration 

practice. The use of consensus standard methods, industry standards or manufacture’s 

specifications rather than an inflexible list of prescribed calibration methods afford the facility 

the alternative to select the most appropriate and accurate calibration method for their particular 

measurement device. Due to the variety of flow measurement devices, this flexibility ensures the 
167 

proper alignment between the measurement device with the appropriate calibration methodology. 

Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

. 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2400.1 

Comment Excerpt Number: 1 

Comment: EPA’s Clarifications to Tier 4 Monitoring Requirements 

ERC supports EPA’s proposal to clarify continuous emissions monitoring (CEMs) hourly 

average data validation consistent with 40 CFR 60.13. This clarification will ensure CO2

validation is consistent with required CEMs for criteria pollutants (SO2, NOx and CO) applied to 

Part 60 sources such as large MWCs. We note, however, that EPA has proposed a 

recommendation for quarterly ASTM 7459-08 sampling (“collect small amount 1-5 cc every 

hour for quarter”). In practice this recommendation would be very difficult and costly to 

implement. The proposal would require development of a separate sample collection system and 

could not be readily integrated into an existing CEM system without considerable modifications 

to both sampling components and software. Because of the significant impediments to 

implementing quarterly ASTM 7459-08 sampling, we strongly recommend that EPA delete this 

proposed recommendation. 

We do have a recommendation for refining the sampling requirement language to better facilitate 

the Agency’s recommendation that sampling be collected over a longer time period, EPA should 

revise the sampling requirement by striking out the word “consecutive” to: “... collect gas 

sample during normal operation for at least 24 consecutive hours or for as long as is deemed 

necessary to obtain a representative sample.” Eliminating the term “consecutive” would allow a 

source to spread sampling out over longer period of time consistent with EPA’s own 

recommendation. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2393.1, Excerpt 3. 

Commenter Name: Mark Strohfus 

Commenter Affiliation: Great River Energy 

Document Control Number: EPA-HQ-OAR-2008-0508-2391.1 

Comment Excerpt Number: 1 

Comment: RDF is a very homogenous fuel because of the level of mixing that occurs during its 

processing. The MSW is dumped from curbside collection trucks onto the receiving floor. A 
168 

front-end loader moves the trash around the floor into various working piles, which are later 

loaded into open feed troughs. Grapple crane operators watch the trash moving through the feed 

troughs and extract any larger materials such as furniture and carpeting that can upset the 

downstream processing operations. The acceptable trash then proceeds to multiple screening and 

shredding operations to remove ferrous metals, aluminum, sand, grit and glass. The final RDF 

product is a well mixed composite of materials that are approximately 2 inches by 6 inches in 

size or smaller. The RDF is then trucked to Elk River Station, where it is once again dumped 

onto a receiving floor, pushed into a large feeder pile, and eventually loaded onto a walking floor 

feeder trough. Because of the significant mixing and processing done in the RDF production 

process, the RDF burned at 2:00 am is very similar in biogenic content as the fuel burned at 2:00 

pm. 

Collecting a sample over 24 hours is unnecessarily burdensome. Sampling for more than 8 hours 

requires one shift operator to transfer the sampling duties along with all the other daily duties to 

the next shift operator. Overnight shifts are staffed at lower levels making the additional duties 

more burdensome. Furthermore, professional staff can help with sampling duties during daytime 

shifts in the event that the operators need to tend to duties elsewhere in the plant. 

During the most recent biogenic sampling, Great River Energy collected samples over varying 

timeframes to demonstrate that shorter sampling durations result in the same level of measured 

biogenic emission fractions. We collected, in accordance with ASTM D7459-08 sampling 

protocol: 1) a 24-hour composite sample by drawing a flue gas sample once every hour into a 

large sample bag (09/14 7:00 pm – 09/15 6:00 pm), 2) an 8-hour composite sample by drawing a 

flue gas sample once every hour (09/15 8:40 am –4:40 pm), and 3) a 1-hour continuous sample 

(09/15 2:40 pm – 3:40 pm). The flue gas samples were analyzed by Beta Analytical, Miami, FL. 

Results are summarized in the following table [see table in EPA-HQ-OAR-2008-2391.1]. 

Beta Analytical cites its ASTM-D6866 test has an absolute precision of ±3%, which means the 

results for all three sampling time frames are equal. 

Samples collected and analyzed during the first and second quarter or 2010 are also equal. The 

biogenic portion was 61 percent and 59 percent during the first and second quarter, respectively, 

suggesting that there may not even be any seasonal variability in the biogenic fraction. 

Great River Energy’s results demonstrate that collecting a flue gas sample over a 24-hour period 

is not necessary to ensure that representative data is obtained. Clearly in the case of Elk River 

Station, a one-hour sample is as representative of the fuel’s biogenic portion over a 24-hour 

sample and over the first three quarters of calendar year 2010. At a maximum, Great River 

Energy recommends the rule require quarterly sampling with no more than an 8-hour sample 

being collected for RDF-fired facilities. By limiting the sampling duration to eight hours or less, 

we can avoid the pitfalls of having to transfer sampling duties from one shift of operators to the 

next shift. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2374.1, Excerpt 8. 
169 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 10 

Comment: VII. Fuel Sampling for Coal and Fuel Oil 

As promulgated, the Tier 2 and 3 methodologies in §§ 98.34(a)(2)(ii) and (b)(3)(ii) require “for 

coal and fuel oil, analysis of at least one representative sample from each fuel lot,” which is 

defined as a shipment or delivery of a single fuel. In its Reconsideration Petition, UARG 

expressed concern that this requirement might not be satisfied by the Part 75, Appendix D 

sampling methods that rely on sampling from tanks or from fuel lines downstream of a tank 

(since those methods do not sample each lot or shipment). Although Part 75 sources are reporting 

CO2 under Part 75, other combustion units at a facility that share a fuel supply with a Part 75 unit 

could be required to perform unnecessary and duplicative sampling and analysis if the Part 75 

sampling did not satisfy Tier 2 or 3. UARG also is concerned that without further guidance 

regarding what constitutes a “fuel lot” when multiple deliveries are received of a particular fuel 

(e.g., multiple trucks or train cars), sources that are sampling deliveries may either sample too 

much or too little. 

To address these concerns, EPA proposes to revise § 98.34(a)(2)(ii) and (b)(3)(ii) to make clear 

that fuel sampling options allowed or required under Part 75 (i.e., manual oil sampling from 

storage tanks after addition of oil, daily manual sampling, flow-proportional sampling, and 

continuous drip sampling) are allowed. 75 Fed. Reg. at 48,760. EPA also proposes to revise the 

rule to provide that multiple deliveries from the same supply source in a month would be 

considered a single lot. This revision would ensure that unless a supply source changed, 

sampling would not be required more than once a month. This revision is reasonable and 

necessary to ensure consistent implementation of the rule without an excessive amount of 

sampling. 

Response: EPA thanks the commenter for the input. For additional information on EPA’s final 

amendments clarifying the definition of “fuel lot” please refer to Section II.G of the preamble. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 11 

Comment: VIII. Use of Consensus Standard Methods 

As promulgated, §§ 98.34(a)(6), (b)(4), and (b)(5) list specific consensus standards that must be 

used for fuel sampling and analysis for HHV under Tier 2, fuel flow meter calibrations under 

Tier 3, and carbon content analysis under Tier 3, respectively. In its Reconsideration Petition, 

UARG objected to the Tier 2 sampling, analysis, and reporting requirements to the extent that 

Tier 2 requires sampling and/or analysis for HHV that is different than the sampling and analysis 
170 

already performed for that fuel under Part 75, Appendix D. UARG also is concerned that 

specifying particular methods, which are required by the Office of the Federal Register to be 

identified in the rule not only by method number but also by year of authorization or revision, 

sources might become subject to different methods for the same task under different rules. For 

example, although this rule lists a number of the same ASTM methods for sampling and analysis 

as Part 75, Appendix D, the cited methods are not from the same year. While the differences 

between the versions may sometimes be small, sources may have difficulty determining whether 

an analysis performed under one version is sufficient to satisfy the other. In other cases, the 

versions may be very different. No source should be required to apply two different methods to 

obtain the same data under different rules. 

To address UARG’s concerns, and concerns expressed by others, EPA proposes to revise §§ 

98.34(a)(6), (b)(4) and (b)(5) to remove references to specific consensus standards and to instead 

allow use of any appropriate standard. 75 Fed. Reg. at 48,761. This revision is not only 

reasonable, it is necessary to ensure that sources are not subject to multiple different, but 

duplicative, methods under different rules. The revision also has the advantage of allowing 

sources to use improved methods without petitioning EPA for an exception to the rule or waiting 

for a rule revision. 

CATF objects to EPA’s removal of specific consensus standards from these provisions, arguing 

that this will lead to inconsistencies in accuracy between sources and frustrate EPA’s verification 

of emissions. EPA-HQ-OGC-2010-0575-14 at 4-5. CATF’s concerns are overblown. As 

promulgated the rule already allows use of a variety of methods. Allowing use of revised 

methods or newly developed methods does not change that fact. The alternative proposed by 

CATF -- requiring sources to perform “uncertainty assessments” for each method prior to use -- 

is not realistic. Few consensus standards provide this information and individual sources cannot 

be expected to perform the sort of research needed to develop such statistics for each method 

they use. The proposed revised rule is more than sufficient to satisfy its intended purpose, which 

is to provide Congress and EPA information to inform future legislative and regulatory decision. 

Response: EPA thanks the commenter for the input. We concur with the commenter’s response 

to CATF and have finalized the amendments noted by the commenter, as proposed. See section 

II.G of the preamble to the final rule amendments for further information. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 16 

Comment: Finally, we are somewhat concerned with the effect of EPA’s proposed amendment 

to the monitoring methods provided in section 98.33 for MSW facilities. EPA proposes to amend 

these methods by requiring facilities who combust MSW to calculate their methods using ASTM 

D-6866-08 and ASTM D7459-08 methodologies. We request that EPA in the final rulemaking 

ensure that these methodologies are as accurate as those contained currently in section 
171 

98.33(e)(3). If they are not, EPA should not adopt the proposal. In addition, EPA should once 

again take this opportunity to strengthen the provisions of this rule by requiring facilities that 

combust MSW to report the amount and type of MSW. Finally, EPA proposes to require testing 

at only one unit if MSW is the primary fuel at the facility and “the units are fed from a common 

fuel source.” We request that EPA clarify what is meant by “common fuel source” in the last 

sentence of proposed section 98.33(d). If the MSW fueling different units is fairly uniform, we 

do not see this proposal as problematic. However, if there is the potential that the constituents of 

the MSW fueling different units could vary, EPA should require testing at all units. 

Response: Part 98 has always required use of ASTM methods D7459-08 and D6866-08 for 

determining biogenic CO2 emissions from MSW combustion (see §98.34(d)). In fact, these are 

the only methods that we know of that are capable of providing this information for a partly 

biogenic fuel such as MSW. Results obtained from these methods are estimated to be accurate to 

within about 2 to 3%. EPA therefore finds no need to strengthen the provisions for calculating 

biogenic CO2 emissions from MSW combustion. 

We have not incorporated the commenter’s suggestion to define “common supply source”. 

Based on many years of experience with stationary combustion units, we do not expect to see 

significant variation in fuel composition when multiple units at the same facility combust the 

same type of fuel. 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 7 

Comment: We oppose EPA’s proposed weakening of the requirements for fuel lot sampling for 

coal and fuel oil, as proposed in the UARG settlement. See 75 Fed. Reg. at 48,760. Carbon 

dioxide emissions from coal vary based on the carbon, hydrogen, and oxygen content. These 

parameters can vary significantly among different sources of coal. By going from a 

representative sample of each shipment or delivery of a single fuel to one sample for an entire 

month’s worth of deliveries, EPA is creating a potentially significant loophole for underreporting 

or otherwise mis-calculating emissions. 

Under EPA’s final rule, a fuel lot is defined straightforwardly as “a shipment or delivery of a 

single fuel (e.g., ship load, barge load, group of trucks, oil delivery via pipeline from a tank farm, 

group of railroad cars, etc.)” 40 C.F.R. § 98.34(a)(2)(ii). The proposed revision would introduce 

an alternative definition as follows: “[i]f multiple deliveries of a particular type of fuel are 

received from the same supply source in a given calendar month, the deliveries for that month 

are considered, collectively, to comprise a fuel lot, requiring only one representative sample.” 75 

Fed. Reg. at 48,792. We generally oppose a change from the sample-per-delivery current 

definition to the proposed sample-per-month definition, due to the increased uncertainty and 

variability such a change introduces into the fuel portion of the emission calculations. However, 
172 

if EPA chooses to weaken its fuel lot provision as proposed, there are several specific problems 

with the change which EPA should address in its final rulemaking. 

First, the definition of “supply source” is not clear. EPA should specify whether a supply source 

means a particular mine/well or a fuel supply company owning several mines/wells, or has some 

other meaning. We believe that the former definition should apply. Focusing on a mine or well as 

opposed to a fuel supply company likely will reduce the range of variability in fuel parameters 

seen in a month’s worth of deliveries, such that any single sample better captures 

the fuel actually received and combusted. 

Second, and more importantly, the rule does not contain adequate provisions for determining 

whether, and ensuring that, a particular sample is representative of a month’s worth of deliveries. 

EPA should specifically delineate the standards and parameters by which the agency will gauge a 

fuel sample’s representativeness for the month. One could read the existing general 

recordkeeping requirements as extending to the fuel sample representativeness analysis. 

However, the recordkeeping provision only states that a source must retain “the data used to 

calculate the GHG emissions for each unit... [including]... (iii) The results of all required 

analyses for high heat value, carbon content, and other required fuel or feedstock parameters. (iv) 

Any facility operating data or process information used for the GHG emission calculations.” 40 

C.F.R. § 98.3(g)(2). It contains no explicit requirements for determining fuel sample 

representativeness, but reads as a catchall provision incorporating substantive requirements from 

elsewhere in the regulations. Since there are no such substantive requirements for fuel 

representativeness in the fuel lot provision, the general recordkeeping provision is inadequate to 

provide any guidance to sources and the public that would ensure consistency in analysis across 

sources. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2381, Excerpt 1. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 8 

Comment: We oppose EPA’s proposed weakening of the requirements for fuel lot sampling for 

coal and fuel oil, as proposed in the UARG settlement. See 75 Fed. Reg. at 48,760. Carbon 

dioxide emissions from coal vary based on the carbon, hydrogen, and oxygen content. These 

parameters can vary significantly among different sources of coal. By going from a 

representative sample of each shipment or delivery of a single fuel to one sample for an entire 

month’s worth of deliveries, EPA is creating a potentially significant loophole for underreporting 

or otherwise mis-calculating emissions. 

Under EPA’s final rule, a fuel lot is defined straightforwardly as “a shipment or delivery of a 

single fuel (e.g., ship load, barge load, group of trucks, oil delivery via pipeline from a tank farm, 
173 

group of railroad cars, etc.)” 40 C.F.R. § 98.34(a)(2)(ii). The proposed revision would introduce 

an alternative definition as follows: “[i]f multiple deliveries of a particular type of fuel are 

received from the same supply source in a given calendar month, the deliveries for that month 

are considered, collectively, to comprise a fuel lot, requiring only one representative sample.” 75 

Fed. Reg. at 48,792. We generally oppose a change from the sample-per-delivery current 

definition to the proposed sample-per-month definition, due to the increased uncertainty and 

variability such a change introduces into the fuel portion of the emission calculations. However, 

if EPA chooses to weaken its fuel lot provision as proposed, there are several specific problems 

with the change which EPA should address in its final rulemaking. 

First, the definition of “supply source” is not clear. EPA should specify whether a supply source 

means a particular mine/well or a fuel supply company owning several mines/wells, or has some 

other meaning. We believe that the former definition should apply. Focusing on a mine or well as 

opposed to a fuel supply company likely will reduce the range of variability in fuel parameters 

seen in a month’s worth of deliveries, such that any single sample better captures the fuel 

actually received and combusted. 

Second, and more importantly, the rule does not contain adequate provisions for determining 

whether, and ensuring that, a particular sample is representative of a month’s worth of deliveries. 

EPA should specifically delineate the standards and parameters by which the agency will gauge a 

fuel sample’s representativeness for the month. One could read the existing general 

recordkeeping requirements as extending to the fuel sample representativeness analysis. 

However, the recordkeeping provision only states that a source must retain “the data used to 

calculate the GHG emissions for each unit... [including]... (iii) The results of all required 

analyses for high heat value, carbon content, and other required fuel or feedstock parameters. (iv) 

Any facility operating data or process information used for the GHG emission calculations.” 40 

C.F.R. § 98.3(g)(2). It contains no explicit requirements for determining fuel sample 

representativeness, but reads as a catchall provision incorporating substantive requirements from 

elsewhere in the regulations. Since there are no such substantive requirements for fuel 

representativeness in the fuel lot provision, the general recordkeeping provision is inadequate to 

provide any guidance to sources and the public that would ensure consistency in analysis across 

sources. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2381, Excerpt 1. 

DATA REPORTING REQUIREMENTS 

Commenter Name: Terry Mutter 

Commenter Affiliation: Boeing Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2359.1 

Comment Excerpt Number: 1 
174 

Comment: This rule should not require small combustion units to be individually inventoried or 

counted. 

The proposed amendments to the rule provide a partial relief from data collection and reporting 

requirements of 40 CFR 98.36 (c)(1) and (c)(3). Specifically, the amendments remove the 

requirement for unique ID numbers to be assigned for each combustion unit at an affected 

source. The proposed amendment would allow sources to report only the total number of 

combustion units under an aggregated facility or pipeline. These are units without individual gas 

meters and for which generic Tier 1 emission calculations are appropriate. 

The proposed change, while an improvement, does not remove the unwarranted burden to 

identify and inventory all combustion units, regardless of size. Without relief this will force 

facility personnel to annually perform a count of every furnace, process heater, water heater and 

lab burner at a site. At large, complex manufacturing facilities such as ours, the constantly 

changing inventory of combustion equipment assures the count will be inaccurate immediately 

after the annual accounting has been performed. Small furnaces and space heaters are 

continuously moved or installed as operations are changed, devaluing the data EPA is requesting. 

The essence of the rule is to determine a facility's overall GHG output. Reporting the total 

number of all combustion units at a facility provides no additional value to the agency while 

significantly increasing the liability and burden on resources to the facility. 

We ask that EPA either remove the individual combustion unit accounting requirement in 98.36 

(c)(1) and (c)(3), or, establish a minimum threshold value to identify significant combustion 

units. A threshold value of 10 MMBTU/hr input and would be consistent with current Title V 

tracking and reporting requirements at most affected facilities. 

Response: EPA agrees that keeping an accurate count of very small combustion sources can be 

burdensome. In view of this, we have withdrawn the proposed requirement to report the number 

of units in an aggregated group. We have concluded that the most essential information for the 

group is the heat input capacity of the largest unit. Therefore, we have removed and reserved 

§§98.36 (c)(1)(ii) and (c)(1)(iii). We have also removed and reserved §98.36(c)(3)(ii) under the 

common pipe reporting option, for similar reasons. See section II.G of the preamble to the final 

rule amendments for additional information. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 36 

Comment: Change the title of §98.36 from “Data reporting requirements” to “Data reporting 

and recordkeeping requirements” to more accurately reflect the contents of the section. 
175 

Response: No rule changes have been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. We note, however that 

although §98.36 does contain some record keeping provisions, changing the section title is 

unnecessary, as it is clear which data elements in §98.36 must be reported. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 37 

Comment: §98.36(c)(3) provides options available for estimating fuel use when two or more 

combustion units share a common fuel supply line or pipe. Most of the information in this 

paragraph describes emissions calculations and would therefore be more appropriately placed in 

§98.33. It is proposed to move the majority of §98.36(c)(3) to a new §98.33(f). Since this option 

is available for units using the new Tier 1 gas billing records option, as indicated in the second 

example provided by EPA, the language requiring measurement of the fuel should be revised to 

allow the fuel use to be obtained from billing records as well. An additional change is also 

proposed to account for a situation when a single combustion unit remains after other fuel users 

on the common supply line or pipe are accounted for in accordance with other applicable 

subparts. It is also appropriate to remove the term “in units of therms” consistent with changes 

suggested elsewhere in these comments. Suggested changes are as follows: 

Keep the last sentence of §98.36(c)(3) with changes necessitated by moving most of the 

paragraph to new §98.33(f). 

a. 

§98.36(c)(3) When the common pipe calculation methodology described in §98.33(f) is 

usedreporting option is selected, the following information shall be reported instead of the 

information in paragraph (b) of this section: 

Move majority of §98.36(c)(3) to new §98.33(f) with changes shown below. 

98.33(f) Common pipe configurations. 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 served by the common supply line, in lieu of separately reporting the GHG emissions from 

the individual 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, or, for natural gas, the 

amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the 

flow meter shall be calibrated in accordance with §98.34(b). If a portion of the fuel measured, or 

obtained from gas billing records, at the common pipe is diverted to either: A flare, or another 

stationary fuel combustion unit (or units), including units that use a CO2 mass emissions 

calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used 

as a raw material but not combusted), and the remainder of the fuel is distributed to a group of 

combustion unit (or units) for which you elect to use the common pipe reporting option, you may 
176 

use company records to subtract out the diverted portion of the fuel from the fuel measured or 

obtained from gas billing records at the main supply line prior to performing the GHG emissions 

calculations for the group of unit(s) using the common pipe option. If the diverted portion of the 

fuel is combusted, the GHG emissions from the diverted portion shall be accounted for in 

accordance with the applicable provisions of this part. When the common pipe option is selected, 

the applicable tier shall be used based on the maximum rated heat input capacity of the largest 

unit served by the common pipe configuration, except where the applicable tier is based on 

criteria other than unit size. For example, if the maximum rated heat input capacity of the largest 

unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported through the 

common pipe is natural gas or distillate oil, in which case Tier 2 may be used, in accordance with 

§98.33(b)(2)(ii). As a second example, in accordance with §98.33(b)(1)(v), Tier 1 may be used 

regardless of unit size when natural gas is transported through the common pipe, if the annual 

fuel consumption is obtained from gas billing records in units of therms. 

Response: We do not agree that the commenter’s suggested reorganization of §§98.33 and 98.36 

is necessary. The common pipe option is not an alternative calculation method---it uses Tier 1, 

2, or 3. Rather, it is an alternative reporting option, i.e., an alternative to single-unit reporting 

under §98.36(b). However, we have incorporated the commenter’s suggestion to modify 

§98.36(c)(3) by including references to the use of gas billing records, when a portion of the fuel 

measured at the common pipe is diverted to a flare or combustion unit. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2374.1 

Comment Excerpt Number: 6 

Comment: Under the proposed rule, large units (boilers and combustion turbines) and small 

onsite combustion sources such as space heaters and hot water heaters can attribute all emissions 

to the large unit provided that: 1) The total fuel supply is measured either at the "gate" or at a 

point inside the facility using a fuel flow, billing meter, or tank drop measurement; 2) At least 95 

percent (by mass or volume) of shared fuel is combusted in the large unit; and 3) The Monitoring 

Plan lists the units that share the common fuel supply. For the small onsite combustion sources, a 

description and the approximate number of small sources is sufficient. Xcel Energy supports this 

revision because it clarifies how EPA expects facilities to report emissions from comfort heat, 

given that these sources most often use a common fuel supply line. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 
177 

Comment Excerpt Number: 11 

Comment: §98.36(c)(3): This proposed revision modifies the requirements associated with the 

common pipe reporting alternative. It allows a portion of the fuel measured at the main supply 

line that is diverted to a combustion unit covered under a different subpart to be subtracted out 

from the main flow, as long as the combustion emissions from the diverted fuel are accounted for 

in accordance with that subpart. Therefore, a facility may use company records to subtract out 

the diverted portion of fuel from that measured at the main supply line. This revision provides a 

straightforward and accurate alternative to account for fuel usage, and still comply with the 

applicable subpart requirements for each combustion unit. Weyerhaeuser supports this revision. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 8 

Comment: Reporting requirements in 98.36(c)(1) - requirement to report the number of units in 

the group if using the aggregation method: 

Current language, including changes proposed by the EPA: 

“The number of units in the group.” 

Proposed language with the requested changes in square brackets: 

“The number of units in the group [or listing of units in the group. When small sources not 

related to the reporter primary business, such as space heaters, hot water heaters, and small 

process heaters are reported in addition to large combustion units, such as engines or large 

process heaters, they can be reported as a single domestic type source as long as emissions from 

these small sources are included in the total emissions.]” 

The objective of the proposed change was to simplify the reporting requirements. However, 

many reporters, including El Paso, have already developed their reporting systems based on the 

originally promulgated regulation. Therefore, El Paso is requesting flexibility in reporting either 

the number of units in the group or listing each unit in the group. The best option would be to list 

all domestic type units as one source and provide the best available estimate of their combined 

heat input capacities. This reporting option will also be more representative of the facility and the 

domestic sources can be easily separated from the industrial sources as needed during 

verification. 
178 

For example, a compressor station operating five (5) natural gas fired compressor engines with a 

heat input capacity of 12 mmBtu/hr, ten (10) space heaters rated at 0.2 mmBtu/hr, and two (2) 

water heaters rated at 0.03 mmBtu/hr would report 17 emission units if the changes proposed by 

the EPA were implemented. However, only six (6) units would be reported if El Paso’s proposed 

language was considered, i.e. the space heaters, hot water heaters, and small process heaters 

would be counted as one domestic type source rated at 2.06 mmBtu/hr. Reporting six (6) units is 

more representative because only five (5) units at the facility will be attributable to the majority 

of emissions. Typically, only when the domestic type sources are aggregated, their combined 

heat input capacity is in a range comparable to the heat input capacity of a process type emission 

unit. In addition, process type emission sources are well documented; the number of space 

heaters, water heaters and small process heaters might be estimated by the reporter. The overall 

accuracy of the report will decrease if well documented and estimated sources are reported as 

one number. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2359.1, Excerpt 1. 

Commenter Name: Fiji George 

Commenter Affiliation: El Paso Corporation 

Document Control Number: EPA-HQ-OAR-2008-0508-2390.1 

Comment Excerpt Number: 9 

Comment: El Paso proposes to allow reporters to combine the aggregation and common pipe 

methods. Under this approach, a reporter could aggregate units fueled by two or more common 

pipes for one or more units, provided that each of the emission units has a maximum heat input 

capacity of 250 mmBtu/hr or less. Fuel consumption under the hybrid approach will be 

established based on metered volumes for each common pipe. 

Response: EPA disagrees with the commenter. Although both options are intended to allow 

facilities to report multiple units under one reporting methodology, the two options have 

distinctions that must be retained. The “aggregation of units” option is intended only to apply for 

units smaller than 250 mmBtu/hr and it allows units that burn multiple fuel types to be 

aggregated. The common pipe reporting option allows for emissions reporting from units larger 

than 250 mmBtu/hr, but it requires the common pipe to supply only one fuel type and the fuel 

must be measured at a common supply point. The common pipe reporting option applies only to 

liquid and gaseous fuels being supplied through a pipe. The aggregate reporting option is 

available for any fuel type. Referring to the commenter’s example, since the units are all 250 

mmBtu/hr or less, the aggregated group reporting option in §98.36(c)(1) may be used. Provided 

that the quantity of each fuel supplied to the group is known, it makes no difference that the fuels 

are supplied to the group through two separate common pipes. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 
179 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 11 

Comment: EPA Should Allow Sources to Use Available Information When Using Provision to 

Aggregate Very Small Combustion Units. 

The present rule in § 98.36(c)(I) requires sources that use the Aggregation Provision for small 

combustion units to provide the highest maximum rated heat input within the group and 

cumulative heat input of all units being aggregated. However, affected facilities can have 

numerous small combustion units, such as space heaters, water heaters and other furnaces, that 

are very old and their actual rated heat input capacity can not be determined. Therefore, we 

request EPA include a provision for these small units under the Aggregation of Units provision 

in § 98.36(c)(1) to use the actual cumulative heat input for such small older units. In addition, 

since it is impossible determine the highest maximum rated heat input for a unit within this group 

of old units, EPA must allow the use of actual cumulative heat input for this group. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2359.1, Excerpt 1. 

Commenter Name: Lauren E. Freeman 

Commenter Affiliation: Utility Air Regulatory Group (UARG) 

Document Control Number: EPA-HQ-OAR-2008-0508-2388.1 

Comment Excerpt Number: 12 

Comment: IX. Alternative Reporting Option for Facilities with Large and Small Combustion 

Units That Share A Common Liquid or Gaseous Fuel Supply 

In its Reconsideration Petition, UARG expressed a number of concerns regarding application of 

Subpart C requirements for general stationary combustion units to small combustion units or 

activities that share a fuel supply with a Part 75 unit. Although EPA has proposed a number of 

revisions designed to eliminate some of the unnecessary burdens for such small units and 

activities, none of those provisions addressed the practice under Part 75 of measuring fuel use at 

one location (e.g., one tank or one meter at the fence line) and disregarding small fuel diversions 

when calculating and reporting emissions from larger combustion sources. 

For example, some facilities with large units that combust oil or gas may use a small unmeasured 

portion of the fuel delivered to the facility for other uses and simply report emissions under other 

programs (like Part 75) as if all of the fuel delivered was combusted by the large combustion 

unit. This might occur when the amount of fuel diverted is so small compared to the amount 

combusted by the large unit that the overestimate in reported emissions is insignificant relative to 

other sources of error in the measurements. Because the rule currently provides no exception to 

the reporting requirements for Subpart D units for diversion of fuel to Subpart C units, if this 

practice were continued following promulgation of this rule, the rule would require sources to 

either ensure systems were in place to determine the amount of fuel diverted, or double count the 

emissions from the small combustion units by reporting the emissions under Subpart C as well. 
180 

To address this scenario, EPA proposes to revise § 98.36(c)(4) to allow simplified reporting for 

units with a common fuel supply where emissions from fuel supplied to small combustion 

sources is already reported (or can be reported) along with emissions from large combustion 

sources. 75 Fed. Reg. at 48,763. To ensure that the option is not applied to avoid separate 

reporting of emissions from large units, the option is limited to those circumstances where the 

source demonstrates using company records that at least 95 percent of the shared fuel supply is 

combusted in the large unit. The total quantity of the shared fuel supply also must be measured 

using a fuel flow meter, billing meter, or tank drop method. UARG appreciates the addition of 

this option, which is necessary to accommodate existing Part 75 reporting practices without 

requiring installation of new fuel measurement equipment. The option also will be useful to other 

facilities to avoid unnecessary fuel measurements without any sacrifice in data quality. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 25 

Comment: API supports the revision of §98.36(b)(10) – Removed the requirement to report the 

customer meter number for units that combust natural gas. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 26 

Comment: API supports the revision of §98.36(c)(1)(ii), (c)(2)(ii), and (c)(3)(ii) - Removed the 

requirement to report an identification number for each unit in the grouping of units, sharing the 

common stack or duct, or served by the common pipe. Instead, EPA proposes facilities report the 

number of units in the group. 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2359.1, excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
181 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 28 

Comment: API supports the revision of §98.36(c)(3) – If a portion of the fuel measured at the 

main supply line is diverted to either a flare or another stationary combustion unit, company 

records may be used to subtract out the diverted portion of the fuel. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 29 

Comment: API supports the revision of §98.36(c)(4) – New provision where liquid or gas fuel is 

shared between one of more large combustion units and small combustion units. Reporting may 

be simplified by attributing all of the shared fuel to the large combustion unit(s) provided (i) the 

total fuel quantity is measured (ii) 95% of the fuel is combusted in the large unit(s) (company 

records may be used to determine the percentage), and (iii) the use of this approach is 

documented in the Monitoring Plan. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 30 

Comment: API supports the revision of §98.36(e)(2)(ii)(C) – Removed the requirement to report 

the date each fuel sample was taken for Tier 2. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 31 

Comment: API supports the revision of §98.36(e)(2)(iii) – EPA proposes to revise the Tier 2 

recordkeeping provision requiring records be maintained of the date of each fuel sample to 
182 

include an exception for cases where the sampling data is provided by the fuel supplier. In such 

cases, the reporters would be required to maintain a record of the date on which the analytic 

results were received. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

TABLE C-1 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 10 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 10 

These two commenters submitted identical comments on this subject. 

Comment: We are somewhat concerned that EPA proposes to redefine MSW and tires as “Other 

Fuels (Solid),” rather than as “Fossil-Fuel Derived Fuels.” See 75 Fed. Reg. at 48,674. Although 

this change appears to be entirely cosmetic, we still request that EPA carefully determine 

whether this definitional change would have any substantive impacts on MSW or tire burning 

facilities. 

Response: The intent of changing the table grouping from “Fossil fuel-derived (solid)” to 

“Other fuels (solid)” was to recognize that there is a biogenic portion to both MSW and tires and 

these fuels are not entirely fossil-derived. The previous group listing seemed to indicate that 

there was no biogenic component in these fuels. The classification in Table C-1 was also 

inconsistent with the rule text because methods were provided in §98.34(d) to calculate biogenic 

CO2 emissions from MSW. Other than clarifying that MSW and tires are not entirely fossilderived, there is no impact from this change---it has no effect on how emissions from the 

combustion of MSW or tires are calculated and reported. There will be no loss of coverage as a 

result of this change. Please see section II.F of the proposal preamble (75 FR 48754). 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 2 
183 

Comment: WM supports the proposed categorization of MSW and Tires in Table C-1 as “other 

fuels (solid)” as a needed clarification. EPA correctly notes that MSW and tires are not 

appropriately termed “fossil fuel-derived fuels” because both have a biogenic component. In fact, 

a significant majority of MSW material produced in the U.S. is of biogenic origin – fully 65 

percent on average. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 3 

Comment: We do, however, question the appropriateness of listing MSW with plastics and 

petroleum coke. Petroleum coke is listed twice in the table, first under petroleum products and 

then again under “other fuels (solid).” As a petroleum derivative, petroleum coke is more 

appropriately listed with the other “petroleum products.” 

Response: See Section II.G of the preamble to the final rule amendments for the response to this 

comment. 

Commenter Name: Kerry Kelly 

Commenter Affiliation: Waste Management (WM) 

Document Control Number: EPA-HQ-OAR-2008-0508-2360.1 

Comment Excerpt Number: 4 

Comment: Further, EPA has called out plastics as a fuel for the first time in the GHG MRR. 

Plastics are a small component of MSW – according to EPA plastics comprise only 12 percent of 

MSW in the U.S. There is no discussion of why EPA now feels the need for the first time to 

highlight plastics as a separate fuel stream, and we recommend that the listing be deleted as it 

serves no useful purpose. We are unaware of segregated plastics being commonly used as a fuel 

stream by stationary combustors. 

Response: Note that another commenter has stated that plastics are sometimes recovered from 

MSW and burned separately (see the response to EPA-HQ-OAR-2008-0508-2401.1, Excerpt 1). 

Commenter Name: John H. Skinner 

Commenter Affiliation: Solid Waste Association of North America (SWANA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2397.1 

Comment Excerpt Number: 2 
184 

Comment: The Solid Waste Association of North America (SWANA) agrees with EPA’s 

decision to re-classify municipal solid waste and tires as “other fuels” in table C-1 of Subpart C. 

The classification of them as fossil fuel derived ignores the fact that the majority of emissions 

from the combustion of these sources are biogenic in nature. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Ted Michaels 

Commenter Affiliation: Energy Recovery Council (ERC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2393.1 

Comment Excerpt Number: 2 

Comment: The proposed corrections to Table C-1 fuel categories provide appropriate and 

necessary clarification. The Energy Recovery Council (ERC) supports the proposed 

categorization of MSW and Tires in Table C-1 as “other fuels (solid)” as a needed clarification. 

EPA correctly notes that MSW and tires are not appropriately termed “fossil fuel-derived fuels” 

because both have a biogenic component. In fact, a significant majority of MSW material 

produced in the U.S. is of biogenic origin, fully 65 percent on average. We may suggest however 

that consistent with other proposed clarifying language in 40 CFR 98 (See 98.34(e)), it would be 

more appropriate to include tires and MSW in Table C-1 under the category “heterogeneous 

fuels (solid)”. 

We do question the appropriateness of listing MSW with plastics and petroleum coke which have 

no biogenic component since both are derived exclusively from fossil fuels. Petroleum coke is 

listed twice in the table, first under petroleum products and then again under “other fuels 

(solid).” As a petroleum derivative, petroleum coke is more appropriately listed with the other 

“petroleum products.” Plastics are a small component of MSW – according to EPA, plastics 

comprise only 12 percent of MSW in the U.S. There was no discussion of why EPA feels the 

need to include plastics now as a separate fuel stream, and we recommend that the listing be 

deleted consistent with the final rule, as it serves no useful purpose. We are unaware of 

segregated plastics being commonly used as a fuel stream by stationary combustors. 

Response: See Section II.G of the preamble to the final rule amendments for the response to this 

comment. 

Commenter Name: Walter Tyler 

Commenter Affiliation: INVISTA 

Document Control Number: EPA-HQ-OAR-2008-0508-2372.1 

Comment Excerpt Number: 3 
185 

Comment: The inclusion of “Fuel Gas” emission factors on Table C-1 was clearly established 

for the convenience of Subpart X and Subpart Y facilities, however, Footnote 2 associated with 

the emission Fuel Gas factors could be interpreted to require facilities not subject to Subpart X or 

Subpart Y to monitor and report GHG emissions from process waste off-gas streams. 

Consistent with the comments above on the definition of fuel, INVISTA recommends that 

footnote 2 to Table C-1 be rewritten as follows to clarify the applicability of the Fuel Gas 

emission factors: 

“Reporters subject to subpart X of this part that are complying with § 98.243(d) or subpart Y of 

this part may only use the default HHV and the default CO2 emission factor for fuel gas 

combustion under the conditions prescribed in § 98.243(d)(2)(i) and (d)(2)(ii) and § 98.252(a)(1) 

and (a)(2), respectively. Otherwise, reporters subject to subpart X or subpart Y shall use either 

Tier 3 (Equation C–5) or Tier 4. 

Response: We agree with the commenter. In the final rule, footnote 2 below Table C-1 has been 

modified, as requested. 

Commenter Name: David A. Buff 

Commenter Affiliation: Golder Associates Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2395.1 

Comment Excerpt Number: 3 

Comment: Table C-1 contains default high heating values (HHV) for various types of fuels. For 

“Biomass Fuels – solid”, the default value in the table is 8.25 mmBtu/short ton. It is presumed 

that this value is for short tons as received, as opposed to short tons on a dry basis. However, due 

to the large difference between HHV of wet vs. dry biomass fuels, this should be clearly stated in 

the table. Even with this clarification, the HHV of solid biomass fuels may vary greatly. For 

example, sugarcane bagasse is typically 3,600 – 4,200 Btu/lb, wet basis (approx. 50-55% 

moisture as received) (7.2 to 8.4 mmBtu/short ton). However, rice hulls or peanut shells may in 

fact have a much higher heating value since these materials are relatively dry. To more 

accurately reflect actual heating values for a particular type of biomass (and more accurately 

report GHG emissions), the rule should allow published data, best available data, industry 

standards, etc., to be used in lieu of the default values. The HHV and the justification/rationale 

for the values can be required to be incorporated into the GHG monitoring plan. 

Response: The purpose of Table C-1 is to provide default HHV and emission factor values that 

can be used by reporters, where appropriate, and therefore simplify emissions reporting. The 

default value of 8.25 mmBtu/short ton is on a dry-basis. We recognize that not all biomass fuels 

will be combusted on a dry-basis, however for the purposes of a default value we have concluded 

that this value is sufficient to represent the potential range of HHVs of the fuels, as combusted. 

We do not agree that it is necessary to allow published data, best available data, industry 

standards, etc. to be used in the emissions calculations for HHVs of biomass fuels- solid. If the 

commenter wants a more refined HHV than what is strictly required by the reporting rule, they 
186 

may use a Tier 2 or Tier 3 methodology, and therefore a site-specific HHV, instead of the Tier 1 

methodology for calculating emissions from biomass. 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 5 

Comment: The proposed addition of the term “fuel gas” to Table C-1 with no modification to 

the current "fuel gas" definition results in additional impacts that EPA should clarify in the final 

rule. ACC understands “still gas” was removed from Table C-1 and “fuel gas” was added to 

Table C-1 as part of a settlement agreement to address concerns with a provision specific to 

petroleum refineries in Subpart Y that requires refineries to calculate CO2 emissions from the 

combustion of refinery fuel gas using either Tier 3 or Tier 4 methodology. “Fuel gas,” as defined 

in subpart A, “means gas generated at a petroleum refinery, petrochemical plant, or similar 

industrial process unit, and that is combusted separately or in any combustion with any type of 

gas.” 

Due the definition of fuel gas, the addition of “fuel gas” to Table C-1 affects 

petrochemical plants in addition to petroleum refineries, and could be interpreted to include 

process off-gas derived from processes that are not subject to Subpart X or Y. The proposed 

revision to add “fuel gas” to Table C-1 will result in numerous “fuel gas” streams at 

petrochemical plants and possibly others now being subject to the MRR requirements. ACC 

recommends that EPA: revise the entry in Table C-1 to “refinery fuel gas” instead of “fuel gas” 

and modify the definition of "fuel gas" in 98.6 to stipulate this refers to "refinery fuel gas" only; 

and, (2) clarify the calculation and reporting of emissions from “fuel gas” streams is not required 

until the 2011 reporting year, with the annual report due by March 31, 2012, since “fuel gas” was 

added to Table C-1 during the 2010 reporting year and thus reporters could not comply with the 

requirement as of January 1, 2010. 

Response: Please see response to comment EPA-HQ-OAR-OAP-2008-0508-2366.1, excerpt 4. 

Commenter Name: Bryan Brendle 

Commenter Affiliation: Portland Cement Association 

Document Control Number: EPA-HQ-OAR-2008-0508-2399.1 

Comment Excerpt Number: 4 

Comment: EPA also proposes to broaden the proposed categories for various fossil-fuel derived 

fuels. More specifically, EPA is proposing some changes to Table C-1 to expand the meaning of 

“solid and gaseous fossil fuel derived fuels” to include plastics, municipal solid waste, tires and 

petroleum coke for solids, and blast furnace gas, coke oven gas, propane gas, and fuel gas for 

gaseous fuels." PCA believes these changes add flexibility. 
187 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 14 

Comment: First, as we stated in comments on the proposed settlement agreement, we are 

concerned with EPA’s proposal to redefine MSW and tires as “Other fuels (solid)”. EPA states 

that “overall we do not believe that the changes between the proposed and final Part 98, nor the 

amendments [described in this proposed rulemaking], have a substantive impact on the 

calculation requirements or the reporting of emissions for MSW or tires under this rule.” While it 

may be the case that this change is entirely cosmetic, we nonetheless continue to request that 

EPA determine “whether this definitional change would have any substantive impacts on MSW 

or tire burning facilities.” 

Response: Please see response to comment EPA-HQ-OAR-2008-0508-2403.2, excerpt 10 for 

the response to this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 15 

Comment: For refinery applications, API supports the replacement of the emission factor and 

higher heating values listed for “still gas” in Subpart C, Table C-1. However, for the purposes of 

reporting under Subpart X, adding a default factor for “fuel gas” versus “refinery fuel gas” could 

have a negative impact on chemical plant fuel gas streams that were previously exempt from Tier 

3 requirements (e.g., the streams provide < 10% of the annual heat input to a unit rated > 250 

MMBtu/hr) because previously there was no fuel gas factor in the Table C-1. 

Without the addition of “refinery” to the “fuel gas” information in Table C-1, a timing 

compliance issue results. Petrochemical gas stream that were previously exempt from reporting 

must now be metered and sampled weekly to comply with the Tier 3 requirements. In such cases, 

installation of new meters may be required. There is no retroactive BAMM period until such 

meters are installed. As a result, complying with the sampling, calibration, and reporting 

requirements for Tier 3 is not feasible given that most of 2010 is past. 

API requests that EPA change the label in Table C-1 to “refinery fuel gas”. 

Response: Please see response to comment EPA-HQ-OAR-OAP-2008-0508-2366.1, excerpt 4 
188 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 17 

Comment: API supports the August 11, 2010 proposed revision to the natural gas entry in Table 

C-1 that removes the word “pipeline”, which allows reporters to use the Tier 1 or Tier 2 CO2

emissions calculation methodology for either field quality or pipeline quality natural gas. 

However, EPA’s proposed change to the definition of natural gas negate the revision to Table C1. 

Response: In the final rule we have withdrawn the proposed HHV and methane content 

specifications in the definition of natural gas. See Section II.G of the Preamble for further 

discussion. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 19 

Comment: First, EPA requests comment on “new and revised fuel categories” in Table C-1. 75 

Fed. Reg. at 48,764. We recommend that EPA add an additional category of “waste coal”, 

including gob and boney (bituminous waste) and culm (anthracite waste) left behind by coal 

mining. These fuels are in common use in circulating fluidized bed boilers (CFBs) and should be 

accounted for in the reporting rule. 

CFBs are able to burn a wider range of fuels than most other coal-fired boilers. This has made 

them particularly attractive as “waste coal” burners, as they can be used to burn the gob, boney, 

and culm left behind by coal mining. Waste coal-fired CFBs comprise a significant category of 

boilers. Reliant Energy’s Seward station, for instance, has two 260 MW units and is designed to 

burn almost exclusively coal waste. One comprehensive reference reports that “[w]ith the advent 

of CFB technology and its application to this fuel, there has been a significant increase in the use 

of anthracite culm and bituminous gob within the USA,” charting an increase from just 1.3-1.4 

million tons used in 1989 to 8.9-9.3 million tons burned in 2001.47 This increase is attributable, 

almost entirely, to CFBs. 

Indeed, according to EPA, there are currently 18 plants burning waste coal as a primary fuel, and 

13 plants using waste coal as a secondary fuel. EPA records 17 additional plants that have been 

proposed and are in some phase of project development. According to EPA, every one of these 

plants uses CFB technology. 

The upshot is that, as these waste coal burners operate and come online, it becomes increasingly 

important both to understand any unique factors associated with using waste coal as a fuel. We 
189 

urge EPA to develop emissions factors for this fuel, taking into account its carbon dioxide, 

methane, and nitrous oxide emissions. 

Response: No rule change has been made as a result of this comment at this time. EPA agrees 

with the commenter that the HHV and other characteristics of waste coal such as culm and gob 

are distinctly different from those of anthracite and bituminous coal. However, we have 

concluded that it is not necessary to provide default HHVs and CO2 emission factors for these 

fuels in Table C-1 because the units that burn these fuels (including the Seward station 

mentioned by the commenter) are located principally in the Northeastern United States and are 

equipped with the CEMS that are needed to measure CO2 mass emissions. Therefore, most, if 

not all of them, are in the Acid Rain Program, and are subject to Subpart D of Part 98. If 

additional information is made available in the future to indicate that others combust this fuel in 

relevant quantities, we will reconsider whether this fuel should be added to Table C-1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 54 

Comment: Corrections to Tables C-1 and C-2: 

a. Given that reporting under the MRR begins January 2010, the fuel factors used in the most 

recent EPA national inventory would be more appropriate than values cited three years ago. 

b. The heating values cited in the MRR for residual fuel #5 and ethane are notably different from 

values cited in the 2009 API Compendium (7% for residual fuel #5 and 37% for ethane). For 

ethane, the value cited in the MRR appears to be a mistype; 0.096 MMBtu/gal, where the TSD 

indicates 0.069 MMBtu/gal (the Compendium value is 0.070 MMBtu/gal). For residual fuel oil 

#5, the TSD showed 0.150 MMBtu/gal, where the value in the final rule is 0.140 MMBtu/gal 

(the Compendium value is 0.150 MMBtu/gal). 

c. The EPA MRR emission factors for municipal solid waste appear to have an error in the units. 

d. The natural gas factors shown in the MRR appear to have applied the liquid or solid fuel 

conversion from LHV to HHV, rather than the gas fuel conversion. Similarly, for the N2O 

emission factor for coke oven gas. 

e. There appears to be round-off differences or errors in adjusting from LHV to HHV for 

groupings of emission factors (most of the liquid fuel and solid fuel factors). 

f. The CH4 emission factor for coke oven gas shown in the MRR is approximately one-half the 

value reported by IPCC and cited in the Compendium. 
190 

g. The MRR emission factors differ from the IPCC factors for LPG and ethane. Where IPCC 

aligns the emission factors for these sources with other gaseous fuels, the MRR applies emission 

factors used for other liquid fuels. 

h. Other notable differences were observed in comparing the MRR emission factors for peat, 

biodiesel, and biogas to the API Compendium. However, the reason for the difference is not 

clear without knowing the source of the MRR values. 

i. EPA should provide an explanation for the change from factors cited in the TSD and should 

also provide a citation for the factors. 

Response: We thank the commenter for the input. Several of the specific comments above are 

outside the scope of the proposed amendments and no rule change has been made as a result of 

those comments. The proposed rule solicited comment on amendments to specific fuel types and 

categories listed in Table C-1, and specifically requested comment on the (1) the new and revised 

fuel categories; (2) the appropriateness of the HHVs and CO2 emission factors for the fuels listed 

in these categories; and (3) whether additional fuels should be included in Table C-1, and if so, 

what the HHVs and CO2 emission factors for those fuels should be. We address the in-scope 

comments below. 

In developing the rule in 2008, EPA relied on the latest statistical information on national fuel 

consumption and characteristics available, as published in EIA’s Annual Energy Review. 

Subsequently, EIA updated heat content values, and the changes in factors from the TSD are due 

to those changes. The citation for the changes is based on data in the EIA Annual Energy 

Review 2008 (publication DOE EIA-0384(2008)). 

We did not propose changes to residual fuel #5 and #6 and therefore have not made any changes 

to these HHVs or default emission factors in the final review. We did review the concern about 

ethane and identified a trascription error in the final rule that we have corrected. The TSD was 

correct and the ethane emission factor should be 0.069 mmBtu/gal, close to the value in the API 

Compendium. 

The emission factor of 90.7 kgCO2/mmBtu is consistent with the California Air Resources Board 

(ARB) rulemaking for mandatory reporting of greenhouse gas emissions, as approved and 

adopted by the State of California on December 2, 2008 for reporting beginning on January 1, 

2009 (see: http://www.arb.ca.gov/regact/2007/ghg2007/ghg2007.htm). 

The natural gas factors were taken from the Energy Information Administration Annual Energy 

Review, Table A-4, where EIA reports the high heating value. The emission factors are derived 

from the latest official Inventory of U.S. GHG Emissions and Sinks, based on its examination of 

the carbon contents and composition of the average pipeline quality natural gas in the United 

States, as described in Annex 2.2 of the Inventory report. The HHV data come from EIA, so it is 

not clear what the commenter means by EIA used the wrong LHV to HHV conversion. 
191 

Regarding the methane emission factor for coke oven gas (COG), we agree that the value is 

different from the one presented by the Intergovernmental Panel on Climate Change and the API 

Compendium. We tried to tailor it more to the circumstances in the iron and steel industry. To 

do this, we started with default high heat values from Gannon, H.E. (editor) The Making, 

Shaping and Treating of Steel, Tenth Edition (1985), Page 131. The calculation is presented 

below. 

For Coke oven gas (using 28% CH4 from reference above): 

( )( )

x kg CH mmBtu

x mmBtu scf COG

kg CH scf CH scf CH scf COG 4.8 10 /

5.99 10 /

1.03 x 10 / 0.28 /

4

4

4

4 4 4

-6

−

−

=

The API observation regarding LPG and ethane is correct. We understood that as the fuels leave 

the refinery gate they are under pressure and hence are in the liquid state. Therefore we revised 

the density and carbon content to reflect the LPG components as liquid rather than gas. Please 

see the discussion from the MRR definitions document at: 

http://www.epa.gov/climatechange/emissions/downloads09/documents/SubpartMMProductDefin

itions.pd. f 

We have not proposed changes to the emission factors for peat and biogas, therefore these 

comments are out of scope of this rulemaking and no change has been made as a result of this 

comments. The high heating value for biodiesel of 0.128 mmBtu/gal was taken from the EIA 

Annual Energy Outlook and the emission factor was converted from the value in the EPA 

Climate Leaders reference materials 

(http://www.epa.gov/climateleaders/documents/resources/mobilesource_guidance.pdf). EPA has 

chosen to use the Climate Leaders default emission factors provided in their guidance, as it was 

believed that, in conjunction with the partners to this program, these values represent a generally 

applicable default value for these variable fuel types.

As described above, we will continue to evaluate heating values and emission factors as new data 

become available. In Table C-1, EPA provided reporters with average U.S. values for fuel 

characteristics, based on national statistics collected by EIA, for use with the tier 1 and tier 2 

methodologies. Reporters, as stated in the rule, are welcome to use a higher tier, if they believe 

that use of such a higher tier method would better represent emissions from stationary 

combustion sources. 

TABLE C-2 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2350 

Comment Excerpt Number: 2 

Comment: In Table C-2, Plastics, Petroleum Coke, Propane Gas, and Fuel Gas were omitted. 
192 

Response: EPA did not propose to add default emission factors to Table C-2 for Plastics, 

Petroleum Coke, Propane Gas, and Fuel Gas. Consistent with §98.33(c), facilities are not 

required to calculate and report CH4 and N2O emissions from these fuels as they are not listed in 

Table C-2. EPA will consider adding default emission factors for these fuels in the future. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 20 

Comment: Importantly, these nitrous oxide emissions may be quite high, at least in the context 

of CFBs, which brings us to our second suggestion. EPA has long recognized that the low 

combustion temperatures associated with CFBs generates far more N2O than the higher 

temperatures in other boilers. EPA should therefore revise Table C-2 to include a distinct N2O 

emissions factor for CFBs. 

As EPA writes in its Compilation of Air Pollutant Emissions Factors (generally referred to as 

“AP-42”): 

Formation of N2O during the combustion process is governed by a complex series of reactions 

and its formation is dependent upon many factors. Formation of N2O is minimized when 

combustion temperatures are kept high (above 1575 °F) and excess air is kept to a minimum 

(less than 1 percent). N2O emissions for coal combustion are not significant except for fluidized 

bed combustion (FBC), where the emissions are typically two orders of magnitude higher than 

all other types of coal firing due to areas of low temperature combustion in the fuel bed. 

For this reason, AP-42 distinguishes CFBs from all other coal boilers. Although it sets emissions 

factors of between 0.03-0.09 lb/tons for all other boilers, it provides an emission factor of 3.5 

lb/ton for both CFBs and bubbling fluidized bed boilers. This factor works out to be about 67.3 

g/mmBtu for bituminous coal and 92.0 g/mmBtu for sub-bituminous coal. The present Table C-2 

N2O factor for all coal-fired boilers, by contrast, is set at 1.6 g/mmBtu, an order of magnitude 

different. 

This undercounting is a serious problem, particularly because N2O’s global warming potential is 

roughly three hundred times that of carbon dioxide. EPA should take this opportunity to correct 

this error. Using the existing AP-42 factors would be one fairly straightforward way to make this 

fix. 

Response: No rule change has been made as a result of this comment. On August 11, 2010, we 

did not propose changes to the N2O emission factor for coal-fired units and therefore the specific 

recommendations are outside of the scope of this rulemaking. However, we thank the 

commenter for the input. We note that the suggested emission factors provided by the 

commenter are for bituminous coal and sub-bituminous coal. No factors were provided for 
193 

waste coal (i.e., culm, gob, and boney), which is the principal fuel in many of the CFB units in 

the U.S. We intend to undertake additional research and, as appropriate, would make any future 

changes to the N2O emission factor through a rulemaking. 

OTHER SUBPART C COMMENTS 

Commenter Name: David A. Buff 

Commenter Affiliation: Golder Associates Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2395.1 

Comment Excerpt Number: 4 

Comment: In Subpart C, several references are made to “secondary fuels”. However, there is no 

definition of secondary fuels in the rule. Is a secondary fuel any fuel other than the primary fuel? 

This should be defined. 

Response: EPA has amended the requirements under 40 CFR 98.33(b)(4)(ii)(B) to remove the 

term secondary fuel, which was undefined and caused considerable confusion. 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 4 

Comment: The Subpart C applicability provisions clarify existing fuel blend requirements. 

Response: EPA thanks the commenter for the input. We have finalized the amendments noted 

by the commenter as proposed. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 3 

Comment: EPA Should Add Alternatives to the Requirements for Tier 3 Fuels that Contain Less 

than 1 wt% Carbon. 

EPA should add one or more alternatives to Subpart C of the GHG Reporting Rule for Tier 3 

Fuels that contain less than 1 wt% carbon. An example of such a fuel is a hydrogen fuel stream 

that contains trace levels of carbon compounds. Currently, sources are required to sample these 

streams on a weekly basis in order to determine the carbon content and the molecular weight. 

This activity adds very little value to the quality of the GHG emission calculation even for 
194 

combustion sources with a heat input > 250 MMBtuIHr. Therefore, the following alternatives 

should be considered in the reporting rule: 

1. The rule should allow the use of a default value for the carbon content (CC) up to 0.01 and for 

the use of engineering calculations to determine the molecular weight of the stream (MW). These 

values can be determined based on previous test results or other readily available information. 

2. The rule could also allow the use of the Tier 1 emission calculation approach using the 

proposed emission factors for Fuel Gas in Table C- I. 

Option #1 would result in more accurate GHG emission calculations, but both options would 

streamline the data collection requirements for Tier 3 fuels with very low carbon contents. 

Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the amendments proposed for public 

comment in the Federal Register notice of August 11, 2010. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 21 

Comment: API supports the revision of §98.30(d) – You are not required to report GHG 

emissions from pilot lights (defined as small, permanent auxiliary flame that ignites the burner of 

a combustion device when the control valve opens). 

Response: EPA thanks the commenter for the input. Note that in the final rule, we removed the 

word “permanent” from the definition of “pilot light”. 

4. SUBPART D - ELECTRICITY GENERATION 

Commenter Name: Brady W. Wassom 

Commenter Affiliation: Environmental Systems Corporation (ESC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2367.1 

Comment Excerpt Number: 1 

Comment: Environmental Systems Corporation (ESC) supports the revision to the Mandatory 

Reporting Rule allowing the use of records retained under 40 CFR 75.57(h) for missing data 

events to satisfy the recordkeeping requirements of §98.3(g)(4) for those same events. This 

revision will reduce the recordkeeping burden on our customers and eliminate duplicate 

recordkeeping procedures. 
195 

Response: EPA thanks the commenter for the input. We have finalized the amendments, as 

proposed. 

5. SUBPART F - ALUMINUM PRODUCTION 

Other Subpart F Comments 

Commenter Name: Robert P. Strieter 

Commenter Affiliation: The Aluminum Association, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2362.1 

Comment Excerpt Number: 1 

Comment: The Aluminum Association supports all of the proposed technical corrections 

included for Subpart F applicable to primary aluminum production. EPA has effectively 

addressed all of the technical concerns with reporting GHG emissions from primary 

aluminum production under the final rule published in October 2009. 

We appreciate the efforts of the EPA technical staff in satisfactorily addressing 

the reporting, calculation, monitoring and data estimation issues for primary aluminum 

that we outlined in the final rule. 

Response: EPA thanks the commenter for the input. We have finalized the amendments, as 

proposed. 

6. SUBPART G - AMMONIA MANUFACTURING 

Purge Gas/Recycle Stream 

Commenter Name: Tom Siegrist 

Commenter Affiliation: Koch Nitrogen Company LLC (KNC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2364.1 

Comment Excerpt Number: 2 

Comment: EPA has correctly concluded that reporting of emissions associated with the waste 

recycle or purge stream, under the Ammonia Manufacturing subcategory, is not needed in order 

to accurately characterize emissions from this subcategory. (75 FR 48766) 

EPA has proposed to eliminate the calculation, monitoring and reporting of emissions associated 

with the waste recycle stream or purge currently required by Equation G-6. Whereas the carbon 

contained in the waste recycle or purge has already been accounted for elsewhere through 

consideration of the feedstock carbon content, it would be technically incorrect to double-count 
196 

that same carbon through calculation of an additional emission estimate associated with use of 

the purge as a fuel. EPA is also proposing to amend 40 CFR 98.72(b) to indicate that subpart C 

(general stationary fuel combustion sources) does not apply to CO2 emissions from the use of 

purge gas as fuel. Koch Nitrogen Company, LLC (KNC) supports both of these proposed 

changes as means to improve the accuracy of the resulting emissions estimates. 

Response: EPA thanks the commenter for the input. We have finalized the amendments, as 

proposed. 

Proposed Deletion of Synthetic Fertilizer Reporting 

Commenter Name: William C. Herz 

Commenter Affiliation: The Fertilizer Institute (TFI) 

Document Control Number: EPA-HQ-OAR-2008-0508-2376.1 

Comment Excerpt Number: 2 

Comment: Equating Fertilizer Production And Fertilizer Sales With Fertilizer Application Is 

Not Appropriate. EPA suggests two rationales for removing the requirement to report the total 

pounds of synthetic fertilizer and the total nitrogen contained therein. First, EPA states that 

“[t]he data that would be reported under these subparts do not provide directly applicable 

information with which to determine N2O emissions from application of fertilizer because the 

data are incomplete.” (75 FR 48767) EPA is correct that the data are incomplete, with more 

than 56.4 percent of the U.S. nitrogen fertilizer supply being imported and nitrogen fertilizer 

produced domestically outside of the ammonia and nitric acid production industries not subject 

to reporting under the Rule. Thus, EPA would be missing a large amount of data and it will be 

impossible to generate any meaningful information from the limited data received. In addition, 

the overall percentage would be far less than 43.6 percent as important inputs such as manure, 

biosolids, and nitrogen from atmospheric deposition also are uncounted. These organic sources 

tend to volatilize N2O at far higher rates per unit nitrogen than commercial fertilizer. 

More importantly, however, TFI does not believe that reporting the total pounds of synthetic 

fertilizer and the total nitrogen contained therein bears any correlation to the “application of 

fertilizer” to agricultural soils. This is evidenced by data reported to EPA as part of the 2006 

Inventory Update Reporting (IUR) Program. For 2006, EPA required chemical manufacturers of 

organic chemicals to report for the first-time down-stream processing and use data for their 

chemical substances to the extent that the chemical substances were manufactured and/or 

imported at the site in quantities of at least 300,000 pounds during calendar year 2005. 40 C.F.R. 

§ 710.52(c)(4). 

In particular, EPA required manufacturers exceeding the reporting threshold to report: (1) a 

designation indicating the “type of processing or use operation” at each site that received the 

reported chemical substance (with five options); (2) the five-digit North American Industrial 

Classification System (NAICS) code which best describes each processing or use operation; and 

(3) an “industrial function category” (with 33 options) corresponding to the type of processing or 
197 

use operation/NAICS code for each down-stream activity. Notably, “agricultural chemicals (nonpesticidal)” is one of the 33 “industrial function categories.” 

Based on a review of aggregate IUR data for urea, five “industrial functions categories” in 

addition to “agricultural chemicals (non-pesticidal)” were identified by manufacturers and 

importers of urea: (1) “adhesives and binding agents;” (2) “reducing agents;” (3) “process 

regulators, used in vulcanization or polymerization processes;” (4) “coloring agents, dyes;” and 

(5) “processing aid, not otherwise listed.” 

Further, even as to the “agricultural chemicals (nonpesticidal”) category, this category does not 

correspond to 100 percent of the urea being land applied. Rather, it would include blending or 

mixing of urea with other fertilizers and the sale of urea directly to an end user. Thus, attributing 

100 percent of urea production to fertilizer application is incorrect, and assuming that 100 

percent of a product fertilizer that is sent to an agricultural retail facility is applied to the ground 

is incorrect. The same flaws would apply to other synthetic fertilizers. 

Second, EPA states as its second rationale for deleting the fertilizer production and nitrogen 

content reporting requirements that the data are currently available from the Association of 

American Plant Food Control Officials (AAPFCO). (75 FR 48767) According to EPA, “[t]he 

sales data is [sic] equivalent to fertilizer application since the sales are from the last licensed 

dealer.” Id. As with reporting the total amount of fertilizer produced and the nitrogen content of 

same has no usefulness to determining the amount of fertilizer applied to agricultural soils, the 

AAPFCO data, although useful in tracking sales to a dealer, does not necessarily mean that the 

fertilizer sold to the dealer is ultimately applied to the ground. A given quantity of nitrogen 

fertilizer may be sold multiple times before reaching an agricultural field (e.g., from a distributer 

to a blending operation to a retailer), which results in multiple additions of the same quantity of 

fertilizer. Further, the AAPFCO data includes fertilizer sales for both agriculture and nonagricultural purposes. The EPA Science Advisory Board draft report on reactive nitrogen states: 

The UFTRS (the AAPFCO Commercial Fertilizers data set) was not designed to track the 

source of inorganic nutrients applied to agricultural land on the geographic scale needed 

for watershed modeling. The system only tracks sales of synthetic fertilizers and not 

manure or biosolids applied to farmland. In addition, geographical data associated with 

each sale may or may not be near the actual point of application. [Footnote: EPA Science 

Advisory Board, Reactive Nitrogen in the United States – An Analysis of Inputs, Flows, 

Consequences and Management Options, pg. 37 (May 28, 2010).] 

Because of the limited data set for reported synthetic fertilizer production and nitrogen content of 

same, and the inability to extrapolate this data to application of fertilizer to agricultural soils, TFI 

supports EPA’s proposal to delete the requirement to report synthetic fertilizer production and 

the nitrogen content in the fertilizer. 

Response: Without necessarily agreeing with all of the commenter’s argument, we have 

finalized the amendments, as proposed. Please see Section II.J of the preamble to the final rule 

amendments for the response to this comment. 
198 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 

Comment Excerpt Number: 13 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 13 

These two commenters submitted identical comments on this subject. 

Comment: As EPA writes in its proposed rule, “[n]itrous oxide emissions from agricultural soils 

are an important source of greenhouse gas emissions in the United States (approximately 3 

percent in 2008).” (75 FR 48767) Accurately tracking fertilizer production, which drives 26% of 

emissions from this source, is therefore essential to tracking and reducing N2O emissions. We 

praised EPA’s decision to include this requirement in the final rule and are dismayed that EPA is 

now considering waiving it to settle with The Fertilizer Institute (“TFI”). 

The TFI settlement would have EPA delete its requirement that facilities report on urea 

production and on “total pounds of synthetic fertilizer and total nitrogen contained in that 

fertilizer.” 75 FR 48767; 40 C.F.R. §§ 98.76(b)(16), (b)(17), & (c). EPA offers no coherent 

reason for this deletion. 

First, EPA states that domestic producers produce “less than one-half of the total amount of 

nitrogen-based fertilizer used in the United States.” 75 FR 48767. Surely this is a good reason to 

monitor their production and, if possible, to extend monitoring to imports and other sources. It 

does not justify waiving reporting entirely. 

Second, EPA suggests that it has some sales data from the Association of American Plant Food 

Control Officials (“AAPFCO”) which can address “near-term analytical needs.” Id. But EPA 

admits that AAPFCO’s data comes from state sources where “AAPFCO has indicated in a 

published article that recent stresses on state budgets potentially threaten the continued 

availability of these data.” Id. So this data, which is not supplier-specific and does not 

necessarily cover all reporting rule requirements, may soon vanish and does not, in any event, 

map back onto specific facilities, which EPA must track under the reporting rule mandate. EPA’s 

two justifications do not make sense. EPA acknowledges that it needs N2O data, that fertilizer 

production data begins to fill this need, and that other data sources are not generally adequate 

and may vanish entirely. Indeed, EPA acknowledges that it is poised to “initiate a fertilizer 

reporting requirement” when these sources fail, and that it should expand its reporting to cover 

“elements such as fertilizer application rates, timing of application, and the use of slow-release 

fertilizers and nitrification/urease inhibitors.” Id. 

Given these acknowledged needs, it is perverse to drop the requirements EPA already has. We 

urge EPA not to do so. 
199 

Response: Please see Section II.J of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: William C. Herz 

Commenter Affiliation: The Fertilizer Institute (TFI) 

Document Control Number: EPA-HQ-OAR-2008-0508-2376.1 

Comment Excerpt Number: 3 

Comment: On July 20, (75 FR 42085), EPA published a notice in the Federal Register 

announcing a settlement with TFI and certain other petitioners regarding petitions for review 

filed with the D.C. Circuit relating to EPA’s Greenhouse Gas Reporting Rule. In response to the 

notice, commenters provided comments on portions of the settlement reached with TFI. Because 

these comments directly relate to EPA’s proposals, we respond to the comments today. The 

Clean Air Task Force, Natural Resources Defense Council, and Sierra Club supported retention 

of the requirement for ammonia and nitric acid producers to report synthetic fertilizer production 

and the nitrogen content of same, and the requirement to report urea uses. [Footnote: Docket ID 

Number EPA-HQ-OGC-2010-0575, Comments 0014 and 0015, citing a letter from the Center 

for Biological Diversity, Clean Air Task Force, Environmental Defense Fund, National Wildlife 

Federation, Natural Resources Defense Council, Sierra Club, Union of Concerned Scientists, and 

WildEarth Guardians to EPA Docket ID Number EPA-HQ-OAR-2008-0508 (June 8, 2009).] 

According to these commenters, “EPA’s decision to require reporting of synthetic fertilizer 

production and nitrogen content . . . is a useful first step towards better accounting for the role of 

farming in the climate system.” As previously discussed, these two reporting elements have no 

direct correlation to “the role of farming in the climate system” because use of the elements for 

such a purpose assumes that 100 percent of the reported synthetic fertilizer is directly used in 

farming – which is not the case. 

Next, the commenters state that retention of these reporting requirements makes sense relying on 

EPA’s first rationale for deletion of same – that “less than one-half of the total amount of 

nitrogen-based fertilizer used in the United States [comes from domestic production].” TFI is 

unclear how data accounting for far less than one-half of the synthetic fertilizer used in the 

United States, and the nitrogen content of same, is at all reliable to predict down-stream use of 

the fertilizer, especially when the reported data do not equate to fertilizer applied to the land. 

Finally, the commenters advocate retention of these reporting requirements given that AAPFCO 

may not continue to publish its data and, in any event, since the AAPFCO data are not facilityspecific “this [sic] data, which is [sic] not supplier-specific and does [sic] not necessarily cover 

all reporting rule requirements, may soon vanish and does [sic] not, in any event, map back onto 

specific facilities, which EPA must track under the reporting rule mandate.” These comments, 

however, miss the mark. 

As previously noted, the AAPFCO data, like the Greenhouse Gas Reporting Rule synthetic 

fertilizer and nitrogen content of same data elements, do not correlate to fertilizer applied to the 

land. Further, we are unclear what the commenters are referring to regarding a “reporting rule 

mandate” regarding “specific facilities.” To the extent commenters refer to the 2008 
200 

Consolidated Appropriations Act (H.R. 2764), nothing in that Act requires “map[ping] back to 

specific facilities.” Rather, the Act authorizes EPA to “develop and publish a draft rule no later 

than nine months after the date of enactment of this Act, and a final rule no later than 18 months 

after the date of the enactment of this Act, to require mandatory reporting of greenhouse gas 

emissions above appropriate thresholds in all sectors of the economy of the United States.” As 

such, we encourage EPA to move forward with the proposal to delete the requirements to report 

total pounds of synthetic fertilizer produced, nitrogen content of the fertilizer, and uses of urea. 

Response: Without necessarily agreeing with all of the commenter’s argument, we have 

finalized the amendments, as proposed. Please see Section II.J of the preamble to the final rule 

amendments for the response to this comment. 

Other Subpart G Comments 

Commenter Name: William C. Herz 

Commenter Affiliation: The Fertilizer Institute (TFI) 

Document Control Number: EPA-HQ-OAR-2008-0508-2376.1 

Comment Excerpt Number: 5 

Comment: TFI encourages EPA to re-examine its reliance on the Intergovernmental Panel on 

Climate Change (IPCC) emission factor methodology for estimating N2O emissions from 

agricultural lands, which is associated with high uncertainty. To more realistically represent 

greenhouse gas emissions from agricultural lands, EPA should consider use of the DAYCENT 

biogeochemical model. [Footnote: See for example Del Grosso et al., Global scale DAYCENT 

model analysis of greenhouse gas emissions and mitigation strategies for cropped soils Global 

and Planetary Change. Volume 67, Issues 1-2, pp. 44-50 (May 2009).] The IPCC methodology 

estimates nitrogen losses from croplands based solely on nitrogen inputs. In contrast, DAYCENT 

accounts for soil class, daily weather, historical vegetation cover, and land management practices 

such as crop type, fertilizer additions, and cultivation events. The DAYCENT model also allows 

for comparison of baseline greenhouse gas emissions and nitrogen losses for irrigated and rainfed cropping with land management alternatives intended to mitigate greenhouse gas emissions. 

We agree with EPA that if the Agency was to decide in the future to add a requirement to report 

fertilizer production under the Greenhouse Gas Reporting Rule, or any other new requirement 

related to N2O emissions from agricultural soils, the Agency should initiate a new rulemaking 

process. 

TFI requests that any future rulemaking be preceded by a workgroup of scientists and 

stakeholders to determine the most appropriate methodology for determining N2O emissions 

from agricultural soils, including, but not limited to, model selection, model inputs, nitrogen 

input data use and use of data on current best management practices and other mitigation 

practices. 
201 

Response: EPA thanks the commenter for the input. Part 98 does not include calculation 

methodologies for N2O emission from agricultural soils and therefore this comment is outside 

the scope of the proposed amendments. 

Commenter Name: William C. Herz 

Commenter Affiliation: The Fertilizer Institute (TFI) 

Document Control Number: EPA-HQ-OAR-2008-0508-2376.1 

Comment Excerpt Number: 4 

Comment: TFI generally agrees with EPA’s concern regarding the need for better data on N2O 

emissions. Nitrous oxide emissions from agricultural soils are a source of greenhouse gas 

emissions in the United States (approximately three percent in 2008), and the application of 

nitrogen-based fertilizer to soils represents some fraction of the total N2O emissions from this 

source. However, TFI remains concerned that EPA is focused solely on the domestic synthetic 

fertilizer sector as a source of data. For example, EPA makes no mention of collecting data on 

the use of biosolids and organic nitrogen fertilizers for estimating N2O emissions from 

agricultural fields. The proposed rule also makes no mention of soil best management practices, 

which peer reviewed research [Footnote: International Plant Nutrition Institute, Fertilizer 

Nitrogen BMPs to Limit Losses that Contribute to Global Warming (2008).] indicates can 

dramatically reduce N2O emissions. In this regard, TFI and the International Plant Nutrition 

Institute are advancing the “4R stewardship system” as an environmental management platform 

based on agronomic science that involves using the right nutrient source at the right time, right 

rate and in the right place. The system has been endorsed by the United States Department of 

Agriculture (USDA), AAPFCO, specific provinces in Canada, the International Fertilizer 

Industry Association, Certified Crop Advisors, and others. This system has also received Land 

Grant university support. Several Canadian provinces have embraced the 4R system as a viable, 

voluntary system to pay farmers on a per acre basis to implement N2O emissions reductions. 

Response: EPA thanks the commenter for the input. Part 98 does not include calculation 

methodologies for N2O emission from agricultural soils and therefore this comment is outside 

the scope of the proposed amendments. 

7. SUBPART P - HYDROGEN PRODUCTION 

Oil and Gas Flow Meter Calibration 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 9 

Comment: Fuels and feedstocks to a hydrogen plant subject to Subpart P requirements are often 

the same as the fuels burned in combustion units subject to Subpart C requirements. The 
202 

monitoring and QA/QC requirements under Subparts C and P for these materials should be 

consistent to avoid the possibility of different requirements applying to the same stream. EPA 

recognized and addressed this possibility by proposing to amend Subpart P §98.164(b)(1) to 

require reporters to calibrate oil and gas flow meters that are used to measure liquid and gaseous 

feedstock volumes according to the monitoring and QA/QC requirements for the Tier 3 

methodology in Subpart C §98.34(b)(1). API supports this revision. However, the carbon content 

and molecular weight method provisions in Subpart P were not revised to be consistent with the 

revisions in Subpart C. Subpart P §98.164(b)(5) lists the methods that must be used to determine 

carbon content and molecular weight, in contrast to the proposed revision to Subpart C 

§98.34(b)(4) that deletes the list of analytical methods and instead requires reporters use a 

method published by a consensus standards organization if such a method exits, or an industry 

consensus standard practice. If §98.164(b)(5) is not consistent with §98.34(b)(4), a reporter 

might be required to perform two different analyses for carbon content and molecular weight on 

the same liquid or gas stream. 

API requests EPA revise the carbon content and molecular weight method provision in 

§98.164(b)(5) to be consistent with proposed revisions to Subpart §98.34(b)(4) such that in 

§98.164(b)(5) the list of analytical methods is deleted and instead reporters would be required to 

use a method published by a consensus standards organization if such a method exits, or an 

industry consensus standard practice. 

Response: Please see Section II.A of the preamble for the response to this comment. 

Other Subpart P Comments 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 45 

Comment: Use of GCs to measure HHV and carbon content varies by subpart. In the August 

11, 2010 proposed amendments, EPA proposed revising Subpart Y §98.254(d) consistent with 

our recommendation. EPA proposed adding: “Alternatively, the result of chromatographic 

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

and calibrated according to the manufacturer’s instructions; and the methods used for operation, 

maintenance, and calibration of the gas chromatograph are document in the written Monitoring 

Plan for the unit under §98.3(g)(5).” 

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

and calibrated according to manufacturers’ instructions: “Use any applicable methods from the 

following list to determine the carbon content and molecular weight (for gaseous fuel) of the 

fuel. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that 

the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s 

instructions.” 
203 

Subpart P references §98.34(b)(i) for flow meters, but amendments do not change requirements 

for carbon content and molecular weight. Subpart P specifies that an EPA-specified test method 

must be used to measure carbon content and molecular weight of feedstocks. The test methods 

list includes the following chromatography-specific methods: ASTM D1945-03; ASTM D1946-

90; UOP 539-97; and GPA 2261-00. However, nowhere in Subpart P is there any language that 

allows the use of GCs as long as they are “operated, maintained, and calibrated according to the 

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

Subpart X - Flare Carbon Content or HHV sampling requires that an EPA specified test method 

be used to measure HHV / carbon content / MW of feedstocks. The list of acceptable test 

methods includes GC analysis and EPA is proposing a revision to Subpart X to allow the use of 

modifications to the standards listed or alternative methods. 

The requirements for gas chromatography should be consistent across all subparts. Accordingly, 

in order to enable reporters to develop a consistent approach to their sampling and analysis 

obligations, EPA should extend the requirements for the use of GCs under Subparts C to 

Subparts P, X and Y. 

API requests that EPA take the following specific action: Insert the following language in each 

subpart: “Alternatively, the results of chromatographic analysis of the fuel may be used, 

provided that the gas chromatograph is operated, maintained, and calibrated according to the 

manufacturer’s instructions.” Note, the recent amendments (p. 332 of the pre-FR version) correct 

this issue in Subpart Y, but the same correction has not been made for Subparts P and X. 

Response: Please see Section II.K of the preamble for the response to this comment. 

8. SUBPART V - NITRIC ACID PRODUCTION 

Multiple comments were received on the proposal to remove the synthetic fertilizer and total 

nitrogen reporting requirement in 40 CFR 98.76 (c) (Subpart G – Ammonia Manufacturing) and 

40 CFR 98.226(o) in Subpart V. These were identical reporting requirements in these two 

subparts. Please see Section 6 of this document for the summary and response to the comments 

related to the removal of synthetic fertilizer reporting requirements. 

9. SUBPART X: PETROCHEMICAL PRODUCTION 

GHGS to Report 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 
204 

Comment Excerpt Number: 38 

Comment: Revise §98.242(b) by consolidating the information contained in paragraphs (b)(1) 

and (b)(2) into paragraph (b) and deleting (b)(1) and (b)(2). Both paragraphs (b)(1) and (b)(2) 

require the reporting of CO2, CH4, and N2O from the combustion of supplemental fuel, so it is 

unnecessary and somewhat confusing to separate the information into two paragraphs for the 

different compliance options. 

§98.242(b) CO2, CH4, and N2O combustion emissions from stationary combustion units that 

burn only supplemental fuel. Calculate these emissions by following the requirements of subpart 

C of this part (General Stationary Fuel Combustion Sources). 

§98.242(b)(1) If you comply with §98.243(b) or (d), report these emissions from stationary 

combustion units that are associated with petrochemical process units and burn only 

supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

§98.242(b)(2) If you comply with §98.243(c), report CO2, CH4, and N2O combustion emissions 

under subpart C of this part (General Stationary Fuel Combustion Sources) by following the 

requirements of subpart C only for the combustion of supplemental fuel. Determine the 

applicable Tier in subpart C of this part (General Stationary Fuel Combustion Sources) based on 

the maximum rated heat input capacity of the stationary combustion source. 

Response: No change was made as a result of this comment. This comment addresses an issue 

that is outside the scope of the proposed amendments published on August 11, 2010, because we 

did not propose amendments to the description of GHGs to report in §98.242(b). 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 39 

Comment: If comment #21 [excerpt 38], above is not accepted, revise §98.242(b)(2) to 

eliminate the duplication of general instructions in the first sentence since they are already 

included in the introductory text to paragraph (b), and, delete the last sentence as it is redundant 

of the already referenced subpart C in the first sentence. The elimination of the duplicate 

language in the first sentence would make the language consistent with the preceding paragraph 

(b)(1). 

§98.242(b)(2). If you comply with §98.243(c), report CO2, CH4, and N2O combustion these 

emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by 

following the requirements of subpart C only for the combustion of supplemental fuel. 

Determine the applicable Tier in subpart C of this part (General Stationary Fuel Combustion 

Sources) based on the maximum rated heat input capacity of the stationary combustion source. 
205 

Response: No change was made as a result of this comment. This comment addresses an issue 

that is outside the scope of the proposed amendments published on August 11, 2010, because we 

did not propose amendments to the description of GHGs to report in §98.242(b). 

Calculating CH4 and N2O emissions for Ethylene Only Options 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 8 

Comment: ACC generally supports EPA’s changes to this subpart. In particular, we support 

EPA’s proposed changes to Sections 98.243(d)(2) and (d)(3) to establish provisions for small 

ethylene process off-gas streams. We agree that the installation of flow meters and on-line GCs 

or small collection taps on these ancillary gas streams is not warranted, as these streams do not 

significantly contribute to the overall heat input of the stationary combustion unit. EPA should 

clarify that these provisions can be utilized even if a flow meter is installed in a small ethylene 

line, since the act of collecting and analyzing samples can still be very challenging for small 

isolated streams. 

Response: EPA disagrees with the commenter. The proposed amendments provided limited 

exclusions to the Tier 3 methodology for small streams. The exclusion was specifically targeted 

only to prevent the need to install flow meters for small streams. We did not propose changes to 

the carbon content measurement requirements for streams with flow meters in place. We are not 

persuaded by the comment that relief from such analyses is warranted because the commenter 

has not indicated why collecting and analyzing samples from small streams, or certain types of 

small streams, is any more challenging than for larger streams. 

Equation X-1 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 42 

Comment: §98.243(d)(5) should be changed to identify not only the flare calculation 

methodologies to be used but also the QA/QC requirements for measuring the flare gas flow and 

analyzing the flare gas composition and heat content, as follows: 

§98.243(d)(5) For each flare, calculate CO2, CH4, and N2O emissions using the 

methodology as specified in §98.253(b)(1) through (b)(3) and relevant QA/QC 

requirements as specified in §98.254(b) through (e). 
206 

Response: We agree with the commenter’s suggested change and we modified the final rule 

accordingly. One of the options for flares is to measure higher heating value. Because QA/QC 

procedures for this measurement device are not otherwise included in subpart X, it is necessary 

to reference the applicable QA/QC procedures in subpart Y. In addition, §98.254(d) of subpart 

Y also lists methods for determining the composition of natural gas and related gas streams that 

are not listed in subpart X; these methods are appropriate for flare gas and need to be referenced 

from subpart X. Although the QA/QC procedures for flow meters should be the same in subpart 

X and subpart Y, for clarity we have decided to modify §98.243(d)(5) to reference §98.254(b) 

through (e) in subpart Y for all of the QA/QC requirements that are to be used for flares that are 

used with petrochemical processes. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 46 

Comment: Revise §98.243(d)(2)(ii) to allow the use of Tier 1 or 2 when a meter that does not 

meet the Tier 3 installation requirements is in place. (Note that the rule is currently silent with 

respect to Tier 3 meter installation requirements, which we believe were inadvertently deleted, 

and we proposed to reinstate them in other comments.) The purpose of the current exemption is 

to allow small units to use Tier 1 or Tier 2 subpart C equations when the otherwise required Tier 

3 fuel flow meters are not in place. This recognizes that the cost of a Tier 3 meter is not justified 

for these small units. However, having a meter that does not meet Tier 3 installation 

requirements has the same practical effect as not having a meter in place. An example of such a 

situation is a meter that is not correctly placed in the line to allow enough upstream or 

downstream pipe diameters from the nearest flow disturbance to ensure uniform flow and 

accurate flow measurements. 

§98.243(d)(2)(ii) The combustion unit has a maximum rated heat input capacity of less than 30 

MMBtu/hr, and a fuel flow meter is not installed at any point in the line supplying fuel gas (that 

contains ethylene process off-gas) or an upstream common pipe, except if the fuel flow meter 

does meet the Tier 3 requirements at §98.34(b)(4). In that case, this option can be used. 

Response: EPA disagrees with the commenter. The 2009 final rule required the use of Tier 3 or 

Tier 4 for calculating GHG emissions from all units combusting fuel gas. The proposed 

amendments provide additional flexibility for small streams. This flexibility was specifically 

targeted only to prevent the need to install flow meters for small streams. As we stated in the 

proposal, if a flow meter is installed, we consider the Tier 3 monitoring requirements to be 

reasonable and justified. Installation of a new flow meter is not required as long as the existing 

flow meter can be upgraded to meet the requirements of Tier 3 flow meters. Therefore, we are 

not making the suggested change to allow the use of Tier 1 or Tier 2 if an installed flow meter 

does not meet the installation requirements for Tier 3. 

Commenter Name: Stancy Simpson 
207 

Commenter Affiliation: Eastman Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2369.1 

Comment Excerpt Number: 2 

Comment: Eastman requests that the EPA change the proposed wording of §98.243(d) as 

follows: 

For each ethylene production process, calculate GHG emissions from each combustion 

unit combustion units that burns fuel that contains any off-gas from the ethylene process 

as specified in paragraphs (d)(1) through (d)(5) of this section. 

The proposed introduction of "each combustion unit" appears to preclude the common pipe 

configuration allowed by 98.36(c)(3). Eastman submits that the common pipe reporting option is 

appropriate for stationary combustion units at a facility that combusts the same type of fuel and 

when the fuel is fed to the individual units through a common supply line or pipe. Precluding 

that reporting option will NOT improve the quality of the GHG emissions estimates. It will, 

however, introduce the following overly burdensome requirements to industry: 

• Increase in calibration requirements – Multiple flow instruments would need to meet the 

calibration requirements of Subpart X as opposed to a single flow instrument. 

• Increase in analytical requirements – Sample and analysis would be required for multiple 

locations as opposed to a single analysis point. 

• Increase in the number of emissions calculations – Emissions calculations would need to 

be completed for individual units as opposed to emissions estimates for a group of 

combustion sources. 

Response: Please see Section II.M of the preamble for the final amendments for the response to 

this comment. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 9 

Comment: Dow Supports EPA’s Changes to the Rule for Small Ethylene Process Off-Gas 

Streams and Suggests Further Revisions to the Proposed Section Regarding Flow Meters. 

Dow generally supports EPA’s proposed changes to Sections 98.243(d)(2) and (d)(3) to establish 

provisions for small ethylene process off-gas streams and agrees that the installation of flow 

meters and on-line GC’s or sample collection taps on these ancillary gas streams is not warranted 

as these streams do not significantly contribute to the overall heat input of the stationary 

combustion unit. Dow comments further that EPA should clarify that these provisions can be 

utilized even if a flow meter is installed in the small line since the act of collecting and analyzing 

samples can still be very challenging for the small isolated streams. Thus, the Tier 3 

requirements remain quite burdensome. Also, existing flow meters on small lines may not be 
208 

pressure or temperature compensated. Thus, Dow proposes the following rule text change for 

section 98.243(d)(2)(i): 

The annual average now rate of the fuel gas (that contains ethylene process off-gas) in the fuel 

gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 

345 standard cubic feet per minute at 60°F and 14.7 pounds per square inch absolute and a flow 

meter is not installed at any point in the lie supplying fuel gas or an upstream common pipe. 

Calculate the annual average now rate using company records assuming total now is evenly 

distributed over 525,600 minutes per year. 

Response: See the response to comment EPA-HQ-OAR-2008-0508-2357.1, excerpt number 46. 

Regarding the statement by the commenter that existing flow meters on small lines may not be 

pressure or temperature compensated. In this action we have modified Part 98 to allow assumed 

values to be used for temperature and/or total pressure at the flow meter location, based on 

measurements of these parameters at a remote location (or locations) if certain conditions are 

met. Please see section II.F of the preamble to the final rule amendments for additional 

discussion of these conditions. We would emphasize that both the option of using assumed 

values for temperature and/or total pressures at the flow meter location, as well as the 

opportunity to use Tier 1 or Tier 2 for small streams under certain circumstances, reduce the 

burden of the 2009 final rule. Given this additional flexibility allowed in the August 11, 2010 

amendments we have concluded that the burden for temperature and pressure compensated flow 

meters is significant enough to warrant modifying the requirement to use Tier 3 if flow meters 

are in place. 

Monitoring and QA/QC Requirements 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 43 

Comment: Revise §98.244(b)(2) to address meter installation requirements in addition to the 

already specified operation and maintenance requirements. This is important because the 

installation standards specify, for example, the minimum distance to the nearest flow 

disturbance, which is important for obtaining accurate flow data. Also, expand the installation, 

operation, and maintenance requirements to include, in addition to manufacturer’s recommended 

procedures, methods published by a consensus-based standards organization or industry 

consensus standard practice. Lastly, allow the calibration and recalibration of feedstock and 

product flow meters by a consensus-based standards organization method in addition to the 

industry consensus standard method or manufacturer recommended method. These changes are 

all consistent with the fuel meter requirements in subpart C (General Stationary Fuel Combustion 

Sources). 

§98.244(b)(2) Install, Operate and maintain all flow meters used for gas and liquid 

feedstocks and products according to one of the following methods manufacturer’s 
209 

recommended procedures. You may use the manufacturer’s recommended procedures, a 

method published by a consensus-based standards organization, or industry consensus 

standard practice. You must calibrate each of these flow meters according to one of the 

following. You may use a method published by a consensus-based standard organization 

if such a method exists, an industry consensus standard method, or methods specified by 

the flow meter manufacturer. Consensus-based standards organizations include, but are 

not limited to, the following: ASTM International, the American National Standards 

Institute (ANSI), the American Gas Association (AGA), the American Society of 

Mechanical Engineers (ASME), and the American Petroleum Institute (API). Each flow 

meter must meet the applicable accuracy specification in §98.3(i), except as otherwise 

specified in §98.3(i)(4) through (i)(6). You must recalibrate each flow meter according 

to one of the following frequencies. You may recalibrate either biennially, at the 

minimum frequency specified by the manufacturer, at the interval specified by the 

consensus-based standards organization method, or at the interval specified by the 

industry consensus standard practice used. 

Response: After careful consideration, we have decided not to make the suggested change to 40 

CFR 98.244(b)(2) because we did not want to broaden an “industry concensus standard method” 

to an “industry consensus standard practice”. It is our interpretation that a “method” is a 

documented process or procedure to be followed whereas a “practice” may be more general in 

nature. (We note that we do, however, interpret a method published by a consensus-based 

standards organization to include an “industry consensus standard method.” The commenter did 

not provide sufficient justification for why the existing methods are not sufficient or why the 

allowable methods should be expanded to include “standard practices”. We have also decided 

not to amend §98.244(b)(2) to add meter installation requirements because we have conluded 

that a flow meter can not be operated according to the requirements of the rule without being 

installed according to those requirements as well. We therefore interpret “operate” to include 

“install”. 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 47 

Comment: Revise §98.244(b)(4) and (Subpart Y) §98.254(d) and (e) to add flexibility to the 

sampling and analysis requirements. EPA added flexibility to the fuel sampling and analysis 

requirements in subpart C (General Stationary Fuel Combustion Sources) by eliminating the list 

of specific methods and instead allowing a broader array of methods. In the preamble to the 

proposed changes EPA recognized that: 

Although we attempted to assemble a comprehensive list of methods and provide 

appropriate alternatives, it is possible that other valid methods from these organizations 

and practices have been overlooked, or that in some cases, industry consensus standard 

methods may be more appropriate than the methods listed. 
210 

To be fair, equitable, and create a level-playing field for various industries (e.g., utilities, 

petrochemical producers, and petroleum refineries), this flexibility should also be afforded to the 

feedstock and product sampling and analysis requirements in Subpart X (Petrochemical 

Production) and gas (including flare gas) sampling and analysis requirements in Subpart Y 

(Petroleum Refineries). Additionally, allow the use of analyses conducted by the purchaser of a 

product. There is no reason such analyses should be treated any differently from those supplied 

by a fuel or feedstock supplier. 

[The commenter provided suggested amendatory language for §98.244(b)(4) and §98.254(d) and 

(e) of Subpart Y, if the recommended approach were adopted. The commenter also noted that 

adopting the recommended changes would also necessitate changes to §98.7 and provided 

suggested amendatory language for this section. The suggested language is not reproduced in 

this document, but can be found in the commenter’s letter in the docket for this rule-making.] 

Response: We did not propose to amend §98.244(b)(4) in subpart X or §98.254(d) and (e) in 

Subpart Y to provide the same fuel sampling and analysis options as proposed for Subpart C. 

We are specifically maintaining the specified lists of acceptable methods in subparts X and Y 

because: 1) we identified these as the most appropriate methods to use for these gas streams; and 

2) providing direct methods makes it easier for reporters to identify appropriate methods. We are 

providing additional flexibility regarding use of other gas chromatographic methods provided the 

chromatograph is operated, maintained, and calibrated according to the manufacturer’s 

instructions and the methods are documented in the facility’s Monitoring Plan. These revisions 

provide the flexibility requested by the commenter while still providing guidance and assistance 

to reporters that would like to know the methods most likely to be appropriate for these gas 

streams. Please see Section II.M of the preamble to the final rule amendments for additional 

information on this comment. 

The commenter requests that the rule allow petrochemical producers to use the results of 

analyses conducted by purchasers of their products. We have not incorporated this suggested 

change in the final amendments because we did not propose amendments to the provisions 

specifying who may conduct analyses. Therefore, this comment is beyond the scope of the 

proposed amendments published on August 11, 2010. 

The commenter also suggested editorial changes to how methods in the appendices to 40 CFR 

part 60 are referenced. We have not made the suggested editorial changes. The paragraphs 

containing those methods were not included in the proposed amendments published on August 

11, 2010. 

Commenter Name: Larry Scheinpflug 

Commenter Affiliation: Columbian Chemicals Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2363 

Comment Excerpt Number: 1 

Comment: We would like to add the following comment under §98.243(c)(3) “Calculating 

GHG emissions.” To the statement “Collect a sample of each feedstock and product at least 
211 

once per month and determine the carbon content of each sample according to the procedures in 

98.244(b)(4).” Add, “However, if multiple deliveries of a particular type of fuel or feedstock oil 

used in the carbon black manufacturing process are received from the same supply source in a 

given calendar month, the deliveries for that month are considered, collectively, to comprise a 

fuel lot, requiring only one representative sample.” 

Response: Please see Section II.M of the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Larry Scheinpflug 

Commenter Affiliation: Columbian Chemicals Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2363 

Comment Excerpt Number: 2 

Comment: We agree with the proposed change under §98.244(b)(4), Monitoring and QA/QC 

requirements, paragraph (xii), “An industry standard practice for carbon black feedstock oils and 

carbon black products, effective as of January 1, 2010.” 

Response: EPA thanks the commenter for the input. We have finalized the amendments 

referenced by the commenter, as proposed. 

Commenter Name: Larry Scheinpflug 

Commenter Affiliation: Columbian Chemicals Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2363 

Comment Excerpt Number: 3 

Comment: We would like to add the following under §98.244(b)(4), Monitoring and QA/QC. 

Add paragraph (xiv): “ASTM D7633 Standard test method for Carbon Black – Carbon Content it 

is effective as of January 1, 2010.” Please note this method was reviewed, accepted and 

approved by an International group within ASTM on May 15, 2010. You may visit their website 

at the following for further information http://www.astm.org/Standards/D7633.htm. 

Response: Please see section II.M of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Larry Scheinpflug 

Commenter Affiliation: Columbian Chemicals Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2363 

Comment Excerpt Number: 4 

Comment: We would like to add the following under §98.244(b)(4), Monitoring and QA/QC 

requirements. Add paragraph (xv), “As of 9/23/10 ASTM is currently working on a Standard 

Test Method for Carbon Content in Carbon Black Feedstock Oils under work item number 
212 

WK27667. Once this ASTM method is approved and assigned an official number it is effective 

as of January 1, 2010.” 

Response: Please see section II.M of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Stancy Simpson 

Commenter Affiliation: Eastman Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2369.1 

Comment Excerpt Number: 1 

Comment: EPA solicited comments on whether the proposal to allow modifications of existing 

analytical methods for determining carbon content and molecular weight is warranted. Eastman 

agrees with the EPA allowance for alternatives for carbon content (CC) and molecular weight 

(MW). 

In particular, Eastman believes that the rule revisions proposed in §98.244(b)(4)(xiii) will 

provide for more accurate GHG emissions reporting. That revision specifically allows 

modifications of existing analytical methods or other analytical methods that are applicable to 

your process provided that the methods listed in 98.244(b)(4)(i) through 98.244(b)(4)(xii) are not 

appropriate because the relevant compounds cannot be detected, the quality control requirements 

are not technically feasible, or use of the method would be unsafe, effective as of January 1, 

2010. 

An example of the need for this revision is analysis of a water saturated carbon dioxide stream 

that Eastman sends to a toll converter. This stream meets the Subpart X definition of a "product" 

stream and, thus, must be analyzed for CC and MW. In the current rule, §98.244(b)(4) presents 

standard methods for determining the CC and MW. In particular, Eastman may use ASTM 

1945. However, this product stream is water saturated and Method 1945 prescribes no 

methodology for adjusting CC and MW for stream water content. Using Method 1945 in this 

context will lead to under-reporting of greenhouse gas (GHG) emissions. Therefore, the 

proposed allowance for "Modifications of existing analytical methods" would allow CC and MW 

data to be adjusted for stream water content and yield more valid results and emissions estimates. 

Eastman believes, however, that EPA should provide even more flexibility in certain 

circumstances. Specifically, Eastman recommends that EPA’s revision of §98.244(b)(4)(xiii) be 

revised as follows: 

Modifications of existing analytical methods or other analytical methods that are applicable to 

your process provided that the methods listed in 98.244(b)(4)(i) through 98.244(b)(4)(xii) are not 

appropriate because the relevant compounds cannot be detected, the quality control requirements 

are not technically feasible, or use of the method would be unsafe, effective as of January 1, 

2010. 
213 

Eastman is particularly interested in the revision to § 98.244(b)(4)(xiii) since it would very 

clearly address an issue Eastman has previously brought to the EPA’s attention. More 

specifically, on January 26, 2010, Eastman notified EPA that the rule-prescribed sampling and 

analysis of the ethylene oxide/water mixture from Eastman’s two Ethylene Oxide (EO) plants 

presents a significant personnel safety hazard. In that correspondence Eastman fully described its 

safety concerns. The solution Eastman proposed was the use of densitometers in lieu of sampling 

and analyzing the EO/water streams. 

Eastman’s proposed further amendment to § 98.244(b)(4)(xiii) would allow it to use 

densitometers in lieu of having to sample and analyze the ethylene oxide/water mixture from its 

two EO plants. In the absence of this proposed change, Eastman is concerned that some may 

interpret EPA’s use of the term "analytical method" to exclude the use of densitometers. 

Therefore, Eastman strongly urges the EPA to provide this additional needed flexibility. 

Response: Please see section II.M of the preamble to the final rule amendments for the response 

to this comment. . 

Commenter Name: Paul Mikesell 

Commenter Affiliation: Cytec Industries 

Document Control Number: EPA-HQ-OAR-2008-0508-2384.1 

Comment Excerpt Number: 1 

Comment: Cytec Industries (Cytec) agrees with other owners and operators that EPA should not 

limit carbon content and composition to only the analysis methods currently listed in the 

Mandatory Reporting Rule. The current GC methods are limited to specific products or materials 

and ignore polymers and isomers and are inappropriate for certain analytes. 

Cytec has an operating unit subject to the GHG MRR Subpart X requirements, which require 

mass balance calculation methodology be performed. In doing so, we consider carbon in versus 

carbon out in order to estimate GHG emissions. The carbon out includes waste streams where 

carbon content analysis is necessary and the listed GHG MRR analysis are not appropriate. Prior 

to the GHG MRR, Cytec used TOC analysis per EPA Method 9060A of SW846 for analysis of 

waste streams for internal use. Being that this method is not included in the GHG MRR, we have 

been simultaneously using EPA Method 8015, included in the GHG MRR per 98.244(b)(4) and 

the EPA TOC analysis per Method 9060A, gathering data to substantiate our use of an alternate 

analysis in order to submit a request to EPA. Analysis of waste streams, at an applicable GHG 

MRR Subpart X operating unit, demonstrate that EPA Method 9060A in all cases revealed a 

greater carbon content value when compared to the inappropriate GHG MRR Method 8015 

results. Results vary depending on the streams sampled, but TOC analysis using EPA Method 

9060A results range from < 1% to 99.5% greater carbon content values. As stated above, the GC 

methods ignore polymers and isomers, to which EPA’s TOC Method 9060A does not. Also, the 

cost and time associated with performing the GHG MRR Method 8015 are substantially greater 

than performing EPA’s TOC Method 9060A. 
214 

An additional analysis performed by Cytec’s Lab uses an internal modified method for analysis 

of acetonitrile product for Certificates of Analysis (COA’s) when product is sold. Being that this 

Cytec modified method would not be included in the GHG MRR, when acetonitrile product is 

sold, analysis will be performed using the GHG MRR listed 8015 Method per §98.244(b)(4) and 

the Cytec modified method analysis simultaneously, while gathering data to substantiate our use 

of an alternate analysis in order to submit a request for approval to EPA. 

Cytec appreciates the ability to submit comments on this proposed regulation and is confident 

that EPA will agree to allow for alternate carbon content analysis methods such as EPA’s 

Method 9060A for TOC, as well as the possibility of using Cytec’s internal modified method. 

Again, EPA’s Method 9060A for TOC more accurately reflects the total carbon content of the 

streams where monitoring is required, is far less time consuming and less expensive to conduct, 

while achieving more accurate results. 

Response: Please see section II.M of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 10 

Comment: EPA should add an option to §98.244(b)(4) which allows the use of an on-line mass 

spectrometer to determine the carbon content and molecular weight of feedstock or product 

streams. The rule should require that the instrument be operated, maintained, and calibrated 

according to the manufacturer’s instructions. Technical details regarding an on-line mass 

spectrometer in use at one of our sites are included as an attachment (Attachment 1). 

[See Attachment 1. Technical Details for On-line Mass Spectrometer in use at Dow’s St Charles, 

Louisiana Site. Copyrighted page/s removed. Copyrighted material is not available in 

Regulations.gov since it may not be reproduced without consent of the copyright holder. Contact 

the EPA Docket Center’s Public Reading Room to view or receive a copy of this document. 

Requests for copies may be made as follows: In person/writing: Environmental Protection 

Agency, Docket Center 1301 Constitution Ave NW, 2822T, Room 3334 Washington, DC. 

20004, Telephone: 202-566-1744, Fax: 202-566- 9744 Email: docket-customerservice@epa.gov] 

In addition, Dow generally supports the proposed addition of paragraph (xiii), but also suggests 

that the rule allow for modifications of existing analytical methods or the use of other analytical 

methods for reasons beyond those listed (i.e., relevant compounds cannot be detected, the quality 

control requirements are not technically feasible, or use of the method would be unsafe). Cases 

exist where an owner/operator has already installed an instrument which is capable of making the 

required measurements, but the analytical approach is not currently listed in Section 

98.244(b)(ixii). These alternative analytical instruments should also be allowed if the 

owner/operator can generally demonstrate that these method(s) can accurately measure the 

carbon content and composition or molecular weight of the feedstock or product stream. 
215 

Response: Please see section II.M of the preamble to the final rule amendments for the response 

to this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 10 

Comment: EPA is proposing a new paragraph §98.244(b)(4)(xiii) to allow petrochemical 

facilities to use modifications to the analytical methods listed in §98.244(b)(4) or other 

applicable analytical methods provided that the methods listed in §98.244(b)(4)(i) through (xii) 

are not appropriate because the relevant compounds cannot be detected, the quality control 

requirements are not technically feasible, or the use of the method would be unsafe, effective as 

of January 1, 2010. EPA is proposing in 40 CFR 98.246(a)(11) that if an alternative method is 

used, facilities would include in the annual report the name or title of the method used, and the 

first time it is used, a copy of the method and an explanation of why the use of the alternative 

method is necessary. EPA solicited comment on whether the flexibility provided by this option 

is needed. 

API supports this proposed revision and the flexibility it affords to reporters to use alternate 

methods that are better suited for a given process. 

Response: EPA thanks the commenter for the input. We have finalized the proposed provisions 

to allow for modifications of existing analytical methods under certain circumstances. 

Data Reporting Requirements 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 44 

Comment: Revise §98.246(a)(4) to directly report the MVC value used instead of the 

temperature at which the volumes were measured. The purpose of reporting the temperature is to 

be able to verify that the correct MVC value was used so direct reporting of the MVC value used 

would make reporting the temperature unnecessary. This would also make this paragraph 

consistent with the analogous data reporting requirements for flares at §98.256(e) and therefore 

promote consistency throughout the rule. 

§98.246(a)(4) Each of the monthly volume, mass, and carbon content values used in Equations 

X-1 through X-3 of this subpart (i.e., the directly measured values, substitute values, or the 

calculated values based on other measured data such as tank levels or gas composition) and the 
216 

molecular weights and molar volume conversion factor used in Equation X-1 of this subpart, and 

the temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X1 of this subpart were determined. 

Response: We considered requiring reporting of just the MVC value. However, we concluded 

that if the temperature is reported, it will enhance our ability to conduct verification on the 

reported emissions. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 11 

Comment: EPA is proposing in §98.246(a)(11) that if an alternative standard is used, the report 

must provide a copy of the standard. It is unclear how the electronic reporting system will be set 

up to allow the submittal of such documents. 

 

Response: The electronic reporting system will allow reporters to attach documents to an annual 

report submittal. 

Other Subpart X Comments 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 40 

Comment: Delete the second sentence of §98.243(c)(3) because it is duplicative of the 

procedures in §98.244(b)(4). . 

“Alternatively, you may use the results of analyses conducted by a fuel or feedstock 

supplier provided the sampling and analysis are conducted at least once per month using 

any of the procedures specified in §98.244(b)(4).”

If this comment is not accepted, revise this sentence to allow the use of analyses conducted by 

the purchaser of a product 

Alternatively, you may use the results of analyses conducted by a fuel or 

feedstock supplier, or product purchaser, provided the sampling and analysis are 

conducted at least once per month using any of the procedures specified in §98.244(b)(4). 

There is no reason such analyses should be treated any differently from those supplied by a fuel 

or feedstock supplier. 

 
217 

Response: Response: Although it is repetitive, we think it is helpful to clarify in §98.243(c)(3) 

that an owner or operator has the option of conducting the sampling and analysis in-house or to 

use the results provided by a feedstock supplier. We also decided not to adopt the commenter’s 

alternative suggestion to add “or product purchaser” to this paragraph. Such a change is outside 

the scope of this final rulemaking effort because we did not propose changes to 98.243(c)(3). 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 7 

Comment: EPA should establish in §98.243(c), "Mass Balance for each petrochemical process 

unit," that small quantities of additives are excluded from the material balance calculations for 

the following reasons: 

The annual quantity of these additives is typically so small that they don’t have a significant 

impact on the overall material balance calculation. For example, a process may use < 100,000 

lbs/yr of a liquid additive, but produce 500,000,000 lbs/yr of a petrochemical product, thus the 

amount of liquid additive is < 0.02% of the product stream, which is far less than required 

accuracy (+5%) of feedstock flow meters and product stream flow meters. Thus, the 

contribution of the additive carbon material will be of little consequence to the overall material 

balance. 

Obtaining the required carbon content information for each liquid additive can also present 

challenges since sometimes the composition of the liquid is proprietary information that can only 

be obtained from an outside vendor. In some cases, vendors are refusing to provide this level of 

information regarding their additives which then requires time consuming and costly sampling 

for these small streams. Also, in some cases, the owner/operator is not allowed per contract to 

analyze the vendor’s raw materials. 

Determining the exact flowrate for these small additive streams can also be problematic. At a 

minimum, EPA should provide an option in the rule that allows the owner/operator to count the 

number of fixed volume containers that are used in a given month to determine monthly usage 

volume. 

If EPA decides not to exclude these small additives, the final rule should include a provision that 

allows the owner/operator to use default carbon content and flowrate values based on process 

knowledge, engineering calculations, and other readily available information to ease the 

reporting burden for these small streams. 

 

Response: No rule change has been made as a result of this comment. This comment addresses 

an issue that is outside the scope of the current rulemaking because we did not propose 

amendments to the types of streams for which measurement is required when using the mass 

balance option in §98.243(c). 
218 

Commenter Name: Robert Rouse 

Commenter Affiliation: The Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2366.1 

Comment Excerpt Number: 8 

Comment: EPA should clarify that supplemental gas streams that are routed to petrochemical 

processes that contain trace quantities of hydrocarbons (i.e., up to 0.5 wt% hydrocarbons) are 

excluded from the definition of feedstock. This would alleviate confusion over which types of 

miscellaneous gas streams have to be considered as feedstocks in situations where a gas stream is 

routed to petrochemical process just for efficiency purposes. In many cases, these types of gas 

streams are generated by a non-covered process and are routed to the Subpart X petrochemical 

process to recover process materials. The small amount of additional carbon present in these 

supplemental gas streams does not impact the quality of the material balance for the Subpart X 

process and should not be included since the origin of the carbon comes from a non-covered 

process. 

Response: Please see the response to comment EPA-HQ-OAR-2008-0508-2366.1, excerpt 7, for 

the response to this comment. 

10. SUBPART Y- PETROLEUM REFINERIES 

GHGs to report 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 13 

Comment: EPA incorporated API’s proposed changes to some fuel gas provisions, per the 

settlement agreement to the Request for Reconsideration filed by API and NPRA. [Note: EPA’s 

notice announced six proposed settlement agreements to address six separate petitions for review 

of the MRR. See 75 FR 42,085 (July 20, 2010). API and NPRA’s comments were directed solely 

at the Settlement Agreement proposed to resolve litigation in American Petroleum Institute et. al. 

v. EPA (D.C. Cir. No. 09-1328).] These changes are now reflected in the proposed revisions to 

§98.252(a). However, upon further review, API members have identified gas streams in which 

Tier 3 requirements are imposed due to the amended language. These are streams where the 

associated weekly sampling poses a significant safety issue as well as significant difficulty in 

sampling streams that were not previously accessed for sampling. These small flow streams 

would otherwise fit the requirements for the use of Tier 1 or Tier 2 methodologies if it were not 

for the fact that they are equipped with flow meters. These streams are not what industry would 

define as “refinery fuel gas” but would fall under the realm of “fuel gas” as is written into the 

definition under the rule. These can include streams that are process off-gas or vent gases with 
219 

properties much different than traditional “refinery fuel gas” streams and are not part of the 

refinery’s fuel gas system. 

As stated previously, these off-gas streams may not currently be sampled, and only due to the 

changed rule language, these streams with an existing flow meter must now be sampled weekly. 

Many of these streams are difficult to sample (for example, because of low pressure) or may 

present hazardous sampling conditions. Examples of safety issues associated with sampling 

these streams include toxicity of the stream, potentially high temperature conditions, or 

flammability and explosion potential. In these situations, the added rigor associated with Tier 3 

requirements and the additional expense to safely conduct the weekly sampling are not justified 

for the increased safety risk and overall minuscule contribution of emissions (on the order of 

0.1% of a refinery’s total greenhouse gas emissions as estimated by some member companies). 

EPA should not impose high risk sampling requirements for a negligible improvement in 

accuracy. 

API requests that §98.252(a)(1)(ii) and §98.252(a)(2)(ii) be further amended to exclude such 

small flow or hazardous fluid streams that may have a meter but are not currently being sampled 

per Tier 3 requirements, and allow the use Tier 1 or Tier 2 calculation methodologies for these 

streams if they meet the other parameters of the regulatory language. Please see below for 

suggested wording (see the edits in square brackets): 

(1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior 

to any split to individual burners or ports, does not exceed 345 standard cubic feet per 

minute at 60oF and 14.7 pounds per square inch absolute and either of the conditions in 

paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual average flow rate 

using company records assuming total flow is evenly distributed over 525,600 minutes 

per year. 

(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream 

common pipe. 

(ii) The fuel gas line contains vapors from loading or unloading, waste or wastewater 

handling, [off-gas or vent gas not part of the refinery fuel gas system,] and remediation 

activities that are combusted in a thermal oxidizer or thermal incinerator. 

(2) The combustion unit has a maximum rated heat input capacity of less than 30 

MMBtu/hr and either of the following conditions exist: 

(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream 

common pipe; or 

(ii) The fuel gas line contains vapors from loading or unloading, waste or wastewater 

handling, [off-gas or vent gas not part of the refinery fuel gas system,] and remediation 

activities that are combusted in a thermal oxidizer or thermal incinerator. 

Response: Please see Section II.N of the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
220 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 32 

Comment: API supports the clarification of §98.252(i) – Clarified hydrogen produced from 

catalytic reforming units is not subject to Subpart P. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Reporting Emissions From Flares 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 50 

Comment: Revise §98.253(b)(1)(ii)(A) and §98.253(b)(1)(ii)(B) to allow facilities that routinely 

measure the carbon content and/or heat value of the flare gas an option to separately measure or 

estimate these parameters for startup, shutdown and malfunction events exceeding 500,000 

scf/day and use these values to calculate flare emissions separately for these events. The flare 

calculations at subpart Y are separated into two basic categories for facilities that do and do not 

measure the carbon content and/or heat value of the flare gas at least weekly. Facilities that do 

not measure these parameters must measure or estimate the heat content of the fuel gas during 

periods of normal operation and use those values to calculate flare emissions. They also must 

separately estimate the carbon content of the flare gas during periods of start-up, shutdown, or 

malfunction when the flared gas volume exceeds 500,000 scf/day and use that value to calculate 

emissions from these events. Facilities that do measure the carbon content and/or heat value of 

the flare gas must use the results of these analyses to calculate flare emissions for both normal 

operations and emission events. However, these samples may not be representative of the flare 

gas during a start-up, shutdown, or malfunction event, as the characteristics of the gas during 

these events can vary markedly from routine operations. Providing an option to facilities that 

routinely measure the carbon content and/or heat value of the flare gas to use an estimate of these 

parameters that are specific to the start-up, shutdown, or malfunction event would result in more 

accurate emission calculations. 

[The commenter provided suggested amendatory language for §98.253(b)(1)(ii)(A) and 

§98.253(b)(1)(ii)(B). The commenter also noted that adopting the recommended changes would 

also necessitate changes to the recordkeeping requirements at §98.256(e)(6) through (e)(8), and 

provided suggested amendatory language for those sections. The suggested language is not 

reproduced in this document, but can be found in the commenter letter in the docket for this rulemaking.] 

Response: We expect that facilities that routinely measure the carbon content or heat content of 

the flare gas will directly include the effects of any startup, shutdown or malfunction (SSM) 

event on the reported flow rates and carbon content (or heat content) of the flare gas during that 
221 

measurement period. Nothing in the rule prevents the reporter from making more frequent 

measurements. That is, we consider that the rule adequately accommodates the commenter’s 

request without the need for additional amendments. While the emissions will not be 

characterized separately as emissions from “normal operations” and emissions from an “event,” 

the values used in Equations Y-1a, Y-1b, or Y-2 should fully characterize the total emissions 

from the flare. Consequently, we determined that the suggested amendments are unnecessary. 

Sulfur Recovery: Sour Gas Sent Offsite 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 34 

Comment: The revised §98.253(f) expanded provisions to include reporting for sour gas sent off 

site for sulfur recovery and for non-Claus sulfur recovery plants. API does not support adding 

reporting burden or the requirement for refiners to have to report emissions from off-site, nonoperated processes. 

Response: The amendments proposed did not add any additional reporting burden. Per 

§98.252(c) of the final rule promulgated in October 30, 2009, which describes the GHGs to be 

reported, emissions from off-site sulfur recovery units were already required to be reported. This 

section (§98.252(c)) specifically states (per the October 30, 2009 final rule) that the calculation 

methodologies listed in §98.253(f) must be followed for calculating CO2 emissions from sour gas 

sent off site for sulfur recovery operations. Similarly, the October 30, 2009, final rule included 

reporting requirements in §98.256(h) for “sulfur recovery plants and for emissions from sour gas 

sent off-site for sulfur recovery.” The amendments proposed to §98.253(f), which describe how 

GHG emissions are to be calculated, adding the phrase “and for sour gas sent off-site for sulfur 

recovery” are for clarification purposes only; no new reporting burden was added. 

Regarding non-Claus sulfur recovery plants, these plants were already included in the reporting 

requirements under §§98.252(d) and 98.256(h). We received questions regarding how to apply 

the calculation methodologies to non-Claus sulfur recovery plants, which we proposed to 

addressed in these amendments. We consider the proposed amendments to provide more 

reasonable methodologies for non-Claus sulfur recovery plants, and are finalizing these 

amendments as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 47 
222 

Comment: In §98.253(f)(4), Equation Y-12 is to be used for calculating CO2 emissions from 

sulfur recovery units. However, the equation provides a default carbon content of 0.20 mole 

fraction in the sour gas feed to the sulfur recovery plant. This default carbon content seems very 

high and is not supported by any references. The methodology presented in the API 

Compendium has no default carbon content; it is assumed that each site will develop their own 

factor based on typical operating conditions. API requests to remove the default carbon content. 

Response: Reporters are allowed to develop their own site-specific carbon content and use this 

value in Equation Y-12. However, based on comments we received on the original April 10, 

2009 proposal, many reporters desired to have simple default parameters to use for “smaller” 

emission sources. We see no benefit to removing this default value, and if we did remove it the 

monitoring requirements of the rule would increase because facilities would be required to 

measure the carbon content of this stream rather than rely on the default value. Therefore, we 

are not removing this default parameter. 

CO2 Emissions From Asphalt Blowing 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 48 

Comment: In §98.253(h)(1), Equations Y-14 and Y-15 provide default emission factors of 1100 

tonnes CO2/MMbbl asphalt and 580 tonnes CH4/MMbbl for uncontrolled asphalt blowing. The 

2009 API Compendium presents in Table 5-7 on page 5-34 other default factors for uncontrolled 

emission. The emission factors presented are 1010 tonnes CO2/MMbbl and 555 tonnes 

CH4/MMbbl (converted from bbl basis to MMbbl basis). 

API requests to reconcile values with the API Compendium values since these values were 

derived using data provided by EPA as reference to AP-42. 

Response: We derived the default emission factors of 1100 tonnes CO2/MMbbl asphalt and 580 

tonnes CH4/MMbbl for uncontrolled asphalt blowing based on the data presented in the 2004 

API Compendium, which directly reports the concentrations, AP-42 emission factors, and the 

assumptions used. The 2009 API Compendium appears to cite the same data sources, but only 

presents the emission factors. We cannot derive the values reported in the 2009 API 

Compendium from the concentration data and AP-42 emission factor. We do note that the 

values suggested in the 2009 API Compendium are not significantly different from those 

required for use in Equations Y-14 and Y-15, but the 2009 API Compendium values are reported 

without sufficient background data to understand their derivation. Consequently, as we 

understand the basis of the values required in the GHG reporting rule and have been provided no 

direct evidence that our original calculations (which are based on the data more fully presented 

in the 2004 API Compendium) are incorrect, we are not revising these emission factors in the 

final amendments 
223 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 49 

Comment: In §98.253(h)(2), Equation Y-16 provides the CO2 emissions estimate for asphalt 

blowing controlled by a flare or thermal oxidizer based on a material balance that uses the carbon 

content of the controlled asphalt blown stream. A default value of 2750 tonnes carbon/MMbbl 

asphalt is provided. In comparison, the API Compendium in Equation 5-13 on page 5-35 also 

uses a material balance approach for estimating the controlled asphalt blowing CO2 emissions 

and accounts for the CO2 already in the stream plus the conversion of CH4 to CO2 from the 

controlled combustion. API requests to allow the use of the more comprehensive mass balance 

method using Equation 5-13 on page 5-35 of the 2009 edition of the API Compendium, process. 

Response: We disagree that Equation 5-13 of the API Compendium is a more comprehensive 

approach to estimating CO2 emissions from asphalt blowing controlled by a flare or thermal 

oxidizer. The equation in the 2009 API Compendium does not take into account ethane, propane, 

butane, and heavier organic compounds that exist in the asphalt blowing stream and that will be 

converted to CO2 in the control device. These other compounds, as seen in the data provided in 

the 2004 Compendium, represent a significant mass of carbon in the asphalt stream. While we 

agree that there is a slight low bias in Equation Y-16 as the 0.98 factor arguably should not be 

applied to the CO2 carbon, we find that Equation Y-16 is much more appropriate than Equation 

5-13 of the 2009 Compendium. We do agree that the 0.98 factor should not apply to the CO2

pre-existing in the vent stream, but we are also concerned with increasing the measurement data 

requirements (for those using facility-specific carbon emission factors). Therefore, we proposed 

to retain Equation Y-16 (re-numbering it as Y-16a) and also included a new Equation Y-16b that 

does not apply the 0.98 conversion factor to the CO2 pre-existing in the vent gas prior to the 

control device. These provisions are being finalized as proposed. 

Other Equations 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 35 

Comment: API supports the revision of Equation Y-19 – Clarified the equation for process vent 

emissions allowing the use of measurement data, process knowledge, or engineering estimates to 

determine the volumetric flow rate and mole fraction of GHG. 

Response: EPA thanks the commenter for the input. We have finalized the amendment, as 

proposed. 
224 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 50 

Comment: In §98.253(i)(1), Equation Y-18 fails to correct the gaseous emissions for 

temperature. The equation does contain the pressure correction but left out the corresponding 

temperature correction. Since the equation is based on the actual volume vented from the coke 

vessel, both the pressure and temperature of the vessel should be corrected with the applicable 

molar volume correction factor used for the applicable conditions. If the degassing occurs above 

standard temperature, the current Equation Y-18, as provided in the final rule, would 

overestimate emissions. 

The amended equation Y-18 should read: 

CH4 = (Current Equation Y-18) * [(Tstd + 460)/ (Tsteam + 460)] 

Where, 

Tstd = temperature of gas (degrees Rankine) at standard conditions, and 

Tsteam = temperature of the gas (degreed Rankine) in the delayed coking vessel 

Equation Y-18 should be corrected to include the applicable gas law temperature correction and 

the appropriate molar volume correction factor that is applicable for the standard conditions 

used. 

Response: We disagree that Equation Y-18 will underestimate the emissions from the delayed 

coking unit. While we acknowledge that the equation does not have the ideal gas law temperature 

correction, it also does not account for additional steam generated as the pressure is lowered. We 

originally developed this equation based on correlations with actual flows from this vent. In the 2009 

proposal, we also did not include a correction factor for the void fraction. We added this correction 

factor in the 2009 final rule, but this approach tended to cause Equation Y-18 to slightly 

underestimate the actual emissions from the test data. Including the temperature correction factor 

requested would further bias the estimates from Equation Y-18 low. Actually, at higher 

depressurization temperatures, more steam is generated during the venting process, thereby 

increasing the flow from the system rather than lowering the flow as the “correction” suggested by 

API would yield. Thus, we intentionally omitted the temperature correction factor as a means to 

account for the added flow caused be steam generation as the pressure of the system is lowered and 

to provide a better correlation of the available data. We considered including a flow term to account 

for the additional gas generated from the system, but this would significantly increase the complexity 

of the equation and would require numerous additional monitoring variables. Consequently, we are 

not revising Equation Y-18 at this time. 

We note that direct measurements of the emissions from this vent are allowed within the existing 

provisions of the rule if a more accurate estimate of these emissions is desired by the reporter. 
225 

Calculating GHG Emissions 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 27 

Comment: Revise §98.33(a)(3)(iii) Equation C-5 and §98.253(b)(1)(ii)(B) Equation Y-2 to 

revise the term “MVC” to be consistent with changes proposed in other parts of the rule. 

Additionally, revise the reporting requirements at §98.36(e)(2)(iv)(B). 

Response: Please see the response to comment EPA-HQ-OAR-2008-0508-2402.1, excerpt 2, in 

Section 3 of this document, for the response to this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 33 

Comment: The amended Subpart Y provided an alternative Molar Volume Correction (MVC) 

term of 836.6 scf/kg-mole at 60 F and 14.7 psia. API supports this revision and requests that this 

alternative MVC be provided in all subparts that address gaseous streams. 

Response: Please see the response to comment EPA-HQ-OAR-2008-0508-2402.1, excerpt 2, in 

Section 3 of this document, for the response to this comment. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 17 

Comment: One of the goals of the GHG reporting rule is to enable regulators to compare 

emission sources and efficiently reduce GHG emissions. EPA’s proposal to allow refineries to 

report CO2 emissions from refinery fuel gas combustion at smaller process heaters using Tier 1 

and Tier 2 methodologies will undermine this goal. The proposal will allow refiners to estimate 

CO2 emissions from process heaters that 1) have capacities less than 30 mmBtu/hr or average 

annual flow rates less than 345 scfm and 2) no flow meter installed based on sporadic sampling 

of higher heating value (HHV) or fixed assumptions and company records about fuel 

consumption. 75 FR 48772. Tier 3 requires refineries to report emissions by measuring flow 

rates and carbon content. 40 C.F.R. § 98.33(a)(3). 
226 

The Tier 1 and 2 methodologies are inaccurate because they do not account for the variable 

carbon content of refinery fuel gas. The Tier 1 assumes a constant HHV value as a proxy for 

carbon content. Id. at § 98.33(a)(1). This will result in inaccurate reporting because HHV 

significantly fluctuates in refinery fuel gas. While Tier 2 requires refiners to report emissions 

based on periodic HHV measurements this is not sufficient. 40 C.F.R. § 98.33(a)(2). HHV 

measures hydrogen content as well as carbon content. Petroleum Refining Support Document at 

20. Hydrogen in refinery fuel gas does not contribute to CO2 emissions. Id. at 20. Therefore, 

either of these methodologies will result in inaccurate CO2 emissions reporting. 

EPA’s justification for this change is that it will ease the burden on smaller refiners and that 

these refiners only account for 2% of the national refining capacity. 75 FR 48772. Implied in 

this statement is that these emissions are too small to worry about. While it logically follows that 

the process heater in question produces a small percentage of refinery emissions, it is not 

apparent that these emissions are negligible from a national inventory standpoint. Leaving the 

quantity of emissions aside, EPA’s justification misses the point. The goal of collecting this data 

is to compare emission rates between refineries. Because most of these smaller process heaters 

are at smaller refineries, it will be difficult to compare GHG emission rates of small refineries 

against large refineries. It will also be difficult to compare CO2 emission rates of small process 

heaters against large process heaters. Without the ability to make these comparisons, EPA won’t 

be able to make educated decisions regarding the most efficient targets for reducing GHGs. 

Therefore, EPA must insist that refineries use Tier 3 methodologies on all process heaters. If 

EPA does conclude that Tier 3 methodologies are not warranted for these smaller process 

heaters, EPA should at least require Tier 2 methodologies. 

Response: We agree that one of the goals of the GHG reporting rule is to enable regulators to 

compare emission sources and develop effective climate policies; however, we disagree that the 

limited flexibility provided in the proposed amendments for small process heaters or small fuel 

gas lines that are not equipped with flow meters will undermine this goal. First, some small 

process heaters will continue to use Tier 3 because they have a flow meter either at the process 

heater or at an upstream common pipe, as indicated by other comments received requesting a 

broader exclusion for these small process heaters. Thus, we will be collecting some data by 

which to more accurately characterize smaller process heaters. 

Second, we proposed to provide additional flexibility in calculating emissions for certain small 

process heaters or fuel gas lines because, based on the Agency's experience with the fuel gas 

standards in 40 CFR part 60 subpart J, we did not expect that there would be a significant 

number of fuel gas lines that were not part of a centralized fuel gas system monitor. We 

estimated the cost of installing fuel flow meters only on larger, common pipe configurations. 

For the small number of large (centralized) fuel gas lines, we determined that the Tier 3 

monitoring requirements were appropriate and justified. However, when we consider the cost 

associated with imposing Tier 3 requirements on small process individual process heaters or fuel 

gas lines (e.g., those that are not part of a centralized fuel gas system), we arrive at a different 

conclusion. We estimate the cost of installing fuel gas flow meters on individual small fuel gas 

lines would exceed $0.50 per ton of CO2 reported, which we determined to be unacceptable. (As 

shown in Table 5-2 of the Regulatory Impact Analysis for the Mandatory Reporting of 

Greenhouse Gases Final Rule (GHG Reporting) Final Report (EPA-HQ-OAR-2008-0508) 
227 

September 2009, the cost/ton of CO2 emissions reported is significantly lower across all of the 

subparts in the rule.)Therefore, we provided this limited flexibility for small process heaters or 

fuel gas lines that do not have a flow meter installed in the line or in an upstream common pipe. 

While we estimated the potential impact of this flexibility by considering the emissions produced 

by all process heaters with a capacity of less than 30 MMBtu/hr, we note that this is the 

maximum potential impact and that a large number of these small process heaters will not 

qualify for the limited flexibility. 

Third, it is likely that some facilities will elect to use Tier 2 for high hydrogen- or nitrogencontaining process gas streams that are not well characterized by the Tier 1 default Btu content 

for fuel gas. While we consider the Tier 1 default Btu content for fuel gas in Table C-1 to be 

representative of the primary sources of fuel gas within the refinery, the Tier 1 defaults will 

typically overstate the emissions from these high hydrogen- or nitrogen-containing process gas 

streams. Consequently, some facilities may elect to use Tier 2 rather than overstate these 

emissions. However, we decided not to require Tier 2 for these sources because both Tier 1 and 

Tier 2 are expected to have significant uncertainties. Given the high uncertainties of both Tier 1 

and Tier 2, we conclude that there is little benefit for requiring Tier 2 over Tier 1 in this situation 

because the higher uncertainty of either method is acceptable based on the very small percentage 

of combustion emissions represented by the small process heaters or fuel gas lines that do not 

have flow meters installed. 

In summary, we are finalizing the amendments to allow certain small process heaters and fuel 

gas lines to use Tier 1 or Tier 2, in lieu of Tier 3, monitoring requirements as proposed. When 

flow meters are installed on small process heaters or fuel gas lines (or an upstream common 

pipe), the Tier 3 methodology must be followed. When flow meters are not installed, Tier 3 

becomes too costly when considering the relatively small quantity of CO2 emissions. Therefore, 

when flow meters are not installed on small process heaters or fuel gas lines, either Tier 1 or Tier 

2 may be used. 

Monitoring and QA/QC Requirements 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment Excerpt Number: 48 

Please see the summary and response to comment EPA-HQ-OAR-2008-0508-2357.1, 

excerpt 47, in Section 9 of this document, for the summary and response to parallel comments 

made on the monitoring and QA/QC requirements in subparts X and Y. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
228 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 14 

Comment: The October 2009 final rule required exhaust gas flow meters used to comply with 

the §98.253(c)(2)(ii) for catalytic cracking units to be installed, operated, calibrated and 

maintained according to the Refinery MACT [Petroleum Refinery NESHAP] requirements in 

§63.1572(c). EPA proposes to revise §98.254(f) to also require exhaust gas flow meters used to 

comply with the §98.253(j) requirements for process vents not covered in §98.253(a) through (i) 

to be installed, operated, calibrated and maintained according the Refinery MACT requirements 

in §63.1572(c). 

The Refinery MACT requirements in §63.1572(c) contain provisions that are more stringent than 

the monitoring and QA/QC requirements throughout the GHGRP. For example, §63.1572(c) 

requires each monitoring system to have valid hourly average data from at least 75% of the hours 

during which the process operated and to complete a minimum of one cycle of operation for each 

successive 15-minute period with a minimum of four successive cycles of operation to have a 

valid hour of data (or at least two if a calibration check is performed during that hour or if the 

continuous parameter monitoring system is out-of-control). Since the flow monitoring 

requirements for Refinery MACT in §63.1572(c) were established to demonstrate compliance 

with emission limits, they should not be used as a template for requirements of flow metering for 

GHG reporting. Hence, the process vent exhaust flow meter requirements should be consistent 

with the requirements for other gas flow meters throughout the GHGRP such as flare and sour 

gas flow meters. 

API requests that EPA not revise §98.254(f) but instead revise §98.254(c) for flare and sour gas 

flow meters to also include flow meters used to comply with §98.253(j) [process vents not 

covered in §98.253(a) through (i)]. 

Response: Please see Section II.N of the preamble to the final rule amendments for the 

response to this comment. 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.1 

Comment Excerpt Number: 18 

Comment: EPA is proposing to allow refineries to use any chromatographic analysis to 

determine flare gas composition and HHV provided the gas chromatograph is operated according 

to the manufacturer’s specifications. 75 FR 48774. EPA has already provided five different 

methods to measure flare gas composition and another five methods to measure flare gas higher 

heating value. 40 C.F.R. § 98.254(d)-(e). Different methods for chromatographic analysis may 

provide emission measurements that are not comparable. Because this exception potentially 

allows as many methods as there are manufacturers, it will make comparative analysis that much 

more difficult. As a result, EPA and the public will be in the dark about comparative emission 

rates between different refineries. We urge EPA to abandon this exception. 
229 

Response: We added the flexibility in the proposed amendments to use other gas 

chromatographic methods to acknowledge the fact that there may be other appropriate methods 

that reporters could use in addition to those we included in the October 30, 2009, final rule. 

However, we disagree with the assertion that the flexibility provided in the proposed 

amendments would lead to incomparable results. The mere fact that different methods may be 

used to analyze data does not per se mean the resulting data cannot be compared. These different 

gas chromatography methods should yield comparable results provided the appropriate 

calibrations and quality assurance checks are conducted. Gas chromatography methods other 

that those we specifically identified can provide accurate compositional analyses provided the 

appropriate calibrations and quality assurance checks are conducted. Therefore, when another 

gas chromatography method is used, the proposed amendments requires the chromatograph be 

operated, maintained and calibrated according to the manufacturer’s instructions and that the 

methods be documented in the facility’s Monitoring Plan. By including these additional 

requirements on these “other” chromatography methods, the data received should be comparable 

to data generated by the other methods specifically listed in the rule. Other than conclusory 

allegations to the contrary, the commenter does not provide any support for its objection. 

Consequently, we are finalizing this amendment as proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 36 

Comment: API supports the revision of §98.254(c) – Deleted list of list of procedures for flare 

and sour gas meters. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 37 

Comment: API supports the revision of §98.254(d) – Allows the use of gas chromatograph 

analyses to determine the gas composition and molecular weight. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Commenter Name: Karin Ritter 
230 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 38 

Comment: API supports the revision of §98.254(e) – Allows the use of gas chromatograph 

analyses to determine the flare gas HHV. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Other Subpart Y Comments 

Commenter Name: Michael Hannan 

Commenter Affiliation: Williams Olefins LLC 

Document Control Number: EPA-HQ-OAR-2008-0508-2357.1 

Comment: The commenter noted that the proposed amendments to 40 CFR 98.7 would add a 

new paragraph 98.7(e)(43) to incorporate by reference ASTM D2503-92 (Reapproved 2007) 

Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 

Thermoelectric Measurement of Vapor Pressure, for §98.254(d) of Subpart Y. The commenter 

noted that this method is already listed in 40 CFR 98.7(e)(15); therefore, this paragraph only 

needs to be amended to add §98.254(d), and a new paragraph does not need to be added to 

§98.7(e). 

Response: The commenter is correct. Addition of ASTM D2503-92 should be done by 

amending §98.7(e)(15).

Commenter Name: Jamie Mann 

Commenter Affiliation: Suncor Energy USA, Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2389.1 

Comment Excerpt Number: 4 

Comment: EPA states that this proposed rule does not contain a Federal mandate that may result 

in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, 

or the private sector in anyone year. EPA has estimated that, overall, the proposed revisions do 

not significantly change the overall costs of compliance with Part 98. The proposed amendments 

include providing additional flexibility for reporters, clarifying existing reporting requirements, 

and requiring reporting of information already required to be collected under Part 98. 

EPA estimates that the cost for all reporters in reviewing the proposed rule and determining if, 

and if so how, it applies to their facility, is approximately $2.5 million in the first year. 

Considering the additional flexibilities proposed, in sum, EPA has estimated that the proposed 

rule, if finalized, would reduce the burden to reporters as compared to the 2009 final rule. Thus, 
231 

this rule is not subject to the requirements of sections 202 or 205 of Unfunded Mandates Reform 

Act (UMRA). For more information on the cost analysis, please refer to the memorandum titled 

"Mandatory Greenhouse Gas Reporting: Changes in National Cost Estimates Associated with the 

Proposed Notice of Revisions" found in the docket at (EPA-HQ-OAR-2008-0508). 

Suncor Energy U.S.A., Inc. (Suncor) believes that the revised cost analysis does not appear to 

accurately represent the costs to either install multi-variable transmitters on flow meters to 

measure temperature, pressure and flow at the same location for every flow meter or the costs 

associated with developing the documentation to demonstrate that the use of common 

temperatures and pressures satisfies the rule (i.e., the ability to compensate for all ambient 

conditions on a daily basis for every flow meter). 

Suncor has reviewed the memorandum titled" "Mandatory Greenhouse Gas Reporting: Changes 

in National Cost Estimates Associated with the Proposed Notice of Revisions" for the October 

30, 2009 rule, in which EPA indicated that cost impacts to a single petroleum refinery was as 

follows [Note: Preamble of the MRR, Page 56363, Table VII "Estimated Covered Entities, 

Emissions, Costs by Subpart (2006$)"]: 

(1) $10,666/yr (5 yr annualized cost $1.6 M /150 refineries) 

(2) $40,667 year 1 costs ($6.1 M /150 refineries) 

Recent data presented in a white paper [Note: “A Survey of Refinery MRR GHG Emission 

Inventory Efforts," Matthew Harrison, URS Corporation] at the National Petrochemical and 

Refiners Association (NPRA) Conference indicates that the average cost of implementing the 

GHG Mandatory Reporting Rule, actually is much higher than was projected by EPA. According 

to the author of the abovementioned white paper "the survey clearly shows that actual incurred 

costs have far exceeded EPA’s OMB approved estimates by almost an order of magnitude for 

year 1 (a factor of 8.8 higher) ... Capital costs are clearly higher than EPA projected. Even 

without the capital costs, each refinery was spending almost $112,000 in internal and external 

costs for MRR compliance to date." 

Given this background, coupled with site-specific cost projections, Suncor requests that EPA 

reevaluate the assumptions contained in its cost analysis. Suncor also requests that EPA 

reconsider whether the total costs to the private sector to implement the proposed updates to the 

rule is greater than the $100 million threshold under the Unfunded Mandates Reform Act. 

Response: We maintain that the costs of the proposed amendments are far less than $100-million 

in any one year. Please note that the costs are specific to the proposed amendments and not to 

the aggregate cost of the Oct. 30, 2009, final mandatory reporting rule. We agree that the final 

rule posed costs exceeding $100-million in any one year and we already have complied with the 

requirements of the Unfunded Mandates Reform Act in the promulgation of that final rule. 

However, the amendments we proposed do not increase burden on the regulated community. On 

the contrary, we believe that the amendments reduce the burden of the final rule and, therefore, 

we only estimated the incremental costs of the amendments as those associated with reading and 

understanding the amendments. The commenter’s particular concern is that the cost analysis (for 
232 

the proposed amendments) does not appear to accurately represent the costs to either install 

multi-variable transmitters on flow meters to measure temperature, pressure and flow at the same 

location for every flow meter or the costs associated with developing the documentation to 

demonstrate that the use of common temperatures and pressures satisfies the rule (i.e., the ability 

to compensate for all ambient conditions on a daily basis for every flow meter). 

First, we note that we interpreted the final rule to require measurement of temperature and 

pressure at the same location as the flow meter (when needed to correct flow to standard 

conditions). Second, we relaxed the flow monitoring requirements to allow use of temperature 

and pressure monitors at locations other than the flow meter. We did not need to estimate costs 

associated with developing the documentation to demonstrate that the use of common 

temperatures and pressures satisfies the rule (i.e., the ability to compensate for all ambient 

conditions on a daily basis for every flow meter) because the reporter could always elect to 

install and use temperature and pressure monitors at the flow monitor as required in (and 

included in the costs of) the final rule. That is, we assume that reporters will elect to use remote 

temperature and pressure monitors only when they result in a cost savings compared to installing 

the temperature and pressure monitors at the flow meter. As such, we consider that the 

amendment specifically cited by the commenter is an example of an amendment that actually 

reduces the burden of the final rule. 

The commenter cited our previous cost estimates, suggesting that the previous cost estimates 

were understated. First, this argument is not really relevant with respect to whether or not the 

proposed updates to the rule cause an increase in the costs (relative to the final rule) greater than 

the $100 million threshold under the Unfunded Mandates Reform Act. To the extent the 

commenter is challenging the costs from the original 2009 final rule, that comment is outside the 

scope of this rulemaking. Second, actual costs incurred by certain reporters can be significantly 

higher than our estimates without our estimates being understated. The costs we develop are 

based on the costs needed to minimally comply with the rule and are averaged over all refineries. 

Some refineries in our analysis had projected costs much higher than the average compliance 

costs. Furthermore, reporters are free to elect other, higher cost monitoring alternatives than 

those minimally required. For example, to comply with the Tier 3 monitoring requirements for 

fuel gas, the reporter may elect to install a continuous on-line gas chromatograph (GC) rather 

than to take the required weekly grab samples. The costs associated with on-line GC will be 

greater than those for weekly sampling, but the continuous monitor may also provide for safer 

operation and improved process control, so the reporter elects to spend more than the rule would 

require for this reporting element. As another example, some reporters may elect to monitor at 

individual combustion sources rather than at a common pipe because monitoring at the 

individual unit also supplies the reporter with additional information with which to evaluate the 

performance and efficiency of that specific unit. Additionally, while the rule requires reporting 

at the facility level, some corporations may impose additional levels of review, recordkeeping, 

reporting, and even monitoring requirements as part of corporate oversight. Our cost estimates 

do not include costs associated with these additional layers of management or optional 

information. Thus, when facilities report actual costs incurred with complying with a rule, they 

generally include the total costs incurred, including additional costs associated with facility or 

corporate preference rather than those strictly mandated by the rule. As a result, these facility-
233 

reported costs can exceed the costs estimated by EPA without indicating that EPA’s mandated 

costs estimate is inaccurate. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 18 

Comment: API supports retaining the previously promulgated equations in 40 CFR 98.253 and 

the flexibility to use either of the methods presented. If EPA were to replace the original 

equations with those proposed as part of this amendment, refineries would have to modify their 

data management systems which, this late in the reporting year, will impact the ability to meet 

the March 31 reporting deadline. 

Response: We agree and are finalizing the amendments as proposed to provide the new 

equations as alternatives to the existing equations. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 42 

Comment: One of the methodologies provided in §98.253(l) for calculating emissions from 

equipment leaks is to use Equation Y-21 and enter into it the number of specified process units 

(catalytic cracking units, coking units, hydrocracking units, distillation columns, etc). For 

distillation columns, it is not clear if columns associated with the other process units listed are to 

be counted separately; namely did EPA intend to include distillation units among the rest of the 

units, or did it actually mean distillation columns? For example, if a refinery has one catalytic 

cracking unit and the catalytic cracking unit includes a depropanizer column, is the column 

considered part of the catalytic cracking unit so NPU1 in the equation equals 1, or is the column 

considered a separate process unit so NPU1 in the equation equals 2? EPA should clarify the 

default method to state that it applies to distillation units and not to individual distillation 

columns that might be part of other units. 

Response: EPA thanks the commenter for the input. No rule change has been made as a result 

of this comment. The changes to Part 98 suggested by the commenter are outside the scope of the 

specific amendments proposed for public comment in the Federal Register notice of August 11, 

2010. We will be providing guidance on Part 98 to address the commenter’s concerns. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 43 
234 

Comment: In section §98.253(k) Equation Y-20 provides a calculation method for uncontrolled 

blowdown systems. The equation applies a default emission factor to the total volume of crude 

oil and intermediate products that enters the refinery for processing. Neither the rule nor the 

Petroleum Refining TSD provides any reference or origin for the default CH4 emission factor of 

137,000 scf CH4/MMbbl that is provided with the equation. 

EPA uses this same factor in the national inventory (Table A-124 in the 2006 inventory) and the 

source cited in EPA’s inventory is a 1999 report "CH4 Emissions for the U.S. Petroleum 

Industry". The 1999 report was an attempt to mimic the 1996 GRI/EPA study, but for the 

petroleum side, and without any new measurements (i.e., relying only on published information). 

The 1999 EPA report bases the CH4 factors for uncontrolled refinery blowdown systems on a 

1977 report "Revision of Emission Factors for Petroleum Refining" (EPA-450/3-77/030). The 

1977 report aimed to update VOC emissions factors and provided a factor in terms of 

hydrocarbon emissions from refinery blowdown activities. For the 1999 EPA report, the authors 

assumed 1% CH4 content and converted the VOC based factor to a CH4 basis. 

The 1977 VOC factor and its 1999 update to CH4 clearly do not represent current industry 

practices as far as refinery blowdown systems, since many rules have been put in place since 

then to control VOC emissions from refineries (for example, refinery MACT rules). 

Also the factors cited were developed for “top down” assessment of CH4 emissions from the 

refining sector and are not applicable for use in the context of facility reporting where EPA’s 

emphasis is on acquiring quality data that is based on current operational practices. 

API is requesting EPA to clarify what sources EPA view as being included in this category of 

uncontrolled refinery blowdown systems, since refinery industry vents are so heavily controlled 

already. API recommended revising or discarding Equation Y-20 and the requirement to report 

emissions from refinery blowdown systems since they are insignificant, or at most a very small 

percentage of GHG emissions in refineries. 

Response: The term "blowdown" is defined in §98.6. The distinction of controlled and 

uncontrolled blowdown system is provided in §98.253(j). Thus, an "uncontrolled blowdown 

system" refers to the system used to manage gases and/or liquids that are generated due to 

emptying or depressuring a vessel (which typically includes knock-out pot for collecting and 

recovering entrained liquids) that subsequently discharges any uncondensed gas streams directly 

to the atmosphere. 

We do anticipate that most blowdown systems will be controlled and that some refineries may 

not have any uncontrolled blowdown systems. 

We acknowledge that there are limited data available for estimating the emissions from these 

"atmospheric vents" from blowdown systems, which highlights the need for obtaining better data 

and to require reporting of these emissions. We also note that the method for process vents 

(Equation Y-19) can be used for these blowdown vents. We are hopeful that better data for 

uncontrolled blowdown systems may be collected due to facilities utilizing this option. 
235 

11. SUBPART AA - PULP AND PAPER MANUFACTURING 

No public comments were received on the proposed amendments to Subpart AA. 

12. SUBPART NN - SUPPLIERS OF NATURAL GAS AND NATURAL GAS 

LIQUIDS 

EPA proposed amendments to the applicability criteria for this source category that are found in 

40 CFR part 98, subpart A, at §98.2(a)(4)(iii)(B). These comments and EPA’s responses are 

found in Section 1 of this document. 

13. SUBPART OO - SUPPLIERS OF INDUSTRIAL GREENHOUSE GASES 

Monitoring and QA/QC Requirements 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 10 and 11 

Comment: Mexichem requests that the EPA not mandate measurement of the concentration of 

all fluorinated GHGs coming out of the production process if the mass coming out of the process 

includes only one fluorinated GHG product and low concentration constituents, or allow the use 

of alternative methods for the determination of the concentration of fluorinated GHGs coming 

out of the process. 

The mass of fluorinated GHGs coming out of Mexichem’s production process consists of only 

HFC-134a and impurities that meet the definition of "low concentration constituents" (<0.1% by 

mass). Therefore, under the proposed rule [amendments] the mass of all material coming out of 

the process would be considered HFC-134a. The proposed rule does not require that the 

concentration(s) of low concentration constituents be measured, but also does not exclude the 

measurement of the concentration of one fluorinated GHG present in concentrations above the 

low concentration constituent threshold (0.1% by mass). Mexichem Fluor requests that the final 
236 

rule exclude the measurement of fluorinated GHGs coming out of the process when the mass 

includes only one fluorinated GHG present above the low concentration constituent threshold. 

Mexichem currently, and for the history of the site, has determined the purity of its product by 

using AHRI 700C-2008: Appendix C to AHRI Standard 700 - Analytical Procedures for AHRI 

Standard 700-06 (Determination of Purity of New and Reclaimed R-22, R-32, R-113, R-134a, R141b, R-142b, and R-245fa by Capillary Column Gas Chromatography). This method is 

applicable to the determination of impurities typically present in the commercially manufactured 

and reclaimed refrigerants referenced above. The concentration of product is determined by 

subtracting the concentrations of the impurities. This method is used on each batch tank of 

product manufactured at the site. Mexichem would need to invest capital in order to utilize the 

methods referenced in the proposed rule and the additional quality control criteria of those 

methods would result in additional and unnecessary burden. As the method currently used by 

Mexichem is an industry standard, Mexichem requests that alternative methods, such as industry 

standards, be allowed in the final rule. 

Response: We are finalizing the proposed requirement at §98.414(n) to measure the 

concentrations of all the fluorinated GHGs, other than low-concentration constituents, in the 

product. While the rule excludes low-concentration constituents from the requirement to measure 

and report the concentrations of the fluorinated GHGs coming out of the process, this is in 

recognition of the impracticality of measuring low concentrations of fluorinated GHGs. The 

exclusion is not intended to exempt product streams from concentration measurements because 

facilities believe that these streams contain only the primary constituent (e.g., HFC-134a in the 

commenter’s example) and low-concentration constituents. The reason the measurement is 

required is either to verify that the concentrations of the other fluorinated GHGs are in fact low 

enough to qualify them as low-concentration constituents (i.e., below 0.1 percent), or to identify 

and quantify concentrations of fluorinated GHGs that are not low-concentration constituents. 

Also as proposed, we are providing flexibility to facilities to use "other analytical methods 

validated using EPA Method 301 or some other scientifically sound validation protocol." As a 

widely-used industry method, the method cited by the commenter has probably been validated 

with the analytes of interest at the concentrations of interest using a scientifically sound 

validation protocol. However, if the facility could not confirm and document this, the facility 

could validate the method itself using EPA Method 301 or another scientifically sound validation 

protocol, or the facility could document that the method is essentially identical to one of the 

methods listed at §98.414(n). 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 9 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 
237 

Comment Excerpt Number: 9 

These two commenters submitted identical comments on this subject. 

Comment: American industry produces hundreds of thousands of tons of fluorinated gases, 

including HFCs, PFC, SF6, NF3, HFEs, CFCs, and HCFCs annually – on the order of 440,000 

tons a year, according to EPA. [Footnote: See EPA, Technical Support Document (Updated) for 

Emissions from Production of Fluorinated Gases (Mar. 22, 2010) (Fluorinated Gas TSD”) at 4.] 

Given the persistence of such gases in the atmosphere and their high global warming potential 

(“GWP”), these gases, if emitted, would translate into hundreds of millions of tons of CO2

[equivalents]. Data on the supply of these gases are therefore critical, and we are concerned that 

some of EPA’s proposed revisions pursuant to its settlement agreement with the American 

Chemistry Council sacrifice data accuracy for this important sector. 

Based on its settlement agreement, EPA proposes to exclude from monitoring, reporting, and 

recordkeeping requirements fluorinated GHGs that occur as low-concentration constituents of 

fluorinated GHG products. For fluorinated GHG production and export, EPA proposes to define 

a low-concentration constituent as a constituent that occurs in the product in concentrations 

below 0.1 percent by mass. For fluorinated GHG import, EPA proposes to define lowconcentration constituents as those that occur in concentrations below 0.5 percent by mass. 

Given the high GWP of these gases, however, even relatively small masses of these gases could 

have significant global warming impacts. In its 4th Assessment Report, IPCC recognized that 

these gases “have extremely long atmospheric lifetimes (thousands of years) and GWP values 

(thousands of times those of CO2) resulting in virtually irreversible atmospheric impacts.” 

Given EPA’s emphasis on CO2e measurements, we are concerned that EPA’s reliance on a massbased de minimis exclusion here improperly exempts a significant amount of emissions from 

reporting. We ask the Agency to provide additional information on the GWPs of these lowconcentration constituents and the emissions affected by this proposed change. If significant 

emissions are lost from the rule as a result, EPA should not make the change. 

We are likewise concerned with the Agency’s proposal to exclude fluorinated GHGs that are 

emitted or destroyed before the fluorinated product is packaged for sale. Emissions from the 

fluorinated GHG production process are significant, accounting for roughly 10.6 mmtCO2e 

annually. EPA accounts for many of these emissions under Subpart L, fluorinated GHG 

production, and EPA notes that these intermediate emissions might more properly fall under this 

subpart because they are not placed into the stream of commerce. Regardless of subpart under 

which facilities are required to report these emissions, we encourage the Agency to ensure that 

these intermediate emissions are fully captured under the reporting rule and ask that it document 

the magnitude of these emissions, the identities and GWPs of compounds in this group, and the 

emissions affected by the proposed change. Again, if significant emissions are lost from the rule 

as a result, EPA should not make the change. 

Response: Please see Section II.Q of the preamble to the final rule amendments for the response 

to this comment. 
238 

Definitions 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 8 

Comment: It is not clear whether an intermediate that is created and transformed in a single 

process with no storage of the intermediate is required to be reported under 40 CFR 98.416(a)(2). 

Mexichem believes that intermediates that meet this definition are not to be reported under 

§98.416(a)(2) because the proposed definition for the source category specifically excludes the 

“creation of fluorinated GHGs that are released or destroyed at the production facility before the 

production measurement at §98.414(a).” Mexichem requests that the EPA clarify in the final rule 

that §98.416(a)(2) only applies to isolated intermediates. 

Response: Under subpart OO, we are not requiring reporting of either the production or the 

transformation of intermediates that are created and transformed in a single process with no 

storage of the intermediate. The definition of “produce a fluorinated GHG” states: “Producing a 

fluorinated GHG does not include . . . the creation of intermediates that are created and destroyed 

in a single process with no storage of the intermediates.” We excluded such intermediates from 

the definition of “produce a fluorinated GHG” because it would be impracticable to measure and 

report their production. It would be similarly impracticable to measure and report their 

transformation. In addition, monitoring and reporting the transformation of fluorinated GHGs 

that were never counted as produced would not enhance our understanding of the fluorinated 

GHG supply; instead, it could lead to an underestimate of that supply 

Other Subpart OO Comments 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 2 

Comment: The Subpart OO applicability provisions clearly delineate how fluorochemical 

manufacturers identify and report fluorinated greenhouse gases (“GHG”) that have entered or 

exited commerce. 

Response: EPA thanks the commenter for the input. 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 7 
239 

Comment: Mexichem generally supports the proposed changes to Subpart OO. We believe these 

proposed changes provide clarity and will ensure consistency in reporting under this subpart. 

Response: EPA thanks the commenter for the input. 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 9 

Comment: ACC supports all of EPA’s proposed changes to subpart OO. If finalized as 

proposed, these changes will address the more serious issues identified by producers of 

fluorinated GHGs with the original subpart OO language. 

Response: EPA thanks the commenter for the input. 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 9 

Comment: The data required under 40 CFR 98.416(a)(8) and (9) are not relevant to Subpart OO 

and should not be reported there under. 40 CFR 98.416(8) and (9) require the reporting of total 

mass in metric tons of each reactant fed into the F–GHG or nitrous oxide production process, by 

process and total mass in metric tons of the reactants, by-products, and other wastes permanently 

removed from the F–GHG or nitrous oxide production process, by process. The EPA has made it 

clear that they are proposing to modify Subpart OO to “explicitly exclude the “creation of 

fluorinated GHGs that are released or destroyed at the production facility before the production 

measurement at § 98.414(a).” 

The data required under §98.416(a)(8) and (9) are relevant to the creation of fluorinated GHGs 

before the production measurement at §98.414(a) and therefore should not be reported under 

Subpart OO. Mexichem requests that these reporting requirements be removed from the final 

rule. 

Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. However, for a discussion of 

the rationale behind the reporting requirements at 40 CFR 98.416(a)(8) and (9), please see the 

response to comments document for subpart OO for the October 30, 2009 final Mandatory 

Reporting Rule, (Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 

Comments, Subpart OO—Suppliers of Industrial Greenhouse Gases), comment number EPAHQ-OAR-2008-0508-0408.1, excerpt 24. 
240 

14. SUBPART PP - SUPPLIERS OF CARBON DIOXIDE 

Calculating CO2 Supply 

Commenter Name: Tom Siegrist 

Commenter Affiliation: Koch Nitrogen Company LLC (KNC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2364.1 

Comment Excerpt Number: 3 

Comment: EPA’s proposal to allow suppliers that supply CO2 in containers to calculate the 

annual mass of CO2 supplied in containers by using weigh bills, scales, load cells, or loaded 

container volume readings, as an alternative to flow meters, reduces the reporting burden while 

maximizing reporting flexibility. (75 FR 48779) 

EPA concluded that measurements made using weigh bills, scales, load cells, or loaded container 

volume readings would meet the level of data quality and accuracy needed by EPA (75 FR 

48779). This proposed approach would also accurately reflect the quantity of CO2 actually sent 

off-site for commercial use, while providing reporters with flexibility as to their point of 

measurement for compliance purposes. Koch Nitrogen Company, LLC (KNC) supports EPA’s 

proposal to accept alternative points and methods of measurement. 

Response: EPA thanks the commenter for the input. We have finalized the amendments as 

proposed. 

Equation PP-1 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 7 

Comment: Proposed §98.423(b) allows CO2 reporters supplying product in “containers” to 

utilize calibrated weigh scales to determine the mass of CO2 supplied into the market. Please 

clarify that “containers” may include, in addition to common packaging cylinders, tank trailers. 

One Arkema facility ships CO2 in tank trailers by truck, and could readily utilize the proposed 

container reporting system as a primary or alternate supply reporting system. 

Response: EPA is clarifying here that containers include tank trailers. 

Equation PP-2 

Commenter Name: Tom Siegrist 

Commenter Affiliation: Koch Nitrogen Company LLC (KNC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2364.1 
241 

Comment Excerpt Number: 4 

Comment: EPA’s proposal to remove the requirement that CO2 measurement be made prior to 

subsequent purification, processing, or compression correctly reflects the real-world situation 

where such a location would not accurately reflect the quantity of CO2 actually available for offsite commercial use (75 FR 48779). 

The current regulatory language could be interpreted to require that facilities measure CO2 flow 

prior to purification, processing, or compression, even if a portion of that flow is diverted for onsite use downstream of purification, processing, or compression. Measurement at the currently 

required point in the process would over-estimate the amount of CO2 available for off-site 

commercial use. EPA’s proposal would eliminate this problem. Whereas EPA has concluded that 

measurements made after purification, processing, or compression would meet the level of data 

quality and accuracy needed for this subpart (75 FR 48779), Koch Nitrogen Company, LLC 

(KNC) supports the proposed removal of language requiring upstream measurement. 

Response: EPA thanks the commenter for the input. The final rule removes the requirement that 

CO2 measurement be made prior to subsequent purification, processing, or compression. 

Commenter Name: Tom Siegrist 

Commenter Affiliation: Koch Nitrogen Company LLC (KNC) 

Document Control Number: EPA-HQ-OAR-2008-0508-2364.1 

Comment Excerpt Number: 5 

Comment: EPA’s proposal to require that the CO2 flow meter be located after the point of 

segregation for on-site use would unfairly penalize those facilities that have installed a flow 

meter according to the current regulatory requirements, and EPA should provide other options 

for compliance. (75 FR 48780) 

The current regulatory language required CO2 suppliers to have meters installed and calibrated 

before April 1, 2010. Facilities that installed a CO2 meter in compliance with the applicable 

regulatory language – at a location prior to purification, processing, or compression – should not 

now be required to install a meter after the point of segregation for on-site CO2 use where they 

have other means to generate the data needed by EPA. Rather, facilities that installed a meter 

ahead of purification, processing, and compression and also ahead of segregation for on-site use 

should have the option to include an appropriately calibrated meter on the on-site diversion flow 

in their GHG reporting program. KNC notes that it has been utilizing the two-meter approach at 

one of its facilities since March 31, 2010. The calculated difference between the two meter 

readings would provide an accurate estimate of the quantity of CO2 available for off-site 

commercial use. Koch Nitrogen Company, LLC (KNC) believes that either this two-meter option 

or the option of using a single meter located after purification, processing, compression and 

downstream of any diversion for on-site use should be equally acceptable under the rule. 

Response: Please see Section II.R of the preamble for the final rule amendments for the response 

to this comment. 
242 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 8 

Comment: In several other Part 98 subparts, EPA recognizes calibrated truck scales as 

appropriate supply measurement determination techniques. EPA should also make a conforming 

edit to proposed §98.424(a)(1)(i) and (a)(1)(iii) to incorporate weigh scale monitored shipping of 

CO2 product. 

Response: Today’s final action provides the flexibility the commenter requested regarding 

calibrated truck scales. 40 CFR Part 98.424(a)(2) contains QA/QC requirements for weigh scales 

and was added in the proposal to apply to reporters following the procedures for containers in 40 

CFR Part 98.423(b). Therefore, 40 CFR Part 98.424(a)(1)(i) and (iii) are not relevant to 

reporters using truck scales to determine the quantity of CO2 supplied. The proposed 

organization has been retained in the final rule amendments, and no revision was made as a 

result of this comment. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 40 

Comment: Third Party Quantity Measurements in Subparts MM, NN and PP 

EPA’s MRR Subpart MM requires information to assure EPA that these measurements are being 

made accurately. This requirement was not in the proposed rule, and in the preamble to the final 

rule [Part 98, October 30, 2009], EPA states that the only reason for adding this requirement is to 

“further EPA’s understanding of the methods and equipment that reporters use, and to help better 

assess the appropriateness of the standard methods and industry practices that individual 

reporters select...” (74 FR 56343). The assurances of third party measurements are simply not 

needed in a system that already requires the highest accuracy. EPA’s MRR requirements add 

considerable burden to the reporters without any real benefit to EPA. Some examples follow: 

1. EPA requires that the reporter state the standard method or industry standard practice 

associated with each quantity measured. This MRR requirement would require the addition of a 

new, separate method of tracking and documenting these standards. The MRR requires new 

information to be obtained from third parties and tracked for reporting. This is burdensome and 

inappropriate when considering how accurate reporting companies need this information to be 

already. 

2. EPA also requires that reporters certify the accuracy of third party meters. It is redundant and 

burdensome to require that reporters certify accuracy to third party meters that are already 

subject to existing internal and external controls. In many cases, the MRR reporter simply does 
243 

not have access to these third party records. Different vendors sometimes supply this data, and it 

is unnecessary to produce additional records to prove their accuracy. 

These requirements add burden without benefit. Currently for reporters subject to reporting 

under Subpart MM, there are more stringent demands already placed on the exchange of 

materials at the point of custody transfer. The accuracy of measurement for this exchange of 

materials between a company and another party is extremely important to both parties, as it sets 

the basis for the financial exchange between the parties. The accuracy of these custody transfers 

is already ensured to a very high level. This transfer requires an accuracy that far exceeds the 

needs of a greenhouse gas emission reporting effort, and therefore the EPA’s GHG Mandatory 

Reporting Rule should not add any additional requirements to ensure accuracy of custody 

transfer quantities. 

API believes that EPA should exclude custody transfer measurements from the QA/QC reporting 

requirements of Subpart MM, NN and PP. Petroleum suppliers (refineries) and importers and 

exporters of record often do not own or operate the equipment used to transport or store materials 

including flow meters and tank gauges. Instead, the supplier or importer/exporter contract with 

wholly independent third parties approved and accredited by the U.S. Customs & Border 

Protection (CBP) to handle the transfer and laboratory analysis of materials. The quantities of 

materials are measured by protocols specified by a number of governing bodies, such as CBP, 

which has a rigorous program to ensure measurement accuracy on international shipments. Even 

on domestic shipments, there are already requirements and methods used by the involved parties 

to ensure accuracy in the custody transfer process. 

It is redundant and burdensome for the EPA to require detailed monitoring and QA/QC, record 

keeping, and reporting on information on the equipment and measurements that are being 

reported for custody transfer amounts by third parties. This requirement adds effort and cost 

without benefit. 

EPA has already made allowances exempting third-party custody-transfer meters from the 

QA/QC requirements of the MRR, such as the documentation, certification of method, and 

certification of accuracy. EPA allows exemptions for “billing meters,” which are third-party 

custody-transfer meters. First, in the General Provisions of Subpart A, §98.3(i)(4), EPA allows 

the following exemption from the meter calibration requirements: 

Fuel billing meters are exempted from the calibration requirements of this section, 

provided that the fuel supplier and any unit combusting the fuel do not have any common 

owners and are not owned by subsidiaries or affiliates of the same company. 

Second, in the Stationary Fuel Combustion sources in Subpart C, EPA already allows 

exemptions for billing meters in §98.34(b)(ii) and (iii): 

(ii) In addition to the initial calibration required by §98.3(i), recalibrate each fuel flow 

meter (except for qualifying billing meters under paragraph (b)(1)(iii) of this section) 

either annually, at the minimum frequency specified by the manufacturer, or at the 

interval specified by the industry consensus standard practice used. 
244 

(iii) Fuel billing meters are exempted from the initial and ongoing calibration 

requirements of this paragraph, provided that the fuel supplier and the unit combusting 

the fuel do not have any common owners and are not owned by subsidiaries or affiliates 

of the same company. 

Billing meters were appropriately excluded by EPA for good reason. First, it is very difficult for 

the reporting entity to obtain all the records the EPA requires on a monitoring device and from 

an operation that is not owned nor controlled by the reporter. The reporter simply does not have 

the means to force the third party to supply all those records. Second, it is expensive and 

burdensome to duplicate and maintain a redundant file of the records maintained by a third party. 

Third, assurance of accuracy for custody transfer is simply unnecessary, since many other 

protocols and motivations already assure the accuracy of a custody transfer measurement. EPA 

should apply the same logic to Subparts MM, NN and PP and exclude custody transfer, 

especially where third-party measurement is involved, from the detailed QA/QC reporting 

requirements. 

Some examples of the superior accuracy of the existing systems (without the new EPA MRR 

requirements) follow: 

These records are the basis for reporting inventories as well as commercial purchase and sale 

payments. The parties making the exchange use industry consensus standards for measurement 

and calibration. 

These financial records also have the benefit of being subject to audit under existing internal 

controls, Sarbanes-Oxley regulations, as well as the Internal Revenue Service (IRS), Customs & 

Border Protection (CBP) and other regulatory compliance systems. 

International custody transfer shipments are tightly controlled already: 

1. The existing financial records already contain volumes (or weights) for all materials 

that are shipped into or out of a facility identified by material-specific codes. For 

imported fuels, CBP is the federal agency tasked with enforcing regular requirements 

around calculation of imported quantities of bulk petroleum feedstocks and products. 

2. 19 CFR§151 Examination, Sampling and Testing of Merchandise details the 

requirements and Subpart C of 19 CFR§151 deals specifically with petroleum and 

petroleum products. The CBP in its guideline for approval and validation of FTZ 

petroleum measurement systems (including sampling) state that petroleum measurement 

systems must be approved (i.e. 19 CFR 151.42(a)(1)(i) and 151.42(a)(3)) and are 

typically accepted if those petroleum measurement systems “meet or exceed the 

installation, operational, and performance criteria found in the “appropriate” (sic current 

edition) API Manual of Petroleum Measurement Standards (MPMS). 

3. For marine movements, third party gaugers bonded and approved by CBP’s Laboratory 

and Scientific Services group are to be employed to objectively determine quantities of 
245 

bulk petroleum materials being imported at refineries and chemical plants. Subpart C of 

19 CFR§151 deals specifically with petroleum and petroleum products. 

4. Third party gaugers are approved by CBP prior to carrying out any marine 

measurement work and they are tasked with assuring the accuracy of the data. CBP 

periodically audits third party gaugers to ensure their practices and equipment are in 

accordance with industry requirements. 

5. The CBP program also applies to some refinery feedstocks. For pipeline movements 

into the United States, CBP requires that a custody transfer meter on the pipeline be 

determined, and the importer must certify to CBP that the meter was installed in 

accordance with API or ASTM guidelines, that the meter is proved/calibrated on a basis 

in accordance with its usage, and that records relating to the installation, care and 

operation of the meter are stored in an organized manner and available for CBP’s review 

upon request. As the importer is often times not the owner/operator of the meter, 

contracts between meter owner and the importer are issued to convey the requirements. 

Recommendations: API suggests that EPA consider the advantage of existing custody transfer 

and accounting systems, consider the precedent EPA has already set for billing meters, and 

consider the information contained here in for quantities measured by third parties. EPA should 

remove the other reporting, monitoring QA/QC, and recordkeeping requirements for third party 

custody transfer for subparts MM, NN, and PP. If EPA wishes to review any records during an 

audit, API suggests that the volumes in the reporter’s financial records be the basis and be 

included in section §98.394 that would allow refineries, importers, and exporters to use existing 

accounting systems and quantities determined under the CBP and other third party programs. 

API suggests the following change be made to provide an exemption similar to that given under 

Subpart A, specifically §98.3(i)(4) for third-party fuel billing meters. 

Under§98.394 (Subpart MM), §98.404 (Subpart NN) and §98.424 (Subpart PP), API suggests 

the language should be modified to add the following: 

Any equipment used in the determination of quantity not owned or operated by the 

reporting entity and used for billing or custody transfer purposes in this subpart is exempt 

from the monitoring and QA/QC requirements, data reporting requirements, and 

recordkeeping requirements specifically for information on the equipment and 

corresponding quantity measurement. Any records from third party equipment that are 

retained as part of normal business operations will be preserved and made available as 

needed. 

Response: No rule change has been made as a result of these comments. The changes to Part 98 

suggested by the commenters are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. 

Other Subpart PP Comments 
246 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 3 

Comment: Several Subpart PP proposed changes appropriately clarify reporting requirements 

for carbon dioxide (“CO2”) suppliers. 

Response: EPA thanks the commenter for the input. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 53 

Comment: Clarification of applicability for carbon dioxide suppliers - The language in §98.421 

should be corrected to exclude the source categories that are explicitly excluded by §98.420(b) 

and (c). API requests adding “and is not excluded from this Subpart by§98.420(b) or (c)” after 

the phrase “meets the requirements of §98.2(a)(4).” 

Response: No rule change has been made as a result of these comments. The changes to Part 98 

suggested by the commenters are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. 

15. COMMENTS ON ADMINISTRATIVE PROCEDURES (E.G., COMMENT 

PERIOD) 

Commenter Name: David P. Tenny 

Commenter Affiliation: National Alliance of Forest Owners (NAFO) 

Document Control Number: EPA-HQ-OAR-2008-0508-2373.1 

Comment Excerpt Number: 1 

Comment: At the outset, NAFO notes that EPA’s notice of its proposed rulemaking fails to 

explain that its proposed revisions were also part of proposed settlements with UARG and 

others, which EPA recently circulated for public comment. See 75 FR 42,085 (June 20, 2010). 

The value of taking public comment on the proposed settlements is significantly undermined 

because EPA clearly failed to conduct any meaningful review of these comments before moving 

forward with the proposed rule. If EPA does not fully consider and respond to all of the 

comments it has received—on the proposed settlements and on the proposed rule—before taking 

final action, it risks acting in an arbitrary and capricious manner. 
247 

Response: While it would be optimal for EPA to be able to consider comments on proposed 

settlements before moving forward with related rulemakings, the schedule for completing the 

proposed revisions prevented EPA from considering the comments on the proposed settlement 

before publishing the proposed amendments. Nonetheless, EPA did carefully consider the 

comments on the settlement agreements before finalizing the agreements. Note, there is no 

obligation under section 113(g) of the Clean Air Act for EPA to respond to comments on 

settlement agreements, unless they are also provided as comments on a related rulemaking. All 

of the comments submitted on the proposed settlements that were also submitted on the proposed 

rule amendments have been fully considered by EPA in developing the final rule amendments. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 12 

Comment: Since EPA has yet to release the e-GGRT for public review and comment, API 

requests EPA describe in the response to comments or the preamble to the final amendments the 

mechanism for submitting documents via e-GGRT. 

Response: The subject of submitting documents via e-GGRT is beyond the scope of the rule 

amendments published for public comment on August 11, 2010. EPA will be providing 

guidance on the e-GGRT through separate action and outreach to facilities and suppliers. 

16. COMMENTS ON LEGAL AUTHORITY FOR THE AMENDMENTS 

Commenter Name: D.N.M. Robinson 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2349 

Comment Excerpt Number: 1 

Comment: The EPA is exceeding its congressionally determined authority, most recently in 

Texas in the matter of requiring filings that could jeopardize schools, churches and small 

businesses. EPA has become the loudest in a now shrinking choir of "global warming" alarmists, 

but the motive is less about air than about power. 

Response: This comment appears to be outside the scope of the specific amendments to the 

GHG Reporting Rule proposed for public comment in the Federal Register notice of August 11, 

2010. Note that the legal authority for Part 98 and the proposed amendments is described in the 

preambles to the proposed and final Part 98 (74 FR 16448, April 10, 2009, and 74 FR 56260, 

October 30, 2009), as well as the Response to Comments document for the final rule. 
248 

17. GENERAL SUPPORT AND OPPOSITION FOR THE AMENDMENTS 

General Support for the Amendments 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2345 

Comment Excerpt Number: 1 

Comment: I am in full support of the proposed rule covered in docket ID No. EPA-HQ-OAR2008-0508. The revisions in this rulemaking, which according to the EPA website, would 

“provide additional clarification where Part 98 was vague or led to confusion among reporters, 

amend specific provisions related to certain issues identified as a result of working with the 

affected sources during rule implementation and outreach, [and would include] corrections to 

terms and definitions in equations and other technical corrections.” The revisions to the pertinent 

subparts, namely A, C, D, F, G, P, V, X, Y, AA, OO, and PP, would allow for clear-cut guidance 

on the regulation and would allow for better reporting through the EPA Greenhouse Gas 

Reporting Program (GHGRP). 

Response: EPA thanks the commenter for the input. 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2353 

Comment Excerpt Number: 1 

Comment: The proposed rule to make specific provisions in the greenhouse gas reporting rule 

by clarifying certain provisions as well as correct technical errors along with editorial errors in 

my opinion will provide a more thorough understanding and interpretation of the rules stated in 

Part 98 of the proposed rule. The definitions of words and phrases that previous existed in the 

original mandatory report allow for owners and operators of facilities to obtain a greater 

understanding of the tasks they must perform in order to report their facilities green house gas 

emissions correctly. 

Response: EPA thanks the commenter for the input. 

Commenter Name: C. Maddox 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2356 

Comment Excerpt Number: 1 

Comment: While I am not for an excessive amount of Government control, when it comes to 

things like protecting our environment, the public and our natural resources I agree that there is 

an increasing need for rules and regulations that work toward ensuring the greater good. I am in 
249 

favor of these proposed regulations. It is important for industrial companies to truthfully report 

GHG emissions and work toward a goal of limiting those emissions in order to protect our 

already deteriorating Ozone. Our world is in trouble due to negligence and carelessness. I am all 

for revising the GHG Reporting Program to include technical corrections, ensure consistency and 

provide clarification. This is extremely important in ensuring that companies can and will abide 

by these regulations because it leaves little to no room for error. 

In short, I support the proposed regulatory measures on the assumption that the EPA is acting in 

the best interests of the general public and our environment. Thank for taking the time to review 

my comment. 

Response: EPA thanks the commenter for the input. 

However, it is important to clarify that the GHG reporting program does not include any 

provisions to specifically limit emissions of chemicals that deplete stratospheric ozone, although 

some of the chemicals that are known to act as greenhouse gases are also know to be ozone 

depleting substances. The protection of stratospheric ozone is addressed by other regulations 

promulgated under other Clean Air Act authority. 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2353 

Comment Excerpt Number: 3 

Comment: Overall, I believe the this proposed rule was developed with the thoughts and 

concerns of owners and operators in mind and therefore this proposed rule is in my opinion a 

necessity to make the burden of reporting greenhouse gas emissions lessen as well as provide a 

more clear and comprehendible rule. 

Response: EPA thanks the commenter for the input. 

Commenter Name: Lorraine Krupa Gershman 

Commenter Affiliation: American Chemistry Council 

Document Control Number: EPA-HQ-OAR-2008-0508-2368.1 

Comment Excerpt Number: 1 

Comment: ACC generally supports EPA’s proposed revisions to the mandatory reporting rule 

(MRR) for greenhouse gases (GHGs). We recognize that EPA has been under extraordinary 

pressure to issue the final MRR and to begin reporting data for the 2010 year beginning January 

1, 2011. The proposed revisions found in this package are the result of detailed discussions with 

impacted trade associations and companies, and generally reflect a more flexible approach to the 

MRR. 
250 

Response: EPA thanks the commenter for the input. 

Commenter Name: Rich Raiders 

Commenter Affiliation: Arkema Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2371.1 

Comment Excerpt Number: 1 

Comment: In general, Arkema supports many aspects of the proposed rule, and recommends 

opportunities for EPA to strengthen the rule before any final promulgation. We appreciate the 

significant effort EPA expended in making these amendments. In general, the proposal clarifies 

several critical aspects of the existing Part 98 climate change reporting system. 

Response: EPA thanks the commenter for the input. 

Commenter Name: William C. Herz 

Commenter Affiliation: The Fertilizer Institute (TFI) 

Document Control Number: EPA-HQ-OAR-2008-0508-2376.1 

Comment Excerpt Number: 1 

Comment: TFI supports EPA’s proposed amendments to 40 C.F.R. Part 98, Subparts G, V, and 

PP and encourages EPA to adopt these amendments. Specifically, TFI supports (1) deleting the 

requirement to report the nitrogen content in synthetic fertilizers from Subparts G and V, (2) 

deleting the requirement to report urea uses from Subpart G, (3) deleting Equation G-6 from 

Subpart G, relating to the waste recycle stream, (4) clarifying in Subpart G that reported CO2

emissions from an ammonia manufacturing facility may include CO2 that is used on-site in the 

manufacture of urea and, as such, is not an emission to the ambient air from the ammonia 

manufacturing facility, (5) making changes to Subpart PP to allow more flexibility when 

determining the amount of CO2 sent off-site by allowing use of weigh bills, scales, or load cells, 

and (6) providing flexibility in Subpart PP when a source uses a flow meter to measure CO2 sent 

off-site regarding where that flow meter may be installed. 

Response: EPA thanks the commenter for the input. 

General Opposition To The Amendments 

Commenter Name: Helen D. Silver 

Commenter Affiliation: Clean Air Task Force et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2403.2 

Comment Excerpt Number: 4 

Commenter Name: Craig Holt Segall 

Commenter Affiliation: Sierra Club Environmental Law Program et. al 

Document Control Number: EPA-HQ-OAR-2008-0508-2398.3 
251 

Comment Excerpt Number: 5 

These two commenters submitted identical comments on this subject. 

Comment: General Assessment 

EPA’s proposed changes would weaken the rule, but EPA does not consider them cumulatively 

to determine how much damage they will do. While we oppose these changes, we ask EPA 

nonetheless to conduct such a calculation, documenting the increased uncertainty, error rates, 

and other rule failures the changes are likely to cause on a cumulative basis. EPA should not be 

moving forward on any of these changes without assessing their impact on the rule as a whole. 

Response: As indicated in the responses to other comments on the proposed amendments to the 

various subparts in Part 98, we disagree with the commenters’ assertion that the proposed 

changes would weaken the rule and increase the uncertainty or error rates associated with the 

GHG emissions data submitted under Part 98. 

We are confident that the monitoring and QA/QC procedures in Part 98, along with the GHG 

Reporting Program’s data verification procedures, will ensure that the data collected under the 

GHG Reporting Program will be of sufficient quality to meet the program’s objectives. 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2346 

Comment Excerpt Number: 1 

Comment: We are trying hard to comply with the Greenhouse Gas Reporting regulations. 

However, EPA has issued so many changes to the original Final Monitoring Requirements that 

we are getting more and more confused. I have calculated emissions for 20 years and I have 

never found an emission so easily calculated as the GHG made so complicated. 

As to making any worthwhile comment on a single one of the many changes is not possible until 

EPA decides what they are doing. Please, please stop making reporting GHG emissions so 

difficult. 

Response: EPA thanks the commenter for the input. EPA appreciates the commenter's concern 

over the complexity of the Part 98 requirements for calculating and reporting GHG emissions. 

However, the overall approach and complexity of estimating and reporting GHG emissions for 

different industries is driven in part by the goal of providing flexibility to accommodate the 

needs of a number of different reporters. 

As explained in the preamble to the proposed rule amendments (75 FR 48747-48748, August 11, 

2010), we have identified errors in the regulatory language as a result of working with affected 

industries to implement the various subparts of Part 98. We have also identified certain rule 

provisions that should be amended to provide greater clarity. Finally, we proposed revisions to 

provide additional flexibility for certain requirements based in part on a better understanding of 
252 

various industries. The majority of those amendments are now being promulgated as proposed, 

and the remainder have been modified since proposal based on comments and input from the 

affected industries and other interested parties. In many cases, the revisions that are being made 

simplify the estimating and reporting of GHG emissions and reduce the burden on those facilities 

required to report GHG emissions. 

18. COMMENTS ON PART 98 ISSUES THAT WERE COVERED BY THE 

FIRST PART 98 CORRECTIONS NOTICE 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 55

[This commenter suggested several changes to subpart MM – Suppliers of Petroleum Products.] 

Comment: Subpart MM Calibration Timing - In §98.394(b)(1) under ‘Equipment Calibration’ 

the rule states, “(1) All measurement equipment shall be calibrated prior to its first use... using 

an appropriate standard method... (2) Measurement equipment shall be recalibrated at the 

minimum frequency specified by the standard method used or by the equipment manufacturer’s 

directions.” 

This section of the rule is inconsistent with §98.3(i)(6) where EPA recognizes that for 

continuously operating units some calibrations are not possible on-line without disrupting 

operations and goes on to state, “In such cases, the owner or operator may postpone the initial 

calibration until the next scheduled maintenance outage, and may similarly postpone the 

subsequent recalibrations. Such postponements shall be documented in the monitoring plan that 

is required under §98.3(g)(5).” 

Recommendations: EPA should amend the text for subpart MM to make it consistent with the 

flexibility afforded by subpart A. 

Calcine Coke (also known as calcined or calcinated coke) - Table MM-1 contains default data 

for petroleum coke but does not contain corresponding data for calcine coke. Petroleum coke and 

calcine coke have different uses, and calcine coke typically has a higher carbon density than 

petroleum coke due to the calcinations process. Because of these differences, it is probably not 

appropriate to utilize the petroleum coke data for reporting on calcine coke under Subpart MM. 

Product quality requirements for calcine coke results in a product that has very little variability in 

its carbon share. However, without default data in Table MM-1, calcine coke producers would be 

forced into a burdensome sampling program for calcine coke reporting under subpart MM. 

API is requesting that EPA include applicable calcine coke data in Table MM-1 to prevent the 

waste of time, money, and effort that would otherwise be imposed on reporters. 
253 

Recommendation: API is recommending the addition of new default factors for Calcine Coke in 

Table MM-1: Average Calcine Coke Carbon Content: 96.95%; Calcine Coke Density: 0.1910 

Metric Tons/Bbl; Emission Factor: 0.6462 Metric Tons CO2/Bbl 

Corrections to Table MM-1: The densities shown for ethane, propane and butane differ from 

values commonly used by the oil and gas industry. EIA’s Inventory of U.S. Greenhouse Gas 

Emissions and Sources (which is cited by the API Compendium) uses 0.0592 tonnes/bbl for 

ethane, 0.0804 tonnes/bbl for propane, and 0.0926 tonnes/bbl for butane. 

Recommendation: API requests that the densities be updated consistent with values commonly 

used by the oil and gas industry. 

Response: No rule change has been made as a result of these comments. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 56

Comment: Section 98.407 is titled “Records that must be retained,” but states that the 

information must be contained in the annual report. 

Recommendation: We believe EPA meant this to state, “All reporters shall retain copies of the 

following information.” API requests that this be corrected. 

Response: The commenter is correct that the introductory text to 40 CFR 98.407 should have 

referred to records that should be kept by the reporting entity, and not information to be included 

in the annual report. However, no rule change has been made as a result of this comment. The 

change to Part 98 suggested by the commenter is outside the scope of the specific amendments 

proposed for public comment in the Federal Register notice of August 11, 2010, but will be 

considered for future rulemakings. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2008-0508-2383.1 

Comment Excerpt Number: 52 

Comment: Clarification of applicability for suppliers of natural gas and natural gas liquids – The 

language in section §98.401 should be corrected to exclude the source categories that are 

explicitly excluded by section §98.400(c). Recommendation: API requests adding “and is not 

excluded from this Subpart by §98.400(c)” after the phrase “meets the requirements of 

§98.2(a)(4).” 
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Response: No rule change has been made as a result of this comment. The changes to Part 98 

suggested by the commenter are outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. We would note that we do 

not believe the proposed clarification is needed, as the industries listed in §98.400(c) are clearly 

excluded from the source category. 

19. GENERAL OUT OF SCOPE COMMENTS 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2351 

Comment Excerpt Number: 1 

Comment: Even in light of actual research, and "doctored" research allegedly supporting global 

warming, you persist in pushing regulations to limit a gas that is the normal byproduct of every 

living organism and required by every living plant. This sounds like an agenda, not science. The 

public is clearly not in favor of such limitations, so the government tries an "end around." 

Response: This comment is outside the scope of the specific amendments to the GHG Reporting 

Rule proposed for public comment in the Federal Register notice of August 11, 2010. Note that 

the legal authority for Part 98 and the proposed amendments is described in the preambles to the 

proposed and final Part 98 (74 FR 16448, April 10, 2009, and 74 FR 56260, October 30, 2009), 

as well as the Response to Comments document for the final rule. 

Commenter Name: Gordon Arbuckle 

Commenter Affiliation: Patton Boggs LLP 

Document Control Number: EPA-HQ-OAR-2008-0508-2386.1 

Comment Excerpt Number: 1 

Comment: As EPA was advised during the earlier comment process, the GHG reporting 

regulations are critically deficient because they fail to require submission of the information 

necessary to assess the questions of (1) whether, and to what extent, intensive U.S. based 

regulation of GHG emissions will result in “leakage” – or migration of energy intensive 

manufacturing operations to countries with less stringent regulatory regimes resulting; and (2) 

whether, and to what extent, that shift will result in a net increase in worldwide GHG emissions. 

GHG Reporting Rules which do not provide for the development of the data required to assess 

the impact of regulation of emissions from U.S. sources, without commensurate regulation of the 
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sources which power the competitive foreign industries, are not responsive to Congress’ 

expectations in enacting the Consolidated Appropriations Act. Without that data, neither EPA 

nor the Congress will be able to meaningfully consider the critical question of whether stringent 

U.S. regulation, without global balance or border adjustment mechanisms, might actually result 

in both damage to U.S. jobs and the manufacturing sector and net increases in global GHG 

emissions. Such a result would directly contradict the Administration’s often announced policy 

of restoring and protecting the U.S. manufacturing sector and saving and creating U.S. jobs. 

Moreover, the inability to credibly answer the fundamental question of whether U.S. regulations 

will increase or diminish global GHG emissions would call into question the legality of any 

GHG emission limits which the EPA might adopt in the future. 

In short, because the GHG Reporting Rules, as they currently stand, do not require information 

regarding upstream emissions associated with the production of high carbon intensity products 

exported to the U.S., they cannot develop the information required to properly devise a 

regulatory scheme under either the Clean Air Act or any of the legislation pending in the 

Congress. They will not provide the information required to assess the regulatory and 

environmental effects of any such regulations, to assess impacts on U.S. employment and the 

manufacturing sector, or to measure the regulations’ effectiveness in achieving the objective of 

reducing worldwide greenhouse gas emissions. In the absence of a viable information base, 

regulatory decisions respecting GHG will be necessarily arbitrary and unsupported by scientific 

evidence. EPA is dealing here with a global issue and must develop the information required to 

assess worldwide effects as well as those which occur within the U.S. It is essential that the GHG 

Reporting Rules provide the basis for collection of the full suite of information and metrics 

required to effectively address issues of climate control without inadvertently causing net 

increases in global GHG emissions or unnecessarily damaging key U.S. industries with resulting 

loss of U.S. jobs. 

EPA, in making regulatory decisions under either the Clean Air Act or some new legislation will 

face these questions, both in phasing and in assessing environmental effects and regulatory 

impacts. The Agency will not be able to make decisions which will survive judicial review 

unless it has scientific evidence to support its decisions. The GHG Reporting Rule, as it currently 

stands, will not obtain this information or assure appropriate consideration of it. We are aware 

that, when similar comments were submitted previously, EPA responded that "the collection of 

economic data and data on the regulatory frameworks of other countries, the performance of 

economic impact analyses of potential future regulatory programs, and the determination of the 

global GHG impacts if companies were to move production overseas due to a future program is 

beyond the scope of the reporting rule." We are also aware that the Notice for this proposed 

rulemaking is explicit to the effect that only the technical issues addressed in the Notice will be 

considered. 

We would point out, however, that: (1) EPA has not promulgated the regulations it was directed 

to promulgate and is now over three years in breach of a statutory duty. (2) That breach imperils 

the Agency’s ability to credibly support any GHG regulations it may currently be considering. 

(3) Failure to collect and assess the data required to ultimately enact legislation that will avoid 

unnecessary loss of jobs and manufacturing capacity is contrary to Administration policy and 

adverse to the public interest. 
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If new carbon controls are implemented for energy-intensive/internationally competitive 

industries, the adverse competitive effects could be substantial. Costs could rise; prices could 

rise; long established customers could turn to foreign companies operating in countries that have 

less developed environmental standards and regulatory authority. 

If it is not clear how much U.S. production would be displaced or lost to other less stringently 

regulated countries, then it will be impossible to determine the impact of any U.S.-only 

regulatory regime. It is likely that, without regulatory accommodations, U.S.-only regulation of 

GHG emissions from energy intensive industries will result in loss of US-based jobs; economic 

disruption and dislocation; and possibly also in the unintended consequences of reduction of 

energy efficiency and increase in worldwide carbon emissions. 

Failure to provide for the development of metrics and data to support assessment of business and 

jobs migration and its consequent effect on GHG emissions will substantially impede 

achievement of the primary objective: reducing worldwide GHG emissions. The proposed rules 

must be revised to require information addressing at least the following questions: What are the 

energy intensive U.S. industries subject to intense foreign competition? What is the likelihood 

and magnitude of anticipated production shifts in each such industry category? What are the 

relative life-cycle carbon emissions from U.S. products as opposed to those from likely 

exporters? What metrics should be used to measure? What is the likely net effect on worldwide 

GHG emissions of any regulatory approach under consideration? 

An effective climate change program must encourage innovation and investment, while 

discouraging emissions migration and, with it, the loss of U.S. jobs. If manufacturing activities 

move from inside the U.S. to countries with weaker regulation and enforcement mechanisms in 

place, U.S. employment opportunities will decrease, while, at the same time, global greenhouse 

gas emissions will increase. Failure to obtain the information required to address this issue would 

be a fatal weakness in the foundation for any EPA GHG regulation program. Please provide a 

substantive response to these comments. To the extent that these comments are not addressed in 

these proceedings, please treat this submission as a petition for rulemaking. 

Response: The subjects of the effect of U.S. GHG emission regulations on U.S. manufacturing, 

jobs, and global GHG emissions rates, and the data needed to estimate those impacts are beyond 

the scope of 40 CFR part 98 and these proposed amendments. Note that the legal authority for 

Part 98 and the proposed amendments is described in the preambles to the proposed and final 

Part 98 (74 FR 16448, April 10, 2009, and 74 FR 56260, October 30, 2009), as well as the 

Response to Comments document for the final rule. The process of amending Part 98 is not the 

appropriate forum for the discussion of these subjects. The topics identified by the commenter 

are likely to be the subject of future policy and scientific discussions. However, to the extent that 

accurate GHG emission estimates are needed to inform those discussions, the amendments to 

Part 98 will help provide those estimates. 

Finally, a comment letter on these proposed amendments is not the appropriate avenue for 

submitting a petition for rulemaking. 
257 

Commenter Name: Anonymous 

Commenter Affiliation: None 

Document Control Number: EPA-HQ-OAR-2008-0508-2345 

Comment Excerpt Number: 2 

Comment: These regulations and reports will help businesses operate on a higher economically 

friendly level. As this is a world we all share, not only with other countries, but with future 

generations, the preservation of as much as possible is an imperative. On the topic of EPA 

verification of reported data, I also agree with what is in the docket. Even if the information has 

gone through a separate third-party verification process, I believe that it is the EPA’s job to 

verify to their own standards, although, as written in their statement to the EPA, the Glass 

Association of North America (“GANA”), clearly disagree. It seems like they are just trying to 

have less work on their plate. In that same statement, they also request to have the initial date of 

reporting changed, stating the “EPA underestimates the time the flat glass manufacturing 

industry requires to compile, verify, and review the annual data needed for submittal...” I do not 

believe the EPA needs to change the original date as specified in the plan. Keeping these original 

dates and keeping the EPA in charge of verification takes away opportunities for corruption or 

the manipulation of GHG numbers. 

Response: EPA thanks the commenter for the input. 

No rule change has been made as a result of this comment. The subject of EPA's emissions 

verification approach is outside the scope of the specific amendments proposed for public 

comment in the Federal Register notice of August 11, 2010. Responses to pubic comments on 

EPA's emissions verification approach can be found in the preamble to the final Part 98 (74 FR 

56282-56283, October 30, 2009), and in "Mandatory Greenhouse Gas Reporting Rule: EPA's 

Response to Public Comments, Approach to Verification and Missing Data" (September 2009, 

EPA-HQ-OAR-2008-0508). 

See EPA's response to comments in the section, "How these amendments apply to 2011 GHG 

emission reports," in this document for EPA's response on whether the dates of the initial reports 

or any of the other reporting requirements have been changed as a result of the amendments to 

Part 98. 

Commenter Name: Peter Zalzal 

Commenter Affiliation: Environmental Defense Fund (EDF) 

Document Control Number: EPA-HQ-OAR-2008-0508-2370.1 

Comment Excerpt Number: 2 

Comment: Environmental Defense Fund (EDF) reiterates our long-standing request that EPA 

make public these BAMM extension requests. We respectfully recommend that EPA list all of 

the companies and facilities that have requested to use BAMM along with the status of those 

requests. This commitment to transparency is at the core of President’s January 26, 2009 

Executive Order and is consistent with EPA’s commitment to public disclosure in its 
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Confidential Business Information proposal, where the Agency recognized that such disclosure is 

critical “because it ensures transparency and promotes public confidence in the data.” 75 FR 

39094, 39097 (Jul. 7, 2010). Public disclosure of these requests will likewise help to promote 

accountability, ensuring that the public and polluters alike are aware of facilities that have yet to 

fully comply with the requirements of the final MRR. 

Response: EPA thanks the commenter for the input. 

No rule change has been made as a result of this comment. The subjects of transparency, 

confidential business information, and whether requests to extend the use of best available 

monitoring method (BAMM) should be made public are beyond the scope of the amendments to 

Part 98 published on August 11, 2010. 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 4 

Comment: EPA states that it will rely on Agency verification of the electronic data provided in 

the annual reports in lieu of third-party verification. The agency further states that “sufficient 

information must be included in the electronic reports, at the facility, source category, and unit 

levels, to enable EPA to recalculate the reported GHG emissions and to quality-assure the data.” 

[75 FR 48762] Mexichem questions the need for the EPA to perform calculations. Programs 

such as the Toxic Release Inventory (TRI) are equivalent to the GHG MMR in that it is a 

reporting program. The agency does not calculate emissions under the TRI program and should 

not need to calculate them under the GHG MMR. 

Response: No rule change has been made as a result of this comment. The subject of EPA's 

emissions verification approach is outside the scope of the specific amendments proposed for 

public comment in the Federal Register notice of August 11, 2010. 

Commenter Name: Rhea Hale 

Commenter Affiliation: American Forest & Paper Association (AF&PA) 

Document Control Number: EPA-HQ-OAR-2008-0508-2382.1 

Comment Excerpt Number: 5 

Comment: The American Forest & Paper Association (AF&PA) has identified two technical 

errors in subpart TT of the EPA GHG rule (industrial landfills). Note that these errors are 

associated with the final rule amendments published on July 12 (not the July 20 proposed 

amendments). 

The first error is in regard to the start year for quantifying waste deposits and calculating 

associated emissions. The text in Section 98.463(a)(2) states “determine annual waste quantities 

... for each year starting with January 1, 1980 or the year the landfills first accepted waste if after 
259 

January 1980, up until the most recent reporting year.” However, the key to Equation TT-1 

(which is used to calculate methane generation based on the quantified waste deposits) includes 

this description for S, the start year “use the year 1960 or the opening year of the landfill, 

whichever is more recent.” Also, the key to Equation TT-4 (which is used to calculate average 

annual waste deposition quantities during historic periods historic data is not available) includes 

a similar description for “YrOpen = year 1960 or the year in which the landfill first received 

waste from company records, whichever is more recent...” Therefore, it is unclear whether or 

not EPA intends for reporters to base calculations on data beginning in 1960, or in 1980. 

The second error is in regard to the method presented for calculating a waste-specific DOCx 

value for waste streams using Equation TT-8 in Section 98.364(b)(4). The key to Equation 8 

states that the result of the calculation (DOCx) is “degradable organic content of waste stream in 

Year X (weight fraction, wet basis).” However, the equation as provided would return a DOCx 

value on a dry basis. 

Response: EPA thanks the commenter for the input. No rule change has been made as a result 

of this comment. The changes to subpart TT of Part 98 suggested by the commenter are outside 

the scope of the specific amendments proposed for public comment in the Federal Register 

notice of August 11, 2010. 

Commenter Name: Joel R. Hall 

Commenter Affiliation: Mexichem Fluor Inc. 

Document Control Number: EPA-HQ-OAR-2008-0508-2365 

Comment Excerpt Number: 3 

Comment: Mexichem is concerned with the confidentiality of data submitted under 40 CFR 

98.3(c)(5)(ii). Because this data will be reported in metric tons of GHG it could be used by 

competitors to the disadvantage of our business. The Data category assignments for reporting 

elements to be reported under 40 CFR part 98 and its amendments memo from Lisa GroganMcCulloch, EPA/Climate Change Division and Ruth Mead and Amanda Baynham, ERG to 

EPA-HQ-OAR-2009-0924 dated June 28, 2010 indicates that data submitted under §98.3(c)(5)(i) 

and (ii) will not be confidential business information (CBI) [Table B-1: List of Data Elements in 

Proposed and Final Supplier Subparts, page 1 of 33]. Therefore, this data, which includes raw 

production data, will be available to the public. Mexichem requests that the EPA consider a 

means to protect the confidentiality of this data. 

In addition, §98.3(c)(4)(iii) will require that Mexichem report annual emissions of each 

fluorinated GHG (including those not listed in Table A–1of this subpart) expressed in metric tons 

under Subpart L. This data will include not only raw production data, but also raw material 

inputs, wastes removed from the process, etc. This data is not considered CBI under the Data 

category assignments for reporting elements memo and will therefore be available to the public. 

Access to this data by our competitors has the potential to cause a competitive disadvantage for 

us. Mexichem requests that the EPA consider a means to protect the confidentiality of this data. 
260 

Response: EPA thanks the commenter for the input. No rule change has been made as a result 

of these comments. No changes were proposed to 40 CFR 98.3(c)(5)(ii) in the August 11, 2010, 

proposed amendments. Likewise, no changes were proposed to 40 CFR 98.3(c)(4)(iii) for the 

reporting of each fluorinated GHG in the August 11, 2010, proposed amendments. The 

determination of which data elements will be considered to be CBI is not the subject of the 

August 11, 2010, proposed amendments. The subject of CBI determinations is being addressed 

by another proposed rule that was published on July 7, 2010 at 74 FR 39094 under docket EPAHQ-OAR-2009-0924. 

Commenter Name: Stephen E. Woock 

Commenter Affiliation: Weyerhaeuser Company 

Document Control Number: EPA-HQ-OAR-2008-0508-2375.1 

Comment Excerpt Number: 12 

Comment: A reference error in the new Subpart TT for Industrial Waste Landfills needs 

correction. 

In addition to the proposed revisions to the GHG MRR, Weyerhaeuser believes there is a misdirected reference (typographical error) in the current rule that should be addressed. In newly 

added Subpart TT Industrial Waste Landfills, [Footnote: 75 FR 39736; July 12, 2010.] at Table 

TT-1 the line item labeled “Inert Waste (i.e. wastes listed in §98.460(b)(3))” is in error. There is 

no §98.460(b)(3), and instead the reference should be to §98.460(c)(2). The latter refers to the 

listed inert waste materials that are important when using Equation TT-1. 

Response: EPA thanks the commenter for the input. No rule change has been made as a result 

of this comment. The changes to subpart TT of Part 98 suggested by the commenter are outside 

the scope of the specific amendments proposed for public comment in the Federal Register 

notice of August 11, 2010.